UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________

FORM 10-Q



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

For the quarterly period ended ~~September 30, 2013~~March 31, 2014



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

For the transition period from to

Commission File No.: 1-16335

_________________________________________

Magellan Midstream Partners, L.P.

(Exact name of registrant as specified in its charter)



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

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

(Address of principal executive offices and zip code)

(918) 574-7000

(Registrant’s telephone number, including area code)

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

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

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

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

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

Act). Yes £ No x

As of ~~October 31, 2013,~~May 5, 2014, there were ~~226,679,438~~227,068,257 outstanding limited partner units of Magellan Midstream Partners, L.P. that trade on the New York Stock Exchange under the ticker symbol "MMP."

Table of Contents

TABLE OF CONTENTS

PART I

FINANCIAL INFORMATION


ITEM 1.	ITEM 1.	CONSOLIDATED FINANCIAL STATEMENTS		ITEM 1.	CONSOLIDATED FINANCIAL STATEMENTS
	CONSOLIDATED STATEMENTS OF INCOME		2	CONSOLIDATED STATEMENTS OF INCOME		2
	CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME		3	CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME		3
	CONSOLIDATED BALANCE SHEETS		4	CONSOLIDATED BALANCE SHEETS		4
	CONSOLIDATED STATEMENTS OF CASH FLOWS		5	CONSOLIDATED STATEMENTS OF CASH FLOWS		5
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS:			NOTES TO CONSOLIDATED FINANCIAL STATEMENTS:
	1.	Organization, Description of Business and Basis of Presentation	6	1.	Organization, Description of Business and Basis of Presentation	6
	2.	Product Sales Revenue	7	2.	Product Sales Revenue	7
	3.	Segment Disclosures	7	3.	Segment Disclosures	8
	4.	Investments in Non-Controlled Entities	10	4.	Investments in Non-Controlled Entities	9
	5.	Inventory	11	5.	Inventory	11
	6.	Employee Benefit Plans	11	6.	Employee Benefit Plans	11
	7.	Debt	12	7.	Debt	12
	8.	Derivative Financial Instruments	12	8.	Derivative Financial Instruments	13
	9.	Commitments and Contingencies	16	9.	Commitments and Contingencies	18
	10.	Long-Term Incentive Plan	17	10.	Long-Term Incentive Plan	19
	11.	Distributions	18	11.	Distributions	20
	12.	Fair Value	19	12.	Fair Value	21
	13.	Related Party Transactions	20	13.	Related Party Transactions	22
	14.	Subsequent Events	20	14.	Subsequent Events	23
ITEM 2.	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Introduction		21	Introduction		24
	Recent Developments		21	Recent Developments		24
	Results of Operations		22	Results of Operations		25
	Distributable Cash Flow		27	Distributable Cash Flow		28
	Liquidity and Capital Resources		28	Liquidity and Capital Resources		29
	Off-Balance Sheet Arrangements		30	Off-Balance Sheet Arrangements		32
	Environmental		30	Environmental		32
	Other Items		31	Other Items		32
	New Accounting Pronouncements		33	New Accounting Pronouncements		34
ITEM 3.	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	34	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	35
ITEM 4.	ITEM 4.	CONTROLS AND PROCEDURES	34	ITEM 4.	CONTROLS AND PROCEDURES	36
Forward-Looking Statements	Forward-Looking Statements		35	Forward-Looking Statements		36
PART II OTHER INFORMATION	PART II OTHER INFORMATION			PART II OTHER INFORMATION
ITEM 1.	ITEM 1.	LEGAL PROCEEDINGS	37	ITEM 1.	LEGAL PROCEEDINGS	38
ITEM 1A.	ITEM 1A.	RISK FACTORS	37	ITEM 1A.	RISK FACTORS	39
ITEM 2.	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	38	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	39
ITEM 3.	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	38	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	39
ITEM 4.	ITEM 4.	MINE SAFETY DISCLOSURES	38	ITEM 4.	MINE SAFETY DISCLOSURES	39
ITEM 5.	ITEM 5.	OTHER INFORMATION	38	ITEM 5.	OTHER INFORMATION	39
ITEM 6.	ITEM 6.	EXHIBITS	39	ITEM 6.	EXHIBITS	40

Table of Contents

PART I

FINANCIAL INFORMATION


ITEM 1.	CONSOLIDATED FINANCIAL STATEMENTS

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per unit amounts)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2012			2013			2012			2013			2013			2014
Transportation and terminals revenue	$	255,492		$	295,326		$	721,807		$	805,059		$	227,271		$	317,637
Product sales revenue	70,178			144,852			546,476			504,485			201,711			296,063
Affiliate management fee revenue	199			3,657			596			10,624			3,439			4,906
Total revenue	325,869			443,835			1,268,879			1,320,168			432,421			618,606
Costs and expenses:
Operating	103,272			103,262			254,050			245,858			65,181			73,497
Product purchases	85,819			120,299			478,929			396,025
Cost of product sales													160,398			198,040
Depreciation and amortization	31,692			35,270			94,688			105,788			36,332			37,511
General and administrative	27,551			32,755			76,709			96,073			30,056			34,935
Total costs and expenses	248,334			291,586			904,376			843,744			291,967			343,983
Earnings of non-controlled entities	1,749			2,375			4,875			5,162			2,051			466
Operating profit	79,284			154,624			369,378			481,586			142,505			275,089
Interest expense	29,113			31,852			87,354			95,295			31,723			36,416
Interest income	(16		)	(215		)	(80		)	(250		)	(22		)	(391		)
Interest capitalized	(1,439		)	(3,780		)	(3,331		)	(10,474		)	(3,451		)	(5,310		)
Debt placement fee amortization expense	519			540			1,556			1,620			540			599
Income before provision for income taxes	51,107			126,227			283,879			395,395			113,715			243,775
Provision for income taxes	585			604			2,012			3,165			748			1,221
Net income	$	50,522		$	125,623		$	281,867		$	392,230		$	112,967		$	242,554
Basic and diluted net income per limited partner unit	$	0.22		$	0.55		$	1.25		$	1.73		$	0.50		$	1.07
Weighted average number of limited partner units outstanding used for basic and diluted net income per unit calculation	226,431			226,866			226,348			226,812			226,705			227,141

See notes to consolidated financial statements.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited, in thousands)

Three Months Ended September 30, Nine Months Ended September 30,
2012 2013 2012 2013
Net income $ 50,522
$ 125,623
$ 281,867
$ 392,230
Other comprehensive income:

Net gain (loss) on cash flow hedges⁽¹⁾
9,666
(36 ) 12,341
(4,596 )
Reclassification of net loss (gain) on cash flow hedges to income⁽²⁾
(1,425 ) (41 ) (1,507 ) 4,285
Changes in employee benefit plan assets and benefit obligations recognized in income⁽³⁾
(2,812 ) 491
(1,107 ) 1,473
Adjustment to recognize the funded status of postretirement plans 8,325
(367 ) 8,325
(367 )
Total other comprehensive income 13,754
47
18,052
795
Comprehensive income $ 64,276
$ 125,670
$ 299,919
$ 393,025



	Three Months Ended March 31,
	2013			2014
Net income	$	112,967		$	242,554
Other comprehensive income:
Derivative activity:
Net loss on cash flow hedges⁽¹⁾	(4,560		)	(3,613		)
Reclassification of net loss (gain) on cash flow hedges to income⁽¹⁾	4,367			(26		)
Changes in employee benefit plan assets and benefit obligations recognized in other comprehensive income:
Amortization of actuarial loss⁽²⁾	1,330			824
Amortization of prior service credit⁽²⁾	(851		)	(895		)
Total other comprehensive income (loss)	286			(3,710		)
Comprehensive income	$	113,253		$	238,844

(1) See Note 8–Derivative Financial Instruments for ~~additional information on unrealized gains and losses on cash flow hedges~~details of the amount of gain/loss recognized in accumulated other comprehensive ~~loss.~~

~~(2) See Note 8–Derivative Financial Instruments~~ ~~for additional information~~loss ("AOCL") on ~~amounts~~derivatives and the amount of gain/loss reclassified ~~out of accumulated other comprehensive loss~~from AOCL into income.

~~(3)~~(2) These ~~accumulated other comprehensive loss~~AOCL components are included in the computation of net periodic pension cost (see Note 6–Employee Benefit Plans).

See notes to consolidated financial statements.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands)


	December 31, 2012			September 30, 2013			December 31, 2013			March 31, 2014
ASSETS				(Unaudited)						(Unaudited)
Current assets:
Cash and cash equivalents	$	328,278		$	14,228		$	25,235		$	196,630
Trade accounts receivable (less allowance for doubtful accounts of $5 at December 31, 2012)	91,114			107,710
Trade accounts receivable							116,295			101,292
Other accounts receivable	12,329			6,827			6,462			12,202
Inventory	221,888			208,485			187,224			210,235
Energy commodity derivatives contracts, net	—			8,441
Energy commodity derivatives deposits	18,304			10,294			14,782			12,714
Other current assets	28,365			31,296			46,735			33,969
Total current assets	700,278			387,281			396,733			567,042
Property, plant and equipment	4,408,550			4,764,325			4,986,750			5,017,786
Less: Accumulated depreciation	943,248			1,039,139			1,070,492			1,104,191
Net property, plant and equipment	3,465,302			3,725,186			3,916,258			3,913,595
Investments in non-controlled entities	107,356			291,384			360,852			487,295
Long-term receivables	5,135			3,140			2,730			30,365
Goodwill	53,260			53,260			53,260			53,260
Other intangibles (less accumulated amortization of $16,715 and $8,130 at December 31, 2012 and September 30, 2013, respectively)	13,274			7,969
Debt placement costs (less accumulated amortization of $7,886 and $9,506 at December 31, 2012 and September 30, 2013, respectively)	15,080			13,532
Other intangibles (less accumulated amortization of $8,809 and $9,489 at December 31, 2013 and March 31, 2014, respectively)							7,290			6,610
Debt placement costs (less accumulated amortization of $9,113 and $9,712 at December 31, 2013 and March 31, 2014, respectively)							17,505			19,554
Tank bottom inventory	58,493			63,184			61,915			62,635
Other noncurrent assets	1,889			3,069			4,269			3,426
Total assets	$	4,420,067		$	4,548,005		$	4,820,812		$	5,143,782
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable	$	112,002		$	83,190		$	76,326		$	73,417
Accrued payroll and benefits	32,434			38,216			42,243			27,691
Accrued interest payable	42,059			37,174			44,935			50,129
Accrued taxes other than income	33,089			38,395			38,574			31,095
Environmental liabilities	14,442			14,169			12,147			13,631
Deferred revenue	46,371			67,882			63,164			64,612
Accrued product purchases	72,049			69,702			63,033			43,055
Energy commodity derivatives contracts, net	7,338			—			6,737			3,421
Current portion of long-term debt	—			249,954			249,971			249,988
Other current liabilities	32,836			43,078			41,146			47,111
Total current liabilities	392,620			641,760			638,276			604,150
Long-term debt	2,393,408			2,236,761			2,435,316			2,691,288
Long-term pension and benefits	68,134			63,036			51,637			55,736
Other noncurrent liabilities	16,382			20,068			21,802			19,660
Environmental liabilities	33,821			23,327			26,339			23,462
Commitments and contingencies
Partners’ capital:
Limited partner unitholders (226,201 units and 226,679 units outstanding at December 31, 2012 and September 30, 2013, respectively)	1,550,760			1,597,316
Limited partner unitholders (226,679 units and 227,068 units outstanding at December 31, 2013 and March 31, 2014, respectively)							1,666,946			1,772,700
Accumulated other comprehensive loss	(35,058		)	(34,263		)	(19,504		)	(23,214		)
Total partners’ capital	1,515,702			1,563,053			1,647,442			1,749,486
Total liabilities and partners' capital	$	4,420,067		$	4,548,005		$	4,820,812		$	5,143,782

See notes to consolidated financial statements.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)


	Nine Months Ended						Three Months Ended
	September 30,						March 31,
	2012			2013			2013			2014
Operating Activities:
Net income	$	281,867		$	392,230		$	112,967		$	242,554
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	94,688			105,788			36,332			37,511
Debt placement fee amortization expense	1,556			1,620			540			599
Loss on sale, retirement and impairment of assets	10,575			4,269			1,791			1,205
Earnings of non-controlled entities	(4,875		)	(5,162		)	(2,051		)	(466		)
Distributions from investments in non-controlled entities	4,875			1,907			676			384
Equity-based incentive compensation expense	12,555			14,499			4,856			5,088
Changes in employee benefit plan assets and benefit obligations	(1,107		)	1,473			479			(71		)
Changes in operating assets and liabilities:
Trade accounts receivable and other accounts receivable	(22,561		)	(11,094		)	(16,833		)	15,022
Inventory	38,144			13,403			16,736			(23,011		)
Energy commodity derivatives contracts, net of derivatives deposits	7,047			(8,887		)	1,311			(529		)
Accounts payable	(14,840		)	956			11,310			2,960
Accrued payroll and benefits	(279		)	5,782			(10,713		)	(14,552		)
Accrued interest payable	(7,283		)	(4,885		)	(4,653		)	5,194
Accrued taxes other than income	4,363			5,306			(5,798		)	(7,479		)
Accrued product purchases	10,726			(2,347		)	6,273			(19,978		)
Deferred revenue	5,082			21,511			10,647			1,448
Current and noncurrent environmental liabilities	1,977			(10,767		)	(1,469		)	(1,393		)
Other current and noncurrent assets and liabilities	(10,268		)	(4,361		)	4,540			25,588
Net cash provided by operating activities	412,242			521,241			166,941			270,074
Investing Activities:
Property, plant and equipment:
Additions to property, plant and equipment	(230,015		)	(289,669		)	(89,947		)	(70,295		)
Proceeds from sale and disposition of assets	255			2,414			25			42
Increase (decrease) in accounts payable related to capital expenditures	45,197			(29,768		)
Acquisition of business	—			(57,000		)
Acquisition of assets	—			(22,500		)
Increase in accounts payable related to capital expenditures							(11,863		)	(5,219		)
Investments in non-controlled entities	(37,495		)	(181,377		)	(47,020		)	(127,698		)
Distributions in excess of earnings of non-controlled entities	1,228			604			188			687
Net cash used by investing activities	(220,830		)	(577,296		)	(148,617		)	(202,483		)
Financing Activities:
Distributions paid	(293,778		)	(349,087		)	(113,340		)	(132,835		)
Net borrowings under revolver	—			98,400
Increase in outstanding checks	6,238			4,951
Borrowings under long-term notes							—			257,713
Debt placement costs							—			(2,648		)
Net payment on financial derivatives							—			(3,613		)
Settlement of tax withholdings on long-term incentive compensation	(13,001		)	(12,259		)	(12,259		)	(14,813		)
Net cash used by financing activities	(300,541		)	(257,995		)
Net cash provided (used) by financing activities							(125,599		)	103,804
Change in cash and cash equivalents	(109,129		)	(314,050		)	(107,275		)	171,395
Cash and cash equivalents at beginning of period	209,620			328,278			328,278			25,235
Cash and cash equivalents at end of period	$	100,491		$	14,228		$	221,003		$	196,630
Supplemental non-cash financing activity:
Supplemental non-cash investing and financing activities:
Issuance of limited partner units in settlement of equity-based incentive plan awards	$	7,295		$	6,404		$	6,404		$	7,315

See notes to consolidated financial statements.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.	Organization, Description of Business and Basis of Presentation

Organization

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

During first quarter 2013, we completed a reorganization of our reporting segments. This reorganization was effected to reflect strategic changes in our businesses, particularly in the area of our crude oil activities, which have had or will have a significant impact on the way we manage our operations. Accordingly, we have updated our segment disclosures for all previous periods included in this report. Our reportable segments offer different products and services and are managed separately because each requires different marketing strategies and business knowledge.

Description of Business

We are principally engaged in the transportation, storage and distribution of refined petroleum products and crude oil. As of ~~September 30, 2013~~March 31, 2014, our asset portfolio including the assets of our joint ventures consisted of:

our refined products segment, including ~~almost~~our ~~9,100~~9,500 ~~miles of~~-mile refined products pipeline system with 4954 ~~connected~~ terminals as well as 27 independent terminals not connected to our pipeline system and our 1,100-mile ammonia pipeline system;

our crude oil segment, comprised of approximately ~~800~~1,100 miles of crude oil pipelines and storage facilities with an aggregate ~~leasable~~ storage capacity of approximately 18 million barrels, of which 1512 million ~~barrels;~~is used for leased storage; and

our marine storage segment, consisting of five marine terminals located along coastal waterways with an aggregate storage capacity of ~~more than~~approximately 2627 million barrels.

Products transported, stored and distributed through our pipelines and terminals include:

refined products, which are the output from refineries and are primarily used as fuels by consumers. Refined products include gasoline, diesel fuel, aviation fuel, kerosene and heating oil. Collectively, diesel fuel and heating oil are referred to as distillates;

liquefied petroleum gases, or LPGs, which are produced as by-products of the crude oil refining process and in connection with natural gas production. LPGs include butane and propane;

blendstocks, which are blended with refined products to change or enhance their characteristics such as increasing a gasoline's octane or oxygen content. Blendstocks include alkylates, oxygenates and ~~oxygenates;~~natural gasoline;

heavy oils and feedstocks, which are used as burner fuels or feedstocks for further processing by refineries and petrochemical facilities. Heavy oils and feedstocks include No. 6 fuel oil and vacuum gas oil;

crude oil and condensate, which are used as feedstocks by refineries and petrochemical facilities;

biofuels, such as ethanol and biodiesel, which are increasingly required by government mandates; and

ammonia, which is primarily used as a nitrogen fertilizer.

Except for ammonia, we use the term petroleum products to describe any, or a combination, of the above-noted products.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Basis of Presentation

In the opinion of management, our accompanying consolidated financial statements which are unaudited, except for the consolidated balance sheet as of December 31, ~~2012~~2013, which is derived from our audited financial statements, include all normal and recurring adjustments necessary to present fairly our financial position as of ~~September 30, 2013~~March 31, 2014, the results of operations

~~Table of Contents~~

for the three ~~and~~ ~~nine~~months ended ~~September 30, 2012~~March 31, 2013 and ~~2013~~2014 and cash flows for the ~~nine~~three months ended ~~September 30, 2012~~March 31, 2013 and ~~2013~~2014. The results of operations for the ~~nine~~three months ended ~~September 30, 2013~~March 31, 2014 are not necessarily indicative of the results to be expected for the full year ending December 31, ~~2013.~~2014.

Pursuant to the rules and regulations of the Securities and Exchange Commission, the financial statements in this report do not include all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States. These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, ~~2012~~2013 ~~and the updates to our Annual Report reflecting changes in our reporting segments included in our Current Report on Form 8-K filed with the Securities and Exchange Commission on April 29, 2013.~~.


2.	Product Sales Revenue

The amounts reported as product sales revenue on our consolidated statements of income include revenue from the physical sale of petroleum products and from mark-to-market adjustments from New York Mercantile Exchange ("NYMEX") contracts. We use NYMEX contracts to hedge against changes in the price of refined products we expect to sell from our business activities where we acquire or produce petroleum products. Some of these NYMEX contracts qualify for hedge accounting treatment and we designate and account for these as either cash flow or fair value hedges. The effective portion of the fair value changes in contracts designated as cash flow hedges are recognized as adjustments to product sales when the hedged product is physically sold. Ineffectiveness in the contracts designated as cash flow hedges is recognized as an adjustment to product sales in the period the ineffectiveness occurs. We account for NYMEX contracts that do not qualify for hedge accounting treatment as economic hedges, with the period changes in fair value recognized as product sales, except for those agreements that economically hedge the inventories associated with our pipeline system overages (the period changes in the fair value of these agreements are charged to operating expense). See Note 8 – Derivative Financial Instruments for further disclosures regarding our NYMEX contracts.

For the three ~~and~~ ~~nine~~months ended ~~September 30, 2012~~March 31, 2013 and ~~2013~~2014, product sales revenue included the following (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2012			2013			2012			2013			2013			2014
Physical sale of petroleum products	$	113,500		$	146,887		$	584,624		$	500,347		$	207,880		$	293,240
NYMEX contract adjustments:
Change in value of NYMEX contracts that did not qualify for hedge accounting treatment and the effective portion of gains and losses of matured NYMEX contracts that qualified for hedge accounting treatment associated with our butane blending and fractionation activities⁽¹⁾	(36,172		)	(2,035		)	(33,211		)	4,149			(6,158		)	2,823
Change in value of NYMEX contracts that did not qualify for hedge accounting treatment associated with the Houston-to-El Paso pipeline linefill working inventory⁽¹⁾	(7,080		)	—			(5,159		)	—
Other	(70		)	—			222			(11		)	(11		)	—
Total NYMEX contract adjustments	(43,322		)	(2,035		)	(38,148		)	4,138			(6,169		)	2,823
Total product sales revenue	$	70,178		$	144,852		$	546,476		$	504,485		$	201,711		$	296,063

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

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


3.	Segment Disclosures

~~During the first quarter of 2013, we revised our reporting segments. See Note 1 –~~ ~~Organization, Description of Business and Basis of Presentation~~ ~~for a discussion of this matter.~~

Our reportable segments are strategic business units that offer different products and services. Our segments are managed separately because each segment requires different marketing strategies and business knowledge. Management evaluates performance based on segment operating margin, which includes revenue from affiliates and external customers, operating

~~Table~~ expenses, cost of ~~Contents~~

~~MAGELLAN MIDSTREAM PARTNERS, L.P.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

~~expenses,~~ product ~~purchases~~sales and earnings of non-controlled entities. Transactions between our business segments are conducted and recorded on the same basis as transactions with third-party entities.

We believe that investors benefit from having access to the same financial measures used by management. Operating margin, which is presented in the following tables, is an important measure used by management to evaluate the economic performance of our core operations. Operating margin is not a generally accepted accounting principles ("GAAP") measure, but the components of operating margin are computed 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 depreciation and amortization expense and general and administrative ("G&A") expenses that management does not ~~focus on~~consider when evaluating the core profitability of our separate operating segments.


	Three Months Ended September 30, 2012													Three Months Ended March 31, 2013
	(in thousands)													(in thousands)
	Refined Products		Crude Oil			Marine Storage		Intersegment Eliminations			Total			Refined Products		Crude Oil			Marine Storage			Intersegment Eliminations			Total
Transportation and terminals revenue	$	193,880	$	23,868		$	37,744	$	—		$	255,492		$	165,359	$	23,228		$	38,684		$	—		$	227,271
Product sales revenue	66,776		—			3,402		—			70,178			199,415		—			2,296			—			201,711
Affiliate management fee revenue	—		199			—		—			199			—		3,159			280			—			3,439
Total revenue	260,656		24,067			41,146		—			325,869			364,774		26,387			41,260			—			432,421
Operating expenses	80,705		3,441			19,824		(698		)	103,272			46,281		5,107			14,553			(760		)	65,181
Product purchases	84,041		—			1,778		—			85,819
(Earnings) losses of non-controlled entities	—		(1,752		)	3		—			(1,749		)
Cost of product sales														158,298		—			2,100			—			160,398
Earnings of non-controlled entities														—		(1,375		)	(676		)	—			(2,051		)
Operating margin	95,910		22,378			19,541		698			138,527			160,195		22,655			25,283			760			208,893
Depreciation and amortization expense	21,432		2,885			6,677		698			31,692			21,353		7,469			6,750			760			36,332
G&A expenses	21,948		1,375			4,228		—			27,551			21,202		4,127			4,727			—			30,056
Operating profit	$	52,530	$	18,118		$	8,636	$	—		$	79,284		$	117,640	$	11,059		$	13,806		$	—		$	142,505

Three Months Ended September 30, 2013
(in thousands)
Refined Products Crude Oil Marine Storage
Intersegment
Eliminations
Total
Transportation and terminals revenue $ 205,859
$ 49,519
$ 39,948
$ —
$ 295,326
Product sales revenue 143,549
—
1,303
—
144,852
Affiliate management fee revenue —
3,369
288
—
3,657
Total revenue 349,408
52,888
41,539
—
443,835
Operating expenses 82,174
4,034
17,813
(759 ) 103,262
Product purchases 120,429
—
(130 ) —
120,299
Earnings of non-controlled entities —
(1,770 ) (605 ) —
(2,375 )
Operating margin 146,805
50,624
24,461
759
222,649
Depreciation and amortization expense 21,851
5,538
7,122
759
35,270
G&A expenses 22,741
5,100
4,914
—
32,755
Operating profit $ 102,213
$ 39,986
$ 12,425
$ —
$ 154,624

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Nine Months Ended September 30, 2012
(in thousands)
Refined Products Crude Oil Marine Storage
Intersegment
Eliminations
Total
Transportation and terminals revenue $ 538,812
$ 67,626
$ 115,369
$ —
$ 721,807
Product sales revenue 539,434
—
7,042
—
546,476
Affiliate management fee revenue —
596
—
—
596
Total revenue 1,078,246
68,222
122,411
—
1,268,879
Operating expenses 204,064
4,046
48,042
(2,102 ) 254,050
Product purchases 475,839
—
3,090
—
478,929
(Earnings) losses of non-controlled entities —
(4,913 ) 38
—
(4,875 )
Operating margin 398,343
69,089
71,241
2,102
540,775
Depreciation and amortization expense 64,075
8,641
19,870
2,102
94,688
G&A expenses 61,258
3,766
11,685
—
76,709
Operating profit $ 273,010
$ 56,682
$ 39,686
$ —
$ 369,378


	Nine Months Ended September 30, 2013														Three Months Ended March 31, 2014
	(in thousands)														(in thousands)
	Refined Products		Crude Oil			Marine Storage			Intersegment Eliminations			Total			Refined Products		Crude Oil		Marine Storage			Intersegment Eliminations			Total
Transportation and terminals revenue	$	573,615	$	113,905		$	117,539		$	—		$	805,059		$	210,236	$	67,903	$	39,498		$	—		$	317,637
Product sales revenue	499,285		—			5,200			—			504,485			293,710		—		2,353			—			296,063
Affiliate management fee revenue	—		9,767			857			—			10,624			—		4,595		311			—			4,906
Total revenue	1,072,900		123,672			123,596			—			1,320,168			503,946		72,498		42,162			—			618,606
Operating expenses	194,911		13,168			40,060			(2,281		)	245,858			51,157		9,058		14,086			(804		)	73,497
Product purchases	393,187		—			2,838			—			396,025
Earnings of non-controlled entities	—		(3,255		)	(1,907		)	—			(5,162		)
Cost of product sales															197,756		—		284			—			198,040
Losses (earnings) of non-controlled entities															—		180		(646		)	—			(466		)
Operating margin	484,802		113,759			82,605			2,281			683,447			255,033		63,260		28,438			804			347,535
Depreciation and amortization expense	64,428		18,111			20,968			2,281			105,788			23,172		6,463		7,072			804			37,511
G&A expenses	67,235		14,142			14,696			—			96,073			23,019		5,994		5,922			—			34,935
Operating profit	$	353,139	$	81,506		$	46,941		$	—		$	481,586		$	208,842	$	50,803	$	15,444		$	—		$	275,089

~~Table of Contents~~

~~MAGELLAN MIDSTREAM PARTNERS, L.P.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~


4.	Investments in Non-Controlled Entities

We own a 50% interest in Texas Frontera, LLC ("Texas Frontera"), which owns approximately ~~0.8~~one million barrels of refined products storage at our Galena Park, Texas terminal. The storage capacity owned by this joint venture is leased to an affiliate of Texas Frontera under a long-term lease agreement. ~~Texas Frontera began operations in October 2012.~~ We receive management fees from Texas Frontera, which we report as affiliate management fee revenue on our consolidated statements of income.

We own a 50% interest in Osage Pipe Line Company, LLC ("Osage"), which owns a 135-mile crude oil pipeline in Oklahoma and Kansas that we operate. We receive management fees from Osage, which we report as affiliate management fee revenue on our consolidated statements of income. Our initial investment in Osage included an excess net investment amount of $21.7 million. Excess investment is the amount by which our initial investment exceeded our proportionate share of the book value of the net assets of the investment. The unamortized excess net investment amount at March 31, 2014 was $15.0 million.

We own a 50% interest in Double Eagle Pipeline LLC ("Double Eagle"), which ~~owns a~~ ~~140~~-mile pipeline that connects to an existing pipeline owned by an affiliate of Double Eagle. Double Eagle is operated by a third-party entity. This pipeline, which began operating in second quarter 2013, transports condensate from the Eagle Ford shale formation in South Texas via a 195-mile pipeline to our terminal in Corpus Christi, Texas. Double Eagle is operated by an affiliate of the other 50% member of Double Eagle. We receive ~~connection fees~~throughput revenue from Double Eagle that ~~are~~is included in our transportation and terminals revenue on our consolidated statements of income. For the three ~~and~~ ~~nine~~ months ended ~~September 30, 2013~~March 31, 2014, we received ~~connection fees~~throughput revenue of $0.5 million ~~and~~ ~~$0.8 million, respectively, and we~~. We recorded a $0.2 million and $0.3 million trade accounts receivable from Double Eagle at December 31, 2013 and ~~September 30, 2013~~March 31, 2014., respectively.

We own a 50% interest in BridgeTex Pipeline Company, LLC ("BridgeTex"), which is in the process of constructing a 450-mile pipeline with related infrastructure to transport crude oil from Colorado City, Texas for delivery to Houston and Texas City, Texas refineries. This pipeline is expected to begin service in mid-2014. We receive construction management fees from BridgeTex, which we report as affiliate management fee revenue on our consolidated statements of income.

~~A summary~~

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

During 2013, we received $4.8 million from BridgeTex as a deposit for the purchase of emission reduction credits, which, pending governmental approval, we expect to transfer to BridgeTex during the second quarter of 2014. Also in 2013, we received $1.4 million from BridgeTex for the purchase of easement rights from us, of which $0.7 million was recorded as a reduction of operating expense and $0.7 million was recorded as an adjustment to our ~~investments~~investment in ~~non-controlled entities follows (in thousands):~~

Texas Frontera Osage Double Eagle BridgeTex Consolidated
Investment at December 31, 2012 $ 15,728
$ 18,888
$ 40,840
$ 31,900
$ 107,356
Additional investment —
—
33,454
147,923
181,377
Earnings (losses) of non-controlled entities:
Proportionate share of earnings 1,907
3,610
141
2
5,660
Amortization of excess investment —
(498 ) —
—
(498 )
Earnings of non-controlled entities 1,907
3,112
141
2
5,162
Less:
Distributions of earnings from investments in non-controlled entities 1,907
—
—
—
1,907
Distributions in excess of earnings of non-controlled entities 604
—
—
—
604
Investment at September 30, 2013 $ 15,124
$ 22,000
$ 74,435
$ 179,825
$ 291,384

BridgeTex, which will be amortized as a reduction of operating expense over the weighted average depreciable lives of the BridgeTex assets.

The operating results from Texas Frontera are included in our marine storage segment and the operating results from Osage, Double Eagle and BridgeTex are included in our crude oil ~~segment.~~segment as earnings of non-controlled entities.

~~Our initial investment~~A summary of our investments in ~~Osage included an excess net investment amount~~non-controlled entities follows (in thousands):



	BridgeTex			All Others			Consolidated
Investment at December 31, 2013	$	246,875		$	113,977		$	360,852
Additional investment	126,748			950			127,698
Other adjustment to investment	—			(650		)	(650		)
Earnings (losses) of non-controlled entities:
Proportionate share of earnings (loss)	(20		)	674			654
Amortization of excess investment and capitalized interest	—			(188		)	(188		)
Earnings (losses) of non-controlled entities	(20		)	486			466
Less:
Distributions of earnings from investments in non-controlled entities	—			384			384
Distributions in excess of earnings of non-controlled entities	—			687			687
Investment at March 31, 2014	$	373,603		$	113,692		$	487,295

Summarized financial information of ~~$21.7 million. Excess investment is~~our non-controlled entities as of and for the ~~amount by which our initial investment exceeded our proportionate share of the book value of the net assets of the investment. The unamortized excess net investment amount at~~ ~~September 30, 2013~~ ~~was~~ ~~$15.3 million~~.

three months ended March 31, 2014 follows (in thousands):

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	BridgeTex			All Others		Consolidated
Current assets	$	78,654		$	19,204	$	97,858
Noncurrent assets	634,188			176,514		810,702
Total assets	$	712,842		$	195,718	$	908,560
Current liabilities	101,712			3,224		104,936
Noncurrent liabilities	—			96		96
Total liabilities	$	101,712		$	3,320	$	105,032
Equity	$	611,130		$	192,398	$	803,528

Revenue	$	—		$	6,755	$	6,755
Net income (loss)	$	(40	)	$	1,347	$	1,307


5.	Inventory

Inventory at December 31, ~~2012~~2013 and ~~September 30, 2013~~March 31, 2014 was as follows (in thousands):


	December 31, 2012		September 30, 2013		December 31, 2013		March 31, 2014
Refined products	$	88,630	$	44,470	$	77,144	$	76,229
Liquefied petroleum gases	45,657		93,202		23,476		33,398
Transmix	63,026		57,238		72,156		79,127
Crude oil	17,443		7,124		7,188		15,852
Additives	7,132		6,451		7,260		5,629
Total inventory	$	221,888	$	208,485	$	187,224	$	210,235


6.	Employee Benefit Plans

We sponsor two union pension plans for certain union employees and a pension plan primarily for salaried employees, a postretirement benefit plan for selected employees and a defined contribution plan. The following tables present our consolidated net periodic benefit costs related to the pension and postretirement benefit plans for the three ~~and~~ ~~nine~~months ended ~~September 30, 2012~~March 31, 2013 and ~~2013~~2014 (in thousands):

Three Months Ended Three Months Ended
September 30, 2012 September 30, 2013

Pension
Benefits

Other Post-
Retirement
Benefits

Pension
Benefits

Other Post-
Retirement
Benefits
Components of net periodic benefit costs:
Service cost $ 2,786
$ 22
$ 3,476
$ 72
Interest cost 1,240
101
1,342
103
Expected return on plan assets (1,448 ) —
(1,556 ) —
Amortization of prior service cost (credit)⁽¹⁾
77
—
76
(928 )
Amortization of actuarial loss⁽¹⁾
1,051
141
1,084
259
Curtailment gain⁽¹⁾
—
(4,081 ) —
—
Net periodic benefit cost (credit) $ 3,706
$ (3,817 ) $ 4,422
$ (494 )

Nine Months Ended Nine Months Ended
September 30, 2012 September 30, 2013

Pension
Benefits

Other Post-
Retirement
Benefits

Pension
Benefits

Other Post-
Retirement
Benefits
Components of net periodic benefit costs:
Service cost $ 9,166
$ 297
$ 10,426
$ 216
Interest cost 3,647
616
4,026
309
Expected return on plan assets (3,800 ) —
(4,671 ) —
Amortization of prior service cost (credit)⁽¹⁾
231
(424 ) 230
(2,784 )
Amortization of actuarial loss⁽¹⁾
2,704
463
3,251
776
Curtailment gain⁽¹⁾
—
(4,081 ) —
—
Net periodic benefit cost (credit) $ 11,948
$ (3,129 ) $ 13,262
$ (1,483 )

~~(1)These amounts are included in our Consolidated Statements of Comprehensive Income and Consolidated Statement of Cash Flows as changes in employee benefit plan assets and benefit obligations.~~

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Three Months Ended						Three Months Ended
	March 31, 2013						March 31, 2014
	Pension Benefits			Other Post- Retirement Benefits			Pension Benefits			Other Post- Retirement Benefits
Components of net periodic benefit costs:
Service cost	$	3,576		$	77		$	3,352		$	67
Interest cost	1,350			115			1,659			114
Expected return on plan assets	(1,470		)	—			(1,697		)	—
Amortization of prior service cost (credit)⁽¹⁾	77			(928		)	33			(928		)
Amortization of actuarial loss⁽¹⁾	1,022			308			629			195
Net periodic benefit cost (credit)	$	4,555		$	(428	)	$	3,976		$	(552	)

(1) These amounts are included in our Consolidated Statements of Comprehensive Income and Consolidated Statements of Cash Flows as changes in employee benefit plan assets and benefit obligations.


7.	Debt

Consolidated debt at December 31, ~~2012~~2013 and ~~September 30, 2013~~March 31, 2014 was as follows (in thousands, except as otherwise noted):



	December 31, 2012		September 30, 2013		Weighted-Average Interest Rate at September 30, 2013 (1)	December 31, 2013		March 31, 2014		Weighted-Average Interest Rate for Three Months Ending March 31, 2014 ⁽¹⁾
Revolving credit facility	$	—	$	98,400	1.2%	$	—	$	—	—%
$250.0 million of 6.45% Notes due 2014	249,905		249,954		6.3%	249,971		249,988		6.3%
$250.0 million of 5.65% Notes due 2016	251,609		251,288		5.7%	251,183		251,076		5.7%
$250.0 million of 6.40% Notes due 2018	261,411		259,863		5.4%	259,346		258,829		5.4%
$550.0 million of 6.55% Notes due 2019	575,065		572,412		5.7%	571,515		570,613		5.7%
$550.0 million of 4.25% Notes due 2021	558,088		557,434		4.0%	557,213		556,988		4.0%
$250.0 million of 6.40% Notes due 2037	248,981		248,994		6.4%	248,998		249,003		6.4%
$250.0 million of 4.20% Notes due 2042	248,349		248,370		4.2%	248,377		248,384		4.2%
$550.0 million of 5.15% Notes due 2043						298,684		556,395		5.2%
Total debt	$	2,393,408	$	2,486,715	5.2%	$	2,685,287	$	2,941,276	5.2%


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

The revolving credit facility and notes detailed in the table above are senior indebtedness.

The face value of our debt at December 31, ~~2012~~2013 and ~~September 30, 2013~~March 31, 2014 was $~~2.4~~2.7 billion. and $2.9 billion, respectively. The difference between the face value and carrying value of the debt outstanding is the unamortized portion of terminated fair value hedges and the unamortized discounts and premiums on debt issuances. Realized gains and losses on fair value hedges and note discounts and premiums are being amortized or accreted to the applicable notes over the respective lives of those notes.

Table of Contents

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2014 Debt Offering

In March 2014, we issued an additional $250.0 million of our 5.15% notes due October 15, 2043 in an underwritten public offering. The notes were issued at 103.1% of par. We used the net proceeds from this offering of approximately $255.1 million, after underwriting discounts and offering expenses of $2.6 million, to repay borrowings outstanding under our revolving credit facility and for general partnership purposes, including expansion capital.

Other Debt

Revolving Credit Facility. The total borrowing capacity under our revolving credit facility, which matures in ~~October 2016,~~November 2018, is $~~800.0 million~~1.0 billion. Borrowings under the facility are unsecured and bear interest at LIBOR plus a spread ranging from ~~0.875%~~1.0% to 1.75% based on our credit ~~ratings and amounts outstanding under the facility.~~ratings. Additionally, an unused commitment fee is assessed at a rate from ~~0.125%~~0.10% to ~~0.3%~~0.28%, depending on our credit ratings. The unused commitment fee was ~~0.2%~~0.125% at ~~September 30, 2013~~March 31, 2014. Borrowings under this facility may be used for general partnership purposes, including capital expenditures. As of ~~September 30, 2013~~March 31, 2014, there ~~was~~ ~~$98.4 million~~ ofwere no borrowings outstanding under this facility and $5.6 million was obligated for letters of credit. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheets, but decrease our borrowing capacity under the facility.

~~See Note 14 –~~ ~~Subsequent Events~~ ~~for a discussion of debt we issued after September 30, 2013.~~


8.	Derivative Financial Instruments

Interest Rate Derivatives

We periodically enter into interest rate derivatives to economically hedge debt, interest or expected debt issuances, and we have historically designated these derivatives as cash flow or fair value hedges for accounting purposes. Adjustments resulting from discontinued hedges continue to be recognized in accordance with their historic hedging relationships.

In ~~September 2013,~~first quarter 2014, we entered into ~~$150.0~~$200.0 million of ~~Treasury lock contracts~~interest rate swap agreements to hedge against the ~~risk of~~ variability of future interest payments on ~~a portion~~an anticipated debt issuance. We accounted for these agreements as cash flow hedges. When we issued the $250.0 million of 5.15% notes due 2043 later in the ~~debt~~first quarter of 2014, we ~~expected to issue in early October 2013. The fair value of these contracts at September 30, 2013 was a liability of less than $0.1 million. These contracts were~~ settled ~~on October 3, 2013~~the associated interest rate swap agreements for a loss of ~~$0.2 million~~ ~~(see Note 14 –~~ ~~Subsequent Events, for more information about this settlement). We have accounted for these contracts~~$3.6 million. The loss was recorded to other comprehensive income and will be recognized into earnings as an adjustment to our periodic interest expense accruals over the life of the associated notes. This loss was also reported as net payment on financial derivatives in the financing activities of our consolidated statements of cash ~~flow hedges.~~flows.

~~Table of Contents~~

~~MAGELLAN MIDSTREAM PARTNERS, L.P.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

During 2012, we terminated and settled certain interest rate swap agreements and realized a gain of $11.0 million, which was recorded to other comprehensive income. The purpose of these swaps was to hedge against the variability of future interest payments on the refinancing of our debt that matures in 2014. If management were to determine that it was probable this forecasted transaction would not occur, ~~in 2014,~~ the $11.0 million gain we have recorded to other comprehensive income would be reclassified into earnings.

Table of Contents

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Commodity Derivatives

Hedging Strategies

Our butane blending activities produce gasoline products, and we can reasonably estimate the timing and quantities of sales of these products. We use a combination of forward purchase and sale contracts, NYMEX contracts and butane futures agreements to help manage price changes, which has the effect of locking in most of the product margin realized from our butane blending activities that we choose to hedge.

We account for the forward physical purchase and sale contracts we use in our butane blending and fractionation activities as normal purchases and sales. Forward contracts that qualify for and are elected as normal purchases and sales are accounted for using traditional accrual accounting. As of ~~September 30, 2013~~March 31, 2014, we had commitments under these forward purchase and sale contracts as follows (in millions):


	Market Value		Barrels	Notional Value		Barrels
Forward purchase contracts	$	158.8	2.6	$	73.4	1.3
Forward sale contracts	$	44.4	0.4	$	25.2	0.2

We use NYMEX contracts to hedge against changes in the price of petroleum products we expect to sell in future periods. Our NYMEX contracts fall into one of three hedge categories:



Hedge Category	Hedge Purpose	Accounting Treatment
Qualifies For Hedge Accounting Treatment
Cash Flow Hedge	To hedge the variability in cash flows related to a forecasted transaction.	The effective portion of changes in the value of the hedge are recorded to accumulated other comprehensive income/loss and reclassified to earnings when the forecasted transaction occurs. Any ineffectiveness is recognized currently in earnings.
Fair Value Hedge	To hedge against changes in the fair value of a recognized asset or liability.	The effective portion of changes in the value of the hedge are recorded as adjustments to the asset or liability being hedged. Any ineffectiveness is recognized currently in earnings.
Does Not Qualify For Hedge Accounting Treatment
Economic Hedge	To effectively serve as either a fair value or a cash flow hedge; however, the derivative agreement does not qualify for hedge accounting treatment ~~or is ASC~~under Accounting Standards Codification ("ASC") 815, Derivatives and Hedging.	Changes in the value of these agreements are recognized currently in earnings.

Period changes in the fair value of NYMEX agreements that are considered economic hedges, the effective portion of changes in the fair value of cash flow hedges that are reclassified from accumulated other comprehensive income/loss and any ineffectiveness associated with hedges related to our commodity activities are recognized currently in earnings as adjustments to product sales.

We also use exchange-traded butane futures agreements, which are not designated as hedges for accounting purposes, to hedge against changes in the price of butane we expect to purchase in the future. ~~Changes~~Period changes in the fair value of these agreements are recognized currently in earnings as adjustments to cost of product ~~purchases.~~sales.

Additionally, we currently hold petroleum product inventories that we obtained from overages on our pipeline systems. We use NYMEX contracts ~~which~~that are not designated as hedges for accounting purposes to help manage price

Table of Contents

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

changes related to these overage inventory barrels. ~~Changes~~Period changes in the fair value of these agreements are recognized currently in earnings as adjustments to operating expense.

~~Table of Contents~~

~~MAGELLAN MIDSTREAM PARTNERS, L.P.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

As outlined in the table below, our open NYMEX contracts and butane futures agreements at ~~September 30, 2013~~March 31, 2014 were as follows:



Type of Contract/Accounting Methodology	Product Represented by the Contract and Associated Barrels	Maturity Dates
NYMEX - Fair Value Hedges	0.7 million barrels of crude oil	Between ~~October 2013~~April 2014 and November 2016
NYMEX - Economic Hedges	~~3.2~~2.2 million barrels of refined products and crude oil	Between ~~October 2013~~April 2014 and ~~April 2014~~January 2015
Butane Futures Agreements - Economic Hedges	~~0.4~~0.1 million barrels of butane	Between ~~October 2013~~April 2014 and ~~April 2014~~January 2015

Energy Commodity Derivatives Contracts and Deposits Offsets

At ~~September 30, 2013~~March 31, 2014, we had made margin deposits of $~~10.3~~12.7 million related to our NYMEX contracts, which were recorded as a current asset under energy commodity derivatives deposits on our consolidated balance sheet. We have the right to offset the combined fair values of our open NYMEX contracts and our open butane futures agreements against our margin deposits under a master netting arrangement; however, we have elected to disclose the combined fair values of our open NYMEX and butane futures agreements separately from the related margin deposits on our consolidated balance sheets. Additionally, we have the right to offset the fair values of our NYMEX agreements and butane futures agreements together for each counterparty, which we have elected to do, and we report the combined net balances on our consolidated balance sheets. A schedule of the derivative amounts we have offset and the deposit amounts we could offset under a master netting arrangement are provided below as of December 31, ~~2012~~2013 and ~~September 30, 2013~~March 31, 2014 (in thousands):


	December 31, 2012												December 31, 2013
Description	Gross Amounts of Recognized Liabilities			Gross Amounts of Assets Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet			Margin Deposit Amounts Not Offset in the Consolidated Balance Sheet		Net Amount		Gross Amounts of Recognized Liabilities			Gross Amounts of Assets Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet⁽¹⁾			Margin Deposit Amounts Not Offset in the Consolidated Balance Sheet		Net Asset Amount
Derivative-related balances	$	(9,388	)	$	2,050	$	(7,338	)	$	18,304	$	10,966
Energy commodity derivatives													$	(7,167	)	$	2,665	$	(4,502	)	$	14,782	$	10,280


	September 30, 2013											March 31, 2014
Description	Gross Amounts of Recognized Assets		Gross Amounts of Liabilities Offset in the Consolidated Balance Sheet			Net Amounts of Assets Presented in the Consolidated Balance Sheet		Margin Deposit Amounts Not Offset in the Consolidated Balance Sheet		Net Amount		Gross Amounts of Recognized Liabilities			Gross Amounts of Assets Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet⁽²⁾			Margin Deposit Amounts Not Offset in the Consolidated Balance Sheet		Net Asset Amount
Derivative-related balances	$	9,573	$	(166	)	$	9,407	$	10,294	$	19,701
Energy commodity derivatives												$	(3,439	)	$	1,534	$	(1,905	)	$	12,714	$	10,809

(1) Net amount includes energy commodity derivative contracts classified as current liabilities, net, of $6,737 and noncurrent assets of $2,235.

(2) Net amount includes energy commodity derivative contracts classified as current liabilities, net, of $3,421 and noncurrent assets of $1,516.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Impact of Derivatives on Income Statement, Balance Sheet, Cash Flows and AOCL

The changes in derivative activity included in ~~accumulated other comprehensive loss ("AOCL")~~AOCL for the three ~~and~~ ~~nine~~months ended ~~September 30, 2012~~March 31, 2013 and ~~2013~~2014 were as follows (in thousands):

Three Months Ended September 30, Nine Months Ended September 30,
Derivative Gains (Losses) Included in AOCL 2012 2013 2012 2013
Beginning balance $ 5,754
$ 13,892
$ 3,161
$ 14,126
Net gain (loss) on cash flow hedges 9,666
(36 ) 12,341
(4,596 )
Reclassification of net loss (gain) on cash flow hedges to income (1,425 ) (41 ) (1,507 ) 4,285
Ending balance $ 13,995
$ 13,815
$ 13,995
$ 13,815

~~As of~~ ~~September 30, 2013, the net gain estimated to be classified to interest expense over the next twelve months from AOCL is approximately~~ ~~$0.2 million~~.



	Three Months Ended March 31,
Derivative Gains (Losses) Included in AOCL	2013			2014
Beginning balance	$	14,126		$	13,627
Net loss on cash flow hedges	(4,560		)	(3,613		)
Reclassification of net loss (gain) on cash flow hedges to income	4,367			(26		)
Ending balance	$	13,933		$	9,988

During ~~2013,~~2014, we had open NYMEX contracts on 0.7 million barrels of crude oil that were designated as fair value hedges. These agreements hedge against the change in value of our crude oil linefill and tank bottom ~~inventory.~~inventories. Because there was no ineffectiveness recognized on these hedges, the cumulative losses of $~~10.2~~9.6 million from the agreements as of ~~September 30, 2013~~March 31, 2014 were fully offset by a cumulative increase of $~~10.2~~9.6 million to tank bottom inventory and a cumulative

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~~MAGELLAN MIDSTREAM PARTNERS, L.P.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

increase of less than $0.1 million to our crude oil linefill, which is reported in other current assets; therefore, there was no net impact from these agreements on our results of operations.

The following tables provide a summary of the effect on our consolidated statements of income for the three ~~and~~ ~~nine~~months ended ~~September 30, 2012~~March 31, 2013 and ~~2013~~2014 of the effective portion of derivatives accounted for under ASC 815-30, Derivatives and Hedging—Cash Flow Hedges, that were designated as hedging instruments (in thousands):




	Three Months Ended March 31, 2013
Derivative Instrument	Amount of Loss Recognized in AOCL on Derivative				Location of Gain (Loss) Reclassified from AOCL into Income	Amount of Gain (Loss) Reclassified from AOCL into Income
Interest rate contracts		$	—		Interest expense		$	41
NYMEX commodity contracts		(4,560		)	Product sales revenue		(4,408		)
Total cash flow hedges		$	(4,560	)	Total		$	(4,367	)



	Three Months Ended March 31, 2014
Derivative Instrument	Amount of Loss Recognized in AOCL on Derivative				Location of Gain Reclassified from AOCL into Income	Amount of Gain Reclassified from AOCL into Income
Interest rate contracts		$	(3,613	)	Interest expense		$	26

Three Months Ended September 30, 2012
Derivative Instrument Amount of Gain (Loss) Recognized in AOCL on Derivative Location of Gain Reclassified from AOCL into Income Amount of Gain Reclassified from AOCL into Income
Interest rate contracts $ 10,126
Interest expense $ 41

NYMEX commodity contracts (460 ) Product sales revenue 1,384

Total cash flow hedges $ 9,666
Total $ 1,425

Three Months Ended September 30, 2013
Derivative Instrument Amount of Loss Recognized in AOCL on Derivative Location of Gain Reclassified from AOCL into Income Amount of Gain Reclassified from AOCL into Income
Interest rate contracts $ (36 ) Interest expense $ 41

NYMEX commodity contracts —
Product sales revenue —

Total cash flow hedges $ (36 ) Total $ 41

Nine Months Ended September 30, 2012
Derivative Instrument Amount of Gain Recognized in AOCL on Derivative Location of Gain Reclassified from AOCL into Income Amount of Gain Reclassified from AOCL into Income
Interest rate contracts $ 11,134
Interest expense $ 123

NYMEX commodity contracts 1,207
Product sales revenue 1,384

Total cash flow hedges $ 12,341
Total $ 1,507

Nine Months Ended September 30, 2013
Derivative Instrument Amount of Loss Recognized in AOCL on Derivative Location of Gain (Loss) Reclassified from AOCL into Income Amount of Gain (Loss) Reclassified from AOCL into Income
Interest rate contracts $ (36 ) Interest expense $ 123

NYMEX commodity contracts (4,560 ) Product sales revenue (4,408 )
Total cash flow hedges $ (4,596 ) Total $ (4,285 )

There was no ineffectiveness recognized on the financial instruments disclosed in the above tables during the three ~~or nine~~ months ended ~~September 30, 2012~~March 31, 2013 or ~~2013~~2014. As of March 31, 2014, the net loss estimated to be classified to interest expense over the next twelve months from AOCL is approximately $0.4 million.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table provides a summary of the effect on our consolidated statements of income for the three ~~and nine~~ months ended ~~September 30, 2012~~March 31, 2013 and ~~2013~~2014 of derivatives accounted for under ASC ~~815-10-35;~~815; Derivatives and Hedging—~~Overall—Subsequent Measurement~~Overall, that were not designated as hedging instruments (in thousands):


		Amount of Gain (Loss) Recognized on Derivative													Amount of Gain (Loss) Recognized on Derivative
		Three Months Ended						Nine Months Ended							Three Months Ended
Derivative Instrument	Location of Gain (Loss) Recognized on Derivative	September 30, 2012			September 30, 2013			September 30, 2012			September 30, 2013			Location of Gain (Loss) Recognized on Derivative	March 31, 2013			March 31, 2014
NYMEX commodity contracts	Product sales revenue	$	(44,706	)	$	(2,035	)	$	(39,532	)	$	8,546		Product sales revenue	$	(1,761	)	$	2,823
NYMEX commodity contracts	Operating expenses	(7,733		)	(3,107		)	(3,216		)	(1,645		)	Operating expenses	(1,886		)	365
Butane futures agreements	Product purchases	3,007			2,878			(1,620		)	2,117			Cost of product sales	(781		)	144
	Total	$	(49,432	)	$	(2,264	)	$	(44,368	)	$	9,018		Total	$	(4,428	)	$	3,332

The impact of the derivatives in the above table was reflected as cash from operations on our consolidated statements of cash flows.

The following tables provide a summary of the fair value of derivatives accounted for under ASC 815, Derivatives and Hedging, which are presented on a net basis in our consolidated balance sheets, that were designated as hedging instruments as of December 31, 2013 and March 31, 2014 (in thousands):

December 31, 2013

Asset Derivatives

Liability Derivatives

Derivative Instrument

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

NYMEX commodity contracts

Energy commodity derivatives contracts, net

—

Energy commodity derivatives contracts, net

146

NYMEX commodity contracts

Other noncurrent assets

2,235

Other noncurrent liabilities

—

Total

2,235

Total

146

March 31, 2014

Asset Derivatives

Liability Derivatives

Derivative Instrument

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

NYMEX commodity contracts

Energy commodity derivatives contracts, net

—

Energy commodity derivatives contracts, net

170

NYMEX commodity contracts

Other noncurrent assets

1,516

Other noncurrent liabilities

—

Total

1,516

Total

170

1517

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following tables provide a summary of the fair value of derivatives accounted for under ASC 815, Derivatives and Hedging, which are presented on a net basis in our consolidated balance sheets, that were ~~designated as hedging instruments as of~~ ~~December 31, 2012~~ ~~and~~ ~~September 30, 2013~~ ~~(in thousands):~~

December 31, 2012
Asset Derivatives Liability Derivatives
Derivative Instrument Balance Sheet Location Fair Value Balance Sheet Location Fair Value
NYMEX commodity contracts Energy commodity derivatives contracts, net $ 473
Energy commodity derivatives contracts, net $ 207

September 30, 2013
Asset Derivatives Liability Derivatives
Derivative Instrument Balance Sheet Location Fair Value Balance Sheet Location Fair Value
NYMEX commodity contracts Energy commodity derivatives contracts, net $ 214
Energy commodity derivatives contracts, net $ —
NYMEX commodity contracts Other noncurrent assets 966
Other noncurrent liabilities —
Interest rate contracts Other current assets —
Other current liabilities 36
Total $ 1,180
Total $ 36

~~The following tables provide a summary of the fair value of derivatives accounted for under ASC 815,~~ ~~Derivatives and Hedging,~~ ~~which are presented on a net basis in our consolidated balance sheets, that were~~ not designated as hedging instruments as of December 31, ~~2012~~2013 and ~~September 30, 2013~~March 31, 2014 (in thousands):


	December 31, 2012						December 31, 2013
	Asset Derivatives			Liability Derivatives			Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
NYMEX commodity contracts	Energy commodity derivatives contracts, net	$	227	Energy commodity derivatives contracts, net	$	8,954	Energy commodity derivatives contracts, net	$	48	Energy commodity derivatives contracts, net	$	7,021
Butane futures agreements	Energy commodity derivatives contracts, net	1,350		Energy commodity derivatives contracts, net	227		Energy commodity derivatives contracts, net	382		Energy commodity derivatives contracts, net	—
	Total	$	1,577	Total	$	9,181	Total	$	430	Total	$	7,021

	September 30, 2013						March 31, 2014
	Asset Derivatives			Liability Derivatives			Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
NYMEX commodity contracts	Energy commodity derivatives contracts, net	$	5,683	Energy commodity derivatives contracts, net	$	166	Energy commodity derivatives contracts, net	$	—	Energy commodity derivatives contracts, net	$	3,217
Butane futures agreements	Energy commodity derivatives contracts, net	2,710		Energy commodity derivatives contracts, net	—		Energy commodity derivatives contracts, net	18		Energy commodity derivatives contracts, net	52
	Total	$	8,393	Total	$	166	Total	$	18	Total	$	3,269


9.	Commitments and Contingencies

~~Clean Air Act - Section 185 Liability~~

Section 185 of the Clean Air Act ("CAA 185") requires states to collect annual fees from major source facilities located in severe or extreme nonattainment ozone areas that did not meet the attainment deadline. The CAA 185 fees are required annually until the area is redesignated as an attainment area for ozone. The Environmental Protection Agency ("EPA") is required to collect the fees if a state does not administer and enforce CAA 185. The Houston-Galveston region was initially determined to be a severe nonattainment area that did not meet its 2007 attainment deadline and, as such, would be subject to CAA 185. In June 2013, the Texas Commission on Environmental Quality (“TCEQ”) adopted its “Failure to Attain Rule” to implement the requirements of CAA 185 which will provide for the collection of an annual failure to attain fee for excess emissions but does not require retroactive assessment of Section 185 fees for the annual periods of 2008 through 2011. As a

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~~MAGELLAN MIDSTREAM PARTNERS, L.P.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

~~result, we reduced our accrual and decreased our environmental expense by~~ ~~$10.6 million~~ ~~in the second quarter of 2013 in accordance with the TCEQ's final rule. The total accrual as of~~ ~~September 30, 2013~~ ~~was~~ ~~$0.7 million~~.

Environmental Liabilities

Liabilities recognized for estimated environmental costs were $~~48.3~~38.5 million and $~~37.5~~37.1 million at December 31, ~~2012~~2013 and ~~September 30, 2013~~March 31, 2014, respectively. We have classified environmental liabilities as current or noncurrent based on management’s estimates regarding the timing of actual payments. Management estimates that expenditures associated with these environmental liabilities will be paid over the next 10 years. Environmental expenses recognized as a result of changes in our environmental liabilities are included in operating expenses on our consolidated statements of income. Environmental expenses for the three ~~and~~ ~~nine~~months ended ~~September 30, 2012~~March 31, 2013 and 2014 were $~~10.0~~0.7 million and $~~12.7~~0.3 million, respectively. ~~Environmental expenses for the~~ ~~three~~ ~~and~~ ~~nine~~ ~~months ended~~ ~~September 30, 2013~~ ~~were~~ ~~$2.9 million~~ ~~and~~ ~~$(5.8) million, respectively, with the year-to-date amount including the~~ ~~$10.6 million~~ ~~favorable adjustment to the CAA 185 liability noted above.~~

Environmental Receivables

Receivables from insurance carriers and other third parties related to environmental matters at December 31, ~~2012~~2013 were $~~7.9~~4.8 million, of which $~~2.8~~2.1 million and $~~5.1~~2.7 million were recorded to other accounts receivable and long-term receivables, respectively, on our consolidated balance sheet. Receivables from insurance carriers and other third parties related to environmental matters at ~~September 30, 2013~~March 31, 2014 were $~~4.9~~4.7 million, of which $~~1.8~~2.1 million and $~~3.1~~2.6 million were recorded to other accounts receivable and long-term receivables, respectively, on our consolidated balance sheet.

Other

In January 2014, we placed into operation a 36-mile pipeline we constructed in Texas and New Mexico at a cost of approximately $35.0 million. We entered into a long-term throughput and deficiency agreement with a

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

customer on this pipeline, which contains minimum volume/payment commitments. This agreement is being accounted for as a direct financing lease under which, in addition to transportation revenue, we will receive capital recovery payments of approximately $19.3 million over the next 41 months.

We are a party to various other claims, legal actions and complaints arising in the ordinary course of business, including without limitation those disclosed in Item 1, Legal Proceedings of Part II of this report on Form 10-Q. While the results cannot be predicted with certainty, management believes the ultimate resolution of these claims, legal actions and complaints after consideration of amounts accrued, insurance coverage or other indemnification arrangements will not have a material adverse effect on our results of operations, financial position or cash flows.


10.	Long-Term Incentive Plan

We have a long-term incentive plan (“LTIP”) for certain of our employees and for directors of our general partner. The LTIP primarily consists of phantom units and permits the grant of awards covering an aggregate payout of 9.4 million of our limited partner ~~units as of~~ ~~September 30, 2013~~.units. The ~~remaining~~estimated units available under the LTIP at ~~September 30, 2013~~March 31, 2014 total 1.8 million. The compensation committee of our general partner’s board of directors administers our LTIP.

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


	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30, 2012						September 30, 2012						March 31, 2013
	Equity Method		Liability Method		Total		Equity Method		Liability Method		Total		Equity Method		Liability Method		Total
Performance-based awards:
Performance/market-based awards:
2010 awards	$	1,489	$	1,776	$	3,265	$	3,666	$	2,954	$	6,620	$	121	$	73	$	194
2011 awards	684		566		1,250		2,111		1,021		3,132		983		1,147		2,130
2012 awards	581		259		840		1,711		557		2,268		881		611		1,492
2013 awards													726		189		915
Retention awards	192		—		192		535		—		535		125		—		125
Total	$	2,946	$	2,601	$	5,547	$	8,023	$	4,532	$	12,555	$	2,836	$	2,020	$	4,856

Allocation of LTIP expense on our consolidated statements of income:
G&A expense					$	4,940					$	11,160					$	4,485
Operating expense					607						1,395						371
Total					$	5,547					$	12,555					$	4,856

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30, 2013						September 30, 2013						March 31, 2014
	Equity Method		Liability Method		Total		Equity Method		Liability Method		Total		Equity Method		Liability Method		Total
Performance-based awards:
2010 awards	$	—	$	—	$	—	$	121	$	73	$	194
2011 awards	1,101		717		1,818		4,204		2,940		7,144
Performance/market-based awards:
2012 awards	856		432		1,288		2,563		1,413		3,976		1,022		924		1,946
2013 awards	763		223		986		2,222		610		2,832		1,181		548		1,729
2014 awards													904		—		904
Retention awards	125		—		125		353		—		353		509		—		509
Total	$	2,845	$	1,372	$	4,217	$	9,463	$	5,036	$	14,499	$	3,616	$	1,472	$	5,088

Allocation of LTIP expense on our consolidated statements of income:
G&A expense					$	4,126					$	13,928					$	4,974
Operating expense					91						571						114
Total					$	4,217					$	14,499					$	5,088

On February 3, 2014, 178,184 phantom unit awards were issued pursuant to our long-term incentive plan. These grants included both performance-based and retention awards and have a three-year vesting period that will end on December 31, 2016.

On February 3, 2014, we issued 388,819 limited partner units, of which 387,216 were issued to settle unit award grants to certain employees that vested on December 31, 2013 and 1,603 were issued to settle the equity-based retainer paid to a member of our general partner's board of directors.


11.	Distributions

Distributions we paid during ~~2012~~2013 and ~~2013~~2014 were as follows (in thousands, except per unit amounts):

Payment Date
Per Unit Cash
Distribution
Amount
Total Cash Distribution to Limited Partners
2/14/2012 $ 0.40750
$ 92,177

5/15/2012 0.42000
95,004

8/14/2012 0.47125
106,597

Through 9/30/2012 1.29875
293,778

11/14/2012 0.48500
109,707

Total $ 1.78375
$ 403,485

2/14/2013 $ 0.50000
$ 113,340

5/15/2013 0.50750
115,040

8/14/2013 0.53250
120,707

Through 9/30/2013 1.54000
349,087

11/14/2013⁽¹⁾
0.55750
126,374

Total $ 2.09750
$ 475,461



Payment Date	Per Unit Cash Distribution Amount			Total Cash Distribution to Limited Partners
02/14/2013		$	0.5000		$	113,340
05/15/2013		0.5075			115,040
08/14/2013		0.5325			120,707
11/14/2013		0.5575			126,374
Total		$	2.0975		$	475,461

02/14/2014		$	0.5850		$	132,835
5/15/2014⁽¹⁾		0.6125			139,079
Total		$	1.1975		$	271,914

(1) Our general partner's board of directors declared this cash distribution on ~~October~~April 24, ~~2013~~2014 to be paid on ~~November 14, 2013~~May 15, 2014 to unitholders of record at the close of business on ~~November 7, 2013.~~May 8, 2014.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


12.	Fair Value

Fair Value Methods and Assumptions - Financial Assets and Liabilities

We used the following methods and assumptions in estimating fair value for our financial assets and liabilities:

Cash and cash equivalents. Cash equivalents include money market and mutual fund accounts and commercial paper. The carrying amounts reported on our consolidated balance sheets approximate fair value due to the short-term maturity or variable rates of these instruments.

Energy commodity derivatives deposits. This asset represents short-term deposits we have made associated with our energy commodity derivatives contracts. The carrying amount reported on our consolidated balance sheets approximates fair value as the deposits change daily in relation to the associated contracts and are held in separate accounts.

Energy commodity derivatives contracts. These include NYMEX futures and exchange-traded butane futures agreements related to petroleum products. These contracts are carried at fair value on our consolidated balance sheets and are valued based on quoted prices in active markets. See Note 8 – Derivative Financial Instruments for further disclosures regarding these contracts.

~~Treasury lock hedge derivative agreements. These agreements were entered into to protect against the risk of variability in interest payments related to a future debt issuance (see Note 8 –~~ ~~Derivative Financial Instruments~~ for further disclosures regarding these agreements). Fair value was determined based on an assumed exchange, at the end of each period, in an orderly transaction with a market participant in the market in which the financial instrument is traded, adjusted for the effect of counter-party credit risk. The exchange value was calculated using present value techniques on estimated future cash flows based on forward interest rate curves.

Long-term receivables. These ~~are primarily~~include lease payments receivable under a direct-financing leasing arrangement and insurance ~~receivables, whose fair~~receivables. Fair value was determined by estimating the present value of future cash flows using ~~a risk-free rate of interest derived from U.S. treasury~~current market rates.

Debt. The fair value of our publicly traded notes was based on the prices of those notes at December 31, ~~2012~~2013 and ~~September 30, 2013~~March 31, 2014; however, where recent observable market trades were not available, prices were determined using adjustments to the last traded value for that debt issuance or by adjustments to the prices of similar debt instruments of peer entities that are actively traded. The carrying amount of borrowings, if any, under our revolving credit facility approximates fair value due to the variable rates of that instrument.

Fair Value Measurements - Financial Assets and Liabilities

The following tables summarize the carrying amounts, fair values and recurring fair value measurements recorded or disclosed as of December 31, ~~2012~~2013 and ~~September 30, 2013~~March 31, 2014, based on the three levels established by ASC ~~820-10-50;~~820; Fair Value Measurements and ~~Disclosures—Overall—Disclosure~~Disclosures. The carrying values of cash and cash equivalents (classified as Level 1) and energy commodity derivatives deposits approximate fair value because of the short-term nature or variable rates of these instruments; therefore, these items are not presented in the following ~~tables.~~tables (in thousands).

As of December 31, 2012
Assets / (Liabilities) ($ in thousands) Fair Value Measurements
Carrying Amount Fair Value
Quoted Prices in
Active Markets
for Identical
Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)
Energy commodity derivatives contracts (liabilities) $ (7,338 ) $ (7,338 ) $ (7,338 ) $ —
$ —
Long-term receivables $ 5,135
$ 5,108
$ —
$ —
$ 5,108
Debt $ (2,393,408 ) $ (2,721,985 ) $ (2,721,985 ) $ —
$ —

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As of September 30, 2013
Assets / (Liabilities) ($ in thousands) Fair Value Measurements
Carrying Amount Fair Value
Quoted Prices in
Active Markets
for Identical
Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)
Energy commodity derivatives contracts (assets) $ 9,407
$ 9,407
$ 9,407
$ —
$ —
Treasury lock hedge agreements $ (36 ) $ (36 ) $ —
$ (36 ) $ —
Long-term receivables $ 3,140
$ 3,097
$ —
$ —
$ 3,097
Debt $ (2,486,715 ) $ (2,676,025 ) $ —
$ (2,676,025 ) $ —



	As of December 31, 2013
Assets (Liabilities)							Fair Value Measurements using:
Assets (Liabilities)	Carrying Amount			Fair Value			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Energy commodity derivatives contracts (liabilities)	$	(4,502	)	$	(4,502	)	$	(4,502	)	$	—		$	—
Long-term receivables	$	2,730		$	2,658		$	—		$	—		$	2,658
Debt	$	(2,685,287	)	$	(2,815,210	)	$	—		$	(2,815,210	)	$	—

During second quarter 2013, we reevaluated the market in which our debt securities trade. Based on that review, we determined that this market no longer included sufficient market activity to qualify as an active market, as defined in ASC 820, ~~Fair Value Measurements~~. As a result, we transferred the hierarchical reporting level of the fair value measurement of our debt securities from Level 1 to Level 2. Our policy is to effect transfers between hierarchical reporting levels at the end of the reporting period where it has been determined that a change is required.



	As of March 31, 2014
Assets (Liabilities)							Fair Value Measurements using:
Assets (Liabilities)	Carrying Amount			Fair Value			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Energy commodity derivatives contracts (liabilities)	$	(1,905	)	$	(1,905	)	$	(1,905	)	$	—		$	—
Long-term receivables	$	30,365		$	30,992		$	—		$	—		$	30,992
Debt	$	(2,941,276	)	$	(3,186,457	)	$	—		$	(3,186,457	)	$	—


13.	Related Party Transactions

Barry R. Pearl is an independent member of our general partner's board of directors and is also a director of Targa Resources Partners, L.P. ("Targa"). In the normal course of business, we purchase butane from subsidiaries of Targa. For the three months ended ~~September 30, 2012~~March 31, 2013 and ~~2013, we made purchases of butane from subsidiaries of Targa of less than~~ ~~$0.1 million~~ ~~and~~ ~~$1.0 million, respectively. For the~~ ~~nine months ended September 30, 2012~~ ~~and~~ ~~2013~~2014, we made purchases of butane from subsidiaries of Targa of $~~12.5~~14.2 million and $~~15.6~~12.2 million, respectively. These purchases were made on the same terms as comparable third-party transactions. ~~We had~~There were ~~$0.1 million~~no ~~and~~ $0amounts payable to Targa at December 31, ~~2012~~2013 ~~and~~or ~~September 30, 2013~~March 31, 2014, respectively.

See Note 4 – Investments in Non-Controlled Entities for a discussion of affiliate joint venture transactions we account for under the equity method.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


14.	Subsequent Events

Recognizable events

No recognizable events occurred during the period.

Non-recognizable events

In ~~October 2013,~~April 2014, we ~~issued~~ ~~$300.0 million~~initiated a commercial paper program pursuant to which we may issue short-term, unsecured commercial paper notes of ~~5.15%~~ ~~notes due October 15, 2043 in an underwritten public offering. The notes were issued for~~up to $1.0 billion. Borrowings under the ~~discounted price of~~ ~~99.56%~~ ~~of par.~~program are backed by and may not exceed the available capacity on our revolving credit facility. We ~~intend~~expect to use the net proceeds ~~from this offering~~ of ~~approximately~~ ~~$295.6 million, after underwriting discounts and estimated offering expenses, to repay borrowings outstanding under our revolving credit facility and~~issuances of the notes for general partnership ~~purposes, which may include capital expenditures.~~purposes. We currently have no notes issued under this program.

In ~~September 2013, we entered into~~ ~~$150.0 million~~ ~~of Treasury lock contracts to protect against the risk of variability in future interest payments associated with the~~ ~~$300.0 million~~ ~~of notes discussed above (see Note 8 –~~ ~~Derivative Financial Instruments~~ ~~for more information on the Treasury lock contracts). In October 2013, we settled these Treasury lock contracts and realized a loss of~~ ~~$0.2 million~~. The loss was recorded to other comprehensive income and will be recognized into earnings as an adjustment to our periodic interest accruals over the next 30 years to coincide with interest payments on the underlying debt.

~~In October 2013,~~April 2014, our general partner's board of directors declared a quarterly distribution of $~~0.5575~~0.6125 per unit to be paid on ~~November 14, 2013~~May 15, 2014 to unitholders of record at the close of business on ~~November 7, 2013.~~May 8, 2014. The total cash distributions expected to be paid are $~~126.4~~139.1 million.

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

Introduction

We are a publicly traded limited partnership principally engaged in the transportation, storage and distribution of refined petroleum products and crude oil. As of ~~September 30, 2013~~March 31, 2014, our ~~three operating segments included:~~asset portfolio including the assets of our joint ventures consisted of:

our refined products segment, including ~~almost 9,100 miles of~~our 9,500-mile refined products pipeline system with ~~49 connected~~54 terminals as well as 27 independent terminals not connected to our pipeline system and our ~~1,100-mile~~1,100-mile ammonia pipeline system;

our crude oil segment, comprised of approximately ~~800~~1,100 miles of crude oil pipelines and storage facilities with an aggregate ~~leasable~~ storage capacity of approximately 1518 million ~~barrels;~~barrels, of which 12 million is used for leased storage; and

our marine storage segment, consisting of five marine terminals located along coastal waterways with an aggregate storage capacity of ~~more than 26~~approximately 27 million barrels.

The following discussion provides an analysis of the results for each of our operating segments, an overview of our liquidity and capital resources and other items related to our partnership. The following discussion and analysis should be read in conjunction with (i) our accompanying interim consolidated financial statements and related notes and (ii) our consolidated financial statements, related notes and management’s discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the year ended December 31, ~~2012~~2013, and (iii) updates to the information contained in our Annual Report for the year ended December 31, 2012 related to the changes made in our reporting segments included in our Current Report on Form 8-K, which we filed with the Securities and Exchange Commission on April 29, 2013..

Recent Developments

~~Executive Officer Changes.~~Condensate Splitter. ~~Our Senior Vice President~~In March 2014, we announced our plans to construct a condensate splitter at our terminal in Corpus Christi, Texas under a fee-based, take-or-pay agreement with a third-party customer. The project also includes construction of more than one million barrels of storage, dock improvements and ~~Chief Financial Officer, John D. Chandler, has announced his resignation from such positions effective March 31, 2014.~~two additional truck rack bays at our terminal as well as pipeline connectivity between our terminal and our customer's nearby facility. The splitter will be capable of processing 50,000 barrels per day of condensate. We expect the condensate splitter and related infrastructure to cost approximately $250 million and to be operational during the second half of 2016, subject to receipt of necessary permits and authorizations.

~~2013 Debt Offering.~~Little Rock Pipeline. In ~~October 2013,~~May 2014, we ~~issued $300.0~~announced plans to transport refined products from our Ft. Smith, Arkansas terminal to Little Rock, Arkansas. We have entered into an agreement with a third party to utilize an existing pipeline for a portion of the route, which we will extend to our Ft. Smith terminal and to the Little Rock market with approximately 50 miles of newly-constructed pipeline. We further plan to make enhancements to our pipeline system to accommodate additional volumes. The Little Rock pipeline project is expected to cost approximately $150 million and be operational in early 2016, subject to receipt of ~~5.15%~~regulatory and other approvals.

Commercial Paper Program. In April 2014, we initiated a commercial paper program pursuant to which we may issue short-term, unsecured commercial paper notes ~~due October 15, 2043 in an underwritten public offering. The notes were issued for~~of up to $1.0 billion. Borrowings under the ~~discounted price of 99.56% of par.~~program are backed by and may not exceed available capacity on our revolving credit facility. We ~~intend~~expect to use the net proceeds ~~from this offering~~ of ~~approximately $295.6 million, after underwriting discounts and estimated offering expenses, to repay borrowings outstanding under our revolving credit facility and~~issuances of the notes for general partnership ~~purposes, which may include capital expenditures.~~

~~In September 2013, we entered into $150.0 million of Treasury lock contracts to protect against the risk of variability in a portion of future interest payments associated with the $300.0 million of~~purposes. We currently have no notes ~~discussed above. In October 2013, we settled these Treasury lock contracts and realized a loss of~~ ~~$0.2 million~~. The loss was recorded to other comprehensive income and will be recognized into earnings as an adjustment to our periodic interest accruals over the next 30 years to coincide with interest payments on the underlying debt.

~~Longhorn Pipeline Reversal Project.~~ In mid-April 2013, we began deliveries of crude oil from our Longhorn pipeline. During third quarter 2013, Longhorn's crude oil deliveries averaged approximately 100,000 barrels per day. The pipeline has been capable of operating at its full 225,000 barrel-per-day capacity since mid-October and is expected to average approximately 190,000 barrels per day during the fourth quarter. We plan to expand the capacity of the Longhorn pipeline by 50,000 barrels per day to 275,000 barrels per day, all fully committed by long-term contracts. Subject to regulatory approval, we expect to reach the 275,000 barrel-per-day operating capacity by mid-2014. We estimateissued under this ~~expansion project will cost approximately $55 million.~~

~~Pipeline Acquisition.~~ In February 2013, we announced an agreement to acquire approximately 800 miles of refined petroleum products pipeline. On July 1, 2013, we closed on a portion of this transaction which includes a 250-mile pipeline that transports refined petroleum products from El Paso, Texas north to Albuquerque, New Mexico and transports products south to the U.S.-Mexico border for delivery within Mexico via a third-party pipeline. This New Mexico pipeline cost $57 million, which we funded with cash on hand. We expect to complete the remainder of this acquisition, which includes approximately 550 miles of common carrier pipeline that distributes refined petroleum products in Colorado, South Dakota and Wyoming in the fourth quarter of 2013 for an adjusted purchase price of $135 million. We expect to fund the remainder of this acquisition primarily with proceeds from our recent debt offering.program.

Cash Distribution. In ~~October 2013,~~April 2014, the board of directors of our general partner declared a quarterly cash distribution of ~~$0.5575~~$0.6125 per unit for the period of ~~July~~January 1, ~~2013~~2014 through ~~September 30, 2013.~~March 31, 2014. This quarterly cash distribution will be paid on

~~Table of Contents~~

~~November 14, 2013~~ May 15, 2014 to unitholders of record on ~~November 7, 2013.~~May 8, 2014. Total distributions expected to be paid under this declaration are approximately ~~$126.4 million~~.$139.1 million.

~~Change in Reporting Segments.~~ ~~During first quarter 2013, we completed a reorganization~~

Table of our reporting segments to reflect strategic changes in our businesses, particularly in the area of our crude oil activities, which have had or will have a significant impact on the way we manage our operations. Accordingly, we have restated our segment disclosures for all periods included in this report.Contents

Results of Operations

We believe that investors benefit from having access to the same financial measures utilized by management. Operating margin, which is presented in the following ~~tables,~~table, is an important measure used by management to evaluate the economic performance of our core operations. Operating margin is not a generally accepted accounting principles (“GAAP”) measure, but the components of operating margin are computed using amounts that are determined in accordance with GAAP. A reconciliation of operating margin to operating profit, which is its nearest comparable GAAP financial measure, is included in the following ~~tables.~~table. Operating profit includes expense items, such as depreciation and amortization expense and general and administrative (“G&A”) expenses, which management does not focus on when evaluating the core profitability of our separate operating segments. Additionally, product margin, which management primarily uses to evaluate the profitability of our commodity-related activities, is provided in ~~these tables.~~this table. Product margin is a non-GAAP measure; however, its components of product sales and cost of product ~~purchases~~sales are determined in accordance with GAAP. Our butane blending, fractionation and other commodity-related activities generate significant product revenue. We believe the product margin from these activities, which takes into account the related cost of product ~~purchases,~~sales, better represents its importance to our results of operations.

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Three Months Ended ~~September 30, 2012~~March 31, 2013 Compared to Three Months Ended ~~September 30, 2013~~March 31, 2014


	Three Months Ended September 30,						Variance Favorable (Unfavorable)				Three Months Ended March 31,						Variance Favorable (Unfavorable)
	2012			2013			$ Change			% Change	2013			2014			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)
Transportation and terminals revenue:
Refined products	$	193.8		$	205.9		$	12.1		6	$	165.4		$	210.2		$	44.8		27
Crude oil	23.9			49.5			25.6			107	23.2			67.9			44.7			193
Marine storage	37.8			39.9			2.1			6	38.7			39.5			0.8			2
Total transportation and terminals revenue	255.5			295.3			39.8			16	227.3			317.6			90.3			40
Affiliate management fee revenue	0.2			3.6			3.4			n/a	3.4			4.9			1.5			44
Operating expenses:
Refined products	80.7			82.1			(1.4		)	(2)	46.3			51.2			(4.9		)	(11)
Crude oil	3.4			4.1			(0.7		)	(21)	5.1			9.1			(4.0		)	(78)
Marine storage	19.9			17.8			2.1			11	14.6			14.1			0.5			3
Intersegment eliminations	(0.7		)	(0.8		)	0.1			14	(0.8		)	(0.8		)	—			—
Total operating expenses	103.3			103.2			0.1			—	65.2			73.6			(8.4		)	(13)
Product margin:
Product sales revenue	70.2			144.9			74.7			106	201.7			296.1			94.4			47
Product purchases	85.8			120.3			(34.5		)	(40)
Cost of product sales											160.4			198.0			(37.6		)	(23)
Product margin⁽¹⁾	(15.6		)	24.6			40.2			n/a	41.3			98.1			56.8			138
Earnings of non-controlled entities	1.8			2.4			0.6			33	2.1			0.5			(1.6		)	(76)
Operating margin	138.6			222.7			84.1			61	208.9			347.5			138.6			66
Depreciation and amortization expense	31.7			35.3			(3.6		)	(11)	36.3			37.5			(1.2		)	(3)
G&A expense	27.6			32.8			(5.2		)	(19)	30.1			34.9			(4.8		)	(16)
Operating profit	79.3			154.6			75.3			95	142.5			275.1			132.6			93
Interest expense (net of interest income and interest capitalized)	27.6			27.9			(0.3		)	(1)	28.3			30.7			(2.4		)	(8)
Debt placement fee amortization expense	0.6			0.5			0.1			17	0.5			0.6			(0.1		)	(20)
Income before provision for income taxes	51.1			126.2			75.1			147	113.7			243.8			130.1			114
Provision for income taxes	0.5			0.6			(0.1		)	(20)	0.7			1.2			(0.5		)	(71)
Net income	$	50.6		$	125.6		$	75.0		148	$	113.0		$	242.6		$	129.6		115
Operating Statistics:
Refined products:
Transportation revenue per barrel shipped	$	1.228		$	1.306						$	1.136		$	1.356
Volume shipped (million barrels):
Gasoline	61.8			61.9							53.6			59.8
Distillates	36.5			36.1							33.8			37.5
Aviation fuel	5.9			5.9							4.5			5.0
Liquefied petroleum gases	3.2			4.0							1.1			1.5
Total volume shipped	107.4			107.9							93.0			103.8
Crude oil:
Transportation revenue per barrel shipped	$	0.311		$	1.010						$	0.313		$	1.113
Volume shipped (million barrels)	19.3			28.6							15.9			41.8
Crude oil terminal average utilization (million barrels per month)	12.6			12.3							12.8			12.1
Marine storage:
Marine terminal average utilization (million barrels per month)	23.6			23.2							22.7			22.7

(1) Product margin does not include depreciation or amortization expense.

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Transportation and terminals revenue increased $~~39.8~~90.3 million resulting from:

an increase in refined products revenue of $~~12.1~~44.8 million. Excluding the pipeline systems we acquired in the second half of 2013, refined products revenue increased $34.7 million primarily due to ~~revenue from the New Mexico pipeline we acquired on July 1, 2013, which represented approximately one-third of the~~a 3% increase in transportation volumes and higher ~~weighted average tariff rates on our existing pipeline system~~rates. Shipments were higher primarily due to ~~our~~increased demand for gasoline and distillates. The average rate per barrel was impacted by the mid-year 2013 tariff rate increase ~~of 4.6%~~ and ~~deficiency payments during third quarter 2013 from committed volumes that did not ship;~~more long-haul shipments (which are at a higher rate);

an increase in crude oil revenue of $~~25.6~~44.7 million primarily due to crude oil deliveries from our Longhorn pipeline, which represented approximately ~~90%~~85% of the ~~increase, and additional condensate throughput at our Corpus Christi, Texas terminal.~~increase. Our Longhorn pipeline began delivering crude oil in mid-April 2013 and averaged approximately ~~100,000~~200,000 barrels per day during ~~third~~first quarter ~~2013;~~2014; and

an increase in marine storage revenue of $~~2.1~~0.8 million primarily due to new storage placed into service at our Galena Park, Texas terminal since ~~third-quarter 2012, as well as higher throughput fees.~~early 2013.

Affiliate management fee revenue increased $~~3.4~~1.5 million due to higher construction management fees ~~we received in third quarter 2013~~ related to BridgeTex Pipeline Company, LLC ("BridgeTex") ~~and~~. The construction management fees we ~~received from operating storage tanks~~receive are designed to reimburse us for ~~Texas Frontera, LLC ("Texas Frontera"), both~~our costs of ~~which began after third quarter 2012.~~providing services to BridgeTex during its construction.

Operating expenses ~~decreased slightly~~increased by $~~0.1~~8.4 million resulting from:

an increase in refined products expenses of $~~1.4~~4.9 million primarily due to $4.3 million of expenses related to the ~~New Mexico~~ pipeline systems we acquired ~~on July 1, 2013~~in the second half of 2013. Otherwise, higher property taxes, power expenses and ~~less favorable~~personnel costs related to our other pipeline segments were primarily offset by higher product ~~gains~~overages (which reduce operating expenses)~~, partially offset by lower environmental accruals and less asset retirements;~~;

an increase in crude oil expenses of $~~0.7~~4.0 million primarily due to costs related to the operation of our Longhorn pipeline in crude oil service in the current period, including higher power expenses, personnel costs and pipeline rental ~~costs~~fees to access product from third-party origination sources, ~~higher personnel costs, power and integrity spending,~~ partially offset by more favorable product overages (which reduce operating expenses); and

a decrease in marine storage expenses of $~~2.1~~0.5 million primarily due to lower ~~environmental accruals, partially offset by higher~~ asset integrity costs ~~and property taxes~~ in the current period.

Product sales revenue primarily resulted from our butane blending activities, product gains from our independent terminals and transmix fractionation. We utilize New York Mercantile Exchange (“NYMEX”) contracts to hedge against changes in the price of petroleum products we expect to sell in the future. ~~The~~Product sales revenue also included the period change in the mark-to-market value of these contracts that are not designated as hedges for accounting purposes, the effective portion of the change in value of matured NYMEX contracts that qualified for hedge accounting treatment and any ineffectiveness of NYMEX contracts that qualify for hedge accounting ~~treatment are also included in product sales revenue.~~treatment. We use butane futures agreements to hedge against changes in the price of butane we expect to purchase in future periods. The period change in the mark-to-market value of these futures agreements, which were not designated as hedges, are included as adjustments to cost of product ~~purchases. Product margin increased~~ ~~$40.2~~ million primarily due to unrealized gains on NYMEX contracts in the current quarter compared to unrealized NYMEX losses in third quarter 2012, and higher margins from our butane blending activities as a result of higher volumes sold and lower butane costs.sales. See Other Items—Commodity Derivative Agreements—Impact of Commodity Derivatives on Results of Operations below for more information about our NYMEX contracts. Product margin increased $56.8 million primarily attributable to higher margins from our butane blending activities as a result of lower butane costs and higher sales volumes. The increased volume was primarily attributable to selling additional volume carried over from our fourth quarter 2013 blending activities as well as more blending opportunities during first quarter 2014.

Earnings of non-controlled entities ~~increased~~decreased $~~0.6~~1.6 million primarily due to earnings of Double Eagle Pipeline LLC ("Double Eagle") and Texas Frontera, both of which began operations after third quarter 2012, partially offset by lower earnings of Osage Pipe Line Company, LLC ("Osage") primarily due to a lower weighted-average ~~tariff rate.~~tariffs and higher depreciation costs.

Depreciation and amortization expense increased $~~3.6~~1.2 million primarily due to expansion capital projects placed into service since ~~third~~first quarter ~~2012.~~2013.

G&A expense increased $~~5.2~~4.8 million primarily due to higher compensation costs resulting from an increase in employee headcount and ~~an increase in~~ the ~~current year~~timing of recognizing our employee bonus accrual, ~~resulting from above-target payout estimates as well as legal costs associated with the pending refined products pipeline acquisition we expect to close in the fourth quarter of 2013.~~higher equity-based compensation

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~~Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2013~~

Nine Months Ended September 30,
Variance
Favorable (Unfavorable)
2012 2013 $ Change % Change
Financial Highlights ($ in millions, except operating statistics)
Transportation and terminals revenue:
Refined products $ 538.8
$ 573.6
$ 34.8
6
Crude oil 67.6
113.9
46.3
68
Marine storage 115.4
117.5
2.1
2
Total transportation and terminals revenue 721.8
805.0
83.2
12
Affiliate management fee revenue 0.6
10.6
10.0
n/a
Operating expenses:
Refined products 204.1
194.9
9.2
5
Crude oil 4.0
13.2
(9.2 ) (230)
Marine storage 48.1
40.0
8.1
17
Intersegment eliminations (2.1 ) (2.3 ) 0.2
10
Total operating expenses 254.1
245.8
8.3
3
Product margin:
Product sales revenue 546.5
504.5
(42.0 ) (8)
Product purchases 478.9
396.0
82.9
17
Product margin⁽¹⁾
67.6
108.5
40.9
61
Earnings of non-controlled entities 4.9
5.2
0.3
6
Operating margin 540.8
683.5
142.7
26
Depreciation and amortization expense 94.7
105.8
(11.1 ) (12)
G&A expense 76.7
96.1
(19.4 ) (25)
Operating profit 369.4
481.6
112.2
30
Interest expense (net of interest income and interest capitalized) 83.9
84.6
(0.7 ) (1)
Debt placement fee amortization expense 1.6
1.6
—
—
Income before provision for income taxes 283.9
395.4
111.5
39
Provision for income taxes 2.0
3.2
(1.2 ) (60)
Net income $ 281.9
$ 392.2
$ 110.3
39
Operating Statistics:
Refined products:
Transportation revenue per barrel shipped $ 1.233
$ 1.274

Volume shipped (million barrels):
Gasoline 163.8
174.6

Distillates 99.9
105.4

Aviation fuel 16.7
15.4

Liquefied petroleum gases 7.9
7.3

Total volume shipped 288.3
302.7

Crude oil:
Transportation revenue per barrel shipped $ 0.298
$ 0.765

Volume shipped (million barrels) 51.4
72.6

Crude oil terminal average utilization (million barrels per month) 12.6
12.4

Marine storage:
Marine terminal average utilization (million barrels per month) 23.8
22.9

~~(1) Product margin does not include depreciation or amortization expense.~~

~~Table of Contents~~

~~Transportation and terminals revenue increased~~ ~~$83.2~~ ~~million resulting from:~~

~~an increase in refined products revenue of~~ ~~$34.8~~ million primarily due to a 5% increase in transportation volumes and higher rates. Gasoline and distillate shipments were higher primarily due to additional volumes on our South Texas pipeline system resulting from increased demand and incentive tariffs put in place to attract volumes, as well as volumes from the New Mexico pipeline we acquired on July 1, 2013, which contributed approximately 10% of the increase in transportation revenue. The average rate per barrel increased due to the mid-year 2012 and 2013 tariff rate increases of 8.6% and 4.6%, respectively, partially offset by more South Texas movements, which are at a significantly lower tariff rate than shipments on our other pipeline sections;

~~an increase in crude oil revenue of~~ ~~$46.3~~ million primarily due to crude oil deliveries from our Longhorn pipeline, which represented approximately 80% of the increase, and higher utilization and rates on our Houston-area crude oil distribution system. Our Longhorn pipeline began delivering crude oil in 2013 and averaged approximately 95,000 barrels per day since its mid-April start date. We also benefited from additional condensate throughput at our Corpus Christi terminal; and

~~an increase in marine storage revenue of~~ ~~$2.1~~ ~~million primarily due to new storage placed into service at our Galena Park, Texas terminal since late 2012 and higher throughput fees.~~

~~Affiliate management fee revenue increased~~ ~~$10.0~~ million due to construction management fees we received in 2013 related to BridgeTex and management fees we received from operating storage tanks for Texas Frontera, both of which began after the third quarter of 2012.

~~Operating expenses decreased~~ ~~$8.3~~ ~~million resulting from:~~

~~a decrease in refined products expenses of~~ ~~$9.2~~ million primarily due to higher product overages (which reduce operating expenses), favorable gains on asset sales and lower losses on asset retirements, the 2013 favorable adjustment of an accrual for air emission fees at our East Houston terminal (see Notes to Consolidated Financial Statements, Note 9—~~Commitments and Contingencies~~ ~~for more information regarding the adjustment of this accrual) and lower environmental accruals, partially offset by higher compensation, power~~ costs and property taxes, as well as expenses related to the New Mexico pipeline we acquired on July 1, 2013. The higher compensation costs were due to increased employee headcount and higher bonus accruals. The higher power costs primarily reflect the increase in product shipments over 2012 and the higher property taxes are the result of asset additions over the past year;

~~an increase in crude oil expenses of~~ ~~$9.2~~ million primarily due to costs related to the operation of our Longhorn pipeline in crude oil service in the 2013, including pipeline rental costs to access product from third-party origination sources, higher personnel costs, power and integrity spending, partially offset by more favorable product overages (which reduce operating expenses); and

~~a decrease in marine storage expenses of~~ ~~$8.1~~ ~~million primarily due to the 2013 favorable adjustment of an accrual for potential air emission fees at our Galena Park, Texas facility (see Notes to Consolidated Financial Statements, Note 9—Commitments and Contingencies~~ for more information regarding the adjustment of this accrual) and lower environmental accruals, partially offset by insurance reimbursements received in 2012 for historical hurricane-related damage and higher asset integrity costs in 2013.

~~Product margin increased~~ ~~$40.9~~ million primarily due to unrealized gains on NYMEX contracts in the current year compared to unrealized NYMEX losses in 2012, and higher margins from our butane blending activities mainly as a result of lower butane costs. See ~~Other Items—Commodity Derivative Agreements—Impact of Commodity Derivatives on Results of Operations~~ ~~below for more information about our NYMEX contracts.~~

~~Earnings of non-controlled entities increased~~ ~~$0.3~~ ~~million primarily due to earnings of Double Eagle and Texas Frontera, both of which began operations after third quarter 2012, partially offset by lower earnings of Osage.~~

~~Depreciation and amortization expense increased~~ ~~$11.1~~ ~~million primarily due to increased amortization of intangible assets and expansion capital projects placed into service since 2012.~~

~~G&A expense increased~~ ~~$19.4~~ million primarily due to higher compensation costs resulting from an increase in employee headcount and an increase in the current year bonus accrual resulting from above-target payout estimates, legal costs related to potential projects and the pending acquisition we expect to close in the fourth quarter of 2013, and higher equity-based compensation costs and deferred board of director compensation expense primarily due to a higher price for our limited partner ~~units.~~units and higher prospecting and legal costs primarily related to expansion projects.

Interest expense, net of interest income and interest capitalized, increased $2.4 million. Our average outstanding debt increased from $2.4 billion in first quarter 2013 to $2.8 billion in first quarter 2014 primarily due to borrowings for expansion capital expenditures, including $300.0 million of 5.15% senior notes issued in October 2013 and $250.0 million of 5.15% senior notes issued in March 2014. Our weighted-average interest rate was unchanged at 5.2%.

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Distributable Cash Flow

Distributable cash flow ("DCF") and adjusted EBITDA are non-GAAP measures. Management uses ~~this measure~~DCF as a basis for recommending to our general partner's board of directors the amount of cash distributions to be paid each period. Management also uses DCF (adjusted) as a performance measure in determining equity-based ~~compensation and also to evaluate our ability to generate cash for distribution to our limited partners.~~compensation. Adjusted EBITDA is an important measure that we and the investment community use to assess the financial results of an entity. We believe that investors benefit from having access to the same financial measures utilized by management for these evaluations. A reconciliation of DCF and adjusted EBITDA for the ~~nine~~three months ended ~~September 30, 2012~~March 31, 2013 and ~~2013~~2014 to net income, which is its nearest comparable GAAP financial measure, follows (in millions):


	Nine Months Ended September 30,						Increase			Three Months Ended March 31,						Increase
	2012			2013			(Decrease)			2013			2014			(Decrease)
Net income	$	281.9		$	392.2		$	110.3		$	113.0		$	242.6		$	129.6
Interest expense, net	83.9			84.6			0.7			28.3			30.7			2.4
Depreciation and amortization⁽¹⁾	96.2			107.4			11.2			36.9			38.1			1.2
Equity-based incentive compensation expense⁽²⁾	(0.4		)	2.2			2.6			(7.4		)	(9.7		)	(2.3		)
Asset retirements and impairments	10.6			4.3			(6.3		)	1.8			1.2			(0.6		)
Commodity-related adjustments:
Derivative (gains) losses recognized in the period associated with future product transactions⁽³⁾	18.4			(8.3		)	(26.7		)	2.3			(0.1		)	(2.4		)
Derivative gains (losses) recognized in previous periods associated with products sold in the period⁽⁴⁾	(6.7		)	(5.7		)	1.0			(5.2		)	(5.3		)	(0.1		)
Lower-of-cost-or-market adjustments	(1.0		)	(0.5		)	0.5			(2.0		)	—			2.0
Houston-to-El Paso cost of sales adjustments⁽⁵⁾	8.2			—			(8.2		)
Total commodity-related adjustments	18.9			(14.5		)	(33.4		)	(4.9		)	(5.4		)	(0.5		)
Other	0.4			(3.0		)	(3.4		)	(1.4		)	0.4			1.8
Adjusted EBITDA	491.5			573.2			81.7			166.3			297.9			131.6
Interest expense, net	(83.9		)	(84.6		)	(0.7		)	(28.3		)	(30.7		)	(2.4		)
Maintenance capital⁽⁶⁾	(47.2		)	(55.5		)	(8.3		)
Maintenance capital⁽⁵⁾										(14.1		)	(14.0		)	0.1
DCF	$	360.4		$	433.1		$	72.7		$	123.9		$	253.2		$	129.3


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

(2)

Because we intend to satisfy vesting of units under our equity-based incentive compensation program with the issuance of limited partner units, expenses related to this program generally are deemed non-cash and added back ~~for DCF purposes.~~to net income to calculate DCF. Total equity-based incentive compensation expense for the ~~nine~~three months ended ~~September 30, 2012~~March 31, 2013 and ~~2013~~2014 was ~~$12.6~~$4.9 million and ~~$14.5~~$5.1 million, respectively. However, the figures above include an adjustment for minimum statutory tax withholdings we paid in ~~2012~~2013 and ~~2013~~2014 of ~~$13.0~~$12.3 million and ~~$12.3~~$14.8 million, respectively, for equity-based incentive compensation units that vested at the previous year end, which reduce DCF.

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(3)	Certain derivatives we use as economic hedges have not been designated as hedges for accounting purposes and the mark-to-market changes of these derivatives are recognized currently in earnings. These amounts represent the gains or losses from economic hedges in our earnings for the period associated with products that had not yet been physically sold as of the ~~period end~~period-end date.


(4)	When we physically sell products that we have economically hedged (but were not designated as hedges for accounting purposes), we include in our DCF calculations the full amount of the change in fair value of the associated derivative agreement.


(5)	Cost of goods sold adjustment related to commodity activities for our Houston-to-El Paso pipeline to more closely resemble current market prices for the applicable period for DCF purposes rather than average inventory costing as used to determine our results of operations. We discontinued these commodity activities during 2012 in conjunction with the Longhorn crude pipeline project.


~~(6)~~	Maintenance capital expenditure projects are not undertaken primarily to generate incremental ~~distributable cash flow~~DCF (i.e. incremental returns to our unitholders), while expansion capital projects are undertaken primarily to generate incremental ~~distributable cash flow.~~DCF. For this reason, we deduct maintenance capital expenditures to determine ~~distributable cash flow.~~DCF.

Current period DCF increased $~~72.7~~129.3 million over the prior year. The change in net income and depreciation and amortization is discussed in detail in Results of Operations above, the change in equity-based compensation is discussed in footnote 2 to the table above and a discussion of our maintenance capital expenditures is provided in Capital Requirements below. The change in DCF from commodity-related adjustments is primarily due to the impact of product price changes during

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each period on economic hedges that do not qualify for hedge accounting ~~treatment and the discontinuance of our Houston-to-El Paso linefill management activities.~~treatment.

A reconciliation of DCF to cash distributions paid is as follows (in millions):


	For the Nine Months Ended				Three Months Ended
	September 30,				March 31
	2012		2013		2013		2014
Distributable cash flow	$	360.4	$	433.1	$	123.9	$	253.2
Less: Cash reserves approved by our general partner	66.6		84.0		10.6		120.4
Total cash distributions paid	$	293.8	$	349.1	$	113.3	$	132.8

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

Net cash provided by operating activities was $~~412.2~~166.9 million and $~~521.2~~270.1 million for the ~~nine~~three months ended ~~September 30,~~March 31, ~~2012~~2013 and ~~2013~~2014, respectively. The $~~109.0~~103.2 million increase from ~~2012~~2013 to ~~2013~~2014 was primarily attributable to:

a ~~$121.4~~$129.6 million increase in net ~~income, excluding the increase in non-cash depreciation~~income; and ~~amortization expense;~~

a ~~$16.4~~$31.8 million increase resulting from a ~~$21.5~~$15.0 million increase in deferred revenue in 2013 versus a $5.1 million increase in deferred revenue in 2012. The increase in 2013 was primarily due to an increase in product-in-transit in our pipeline, an increase related to customers’ transportation deficiencies where the customer has future make-up rights and a deferral of a sale of an asset where the title has not yet passed, but the cash has been received. The decrease ~~in 2012 was primarily due to a customer deficiency recognized in 2011 due to the make-up period expiring (with no like amount in 2012);~~

a $15.8 million increase resulting from a $1.0 million increase in accounts payable in 2013 versus a $14.8 million decrease in accounts payable in 2012, primarily due to the timing of invoices paid to vendors and suppliers; and

~~an $11.5 million increase resulting from an $11.1 million increase~~ in trade accounts receivable and other accounts receivable in ~~2013~~2014 versus a ~~$22.6~~$16.8 million increase during ~~2012,~~2013, primarily due to timing of payments from our customers.

These increases were partially offset by:

a ~~$24.7~~$39.7 million decrease resulting from a ~~$13.4~~$23.0 million increase in inventory in 2014 versus a $16.7 million decrease in inventory in 2013 ~~versus a $38.1 million decrease in inventory in 2012. The decrease in 2012 was primarily~~principally due to ~~the sale of~~increased inventories from product overages on our ~~Houston-to-El Paso~~ pipeline ~~section linefill working inventory in anticipation of converting that pipeline to crude oil service;~~system; and

a $15.9 million decrease resulting from an $8.9 million decrease in energy commodity derivatives contracts, net of derivatives deposits in 2013, versus a $7.0 million increase in 2012, primarily due to the impact of changes in commodity prices on our economic hedges and a decrease in the number of NYMEX contracts during 2012;

~~a $13.0~~$26.3 million decrease resulting from a ~~$2.3~~$20.0 million decrease in accrued product purchases in ~~2013~~2014 versus a ~~$10.7~~$6.3 million increase in accrued product purchases in ~~2012,~~2013, primarily due to the timing of invoices paid to vendors and ~~suppliers; and~~

a $12.8 million decrease resulting from a $10.8 million decrease in current and noncurrent environmental liabilities in 2013 versus a $2.0 million increase in current and noncurrent environmental liabilities in 2012, primarily due to an adjustment during the current period of an accrual for potential air emission fees at our East Houston terminal and Galena Park facilities (see ~~Environmental~~ ~~below for more information regarding the adjustment of this accrual).~~

suppliers.

Net cash used by investing activities for the ~~nine~~three months ended ~~September 30,~~March 31, ~~2012~~2013 and ~~2013~~2014 was $~~220.8~~148.6 million and $~~577.3~~202.5 million, respectively. During ~~2013,~~2014, we spent $~~289.7~~70.3 million for capital expenditures, which included $~~55.5~~14.0 million for maintenance capital and $~~234.2~~56.3 million for expansion capital. ~~Our expansion capital spending during 2013 was primarily for the Longhorn pipeline reversal project.~~ Also during ~~2013,~~2014, we contributed capital of $~~181.4~~127.7 million in conjunction with our joint venture capital projects (primarily BridgeTex) which we account for as investments in non-controlled entities. During 2013, we spent $89.9 million for capital expenditures,

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which included $14.1 million for maintenance capital and $75.8 million for expansion capital. Also during 2013, we contributed capital of $47.0 million in conjunction with our joint venture capital projects which we account for as investments in non-controlled ~~entities, acquired a 250-mile pipeline business for $57.0 million and spent $22.5 million on an asset acquisition. During 2012, we spent~~ ~~$230.0 million~~ ~~for capital expenditures, which included~~ ~~$47.2 million~~ ~~for maintenance capital and~~ ~~$182.8 million~~ ~~for expansion capital, and contributed capital of~~ ~~$37.5 million~~ ~~in conjunction with our joint venture capital projects.~~entities.

Net cash ~~used~~provided (used) by financing activities for the ~~nine~~three months ended ~~September 30,~~March 31, ~~2012~~2013 and ~~2013~~2014 was $~~300.5~~(125.6) million and $~~258.0~~103.8 million, respectively. During first quarter 2014, we paid cash distributions of $132.8 million to our unitholders. Additionally, we received net proceeds of $257.7 million from borrowings under notes, which were used to repay borrowings outstanding under our revolving credit facility and for general partnership purposes, including expansion capital. Also, in January 2014, the cumulative amounts of the January 2011 equity-based incentive compensation award grants were settled by issuing 387,216 limited partner units and distributing those units to the long-term incentive plan ("LTIP") participants, resulting in payments of associated tax withholdings of $14.8 million. During the first ~~nine~~three months of 2013, we paid cash distributions of $~~349.1~~113.3 million to our ~~unitholders and borrowed $98.4 million on our revolving credit facility.~~unitholders. Also, in January 2013, the cumulative amounts of the January 2010 equity-based incentive compensation award grants were settled by issuing 476,682 limited partner units and distributing those units to the LTIP participants, resulting in payments of associated tax withholdings of $12.3 million. ~~During the first nine months of 2012, we paid cash distributions of~~ ~~$293.8 million~~ to our unitholders. Also, in January 2012, the cumulative amounts of the January 2009 equity-based incentive compensation award grants were settled by issuing 722,766 limited partner units and distributing those units to the participants, resulting in payments of associated tax withholdings of ~~$13.0 million~~.

The quarterly distribution amount related to our ~~third-quarter 2013~~first-quarter 2014 financial results (to be paid in ~~fourth~~second quarter ~~2013)~~2014) is ~~$0.5575~~$0.6125 per unit. If we meet management's targeted distribution growth of ~~16%~~20% for ~~2013~~2014 and the number of outstanding limited partner units remains at ~~226.7~~227.1 million, total cash distributions of approximately ~~$494.2~~$593.8 million will be paid to our unitholders related to ~~2013~~2014 financial results. Management believes we will have sufficient distributable cash flow to fund these distributions.

Capital Requirements

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

Maintenance capital expenditures. These expenditures include costs required to maintain equipment reliability and safety and to address environmental or other regulatory requirements rather than to generate incremental distributable cash flow; and

Expansion capital expenditures. These expenditures are undertaken primarily to generate incremental distributable cash flow and include costs to acquire additional assets to grow our business and to expand or upgrade our existing facilities, which we refer to as organic growth projects. Organic growth projects include capital expenditures that increase storage or throughput volumes or develop pipeline connections to new supply sources.

For the ~~nine~~three months ended ~~September 30,~~March 31, ~~2012~~ ~~and~~ ~~2013~~2014, our maintenance capital spending was $~~47.2~~14.0 million ~~and~~ ~~$55.5 million, respectively.~~. For ~~2013,~~2014, we expect to ~~incur~~spend approximately $77.0 million on maintenance capital.

In addition to maintenance capital expenditures, ~~for~~we also incur expansion capital expenditures at our existing ~~businesses of approximately $75.0 million.~~

facilities and to acquire new assets. During the first ~~nine~~three months of ~~2013~~2014, we spent $~~234.2~~56.3 million for organic growth capital and $~~181.4~~127.7 million for capital projects in conjunction with our joint ventures. ~~Additionally, we spent $79.5 million on acquisitions.~~ Based on the progress of expansion projects already underway, including the ~~reversal and conversion~~expansion of our Longhorn ~~pipeline from refined products to~~ crude oil ~~service~~pipeline, construction of a condensate splitter at Corpus Christi and our investment in the BridgeTex pipeline, we expect to spend approximately ~~$925~~$700.0 million for expansion capital during ~~2013, which includes $192 million for the New Mexico pipeline we acquired on July 1, 2013 and the pending acquisition of the Rocky Mountain pipeline,~~2014, with an additional ~~$400~~$325.0 million in ~~2014~~2015 and $75.0 million in 2016 to complete our current projects.

Liquidity

Consolidated debt at December 31, ~~2012~~2013 and ~~September 30, 2013~~March 31, 2014 was as follows (in millions):

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	December 31, 2012		September 30, 2013		Weighted-Average Interest Rate at September 30, 2013 ⁽¹⁾	December 31, 2013		March 31, 2014		Weighted-Average Interest Rate for Three Months Ending March 31, 2014 ⁽¹⁾
Revolving credit facility	$	—	$	98.4	1.2%	$	—	$	—	—%
$250.0 of 6.45% Notes due 2014	249.9		250.0		6.3%	250.0		250.0		6.3%
$250.0 of 5.65% Notes due 2016	251.6		251.3		5.7%	251.2		251.1		5.7%
$250.0 of 6.40% Notes due 2018	261.4		259.9		5.4%	259.3		258.8		5.4%
$550.0 of 6.55% Notes due 2019	575.1		572.4		5.7%	571.5		570.6		5.7%
$550.0 of 4.25% Notes due 2021	558.1		557.4		4.0%	557.2		557.0		4.0%
$250.0 of 6.40% Notes due 2037	249.0		249.0		6.4%	249.0		249.0		6.4%
$250.0 of 4.20% Notes due 2042	248.3		248.4		4.2%	248.4		248.4		4.2%
$550.0 of 5.15% Notes due 2043						298.7		556.4		5.2%
Total debt	$	2,393.4	$	2,486.8	5.2%	$	2,685.3	$	2,941.3	5.2%


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

The revolving credit facility and notes detailed in the table above are senior indebtedness.

The face value of our debt at December 31, ~~2012~~2013 and ~~September 30, 2013~~March 31, 2014 was $~~2.4~~2.7 billion. and $2.9 billion, respectively. The difference between the face value and carrying value of the debt outstanding is the unamortized portion of various fair value hedges and the unamortized discounts and premiums on debt issuances. Realized gains and losses on fair value hedges and note discounts and premiums are being amortized or accreted to the applicable notes over the respective lives of those notes.

2014 Debt Offering.In March 2014, we issued an additional $250.0 million of our 5.15% notes due October 15, 2043 in an underwritten public offering. The notes were issued at 103.1% of par. We used the net proceeds from this offering of approximately $255.1 million, after underwriting discounts and offering expenses of $2.6 million, to repay borrowings outstanding under our revolving credit facility and for general partnership purposes, including expansion capital.

6.45% Notes due 2014. The maturity date of our $250.0 million of 6.45% notes is June 1, 2014. The carrying amount of these notes was recorded as current portion of long-term debt on our consolidated balance ~~sheet~~sheets as of December 31, 2013 and ~~September 30, 2013~~March 31, 2014. We anticipate ~~refinancing~~using cash on hand and borrowings against our commercial paper program (see Commercial Paper Program below) to repay this debt ~~prior to its maturity in June 2014.~~when it matures.

Revolving Credit Facility. The total borrowing capacity under our revolving credit facility, which matures in ~~October 2016,~~November 2018, is $~~800.0 million~~1.0 billion. Borrowings under the facility are unsecured and bear interest at LIBOR plus a spread ranging from ~~0.875%~~1.0% to 1.75% based on our credit ~~ratings and amounts outstanding under the facility.~~ratings. Additionally, an unused commitment fee is assessed at a rate from ~~0.125%~~0.10% to ~~0.3%~~0.28%, depending on our credit ratings. The unused commitment fee was ~~0.2%~~0.125% at ~~September 30, 2013~~March 31, 2014. Borrowings under this facility may be used for general partnership purposes, including capital expenditures. As of ~~September 30, 2013~~March 31, 2014, there ~~was $98.4 million~~were no borrowings outstanding under this facility and $5.6 million was obligated for letters of credit. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheets, but decrease our borrowing capacity under the facility.

Commercial Paper Program. In April 2014, we initiated a commercial paper program pursuant to which we may issue short-term, unsecured commercial paper notes of up to $1.0 billion. Borrowings under the program are backed by and may not exceed the available capacity on our revolving credit facility. We expect to use the net proceeds of issuances of the notes for general partnership purposes. We currently have no notes issued under this program.

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Interest Rate Derivatives. In ~~September 2013,~~first quarter 2014, we entered into ~~$150.0~~$200.0 million of ~~Treasury lock contracts~~interest rate swap agreements to hedge against the ~~risk of~~ variability of future interest payments on ~~a portion~~an anticipated debt issuance. We accounted for these agreements as cash flow hedges. When we issued the $250.0 million of 5.15% notes due 2043 later in the ~~debt~~first quarter of 2014, we ~~expected to issue in early October 2013. The fair value of these contracts at September 30, 2013 was a liability of less than $0.1 million. These contracts were~~ settled ~~on October 3, 2013~~the associated interest rate swap agreements for a loss of ~~$0.2~~$3.6 million. ~~We have accounted for these contracts~~The loss was recorded to other comprehensive income and will be recognized into earnings as ~~cash flow hedges.~~

~~See~~ ~~Recent Developments~~ ~~above for a discussion~~an adjustment to our periodic interest accruals over the life of the ~~debt we issued after September 30, 2013.~~associated notes. This loss was also reported as net payment on financial derivatives in the financing activities of our consolidated statements of cash flows.

Off-Balance Sheet Arrangements

None.

Environmental

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

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~~Clean Air Act - Section 185 Liability~~

Other Items

Commodity Derivative Agreements. Certain of the business activities in which we engage result in our owning various commodities which exposes us to commodity price risk. We use NYMEX contracts and butane futures agreements to help manage this commodity price risk. We use NYMEX contracts to hedge against changes in the price of refined products we expect to sell in future periods. We use and account for those NYMEX contracts that qualify for hedge accounting treatment as either cash flow or fair value hedges, and we use and account for those NYMEX contracts that do not qualify for hedge accounting treatment as economic hedges. We use butane futures agreements to economically hedge against changes in the price of butane we expect to purchase in the future as part of our butane blending activity. As of ~~September 30, 2013~~March 31, 2014, our open derivative contracts were as follows:

Open Derivative Contracts Designated as Hedges

NYMEX contracts covering 0.7 million barrels of crude oil to hedge against future price changes of crude oil linefill and tank bottom inventory. These contracts, which we are accounting for as fair value hedges, mature between ~~October 2013~~April 2014 and November 2016. Through ~~September 30, 2013~~March 31, 2014, the cumulative amount of losses from these agreements was $~~10.2~~9.6 million. The cumulative losses from these fair value hedges were recorded as adjustments to the asset being hedged, and there has been no ineffectiveness recognized for these hedges. As a result, none of these cumulative losses have impacted our consolidated income statement.

Open Derivative Contracts Not Designated as Hedges

NYMEX contracts covering ~~2.8~~1.6 million barrels of refined products related to our butane blending and fractionation activities. These contracts mature between ~~October 2013~~April 2014 and ~~April 2014~~January 2015 and are being accounted for as economic hedges. Through ~~September 30, 2013~~March 31, 2014, the cumulative amount of net unrealized ~~gains~~losses associated with these agreements was ~~$5.0 million, all of which was recognized~~$2.7 million. We recorded these losses as an ~~increase~~adjustment to product sales revenue, of which $2.9 million of net losses was recognized in ~~2013.~~2013 and $0.2 million of net gains was recognized in 2014.

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NYMEX contracts covering ~~0.4~~0.6 million barrels of refined products and crude oil related to inventory we carry that resulted from pipeline product overages. These contracts, which mature in ~~October 2013,~~April 2014, are being accounted for as economic hedges. Through ~~September 30, 2013~~March 31, 2014, the cumulative amount of net unrealized ~~gains~~losses associated with these agreements was $0.5 million. We recorded these ~~gains~~losses as ~~a decrease in~~an adjustment to operating expenses, all of which was recognized in ~~2013.~~2014.

Butane futures agreements to purchase ~~0.4~~0.1 million barrels of butane that mature between ~~October 2013~~April 2014 and ~~April 2014,~~January 2015, which are being accounted for as economic hedges. Through ~~September 30, 2013~~March 31, 2014, the cumulative amount of net unrealized ~~gains~~losses associated with these agreements was ~~$2.7~~less than $0.1 million. We recorded these ~~gains~~losses as ~~a decrease in~~an adjustment to cost of product ~~purchases, all~~sales, of which less than $0.1 million of net gains was recognized in ~~2013.~~2013 and $0.1 million of net losses was recognized in 2014.

Settled Derivative Contracts

We settled NYMEX contracts covering ~~5.1~~2.4 million barrels of refined products related to economic hedges of products from our butane blending and fractionation activities that we sold during ~~2013.~~2014. We recognized a gain of ~~$3.5~~$2.6 million in ~~2013~~2014 related to ~~these contracts which we recorded as an adjustment to product sales revenue.~~

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We settled NYMEX contracts covering 0.2 million barrels of refined products related to cash flow hedges of products from our butane blending and fractionation activities that we sold during 2013. We recognized a loss of $4.4 million on the settlement of these contracts, which we recorded as an adjustment to product sales revenue.

We settled NYMEX contracts covering ~~3.9~~1.2 million barrels of refined products and crude oil related to economic hedges of product inventories from product overages on our pipeline system ~~which~~that we sold during ~~2013.~~2014. We recognized a ~~loss~~gain of ~~$2.1~~$0.9 million in ~~2013~~2014 on the settlement of these contracts, which we recorded as an adjustment to operating expense.

We settled butane futures agreements covering ~~0.2~~0.1 million barrels related to economic hedges of butane purchases we made during ~~2013~~2014 associated with our butane blending activities. We recognized a ~~loss~~gain of ~~$0.6~~$0.2 million in the current period on the settlement of these contracts, which we recorded as an adjustment to cost of product ~~purchases.~~sales.

Impact of Commodity Derivatives on Results of Operations

The following tables provide a summary of the positive and (negative) impacts of the mark-to-market gains and losses associated with NYMEX contracts on our results of operations for the respective periods presented (in millions):


	Nine Months Ended September 30, 2012												Three Months Ended March 31, 2013
	Product Sales			Product Purchases			Operating Expense			Net Impact on Results of Operations			Product Sales			Cost of Product Sales			Operating Expense			Net Impact on Results of Operations
NYMEX losses recognized during the period that were associated with economic hedges of physical product sales or purchases during the period	$	(27.6	)	$	(0.5	)	$	(2.4	)	$	(30.5	)	$	(4.5	)	$	(0.7	)	$	(0.7	)	$	(5.9	)
NYMEX losses recorded during the period that were associated with products that will be or were sold or purchased in future periods	(10.5		)	(1.1		)	(0.8		)	(12.4		)	(1.7		)	(0.1		)	(1.2		)	(3.0		)
Net impact of NYMEX contracts	$	(38.1	)	$	(1.6	)	$	(3.2	)	$	(42.9	)	$	(6.2	)	$	(0.8	)	$	(1.9	)	$	(8.9	)

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Nine Months Ended September 30, 2013
Product Sales Product Purchases Operating Expense Net Impact on Results of Operations
NYMEX losses recognized during the period that were associated with economic hedges of physical product sales or purchases during the period $ (0.9 ) $ (0.6 ) $ (2.1 ) $ (3.6 )
NYMEX gains recorded during the period that were associated with products that will be or were sold or purchased in future periods 5.0
2.7
0.5
8.2
Net impact of NYMEX contracts $ 4.1
$ 2.1
$ (1.6 ) $ 4.6



	Three Months Ended March 31, 2014
	Product Sales		Cost of Product Sales			Operating Expense			Net Impact on Results of Operations
NYMEX gains recognized during the period that were associated with economic hedges of physical product sales or purchases during the period	$	2.6	$	0.2		$	0.9		$	3.7
NYMEX gains (losses) recorded during the period that were associated with products that will be sold or purchased in future periods	0.2		(0.1		)	(0.5		)	(0.4		)
Net impact of NYMEX contracts	$	2.8	$	0.1		$	0.4		$	3.3

Related Party Transactions. Barry R. Pearl is an independent member of our general partner's board of directors and is also a director of Targa Resources Partners, L.P. ("Targa"). In the normal course of business, we purchase butane from subsidiaries of Targa. For the three months ended ~~September 30, 2012~~March 31, 2013 and ~~2013, we made purchases of butane from subsidiaries of Targa of less than~~ ~~$0.1 million~~ ~~and~~ ~~$1.0 million, respectively. For the~~ ~~nine months ended September 30, 2012~~ ~~and~~ ~~2013~~2014, we made purchases of butane from subsidiaries of Targa of $~~12.5~~14.2 million and $~~15.6~~12.2 million, respectively. These purchases were made on the same terms as comparable third-party transactions. ~~We had~~There were ~~$0.1 million~~no ~~and~~ $0amounts payable to Targa at December 31, ~~2012~~2013 ~~and~~or ~~September 30, 2013~~March 31, 2014, respectively.

We own a 50% interest in Texas Frontera, LLC ("Texas Frontera"), which owns ~~0.8~~approximately one million barrels of refined products storage at our Galena Park, Texas terminal. The storage capacity owned by this joint venture is leased to an affiliate of Texas Frontera under a long-term lease agreement. ~~Texas Frontera began operations in October 2012.~~ We receive management fees from Texas Frontera, which we report as affiliate management fee revenue on our consolidated statements of income.

We own a 50% interest in Osage, which owns a ~~135-mile~~135-mile crude oil pipeline in Oklahoma and Kansas that we operate. We receive management fees from Osage, which we report as affiliate management fee revenue on our consolidated statements of income.

We own a 50% interest in Double Eagle which ~~owns a 140-mile pipeline that connects to an existing pipeline owned by an affiliate of Double Eagle. Double Eagle is operated by a third-party entity. This pipeline, which began limited operation in~~

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~~second quarter 2013,~~ transports condensate from the Eagle Ford shale formation in South Texas via a 195-mile pipeline to our terminal in Corpus Christi, Texas. Double Eagle is operated by an affiliate of the other 50% member of Double Eagle. We receive ~~connection fees~~throughput revenue from Double Eagle that ~~are~~is included in our transportation and terminals revenue on our consolidated statements of income. For the three ~~and nine~~ months ended ~~September 30, 2013,~~March 31, 2014, we received ~~connection fees~~throughput revenue of ~~$0.5~~$0.5 million ~~and $0.8 million, respectively,~~ and we recorded a ~~$0.2~~$0.2 million and $0.3 million trade accounts receivable from Double Eagle at ~~September 30, 2013.~~December 31, 2013 and March 31, 2014, respectively.

We own a 50% interest in BridgeTex, which is in the process of constructing a ~~450-mile~~450-mile pipeline ~~and~~with related infrastructure to transport crude oil from Colorado City, Texas for delivery to Houston and Texas City, Texas refineries. This pipeline is expected to begin service in mid-2014. We receive construction management fees from BridgeTex, which we report as affiliate management fee revenue on our consolidated statements of income.

During 2013, we received $4.8 million from BridgeTex as a deposit for the purchase of emission reduction credits, which, pending governmental approval, we expect to transfer to BridgeTex during the second quarter of 2014. Also in 2013, we received $1.4 million from BridgeTex for the purchase of easement rights from us, of which $0.7 million was recorded as a reduction of operating expense and $0.7 million was recorded as an adjustment to our investment in BridgeTex, which is being amortized as a reduction of operating expense over the weighted average depreciable lives of the BridgeTex assets.

New Accounting Pronouncements

~~In February 2013, the Financial Accounting Standards Board ("FASB")~~There were no significant accounting pronouncements issued ~~Accounting Standards Update ("ASU") 2013-02,~~ ~~Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. The amendments in ASU 2013-02 do not change the current requirements for reporting net income~~during 2014 that had or other comprehensive income in financial statements. However, the amendments require an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under GAAP that provide additional detail about those amounts. ASU 2013-02 is effective for annual and interim periods beginning after December 15, 2012 and is to be applied prospectively. We adopted this standard in the first quarter of 2013 and its adoption did notwill have a material impact on our consolidated results of operations, financial position or cash flows.

~~In December 2011, the FASB issued ASU 2011-11,~~ ~~Disclosures about Offsetting Assets and Liabilities~~. This ASU requires entities that have financial instruments and derivatives that are either: (i) offset in accordance with ASC Topic 210 or Topic 815 or (ii) are subject to an enforceable master netting arrangement or similar agreement to make additional disclosures of the gross and net amounts of those assets and liabilities, the amounts offset in accordance with ASC Topics 210 and 815, as well as qualitative disclosures of the entity's master netting arrangement or similar agreement. In January 2013, the FASB issued ASU 2013-01, ~~Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. The amendments in ASU 2013-01 clarify that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with ASC Topic 815,~~ ~~Derivatives and Hedging~~. ASU 2011-11 must be applied retrospectively and became effective for fiscal years beginning on or after January 1, 2013. We adopted these standards in the first quarter of 2013 and their adoption did not have a material impact on our results of operations, financial position or cash flows.

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ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

We use derivatives to help us manage commodity price risk. Forward physical contracts that qualify for and are elected as normal purchases and sales are accounted for using traditional accrual accounting. As of ~~September 30, 2013~~March 31, 2014, we had commitments under forward purchase and sale contracts used in our butane blending and fractionation activities as follows (in millions):


	Market Value		Barrels	Notional Value		Barrels
Forward purchase contracts	$	158.8	2.6	$	73.4	1.3
Forward sale contracts	$	44.4	0.4	$	25.2	0.2

We use NYMEX contracts to hedge against changes in the price of petroleum products we expect to sell from activities in which we acquire or produce petroleum products. Some of these NYMEX contracts qualify for hedge accounting treatment, and we designate and account for these as either cash flow or fair value hedges. We account for those NYMEX contracts that do not qualify for hedge accounting treatment, or are otherwise undesignated as cash flow or fair value hedges, as economic hedges. We also use butane futures agreements to hedge against changes in the price of butane that we expect to purchase in future periods. At ~~September 30, 2013~~March 31, 2014, we had open NYMEX contracts representing ~~3.9~~2.9 million barrels of petroleum products we expect to sell in the future. Additionally, we had open butane futures agreements for ~~0.4~~0.1 million barrels of butane we expect to purchase in the future.

At ~~September 30, 2013~~March 31, 2014, the fair value of our open NYMEX contracts was ~~an asset~~a liability of $~~6.7~~1.9 million and the fair value of our butane futures agreements was ~~an asset~~a liability of less than $~~2.7~~0.1 million. Combined, the net ~~asset~~liability of $~~9.4~~1.9 million was recorded as a current ~~asset~~liability to energy commodity derivatives contracts ($~~8.4~~3.4 million) and other non-current assets ($~~1.0~~1.5 million).

At ~~September 30, 2013~~March 31, 2014, open NYMEX contracts representing ~~3.2~~2.2 million barrels of petroleum products did not qualify for hedge accounting treatment. A $10.00 per barrel increase in the price of these NYMEX contracts for reformulated gasoline blendstock for oxygen blending (“RBOB”) gasoline or heating oil would result in a $~~32.0~~22.0 million decrease in our operating profit and a $10.00 per barrel decrease in the price of these NYMEX contracts for RBOB or heating oil would result in a $~~32.0~~22.0 million increase in our operating profit. However, the increases or decreases in operating profit we recognize from our open NYMEX contracts will be substantially offset by higher or lower product sales revenue when the physical sale of the product occurs. These contracts may be for the purchase or sale of product in markets different from those in which we are attempting to hedge our exposure, resulting in hedges that do not eliminate all price risks.

Interest Rate Risk

At ~~September 30, 2013~~March 31, 2014, we had ~~$98.4 million outstanding on our~~no variable rate ~~revolving credit facility. Considering the amount~~debt outstanding, including on our revolving credit facility. Our revolving credit facility ashas total borrowing capacity of ~~September 30, 2013~~,$1.0 billion, from which we could borrow in the future. To the extent we borrow funds under this facility in any future period, those borrowings would bear interest at LIBOR plus a spread ranging from 1.0% to 1.75% based on our ~~annual interest expense would change by $0.1 million if LIBOR were to change by 0.125%.~~credit ratings.

During 2012 we terminated and settled certain interest rate swap agreements and realized a gain of $11.0 million, which was recorded to other comprehensive income. The purpose of these swaps was to hedge against the variability of future interest payments on the refinancing of our debt that matures in 2014. If management were to

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determine that it was probable this forecasted transaction would not occur, ~~in 2014,~~ the $11.0 million gain we have recorded to other comprehensive income would be reclassified into earnings.


ITEM 4.	CONTROLS AND PROCEDURES

We performed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in rule 13a-14(c) of the Securities Exchange Act) as of the end of the period covered by the date of this report. We performed this evaluation under the supervision and with the participation of our management, including our general partner’s Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our general partner’s Chief Executive Officer

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and Chief Financial Officer concluded that these disclosure controls and practices are effective in providing reasonable assurance that all required disclosures are included in the current report. Additionally, these disclosure controls and practices are effective in ensuring that information required to be disclosed is accumulated and communicated to our Chief Executive Officer and Chief Financial Officer to allow timely decisions regarding required disclosures. There has been no change in our internal control over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act) during the quarter ended ~~September 30, 2013~~March 31, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Forward-Looking Statements

Certain matters discussed in this Quarterly Report on Form 10-Q include forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act that discuss our expected future results based on current and pending business operations. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. Forward-looking statements can be identified by words such as "anticipates," "believes," "continue," "could," "estimates," "expects," "forecasts," "goal," "guidance," "intends," "may," "might," "plans," "potential," "projects," "scheduled," "should" and other similar expressions. Although we believe our forward-looking statements are based on reasonable assumptions, statements made regarding future results are not guarantees of future performance and subject to numerous assumptions, uncertainties and risks that are difficult to predict. Therefore, actual outcomes and results may be materially different from the results stated or implied in such forward-looking statements included in this report.

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

overall demand for refined products, crude oil, liquefied petroleum gases and ammonia in the U.S.;

price fluctuations for refined products, crude oil, liquefied petroleum gases and ammonia and expectations about future prices for these products;

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

changes in the financial condition of our customers, vendors, derivatives counterparties, joint venture co-owners or lenders;

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

development of alternative energy sources, including but not limited to natural gas, solar power, wind power and geothermal energy, increased use of biofuels such as ethanol and biodiesel, increased conservation or fuel efficiency, as well as regulatory developments or other trends that could affect demand for our services;

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

changes in demand for storage in our refined products, or crude oil or marine terminals;

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

our ability to manage interest rate and commodity price exposures;

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changes in our tariff rates implemented by the Federal Energy Regulatory Commission, the U.S. Surface Transportation Board or state regulatory agencies;

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

the effect of weather patterns and other natural phenomena, including climate change, on our operations and demand for our services;

an increase in the competition our operations encounter;

the occurrence of natural disasters, terrorism, operational hazards, equipment failures, system failures or unforeseen ~~interruptions for which we are~~ interruptions;

not being adequately ~~insured;~~insured or having losses that exceed our insurance coverage;

our ability to obtain insurance and to manage the increased cost of available insurance;

the treatment of us as a corporation for federal or state income tax purposes or if we become subject to significant forms of other taxation or more aggressive enforcement or increased assessments under existing forms of taxation;

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

our ability to make and integrate accretive acquisitions and joint ventures and successfully execute our business strategy;

uncertainty of estimates, including accruals and costs of environmental remediation;

our ability to cooperate with and rely on our joint venture co-owners;

actions by rating agencies concerning our credit ratings;

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our ability to timely obtain and maintain all necessary approvals, consents and permits required to operate our existing assets and any new or modified assets;

our ability to promptly obtain all necessary services, materials, labor, supplies and rights-of-way required for construction of our growth projects, and to complete construction without significant delays, disputes or cost overruns;

risks inherent in the use and security of information systems in our business and implementation of new software and hardware;

changes in laws and regulations that govern product quality specifications or renewable fuel obligations that could impact our ability to produce gasoline volumes through our blending activities or that could require significant capital outlays for compliance;

changes in laws and regulations to which we or our customers are or become subject, including tax withholding issues, safety, security, employment and environmental laws and regulations, including laws and regulations designed to address climate change, ~~and laws and regulations~~ affecting hydraulic ~~fracturing;~~fracturing, and relating to derivatives transactions;

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

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

the effect of changes in accounting policies;

the potential that our internal controls may not be adequate, weaknesses may be discovered or remediation of any identified weaknesses may not be successful;

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

petroleum product supply disruptions;

global and domestic repercussions from terrorist activities, including cyber attacks, and the government's response thereto; and

other factors and uncertainties inherent in the transportation, storage and distribution of refined products and crude oil.

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

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PART II

OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

Glenn A. Henke, et al. v. Magellan Pipeline Company, L.P., et al.

In February 2010, a class action lawsuit was filed against us, ARCO Midcon L.L.C. and WilTel Communications, L.L.C. ~~(“WilTel”~~("WilTel"). The complaint alleges that the property owned by plaintiffs and those similarly situated has been damaged by the existence of hazardous chemicals migrating from a pipeline easement onto the plaintiffs' ~~property.~~property and seeks recovery for such damages. We acquired the pipeline from ARCO Pipeline ~~(“APL”~~("APL") in 1994 as part of a larger transaction and subsequently transferred the property to WilTel. We are required to indemnify and defend WilTel pursuant to the transfer agreement. Prior to our acquisition of the pipeline property from APL, the pipeline was purged of product. Neither we nor WilTel ever transported hazardous materials through the pipeline. A hearing on the plaintiffs' Motion for Class Certification was held in the U.S. District Court for the Eastern District of Missouri in December 2012. ~~The court has not yet rendered a decision on~~In March 2014, the ~~issue~~U.S. District Court denied plaintiff's motion for Class Certification. While the results of ~~class certification. We~~the remaining litigation cannot be predicted with certainty, we believe that the ultimate resolution of this matter will not have a material impact on our results of operations, financial position or cash flows.

2011 EPA Clean Water Act Information Request for Pipeline Release in Texas

In July 2011, we received an information request from the Environmental Protection Agency ("EPA") pursuant to Section 308 of the Clean Water Act regarding a pipeline release in February 2011 in Texas. We have accrued $0.1 million for potential monetary sanctions related to this matter. WeWhile the results cannot be predicted with certainty, we believe that the ultimate resolution of this matter will not have a material impact on our results of operations, financial position or cash flows.

2012 Notice of Probable Violation from PHMSA for Oklahoma and Texas

In March 2012, we received a Notice of Probable Violation from the U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration ("PHMSA") for alleged violations related to the operation and maintenance of certain pipelines in Oklahoma and Texas. We have accrued approximately ~~$0.1~~$0.15 million for potential monetary sanctions related to this matter. WeWhile the results cannot be predicted with certainty, we believe that the ultimate resolution of this matter will not have a material impact on our results of operations, financial position or cash flows.

2012 EPA Clean Water Act Information Request for Pipeline Release in Nebraska

In April 2012, we received an information request from the EPA pursuant to Section 308 of the Clean Water Act, regarding a pipeline release in December 2011 in Nebraska. We have accrued $0.6 million for potential monetary sanctions related to this matter. WeWhile the results cannot be predicted with certainty, we believe that the ultimate resolution of this matter will not have a material impact on our results of operations, financial position or cash flows.

US Oil Recovery, EPA ID No.: TXN000607093 Superfund Site

We have liability at the U.S. Oil Recovery Superfund Site in Pasadena, Texas as a potential responsible party ("PRP") under Section 107(a) of the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as ~~amended.~~ amended ("CERCLA"). As a result of the EPA’s Administrative Settlement Agreement and Order on Consent for Removal Action, filed August 25, 2011, EPA Region 6, CERCLA Docket No. 06-10-11, we voluntarily entered into the PRP group responsible for the site investigation, stabilization and subsequent site cleanup.

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Currently, there is an ongoing removal action designed to stabilize the site, remove the immediate threat posed at the site and set the stage for a later more comprehensive action, known as the assessment phase. We have ~~accrued and~~ paid $15,000 associated with the assessment phase. Until this assessment phase has been completed, we cannot reasonably estimate our proportionate share of the remediation costs associated with this site.

In April 2013, we received a Notice of Probable Violation from PHMSA, which resulted from alleged violations discovered during a 2012 inspection of our central Oklahoma pipeline facilities. In third quarter 2013, we paid $0.1 million for monetary sanctions related to this matter, which is now resolved.

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


ITEM 1A.	RISK FACTORS

In addition to the information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, ~~2012,~~2013, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not our only risks. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

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

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~~Our butane blending activities subject us to federal regulations that govern renewable fuel requirements in the United States.~~

The Energy Independence and Security Act of 2007 expanded the required use of renewable fuels in the United States. Each year, the EPA establishes a Renewable Volume Obligation ("RVO") requirement for refiners and fuel manufacturers based on overall quotas established by the federal government. By virtue of our butane blending activity, and resulting gasoline production, we are an obligated party and receive an annual RVO from the EPA. In lieu of blending renewable fuels (such as ethanol and biodiesel), we have the option to purchase renewable energy credits, called RINs, to meet this obligation.RINs are generated when a gallon of biofuel such as ethanol or biodiesel is produced. RINs may be separated when the biofuel is blended into gasoline or diesel, at which point the RIN is available for use in compliance or is available for sale on the open market.~~The cost of RINs has been volatile during 2013, and the cost and availability of RINs could have an adverse impact on our results of operations, cash flows and cash distributions.~~


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

None.


ITEM 3.	DEFAULTS UPON SENIOR SECURITIES

None.


ITEM 4.	MINE SAFETY DISCLOSURES

Not applicable.


ITEM 5.	OTHER INFORMATION

None.

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ITEM 6.	EXHIBITS



Exhibit Number		Description

Exhibit 12	—	Ratio of earnings to fixed charges.

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

Exhibit 31.2	—	Certification of ~~John D. Chandler,~~Michael P. Osborne, principal financial officer.

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

Exhibit 32.2	—	Section 1350 Certification of ~~John D. Chandler,~~Michael P. Osborne, Chief Financial Officer.

Exhibit 101.INS	—	XBRL Instance Document.

Exhibit 101.SCH	—	XBRL Taxonomy Extension Schema.

Exhibit 101.CAL	—	XBRL Taxonomy Extension Calculation Linkbase.

Exhibit 101.DEF	—	XBRL Taxonomy Extension Definition Linkbase.

Exhibit 101.LAB	—	XBRL Taxonomy Extension Label Linkbase.

Exhibit 101.PRE	—	XBRL Taxonomy Extension Presentation Linkbase.

____________

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SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized in Tulsa, Oklahoma on ~~November 1, 2013.~~May 6, 2014.



MAGELLAN MIDSTREAM PARTNERS, L.P.

By:		Magellan GP, LLC,
		its general partner

/s/ ~~John D. Chandler~~Michael P. Osborne
~~John D. Chandler~~Michael P. Osborne
Chief Financial Officer
(Principal Accounting and Financial Officer)

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INDEX TO EXHIBITS




Exhibit Number		Description

Exhibit 12	—	Ratio of earnings to fixed charges.

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

Exhibit 31.2	—	Certification of ~~John D. Chandler,~~Michael P. Osborne, principal financial officer.

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

Exhibit 32.2	—	Section 1350 Certification of ~~John D. Chandler,~~Michael P. Osborne, Chief Financial Officer.

Exhibit 101.INS	—	XBRL Instance Document.

Exhibit 101.SCH	—	XBRL Taxonomy Extension Schema.

Exhibit 101.CAL	—	XBRL Taxonomy Extension Calculation Linkbase.

Exhibit 101.DEF	—	XBRL Taxonomy Extension Definition Linkbase.

Exhibit 101.LAB	—	XBRL Taxonomy Extension Label Linkbase.

Exhibit 101.PRE	—	XBRL Taxonomy Extension Presentation Linkbase.

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	Three Months Ended September 30, 2013
	(in thousands)
	Refined Products		Crude Oil			Marine Storage			Intersegment Eliminations			Total
Transportation and terminals revenue	$	205,859	$	49,519		$	39,948		$	—		$	295,326
Product sales revenue	143,549		—			1,303			—			144,852
Affiliate management fee revenue	—		3,369			288			—			3,657
Total revenue	349,408		52,888			41,539			—			443,835
Operating expenses	82,174		4,034			17,813			(759		)	103,262
Product purchases	120,429		—			(130		)	—			120,299
Earnings of non-controlled entities	—		(1,770		)	(605		)	—			(2,375		)
Operating margin	146,805		50,624			24,461			759			222,649
Depreciation and amortization expense	21,851		5,538			7,122			759			35,270
G&A expenses	22,741		5,100			4,914			—			32,755
Operating profit	$	102,213	$	39,986		$	12,425		$	—		$	154,624



	Texas Frontera		Osage			Double Eagle		BridgeTex		Consolidated
Investment at December 31, 2012	$	15,728	$	18,888		$	40,840	$	31,900	$	107,356
Additional investment	—		—			33,454		147,923		181,377
Earnings (losses) of non-controlled entities:
Proportionate share of earnings	1,907		3,610			141		2		5,660
Amortization of excess investment	—		(498		)	—		—		(498		)
Earnings of non-controlled entities	1,907		3,112			141		2		5,162
Less:
Distributions of earnings from investments in non-controlled entities	1,907		—			—		—		1,907
Distributions in excess of earnings of non-controlled entities	604		—			—		—		604
Investment at September 30, 2013	$	15,124	$	22,000		$	74,435	$	179,825	$	291,384



	Three Months Ended September 30, 2012
Derivative Instrument	Amount of Gain (Loss) Recognized in AOCL on Derivative				Location of Gain Reclassified from AOCL into Income	Amount of Gain Reclassified from AOCL into Income
Interest rate contracts		$	10,126		Interest expense		$	41
NYMEX commodity contracts		(460		)	Product sales revenue		1,384
Total cash flow hedges		$	9,666		Total		$	1,425



	Nine Months Ended September 30, 2012
Derivative Instrument	Amount of Gain Recognized in AOCL on Derivative			Location of Gain Reclassified from AOCL into Income	Amount of Gain Reclassified from AOCL into Income
Interest rate contracts		$	11,134	Interest expense		$	123
NYMEX commodity contracts		1,207		Product sales revenue		1,384
Total cash flow hedges		$	12,341	Total		$	1,507



	As of December 31, 2012
Assets / (Liabilities) ($ in thousands)							Fair Value Measurements
Assets / (Liabilities) ($ in thousands)	Carrying Amount			Fair Value			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Energy commodity derivatives contracts (liabilities)	$	(7,338	)	$	(7,338	)	$	(7,338	)	$	—	$	—
Long-term receivables	$	5,135		$	5,108		$	—		$	—	$	5,108
Debt	$	(2,393,408	)	$	(2,721,985	)	$	(2,721,985	)	$	—	$	—



	As of September 30, 2013
Assets / (Liabilities) ($ in thousands)							Fair Value Measurements
Assets / (Liabilities) ($ in thousands)	Carrying Amount			Fair Value			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Energy commodity derivatives contracts (assets)	$	9,407		$	9,407		$	9,407	$	—		$	—
Treasury lock hedge agreements	$	(36	)	$	(36	)	$	—	$	(36	)	$	—
Long-term receivables	$	3,140		$	3,097		$	—	$	—		$	3,097
Debt	$	(2,486,715	)	$	(2,676,025	)	$	—	$	(2,676,025	)	$	—