Edgar Filing: MAGELLAN MIDSTREAM PARTNERS LP

MMP - 2014.3.31.10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________

FORM 10-Q



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

For the quarterly period ended March 31, 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 May 5, 2014, there were 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.		CONSOLIDATED FINANCIAL STATEMENTS
	CONSOLIDATED STATEMENTS OF INCOME		2
	CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME		3
	CONSOLIDATED BALANCE SHEETS		4
	CONSOLIDATED STATEMENTS OF CASH FLOWS		5
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS:
	1.	Organization, Description of Business and Basis of Presentation	6
	2.	Product Sales Revenue	7
	3.	Segment Disclosures	8
	4.	Investments in Non-Controlled Entities	9
	5.	Inventory	11
	6.	Employee Benefit Plans	11
	7.	Debt	12
	8.	Derivative Financial Instruments	13
	9.	Commitments and Contingencies	18
	10.	Long-Term Incentive Plan	19
	11.	Distributions	20
	12.	Fair Value	21
	13.	Related Party Transactions	22
	14.	Subsequent Events	23
ITEM 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Introduction		24
	Recent Developments		24
	Results of Operations		25
	Distributable Cash Flow		28
	Liquidity and Capital Resources		29
	Off-Balance Sheet Arrangements		32
	Environmental		32
	Other Items		32
	New Accounting Pronouncements		34
ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	35
ITEM 4.		CONTROLS AND PROCEDURES	36
Forward-Looking Statements			36
PART II OTHER INFORMATION
ITEM 1.		LEGAL PROCEEDINGS	38
ITEM 1A.		RISK FACTORS	39
ITEM 2.		UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	39
ITEM 3.		DEFAULTS UPON SENIOR SECURITIES	39
ITEM 4.		MINE SAFETY DISCLOSURES	39
ITEM 5.		OTHER INFORMATION	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 March 31,
	2013			2014
Transportation and terminals revenue	$	227,271		$	317,637
Product sales revenue	201,711			296,063
Affiliate management fee revenue	3,439			4,906
Total revenue	432,421			618,606
Costs and expenses:
Operating	65,181			73,497
Cost of product sales	160,398			198,040
Depreciation and amortization	36,332			37,511
General and administrative	30,056			34,935
Total costs and expenses	291,967			343,983
Earnings of non-controlled entities	2,051			466
Operating profit	142,505			275,089
Interest expense	31,723			36,416
Interest income	(22		)	(391		)
Interest capitalized	(3,451		)	(5,310		)
Debt placement fee amortization expense	540			599
Income before provision for income taxes	113,715			243,775
Provision for income taxes	748			1,221
Net income	$	112,967		$	242,554
Basic and diluted net income per limited partner unit	$	0.50		$	1.07
Weighted average number of limited partner units outstanding used for basic and diluted net income per unit calculation	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 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 details of the amount of gain/loss recognized in accumulated other comprehensive loss ("AOCL") on derivatives and the amount of gain/loss reclassified from AOCL into income.

(2) These 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, 2013			March 31, 2014
ASSETS				(Unaudited)
Current assets:
Cash and cash equivalents	$	25,235		$	196,630
Trade accounts receivable	116,295			101,292
Other accounts receivable	6,462			12,202
Inventory	187,224			210,235
Energy commodity derivatives deposits	14,782			12,714
Other current assets	46,735			33,969
Total current assets	396,733			567,042
Property, plant and equipment	4,986,750			5,017,786
Less: Accumulated depreciation	1,070,492			1,104,191
Net property, plant and equipment	3,916,258			3,913,595
Investments in non-controlled entities	360,852			487,295
Long-term receivables	2,730			30,365
Goodwill	53,260			53,260
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	61,915			62,635
Other noncurrent assets	4,269			3,426
Total assets	$	4,820,812		$	5,143,782
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable	$	76,326		$	73,417
Accrued payroll and benefits	42,243			27,691
Accrued interest payable	44,935			50,129
Accrued taxes other than income	38,574			31,095
Environmental liabilities	12,147			13,631
Deferred revenue	63,164			64,612
Accrued product purchases	63,033			43,055
Energy commodity derivatives contracts, net	6,737			3,421
Current portion of long-term debt	249,971			249,988
Other current liabilities	41,146			47,111
Total current liabilities	638,276			604,150
Long-term debt	2,435,316			2,691,288
Long-term pension and benefits	51,637			55,736
Other noncurrent liabilities	21,802			19,660
Environmental liabilities	26,339			23,462
Commitments and contingencies
Partners’ capital:
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	(19,504		)	(23,214		)
Total partners’ capital	1,647,442			1,749,486
Total liabilities and partners' capital	$	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)



	Three Months Ended
	March 31,
	2013			2014
Operating Activities:
Net income	$	112,967		$	242,554
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	36,332			37,511
Debt placement fee amortization expense	540			599
Loss on sale, retirement and impairment of assets	1,791			1,205
Earnings of non-controlled entities	(2,051		)	(466		)
Distributions from investments in non-controlled entities	676			384
Equity-based incentive compensation expense	4,856			5,088
Changes in employee benefit plan assets and benefit obligations	479			(71		)
Changes in operating assets and liabilities:
Trade accounts receivable and other accounts receivable	(16,833		)	15,022
Inventory	16,736			(23,011		)
Energy commodity derivatives contracts, net of derivatives deposits	1,311			(529		)
Accounts payable	11,310			2,960
Accrued payroll and benefits	(10,713		)	(14,552		)
Accrued interest payable	(4,653		)	5,194
Accrued taxes other than income	(5,798		)	(7,479		)
Accrued product purchases	6,273			(19,978		)
Deferred revenue	10,647			1,448
Current and noncurrent environmental liabilities	(1,469		)	(1,393		)
Other current and noncurrent assets and liabilities	4,540			25,588
Net cash provided by operating activities	166,941			270,074
Investing Activities:
Property, plant and equipment:
Additions to property, plant and equipment	(89,947		)	(70,295		)
Proceeds from sale and disposition of assets	25			42
Increase in accounts payable related to capital expenditures	(11,863		)	(5,219		)
Investments in non-controlled entities	(47,020		)	(127,698		)
Distributions in excess of earnings of non-controlled entities	188			687
Net cash used by investing activities	(148,617		)	(202,483		)
Financing Activities:
Distributions paid	(113,340		)	(132,835		)
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	(12,259		)	(14,813		)
Net cash provided (used) by financing activities	(125,599		)	103,804
Change in cash and cash equivalents	(107,275		)	171,395
Cash and cash equivalents at beginning of period	328,278			25,235
Cash and cash equivalents at end of period	$	221,003		$	196,630
Supplemental non-cash investing and financing activities:
Issuance of limited partner units in settlement of equity-based incentive plan awards	$	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.

Description of Business

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


•	our refined products segment, including our 9,500-mile refined products pipeline system with 54 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 1,100 miles of crude oil pipelines and storage facilities with an aggregate storage capacity of approximately 18 million 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 approximately 27 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 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, 2013 which is derived from our audited financial statements, include all normal and recurring adjustments necessary to present fairly our financial position as of March 31, 2014, the results of operations for the three months ended March 31, 2013 and 2014 and cash flows for the three months ended March 31, 2013 and 2014. The results of operations for the three months ended March 31, 2014 are not necessarily indicative of the results to be expected for the full year ending December 31, 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, 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 months ended March 31, 2013 and 2014, product sales revenue included the following (in thousands):



	Three Months Ended March 31,
	2013			2014
Physical sale of petroleum products	$	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⁾	(6,158		)	2,823
Other	(11		)	—
Total NYMEX contract adjustments	(6,169		)	2,823
Total product sales revenue	$	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

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 expenses, cost of product 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 consider when evaluating the core profitability of our separate operating segments.



	Three Months Ended March 31, 2013
	(in thousands)
	Refined Products		Crude Oil			Marine Storage			Intersegment Eliminations			Total
Transportation and terminals revenue	$	165,359	$	23,228		$	38,684		$	—		$	227,271
Product sales revenue	199,415		—			2,296			—			201,711
Affiliate management fee revenue	—		3,159			280			—			3,439
Total revenue	364,774		26,387			41,260			—			432,421
Operating expenses	46,281		5,107			14,553			(760		)	65,181
Cost of product sales	158,298		—			2,100			—			160,398
Earnings of non-controlled entities	—		(1,375		)	(676		)	—			(2,051		)
Operating margin	160,195		22,655			25,283			760			208,893
Depreciation and amortization expense	21,353		7,469			6,750			760			36,332
G&A expenses	21,202		4,127			4,727			—			30,056
Operating profit	$	117,640	$	11,059		$	13,806		$	—		$	142,505

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Three Months Ended March 31, 2014
	(in thousands)
	Refined Products		Crude Oil		Marine Storage			Intersegment Eliminations			Total
Transportation and terminals revenue	$	210,236	$	67,903	$	39,498		$	—		$	317,637
Product sales revenue	293,710		—		2,353			—			296,063
Affiliate management fee revenue	—		4,595		311			—			4,906
Total revenue	503,946		72,498		42,162			—			618,606
Operating expenses	51,157		9,058		14,086			(804		)	73,497
Cost of product sales	197,756		—		284			—			198,040
Losses (earnings) of non-controlled entities	—		180		(646		)	—			(466		)
Operating margin	255,033		63,260		28,438			804			347,535
Depreciation and amortization expense	23,172		6,463		7,072			804			37,511
G&A expenses	23,019		5,994		5,922			—			34,935
Operating profit	$	208,842	$	50,803	$	15,444		$	—		$	275,089


4.	Investments in Non-Controlled Entities

We own a 50% interest in Texas Frontera, LLC ("Texas Frontera"), which owns 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. 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 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 throughput revenue from Double Eagle that is included in our transportation and terminals revenue on our consolidated statements of income. For the three months ended March 31, 2014, we received throughput revenue of $0.5 million. We recorded a $0.2 million and $0.3 million trade accounts receivable from Double Eagle at December 31, 2013 and 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.

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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 investment in 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 as earnings of non-controlled entities.

A summary of our investments in 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 our non-controlled entities as of and for the 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, 2013 and March 31, 2014 was as follows (in thousands):



	December 31, 2013		March 31, 2014
Refined products	$	77,144	$	76,229
Liquefied petroleum gases	23,476		33,398
Transmix	72,156		79,127
Crude oil	7,188		15,852
Additives	7,260		5,629
Total inventory	$	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 months ended March 31, 2013 and 2014 (in thousands):

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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, 2013 and March 31, 2014 was as follows (in thousands, except as otherwise noted):




	December 31, 2013		March 31, 2014		Weighted-Average Interest Rate for Three Months Ending March 31, 2014 ⁽¹⁾
Revolving credit facility	$	—	$	—	—%
$250.0 million of 6.45% Notes due 2014	249,971		249,988		6.3%
$250.0 million of 5.65% Notes due 2016	251,183		251,076		5.7%
$250.0 million of 6.40% Notes due 2018	259,346		258,829		5.4%
$550.0 million of 6.55% Notes due 2019	571,515		570,613		5.7%
$550.0 million of 4.25% Notes due 2021	557,213		556,988		4.0%
$250.0 million of 6.40% Notes due 2037	248,998		249,003		6.4%
$250.0 million of 4.20% Notes due 2042	248,377		248,384		4.2%
$550.0 million of 5.15% Notes due 2043	298,684		556,395		5.2%
Total debt	$	2,685,287	$	2,941,276	5.2%


(1)	Weighted-average interest rate includes 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, 2013 and March 31, 2014 was $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.

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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 November 2018, is $1.0 billion. Borrowings under the facility are unsecured and bear interest at LIBOR plus a spread ranging from 1.0% to 1.75% based on our credit ratings. Additionally, an unused commitment fee is assessed at a rate from 0.10% to 0.28%, depending on our credit ratings. The unused commitment fee was 0.125% at March 31, 2014. Borrowings under this facility may be used for general partnership purposes, including capital expenditures. As of March 31, 2014, there 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.


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 first quarter 2014, we entered into $200.0 million of interest rate swap agreements to hedge against the variability of future interest payments on 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 first quarter of 2014, we settled the associated interest rate swap agreements for a loss of $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 flows.

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, the $11.0 million gain we have recorded to other comprehensive income would be reclassified into earnings.

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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 March 31, 2014, we had commitments under these forward purchase and sale contracts as follows (in millions):



	Notional Value		Barrels
Forward purchase contracts	$	73.4	1.3
Forward sale contracts	$	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 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. Period changes in the fair value of these agreements are recognized currently in earnings as adjustments to cost of product sales.

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

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

As outlined in the table below, our open NYMEX contracts and butane futures agreements at 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 April 2014 and November 2016
NYMEX - Economic Hedges	2.2 million barrels of refined products and crude oil	Between April 2014 and January 2015
Butane Futures Agreements - Economic Hedges	0.1 million barrels of butane	Between April 2014 and January 2015

Energy Commodity Derivatives Contracts and Deposits Offsets

At March 31, 2014, we had made margin deposits of $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, 2013 and March 31, 2014 (in thousands):



	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⁽¹⁾			Margin Deposit Amounts Not Offset in the Consolidated Balance Sheet		Net Asset Amount
Energy commodity derivatives	$	(7,167	)	$	2,665	$	(4,502	)	$	14,782	$	10,280



	March 31, 2014
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⁽²⁾			Margin Deposit Amounts Not Offset in the Consolidated Balance Sheet		Net Asset Amount
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 AOCL for the three months ended March 31, 2013 and 2014 were as follows (in thousands):



	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 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 inventories. Because there was no ineffectiveness recognized on these hedges, the cumulative losses of $9.6 million from the agreements as of March 31, 2014 were fully offset by a cumulative increase of $9.6 million to tank bottom inventory and a cumulative 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 months ended March 31, 2013 and 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

There was no ineffectiveness recognized on the financial instruments disclosed in the above tables during the three months ended March 31, 2013 or 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 months ended March 31, 2013 and 2014 of derivatives accounted for under ASC 815; Derivatives and Hedging—Overall, that were not designated as hedging instruments (in thousands):



		Amount of Gain (Loss) Recognized on Derivative
		Three Months Ended
Derivative Instrument	Location of Gain (Loss) Recognized on Derivative	March 31, 2013			March 31, 2014
NYMEX commodity contracts	Product sales revenue	$	(1,761	)	$	2,823
NYMEX commodity contracts	Operating expenses	(1,886		)	365
Butane futures agreements	Cost of product sales	(781		)	144
	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

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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 not 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

7,021

Butane futures agreements

Energy commodity derivatives contracts, net

382

Energy commodity derivatives contracts, net

—

Total

430

Total

7,021

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

3,217

Butane futures agreements

Energy commodity derivatives contracts, net

Total

3,269


9.	Commitments and Contingencies

Environmental Liabilities

Liabilities recognized for estimated environmental costs were $38.5 million and $37.1 million at December 31, 2013 and 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 months ended March 31, 2013 and 2014 were $0.7 million and $0.3 million, respectively.

Environmental Receivables

Receivables from insurance carriers and other third parties related to environmental matters at December 31, 2013 were $4.8 million, of which $2.1 million and $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 March 31, 2014 were $4.7 million, of which $2.1 million and $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. The estimated units available under the LTIP at 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
	March 31, 2013
	Equity Method		Liability Method		Total
Performance/market-based awards:
2010 awards	$	121	$	73	$	194
2011 awards	983		1,147		2,130
2012 awards	881		611		1,492
2013 awards	726		189		915
Retention awards	125		—		125
Total	$	2,836	$	2,020	$	4,856

Allocation of LTIP expense on our consolidated statements of income:
G&A expense					$	4,485
Operating expense					371
Total					$	4,856

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Three Months Ended
	March 31, 2014
	Equity Method		Liability Method		Total
Performance/market-based awards:
2012 awards	1,022		924		1,946
2013 awards	1,181		548		1,729
2014 awards	904		—		904
Retention awards	509		—		509
Total	$	3,616	$	1,472	$	5,088

Allocation of LTIP expense on our consolidated statements of income:
G&A expense					$	4,974
Operating expense					114
Total					$	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 2013 and 2014 were as follows (in thousands, except per unit amounts):



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 April 24, 2014 to be paid on May 15, 2014 to unitholders of record at the close of business on 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.


•	Long-term receivables. These include lease payments receivable under a direct-financing leasing arrangement and insurance receivables. Fair value was determined by estimating the present value of future cash flows using current market rates.

•

Debt. The fair value of our publicly traded notes was based on the prices of those notes at December 31, 2013 and 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, 2013 and March 31, 2014, based on the three levels established by ASC 820; Fair Value Measurements and 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 (in thousands).

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	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	)	$	—



	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 March 31, 2013 and 2014, we made purchases of butane from subsidiaries of Targa of $14.2 million and $12.2 million, respectively. These purchases were made on the same terms as comparable third-party transactions. There were no amounts payable to Targa at December 31, 2013 or 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 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.

In April 2014, our general partner's board of directors declared a quarterly distribution of $0.6125 per unit to be paid on May 15, 2014 to unitholders of record at the close of business on May 8, 2014. The total cash distributions expected to be paid are $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 March 31, 2014, our asset portfolio including the assets of our joint ventures consisted of:


•	our refined products segment, including our 9,500-mile refined products pipeline system with 54 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 1,100 miles of crude oil pipelines and storage facilities with an aggregate storage capacity of approximately 18 million 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 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, 2013.

Recent Developments

Condensate Splitter. 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 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.

Little Rock Pipeline. In May 2014, we 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 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 of up to $1.0 billion. Borrowings under the program are backed by and may not exceed 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.

Cash Distribution. In April 2014, the board of directors of our general partner declared a quarterly cash distribution of $0.6125 per unit for the period of January 1, 2014 through March 31, 2014. This quarterly cash distribution will be paid on May 15, 2014 to unitholders of record on May 8, 2014. Total distributions expected to be paid under this declaration are approximately $139.1 million.

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Results of Operations

We believe that investors benefit from having access to the same financial measures utilized by management. Operating margin, which is presented in the following table, is an important measure used by management to evaluate the economic performance of our core operations. Operating margin is not a generally accepted accounting principles (“GAAP”) measure, but the components of operating margin are computed using amounts that are determined in accordance with GAAP. A reconciliation of operating margin to operating profit, which is its nearest comparable GAAP financial measure, is included in the following table. Operating profit includes expense items, such as depreciation and amortization expense and general and administrative (“G&A”) 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 this table. Product margin is a non-GAAP measure; however, its components of product sales and cost of product 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 sales, better represents its importance to our results of operations.

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Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2014



	Three Months Ended March 31,						Variance Favorable (Unfavorable)
	2013			2014			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)
Transportation and terminals revenue:
Refined products	$	165.4		$	210.2		$	44.8		27
Crude oil	23.2			67.9			44.7			193
Marine storage	38.7			39.5			0.8			2
Total transportation and terminals revenue	227.3			317.6			90.3			40
Affiliate management fee revenue	3.4			4.9			1.5			44
Operating expenses:
Refined products	46.3			51.2			(4.9		)	(11)
Crude oil	5.1			9.1			(4.0		)	(78)
Marine storage	14.6			14.1			0.5			3
Intersegment eliminations	(0.8		)	(0.8		)	—			—
Total operating expenses	65.2			73.6			(8.4		)	(13)
Product margin:
Product sales revenue	201.7			296.1			94.4			47
Cost of product sales	160.4			198.0			(37.6		)	(23)
Product margin⁽¹⁾	41.3			98.1			56.8			138
Earnings of non-controlled entities	2.1			0.5			(1.6		)	(76)
Operating margin	208.9			347.5			138.6			66
Depreciation and amortization expense	36.3			37.5			(1.2		)	(3)
G&A expense	30.1			34.9			(4.8		)	(16)
Operating profit	142.5			275.1			132.6			93
Interest expense (net of interest income and interest capitalized)	28.3			30.7			(2.4		)	(8)
Debt placement fee amortization expense	0.5			0.6			(0.1		)	(20)
Income before provision for income taxes	113.7			243.8			130.1			114
Provision for income taxes	0.7			1.2			(0.5		)	(71)
Net income	$	113.0		$	242.6		$	129.6		115
Operating Statistics:
Refined products:
Transportation revenue per barrel shipped	$	1.136		$	1.356
Volume shipped (million barrels):
Gasoline	53.6			59.8
Distillates	33.8			37.5
Aviation fuel	4.5			5.0
Liquefied petroleum gases	1.1			1.5
Total volume shipped	93.0			103.8
Crude oil:
Transportation revenue per barrel shipped	$	0.313		$	1.113
Volume shipped (million barrels)	15.9			41.8
Crude oil terminal average utilization (million barrels per month)	12.8			12.1
Marine storage:
Marine terminal average utilization (million barrels per month)	22.7			22.7

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

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Transportation and terminals revenue increased $90.3 million resulting from:

•

an increase in refined products revenue of $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 a 3% increase in transportation volumes and higher rates. Shipments were higher primarily due to increased demand for gasoline and distillates. The average rate per barrel was impacted by the mid-year 2013 tariff rate increase and more long-haul shipments (which are at a higher rate);


•	an increase in crude oil revenue of $44.7 million primarily due to crude oil deliveries from our Longhorn pipeline, which represented approximately 85% of the increase. Our Longhorn pipeline began delivering crude oil in mid-April 2013 and averaged approximately 200,000 barrels per day during first quarter 2014; and


•	an increase in marine storage revenue of $0.8 million primarily due to new storage placed into service at our Galena Park, Texas terminal since early 2013.

Affiliate management fee revenue increased $1.5 million due to higher construction management fees related to BridgeTex Pipeline Company, LLC ("BridgeTex"). The construction management fees we receive are designed to reimburse us for our costs of providing services to BridgeTex during its construction.

Operating expenses increased by $8.4 million resulting from:


•	an increase in refined products expenses of $4.9 million primarily due to $4.3 million of expenses related to the pipeline systems we acquired in the second half of 2013. Otherwise, higher property taxes, power expenses and personnel costs related to our other pipeline segments were primarily offset by higher product overages (which reduce operating expenses);


•	an increase in crude oil expenses of $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 fees to access product from third-party origination sources, partially offset by more favorable product overages (which reduce operating expenses); and


•	a decrease in marine storage expenses of $0.5 million primarily due to lower asset integrity costs 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. 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. 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 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 decreased $1.6 million primarily due to lower weighted-average tariffs and higher depreciation costs.

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

G&A expense increased $4.8 million primarily due to higher compensation costs resulting from an increase in employee headcount and the timing of recognizing our employee bonus accrual, higher equity-based compensation

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costs due to a higher price for our limited partner 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%.

Distributable Cash Flow

Distributable cash flow ("DCF") and adjusted EBITDA are non-GAAP measures. Management uses 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. 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 three months ended March 31, 2013 and 2014 to net income, which is its nearest comparable GAAP financial measure, follows (in millions):



	Three Months Ended March 31,						Increase
	2013			2014			(Decrease)
Net income	$	113.0		$	242.6		$	129.6
Interest expense, net	28.3			30.7			2.4
Depreciation and amortization⁽¹⁾	36.9			38.1			1.2
Equity-based incentive compensation expense⁽²⁾	(7.4		)	(9.7		)	(2.3		)
Asset retirements and impairments	1.8			1.2			(0.6		)
Commodity-related adjustments:
Derivative (gains) losses recognized in the period associated with future product transactions⁽³⁾	2.3			(0.1		)	(2.4		)
Derivative gains (losses) recognized in previous periods associated with products sold in the period⁽⁴⁾	(5.2		)	(5.3		)	(0.1		)
Lower-of-cost-or-market adjustments	(2.0		)	—			2.0
Total commodity-related adjustments	(4.9		)	(5.4		)	(0.5		)
Other	(1.4		)	0.4			1.8
Adjusted EBITDA	166.3			297.9			131.6
Interest expense, net	(28.3		)	(30.7		)	(2.4		)
Maintenance capital⁽⁵⁾	(14.1		)	(14.0		)	0.1
DCF	$	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 to net income to calculate DCF. Total equity-based incentive compensation expense for the three months ended March 31, 2013 and 2014 was $4.9 million and $5.1 million, respectively. However, the figures above include an adjustment for minimum statutory tax withholdings we paid in 2013 and 2014 of $12.3 million and $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 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)	Maintenance capital expenditure projects are not undertaken primarily to generate incremental DCF (i.e. incremental returns to our unitholders), while expansion capital projects are undertaken primarily to generate incremental DCF. For this reason, we deduct maintenance capital expenditures to determine DCF.

Current period DCF increased $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 each period on economic hedges that do not qualify for hedge accounting treatment.

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



	Three Months Ended
	March 31
	2013		2014
Distributable cash flow	$	123.9	$	253.2
Less: Cash reserves approved by our general partner	10.6		120.4
Total cash distributions paid	$	113.3	$	132.8

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

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


•	a $129.6 million increase in net income; and


•	a $31.8 million increase resulting from a $15.0 million decrease in trade accounts receivable and other accounts receivable in 2014 versus a $16.8 million increase during 2013, primarily due to timing of payments from our customers.

These increases were partially offset by:


•	a $39.7 million decrease resulting from a $23.0 million increase in inventory in 2014 versus a $16.7 million decrease in inventory in 2013 principally due to increased inventories from product overages on our pipeline system; and


•	a $26.3 million decrease resulting from a $20.0 million decrease in accrued product purchases in 2014 versus a $6.3 million increase in accrued product purchases in 2013, primarily due to the timing of invoices paid to vendors and suppliers.

Net cash used by investing activities for the three months ended March 31, 2013 and 2014 was $148.6 million and $202.5 million, respectively. During 2014, we spent $70.3 million for capital expenditures, which included $14.0 million for maintenance capital and $56.3 million for expansion capital. Also during 2014, we contributed capital of $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.

Net cash provided (used) by financing activities for the three months ended March 31, 2013 and 2014 was $(125.6) million and $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 three months of 2013, we paid cash distributions of $113.3 million to our 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.

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

Capital Requirements

Our businesses require continual 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 three months ended March 31, 2014, our maintenance capital spending was $14.0 million. For 2014, we expect to spend approximately $77.0 million on maintenance capital.

In addition to maintenance capital expenditures, we also incur expansion capital expenditures at our existing facilities and to acquire new assets. During the first three months of 2014, we spent $56.3 million for organic growth capital and $127.7 million for capital projects in conjunction with our joint ventures. Based on the progress of expansion projects already underway, including the expansion of our Longhorn crude oil pipeline, construction of a condensate splitter at Corpus Christi and our investment in the BridgeTex pipeline, we expect to spend approximately $700.0 million for expansion capital during 2014, with an additional $325.0 million in 2015 and $75.0 million in 2016 to complete our current projects.

Liquidity

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

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	December 31, 2013		March 31, 2014		Weighted-Average Interest Rate for Three Months Ending March 31, 2014 ⁽¹⁾
Revolving credit facility	$	—	$	—	—%
$250.0 of 6.45% Notes due 2014	250.0		250.0		6.3%
$250.0 of 5.65% Notes due 2016	251.2		251.1		5.7%
$250.0 of 6.40% Notes due 2018	259.3		258.8		5.4%
$550.0 of 6.55% Notes due 2019	571.5		570.6		5.7%
$550.0 of 4.25% Notes due 2021	557.2		557.0		4.0%
$250.0 of 6.40% Notes due 2037	249.0		249.0		6.4%
$250.0 of 4.20% Notes due 2042	248.4		248.4		4.2%
$550.0 of 5.15% Notes due 2043	298.7		556.4		5.2%
Total debt	$	2,685.3	$	2,941.3	5.2%


(1)	Weighted-average interest rate includes 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, 2013 and March 31, 2014 was $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 sheets as of December 31, 2013 and March 31, 2014. We anticipate using cash on hand and borrowings against our commercial paper program (see Commercial Paper Program below) to repay this debt when it matures.

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 first quarter 2014, we entered into $200.0 million of interest rate swap agreements to hedge against the variability of future interest payments on 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 first quarter of 2014, we settled the associated interest rate swap agreements for a loss of $3.6 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 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 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.

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 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 April 2014 and November 2016. Through March 31, 2014, the cumulative amount of losses from these agreements was $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 1.6 million barrels of refined products related to our butane blending and fractionation activities. These contracts mature between April 2014 and January 2015 and are being accounted for as economic hedges. Through March 31, 2014, the cumulative amount of net unrealized losses associated with these agreements was $2.7 million. We recorded these losses as an adjustment to product sales revenue, of which $2.9 million of net losses was recognized in 2013 and $0.2 million of net gains was recognized in 2014.

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•

NYMEX contracts covering 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 April 2014, are being accounted for as economic hedges. Through March 31, 2014, the cumulative amount of net unrealized losses associated with these agreements was $0.5 million. We recorded these losses as an adjustment to operating expenses, all of which was recognized in 2014.

•

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

Settled Derivative Contracts


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


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


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



	Three Months Ended March 31, 2013
	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	$	(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	(1.7		)	(0.1		)	(1.2		)	(3.0		)
Net impact of NYMEX contracts	$	(6.2	)	$	(0.8	)	$	(1.9	)	$	(8.9	)

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	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 March 31, 2013 and 2014, we made purchases of butane from subsidiaries of Targa of $14.2 million and $12.2 million, respectively. These purchases were made on the same terms as comparable third-party transactions. There were no amounts payable to Targa at December 31, 2013 or March 31, 2014, respectively.

We own a 50% interest in 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.

We own a 50% interest in Double Eagle which 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 throughput revenue from Double Eagle that is included in our transportation and terminals revenue on our consolidated statements of income. For the three months ended March 31, 2014, we received throughput revenue of $0.5 million and we recorded a $0.2 million and $0.3 million trade accounts receivable from Double Eagle at 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 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.

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

There were no significant accounting pronouncements issued during 2014 that had or will have a material impact on our consolidated 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 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 March 31, 2014, we had commitments under forward purchase and sale contracts used in our butane blending and fractionation activities as follows (in millions):



	Notional Value		Barrels
Forward purchase contracts	$	73.4	1.3
Forward sale contracts	$	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 March 31, 2014, we had open NYMEX contracts representing 2.9 million barrels of petroleum products we expect to sell in the future. Additionally, we had open butane futures agreements for 0.1 million barrels of butane we expect to purchase in the future.

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

At March 31, 2014, open NYMEX contracts representing 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 $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 $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 March 31, 2014, we had no variable rate debt outstanding, including on our revolving credit facility. Our revolving credit facility has total borrowing capacity of $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 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, 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 and Chief Financial Officer concluded that these disclosure controls and practices are effective in providing reasonable assurance that all required disclosures are included in the current report. Additionally, these disclosure controls and practices are effective in ensuring that information required to be disclosed is accumulated and communicated to our Chief Executive Officer and Chief Financial Officer to allow timely decisions regarding required disclosures. There has been no change in our internal control over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act) during the quarter ended March 31, 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, 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;


•	not being adequately 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;


•	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, affecting hydraulic 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"). 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 and seeks recovery for such damages. We acquired the pipeline from ARCO Pipeline ("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. In March 2014, the U.S. District Court denied plaintiff's motion for Class Certification. While the results of 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. While 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 $0.15 million for potential monetary sanctions related to this matter. While 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. While 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 ("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 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.

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, 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.


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 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 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 May 6, 2014.



MAGELLAN MIDSTREAM PARTNERS, L.P.

By:		Magellan GP, LLC,
		its general partner

/s/ Michael P. Osborne
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 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 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.