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 September 30, 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 October 31, 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	5
	2.	Allocation of Net Income	6
	3.	Comprehensive Income	7
	4.	Segment Disclosures	7
	5.	Related Party Disclosures	10
	6.	Inventory	11
	7.	Employee Benefit Plans	12
	8.	Debt	12
	9.	Derivative Financial Instruments	14
	10.	Commitments and Contingencies	15
	11.	Long Term Incentive Plan	17
	12.	Distributions	19
	13.	Net Income Per Unit	19
	14.	Assignment of Supply Agreement	20
	15.	Recent Accounting Standard	20
	16.	Subsequent Events	20
ITEM 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Introduction		21
	Recent Developments		21
	Results of Operations		22
	Liquidity and Capital Resources		27
	Off Balance Sheet Arrangements		29
	Environmental		29
	Other Items		30
	New Accounting Pronouncements		31
ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	32
ITEM 4.		CONTROLS AND PROCEDURES	33
Forward-Looking Statements			34

PART II OTHER INFORMATION

ITEM 1.		LEGAL PROCEEDINGS	36
ITEM 1A.		RISK FACTORS	37
ITEM 2.		UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	38
ITEM 3.		DEFAULTS UPON SENIOR SECURITIES	38
ITEM 4.		SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	38
ITEM 5.		OTHER INFORMATION	38
ITEM 6.		EXHIBITS	39

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 September 30,						Nine Months Ended September 30,
	2007			2008			2007			2008
Transportation and terminals revenues	$	154,492		$	164,257		$	447,713		$	471,216
Product sales revenues		167,287			127,540			493,852			439,622
Affiliate management fee revenue		178			183			534			549

Total revenues		321,957			291,980			942,099			911,387
Costs and expenses:
Operating		64,442			81,886			185,444			194,443
Product purchases		153,926			89,523			444,494			342,383
Depreciation and amortization		15,914			17,726			47,049			52,336
Affiliate general and administrative		17,219			17,151			52,645			53,385

Total costs and expenses		251,501			206,286			729,632			642,547
Gain on assignment of supply agreement		—			—			—			26,492
Equity earnings		1,091			1,722			2,960			3,504

Operating profit		71,547			87,416			215,427			298,836
Interest expense		13,698			15,030			43,637			40,717
Interest income		(332	)		(363	)		(1,449	)		(947	)
Interest capitalized		(1,091	)		(1,322	)		(3,193	)		(3,734	)
Debt placement fee amortization		174			211			1,973			548
Debt prepayment premium		—			—			1,984			—
Other (income) expense		29			—			728			(249	)

Income before provision (benefit) for income taxes		59,069			73,860			171,747			262,501
Provision (benefit) for income taxes		(375	)		524			1,149			1,469

Net income	$	59,444		$	73,336		$	170,598		$	261,032

Allocation of net income:
Limited partners’ interest	$	43,049		$	50,188		$	123,690		$	163,544
General partner’s interest		16,395			23,148			46,908			97,488

Net income	$	59,444		$	73,336		$	170,598		$	261,032

Basic net income per limited partner unit	$	0.65		$	0.75		$	1.86		$	2.45

Weighted average number of limited partner units outstanding used for basic net income per unit calculation		66,550			66,854			66,546			66,826

Diluted net income per limited partner unit	$	0.65		$	0.75		$	1.86		$	2.45

Weighted average number of limited partner units outstanding used for diluted net income per unit calculation		66,550			66,854			66,549			66,826

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands)


	December 31, 2007			September 30, 2008
				(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	19,815
Accounts receivable (less allowance for doubtful accounts of $10 and $11 at December 31, 2007 and September 30, 2008, respectively)		62,834			65,450
Other accounts receivable		10,696			13,370
Affiliate accounts receivable		208			217
Inventory		120,462			81,134
Energy commodity derivative contracts		—			12,161
Other current assets		10,882			9,079

Total current assets		205,082			201,226
Property, plant and equipment		2,435,890			2,647,671
Less: accumulated depreciation		615,329			657,820

Net property, plant and equipment		1,820,561			1,989,851
Equity investments		24,324			24,628
Long-term receivables		7,506			7,189
Goodwill		23,945			26,809
Other intangibles (less accumulated amortization of $6,743 and $7,903 at December 31, 2007 and September 30, 2008, respectively)		7,086			5,926
Debt placement costs (less accumulated amortization of $2,170 and $2,718 at December 31, 2007 and September 30, 2008, respectively)		6,368			7,868
Other noncurrent assets		6,322			6,344

Total assets	$	2,101,194		$	2,269,841

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	39,622		$	62,187
Affiliate accounts payable		12,947			1,766
Affiliate payroll and benefits		23,364			18,860
Accrued interest payable		7,197			21,913
Accrued taxes other than income		21,039			22,307
Environmental liabilities		36,127			19,551
Deferred revenue		20,797			22,505
Accrued product purchases		43,230			47,170
Accrued product shortages		—			12,673
Other current liabilities		16,322			19,879

Total current liabilities		220,645			248,811
Long-term debt		914,536			1,017,521
Long-term affiliate payable		1,878			589
Long-term affiliate pension and benefits		22,370			23,261
Supply agreement deposit		18,500			—
Noncurrent portion of product supply liability		24,348			—
Other deferred liabilities		6,081			6,221
Environmental liabilities		21,672			22,231
Commitments and contingencies
Partners’ capital:
Partners’ capital		882,642			961,078
Accumulated other comprehensive loss		(11,478	)		(9,871	)

Total partners’ capital		871,164			951,207

Total liabilities and partners’ capital	$	2,101,194		$	2,269,841

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)


	Nine Months Ended September 30,
	2007			2008
Operating Activities:
Net income	$	170,598		$	261,032
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		47,049			52,336
Debt placement fee amortization		1,973			548
Debt prepayment premium		1,984			—
Loss on sale and retirement of assets		5,756			3,824
Equity earnings		(2,960	)		(3,504	)
Distributions from equity investment		3,375			3,200
Equity method incentive compensation expense		2,276			3,804
Amortization of prior service cost and net actuarial loss		1,471			984
Gain on assignment of supply agreement		—			(26,492	)
Changes in components of operating assets and liabilities:
Accounts receivable and other accounts receivable		(19,868	)		(5,290	)
Affiliate accounts receivable		289			(9	)
Inventory		(14,433	)		39,328
Accounts payable		(13,128	)		16,239
Affiliate accounts payable		(227	)		(2,645	)
Affiliate payroll and benefits		(430	)		(4,504	)
Accrued interest payable		9,985			14,716
Accrued taxes other than income		4,469			1,268
Accrued product purchases		(19,351	)		3,940
Accrued product shortages		—			12,673
Restricted cash		5,283			—
Supply agreement deposit		(1,000	)		(18,500	)
Long-term affiliate pension and benefits		(9,590	)		1,637
Energy commodity derivative contracts, net of margin deposits		—			(3,966	)
Current and noncurrent environmental liabilities		2,553			(17,577	)
Other current and noncurrent assets and liabilities		1,614			523

Net cash provided by operating activities		177,688			333,565

Investing Activities:
Property, plant and equipment:
Additions to property, plant and equipment		(136,115	)		(208,859	)
Proceeds from sale of assets		893			3,846
Changes in accounts payable		(9,811	)		6,326
Acquisition of businesses		—			(20,567	)

Net cash used by investing activities		(145,033	)		(219,254	)

Financing Activities:
Distributions paid		(174,363	)		(197,385	)
Net borrowings (repayments) under revolver		119,500			(148,500	)
Borrowings under notes		248,900			249,980
Payments on notes		(272,555	)		—
Debt placement costs		(2,669	)		(2,048	)
Payment of debt prepayment premium		(1,984	)		—
Net receipt from financial derivatives		4,556			4,030
Capital contributions by affiliate		37,580			2,453
Increase (decrease) in outstanding checks		1,990			(3,026	)

Net cash used by financing activities		(39,045	)		(94,496	)

Change in cash and cash equivalents		(6,390	)		19,815
Cash and cash equivalents at beginning of period		6,390			—

Cash and cash equivalents at end of period	$	—		$	19,815

Supplemental non-cash financing activity:
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

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 September 30, 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

Basis of Presentation

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. We acquired a petroleum products terminal in Bettendorf, Iowa in January 2008 for $12.0 million and a terminal in Wrenshall, Minnesota in August 2008 for $8.6 million. The results of these facilities have been included in our petroleum products pipeline system segment from their respective acquisition date.

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 September 30, 2008, and the results of operations for the three and nine months ended September 30, 2007 and 2008 and cash flows for the nine months ended September 30, 2007 and 2008. The results of operations for the three and nine months ended September 30, 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, we allocated net income between our general partner and limited partners as follows (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2008			2007			2008
Allocation of net income to general partner:
Net income	$	59,444		$	73,336		$	170,598		$	261,032
Direct charges to the general partner:
Reimbursable G&A costs (a)		1,869			408			3,749			1,224
Previously indemnified environmental charges (credits) (b)		885			2,656			3,757			(7,106	)

Total direct charges (credits) to general partner		2,754			3,064			7,506			(5,882	)

Income before direct charges (credits) to general partner		62,198			76,400			178,104			255,150
General partner’s share of income (c)		30.79	%		34.31	%		30.55	%		35.90	%

General partner’s allocated share of net income before direct charges (credits)		19,149			26,212			54,414			91,606
Direct charges (credits) to general partner		2,754			3,064			7,506			(5,882	)

Net income allocated to general partner	$	16,395		$	23,148		$	46,908		$	97,488

Net income	$	59,444		$	73,336		$	170,598		$	261,032
Less: net income allocated to general partner		16,395			23,148			46,908			97,488

Net income allocated to limited partners	$	43,049		$	50,188		$	123,690		$	163,544

(a)

Reimbursable G&A costs for the nine months ended September 30, 2007 include a $1.3 million non-cash expense related to a payment made by MGG MH to one of our executive officers in connection with the sale by MGG MH of limited partner interests in MGG. This item did not impact cash available for distributions.

(b)

During the second quarter of 2008, we reached an agreement with the Environmental Protection Agency (“EPA”) and the U. S. Department of Justice (“DOJ”) to settle penalties proposed by the EPA associated with petroleum discharges from our pipeline. As a result of the settlement agreement, we reduced our environmental liability for this matter from $17.4 million to $5.3 million, resulting in a reduction to our operating expenses of $12.1 million. Of this reduction amount, $11.9 million was included as part of the indemnification settlement we reached with a former affiliate (see Note 10—Commitments and Contingencies for further discussion of this matter) and, accordingly, was allocated to our general partner. As a result, limited partner net income and earnings per limited partner unit for the nine months ending September 30, 2008 were impacted by only $0.2 million of the $12.1 million reduction in operating expense.

(c)

For periods when the distributions we pay exceed our net income (before direct charges to our general partner), 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). For the third quarter of 2007 and 2008, a per unit theoretical cash distribution of $0.6469 and $0.7520, respectively, would have resulted in total distributions equal to net income before direct charges to our general partner for the period. Our general partner’s share of distributions at these levels was 30.79% and 34.31% for the third quarter of 2007 and 2008, respectively. Our general partner’s share of net income for the nine months ended September 30, 2007 is based on its share of actual distributions paid for the first quarter and theoretical distributions for the second and third quarter. Our general partner’s share of net income for the nine months ended September 30, 2008 is based on its share of theoretical distributions for each of the first, second and third quarters.

The reimbursable G&A costs above represent G&A expenses charged against our income during the periods presented that were reimbursed to us by our general partner under the terms of the omnibus agreement or by separate arrangement. Because the limited partners did not share in these costs, we 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 (credits).” 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 refers to revenues, expenses, gains, and losses that, under generally accepted accounting principles (“GAAP”), are included in comprehensive income but excluded from net income. The 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 September 30,						Nine Months Ended September 30,
	2007			2008			2007		2008
Net income	$	59,444		$	73,336		$	170,598	$	261,032
Change in fair value of cash flow hedges		—			—			5,018		—
Amortization of net loss (gain) on cash flow hedges		(42	)		(41	)		103		(123	)
Amortization of prior service cost and net actuarial loss		473			328			1,471		984
Adjustment to recognize the January 1, 2008 funded status of our affiliate postretirement plans		—			746			—		746

Other comprehensive income		431			1,033			6,592		1,607

Comprehensive income	$	59,875		$	74,369		$	177,190	$	262,639

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 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 September 30, 2007
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products Terminals		Ammonia Pipeline System			Intersegment Eliminations			Total
Transportation and terminals revenues	$	118,862		$	32,786	$	3,672		$	(828	)	$	154,492
Product sales revenues		161,993			5,294		—			—			167,287
Affiliate management fee revenue		178			—		—			—			178

Total revenues		281,033			38,080		3,672			(828	)		321,957
Operating expenses		46,432			13,521		5,950			(1,461	)		64,442
Product purchases		152,189			1,867		—			(130	)		153,926
Equity earnings		(1,091	)		—		—			—			(1,091	)

Operating margin (loss)		83,503			22,692		(2,278	)		763			104,680
Depreciation and amortization		9,980			4,974		197			763			15,914
Affiliate G&A expenses		12,119			4,463		637			—			17,219

Operating profit (loss)	$	61,404		$	13,255	$	(3,112	)	$	—		$	71,547


	Three Months Ended September 30, 2008
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products Terminals		Ammonia Pipeline System			Intersegment Eliminations			Total
Transportation and terminals revenues	$	125,533		$	34,472	$	5,128		$	(876	)	$	164,257
Product sales revenues		118,979			8,561		—			—			127,540
Affiliate management fee revenue		183			—		—			—			183

Total revenues		244,695			43,033		5,128			(876	)		291,980
Operating expenses		64,185			14,367		4,771			(1,437	)		81,886
Product purchases		88,169			1,606		—			(252	)		89,523
Equity earnings		(1,722	)		—		—			—			(1,722	)

Operating margin		94,063			27,060		357			813			122,293
Depreciation and amortization		10,711			5,995		207			813			17,726
Affiliate G&A expenses		12,586			4,014		551			—			17,151

Operating profit (loss)	$	70,766		$	17,051	$	(401	)	$	—		$	87,416

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


	Nine Months Ended September 30, 2007
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products Terminals		Ammonia Pipeline System			Intersegment Eliminations			Total
Transportation and terminals revenues	$	340,558		$	96,549	$	13,085		$	(2,479	)	$	447,713
Product sales revenues		480,729			13,123		—			—			493,852
Affiliate management fee revenue		534			—		—			—			534

Total revenues		821,821			109,672		13,085			(2,479	)		942,099
Operating expenses		131,688			40,627		17,470			(4,341	)		185,444
Product purchases		438,548			6,335		—			(389	)		444,494
Equity earnings		(2,960	)		—		—			—			(2,960	)

Operating margin (loss)		254,545			62,710		(4,385	)		2,251			315,121
Depreciation and amortization		29,405			14,806		587			2,251			47,049
Affiliate G&A expenses		37,352			13,402		1,891			—			52,645

Operating profit (loss)	$	187,788		$	34,502	$	(6,863	)	$	—		$	215,427


	Nine Months Ended September 30, 2008
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products Terminals		Ammonia Pipeline System			Intersegment Eliminations			Total
Transportation and terminals revenues	$	353,025		$	104,043	$	16,534		$	(2,386	)	$	471,216
Product sales revenues		414,461			25,161		—			—			439,622
Affiliate management fee revenue		549			—		—			—			549

Total revenues		768,035			129,204		16,534			(2,386	)		911,387
Operating expenses		146,422			42,581		9,837			(4,397	)		194,443
Product purchases		336,367			6,528		—			(512	)		342,383
Gain on assignment of supply agreement		(26,492	)		—		—			—			(26,492	)
Equity earnings		(3,504	)		—		—			—			(3,504	)

Operating margin		315,242			80,095		6,697			2,523			404,557
Depreciation and amortization		31,645			17,557		611			2,523			52,336
Affiliate G&A expenses		38,303			12,588		2,494			—			53,385

Operating profit	$	245,294		$	49,950	$	3,592		$	—		$	298,836

Segment assets	$	1,486,333		$	705,148	$	31,688		$	—		$	2,223,169
Corporate assets													46,672

Total assets												$	2,269,841

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 September 30, 2007 and 2008, we received operating fees from this pipeline company of $0.2 million, which we reported as affiliate management fee revenue. Affiliate management fee revenue for both the nine months ended September 30, 2007 and 2008 was $0.5 million.

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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2007	2008	2007	2008
MGG GP—allocated operating expenses	20,923	21,335	59,798	63,887
MGG GP—allocated G&A expenses	12,160	11,952	34,537	36,045

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 September 30, 2008 were $23.4 million and $18.9 million, respectively, and the long-term affiliate pension and benefits accruals associated with this agreement at December 31, 2007 and September 30, 2008 were $22.4 million and $23.3 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. We do not expect to receive reimbursements under this agreement beyond 2008. The amount of G&A costs required to be reimbursed by MGG to us was $1.9 million and $3.7 million for the three and nine months ended September 30, 2007, respectively, and $0.4 million and $1.2 million for the three and nine months ended September 30, 2008, respectively. Reimbursable G&A costs for the nine months ended September 30, 2007 included a $1.3 million non-cash expense related to a payment by MGG MH to one of our executive officers in connection with the sale by MGG MH of limited partner interests in MGG.

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):


	Period From 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

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In addition to the above, we provided 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 the three and nine months ended September 30, 2007, our operating expenses included $0.7 million and $2.0 million, respectively, of power costs incurred with Public Service company of Oklahoma (“PSO”), which is a subsidiary of AEP. During the three and nine months ended September 30, 2008, our operating expenses included $0.7 million and $1.8 million, respectively, of power costs incurred with PSO. We had no amounts payable to or receivable from PSO or AEP at either December 31, 2007 or September 30, 2008.

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 September 30, 2008, certain of our executive officers collectively owned approximately 5% of MGG MH, which owned approximately 14% of MGG, the owner of our general partner. Therefore, certain of our executive officers also benefit from the distributions we make 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 $0.7025 per unit, our general partner would receive annual distributions of approximately $91.6 million on its combined general partner interest and incentive distribution rights.

6.	Inventory

Inventory at December 31, 2007 and September 30, 2008 was as follows (in thousands):


	December 31, 2007		September 30, 2008
Refined petroleum products	$	65,215	$	—
Transmix		32,824		41,665
Natural gas liquids		16,233		34,282
Additives		5,812		5,187
Other		378		—

Total inventory	$	120,462	$	81,134

We recorded a $6.5 million lower-of-average-cost-or-market adjustment to our transmix inventory in September 2008 related to product price declines on inventories associated with our product over and short and commercial transmix activities. Petroleum product prices have continued to decline since September 30, 2008. Should these lower prices persist through December 31, 2008 and assuming we maintain our existing inventory levels, we will experience additional lower-of-average-cost-or-market adjustments in fourth-quarter 2008.

The decrease in inventory between December 31, 2007 and September 30, 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 (see Note 14—Assignment of Supply Agreement).

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 tables present our consolidated net periodic benefit costs related to these plans during the three and six months ended September 30, 2007 and 2008 (in thousands):


	Three Months Ended September 30, 2007					Nine Months Ended September 30, 2007
	Pension Benefits			Other Post- Retirement Benefits		Pension Benefits			Other Post- Retirement Benefits
Components of Net Periodic Benefit Costs:
Service cost	$	1,430		$	133	$	4,327		$	400
Interest cost		626			257		1,916			770
Expected return on plan assets		(791	)		—		(1,883	)		—
Amortization of prior service cost		169			45		508			133
Amortization of actuarial loss		87			172		314			516

Net periodic benefit cost	$	1,521		$	607	$	5,182		$	1,819


	Three Months Ended September 30, 2008					Nine Months Ended September 30, 2008
	Pension Benefits			Other Post- Retirement Benefits		Pension Benefits			Other Post- Retirement Benefits
Components of Net Periodic Benefit Costs:
Service cost	$	1,368		$	109	$	4,104		$	327
Interest cost		675			257		2,024			772
Expected return on plan assets		(676	)		—		(2,027	)		—
Amortization of prior service cost		169			45		508			133
Amortization of actuarial loss		37			77		112			231

Net periodic benefit cost	$	1,573		$	488	$	4,721		$	1,463

Contributions estimated to be paid in 2008 are $6.0 million and $0.6 million for the pension and other postretirement benefit plans, respectively. Changes in the fair value of MGG GP’s pension plan investments during the fourth quarter of 2008 could result in changes to our estimated contributions to be paid for the 2008 fiscal year.

Debt

Our debt at December 31, 2007 and September 30, 2008 was as follows (in thousands):


	December 31, 2007		September 30, 2008
Revolving credit facility	$	163,500	$	15,000
6.45% Notes due 2014		249,634		249,669
5.65% Notes due 2016		252,494		253,438
6.40% Notes due 2037		248,908		248,917
6.40% Notes due 2018		—		250,497

Total debt	$	914,536	$	1,017,521

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 September 30, 2008, $15.0 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 September 30, 2007 and 2008 was 5.9% and 2.9%, respectively. Borrowings outstanding under this facility of $212.0 million were repaid with the net proceeds from our debt offering of 10-year senior notes completed in July 2008 (see 6.40% Notes due 2018 below).

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 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 5.65% 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. We used an interest rate swap to effectively convert $100.0 million of these notes to floating-rate debt until May 2008 (see Note 9—Derivative Financial Instruments). Including the amortization of the $3.8 million gain realized from unwinding that swap, and the amortization of losses realized on pre-issuance hedges associated with these notes, the weighted average interest rate of these notes at September 30, 2007 and 2008 was 5.9% and 5.7%, respectively. The outstanding principal amount of the notes was increased by $2.7 million at December 31, 2007 for the fair value of the associated swap-to-floating derivative instrument and by $3.7 million at September 30, 2008 for the unamortized portion of the payment received upon termination of that swap.

6.40% Notes due 2018. In July 2008, we issued $250.0 million of 6.40% notes due 2018 in an underwritten public offering. Net proceeds from the offering, after underwriter discounts of $1.6 million and offering costs of $0.4 million, were $248.0 million. The net proceeds were used to repay the $212.0 million of borrowings outstanding under our revolving credit facility at that time, and the balance was used for general partnership purposes. In connection with this offering, we entered into $100.0 million of interest rate swap agreements to hedge against changes in the fair value of a portion of these notes. These agreements effectively change the interest rate on $100.0 million of these notes from 6.40% to a floating rate of six-month LIBOR plus 1.83%. The swap agreements expire on July 15, 2018, the maturity date of the 6.40% notes. Including the impact of this swap, the weighted-average interest rate on borrowings outstanding under the facility at September 30, 2008 was 5.8%.

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

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9.	Derivative Financial Instruments

Financial Instruments With No Hedging Designation

Our butane blending activities generate gasoline products, and we can estimate the timing and quantities of sales of these products. We use forward sales agreements to lock in forward sales prices and the gross margins realized from our butane blending activities. We account for these forward sales agreements as normal sales.

In the third quarter 2008, in addition to forward sales agreements, we began using New York Mercantile Exchange (“NYMEX”) contracts to lock in forward sales prices. Although these NYMEX agreements represent an economic hedge against price changes on the petroleum products we expect to sell in the future, they do not meet the requirements for hedge accounting treatment under Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended; therefore, we have recognized the change in fair value of these agreements currently in earnings. During September 2008, we terminated agreements associated with the sale of 35 thousand barrels of gasoline and we recognized a gain of $0.2 million from unwinding those contracts. At September 30, 2008, the fair value of the remaining agreements, representing 720 thousand barrels of petroleum product, was $12.2 million, which we recognized as energy commodity derivative contracts on our consolidated balance sheet and as product sales revenues on our current consolidated statement of income. These contracts mature between October 2008 and April 2009. At September 30, 2008, we had received $8.2 million in margin cash from these agreements, which we recorded as other current liabilities.

Financial Instruments Designated as Hedges

We use interest rate derivatives to help manage interest rate risk. As of September 30, 2008, we had two interest rate swap agreements outstanding, which we entered into during July 2008 to hedge against changes in the fair value of a portion of $250.0 million of 6.40% notes due 2018 (see Note 8—Debt). These agreements effectively change the interest rate on $100.0 million of these notes to a floating rate of six-month LIBOR plus 1.83%. The swap agreements expire on July 15, 2018, the maturity date of these notes. The fair value of these interest rate swap agreements at September 30, 2008 was $0.5 million, which was recorded on our balance sheet in other non-current assets.

The following financial instruments designated as hedges were settled during 2008:

•

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 accounted for this agreement as a fair value hedge. The notional amount of this agreement was $100.0 million and effectively converted $100.0 million of our 5.65% fixed-rate senior notes issued in October 2004 to floating-rate debt. In May 2008, we terminated this interest rate swap agreement and received $3.8 million, which was recorded as an adjustment to long-term debt and is being amortized over the remaining life of the 5.65% fixed-rate senior notes due 2016.

•

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. In April 2008, we terminated these interest rate swap agreements and received $0.2 million, which was recorded to other income.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following is a summary of the current impact of our historical derivative activity on accumulated other comprehensive income (“AOCI”) as of September 30, 2008 (in thousands):


	Effective Portion of Gains and Losses
				Amount Reclassified to Earnings from AOCI
Hedge	Unamortized Amount Recognized in AOCI			Three Months Ended September 30, 2008			Nine Months Ended September 30, 2008
Cash flow hedges (date executed):
Interest rate swaps 6.40% Notes (April 2007)	$	5,001		$	(43	)	$	(131	)
Interest rate swaps 5.65% Notes (October 2004)		(4,208	)		130			392
Interest rate swaps and treasury lock 6.45% Notes (May 2004)		2,901			(128	)		(384	)

Total cash flow hedges	$	3,694		$	(41	)	$	(123	)

There was no ineffectiveness recognized on the financial instruments disclosed in the above table during the three or nine months ended September 30, 2008.

Fair Value Measurements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard (“SFAS”) No. 157, Fair Value Measurements. The following table summarizes the fair value measurements of our (i) energy commodity derivative contracts; and (ii) interest rate swap agreements as of September 30, 2008, based on the three levels established by SFAS No. 157 (in thousands):


			Asset Fair Value Measurements as of September 30, 2008 using:
	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Energy commodity derivative contracts	$	12,161	$	12,161	$	—	$	—
Interest rate swap agreements		517		—		517		—

Our fair value measurements as of December 31, 2007 using significant other observable inputs for interest rate swap derivatives were $2.7 million.

10.

Commitments and Contingencies

Environmental Liabilities. Liabilities recognized for estimated environmental costs were $57.8 million and $41.8 million at December 31, 2007 and September 30, 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 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 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 of the releases were violations of the Act and that the EPA would impose the maximum penalty. The EPA further indicated that some of

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

those releases may have also violated the Spill Prevention Control and Countermeasure requirements of Section 311(j) of the Act and that additional penalties could be assessed. The DOJ and EPA 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. In June 2008, we agreed to pay a penalty of $5.3 million and perform certain operational enhancements under the terms of a settlement agreement reached with the EPA and DOJ. This agreement led to a reduction of our environmental liability for these matters from $17.4 million to $5.3 million and a reduction of our operating expenses of $12.1 million during second-quarter 2008. Of this reduction, $11.9 million was included as part of the indemnification settlement we reached with a former affiliate (see Indemnification Settlement description below) and, accordingly, was allocated to our general partner. We paid the $5.3 million penalty in September 2008 in settlement of these matters.

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, at the time of the releases, 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.

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 with our former affiliate 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 September 30, 2008, known liabilities that would have been covered by this indemnity agreement were $42.9 million and $26.5 million, respectively. Through September 30, 2008, we have spent $56.9 million of the $117.5 million indemnification settlement amount for indemnified matters, including $22.5 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 $5.2 million at December 31, 2007 and September 30, 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 $7.4 million as of September 30, 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 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 under our LTIP 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 September 30, 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/ (Below) Target Financial Results		Total Unit Award Accrual	Vesting Date	Unrecognized Compensation Expense (Millions)		Period Over Which the Unrecognized Expense Will Be Recognized	Intrinsic Value of Unvested Awards at September 30, 2008 (Millions)
February 2006	168,105	13,448	139,191		293,848	12/31/08	$	0.7	Next 3 months	$	9.5
Various 2006	9,201	3,165	5,432		11,468	12/31/08		*	Next 3 months		0.4
March 2007	2,640	—	—		2,640	12/31/08		*	Next 3 months		0.1
Various 2007:
– Tranche 1	53,230	2,396	50,834		101,668	12/31/09		1.4	Next 15 months		3.3
– Tranche 2	53,230	2,396	(26,534	)	24,300	12/31/09		0.6	Next 15 months		0.8
– Tranche 3	53,230	—	—		—	12/31/09		—	—		—
January 2008	184,340	8,295	—		176,045	12/31/10		4.3	Next 27 months		5.7
Various 2008	14,740	534	—		14,206	12/31/10		0.3	Next 27 months		0.5
Various 2008	40,315	1,814	—		38,501	12/31/11		0.8	Next 39 months		1.2

Total	579,031	32,048	168,923		662,676		$	8.1		$	21.5

*	Less than $0.1 million.

2008 Activity

We settled our 2005 award grants in January 2008 by issuing 196,856 limited partner units and distributing those units to the participants. We paid associated minimum tax withholdings and employer taxes totaling $5.1 million in January 2008.

The payout calculation for 80% of the unit awards approved in February 2006 is based solely on the attainment of a financial metric established by the Compensation Committee. We account for these award grants as equity. The payout calculation for the remaining 20% of the awards is based on both the attainment of a financial metric and the individual employee’s personal performance, which is subjectively determined by the Compensation Committee. We account for these award grants as liabilities.

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 first tranche of the 2007 awards in the first quarter of 2007 and began accruing for the second tranche in the first quarter of 2008, when the Compensation Committee established the financial metric associated with each respective tranche. We will begin accruing costs for the third tranche when the Compensation Committee establishes the associated financial metric for that tranche, which we expect will happen in the first quarter of 2009. The payout calculation for 80% of these unit awards is based solely on the attainment of a financial metric established by the Compensation Committee, and the award grants are accounted for as equity. The payout calculation for the remaining 20% of the awards is based on both the attainment of a financial metric and the individual employee’s personal performance, and the award grants are accounted for as liabilities.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The unit awards approved in January 2008 will vest on December 31, 2010. The payout calculation for 80% of these unit awards is based solely on the attainment of a financial metric established by the Compensation Committee, and the award grants are accounted for as equity. The payout calculation for the remaining 20% of the awards is based on both the attainment of a financial metric and the individual employee’s personal performance, and the award grants are accounted for as liabilities. The other various unit awards approved in 2008 will vest on December 31, 2010 and December 31, 2011. There are no performance metrics associated with the majority of these awards and they are being accounted for as equity.

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		September 30, 2008 Fair Value of Liability Awards
2006 Awards	$	25.23	$	31.70
2007 Awards	$	33.66	$	28.77
2008 Awards	$	30.97	$	25.67

Compensation Expense Summary

Equity-based incentive compensation expense for the three and nine months ended September 30, 2007 and 2008 was as follows (in thousands):


	Three Months Ended September 30, 2007								Nine Months Ended September 30, 2007
	Equity Method		Liability Method		Employer Taxes Paid		Total		Equity Method		Liability Method		Employer Taxes Paid		Total
2004 awards	$	—	$	—	$	—	$	—	$	—	$	—	$	519	$	519
2005 awards		—		68		—		68		—		3,555		—		3,555
2006 awards		692		90		—		782		1,672		595		—		2,267
2007 awards		323		63		—		386		604		151		—		755

Total	$	1,015	$	221	$	—	$	1,236	$	2,276	$	4,301	$	519	$	7,096


	Three Months Ended September 30, 2008								Nine Months Ended September 30, 2008
	Equity Method		Liability Method		Employer Taxes Paid		Total		Equity Method		Liability Method		Employer Taxes Paid		Total
2005 awards	$	—	$	—	$	—	$	—	$	—	$	26	$	580	$	606
2006 awards		514		34		—		548		1,634		201		—		1,835
2007 awards		353		44		—		397		988		144		—		1,132
2008 awards		499		66		—		565		1,182		209		—		1,391

Total	$	1,366	$	144	$	—	$	1,510	$	3,804	$	580	$	580	$	4,964

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Through 9/30/07		1.84875		123,027		51,336		174,363
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		0.67250		44,885		20,910		65,795
08/14/08		0.68750		45,886		21,911		67,797

Through 9/30/08		2.01750		134,655		62,730		197,385
11/14/08 (a)		0.70250		46,887		22,912		69,799

Total	$	2.72000	$	181,542	$	85,642	$	267,184

(a)	Our general partner declared this cash distribution in October 2008 to be paid on November 14, 2008 to unitholders of record at the close of business on November 7, 2008.

13.

Net Income Per Unit

The following table provides details of the basic and diluted net income per unit computations for 2007 (in thousands, except per unit amounts):


	Three Months Ended September 30, 2007					Nine Months Ended September 30, 2007
	Income (Numerator)		Units (Denominator)	Per Unit Amount		Income (Numerator)		Units (Denominator)	Per Unit Amount
Basic net income per limited partner unit	$	43,049	66,550	$	0.65	$	123,690	66,546	$	1.86
Effect of dilutive restricted unit grants		—	—		—		—	3		—

Diluted net income per limited partner unit	$	43,049	66,550	$	0.65	$	123,690	66,549	$	1.86

Units reported as dilutive securities are related to phantom unit grants (see Note 11 – Long Term Incentive Plan).

Basic shares are equal to diluted shares for 2008.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 the time of this acquisition, we believed that the profits we would receive from the supply agreement were below the fair value of our tariff-based shipments on this pipeline and we established a liability for the expected shortfall. On March 1, 2008, we assigned this supply agreement and sold related inventory of $47.6 million 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 first quarter 2008, we obtained a full release from our supply customer; therefore, we had no future obligation to perform under this supply agreement, even in the event the third-party assignee was unable to perform its obligations under the agreement, and as a result, we wrote off the unamortized amount of the liability and recognized a gain of $26.5 million. We continue to earn transportation revenues for the product we ship related to this supply agreement but we 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 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 that includes our tariff charge. All adjustments resulting from this agreement are being reflected in transportation and terminals revenues. For the three months ended September 30, 2008, our 50% share of the profits was $0.1 million. For the nine months ending September 30, 2008, our 50% share of the losses under this agreement was $0.7 million.

Excluding transportation revenues for products shipped under this product supply agreement, we recognized operating profit of $2.6 million and $9.7 million during the three and nine months ended September 30, 2007, respectively, related to the supply agreement. We recognized $2.9 million of operating profit associated with the agreement for the three months ended March 31, 2008.

15.

Recent Accounting Standard

In March 2008, the 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 2008 reporting periods, basic and diluted earnings per limited partner unit would have increased from $0.75 to $0.80 and from $2.45 to $2.82 for the three and nine months ended September 30, 2008, respectively. This EITF is effective beginning January 1, 2009, including all interim periods after that date. Early application is not permitted. 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

On October 22, 2008, our general partner declared a quarterly distribution of $0.7025 per unit to be paid on November 14, 2008 to unitholders of record at the close of business on November 7, 2008. Total distributions to be paid under this declaration are approximately $69.8 million (see Note 12—Distributions for details).

ITEM 2.

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

Introduction

We are a publicly traded limited partnership formed to own, operate and acquire a diversified portfolio of complementary energy assets. We are principally engaged in the transportation, storage and distribution of refined petroleum products. As of September 30, 2008, our three operating segments include:

•

petroleum products pipeline system, which is primarily comprised of our 8,500-mile petroleum products pipeline system, including 48 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

Deterioration of credit, capital and commodity markets. Credit market conditions deteriorated rapidly during the third quarter and beginning of the fourth quarter of 2008. Several major banks and financial institutions failed or were forced to seek assistance through distressed sales or emergency government measures.

Cash generated from operations is our primary source of liquidity for funding debt service, maintenance capital expenditures and quarterly distributions. However, we rely on our revolving credit facility to provide additional liquidity for working capital needs and as an interim source of financing for capital expansion projects. Our revolving credit facility has total committed capacity of $550.0 million, and drawings on that facility at September 30, 2008 were $15.0 million, with an additional $3.3 million obligated for letters of credit. The facility is funded by a syndicate of 18 banks, with an average commitment of $30.6 million per bank. To date, all of the banks in the syndicate have continued to meet their commitments despite the recent market turmoil. If any banks in the syndicate were unable to perform on their commitments to fund the facility, our liquidity could be impaired, which could reduce our ability to fund growth capital expenditures or finance our working capital needs. On October 9, 2008, we borrowed an additional $70.0 million under our revolving credit facility as a precautionary measure to support our short-term liquidity during the current market turmoil. All of the banks in the syndicate performed their obligation to fund this borrowing.

Current market conditions have also resulted in higher credit spreads on long-term borrowings and significantly reduced demand for new corporate debt issues. Equity prices, including our own unit price, have experienced abnormally high volatility during the current period. If these conditions persist, our cost of capital could increase and our ability to finance growth capital expenditures or acquisitions in a cost-effective manner could be reduced. The financial condition of some of our customers and suppliers could also be impaired by current market conditions. We have experienced no material increase in customer bad debts or non-performance by suppliers and have taken additional measures to reduce our exposure to those events. Current market conditions increase the probability that we could experience losses from customer or supplier defaults.

In addition, should current credit and capital markets conditions result in a prolonged economic downturn in the United States, demand for the petroleum products that we transport, store and distribute could decrease, which could in turn result in lower demand for our services and a reduction in our revenues and cash flow.

We rely on insurers as protection against liability claims, property damage, environmental damage and various other risks. Our primary insurers maintain an A.M. Best financial strength rating of A or better, which is considered excellent or superior, and have adjusted policyholder surplus of $1.0 billion or higher. Nevertheless, we continue to monitor this situation as insurers have been and are expected to continue to be impacted by the current credit and capital market environment.

Accounting for employee benefit plans involves numerous assumptions and estimates. Discount rate and expected return on plan assets are two critical assumptions in measuring the cost and benefit obligation of our affiliate’s pension and other post-retirement

benefit plans. We are closely monitoring the capital markets and, based on changes in these two critical assumptions as of October 31, 2008, we do not expect material changes in our pension costs for 2008 or in the contributions we expect to make to our affiliate’s pension plans for the 2008 fiscal year. Contributions beyond 2008 are not currently determinable since the amount of any contribution is heavily dependent on the future economic environment and investment returns on pension trust assets.

Customer bankruptcy. SemGroup, L.P. and several of its subsidiaries (collectively, “SemGroup”) filed for chapter 11 bankruptcy protection during July 2008. Amounts owed to us by SemGroup at the time of their bankruptcy filing were insignificant.

We had several commercial arrangements with SemGroup for the purchase and sale of petroleum products and natural gas liquids (“NGLs”), transportation of petroleum products and NGLs, lease storage and capacity leases for petroleum products and NGLs and leasing of terminal and tank facilities to or from SemGroup at the time of their bankruptcy. Under bankruptcy laws, SemGroup has the ability to cancel certain of the existing contracts it has with us but has not done so to date and remains current on the amounts owed to us. If they do so, we believe we will be able to replace those contracts with other counterparties on terms similar to those in our contracts with SemGroup. On July 31, 2008, we exercised our right to cancel forward petroleum product sales contracts with SemGroup pursuant to which we had agreed to sell petroleum products to SemGroup at various dates between August 2008 and April 2009. We have replaced these contracts with alternative hedges against changes in product prices.

We do not expect our consolidated results of operations, cash flows or financial position to be materially negatively impacted by the SemGroup bankruptcy. However, bankruptcy proceedings are inherently unpredictable and decisions of the bankruptcy court that we cannot foresee at this time could result in a material adverse effect on our consolidated results of operations, cash flows or financial position.

NYMEX contracts. In August 2008, we entered into New York Mercantile Exchange (“NYMEX”) commodity-based futures contracts to hedge our exposure to price fluctuations for refined petroleum products, primarily related to our blending activities. Although these NYMEX agreements represent a hedge against price changes for petroleum products we expect to sell in the future, they do not meet the requirements for hedge accounting treatment. As a result, we will recognize the change in fair value of these agreements at the end of each quarterly period, which could result in material gains or losses in our earnings. At September 30, 2008, we recognized unrealized gains of $12.2 million on our open NYMEX positions due to the recent decline in petroleum products prices. These NYMEX agreements have maturities from October 2008 through April 2009.

We expect to enter into NYMEX agreements to hedge against price changes for additional volumes of petroleum products related to our blending activities and for other commodity hedging activities. To the extent we use NYMEX contracts, we could experience additional risks related to price basis differentials and margin calls. The change in fair value of these NYMEX agreements could result in material impacts to our results of operations and cash flows in future periods.

Distribution. During October 2008, the board of directors of our general partner declared a quarterly cash distribution of $0.7025 per unit for the period of July 1 through September 30, 2008, representing the 30th consecutive distribution increase since our initial public offering in February 2001. This quarterly distribution, totaling $69.8 million, will be paid on November 14, 2008 to unitholders of record on November 7, 2008.

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 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 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 general and administrative (“G&A”) costs, which management does not consider when evaluating the core profitability of our operations.

Three Months Ended September 30, 2007 Compared to Three Months Ended September 30, 2008


	Three Months Ended September 30,						Variance
	Three Months Ended September 30,						Favorable (Unfavorable)
	2007			2008			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)

Transportation and terminals revenues:
Petroleum products pipeline system	$	118.9		$	125.5		$	6.6		6
Petroleum products terminals		32.7			34.4			1.7		5
Ammonia pipeline system		3.7			5.1			1.4		38
Intersegment eliminations		(0.8	)		(0.8	)		—		—

Total transportation and terminals revenues		154.5			164.2			9.7		6
Affiliate management fees		0.2			0.1			(0.1	)	(50	)
Operating expenses:
Petroleum products pipeline system		46.4			64.2			(17.8	)	(38	)
Petroleum products terminals		13.5			14.4			(0.9	)	(7	)
Ammonia pipeline system		6.0			4.7			1.3		22
Intersegment eliminations		(1.5	)		(1.5	)		—		—

Total operating expenses		64.4			81.8			(17.4	)	(27	)

Product margin:

Product sales		167.3			127.6			(39.7	)	(24	)
Product purchases		153.9			89.5			64.4		42

Product margin		13.4			38.1			24.7		184
Equity earnings		1.0			1.7			0.7		70

Operating margin		104.7			122.3			17.6		17
Depreciation and amortization expense		16.0			17.7			(1.7	)	(11	)
Affiliate G&A expense		17.2			17.2			—		—

Operating profit		71.5			87.4			15.9		22

Interest expense (net of interest income and interest capitalized)		12.3			13.4			(1.1	)	(9	)
Debt placement fee amortization		0.2			0.2			—		—

Income before provision (benefit) for income taxes		59.0			73.8			14.8		25
Provision (benefit) for income taxes		(0.4	)		0.5			(0.9	)	(225	)

Net income	$	59.4		$	73.3		$	13.9		23

Operating Statistics:

Petroleum products pipeline system:
Transportation revenue per barrel shipped	$	1.164		$	1.266
Volume shipped (million barrels)		78.6			74.4
Petroleum products terminals:
Marine terminal average storage utilized (million barrels per month)		21.8			23.9
Inland terminal throughput (million barrels)		30.9			26.2
Ammonia pipeline system:
Volume shipped (thousand tons)		133			177

Transportation and terminals revenues increased by $9.7 million resulting from higher revenues for each of our business segments as described below:

•

an increase in petroleum products pipeline system revenues of $6.6 million. Transportation revenues increased as a result of higher average tariffs due in part to our mid-year 2008 tariff escalation, partially offset by lower transportation volumes due primarily to shipment disruptions in third quarter 2008 attributable to Hurricane Ike. In addition, we earned more ancillary fees for leased storage and ethanol and additive blending services;

•

an increase in petroleum products terminals revenues of $1.7 million. Revenues increased at our marine terminals primarily because operating results from additional storage tanks at our Galena Park, Texas facility that were placed into service over

the past year more than offset the storage and ancillary revenues lost as a result of Hurricane Ike. Conversely, our inland terminal revenues decreased slightly due to current quarter product supply constraints in the Southeastern United States created by Hurricanes Ike and Gustav and due to lower demand for petroleum products due to high petroleum prices; and

•

an increase in ammonia pipeline system revenues of $1.4 million due to higher average tariffs as a result of our new tariff agreements and additional shipments resulting from favorable weather and market conditions.

Operating expenses increased by $17.4 million due to higher expenses at our petroleum products pipeline system and petroleum products terminals segments, partially offset by lower costs at our ammonia pipeline system, as described below:

•

an increase in petroleum products pipeline system expenses of $17.8 million primarily due to the timing of system integrity spending. The higher system integrity spending was due to accelerating work that was originally planned to occur in fourth quarter 2008, as well as some work scheduled for 2009, to balance integrity work and resources across all of our assets. Also contributing to the increase in operating expenses were higher environmental expenses due to increased accruals for several historical releases and less favorable product overages (which reduce operating expenses) in the third quarter of 2008;

•

an increase in petroleum products terminals expenses of $0.9 million primarily related to higher maintenance costs as well as higher casualty loss accruals, partially offset by lower property tax assessments; and

•

a decrease in ammonia pipeline system expenses of $1.3 million primarily due to the timing of system integrity costs, partially offset by higher environmental costs. Environmental expenses were higher due to increased accruals for several historical releases.

Product sales revenues in the current period primarily resulted from our petroleum products blending operation, terminal product gains and transmix fractionation. Product margin resulting from product sales and purchases increased by $24.7 million primarily due to higher margins on our petroleum products blending operations, attributable mainly to higher product prices and a $12.2 million unrealized gain related to NYMEX contracts. While these NYMEX contracts represent economic hedges against price changes on product sales we expect to make in future periods, they do not qualify for hedge accounting treatment; therefore, the change in fair value of these agreements was reflected in the current period product margin.

Operating margin increased $17.6 million primarily due to a higher gross margin from product sales in 2008 and higher revenues from each of our segments, partially offset by higher operating expenses for our petroleum products pipeline system.

Depreciation and amortization expense increased by $1.7 million principally related to expansion capital projects placed into service over the past year.

Interest expense, net of interest income and interest capitalized, increased $1.1 million. Our average debt outstanding, excluding fair value adjustments for interest rate hedges, increased to $1.0 billion for third quarter 2008 from $883.2 million for third quarter 2007 principally due to borrowings for expansion capital expenditures. The weighted-average interest rate on our borrowings, after giving effect to the impact of associated fair value hedges, decreased to 5.9% in the current period from 6.1% in the 2007 quarter.

Provision for income taxes was $0.5 million in third quarter 2008 compared to a $0.4 million benefit in third quarter 2007. We reduced our income tax accrual in third quarter 2007 following an evaluation of our partnership-level tax rate, which is based on the financial results of our assets apportioned to the state of Texas.

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2008


	Nine Months Ended September 30,						Variance
	Nine Months Ended September 30,						Favorable (Unfavorable)
	2007			2008			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)
Transportation and terminals revenues:
Petroleum products pipeline system	$	340.6		$	353.0		$	12.4		4
Petroleum products terminals		96.5			104.0			7.5		8
Ammonia pipeline system		13.1			16.5			3.4		26
Intersegment eliminations		(2.5	)		(2.3	)		0.2		8

Total transportation and terminals revenues		447.7			471.2			23.5		5
Affiliate management fees		0.5			0.5			—		—
Operating expenses:
Petroleum products pipeline system		131.7			146.4			(14.7	)	(11	)
Petroleum products terminals		40.6			42.6			(2.0	)	(5	)
Ammonia pipeline system		17.5			9.8			7.7		44
Intersegment eliminations		(4.4	)		(4.4	)		—		—

Total operating expenses		185.4			194.4			(9.0	)	(5	)

Product margin:

Product sales		493.9			439.6			(54.3	)	(11	)
Product purchases		444.5			342.4			102.1		23

Product margin		49.4			97.2			47.8		97
Gain on assignment of supply agreement		—			26.5			26.5		n/a
Equity earnings		2.9			3.5			0.6		21

Operating margin		315.1			404.5			89.4		28
Depreciation and amortization expense		47.1			52.3			(5.2	)	(11	)
Affiliate G&A expense		52.6			53.4			(0.8	)	(2	)

Operating profit		215.4			298.8			83.4		39

Interest expense (net of interest income and interest capitalized)		39.0			36.0			3.0		8
Debt placement fee amortization		2.0			0.5			1.5		75
Debt prepayment premium		2.0			—			2.0		100
Other (income) expense		0.7			(0.2	)		0.9		129

Income before provision for income taxes		171.7			262.5			90.8		53
Provision for income taxes		1.1			1.5			(0.4	)	(36	)

Net income	$	170.6		$	261.0		$	90.4		53

Operating Statistics:

Petroleum products pipeline system:
Transportation revenue per barrel shipped	$	1.154		$	1.197
Volume shipped (million barrels)		226.8			220.6
Petroleum products terminals:
Marine terminal average storage utilized (million barrels per month)		21.6			23.2
Inland terminal throughput (million barrels)		88.4			81.6
Ammonia pipeline system:
Volume shipped (thousand tons)		533			624

Transportation and terminals revenues increased by $23.5 million resulting from higher revenues for each of our business segments as described below:

•

an increase in petroleum products pipeline system revenues of $12.4 million. Transportation revenues increased as a result of higher average tariffs due in part to our mid-year 2007 and 2008 tariff escalations, partially offset by lower transportation volumes due primarily to shipment disruptions in third quarter 2008 attributable to Hurricane Ike and weak demand for petroleum products as a result of higher product prices. We also earned more ancillary revenues related to leased storage, ethanol blending services, capacity leases and facility rentals;

•

an increase in petroleum products terminals revenues of $7.5 million. Revenues increased at our marine terminals primarily due to operating results from additional storage tanks at our Galena Park, Texas facility that were placed into service throughout 2007 and 2008, as well as higher excess throughput fees. Conversely, our inland terminal revenues decreased slightly in 2008 as a result of lower throughput volumes offset in part by higher ethanol blending fees; and

•

an increase in ammonia pipeline system revenues of $3.4 million primarily due to higher average tariff rates charged and additional shipments resulting from favorable weather and market conditions.

Operating expenses increased by $9.0 million as higher expenses at our petroleum products pipeline system and petroleum products terminals segments were partially offset by lower costs related to our ammonia pipeline system, as described below:

•

an increase in petroleum products pipeline system expenses of $14.7 million primarily due to the timing of system integrity spending, less favorable product overages (which reduce operating expenses) in the third quarter of 2008 and higher environmental expenses related to increased accruals for several historical releases. The higher system integrity spending was due to accelerating work that was originally planned to occur in fourth quarter 2008, as well as some work scheduled for 2009, to balance integrity work and resources across all of our assets. Partially offsetting these items was a $12.1 million reduction to our operating expenses in second quarter 2008 due to the favorable settlement of a civil penalty related to historical product releases;

•

an increase in petroleum products terminals expenses of $2.0 million primarily related to higher personnel costs and maintenance spending. These increases were partially offset by gains recognized from insurance proceeds received in 2008 associated with hurricane damages sustained during 2005; and

•

a decrease in ammonia pipeline system expenses of $7.7 million primarily due to the timing of system integrity costs, partially offset by higher environmental expenses. Environmental expenses were higher due to increased accruals for several historical releases.

Product margin resulting from product sales and purchases increased by $47.8 million. The increase in 2008 product margin was primarily attributable to higher product prices and the sale of additional product overages by our petroleum products terminal and the sale of unprocessed transmix by our petroleum products pipeline segment during 2008. Additionally, a $12.2 million unrealized gain was recorded in third quarter 2008 related to the fair value adjustment for our NYMEX commodity futures contracts. Product sales and product purchases were significantly lower during the current period due to the assignment of a supply agreement during first quarter 2008.

The 2008 period benefited from a $26.5 million gain on the assignment of our third-party supply agreement during March 2008.

Operating margin increased $89.4 million primarily due to higher revenues from each of our business segments and higher gross margin from product sales in 2008.

Depreciation and amortization expense increased by $5.2 million primarily related to capital expansion projects placed into service over the past year.

Affiliate G&A expense increased by $0.8 million between periods primarily due to higher personnel, legal and expansion project prospecting costs during 2008, partially offset by lower equity-based incentive compensation expense primarily resulting from a lower fair value for incentive awards accounted for as liabilities.

Interest expense, net of interest income and interest capitalized, decreased $3.0 million due primarily to a lower weighted-average interest rate on our borrowings for 2008. Our average debt outstanding, excluding fair value adjustments for interest rate hedges, increased to $970.3 million for the 2008 period from $883.9 million for the 2007 period principally due to borrowings for expansion capital expenditures; however, the weighted-average interest rate on our borrowings, after giving effect to the impact of associated fair value hedges, decreased to 5.5% in 2008 from 6.5% in 2007.

We incurred debt refinancing expenses of $2.7 million during the 2007 period with no similar expense in 2008. The expenses for 2007 were associated with the early retirement of our pipeline notes during second quarter 2007, originally due in October 2007, and included a debt prepayment premium of $2.0 million as well as related interest rate hedge settlements of $0.7 million, which were recorded as other expense.

Provision for income taxes increased $0.4 million in 2008 due primarily to a change in our partnership-level tax rate from 0.5% in 2007 to 1.0% in 2008. This rate increase resulted from our losing our petroleum product wholesaler status with the state of Texas following our assignment of a supply agreement in March 2008.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

Net cash provided by operating activities was $333.6 million and $177.7 million for the nine months ended September 30, 2008 and 2007, respectively. The $155.9 million increase from 2007 to 2008 was primarily attributable to:

•

$63.9 million increase in net income, excluding the $26.5 million non-cash gain on assignment of supply agreement;

•

$39.3 million decrease in inventories in 2008 versus a $14.4 million increase 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;

•

$16.2 million increase in accounts payable in 2008 versus a $13.1 million decrease in accounts payable in 2007 due primarily to the timing of invoices received from our vendors and suppliers;

•

$3.9 million increase in accrued product purchases in 2008 versus a $19.4 million decrease in accrued product purchases in 2007 due primarily to the timing of invoices received from our vendors and suppliers; and

•

$5.3 million increase in accounts receivable and other accounts receivable in 2008 versus a $19.9 million increase in receivable and other accounts receivable in 2007 due primarily to the timing of payments received from our customers.

These increases were partially offset by:

•

$17.6 million decrease in environmental liabilities in 2008 versus a $2.6 million increase in environmental liabilities in 2007. The decrease in environmental liabilities during 2008 is principally due to the favorable settlement of a civil penalty related to historical product releases; and

•

$18.5 million decrease in the supply agreement deposit in 2008 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 nine months ended September 30, 2008 and 2007 was $219.3 million and $145.0 million, respectively. During 2008, we spent $208.9 million for capital expenditures, which included $29.7 million for maintenance capital and $179.2 million for expansion capital. Additionally, we acquired petroleum products terminals in Bettendorf, Iowa and Wrenshall, Minnesota for cash spending of $12.0 million and $8.6 million, respectively, during 2008. During 2007, we spent $136.1 million for capital expenditures, of which $25.9 million was for maintenance capital and $110.2 million was for expansion capital.

Net cash used by financing activities for the nine months ended September 30, 2008 and 2007 was $94.5 million and $39.0 million, respectively. Cash distributions paid to our unitholders and general partner were $197.4 million and $174.4 million for 2008 and 2007, respectively. During 2008, borrowings from a debt financing of $250.0 million were used to reduce our revolving credit facility by $148.5 million and pay for expansion projects. Net borrowings on our revolving credit facility of $119.5 million and $248.9 million from a debt financing provided cash during 2007. A portion of these borrowings were used to repay the remaining balance of $272.6 million of our pipeline notes during the 2007 period. Capital contributions from our general partner were $2.5 million and $37.6 million during 2008 and 2007, respectively. Capital contributions for 2007 included the final installment payment of $35.0 million from a former affiliate related to an indemnification settlement (see Environmental—Indemnification settlement below).

During third quarter 2008, we paid $67.8 million in cash distributions to our unitholders and general partner. Based on the declared quarterly distribution of $0.7025 per unit associated with third quarter 2008 we intend to pay $69.8 million in distributions during fourth 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 $279.2 million would be paid on an annual basis. Of this amount, $91.6 million, or 33%, is related to our general partner’s 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:

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

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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 third quarter 2008, our maintenance capital spending was $11.5 million, including $0.7 million of spending that would have been covered by indemnifications settled in May 2004. For the nine months ended September 30, 2008, we spent maintenance capital of $29.7 million, including $2.5 million of spending that would have been covered by the May 2004 indemnification settlement and $1.7 million for which we expect reimbursement. 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 $45.0 million, including $7.0 million of maintenance capital that has already been reimbursed to us through our indemnification settlement or expected to be received from third-party reimbursements.

In addition to maintenance capital expenditures, we also incur expansion capital expenditures at our existing facilities. During third quarter 2008, we spent approximately $65.4 million for organic growth projects and acquired a petroleum products terminal already connected to our petroleum products pipeline system for $8.6 million. For the nine months ended September 30, 2008, we have spent $179.2 million for organic growth projects and acquired two petroleum products terminals already connected to our petroleum products pipeline system for $20.6 million. Based on the progress of expansion projects already underway, we expect to spend approximately $300.0 million of growth capital including acquisitions during 2008, with an additional $200.0 million in 2009 and $80.0 million in 2010 to complete these projects.

We rely on our revolving credit facility as an interim source of financing for capital expansion projects. If any of the banks committed to fund our facility were unable to perform on their commitments, our liquidity could be impaired, which could reduce our ability to fund growth capital expenditures. Current market conditions have resulted in higher credit spreads on long-term borrowings and significantly reduced demand for new corporate debt issues. Equity prices, including our own unit price, have experienced abnormally high volatility during the current period. If these conditions persist, our cost of capital could increase and our ability to finance growth capital expenditures or acquisitions in a cost-effective manner could be reduced. Management believes we will have sufficient liquidity to meet our capital expenditure requirements for the remainder of 2008 and for 2009.

Liquidity

As of September 30, 2008, total debt reported on our consolidated balance sheet was $1,017.5 million. The difference between this amount and the $1,015.0 million face value of our outstanding debt results from adjustments related to fair value hedges and unamortized discounts on debt issuances.

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 hedges associated with these notes, the effective interest rate of these notes is 6.3%.

5.65% Notes due 2016. In October 2004, we issued $250.0 million of 5.65% 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. We used an interest rate swap to effectively convert $100.0 million of these notes to floating-rate debt until May 2008 (see Interest Rate Derivatives, below). Including the amortization of the $3.8 million gain realized from unwinding that swap, and the amortization of losses realized on pre-issuance hedges associated with these notes, the weighted average interest rate of these notes at September 30, 2007 and 2008 was 5.9% and 5.7%, respectively. The outstanding principal amount of the notes was increased by $2.7 million at December 31, 2007 for the fair value of the associated swap-to-floating derivative instrument and by $3.7 million at September 30, 2008 for the unamortized portion of the payment received upon termination of that swap.

6.40% Notes due 2037. In April 2007, we issued $250.0 million of 6.40% notes due 2037 in an underwritten public offering. The notes were issued for the discounted price of 99.6%, or $248.9 million, 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, the effective interest rate of these notes is 6.3%.

Interest Rate Derivatives. We use interest rate derivatives to help manage interest rate risk. As of September 30, 2008, we had two interest rate swap agreements outstanding, which we entered into during July 2008 to hedge against changes in the fair value of a portion of our $250.0 million of 6.40% notes due 2018. These agreements effectively change the interest rate on $100.0 million of these notes to a floating rate of six-month LIBOR plus 1.83%. The swap agreements expire on July 15, 2018, the maturity date of these notes.

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 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 September 30, 2008, known liabilities that would have been covered by this indemnity agreement were $42.9 million and $26.5 million, respectively. Through September 30, 2008, we have spent $56.9 million of the $117.5 million indemnification settlement amount for indemnified matters, including $22.5 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.

Ammonia EPA issue. In February 2007, we received notice from the Department of Justice (“DOJ”) that the Environmental Protection Agency (“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, at the time of the releases, 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.

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. Approximately 40% of our tariffs are subject to this indexing methodology while the remaining 60% of the tariffs can be adjusted at our discretion based on competitive factors. The current approved methodology is the annual change in the producer price index for finished goods (“PPI-FG”) plus 1.3%. Based on an actual change in PPI-FG of approximately 3.9% during 2007, we increased virtually all of our published tariffs by the allowed adjustment of approximately 5.2% effective July 1, 2008. Through September 2008, the change in PPI-FG for 2008 is approximately 8%. At this level, we would be allowed to increase our indexed rates by an amount up to 9% consistent with market conditions.

Impact of commodity prices. The recent high pricing environment for petroleum products has resulted in reduced volumes of refined petroleum products, such as gasoline and diesel fuel, we transport on our petroleum products pipeline system and distribute through our inland terminals. A prolonged period of high refined product prices could lead to a further reduction in demand and result in lower shipments on our pipeline system and reduced demand for our terminal services. Our commodity-related activities, such as our petroleum products blending operation, terminal product gains and transmix fractionation, have benefited from the increasing commodity prices as the gross margin we realize from these activities can be substantially higher in periods when refined petroleum prices are increasing. Through the nine months ended September 30, 2008, the benefit of high prices to our commodity-related activities has exceeded the unfavorable impact to our transportation and terminals volumes, resulting in a larger portion of our financial results attributable to commodity-related activities. Management expects our commodity-related activities will continue to be a larger portion of our financial results despite the recent decline in petroleum product prices because of an overall decrease in demand in petroleum products in the markets we serve.

Ammonia operating agreement. Effective July 1, 2008, we assumed operating responsibility for our ammonia pipeline system, which previously had been operated by a third-party pipeline company.

Ammonia contracts. We finalized new five-year transportation agreements with our three ammonia pipeline system customers that extend from July 1, 2008 through June 30, 2013 and, effective July 1, 2008, we increased our tariffs by an average of $4.00 per ton.

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 $7.4 million as of September 30, 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 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 and nine months ended September 30, 2008, we were allocated operating expenses from MGG’s general partner of $21.3 million and $63.9 million, respectively, and G&A expenses of $12.0 million and $36.0 million, respectively. For the three months and nine months ended September 30, 2007, we were allocated operating expenses from MGG’s general partner of $20.9 million and $59.8 million, respectively, and G&A expenses of $12.2 million and $34.5 million, respectively. MGG reimbursed us G&A costs in excess of the defined G&A cap of $0.4 million and $1.2 million for the three and nine months ended September 30, 2008, respectively, and $1.9 million and $3.7 million for the three and nine months ended September 30, 2007, respectively. Our G&A expenses for the year ended 2007 included a $1.3 million non-cash expense related to a payment by MGG MH to one of our executive officers in connection with MGG MH’s 2007 sale of limited partner interests in MGG. 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 September 30, 2008 and 2007 and $0.5 million for both the nine months ended September 30, 2008 and 2007, respectively. 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 September 30, 2008, certain of the executive officers of our general partner collectively own approximately 5% of MGG MH, 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 $0.7025 per unit, MGG would receive annual distributions of approximately $91.6 million on its combined 2% general partner interest and incentive distribution rights.

New Accounting Pronouncements

In June 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities. This FSP clarifies that unvested share-based payment awards that contain nonforfeitable rights to distributions or distribution equivalents, whether paid or unpaid, are participating securities as defined in Statement of Financial Accounting Standard (“SFAS”) No. 128, Earnings Per Share, and are to be included in the computation of earnings per unit pursuant to the two-class method. This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years with prior period earnings per unit data retrospectively adjusted. Early application of this FSP is not permitted. Adoption of this FSP will not have a material impact on our financial position, results of operations or cash flows.

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. This statement identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements that are presented in conformity with GAAP in the United States. The statement will not change our current accounting practices.

In April 2008, the FASB issued FSP No. FAS 142-3, Determination of the Useful Life of Intangible Assets. This FSP amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets. This FSP also expands the disclosures required for recognized intangible assets. This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. Early adoption is prohibited. Adoption of this FSP will not have a material impact on our financial position, results of operations or cash flows.

income and the distributions we pay. For example, had we applied EITF 07-4 to the 2008 reporting periods, basic and diluted earnings per limited partner unit would have increased from $0.75 to $0.80 and from $2.45 to $2.82 for the three and nine months ended September 30, 2008, respectively. This EITF is effective beginning January 1, 2009, including all interim periods after that date. Early application is not permitted. 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.

In March 2008, the FASB issued 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. We do not expect that our adoption of this statement will have a material impact on our results of operations, financial position or cash flows.

In February 2008, the FASB issued 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.

Commodity Price Risk

We use derivatives to help us manage product purchases and sales. Derivatives that qualify for and are designated as normal purchases and sales are accounted for using traditional accrual accounting. As of September 30, 2008, we had commitments under forward purchase contracts for product purchases of approximately 360 thousand barrels that will be accounted for as normal purchases totaling approximately $26.4 million, and we had commitments under forward sales contracts for product sales of approximately 165 thousand barrels that will be accounted for as normal sales totaling approximately $19.7 million.

In August 2008, we entered into New York Mercantile Exchange (“NYMEX”) commodity based futures contracts, representing 755 thousand barrels of gasoline. Although these NYMEX agreements hedge against price changes on the petroleum products we expect to sell in the future, they do not meet the requirements for hedge accounting treatment under Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended; therefore, we have recognized the gain from these agreements currently in earnings. During September 2008, we terminated agreements associated with the sale of 35 thousand barrels of gasoline and we recognized a gain of $0.2 million from unwinding those contracts. At September 30, 2008, the fair value of the remaining agreements, representing 720 thousand barrels of petroleum products, was $12.2 million, which we recognized as energy commodity derivative contracts on our consolidated balance sheet and as product sales revenues on our current consolidated statement of income. These contracts have maturities from October 2008 through April 2009. Based on our open NYMEX contracts at September 30, 2008, a $1.00 per barrel increase in the price of regular gasoline would result in a $0.7 million decrease in our product sales revenues and a $1.00 per barrel decrease in the price of regular gasoline would result in a $0.7 million increase in our product sales revenues.

Interest Rate Risk

As of September 30, 2008, we had $15.0 million outstanding on our variable rate revolving credit facility. We had no other variable rate debt outstanding; however, due to an interest rate swap agreement discussed below, we are exposed to variable interest rates on an additional $100.0 million of our debt. Considering this swap agreement and the amount outstanding on our revolving credit facility as of September 30, 2008, our annual interest expense would change by $0.1 million if LIBOR were to change by 0.125%.

In July 2008, we entered into a total of $100.0 million of interest rate swap agreements to hedge against changes in the fair value of a portion of our $250.0 million notes due July 2018. These swap agreements effectively change the interest rate on $100.0 million of those notes from 6.40% to a floating rate of six-month LIBOR plus 1.83%. The swap agreements expire on July 15, 2018, the maturity date of the 6.40% notes.

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:

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

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

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weather patterns materially different than historical trends;

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development of alternative energy sources;

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increased use of biofuels such as ethanol and biodiesel;

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changes in demand for storage in our petroleum products terminals;

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

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our ability to manage interest rate and commodity price exposures;

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

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

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

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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;

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

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an increase in the competition our operations encounter;

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

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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;

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

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

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changes in general economic conditions in the United States;

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

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

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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;

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

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the condition of the credit and capital markets in the United States;

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the effect of changes in accounting policies;

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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;

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

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the ability of SemGroup, L.P., and its subsidiaries, to perform its contractual obligations to us, or our ability to replace such contracts with third parties or otherwise;

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

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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;

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supply disruption; and

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

This list of important factors is not exclusive. Please refer to “Risk Factors” in our 2007 Annual Report on Form 10-K and to “Risk Factors” in Part II, Item 1A of this 10-Q report and our 10-Q report for the quarterly period ended June 30, 2008. 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

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, at the time of the releases, 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.

In June 2008, we received a Notice of Probable Violation (“NOPV”) from the Department of Transportation, Pipeline and Hazardous Materials Safety Administration with a preliminary assessed civil penalty of $784,000 for alleged violations associated with a May 23, 2005 pipeline release that occurred in the Fairfax Industrial District of Kansas City, Kansas. The alleged violations principally involve allegations of failing to follow our System Integrity Plan. We plan to submit a written response within 30 days of receipt of the NOPV formally requesting a hearing.

In April 2005, we received a NOPV from the Office of Pipeline Safety (“OPS”), as a result of an inspection of our operator qualification records and procedures. The NOPV alleges that probable violations of 49 CFR Part 195.505 occurred in regards to our operator qualification program. The OPS has preliminarily assessed a civil penalty of $183,500. We have submitted a response to the NOPV, participated in a hearing at our request with the OPS and submitted a post-hearing brief.

In March 2004, we received a Corrective Action Order from the OPS as a result of the OPS’ May 2003 inspection of a former affiliates’ Integrity Management Program applicable to our assets. The Corrective Action Order focused on timing of repairs and temporary pressure reductions upon discovery of anomalies. The OPS preliminarily assessed us with a civil penalty of $105,000. Supplemental information was presented to the OPS in September 2004. We are awaiting the OPS’ formal response on this matter.

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

ITEM 1A.

RISK FACTORS

In addition to the information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A, “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007, and in Part II, Item 1A, “Risk Factors” in our quarterly report on Form 10-Q for the quarterly period ended June 30, 2008, which could materially affect our business, financial condition or future results. The risks described below, in our Annual Report on Form 10-K and in our quarterly reports on Form 10-Q, 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 or operating results.

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

Risks Related to Our Business

We hedge receipt or delivery of refined products by utilizing physical purchase and sale agreements, futures contracts traded on the New York Mercantile Exchange (“NYMEX”) or Intercontinental Exchange (“ICE”), options contracts or over-the-counter transactions. These hedging arrangements may not eliminate all price risks, could result in fluctuations in quarterly or annual profits and could result in material cash obligations.

We hedge our exposure to price fluctuations with respect to refined products generated from or used in our operations by utilizing physical purchase and sale agreements, futures contracts traded on the NYMEX or ICE, options contracts or over-the-counter transactions. To the extent these hedges do not qualify for hedge accounting treatment under Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended) or they result in material amounts of ineffectiveness, we could experience material fluctuations in our quarterly or annual results of operations. In addition, to the extent these hedges are entered into on a public exchange, we may be required to post margin which could result in material cash obligations. Finally, these contracts may be for the purchase or sale of product in markets different from those in which we are attempting to hedge our exposure, resulting in a hedge that does not eliminate all price risks.

We may not be able to obtain funding because of the deterioration of the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.

Global financial markets and economic conditions have been, and continue to be, disrupted and volatile, which has caused a substantial deterioration in the credit and capital markets. These conditions, along with significant write-offs in the financial services sector and the re-pricing of credit risk, have made, and will likely continue to make, it difficult to obtain funding for our capital needs.

In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to existing debt, and reduced and, in some cases, ceased to provide funding to borrowers.

If any of our 18 committed lenders under our revolving credit facility were to become unwilling or unable to meet their funding obligations, and if the other committed lenders thereunder were to refuse to provide additional funding to make up the portion of the unfulfilled commitments, we would be unable to use the full borrowing capacity under our revolving credit agreement.

Due to these factors, we cannot be certain that funding for our capital needs from credit and capital markets will be available if needed and, to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due or be required to substantially reduce our capital expenditures and therefore be unable to expand our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.

Many of our customers’ activity levels and spending for our products and services may be impacted by the volatility of oil and natural gas prices and the current deterioration in the credit and capital markets.

Recently, commodity prices have been extremely volatile and have declined substantially. While current commodity prices are important contributors to positive cash flow for our customers, expectations about future prices and price volatility are generally more important for determining future spending levels. Additionally, many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. Recently, there has been a significant decline in the capital markets and the availability of credit. Additionally, many of our customers’ equity values have substantially declined. The combination of a reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit

facilities and the lack of availability of debt or equity financing may result in our customers reducing capital expenditure budgets, curtailing operations or failing to meet their obligations as they come due. A material reduction in, or curtailment of, the operations or growth of our customer base as a whole, or any failure of our customers to meet or continue their contractual obligations to us could have a material adverse effect on our revenues and results of operations.

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 NUMBER		DESCRIPTION
10.1		Services Agreement dated December 24, 2005 between Magellan Midstream Partners, L.P. and Magellan Midstream Holdings GP, LLC.

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.

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized in Tulsa, Oklahoma, on November 3, 2008.


MAGELLAN MIDSTREAM PARTNERS, L.P.

By:		Magellan GP, LLC
		its General Partner

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

INDEX TO EXHIBITS


EXHIBIT NUMBER		DESCRIPTION
10.1		Services Agreement dated December 24, 2005 between Magellan Midstream Partners, L.P. and Magellan Midstream Holdings GP, LLC.

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.