Exhibit 99.1

Report of Independent Registered Public Accounting Firm

The Board of Directors of Magellan GP, LLC

General Partner of Magellan Midstream Partners, L.P.

and the Limited Partners of Magellan Midstream Partners, L.P.

We have audited the accompanying consolidated balance sheets of Magellan Midstream Partners, L.P. as of December 31, 2008 and 2007, and the related consolidated statements of income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of Magellan Midstream Partners, L.P.’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Magellan Midstream Partners, L.P. at December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 3 to the consolidated financial statements, effective December 31, 2006, Magellan Midstream Partners, L.P. adopted Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. As discussed in Note 4 to the consolidated financial statements, the financial statements have been retrospectively revised for the adoption of Emerging Issues Task Force Issue No. 07-4, Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Magellan Midstream Partners, L.P.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2009 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 26, 2009,

except for the impact of the items described in

Note 4, as to which the date is May 18, 2009

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per unit amounts)

	Years Ended December 31,
	2006			2007			2008
Transportation and terminals revenues	$	558,301		$	607,845		$	637,958
Product sales revenues		664,569			709,564			574,095
Affiliate management fee revenues		690			712			733
Total revenues		1,223,560			1,318,121			1,212,786
Costs and expenses:
Operating		244,526			251,601			265,728
Product purchases		605,341			633,909			436,567
Depreciation and amortization		60,852			63,792			71,153
Affiliate general and administrative		67,112			72,587			70,435
Total costs and expenses		977,831			1,021,889			843,883
Gain on assignment of supply agreement		—			—			26,492
Equity earnings		3,324			4,027			4,067
Operating profit		249,053			300,259			399,462
Interest expense		57,478			57,264			56,751
Interest income		(2,097	)		(1,767	)		(1,478	)
Interest capitalized		(2,371	)		(4,452	)		(4,803	)
Debt placement fee amortization		2,681			2,144			767
Debt prepayment premium		—			1,984			—
Other (income) expense		634			728			(375	)
Income before provision for income taxes		192,728			244,358			348,600
Provision for income taxes		—			1,568			1,987
Net income	$	192,728		$	242,790		$	346,613
Allocation of net income:
Limited partners’ interest	$	146,858		$	179,223		$	251,710
General partner’s interest		45,870			63,567			94,903
Net income	$	192,728		$	242,790		$	346,613
Basic net income per limited partner unit	$	2.21		$	2.69		$	3.77
Weighted-average number of limited partner units outstanding used for basic net income per unit calculation		66,361			66,547			66,855
Diluted net income per limited partner unit	$	2.20		$	2.69		$	3.76
Weighted-average number of limited partner units outstanding used for diluted net income per unit calculation		66,613			66,700			66,927

See notes to consolidated financial statements.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands)

	December 31,
	2007			2008
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	33,241
Accounts receivable (net of allowance for doubtful accounts of $10 and $462 at December 31, 2007 and 2008, respectively)		62,834			37,517
Other accounts receivable		10,696			11,073
Affiliate accounts receivable		208			378
Inventory		120,462			47,734
Energy commodity derivative contracts		—			20,200
Other current assets		10,882			15,440
Total current assets		205,082			165,583
Property, plant and equipment		2,435,890			2,724,326
Less: accumulated depreciation		615,329			674,317
Net property, plant and equipment		1,820,561			2,050,009
Equity investments		24,324			23,190
Long-term receivables		7,506			7,119
Goodwill		23,945			26,809
Other intangibles (net of accumulated amortization of $6,743 and $8,290 at December 31, 2007 and 2008, respectively)		7,086			5,539
Debt placement costs (net of accumulated amortization of $2,170 and $2,937 at December 31, 2007 and 2008, respectively)		6,368			7,649
Other noncurrent assets		6,322			10,217
Total assets	$	2,101,194		$	2,296,115
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	39,622		$	39,441
Affiliate accounts payable		12,947			1,942
Affiliate payroll and benefits		23,364			18,119
Accrued interest payable		7,197			15,077
Accrued taxes other than income		21,039			20,151
Environmental liabilities		36,127			19,634
Deferred revenue		20,797			21,492
Accrued product purchases		43,230			23,874
Energy commodity derivatives deposit		—			18,994
Other current liabilities		16,322			16,534
Total current liabilities		220,645			195,258
Long-term debt		914,536			1,083,485
Long-term affiliate payable		1,878			445
Long-term affiliate pension and benefits		22,370			31,787
Supply agreement deposit		18,500			—
Noncurrent portion of product supply liability		24,348			—
Other deferred liabilities		6,081			7,532
Environmental liabilities		21,672			22,166
Commitments and contingencies
Partners’ capital:
Common unitholders (66,546 units and 66,744 units outstanding at December 31, 2007 and 2008, respectively)		1,192,031			1,274,872
General partner		(309,389	)		(296,826	)
Accumulated other comprehensive loss		(11,478	)		(22,604	)
Total partners’ capital		871,164			955,442
Total liabilities and partners’ capital	$	2,101,194		$	2,296,115

See notes to consolidated financial statements.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Years Ended December 31,
	2006			2007			2008
Operating Activities:
Net income	$	192,728		$	242,790		$	346,613
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		60,852			63,792			71,153
Debt placement fee amortization expense		2,681			2,144			767
Debt prepayment premium		—			1,984			—
Loss on sale and retirement of assets		8,031			8,548			7,180
Equity earnings		(3,324	)		(4,027	)		(4,067	)
Distributions from equity investment		4,125			3,800			5,200
Equity-based incentive compensation expense		10,820			9,994			4,751
Pension settlement expense and amortization of prior service cost and actuarial loss		2,068			3,231			1,310
Gain on assignment of supply agreement		—			—			(26,492	)
Changes in components of operating assets and liabilities (Note 3)		26,698			(71,312	)		29,156
Net cash provided by operating activities		304,679			260,944			435,571
Investing Activities:
Property, plant and equipment:
Additions to property, plant and equipment		(168,544	)		(190,182	)		(272,083	)
Proceeds from sale of assets		6,313			961			3,862
Changes in accounts payable		13,934			(4,434	)		661
Acquisitions of businesses		—			—			(38,302	)
Net cash used by investing activities		(148,297	)		(193,655	)		(305,862	)
Financing Activities:
Distributions paid		(207,966	)		(236,144	)		(267,184	)
Net borrowings (payments) under revolver		7,500			143,000			(93,500	)
Borrowings under notes		—			248,900			249,980
Payments on notes		(14,345	)		(272,555	)		—
Debt placement costs		(426	)		(2,683	)		(2,048	)
Payment of debt prepayment premium		—			(1,984	)		—
Net receipt from financial derivatives		—			4,556			10,312
Capital contributions by affiliate		28,742			40,205			3,301
Increase in outstanding checks		—			3,026			2,671
Other		14			—			—
Net cash used by financing activities		(186,481	)		(73,679	)		(96,468	)
Change in cash and cash equivalents		(30,099	)		(6,390	)		33,241
Cash and cash equivalents at beginning of period		36,489			6,390			—
Cash and cash equivalents at end of period	$	6,390		$	—		$	33,241
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.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(In thousands)

	Common			Subordinated			General Partner			Accumulated Other Comprehensive Loss			Total Partners’ Capital
Balance, January 1, 2006	$	1,097,391		$	67,925		$	(355,271	)	$	(2,055	)	$	807,990
Comprehensive income:
Net income		151,134			—			41,594			—			192,728
Amortization of loss on cash flow hedges		—			—			—			212			212
Net gain on cash flow hedges		—			—			—			236			236
Adjustment to additional minimum pension liability		—			—			—			343			343
Total comprehensive income														193,519
Adjustment to recognize the funded status of our affiliate postretirement plans		—			—			—			(17,587	)		(17,587	)
Conversion of subordinated units to common units (5.7 million units)		64,787			(64,787	)		—			—			—
Affiliate capital contributions		—			—			28,742			—			28,742
Distributions		(148,497	)		(3,138	)		(56,331	)		—			(207,966	)
Equity method incentive compensation expense		1,770			—			—			—			1,770
Other		15			—			(1	)		—			14
Balance, December 31, 2006		1,166,600			—			(341,267	)		(18,851	)		806,482
Comprehensive income:
Net income		180,839			—			61,951			—			242,790
Net gain on cash flow hedges		—			—			—			5,018			5,018
Amortization of net loss on cash flow hedges		—			—			—			63			63
Pension settlement expense and amortization of prior service cost and net actuarial loss		—			—			—			3,231			3,231
Adjustment to recognize the funded status of our affiliate postretirement plans		—			—			—			(939	)		(939	)
Total comprehensive income														250,163
Issuance of common units in settlement of 2004 long-term incentive plan awards (0.2 million units)		7,406			—			—			—			7,406
Affiliate capital contributions		—			—			40,205			—			40,205
Distributions		(165,866	)		—			(70,278	)		—			(236,144	)
Equity method incentive compensation expense		3,076			—			—			—			3,076
Other		(24	)		—			—			—			(24	)
Balance, December 31, 2007		1,192,031			—			(309,389	)		(11,478	)		871,164
Comprehensive income:
Net income		251,709			—			94,904			—			346,613
Amortization of net gain on cash flow hedges		—			—			—			(164	)		(164	)
Amortization of prior service cost and net actuarial loss		—			—			—			1,310			1,310
Adjustment to recognize the funded status of our affiliate postretirement plans		—			—			—			(12,272	)		(12,272	)
Total comprehensive income														335,487
Issuance of common units in settlement of 2005 long-term incentive plan awards (0.2 million units)		8,536			—			—			—			8,536
Affiliate capital contributions		—			—			3,301			—			3,301
Distributions		(181,542	)		—			(85,642	)		—			(267,184	)
Equity method incentive compensation expense		4,138			—			—			—			4,138
Balance, December 31, 2008	$	1,274,872		$	—		$	(296,826	)	$	(22,604	)	$	955,442

See notes to consolidated financial statements.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization, Basis of Presentation and Description of Business

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 publicly traded Delaware limited partnership. 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 to provide all general and administrative (“G&A”) services and operating functions required for our operations. Our organizational structure at December 31, 2008, and that of our affiliate entities, as well as how we refer to these affiliates in our notes to consolidated financial statements, is provided below.

(1) MGG GP is MGG’s general partner but does not hold an economic interest; therefore, MGG GP does not receive any distributions from MGG nor is MGG GP allocated any of MGG’s net income.

Operating Segments

We own a petroleum products pipeline system, petroleum products terminals and an ammonia pipeline system. Our reportable segments offer different products and services and are managed separately because each requires different marketing strategies and business knowledge. During 2008, we acquired petroleum products terminals in Bettendorf, Iowa and Wrenshall, Minnesota and a petroleum products terminal in Mt. Pleasant, Texas along with a 76-mile petroleum products pipeline for $38.3 million plus related liabilities assumed of $2.6 million. The results of these facilities have been included in our petroleum products pipeline system segment from their respective acquisition dates.

Petroleum Products Pipeline System. Our petroleum products pipeline system includes approximately 8,700 miles of pipeline and 49 terminals that provide transportation, storage and distribution services. Our petroleum products pipeline system covers a 13-state area extending from Texas through the Midwest to Colorado, North Dakota, Minnesota, Wisconsin and Illinois. The products transported on our pipeline system are primarily gasoline, distillates, LPGs and aviation fuels. Product originates on the system from direct connections to refineries and interconnects with other interstate pipelines for transportation and ultimate distribution to retail gasoline stations, truck stops, railroads, airports and other end-users. We

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

have an ownership interest in Osage Pipe Line Company, LLC (“Osage Pipeline”), which owns the 135-mile Osage pipeline that transports crude oil from Cushing, Oklahoma to El Dorado, Kansas and has connections to National Cooperative Refining Association’s refinery in McPherson, Kansas and the Frontier refinery in El Dorado, Kansas. Our petroleum products blending and fractionation activities are also included in the petroleum products pipeline system segment.

Petroleum Products Terminals. Most of our petroleum products terminals are strategically located along or near third-party pipelines or petroleum refineries. The petroleum products terminals provide a variety of services such as distribution, storage, blending, inventory management and additive injection to a diverse customer group including governmental customers and end-users in the downstream refining, retail, commercial trading, industrial and petrochemical industries. Products stored in and distributed through the petroleum products terminal network include refined petroleum products, blendstocks, crude oils, heavy oils and feedstocks. The terminal network consists of seven marine terminals and 27 inland terminals. Five of our marine terminal facilities are located along the Gulf Coast and two marine terminal facilities are located on the East Coast. Our inland terminals are located primarily in the southeastern United States.

Ammonia Pipeline System. The ammonia pipeline system consists of a 1,100-mile ammonia pipeline and six company-owned terminals. Shipments on the pipeline primarily originate from ammonia production plants located in Borger, Texas and Enid and Verdigris, Oklahoma for transport to terminals throughout the Midwest. The ammonia transported through the system is used primarily as nitrogen fertilizer.

2. Summary of Significant Accounting Policies

Basis of Presentation. Our consolidated financial statements include the petroleum products pipeline system, the petroleum products terminals and the ammonia pipeline system. All intersegment transactions have been eliminated.

Use of Estimates. The preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of our consolidated financial statements, as well as the reported amounts of revenue and expense during the reporting periods. Actual results could differ from those estimates.

Regulatory Reporting. Our petroleum products pipelines are subject to regulation by the Federal Energy Regulatory Commission (“FERC”), which prescribes certain accounting principles and practices for the annual Form 6 report filed with the FERC that differ from those used in these financial statements. Such differences relate primarily to capitalization of interest, accounting for gains and losses on disposal of property, plant and equipment and other adjustments. We follow U.S. generally accepted accounting principles (“GAAP”) where such differences of accounting principles exist.

Cash Equivalents. Cash and cash equivalents include demand and time deposits and other highly marketable securities with original maturities of three months or less when acquired.

Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable represent valid claims against non-affiliated customers and are recognized when products are sold or services are rendered. We extend credit terms to certain customers based on historical dealings and to other customers after a review of various credit indicators. An allowance for doubtful accounts is established for all or any portion of an account where collections are considered to be at risk and reserves are evaluated no less than quarterly to determine their adequacy. Judgments relative to at-risk accounts include the customers’ current financial condition, the customers’ historical relationship with us and current and projected economic conditions. Accounts receivable are written off when the account is deemed uncollectible.

Inventory Valuation. Inventory is comprised primarily of refined petroleum products, natural gas liquids, transmix and additives, which are stated at the lower of average cost or market.

Property, Plant and Equipment. Property, plant and equipment consist primarily of pipeline, pipeline-related equipment, storage tanks and processing equipment. Property, plant and equipment are stated at cost except for impaired assets. Impaired assets are recorded at fair value on the last impairment evaluation date for which an adjustment was required.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Most of our assets are depreciated individually on a straight-line basis over their useful lives; however, the individual components of certain assets, such as some of our older tanks, are grouped together into a composite asset and those assets are depreciated using a composite rate. We assign asset lives based on reasonable estimates when an asset is placed into service. Subsequent events could cause us to change our estimates, which would impact the future calculation of depreciation expense. The depreciation rates for most of our pipeline assets are approved and regulated by the FERC. Assets with the same useful lives and similar characteristics are depreciated using the same rate. The range of depreciable lives by asset category is detailed in Note 6—Property, Plant and Equipment.

The carrying value of property, plant and equipment sold or retired and the related accumulated depreciation is removed from our accounts and any associated gains or losses are recorded on our income statement in the period of sale or disposition.

Expenditures to replace existing assets are capitalized and the replaced assets are retired. Expenditures associated with existing assets are capitalized when they improve the productivity or increase the useful life of the asset. Direct project costs such as labor and materials are capitalized as incurred. Indirect project costs, such as overhead, are capitalized based on a percentage of direct labor charged to the respective capital project. Expenditures for maintenance, repairs and minor replacements are charged to operating expense in the period incurred.

Asset Retirement Obligation. We record asset retirement obligations under the provisions of Statement of Financial Accounting Standard (“SFAS”) No. 143, Accounting for Asset Retirement Obligations and Financial Interpretation (“FIN”) No. 47, Accounting for Conditional Asset Retirement Obligations (as amended). SFAS No. 143 requires the fair value of a liability related to the retirement of long-lived assets be recorded at the time a legal obligation is incurred, if the liability can be reasonably estimated. When the liability is initially recorded, the carrying amount of the related asset is increased by the amount of the liability. Over time, the liability is accreted to its future value, with the accretion recorded to expense. FIN No. 47 clarified that where there is an obligation to perform an asset retirement activity, even though uncertainties exist about the timing or method of settlement, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be determined.

Our operating assets generally consist of underground refined products and ammonia pipelines and related facilities along rights-of-way and above-ground storage tanks and related facilities. Our rights-of-way agreements typically do not require the dismantling, removal and reclamation of the rights-of-way upon permanent removal of the pipelines and related facilities from service. Additionally, management is unable to predict when, or if, our pipelines, storage tanks and related facilities would become completely obsolete and require decommissioning. Accordingly, except for a $1.5 million liability associated with anticipated tank liner replacements, we have recorded no liability or corresponding asset in conjunction with SFAS No. 143 and FIN No. 47 as both the amounts and future dates of when such costs might be incurred are indeterminable.

Equity Investments. We account for investments greater than 20% in affiliates which we do not control by the equity method of accounting. Under this method, an investment is recorded at our acquisition cost, plus our equity in undistributed earnings or losses since acquisition, less distributions received and less amortization of excess net investment. Excess net investment is the amount by which our initial investment exceeded our proportionate share of the book value of the net assets of the investment. We amortize excess net investment over the weighted-average depreciable asset lives of the equity investee as of the date of the equity investment. We evaluate equity investments for impairment annually or whenever events or circumstances indicate that there is an other-than-temporary loss in value of the investment. In the event we determine that the loss in value of an investment is other-than-temporary, we would record a charge to earnings to adjust the carrying value to fair value. We recorded no equity investment impairments for the years ended December 31, 2006, 2007 or 2008.

Goodwill and Other Intangible Assets. We have adopted SFAS No. 142, Goodwill and Other Intangible Assets. In accordance with this Statement, goodwill, which represents the excess of cost over fair value of assets of businesses acquired, is no longer amortized but is evaluated periodically for impairment. Goodwill was $23.9 million at December 31, 2007 and $26.8 million at December 31, 2008. Of our reported goodwill at December 31, 2008, $23.9 million was acquired in transactions involving our petroleum products terminals segment and $2.9 million was acquired in a transaction involving our petroleum products pipeline system segment.

The determination of whether goodwill is impaired is based on management’s estimate of the fair value of our reporting units using a discounted future cash flow (“DFCF”) model as compared to their carrying values. Critical

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

assumptions used in our DFCF model included: (i) time horizon of 20 years, (ii) revenue growth of 1.5% per year and expense growth of 1.5% per year, except G&A costs with an assumed growth of 4.0% per year, (iii) weighted-average cost of capital of 11.5% based on assumed cost of debt of 8.0%, assumed cost of equity of 15.0% and a 50%/50% debt-to-equity ratio, (iv) annual maintenance capital spending growth of 2.5% and (v) 8 times earnings before interest, taxes and depreciation and amortization multiple for terminal value. We selected October 1 as our impairment measurement test date and have determined that our goodwill was not impaired as of October 1, 2006, 2007 or 2008. If impairment were to occur, the amount of the impairment would be charged against earnings in the period in which the impairment occurred. The amount of the impairment would be determined by subtracting the implied fair value of the reporting unit goodwill from the carrying amount of the goodwill.

Judgments and assumptions are inherent in management’s estimates used to determine the fair value of our operating segments. The use of alternate judgments and assumptions could result in the recognition of different levels of impairment charges in the financial statements.

Other intangible assets are amortized over their estimated useful lives of 5 years up to 25 years. The weighted-average asset life of our other intangible assets at December 31, 2008 was approximately 9 years. The useful lives are adjusted if events or circumstances indicate there has been a change in the remaining useful lives. Our other intangible assets are reviewed for impairment whenever events or changes in circumstances indicate that the recoverability of the carrying amount of the intangible asset should be assessed. We recognized no impairments for other intangible assets for the years ended December 31, 2006, 2007 or 2008. Amortization of other intangible assets was $1.6 million during 2006 and $1.5 million each year during both 2007 and 2008.

Impairment of Long-Lived Assets. We have adopted SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. In accordance with this Statement, we evaluate our long-lived assets of identifiable business activities, other than those held for sale, for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management’s estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. The amount of the impairment recognized is calculated as the excess of the carrying amount of the asset over the fair value of the assets, as determined either through reference to similar asset sales or by estimating the fair value using a discounted cash flow approach.

Long-lived assets to be disposed of through sales that meet specific criteria are classified as “held for sale” and are recorded at the lower of their carrying value or the estimated fair value less the cost to sell. Until the assets are disposed of, an estimate of the fair value is re-determined when related events or circumstances change. We had no significant assets classified as “held for sale” during the years ended December 31, 2006, 2007 and 2008.

Judgments and assumptions are inherent in management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize. The use of alternate judgments and assumptions could result in the recognition of different levels of impairment charges in the financial statements.

We recorded impairment against the earnings of our petroleum products pipeline system segment of $3.0 million in 2006 and $2.2 million in 2007. Impairments recorded during 2008 were insignificant. The inputs for the valuation models used in determining the fair value of assets we impaired during 2006, 2007 and 2008 are Level 3—Significant Unobservable Inputs as described in SFAS No. 157, Fair Value Measurements.

Lease Financings. Direct financing leases are accounted for such that the minimum lease payments plus the unguaranteed residual value accruing to the benefit of the lessor is recorded as the gross investment in the lease. The net investment in the lease is the difference between the total minimum lease payment receivable and the associated unearned income.

Debt Placement Costs. Costs incurred for debt borrowings are capitalized as paid and amortized over the life of the associated debt instrument using the effective interest method. When debt is retired before its scheduled maturity date, any remaining placement costs associated with that debt are written off. When we increase the borrowing capacity of our revolving credit facility, the unamortized deferred costs associated with the old revolving credit facility, any fees paid to the creditor and any third-party cost incurred are capitalized and amortized over the term of the new revolving credit facility.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Capitalization of Interest. Interest on borrowed funds is capitalized on projects during construction based on the weighted-average interest rate of our debt. We capitalize interest on all construction projects requiring three months or longer to complete with total costs exceeding $0.5 million.

Pension and Postretirement Medical and Life Benefit Obligations. MGG GP sponsors three pension plans, which cover substantially all of its employees, a postretirement medical and life benefit plan for selected employees and a defined contribution plan. Our affiliate pension and postretirement benefit liabilities represent the funded status of the present value of benefit obligations of these plans.

MGG GP’s pension, postretirement medical and life benefits costs are developed from actuarial valuations. Actuarial assumptions are established to anticipate future events and are used in calculating the expense and liabilities related to these plans. These factors include assumptions management makes with regards to interest rates, expected investment return on plan assets, rates of increase in health care costs, turnover rates and rates of future compensation increases, among others. In addition, subjective factors such as withdrawal and mortality rates are used to develop actuarial valuations. Management reviews and updates these assumptions on an annual basis. The actuarial assumptions that MGG GP uses may differ from actual results due to changing market rates or other factors. These differences could impact the amount of pension and postretirement medical and life benefit expense we have recorded or may record.

Paid-Time Off Benefits. Affiliate liabilities for paid-time off benefits are recognized for all employees performing services for us when earned by those employees. We recognized affiliate paid-time off liabilities of $8.8 million and $9.8 million at December 31, 2007 and 2008, respectively. These balances represent the remaining vested paid-time off benefits of employees who support us. Affiliate liabilities for paid-time off are reflected in the affiliate payroll and benefits balances of the consolidated balance sheets.

Derivative Financial Instruments. We account for derivative instruments in accordance with SFAS No. 133, Accounting for Financial Instruments and Hedging Activities (as amended), which establishes accounting and reporting standards requiring that derivative instruments be recorded on the balance sheet at fair value as either assets or liabilities.

For those instruments that qualify for hedge accounting, the accounting treatment depends on each instrument’s intended use and how it is designated. Derivative financial instruments qualifying for hedge accounting treatment can generally be divided into two categories: (1) cash flow hedges and (2) fair value hedges. Cash flow hedges are executed to hedge the variability in cash flows related to a forecasted transaction. Fair value hedges are executed to hedge the value of a recognized asset or liability. At inception of a hedged transaction, we document the relationship between the hedging instrument and the hedged item, the risk management objectives and the methods used for assessing and testing correlation and hedge effectiveness. We also assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows or fair value of the hedge item. If we determine that a derivative, originally designated as a cash flow or fair value hedge, is no longer highly effective, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in current earnings. The changes in fair value of derivative financial instruments that either do not qualify for hedge accounting or are not designated a hedging instrument are included in current earnings.

As part of our risk management process, we assess the creditworthiness of the financial and other institutions with which we execute financial derivatives. We use, or have used, derivative agreements primarily for fair value hedges of our debt, cash flow hedges of forecasted debt transactions and for forward purchases and forward sales of petroleum products. Such financial instruments involve the risk of non-performance by the counterparty, which could result in material losses to us.

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 December 31, 2008, we had commitments under forward purchase contracts for product purchases of approximately 0.2 million barrels that will be accounted for as normal purchases totaling approximately $8.4 million, and we had commitments under forward sales contracts for product sales of approximately 0.2 million barrels that will be accounted for as normal sales totaling approximately $8.8 million.

We have entered into New York Mercantile Exchange (“NYMEX”) commodity based futures contracts to hedge against price changes on the petroleum products we expect to sell in the future. These contracts do not qualify as normal sales or for hedge accounting treatment under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(as amended); therefore, we recognize gains or losses from these agreements currently in earnings. At December 31, 2008, the fair value of our NYMEX agreements, representing 0.6 million barrels of petroleum products, was $20.2 million, which we recognized as energy commodity derivative contracts on our consolidated balance sheet and product sales revenues on our consolidated statement of income.

We have used interest rate derivatives to help us manage interest rate risk. For derivatives designated as hedging instruments, we report gains, losses and any ineffectiveness from interest rate derivatives in other income in our results of operations. We recognize the effective portion of cash flow hedges, which hedge against changes in interest rates, as adjustments to other comprehensive income. We record the non-current portion of unrealized gains or losses associated with fair value hedges on long-term debt as adjustments to long-term debt with the current portion recorded as adjustments to interest expense. We report the change in fair value of interest rate derivatives that are not designated as hedging instruments currently in earnings.

See Comprehensive Income in this Note 2 for details of the derivative gains and losses included in accumulated other comprehensive loss.

Revenue Recognition. Petroleum pipeline and ammonia transportation revenues are recognized when shipments are complete. For shipments of product under published tariffs that combine transportation and terminalling services, shipments are complete when our customers take possession of its product out of our system through tanker trucks, railcars or third-party pipelines. For all other shipments, where terminalling services are not included in the tariff, shipments are complete when the product arrives at the customer-designated delivery point. Injection service fees associated with customer proprietary additives are recognized upon injection to the customer’s product, which occurs at the time the product is delivered. Leased tank storage, pipeline capacity leases, terminalling, throughput, ethanol loading and unloading services, laboratory testing, data services, pipeline operating fees and other miscellaneous service-related revenues are recognized upon completion of contract services. Product sales are recognized upon delivery of the product to our customers. Product sales are increased for gains and decreased for losses associated with the change in fair value of our NYMEX agreements.

Deferred Transportation Revenues and Costs. Customers on our petroleum products pipeline are invoiced for transportation services when their product enters our system. At each period end, we record all invoiced amounts associated with products that have not yet been delivered (in-transit products) as a deferred liability. Additionally, at each period end we defer the direct costs we have incurred associated with these in-transit products until delivery occurs. These deferred costs are determined using judgments and assumptions that management considers reasonable.

Excise Taxes Charged to Customers. Revenues are recorded net of all amounts charged to our customers for excise taxes.

Variable-Rate Terminalling Agreements. Our operations have historically included terminalling agreements with customers under which we provided storage rental and throughput fees based on discounted rates. In addition to the discounted storage rentals and throughput fees, our revenues also included a variable-rate storage fee equal to half of cumulative profits, in excess of an established threshold, our customer derived from trading petroleum products through our storage tank over the contract period. For all of these agreements, we were under no obligation to share in any trading losses sustained by our customer. Under these agreements, we recognized the discounted storage rental and throughput fees each accounting period as the services were performed. However, the cumulative amounts of trading profits or losses over the contract period that were realized by our customer (and therefore, the revenue we earn related to these shared trading profits) were not determinable until the end of the contract term. For example, trading losses sustained by our customer on the last day of the contract period could offset all trading profits realized up to that point during the year, in which case, the cumulative trading profit over the contract period would be zero. In such a case we would recognize no revenues under the variable-rate portion of the agreement. Based on the circumstances of these agreements and in accordance with Emerging Issues Task Force (“EITF”) No. D-96, Accounting for Management Fees Based on a Formula, our policy is to defer recognition of the variable-rate portion of revenue from these agreements until the end of the contract term. We recognized $6.4 million of variable-rate terminalling revenues when a contract term expired on January 31, 2006 and $3.0 million, $2.8 million and $0.9 million when a contract term expired on December 31, 2006, 2007 and 2008, respectively.

In March 2008, in conjunction with our assignment of a supply agreement, we entered into an additional agreement with the assignee under which we agreed that if the pricing under the supply agreement, less associated operational costs, did not exceed our full tariff charge, then we would share in 50% of any shortfall versus our full tariff, and similarly, we would

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

be entitled to 50% of any excess above a certain threshold that included our tariff charge. The agreement is structured such that our share of the 50% shortfall cannot exceed the tariff we receive from transporting the associated barrels. All adjustments resulting from this agreement have been reflected in transportation and terminals revenues. For the period from inception of the agreement through December 31, 2008, our 50% share of the profits from this agreement was $1.8 million.

G&A Expenses. Under our services agreement, we paid MGG and MGG GP for direct and indirect G&A expenses incurred on our behalf. Under our omnibus agreement, MGG reimbursed us for the expenses in excess of a G&A cap. The amount of G&A expense reimbursed to us by MGG has been recognized as a capital contribution by our general partner with the associated expense specifically allocated to our general partner.

Equity-Based Incentive Compensation Awards. Our general partner has issued incentive awards of phantom units, without distribution equivalent rights, representing limited partner interests in us to certain employees of MGG GP who support us. In addition, our general partner has issued phantom units with distribution equivalent rights to certain of its directors. These awards are accounted for as prescribed in SFAS No. 123(R), Share-Based Payments.

Under SFAS No. 123(R) we classify unit award grants as either equity or liabilities. Fair value for award grants classified as equity is determined on the grant date of the award and this value is recognized as compensation expense ratably over the requisite service period, which is the vesting period of each unit award. Fair value for equity awards is calculated as the closing price of our common units representing limited partner interests in us on the grant date reduced by the present value of expected per-unit distributions to be paid during the requisite service period. Unit award grants classified as liabilities are re-measured at fair value on the close of business at each reporting period end until settlement date. Compensation expense for liability awards for each period is the re-measured value of the award grants times the percentage of the requisite service period completed less previously-recognized compensation expense. Compensation expense related to unit-based payments is included in operating and G&A expenses on our consolidated statements of income.

Certain unit award grants include performance and other provisions, which can result in payouts to the recipients from zero up to 200% of the amount of the award. Additionally, certain unit award grants are also subject to personal and other performance components which could increase or decrease the number of units to be paid out by 20%. Judgments and assumptions of the final award payouts are inherent in the accruals we record for unit-based incentive compensation costs. The use of alternate judgments and assumptions could result in the recognition of different levels of unit-based incentive compensation costs in our financial statements.

Environmental. Environmental expenditures that relate to current or future revenues are expensed or capitalized based upon the nature of the expenditures. Expenditures that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental costs are probable and can be reasonably estimated. Environmental liabilities are recorded on an undiscounted basis except for those instances where the amounts and timing of the future payments are fixed or reliably determinable. We use the risk-free interest rate to discount these liabilities. At December 31, 2008, expected payments on discounted liabilities were $0.3 million during each year in 2009, 2010 and 2011 and $0.2 million each year in 2012 and 2013 and $4.4 million for all periods thereafter. A reconciliation of our undiscounted environmental liabilities to amounts reported on our consolidated balance sheets is provided in the table below (in thousands). See Note 15—Commitments and Contingencies for a discussion of the changes in our environmental liabilities between December 31, 2007 and December 31, 2008.

	Year Ended December 31,
	2007			2008
Aggregated undiscounted environmental liabilities	$	63,346		$	47,549
Amount of environmental liabilities discounted		(5,547	)		(5,749	)
Environmental liabilities, as reported	$	57,799		$	41,800

Environmental liabilities are recorded independently of any potential claim for recovery. Accruals related to environmental matters are generally determined based on site-specific plans for remediation, taking into account currently available facts, existing technologies and presently enacted laws and regulations. Accruals for environmental matters reflect our prior remediation experience and include an estimate for costs such as fees paid to contractors and outside engineering, consulting and law firms. We maintain selective insurance coverage, which may cover all or portions of certain

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

environmental expenditures. Receivables are recognized in cases where the realization of reimbursements of remediation costs is considered probable. We would sustain losses to the extent of amounts we have recognized as environmental receivables if the counterparties to those transactions become insolvent or are otherwise unable to perform their obligations to us.

We have determined that certain costs would have been covered by indemnifications from a former owner of our general partner, which we have settled (see Note 15—Commitments and Contingencies). We make judgments on what would have been covered by these indemnifications and specifically allocate these costs to our general partner.

The determination of the accrual amounts recorded for environmental liabilities include significant judgments and assumptions made by management. The use of alternate judgments and assumptions could result in the recognition of different levels of environmental remediation costs in our financial statements.

Income Taxes. We are a partnership for income tax purposes and therefore have not been subject to federal income taxes or state income taxes. The tax on our net income is borne by the individual partners through the allocation of taxable income. Net income for financial statement purposes may differ significantly from taxable income of unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in us is not available to us.

During 2006, the state of Texas passed a law that imposed a partnership-level tax on us beginning in 2007 based on the net revenues of our assets apportioned to the state of Texas. This tax is reflected as provision for income taxes in our results of operations for the years ended December 31, 2007 and 2008.

Allocation of Net Income. For purposes of calculating earnings per unit, we allocate net income to our general partner and limited partners each period under the provisions of EITF Issue No. 07-4, Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships. Accordingly, the excess of distributions over earnings or excess of earnings over distributions for each period are allocated to our general partner based on the general partner’s ownership interest at the time. Our general partner is also directly charged with specific costs that it has individually assumed and for which the limited partners are not responsible (see Note 4—Allocation of Net Income). We have retrospectively applied the provisions of EITF No. 07-4 to all periods presented in this report.

For purposes of determining capital balances, for those periods when distributions exceed net income, we allocate net income to our general partner and limited partners based on their proportionate share of contractually-determined cash distributions declared and paid following the close of each quarter with adjustments made for any charges specifically allocated to our general partner. For periods when net income exceeds distributions, we allocate net income to our general partner and limited partners up to the amount of cash distributions paid for that period based on the contractually-determined cash distributions paid to each. The excess of net income over distributions is allocated based on the contractual terms of our partnership agreement. The general partner’s proportionate share of income is further adjusted for direct charges.

Net Income Per Unit. Basic net income per unit for each period is calculated by dividing the limited partners’ allocation of net income by the weighted-average number of limited partner units outstanding. Certain directors of our general partner have been awarded phantom units that carry distribution equivalent rights. These phantom units are included in the weighted-average number of basic limited partner units outstanding. Diluted net income per unit for each period is the same calculation as basic net income per unit, except the weighted-average units outstanding include the dilutive effect of phantom unit grants associated with our long-term incentive plan.

Comprehensive Income. We account for comprehensive income in accordance with SFAS No. 130, Reporting Comprehensive Income. Our comprehensive income was determined based on net income adjusted for changes in other comprehensive income (loss) from our derivative hedging transactions, related amortization of realized gains/losses and adjustments to record our affiliate pension and postretirement benefit obligation liabilities at the funded status of the present value of the benefit obligations. We have recorded total comprehensive income with our consolidated statement of partners’ capital as allowed under SFAS No. 130.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Amounts included in accumulated other comprehensive loss are as follows (in thousands):

	Derivative Gains (Losses)			Minimum Pension Liability			Pension and Postretirement Liabilities			Accumulated Other Comprehensive Loss
Balance, January 1, 2006	$	(1,712	)	$	(343	)	$	—		$	(2,055	)
Amortization of loss on cash flow hedges		212			—			—			212
Net gain on cash flow hedges		236			—			—			236
Adjustment to additional minimum pension liability		—			343			—			343
Adjustment to recognize the funded status of our affiliate postretirement benefit plans		—			—			(17,587	)		(17,587	)
Balance, December 31, 2006		(1,264	)		—			(17,587	)		(18,851	)
Net gain on cash flow hedges		5,018			—			—			5,018
Amortization of net loss on cash flow hedges		63			—			—			63
Pension settlement expense and amortization of prior service cost and net actuarial loss		—			—			3,231			3,231
Adjustment to recognize the funded status of our affiliate postretirement benefit plans		—			—			(939	)		(939	)
Balance, December 31, 2007		3,817			—			(15,295	)		(11,478	)
Amortization of net gain on cash flow hedges		(164	)		—			—			(164	)
Amortization of prior service cost and net actuarial loss		—			—			1,310			1,310
Adjustment to recognize the funded status of our affiliate postretirement benefit plans		—			—			(12,272	)		(12,272	)
Balance, December 31, 2008	$	3,653		$	—		$	(26,257	)	$	(22,604	)

New Accounting Pronouncements

In December 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) FAS 132(R)-1, Employers' Disclosures about Postretirement Benefit Plan Assets. This FSP expands the disclosure requirements for employer pension plans and other postretirement benefit plans to include factors that are pertinent to an understanding of investment policies and strategies. The additional disclosure requirements include: (i) for annual financial statements, the fair value of each major category of plan assets separately for pension and other postretirement plans, (ii) a narrative description of the basis used to determine the expected long-term rate of return on asset assumptions, (iii) information to enable users of financial statements to assess the inputs and valuation techniques used to develop fair value measurements of plan assets at the annual reporting date, (iv) for fair value measurements using unobservable inputs, disclosure of the effect of the measurements on changes in plan assets for the period. This FSP is effective for fiscal years ending after December 15, 2009, with early application permitted. Provisions of this FSP are not required for earlier periods that are presented for comparative purposes. The adoption of this FSP will not have a material impact on our financial position, results of operations or cash flows.

In September 2008, the FASB issued EITF No. 08-6 Equity Method Investment Accounting Considerations. This EITF requires entities to measure its equity method investments initially at cost in accordance with SFAS No. 141(R) Business Combinations. Further, the EITF clarified that entities should not separately test an investee's underlying indefinite-lived intangible asset for impairment; however, they are required to recognize other-than-temporary impairments of an equity method investment in accordance with Accounting Principles Bulletin No. 18, The Equity Method of Accounting for Investments in Common Stock. In addition, entities are required to account for a share issuance by an equity method investee as if the investor had sold a proportionate share of its investment. Any gain or loss to the investor resulting from an investee's share issuance is to be recognized in earnings. This EITF is effective in fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years and is to be applied prospectively. Earlier application by an entity that has previously adopted an alternative accounting policy is not permitted. Adoption of this EITF will not have a material impact on our financial position, results of operations or cash flows.

In June 2008, the FASB issued FSP No. EITF 03- 6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities. This FSP clarified that unvested share-based payment awards that

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

contain nonforfeitable rights to distributions or distribution equivalents, whether paid or unpaid, are participating securities as defined in 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. Adoption of this FSP did 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.

In March 2008, the FASB ratified EITF Issue No. 07-4, Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships. We adopted EITF No. 07-4 on January 1, 2009, which is effective for interim periods. EITF No. 07-4 requires retrospective application; therefore, we have restated all prior period earnings per limited partner unit in this report. Under EITF No. 07-4, the excess of distributions over earnings and/or excess of earnings over distributions for each period are allocated to our general partner based solely on the general partner’s ownership interest at the time. Our previous accounting practice, for purposes of calculating earnings per unit, was to allocate net income to the general partner based on the general partner’s share of total or pro forma distributions, as appropriate, including incentive distribution rights. The effect of adopting this EITF is: (i) for periods when net income exceeds distributions, our reported earnings per limited partner unit will be higher than under our previous accounting practice and (ii) for periods when distributions exceed net income, our reported earnings per limited partner unit will be lower than under our previous accounting practice. These differences have been significant to the calculation of earnings per limited partner unit for those periods where there are significant differences between our net income and the distributions we pay. See Note 4—Allocation of Net Income for a discussion of the differences of our reported earnings per limited partner unit under EITF No. 07-4 and our previous accounting methodology.

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. Our adoption of this Statement will not have a material impact on our financial position, results of operations 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(R), 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. Adoption of this FSP did not have a material effect on our financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 141(R), Business Combinations. This Statement requires, among other things, that entities; (i) recognize, with certain exceptions, 100% of the fair values of assets acquired, liabilities assumed and

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

non-controlling interests in acquisitions of less than a 100% controlling interest when the acquisition constitutes a change in control of the acquired entity; (ii) measure acquirer shares issued in consideration for a business combination at fair value on the acquisition date; (iii) recognize contingent consideration arrangements at their acquisition-date fair values, with subsequent changes in fair value generally reflected in earnings; (iv) recognize, with certain exceptions, pre-acquisition loss and gain contingencies at their acquisition-date fair values; (v) expense, as incurred, acquisition-related transaction costs; and (vi) capitalize acquisition-related restructuring costs only if the criteria in SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities (as amended) are met as of the acquisition date. This Statement is to be applied prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. Early application is prohibited. We do not expect the initial adoption of this Statement to have a material impact on our financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 160, Non-Controlling Interests in Consolidated Financial Statements. This Statement requires, among other things, that: (i) the non-controlling interest be clearly identified and presented in the consolidated statement of financial position within equity, but separate from the parent’s equity; (ii) the amount of consolidated net income attributable to the parent and to the non-controlling interest be clearly identified and presented on the face of the consolidated statement of income; (iii) all changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently (as equity transactions); (iv) when a subsidiary is deconsolidated, any retained non-controlling equity investment in the former subsidiary be initially measured at fair value. The gain or loss on the deconsolidation of the subsidiary is measured using the fair value of any non-controlling equity investment rather than the carrying amount of that retained investment; and (v) sufficient disclosures be made to clearly identify and distinguish between the interests of the parent and the interests of non-controlling owners. SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. This Statement did not have a material impact on our financial position, results of operations or cash flows.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities. This Statement permits entities to choose to measure many financial instruments and certain other items at fair value, with the objective of mitigating volatility in reported earnings caused by measuring related assets and liabilities differently (without being required to apply complex hedge accounting provisions). We can make an election at the beginning of each fiscal year beginning after November 15, 2007 to adopt this Statement. We do not plan to adopt this Statement.

In January 2007, the FASB issued Revised Statement 133 Implementation Issue No. G19, Cash Flow Hedges: Hedging Interest Rate Risk for the Forecasted Issuances of Fixed-Rate Debt Arising from a Rollover Strategy. This Implementation Issue clarified that in a cash flow hedge of a variable-rate financial asset or liability, the designated risk being hedged cannot be the risk of changes in its cash flows attributable to changes in the specifically identified benchmark rate if the cash flows of the hedged transaction are explicitly based on a different index. The effective date of this guidance for us was April 1, 2007. Our adoption of this Implementation Issue did not have a material impact on our financial position, results of operations or cash flows.

In January 2007, the FASB issued Statement 133 Implementation Issue No. G26, Cash Flow Hedges: Hedging Interest Cash Flows on Variable-Rate Assets and Liabilities That Are Not Based on a Benchmark Interest Rate. This Implementation Issue clarified, given the guidance in Implementation Issue No. G19, that an entity may hedge the variability in cash flows by designating the hedged risk as the risk of overall changes in cash flows. Our adoption of this Implementation Issue did not have a material impact on our financial position, results of operations or cash flows.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

3. Consolidated Statements of Cash Flows

Changes in the components of operating assets and liabilities are as follows (in thousands):

	Year Ended December 31,
	2006			2007			2008
Accounts receivable and other accounts receivable	$	(8,843	)	$	(8,512	)	$	24,940
Affiliate accounts receivable		5,052			275			(170	)
Inventory		(13,395	)		(28,912	)		72,728
Energy commodity derivative contracts, net of margin deposit		—			—			(1,206	)
Supply agreement deposit		1,000			5,000			(18,500	)
Accounts payable		16,107			(11,493	)		(842	)
Affiliate accounts payable		921			(3,782	)		(2,873	)
Affiliate payroll and benefits		1,488			4,688			(5,245	)
Accrued interest payable		(362	)		(2,069	)		7,880
Accrued taxes other than income		153			3,579			(894	)
Accrued product purchases		28,326			(19,868	)		(19,356	)
Current and noncurrent environmental liabilities		(439	)		34			(18,549	)
Other current and noncurrent assets and liabilities		(3,310	)		(10,252	)		(8,757	)
Total	$	26,698		$	(71,312	)	$	29,156

At December 31, 2006, in accordance with the additional minimum liability provisions of SFAS No. 87, Employers’ Accounting for Pensions and the transition provisions of SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, we increased our long-term affiliate pension and benefits by $15.6 million and certain other accounts by $2.0 million, resulting in a $17.6 million increase in accumulated other comprehensive loss. At December 31, 2007 and 2008, we increased long-term affiliate pension and benefits by $0.9 million and $12.3 million, respectively, resulting in an increase in accumulated other comprehensive loss. These non-cash amounts are not reflected in the statements of cash flows.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

4. Allocation of Net Income

On January 1, 2009, we adopted EITF No. 07-4, Application of the Two-Class Method Under FASB Statement No. 128 to Master Limited Partnerships. Under EITF No. 07-4, the excess of distributions over earnings or excess of earnings over distributions for each period are allocated to our general partner based on the general partner’s ownership interest at the time. We have retrospectively applied the provisions of EITF No. 07-4 to the allocation of net income for the periods presented below. For the accounting periods presented below, the allocation of net income between our general partner and limited partners is as follows (in thousands, except percentages):

	Year Ended December 31,
	2006			2007			2008
Net income	$	192,728		$	242,790		$	346,613
Direct charges (credits) to general partner:
Reimbursable G&A costs (a)		4,665			6,191			2,072
Previously indemnified environmental charges		8,987			4,426			(6,416	)
Total direct charges (credits) to general partner		13,652			10,617			(4,344	)
Income before direct charges (credits) to general partner		206,380			253,407			342,269
Less: Cash distributions paid for the period		214,754			243,646			274,407
Undistributed income / (distributions in excess of income)	$	(8,374	)	$	9,761		$	67,862
Weighted-average ownership interests:
Limited partners		98.001	%		98.007	%		98.013	%
General partner		1.999	%		1.993	%		1.987	%
Total ownership interests		100.000	%		100.000	%		100.000	%
Allocation of net income:
Limited partner allocation:
Allocation of undistributed income / (distributions in excess of income)	$	(8,207	)	$	9,567		$	66,513
Cash distributions paid for the period		155,065			169,656			185,197
Net income allocated to limited partners	$	146,858		$	179,223		$	251,710
General partner allocation:
Allocation of undistributed income / (distributions in excess of income)	$	(167	)	$	194		$	1,349
Cash distributions paid for the period		59,689			73,990			89,210
Direct (charges) credits to general partner		(13,652	)		(10,617	)		4,344
Net income allocated to general partner	$	45,870		$	63,567		$	94,903
Limited partners’ allocation of net income	$	146,858		$	179,223		$	251,710
General partner’s allocation of net income		45,870			63,567			94,903
Net income	$	192,728		$	242,790		$	346,613

(a) A former executive officer of our general partner had an investment in MGG MH, which until December 2008 indirectly owned a portion of our general partner. This former executive officer left the company during the fourth quarter of 2006 and we were allocated $3.0 million of G&A compensation expense associated with certain distribution payments made by MGG MH to this individual. Reimbursable G&A costs for 2007 and 2008 included $2.1 million and $0.4 million, respectively, of non-cash expenses related to payments by MGG MH to one of our current executive officers. Because the limited partners did not share in these costs, they were allocated to our general partner.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The difference between the amounts of net income allocated to the limited and general partners and the related earnings per unit calculations under EITF No. 07-4 and our previous accounting methodology are provided in the table below (in thousands):

	(in thousands, except per unit amounts)
	Current Accounting Under EITF 07-4		As Previously Reported		Difference
Year Ended December 31, 2006
Net income allocated to the limited partners	$	146,858	$	148,881	$	(2,023	)
Basic earnings per limited partner unit	$	2.21	$	2.24	$	(0.03	)
Diluted earnings per limited partner unit	$	2.20	$	2.24	$	(0.04	)
Year Ended December 31, 2007
Net income allocated to the limited partners	$	179,223	$	173,330	$	5,893
Basic and diluted earnings per limited partner unit	$	2.69	$	2.60	$	0.09
Year Ended December 31, 2008
Net income allocated to the limited partners	$	251,710	$	219,136	$	32,574
Basic earnings per limited partner unit	$	3.77	$	3.28	$	0.49
Diluted earnings per limited partner unit	$	3.76	$	3.27	$	0.49

For purposes of determining the capital balances of the general partner and the limited partners, the allocation of net income was as follows (in thousands):

	Year Ended December 31,
	2006			2007			2008
Allocation of net income to general partner:
Net income	$	192,728		$	242,790		$	346,613
Direct charges to general partner:
Reimbursable G&A costs		4,665			6,191			2,072
Previously indemnified environmental charges (credits)		8,987			4,426			(6,416	)
Total direct charges (credits) to general partner		13,652			10,617			(4,344	)
Income before direct charges (credits) to general partner		206,380			253,407			342,269
General partner’s share of income (a)		26.77	%		28.64	%		26.46	%
General partner’s allocated share of net income before direct charges (credits)		55,246			72,568			90,560
Direct charges (credits) to general partner		13,652			10,617			(4,344	)
Net income allocated to general partner	$	41,594		$	61,951		$	94,904
Net income	$	192,728		$	242,790		$	346,613
Less: net income allocated to general partner		41,594			61,951			94,904
Net income allocated to limited partners	$	151,134		$	180,839		$	251,709

(a) For periods when the distributions we pay exceed our net income, the general partner’s percentage share of income is its proportion of cash distributions paid for the period. For periods when net income exceeds distributions, we allocate net income to our general partner and limited partners up to the amount of cash distributions paid for that period based on the contractually-determined cash distributions paid to each. The excess of net income over distributions is based on the contractual terms of our partnership agreement. The general partner’s proportionate share of income is adjusted for direct charges.

Excluding the payments by MGG Midstream Holdings, L.P. (“MGG MH”) to certain of our executive officers of $3.0 million, $2.1 million and $0.4 million in 2006, 2007 and 2008, respectively, the reimbursable G&A costs in the tables above represent G&A expenses charged against our income during the periods presented that were required to be reimbursed to us by our general partner under the terms of the omnibus agreement. Because the limited partners do not share in these costs, we allocated these G&A expense amounts directly to our general partner. We record the reimbursements by our general partner as capital contributions. In 2004, 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 15—Commitments and Contingencies). Since our limited partners do not share in these costs, we have allocated the expenses and credits related to this previous indemnification agreement directly to our general partner.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

5. Inventory

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

	December 31,
	2007		2008
Refined petroleum products	$	65,215	$	20,917
Transmix		32,824		13,099
Natural gas liquids		16,233		7,534
Additives		5,812		6,184
Other		378		—
Total inventory	$	120,462	$	47,734

During 2008 we recorded a $19.7 million lower-of-average-cost-or-market adjustment to our transmix inventory associated with our pipeline product overages and shortages. This adjustment was included in operating expenses on our consolidated statements of income. In addition, during 2008, we recorded lower-of-average-cost-or-market adjustments of $6.4 million and $3.0 million to our refined petroleum products inventory and transmix inventory, respectively, associated with our petroleum products blending and fractionation activities. These adjustments were recorded as a component of product purchases on our consolidated statements of income.

The decrease in refined petroleum products inventory from 2007 to 2008 was primarily attributable to the sale of inventory in connection with the assignment of a product supply agreement to a third-party entity effective March 1, 2008, as well as a significant decrease in the prices of products that comprise our inventory during 2008.

6. Property, Plant and Equipment

Property, plant and equipment consisted of the following (in thousands):

	December 31,				Estimated Depreciable Lives
	2007		2008
Construction work-in-progress	$	112,891	$	120,521
Land and rights-of-way		52,937		55,069
Carrier property		1,275,714		1,339,542	6 – 59 years
Buildings		14,514		19,095	20 – 53 years
Storage tanks		411,010		499,457	20 – 40 years
Pipeline and station equipment		210,064		214,701	3 – 59 years
Processing equipment		301,115		405,412	3 – 56 years
Other		57,645		70,529	3 – 48 years
Total	$	2,435,890	$	2,724,326

Carrier property is defined as pipeline assets regulated by the FERC. Other includes interest capitalized at December 31, 2007 and 2008 of $22.5 million and $25.4 million, respectively. Depreciation expense for the years ended December 31, 2006, 2007 and 2008 was $59.3 million, $62.2 million and $69.6 million, respectively.

7. Major Customers and Concentration of Risks

Major Customers. The percentage of revenue derived by customers that accounted for 10% or more of our consolidated total revenues is provided in the table below. No other customer accounted for more than 10% of our consolidated total revenue for 2006, 2007 or 2008. The majority of the revenues from Customers A, B and C resulted from

19

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

sales to those customers of refined petroleum products that we generated in connection with our petroleum products blending and fractionation activities. Because the products sold are common commodities, primarily gasoline and diesel, we believe that the loss of Customer A, B or C would not have a material adverse effect on us. In general, accounts receivable from these customers are due within 3 days of sale. Prior to August 2006, Customer E purchased petroleum products from us pursuant to a third-party supply agreement. In August 2006, Customer E assigned its rights under this supply agreement to Customer D. In March 2008, we assigned our obligations under this supply agreement to a third party (see Note 21—Assignment of Supply Agreement).

	Year Ended December 31,
	2006		2007		2008
Customer A	2	%	2	%	12	%
Customer B	1	%	1	%	12	%
Customer C	11	%	13	%	8	%
Customer D	18	%	33	%	2	%
Customer E	29	%	0	%	0	%
Total	61	%	49	%	34	%

Concentration of Risks. We transport, store and distribute petroleum products for refiners, marketers, traders and end-users of those products. The major concentration of our petroleum products pipeline system’s revenues is derived from activities conducted in the central United States. Transportation and storage revenues are generally secured by warehouseman’s liens. We periodically evaluate the financial condition and creditworthiness of our customers and require additional security as we deem necessary.

The employees assigned to conduct our operations are employees of MGG GP. As of December 31, 2008, MGG GP employed 1,204 employees.

At December 31, 2008, the labor force of 577 employees assigned to our petroleum products pipeline system was concentrated in the central United States. Approximately 37% of these employees were represented by the United Steel Workers Union (“USW”). MGG GP’s collective bargaining agreement with the USW was ratified by the union members in February 2009. This agreement expires January 31, 2012. The labor force of 296 employees assigned to our petroleum products terminals operations at December 31, 2008 is primarily concentrated in the southeastern and Gulf Coast regions of the United States. Approximately 10% of these employees were represented by the International Union of Operating Engineers (“IUOE”) and covered by a collective bargaining agreement that expires in October 2010. On July 1, 2008, we assumed operations of our ammonia pipeline from a third-party pipeline company. At December 31, 2008, the labor force of 19 employees assigned to our ammonia pipeline system was concentrated in the central United States and none of these employees were covered by a collective bargaining agreement.

8. Employee Benefit Plans

MGG GP sponsors two union pension plans for certain employees (“USW plan” and “IUOE plan”), a pension plan for certain non-union employees (“Salaried plan”), a postretirement benefit plan for selected employees and a defined contribution plan. We are required to reimburse MGG GP for its obligations associated with the pension plans, postretirement benefit plan and defined contribution plan for qualifying individuals assigned to our operations.

In December 2006, we adopted SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. Upon adoption of SFAS No. 158, we recognized the funded status of the present value of the benefit obligations of MGG GP’s pension plans and its postretirement medical and life benefit plan. The effect of adopting SFAS No. 158 on amounts reported in our consolidated balance sheets is described in Note 3—Consolidated Statement of Cash Flows.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The annual measurement date for the aforementioned plans is December 31. The following table presents the changes in affiliate benefit obligations and plan assets for pension benefits and other postretirement benefits for the years ended December 31, 2007 and 2008 (in thousands):

	Pension Benefits						Other Postretirement Benefits
	2007			2008			2007			2008
Change in affiliate benefit obligation:
Affiliate benefit obligation at beginning of year	$	43,849		$	42,117		$	15,004		$	17,069
Service cost		5,765			5,473			533			435
Interest cost		2,539			2,698			1,026			1,029
Plan participants’ contributions		—			—			61			108
Actuarial (gain) loss		(837	)		2,709			661			1,133
Benefits paid		(951	)		(1,799	)		(216	)		(617	)
Pension settlement		(8,248	)		—			—			—
Affiliate benefit obligation at end of year		42,117			51,198			17,069			19,157
Change in plan assets:
Fair value of plan assets at beginning of year		29,416			36,599			—			—
Employer contributions		15,000			9,143			155			509
Plan participants’ contributions		—			—			61			108
Actual return on plan assets		1,382			(5,730	)		—			—
Benefits paid		(951	)		(1,799	)		(216	)		(617	)
Pension settlement		(8,248	)		—			—			—
Fair value of plan assets at end of year		36,599			38,213			—			—
Funded status at end of year	$	(5,518	)	$	(12,985	)	$	(17,069	)	$	(19,157	)
Accumulated affiliate benefit obligation	$	31,139		$	38,447

The amounts included in pension benefits in the previous table combine the union pension plans with the Salaried pension plan. At December 31, 2007, the fair value of MGG GP’s USW and Salaried pension plans’ assets exceeded their respective accumulated benefit obligations and the fair value of the IUOE plan assets was equal to its accumulated benefit obligation. At December 31, 2008, the fair value of the USW plan’s assets exceeded the fair value of the accumulated benefit obligation by $1.8 million and the fair value of the Salaried and IUOE plans’ assets combined were $2.0 million less than the fair value of their accumulated benefit obligations.

Amounts recognized in our consolidated balance sheets were as follows (in thousands):

	Pension Benefits						Other Postretirement Benefits
	2007			2008			2007			2008
Amounts recognized in the consolidated balance sheet:
Current accrued benefit cost	$	—		$	—		$	(217	)	$	(355	)
Long-term accrued benefit cost		(5,518	)		(12,985	)		(16,852	)		(18,802	)
		(5,518	)		(12,985	)		(17,069	)		(19,157	)
Accumulated other comprehensive loss:
Net actuarial loss		4,980			15,970			5,384			6,209
Prior service cost		4,131			3,456			800			622
Net amount recognized in consolidated balance sheet	$	3,593		$	6,441		$	(10,885	)	$	(12,326	)

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Net pension and other postretirement benefit expense for the years ended December 31, 2006, 2007 and 2008 consisted of the following (in thousands):

	Pension Benefits									Other Postretirement Benefits
	2006			2007			2008			2006		2007		2008
Components of net periodic pension and postretirement benefit expense:
Service cost	$	5,587		$	5,765		$	5,473		$	469	$	533	$	435
Interest cost		2,206			2,539			2,698			834		1,026		1,029
Expected return on plan assets		(1,906	)		(2,497	)		(2,702	)		—		—		—
Amortization of prior service cost		678			678			675			177		177		178
Amortization of actuarial loss		538			414			150			675		688		307
Pension settlement expense (a)		—			1,274			—			—		—		—
Net periodic expense	$	7,103		$	8,173		$	6,294		$	2,155	$	2,424	$	1,949

(a) 26 participants took a lump sum distribution from the USW plan in 2007, resulting in a pension settlement expense of $1.3 million

Expenses related to the defined contribution plan were $4.1 million, $4.6 million and $5.0 million in 2006, 2007 and 2008, respectively.

The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost in 2009 are $1.3 million and $0.7 million, respectively. The estimated net loss and prior service cost for the other defined benefit postretirement plan that will be amortized from accumulated other comprehensive income into net periodic benefit cost in 2009 are $0.5 million and $0.2 million, respectively.

The weighted-average rate assumptions used to determine benefit obligations as of December 31, 2007 and 2008 were as follows:

	Pension Benefits				Other Postretirement Benefits
	2007		2008		2007		2008
Discount rate—Salaried plan	6.50	%	6.00	%	N/A		N/A
Discount rate—USW plan	6.50	%	6.25	%	N/A		N/A
Discount rate—IUOE plan	6.50	%	5.75	%	N/A		N/A
Discount rate—Other Postretirement Benefits	N/A		N/A		6.50	%	5.75	%
Rate of compensation increase – Salaried plan	5.00	%	5.00	%	N/A		N/A
Rate of compensation increase – USW plan	4.50	%	4.50	%	N/A		N/A
Rate of compensation increase – IUOE plan	5.00	%	5.00	%	N/A		N/A

The weighted-average rate assumptions used to determine net pension and other postretirement benefit expense for the years ended December 31, 2006, 2007 and 2008 were as follows:

	Pension Benefits						Other Postretirement Benefits
	2006		2007		2008		2006		2007		2008
Discount rate	5.50	%	5.75	%	6.50	%	5.50	%	6.00	%	6.50	%
Expected rate of return on plan assets	7.00	%	7.00	%	7.00	%	N/A		N/A		N/A
Rate of compensation increase – Salaried plan	5.00	%	5.00	%	5.00	%	N/A		N/A		N/A
Rate of compensation increase – USW plan	4.50	%	4.50	%	4.50	%	N/A		N/A		N/A
Rate of compensation increase – IUOE plan	N/A		5.00	%	5.00	%	N/A		N/A		N/A

The non-pension postretirement benefit plans provide for retiree contributions and contain other cost-sharing features such as deductibles and coinsurance. The accounting for these plans anticipates future cost sharing that is consistent with our expressed intent to increase the retiree contribution rate generally in line with health care cost increases.

22

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The annual assumed rate of increase in the health care cost trend rate for 2009 is 7.5% decreasing systematically to 4.5% by 2018 for pre-65 year-old participants and 9.0% decreasing systematically to 5.3% by 2018 for post-65 year-old participants. The health care cost trend rate assumption has a significant effect on the amounts reported. As of December 31, 2008, a 1.0% change in assumed health care cost trend rates would have the following effect (in thousands):

	1% Increase		1% Decrease
Change in total of service and interest cost components	$	299	$	139
Change in postretirement benefit obligation	$	2,827	$	2,638

The expected long-term rate of return on plan assets was determined by combining a review of projected returns, historical returns of portfolios with assets similar to the current portfolios of the union and non-union pension plans and target weightings of each asset classification. Our investment objective for the assets within the pension plans is to earn a return which exceeds the growth of our obligations that result from interest and changes in the discount rate, while avoiding excessive risk. Defined diversification goals are set in order to reduce the risk of wide swings in the market value from year to year, or of incurring large losses that may result from concentrated positions. We evaluate risks based on the potential impact on the predictability of contribution requirements, probability of under-funding, expected risk-adjusted returns and investment return volatility. Funds are invested with multiple investment managers. Our target allocation and actual weighted-average asset allocation percentages at December 31, 2007 and 2008 were as follows:

	2007				2008
	Actual (a)		Target		Actual (a)		Target
Equity securities	55	%	63	%	30	%	40	%
Debt securities	29	%	36	%	59	%	59	%
Other	16	%	1	%	11	%	1	%

(a) We made cash contributions of $15.0 million and $9.1 million to the pension plans in the 2007 and 2008 fiscal years, respectively. Amounts contributed in 2007 and 2008 in excess of benefit payments made were to be invested in debt and equity securities over a twelve-month period, with the amounts that remained uninvested as of December 31, 2007 and 2008 scheduled for investment in accordance with the target. Excluding these uninvested cash amounts, our actual allocation percentages at December 31, 2007 would have been 66% equity securities and 34% debt securities and at December 31, 2008, would have been 33% equity securities and 67% debt securities. In 2009, these uninvested cash amounts will be invested to bring the total asset allocation in line with the target allocation.

As of December 31, 2008, the benefit amounts expected to be paid through December 31, 2018 were as follows (in thousands):

	Pension Benefits		Other Postretirement Benefits
2009	$	1,922	$	355
2010		2,084		439
2011		2,252		533
2012		2,390		629
2013		2,400		714
2014 through 2018		15,884		4,747

Contributions estimated to be paid in 2009 are $7.2 million and $0.4 million for the pension and other postretirement benefit plans, respectively.

23

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

9. Related Party Transactions

Affiliate Entity Transactions

We own a 50% interest in a crude oil pipeline company and are paid a management fee for its operation. During each of 2006, 2007 and 2008 we received operating fees from this company of $0.7 million, which we reported as affiliate management fee revenue.

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

	Year Ended December 31,
	2006		2007		2008
MGG GP—allocated operating expenses	$	73,920	$	81,184	$	84,460
MGG GP—allocated G&A expenses		40,830		45,300		47,658
MGG MH—allocated G&A expenses		3,000		2,149		440

Under our services agreement with MGG GP, we reimburse MGG GP for costs of employees necessary to conduct our operations. The current affiliate payroll and benefits accruals associated with this agreement at December 31, 2007 and 2008 were $23.4 million and $18.1 million, respectively, and the long-term affiliate pension and benefits accruals associated with this agreement at December 31, 2007 and 2008 were $22.4 million and $31.8 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 GP when MGG GP makes contributions to its pension funds.

MGG historically reimbursed us for G&A expenses (excluding equity-based compensation) in excess of a G&A cap. The amount of G&A costs required to be reimbursed by MGG to us under this agreement was $1.7 million, $4.1 million and $1.6 million in 2006, 2007 and 2008, respectively. We have not received and will not receive reimbursements under this agreement for 2009 and beyond.

A former executive officer of our general partner had an investment in MGG MH, an affiliate that, until December 2008, indirectly owned a portion of our general partner. This former executive officer left the company during the fourth quarter of 2006 and we recognized $3.0 million of G&A compensation expenses associated with certain distribution payments made by MGG MH to this individual, with a corresponding increase in partners’ capital. During the years ended December 31, 2007 and 2008, we recognized $2.1 million and $0.4 million, respectively, of G&A compensation expense, with a corresponding increase in partners’ capital, for payments made by MGG MH to one of our current executive officers.

Other Related Party Transactions

Until December 2008, MGG, which owns our general partner, was 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 2006 and 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. At that time, CRF was part of an investment group that 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 permanently 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 by January 30, 2007.

24

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

During 2006 and 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 periods, 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. 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 2006 and the period of January 1 through January 30, 2007 is provided in the following table (in millions):

	Year Ended December 31, 2006		Period From January 1, 2007 Through January 30, 2007
Product sales revenues	$	177.1	$	20.5
Product purchases	$	63.2	$	14.5
Terminalling and other services revenues	$	4.4	$	0.3
Storage tank lease revenues	$	3.4	$	0.4
Storage tank lease expense	$	1.0	$	0.1

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

One of our general partner’s former independent board members, John P. DesBarres, served as a board member for American Electric Power Company, Inc. (“AEP”) of Columbus, Ohio until December 2008. Mr. DesBarres passed away on December 29, 2008. For the years ended December 31, 2006, 2007 and 2008, our operating expenses included $2.9 million, $2.7 million and $2.8 million, respectively, of power costs incurred with Public Service Company of Oklahoma (“PSO”), which is a subsidiary of AEP. We had no amounts payable to or receivable from PSO or AEP at December 31, 2007 or December 29, 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 December 31, 2008, our executive officers collectively owned a beneficial interest of approximately 1% of MGG, the owner of our general partner. Therefore, our executive officers indirectly benefit from distributions paid to our general partner. For the years ended December 31, 2006, 2007 and 2008, distributions paid to our general partner, based on its general partner interest and incentive distribution rights, totaled $56.3 million, $70.3 million and $85.6 million, respectively.

In connection with the closing of an equity offering completed by MGG in February 2006, we amended our partnership agreement to remove the requirement for our general partner to maintain its 2% interest in any future offering of our limited partner units. In addition, we amended our partnership agreement to restore the incentive distribution rights to the same level as before an amendment made in connection with our October 2004 pipeline system acquisition, which reduced the incentive distributions paid to our general partner by $1.3 million for 2004, $5.0 million for 2005 and $3.0 million for 2006. In return, MGG made a capital contribution to us on February 9, 2006 equal to the present value of the remaining reductions in incentive distributions, or $4.2 million. In January 2007, we issued 185,673 limited partner units primarily to settle the 2004 unit award grants to certain employees, which vested on December 31, 2006. Our general partner did not make an equity contribution associated with this equity issuance and as a result its general partner ownership interest in us changed from 2.000% to 1.995%. In January 2008, we issued 197,433 limited partner units primarily to settle the 2005 unit award grants to certain employees, which vested on December 31, 2007. Our general partner did not make an equity contribution associated with this equity issuance and as a result its general partner ownership interest in us changed from 1.995% to 1.989%. See Note 22—Subsequent Events, for a discussion of equity issuances and changes in our general partner’s ownership interest that occurred after year-end.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

10. Debt

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

	December 31,
	2007		2008
Revolving credit facility	$	163,500	$	70,000
6.45% Notes due 2014		249,634		249,681
5.65% Notes due 2016		252,494		253,328
6.40% Notes due 2018		—		261,555
6.40% Notes due 2037		248,908		248,921
Total debt	$	914,536	$	1,083,485

The face value of our debt outstanding as of December 31, 2008 was $1,070.0 million. The difference between the face value and carrying value of our debt outstanding was amounts recognized for discounts incurred on debt issuances and the unamortized portion of gains recognized on derivative financial instruments which had qualified as fair value hedges of our long-term debt until the hedges were terminated or hedge accounting treatment was discontinued. At December 31, 2008, maturities of our debt were as follows: $0 in 2009, 2010 and 2011; $70.0 million in 2012; $0 in 2013; and $1.0 billion thereafter. Our debt is non-recourse to our general partner.

Revolving Credit Facility. In September 2007, we amended and restated our revolving credit facility to increase the borrowing capacity from $400.0 million to $550.0 million. In addition, the maturity date of the revolving credit facility was extended from May 2011 to September 2012. We incurred $0.2 million of legal and other costs associated with this amendment. Borrowings under the facility remain unsecured and incur interest at LIBOR plus a spread that ranges from 0.3% to 0.8% based on our credit ratings and amounts outstanding under the facility. Borrowings under this facility are used primarily for general purposes, including capital expenditures. As of December 31, 2008, $70.0 million was outstanding under this facility and $3.9 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 December 31, 2007 and 2008 was 5.4% and 4.8%. Additionally, a commitment fee is assessed at a rate from 0.05% to 0.125%, depending on our credit rating. Borrowings outstanding under this facility as of July 14, 2008 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 11—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 11—Derivative Financial Instruments). Including the amortization of the $3.8 million gain realized from terminating that interest rate swap and the amortization of losses realized on pre-issuance hedges associated with these notes, the weighted-average interest rate of these notes at December 31, 2007 and 2008 was 5.5% 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 $3.5 million at December 31, 2008 for the unamortized portion of the gain recognized 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 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, effectively converting $100.0 million of these notes to floating-rate debt (see Note 11—Derivative Financial Instruments). These

26

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

agreements originally expired on July 15, 2018, the maturity date of the 6.40% notes; however, in December 2008 we terminated $50.0 million of these agreements and discontinued hedge accounting on the remaining $50.0 million, resulting in our recognizing gains of $11.7 million. The outstanding principal amount of the notes was increased by $11.7 million at December 31, 2008 for the unamortized portion of those gains. Including the amortization of those gains, the weighted-average interest rate of these notes at December 31, 2008 was 5.9%.

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. Net proceeds from the offering, after underwriter discounts of $2.2 million and offering costs of $0.3 million, were $246.4 million. The net proceeds were used to repay a portion of other notes that were outstanding at that time. Including the impact of amortizing the gains realized on the interest hedges associated with these notes (see Note 11—Derivative Financial Instruments), the effective interest rate of these notes is 6.3%.

The revolving credit facility described above requires us to maintain a specified ratio of consolidated debt to EBITDA of no greater than 4.75 to 1.00. In addition, the revolving credit facility and the indentures under which our public notes were issued contain covenants that limit our ability to, among other things, incur indebtedness secured by certain liens or encumber our assets, engage in certain sale-leaseback transactions, and consolidate, merge or dispose of all or substantially all of our assets. We were in compliance with these covenants as of December 31, 2008.

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

During the years ending December 31, 2006, 2007 and 2008, total cash payments for interest on all indebtedness, including the impact of related interest rate swap agreements, net of amounts capitalized, were $57.2 million, $59.2 million and $49.3 million, respectively.

11. Derivative Financial Instruments

Commodity Derivatives

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

In addition to forward sales agreements, we use 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 qualify as normal sales or for hedge accounting treatment under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended); therefore, we recognize the change in fair value of these agreements currently in earnings. During 2008, we closed our positions on NYMEX contracts associated with the sale of 0.5 million barrels of gasoline, and recognized total gains of $30.7 million as product sales revenues. At December 31, 2008, the fair value of our open NYMEX contracts, representing 0.6 million barrels of petroleum product, was a gain of $20.2 million, which we recognized as energy commodity derivative contracts on our consolidated balance sheet. These open NYMEX contracts mature between January 2009 and April 2009. At December 31, 2008, we had received $19.0 million in margin cash from these agreements, which we recorded as energy commodity derivatives deposit on our consolidated balance sheet.

Interest Rate Derivatives

We use interest rate derivatives to help manage interest rate risk. At December 31, 2008, we had two offsetting interest rate swap agreements outstanding:

• In July 2008, we entered into a $50.0 million interest rate swap agreement (“Derivative A”) to hedge against changes in the fair value of a portion of the $250.0 million of 6.40% notes due 2018. Derivative A effectively converted $50.0 million of those notes from a 6.40% fixed rate to a floating rate of six-month LIBOR plus 1.83%. Derivative A terminates in July 2018. We originally accounted for Derivative A as a fair value hedge. On

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 8, 2008, in order to capture the economic value of Derivative A at that time, we entered into an offsetting derivative, as described below, and discontinued hedge accounting. The $5.4 million fair value of Derivative A at that time was recorded as an adjustment to long-term debt and is being amortized over the remaining life of the 6.40% fixed-rate notes due 2018. The change in fair value of Derivative A from the date we discontinued hedge accounting, until December 31, 2008, was a gain of $1.9 million, which was recorded to other (income) expense on our consolidated statement of income.

• In December 2008, concurrent with the discontinuance of hedge accounting treatment of Derivative A, we entered into an offsetting $50.0 million interest rate swap agreement with a different financial institution pursuant to which we pay a fixed rate of 6.40% and receive a floating rate of six-month LIBOR plus 3.23%. This agreement terminates in July 2018. We entered into this agreement to offset changes in the fair value of Derivative A, excluding changes due to changes in counterparty credit risks. We did not designate this agreement as a hedge for accounting purposes. The fair value of this agreement as of December 31, 2008 was a loss of $1.8 million, which was recorded to other deferred liabilities on our consolidated balance sheet and other (income) expense on our consolidated statement of income.

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

• In July 2008, we entered into a $50.0 million interest rate swap agreement to hedge against changes in the fair value of a portion of the $250.0 million of 6.40% notes due 2018. We accounted for this agreement as a fair value hedge. This agreement effectively converted $50.0 million of our 6.40% fixed-rate notes to floating-rate debt. In December 2008, we terminated and settled this interest rate swap agreement and received $6.3 million, which was recorded as an adjustment to long-term debt and is being amortized over the remaining life of the 6.40% fixed-rate notes.

• 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. We accounted for this agreement as a fair value hedge. This agreement effectively converted $100.0 million of our 5.65% fixed-rate senior notes to floating-rate debt. In May 2008, we terminated and settled 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 notes.

• 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 and settled these interest rate swap agreements and received $0.2 million, which was recorded to other income on our consolidated statement of income.

The following financial instruments designated as hedges were settled during 2007:

• In September and November 2006, we entered into forward starting interest rate swap agreements to hedge against the variability of future interest payments on $250.0 million of debt we issued in April 2007. We accounted for these agreements as cash flow hedges. As of December 31, 2006, we had recorded a $0.2 million gain associated with these agreements to other comprehensive income. These agreements were terminated and settled in April 2007, in conjunction with our public offering of $250.0 million of notes. We received $5.5 million from the settlement of these agreements, of which a gain of $5.0 million was recorded to other comprehensive income that, along with $0.2 million gain recognized in 2006, we are amortizing against interest expense over the life of the notes, $0.2 million was recorded as an adjustment to other current assets and $0.3 million was considered ineffective and recorded as other income on our consolidated statement of income.

• During May 2004, we entered into certain interest rate swap agreements with notional amounts of $250.0 million to hedge against changes in the fair value of a portion of our pipeline notes. We terminated these agreements in May 2007 in conjunction with the repayment of these notes, resulting in payments totaling $1.1 million to the hedge counterparties, of which $0.9 million was recorded to other expense and $0.2 million was recorded as a reduction of accrued interest.

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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”) for the years ended December 31, 2007 and 2008 (in thousands):

				Effective Portion of Gains
				2007						2008
Hedge	Total Gain (Loss) Realized on Settlement of Hedge			Unamortized Amount Recognized in AOCI			Amount Reclassified to Earnings from AOCI			Unamortized Amount Recognized in AOCI			Amount Reclassified to Earnings from AOCI
Cash flow hedges (date executed):
Interest rate swaps 6.40% Notes (April 2007)	$	5,255		$	5,132		$	(123	)	$	4,957		$	(175	)
Interest rate swaps 5.65% Notes (October 2004)		(6,279	)		(4,600	)		524			(4,077	)		523
Interest rate swaps and treasury lock 6.45% Notes (May 2004)		5,119			3,285			(512	)		2,773			(512	)
Interest rate hedge pipeline notes (October 2002)		(995	)		—			174			—			—
Total cash flow hedges				$	3,817		$	63		$	3,653		$	(164	)

There was no ineffectiveness recognized on the financial instruments disclosed in the above table during the years ended December 31, 2007 and 2008.

12. Leases

Leases—Lessee

We lease land, office buildings, tanks and terminal equipment at various locations to conduct our business operations. Several of the agreements provide for negotiated renewal options and cancellation penalties, some of which include the requirement to remove our pipeline from the property for non-performance. Management expects that in the normal course of business, expiring leases will generally be renewed. Leases are evaluated at inception or at any subsequent material modification and, depending on the lease terms, are classified as either capital leases or operating leases, as appropriate under SFAS No. 13, Accounting for Leases. Rent expense is recognized on a straight-line basis over the life of the lease. Total rent expense was $6.3 million, $4.6 million and $4.6 million for the years ended December 31, 2006, 2007 and 2008, respectively. Future minimum annual rentals under non-cancelable operating leases as of December 31, 2008, were as follows (in thousands):

2009	$	3,393
2010		3,379
2011		3,167
2012		2,427
2013		1,476
Thereafter		8,121
Total	$	21,963

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Leases—Lessor

We have entered into capacity and storage leases with remaining terms from one to 10 years that we account for as operating-type leases. All of the agreements provide for negotiated extensions. Future minimum lease payments receivable under operating-type leasing arrangements as of December 31, 2008, were as follows (in thousands):

2009	$	115,465
2010		96,147
2011		77,969
2012		58,667
2013		33,500
Thereafter		58,764
Total	$	440,512

In December 2001, we purchased an 8.5-mile natural gas liquids pipeline in northeastern Illinois from Aux Sable Liquid Products L.P. (“Aux Sable”) for $8.9 million. We then entered into a long-term lease arrangement under which Aux Sable is the sole lessee of these assets. We have accounted for this transaction as a direct financing lease. The lease expires in December 2016 and has a purchase option after the first year. Aux Sable has the right to re-acquire the pipeline at the end of the lease for a de minimus amount. Future minimum lease payments receivable under this direct-financing leasing arrangement as of December 31, 2008 were $1.3 million each year in 2009, 2010, 2011, 2012 and 2013 and $3.7 million cumulatively for all periods after 2013. The net investment under direct financing lease arrangements as of December 31, 2007 and 2008 was as follows (in thousands):

	December 31,
	2007		2008
Total minimum lease payments receivable	$	11,514	$	10,234
Less: Unearned income		4,487		3,664
Recorded net investment in direct financing leases	$	7,027	$	6,570

The net investment in this direct financing lease was classified in the consolidated balance sheets as follows (in thousands):

	December 31,
	2007		2008
Classification of direct financing leases:
Current accounts receivable	$	563	$	622
Noncurrent accounts receivable		6,464		5,948
Total	$	7,027	$	6,570

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

13. Long-Term Incentive Plan

Plan Description

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 remaining units available under the LTIP at December 31, 2008 total 1.7 million. 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:

Vested Unit Awards

Grant Date	Unit Awards Granted	Forfeitures	Adjustments to Unit Awards for Attaining Above- Target Financial Results	Units Paid Out on Vesting Date	Vesting Date	Value of Unit Awards on Vesting Date (Millions)
February 2004	159,024	14,648	140,794	285,170	12/31/06	$	11.0
February 2005	160,640	11,348	149,292	298,584	12/31/07	$	12.9
June 2006	1,170	—	1,170	2,340	12/31/07	$	0.1
February 2006	168,105	13,730	154,143	308,518	12/31/08	$	9.3
Various 2006	9,201	2,640	6,561	13,122	12/31/08	$	0.4
March 2007	2,640	—	—	2,640	12/31/08	$	0.1

In January 2007, we settled the February 2004 award grants by issuing 184,905 limited partner units and distributing those units to the participants. The difference between the limited partner units issued to the participants and the total units accrued for represented the minimum tax withholdings associated with this award settlement. We paid associated tax withholdings and employer taxes totaling $4.4 million in January 2007.

In January 2008, we settled the cumulative amounts of the February 2005 and June 2006 award grants by issuing 196,856 limited partner units and distributing those units to the participants. The difference between the limited partner units issued to the participants and the total units accrued for represented the minimum tax withholdings associated with this award settlement. We paid associated tax withholdings and employer taxes totaling $5.1 million in January 2008.

In January 2009, we settled the cumulative amounts of the remaining 2006 and March 2007 award grants by issuing 209,321 limited partner units and distributing those units to the participants (see Note 22—Subsequent Events). There was no impact on our cash flows associated with these award grants for the periods presented in this report. The difference between the limited partner units issued to the participants and the total units accrued for represented the minimum tax withholdings associated with this award settlement. We paid associated tax withholdings and employer taxes totaling $4.0 million in January 2009.

Performance Based Unit Awards

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

On December 3, 2008, MGG purchased its general partner from MGG MH. When this transaction closed, a change in control occurred as defined in our LTIP. Even though a change in control has occurred, participants in the LTIP must resign voluntarily for good reason or be terminated involuntarily for other than performance reasons within two years of December 3, 2008 in order to receive enhanced LTIP payouts.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For each of the award grants listed below, the payout calculation for 80% of the unit awards will be based solely on the attainment of a financial metric established by the Compensation Committee. This portion of the award grants has been accounted for as equity. The payout calculation for the remaining 20% of the unit awards will be based on both the attainment of a financial metric and the individual employee’s personal performance as determined by the Compensation Committee. This portion of the award grants was accounted for as liabilities. For example, if a LTIP participant received an award of 100 units and at the end of the vesting period the payout for that award grant was at stretch performance, the recipient would receive a minimum of 160 units for the 80% portion of the payout based solely on the attainment of financial metrics (100 unit award x 80% x 200% payout for stretch financial performance). The remainder of the award would be subject to the financial metrics performance results resulting in an additional 40 unit payout (100 unit award x 20% x 200% payout for stretch financial performance); however, the Compensation Committee, at its discretion, can change the payout of this portion of the award from a payout of zero units up to 80 units. Therefore, the original 100 unit award payout, at stretch financial performance, would range from a minimum of 160 units to a maximum of 240 units.

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

Grant Date	Unit Awards Granted	Estimated Forfeitures	Adjustment to Unit Awards in Anticipation of Achieving Above/ (Below) Target Financial Results		Total Unit Award Accrual	Vesting Date	Unrecognized Compensation Expense (Millions) (1)		Intrinsic Value of Unvested Awards at December 31, 2008 (Millions)
January 2007 Awards:
Tranche 1: January 2007	53,230	2,396	50,835		101,669	12/31/09	$	1.1	$	3.1
Tranche 2: January 2008	53,230	2,396	(39,803	)	11,031	12/31/09		0.2		0.3
Tranche 3: (2)	—	—	—		—	12/31/09		—		—
January 2008	184,340	8,295	(123,231	)	52,814	12/31/10		1.1		1.6
Various 2008	5,492	248	(3,672	)	1,572	12/31/10		*		*
Total	296,292	13,335	(115,871	)	167,086		$	2.4	$	5.0

(1) Unrecognized compensation expense will be recognized over the remaining vesting periods of the awards.

(2) The grant date for this tranche has not yet been set. Because this table reflects unvested unit awards at December 31, 2008, quantities associated with this tranche have not been included. There were 53,230 unit awards approved under this tranche.

* Values are less than $0.1 million.

The unit awards approved during 2007 are broken into three equal tranches, with each tranche vesting on December 31, 2009. We began accruing for Tranche 1 in the first quarter of 2007 and Tranche 2 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 Tranche 3 when the Compensation Committee establishes the associated financial metric for that tranche. The unit awards allocated to each tranche are expensed over their respective vesting periods. As of December 31, 2008, the accrual for payout of Tranche 1 was 200%, as the related financial metric for the year ended December 31, 2007 was above the stretch target. The accrual for payout of Tranche 2 was 22%, as the related financial metric was slightly above the threshold target.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Retention Awards

The retention awards below are subject to forfeiture if employment is terminated or the employee resigns from their current position for any reason prior to the applicable vesting date. The award grants do not have an early vesting feature. The award grants listed below were accounted for as equity.

Grant Date	Unit Awards Granted	Estimated Forfeitures	Total Unit Award Accrual	Vesting Date	Unrecognized Compensation Expense (Millions) (1)		Intrinsic Value of Unvested Awards at December 31, 2008 (Millions)
Various 2008	9,248	286	8,962	12/31/10	$	0.2	$	0.3
Various 2008	40,315	1,814	38,501	12/31/11		0.8		1.2
	49,563	2,100	47,463		$	1.0	$	1.5

(1) Unrecognized compensation expense will be recognized over the remaining vesting periods of the awards.

Fair Value of Unit Awards

The following table provides the fair value of our LTIP awards as of December 31, 2008:

	2006 Awards		2007 Awards		2008 Awards
Weighted-average per unit grant date fair value of equity awards (a)	$	25.24	$	33.05	$	28.61
December 31, 2008 per unit fair value of liability awards (b)	$	30.21	$	27.30	$	24.27

(a) Approximately 80% of the unit awards are accounted for as equity (see Plan Description above). Fair value is calculated as our unit price on the grant date less the present value of estimated cash distributions during the vesting period.

(b) Approximately 20% of the unit awards are accounted for as liabilities (see Plan Description above). Fair value is calculated as our unit price at the end of each accounting period less the present value of estimated cash distributions during the remaining portion of the vesting period.

Compensation Expense Summary

Equity-based incentive compensation expense, excluding amounts for the directors of our general partner, for 2006, 2007 and 2008 was as follows (in thousands):

	Year Ended December 31,
	2006								2007						2008
	Equity Method		Liability Method			Total			Equity Method		Liability Method		Total		Equity Method		Liability Method		Total
2003 awards	$	—	$	(89	)	$	(89	)	$	—	$	—	$	—	$	—	$	—	$	—
2004 awards		—		4,355			4,355			—		—		—		—		—		—
2005 awards		—		4,096			4,096			—		5,721		5,721		—		26		26
2006 awards		1,771		687			2,458			2,216		955		3,171		2,509		378		2,887
2007 awards		—		—			—			860		242		1,102		990		127		1,117
2008 awards		—		—			—			—		—		—		639		82		721
Total	$	1,771	$	9,049		$	10,820		$	3,076	$	6,918	$	9,994	$	4,138	$	613	$	4,751

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Long-term incentive awards were also granted to independent members of the board of directors of our general partner pursuant to the LTIP. Beginning in 2007, our independent directors could elect to defer all or a portion of payment of their compensation. All compensation amounts deferred are credited to the applicable director’s account in the form of phantom limited partner units, with distribution equivalent rights. Phantom units earned by our independent directors and the related compensation expense recognized are provided in the table below. The unit and compensation amounts below include amounts credited to the director’s account for distribution equivalents earned (in thousands, except unit amounts):

	Year Ended December 31,
	2006		2007		2008
Phantom units earned		1,459		5,217		6,898
Compensation expense recognized	$	50	$	221	$	263

14. Segment Disclosures

Our reportable segments are strategic business units that offer different products and services. Our segments are managed separately because each 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.

Beginning in 2007, commercial and operating responsibilities for our two inland terminals in the Dallas, Texas area were transferred from the petroleum products terminals segment to our petroleum products pipeline system segment. The primary reasons for these transfers were because of location and operating synergies. Prior to the transfers, our customers were required to work with our different entities in order to do business at these facilities. Additionally, we were engaged in two distinct marketing strategies, one for terminalling services and one for pipeline transportation services. Since the beginning of 2007, these facilities have been under petroleum products pipeline management and their operating results have been reported both internally and externally as part of that segment. Historical financial results for our operating segments have been adjusted to reflect the impact of this transfer. Consolidated segment profit did not change as a result of these historical reclassifications.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

	Year Ended December 31, 2006
	Petroleum Products Pipeline System			Petroleum Products Terminals		Ammonia Pipeline System			Intersegment Eliminations			Total
	(in thousands)
Transportation and terminals revenues	$	419,263		$	125,962	$	16,473		$	(3,397	)	$	558,301
Product sales revenues		649,172			15,397		—			—			664,569
Affiliate management fee revenue		690			—		—			—			690
Total revenues		1,069,125			141,359		16,473			(3,397	)		1,223,560
Operating expenses		189,684			47,376		13,932			(6,466	)		244,526
Product purchases		598,575			7,280		—			(514	)		605,341
Equity earnings		(3,324	)		—		—			—			(3,324	)
Operating margin		284,190			86,703		2,541			3,583			377,017
Depreciation and amortization expense		38,512			17,980		777			3,583			60,852
Affiliate G&A expenses		45,980			18,926		2,206			—			67,112
Operating profit (loss)	$	199,698		$	49,797	$	(442	)	$	—		$	249,053
Segment assets	$	1,338,715		$	560,993	$	23,659		$	—		$	1,923,367
Corporate assets													29,282
Total assets												$	1,952,649
Goodwill	$	—		$	23,945	$	—		$	—		$	23,945
Additions to long-lived assets	$	79,914		$	80,143	$	641		$	—		$	160,698
Equity investments	$	24,087		$	—	$	—		$	—		$	24,087

	Year Ended December 31, 2007
	Petroleum Products Pipeline System			Petroleum Products Terminals		Ammonia Pipeline System			Intersegment Eliminations			Total
	(in thousands)
Transportation and terminals revenues	$	459,772		$	132,693	$	18,287		$	(2,907	)	$	607,845
Product sales revenues		692,355			17,209		—			—			709,564
Affiliate management fee revenue		712			—		—			—			712
Total revenues		1,152,839			149,902		18,287			(2,907	)		1,318,121
Operating expenses		179,426			56,301		21,295			(5,421	)		251,601
Product purchases		626,194			8,233		—			(518	)		633,909
Equity earnings		(4,027	)		—		—			—			(4,027	)
Operating margin (loss)		351,246			85,368		(3,008	)		3,032			436,638
Depreciation and amortization expense		39,658			20,315		787			3,032			63,792
Affiliate G&A expenses		52,198			17,756		2,633			—			72,587
Operating profit (loss)	$	259,390		$	47,297	$	(6,428	)	$	—		$	300,259
Segment assets	$	1,431,069		$	614,409	$	25,911		$	—		$	2,071,389
Corporate assets													29,805
Total assets												$	2,101,194
Goodwill	$	—		$	23,945	$	—		$	—		$	23,945
Additions to long-lived assets	$	92,692		$	92,766	$	2,002		$	—		$	187,460
Equity investments	$	24,324		$	—	$	—		$	—		$	24,324

35

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

	Year Ended December 31, 2008
	Petroleum Products Pipeline System			Petroleum Products Terminals		Ammonia Pipeline System		Intersegment Eliminations			Total
	(in thousands)
Transportation and terminals revenues	$	477,621		$	141,129	$	22,704	$	(3,496	)	$	637,958
Product sales revenues		543,694			30,401		—		—			574,095
Affiliate management fee revenue		733			—		—		—			733
Total revenues		1,022,048			171,530		22,704		(3,496	)		1,212,786
Operating expenses		198,356			59,284		14,061		(5,973	)		265,728
Product purchases		429,294			8,279		—		(1,006	)		436,567
Gain on assignment of supply agreement		(26,492	)		—		—		—			(26,492	)
Equity earnings		(4,067	)		—		—		—			(4,067	)
Operating margin		424,957			103,967		8,643		3,483			541,050
Depreciation and amortization expense		42,571			24,236		863		3,483			71,153
Affiliate G&A expenses		50,580			16,797		3,058		—			70,435
Operating profit	$	331,806		$	62,934	$	4,722	$	—		$	399,462
Segment assets	$	1,465,242		$	734,485	$	32,335	$	—		$	2,232,062
Corporate assets												64,053
Total assets											$	2,296,115
Goodwill	$	2,864		$	23,945	$	—	$	—		$	26,809
Additions to long-lived assets	$	156,266		$	144,620	$	5,536	$	—		$	306,422
Equity investments	$	23,190		$	—	$	—	$	—		$	23,190

15. Commitments and Contingencies

Environmental Liabilities. Liabilities recognized for estimated environmental costs were $57.8 million and $41.8 million at December 31, 2007 and 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. Environmental expenses recognized as a result of changes in our environmental liabilities are included in operating expenses on our consolidated statements of income. Environmental expense was $12.4 million, $10.0 million and $(1.4) million in 2006, 2007 and 2008, respectively. See Indemnification Settlement below for a discussion of a settlement which significantly reduced environmental expense in 2008.

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

• Petroleum Products EPA Issue. In July 2001, the Environmental Protection Agency (“EPA”), pursuant to Section 308 of the Clean Water Act (the “Act”), served an information request to a former affiliate with regard to petroleum discharges from its pipeline operations. That inquiry primarily focused on the petroleum products pipeline system that we subsequently acquired. The EPA added to their original demand two subsequent releases that occurred from our petroleum products pipeline system. In September 2008, we paid a penalty of $5.3 million and agreed to perform certain operational enhancements under the terms of a settlement agreement reached with the EPA and Department of Justice (“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 and, accordingly, was allocated to our general partner.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

• 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 provided indemnifications to us for assets we had acquired from it. In May 2004, we entered into an agreement with our former affiliate under which our former affiliate agreed to pay us $117.5 million to release it from these indemnification obligations. We received the final two installment payments of $35.0 million and $20.0 million associated with this agreement in 2007 and 2006, respectively. At December 31, 2007 and 2008, known liabilities that would have been covered by this indemnity agreement were estimated to be $42.9 million and $25.5 million, respectively. Through December 31, 2008, we have spent $59.0 million of the indemnification settlement proceeds for indemnified matters, including $23.1 million of capital costs. We have not reserved the cash received from this indemnity settlement and have used it for 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 $4.5 million at December 31, 2007 and 2008, respectively.

Unrecognized Product Gains. Our petroleum products terminals operations generate product overages and shortages that result from metering inaccuracies, product evaporation or expansion, product releases and product contamination. Most of the contracts we have with our customers state that we bear the risk of loss (or gain) from these conditions. When our petroleum products terminals experience net product shortages, we recognize expense for those losses in the periods in which they occur. When our petroleum products terminals experience net product overages, we have product on hand for which we have no cost basis. Therefore, these net overages are not recognized in our financial statements until the associated barrels are either sold or used to offset product losses. The net unrecognized product overages for our petroleum products terminals operations had a market value of approximately $2.4 million as of December 31, 2008. However, the actual amounts we will recognize in future periods will depend on product prices at the time the associated barrels are either sold or used to offset future product losses.

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

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

16. Quarterly Financial Data (unaudited)

Summarized quarterly financial data is as follows (in thousands, except per unit amounts):

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2007
Revenues	$	291,987	$	328,155	$	321,957	$	376,022
Operating margin		97,795		112,646		104,680		121,517
Total costs and expenses		228,080		250,051		251,501		292,257
Net income		49,702		61,452		59,444		72,192
Basic net income per limited partner unit		0.53		0.68		0.65		0.83
Diluted net income per limited partner unit		0.53		0.68		0.65		0.82
2008
Revenues	$	346,493	$	272,914	$	291,980	$	301,399
Operating margin		140,230		142,034		122,293		136,493
Total costs and expenses		268,116		168,145		206,286		201,336
Net income		93,322		94,374		73,336		85,581
Basic net income per limited partner unit		1.10		0.92		0.80		0.95
Diluted net income per limited partner unit		1.10		0.92		0.80		0.94

First-quarter 2008 net income was favorably impacted by the $26.5 million gain recognized from our assignment of a supply agreement. Second-quarter 2008 net income was favorably impacted by a $12.1 million reduction in our operating expenses when we settled an environmental matter for less than amounts we had previously accrued. Third-quarter 2008 revenues and net income were favorably impacted by $12.2 million of unrealized gains on NYMEX agreements. Fourth-quarter revenues and net income were favorably impacted by $8.0 million of unrealized gains on outstanding NYMEX agreements and net income was unfavorably impacted by $28.6 million of lower-of-average-cost-or-market adjustments.

Second-quarter 2007 net income was negatively impacted by $2.9 million of expenses associated with the repayment of our pipeline notes. Fourth-quarter 2007 revenues and net income were favorably impacted by $2.8 million of revenues recognized from our variable-rate terminalling agreements.

We have retrospectively applied the provisions of EITF No. 07-4 to the basic and diluted net income per limited partner unit amounts for the 2007 and 2008 periods presented in the tables above.

17. Fair Value Disclosures

Fair Value of Financial Instruments

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

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

Energy commodity derivative contracts. The carrying amount reported in the balance sheet represents fair value (see Note 11 –Derivative Financial Instruments).

Long-term receivables. Fair value was determined by discounting estimated future cash flows by the rates inherent in the long-term instruments adjusted for the change in the risk-free rate since inception of the instrument.

Energy commodity derivatives deposit. This liability represents a short-term deposit we held associated with our energy commodity derivative contracts. The carrying amount reported in the balance sheet approximates fair value due to the short-term maturity of the underlying contracts.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Debt. The fair value of our publicly traded notes, excluding the value of interest rate swaps qualifying as fair value hedges, was based on the prices of those notes at December 31, 2007 and 2008. The carrying amount of borrowings under our revolving credit facility at December 31, 2007 and 2008 approximates fair value due to the variable rates of that instrument.

Interest rate swaps. Fair value was determined based on an assumed exchange, at each year end, in an orderly transaction with the financial institution counterparties of the interest rate derivative agreements.

Other deferred liabilities – deposits. This liability represented a long-term deposit we held associated with a supply agreement which was assigned to a third party in March 2008. Fair value was determined by discounting the deposit amount at our incremental borrowing rate.

The following table reflects the carrying amounts and fair values of our financial instruments as of December 31, 2007 and 2008 (in thousands):

	December 31, 2007				December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount			Fair Value
Cash and cash equivalents	$	—	$	—	$	33,241		$	33,241
Energy commodity derivative contracts		—		—		20,200			20,200
Long-term receivables		7,506		6,849		7,119			5,249
Energy commodity derivatives deposit		—		—		18,994			18,994
Debt		911,801		933,650		1,083,485			934,975
Interest rate swaps:
$100.0 million (October 2004)		2,735		2,735		—			—
$50.0 million (July 2008)		—		—		7,542			7,542
$50.0 million (December 2008)		—		—		(1,770	)		(1,770	)
Other deferred liabilities – deposits		18,500		9,886		—			—

Fair Value Measurements

The following tables summarize the fair value measurements of our energy commodity derivative contracts and interest rate swap agreements as of December 31, 2008, based on the three levels established by SFAS No. 157, Fair Value Measurements (in thousands):

				Asset Fair Value Measurements as of December 31, 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	$	20,200		$	20,200	$	—		$	—
Interest rate swap agreements (date executed):
$50.0 million (July 2008)		7,542			—		7,542			—
$50.0 million (December 2008)		(1,770	)		—		(1,770	)		—

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

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

18. Distributions

We paid the following distributions during 2006, 2007 and 2008 (in thousands, except per unit amounts):

Date Cash Distribution      Paid	Per Unit Cash Distribution Amount		Common Units		Subordinated Units		General Partner (a)		Total Cash Distribution
02/14/06	$	0.55250	$	33,526	$	3,138	$	12,839	$	49,503
05/15/06		0.56500		37,494		—		13,668		51,162
08/14/06		0.57750		38,324		—		14,497		52,821
11/14/06		0.59000		39,153		—		15,327		54,480
Total	$	2.28500	$	148,497	$	3,138	$	56,331	$	207,966
02/14/07	$	0.60250	$	40,094	$	—	$	16,197	$	56,291
05/15/07		0.61625		41,009		—		17,112		58,121
08/14/07		0.63000		41,924		—		18,027		59,951
11/14/07		0.64375		42,839		—		18,942		61,781
Total	$	2.49250	$	165,866	$	—	$	70,278	$	236,144
02/14/08	$	0.65750	$	43,884	$	—	$	19,909	$	63,793
05/15/08		0.67250		44,885		—		20,910		65,795
08/14/08		0.68750		45,886		—		21,911		67,797
11/14/08		0.70250		46,887		—		22,912		69,799
Total	$	2.72000	$	181,542	$	—	$	85,642	$	267,184

(a) Includes amounts paid to our general partner for its incentive distribution rights.

In February 2006, we amended our partnership agreement to restore the incentive distribution rights to the same level as before an amendment made in connection with our October 2004 pipeline system acquisition that reduced the incentive distributions paid to our general partner by $1.3 million for 2004, $5.0 million for 2005 and $3.0 million for 2006. In return, MGG made a capital contribution to us on February 9, 2006 equal to the present value of the remaining reductions in incentive distributions, or $4.2 million.

On February 13, 2009, we paid cash distributions of $0.71 per unit on our outstanding limited partner units to unitholders of record at the close of business on February 6, 2009. Because we issued 210,149 limited partner units in January 2009 and our general partner did not make an equity contribution to us associated with that equity issuance, our general partner’s ownership interest in us changed from 1.989% to 1.983%. See Note 22– Subsequent Events for further discussion of this matter. The total distributions paid on February 13, 2009 were $71.0 million, of which $1.4 million was paid to our general partner on its 1.983% general partner interest and $22.1 million on its incentive distribution rights.

40

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

19. Net Income Per Unit

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

	For The Year Ended December 31, 2006
	Income (Numerator)		Units (Denominator)	Per Unit Amount
Limited partners’ interest in income	$	146,858
Basic net income per limited partner unit	$	146,858	66,361	$	2.21
Effect of dilutive restrictive unit grants		—	252		(0.01	)
Diluted net income per limited partner unit	$	146,858	66,613	$	2.20
	For The Year Ended December 31, 2007
	Income (Numerator)		Units (Denominator)	Per Unit Amount
Limited partners’ interest in income	$	179,223
Basic net income per limited partner unit	$	179,223	66,547	$	2.69
Effect of dilutive restrictive unit grants		—	153		—
Diluted net income per limited partner unit	$	179,223	66,700	$	2.69
	For The Year Ended December 31, 2008
	Income (Numerator)		Units (Denominator)	Per Unit Amount
Limited partners’ interest in income	$	251,710
Basic net income per limited partner unit	$	251,710	66,855	$	3.77
Effect of dilutive restrictive unit grants		—	72		(0.01	)
Diluted net income per limited partner unit	$	251,710	66,927	$	3.76

Units reported as dilutive securities are related to restricted unit grants associated with unvested awards (see Note 13—Long-Term Incentive Plan).

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

20. Partners’ Capital

Units outstanding. The following table details the changes in the number of our units outstanding from January 1, 2006 through December 31, 2008.

	Common	Subordinated		Total
Units outstanding on January 1, 2006	60,680,928	5,679,696		66,360,624
01/06—Conversion of subordinated units to common units (a)	5,679,696	(5,679,696	)	—
Units outstanding on December 31, 2006	66,360,624	—		66,360,624
01/07—Settlement of 2004 award grants	184,905	—		184,905
Other (c)	768	—		768
Units outstanding on December 31, 2007 (b)	66,546,297	—		66,546,297
01/08—Settlement of 2005 award grants	196,856	—		196,856
Other (c)	577	—		577
Units outstanding on December 31, 2008 (b)	66,743,730	—		66,743,730

(a) Our subordination period ended on December 31, 2005 when we met the final financial tests provided for in our partnership agreement. As a result, on January 31, 2006, one day following the distribution record date, the 5,679,696 outstanding subordinated units representing limited partner interests in us converted to common units.

(b) For the years ended December 31, 2007 and 2008, the weighted-average number of limited partner units outstanding for basic net income per unit calculation includes phantom limited partner units associated with deferred compensation of certain directors of our general partner.

(c) Common units issued to settle the equity-based retainer paid to the independent directors of our general partner.

Limited partners holding our common units have the following rights, among others:

• right to receive distributions of our available cash within 45 days after the end of each quarter;

• right to elect the board members of our general partner;

• right to remove Magellan GP, LLC as our general partner upon a 66.7% majority vote of outstanding unitholders;

• right to transfer limited partner unit ownership to substitute limited partners;

• right to receive an annual report, containing audited financial statements and a report on those financial statements by our independent public accountants within 120 days after the close of the fiscal year end;

• right to receive information reasonably required for tax reporting purposes within 90 days after the close of the calendar year;

• right to vote according to the limited partners’ percentage interest in us at any meeting that may be called by our general partner; and

• right to inspect our books and records at the unitholders’ own expense.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

From January 24, 2008 until January 23, 2009, cash distributions to our general partner and limited partners were made based on the following table:

	Percentage of Distributions
			General Partner
Quarterly Distribution Amount per Unit	Limited Partners		General Partner Interest		Incentive Distribution Rights
Up to $0.289	98.011	%	1.989	%	0.000	%
Above $0.289 up to $0.328	85.011	%	1.989	%	13.000	%
Above $0.328 up to $0.394	75.011	%	1.989	%	23.000	%
Above $0.394	50.011	%	1.989	%	48.000	%

See Note 22—Subsequent Events for a discussion of the changes in the percentage of distributions to the limited and general partner interests that occurred after December 31, 2008.

In the event of liquidation, all property and cash in excess of that required to discharge all liabilities will be distributed to the partners in proportion to the positive balances in their respective capital accounts. The limited partners’ liability is generally limited to their investment.

Unit purchase rights plan. In December 2008, the board of directors of our general partner adopted a unit purchase rights plan. Under our unit purchase rights plan, each of our outstanding common units carries the right to purchase one additional common unit at a price of $145, subject to adjustment. Generally, the rights become exercisable only in certain circumstances in which a person or group acquires, or attempts to acquire, 15% or more of our common units without the consent of our general partner’s board of directors. When exercisable, each right would then entitle the holder of the right (other than the person or group making the acquisition) to purchase, for the then current purchase price of the right, our common units, or shares of stock or common units of any person into which we are thereafter merged or to which 50% or more of our assets or earning power is sold, with a market value of twice the purchase price of the right. The rights will expire on December 3, 2011, unless extended or earlier redeemed. Under certain circumstances, the board of directors of our general partner may redeem the rights for $0.001 per right.

Other changes in capital. Capital contributions were $28.7 million, $40.2 million and $3.3 million during 2006, 2007 and 2008, respectively. Capital contributions for 2006 and 2007 included payments of $20.0 million and $35.0 million, respectively, we received under the May 2004 indemnity settlement. 2006 capital contributions included a $4.2 million payment made by MGG to us related to an amendment of our partnership agreement to restore the incentive distributions to the same level as before an amendment made in connection with a 2004 acquisition which reduced the incentive distributions paid to our general partner in 2004, 2005 and 2006 (see Note 9—Related Party Transactions). The remaining capital contributions are primarily from amounts we received from MGG under the G&A cost cap agreement.

21. 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 first quarter 2008, we obtained a full release from the 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. As a result, we wrote off the unamortized amount of the liability and recognized a gain of $26.5 million.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

22. Subsequent Events

On January 23, 2009, we issued 210,149 limited partner units, of which 209,321 were issued to settle the cumulative amount of the 2006 and 2007 unit award grants to certain employees that vested on December 31, 2008, and 828 were issued to settle the equity-based retainer paid to one of the directors of our general partner. Our general partner did not make an equity contribution associated with this equity issuance and as a result its general partner ownership interest in us changed from 1.989% to 1.983%. Our general partner’s incentive distribution rights were not affected by this transaction. As a result, cash distributions paid after January 23, 2009 will be made based on the following table:

	Percentage of Distributions
			General Partner
Quarterly Distribution Amount per Unit	Limited Partners		General Partner Interest		Incentive Distribution Rights
Up to $0.289	98.017	%	1.983	%	0.000	%
Above $0.289 up to $0.328	85.017	%	1.983	%	13.000	%
Above $0.328 up to $0.394	75.017	%	1.983	%	23.000	%
Above $0.394	50.017	%	1.983	%	48.000	%

On February 10, 2009, our Compensation Committee approved 285,000 unit award grants pursuant to the long-term incentive plan. These award grants have a three-year vesting period that will end on December 31, 2011.

On February 13, 2009, we paid cash distributions of $0.71 per unit on our outstanding limited partner units to unitholders of record at the close of business on February 6, 2009. The total distributions paid were $71.0 million, of which $1.4 million was paid to our general partner on its approximate 2% general partner interest and $22.1 million on its incentive distribution rights.

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