Magellan Midstream Partners, L.P. - Quarter Report: 2015 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________

FORM 10-Q



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

For the quarterly period ended March 31, 2015



£	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 4, 2015, there were 227,426,329 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	7
	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	19
	10.	Long-Term Incentive Plan	19
	11.	Distributions	21
	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		35
ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	35
ITEM 4.		CONTROLS AND PROCEDURES	37
Forward-Looking Statements			38
PART II OTHER INFORMATION
ITEM 1.		LEGAL PROCEEDINGS	40
ITEM 1A.		RISK FACTORS	40
ITEM 2.		UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	40
ITEM 3.		DEFAULTS UPON SENIOR SECURITIES	41
ITEM 4.		MINE SAFETY DISCLOSURES	41
ITEM 5.		OTHER INFORMATION	41
ITEM 6.		EXHIBITS	42

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,
	2014			2015
Transportation and terminals revenue	$	317,637		$	345,600
Product sales revenue	296,063			173,127
Affiliate management fee revenue	4,906			3,363
Total revenue	618,606			522,090
Costs and expenses:
Operating	73,497			98,495
Cost of product sales	198,040			136,179
Depreciation and amortization	37,511			41,697
General and administrative	34,935			35,498
Total costs and expenses	343,983			311,869
Earnings of non-controlled entities	466			9,590
Operating profit	275,089			219,811
Interest expense	36,416			36,607
Interest income	(391		)	(349		)
Interest capitalized	(5,310		)	(2,107		)
Debt placement fee amortization expense	599			587
Other expense	—			279
Income before provision for income taxes	243,775			184,794
Provision for income taxes	1,221			1,158
Net income	$	242,554		$	183,636
Basic and diluted net income per limited partner unit	$	1.07		$	0.81
Weighted average number of limited partner units outstanding used for basic and diluted net income per unit calculation	227,141			227,525

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,
	2014			2015
Net income	$	242,554		$	183,636
Other comprehensive income:
Derivative activity:
Net loss on cash flow hedges⁽¹⁾	(3,613		)	(15,465		)
Reclassification of net loss (gain) on cash flow hedges to income⁽¹⁾	(26		)	200
Changes in employee benefit plan assets and benefit obligations recognized in other comprehensive income:
Amortization of prior service credit⁽²⁾	(895		)	(928		)
Amortization of actuarial loss⁽²⁾	824			1,572
Total other comprehensive loss	(3,710		)	(14,621		)
Comprehensive income	$	238,844		$	169,015

(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) See Note 6–Employee Benefit Plans for details of the changes in employee benefit plan assets and benefit obligations recognized in AOCL.

See notes to consolidated financial statements.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands)



	December 31, 2014			March 31, 2015
ASSETS				(Unaudited)
Current assets:
Cash and cash equivalents	$	17,063		$	52,813
Trade accounts receivable (less allowance for doubtful accounts of $0 and $20 at December 31, 2014 and March 31, 2015, respectively)	84,465			96,700
Other accounts receivable	15,711			15,744
Inventory	157,762			160,949
Energy commodity derivatives contracts, net	87,151			36,725
Energy commodity derivatives deposits	6,184			1,100
Other current assets	34,331			31,619
Total current assets	402,667			395,650
Property, plant and equipment	5,533,935			5,642,904
Less: Accumulated depreciation	1,204,601			1,243,310
Net property, plant and equipment	4,329,334			4,399,594
Investments in non-controlled entities	613,867			636,618
Long-term receivables	28,611			27,116
Goodwill	53,260			53,260
Other intangibles (less accumulated amortization of $11,526 and $12,206 at December 31, 2014 and March 31, 2015, respectively)	4,573			3,893
Debt placement costs (less accumulated amortization of $8,952 and $9,539 at December 31, 2014 and March 31, 2015, respectively)	18,084			22,158
Tank bottoms and linefill	42,585			38,361
Other noncurrent assets	24,304			28,467
Total assets	$	5,517,285		$	5,605,117
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable	$	97,131		$	91,022
Accrued payroll and benefits	48,298			31,719
Accrued interest payable	45,973			45,800
Accrued taxes other than income	47,888			42,087
Environmental liabilities	10,564			11,926
Deferred revenue	71,142			75,920
Accrued product purchases	44,355			37,953
Energy commodity derivatives contracts, net	5,413			814
Energy commodity derivatives deposits	84,463			31,512
Other current liabilities	80,928			50,134
Total current liabilities	536,155			418,887
Long-term debt	2,982,895			3,183,750
Long-term pension and benefits	75,155			80,741
Other noncurrent liabilities	29,069			23,427
Environmental liabilities	25,778			24,431
Commitments and contingencies
Partners’ capital:
Limited partner unitholders (227,068 units and 227,426 units outstanding at December 31, 2014 and March 31, 2015, respectively)	1,949,773			1,970,042
Accumulated other comprehensive loss	(81,540		)	(96,161		)
Total partners’ capital	1,868,233			1,873,881
Total liabilities and partners' capital	$	5,517,285		$	5,605,117

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,
	2014			2015
Operating Activities:
Net income	$	242,554		$	183,636
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	37,511			41,697
Debt placement fee amortization expense	599			587
Loss on sale and retirement of assets	1,205			(3		)
Earnings of non-controlled entities	(466		)	(9,590		)
Distributions from investments in non-controlled entities	384			9,229
Equity-based incentive compensation expense	5,088			4,751
Amortization of prior service credit and actuarial loss	(71		)	644
Changes in operating assets and liabilities:
Trade accounts receivable and other accounts receivable	15,022			(12,194		)
Inventory	(23,011		)	(3,187		)
Energy commodity derivatives contracts, net of derivatives deposits	(529		)	(5,804		)
Accounts payable	2,960			(4,351		)
Accrued payroll and benefits	(14,552		)	(16,579		)
Accrued interest payable	5,194			(173		)
Accrued taxes other than income	(7,479		)	(5,801		)
Accrued product purchases	(19,978		)	(6,402		)
Deferred revenue	1,448			4,778
Current and noncurrent environmental liabilities	(1,393		)	15
Other current and noncurrent assets and liabilities	25,588			9,830
Net cash provided by operating activities	270,074			191,083
Investing Activities:
Additions to property, plant and equipment, net⁽¹⁾	(75,514		)	(128,517		)
Proceeds from sale and disposition of assets	42			3,089
Investments in non-controlled entities	(127,698		)	(13,751		)
Distributions in excess of earnings of non-controlled entities	687			4,613
Net cash used by investing activities	(202,483		)	(134,566		)
Financing Activities:
Distributions paid	(132,835		)	(158,061		)
Net commercial paper repayments	—			(296,942		)
Borrowings under long-term notes	257,713			499,589
Debt placement costs	(2,648		)	(4,661		)
Net payment on financial derivatives	(3,613		)	(42,908		)
Settlement of tax withholdings on long-term incentive compensation	(14,813		)	(17,784		)
Net cash provided (used) by financing activities	103,804			(20,767		)
Change in cash and cash equivalents	171,395			35,750
Cash and cash equivalents at beginning of period	25,235			17,063
Cash and cash equivalents at end of period	$	196,630		$	52,813

Supplemental non-cash investing and financing activities:
Contribution of property, plant and equipment to a non-controlled entity	$	—		$	13,252
Issuance of limited partner units in settlement of equity-based incentive plan awards	$	7,315		$	8,045

⁽¹⁾ Additions to property, plant and equipment	$	(70,295	)	$	(127,709	)
Changes in accounts payable and other current liabilities related to capital expenditures	(5,219		)	(808		)
Additions to property, plant and equipment, net	$	(75,514	)	$	(128,517	)

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, 2015, our asset portfolio, including the assets of our joint ventures, consisted of:


•	our refined products segment, comprised of our 9,500-mile refined products pipeline system with 52 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 1,600 miles of crude oil pipelines and storage facilities with an aggregate storage capacity of approximately 21 million barrels, of which 12 million barrels are 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 26 million barrels.

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


•	refined products 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 are produced as by-products of the crude oil refining process and in connection with natural gas production. LPGs include butane and propane;


•	blendstocks 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 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 are used as feedstocks by refineries and petrochemical facilities;


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


•	ammonia 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, 2014 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, 2015, the results of operations for the three months ended March 31, 2014 and 2015 and cash flows for the three months ended March 31, 2014 and 2015. The results of operations for the three months ended March 31, 2015 are not necessarily indicative of the results to be expected for the full year ending December 31, 2015 as profits from our blending activities are realized largely during the first and fourth quarters of each year. Additionally, gasoline demand, which drives transportation volumes and revenues on our pipeline systems, generally trends higher during the summer driving months. Further, the volatility of commodity prices impact the profits from our commodity activities and, to a lesser extent, the volume of petroleum products we ship on our pipelines.

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, 2014.


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. See Note 8 – Derivative Financial Instruments for a discussion of our commodity hedging strategies and how our NYMEX contracts impact product sales revenues.

For the three months ended March 31, 2014 and 2015, product sales revenue included the following (in thousands):



	Three Months Ended
	March 31,
	2014		2015
Physical sale of petroleum products	$	293,240	$	169,247
NYMEX contract adjustments:
Change in value of NYMEX contracts that were not designated as hedging instruments associated with our butane blending and fractionation activities⁽¹⁾	2,823		3,880
Total product sales revenue	$	296,063	$	173,127

(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.


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.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, 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



	Three Months Ended March 31, 2015
	(in thousands)
	Refined Products		Crude Oil			Marine Storage			Intersegment Eliminations			Total
Transportation and terminals revenue	$	216,777	$	86,560		$	42,263		$	—		$	345,600
Product sales revenue	172,639		—			488			—			173,127
Affiliate management fee revenue	—		3,027			336			—			3,363
Total revenue	389,416		89,587			43,087			—			522,090
Operating expenses	70,306		13,861			15,335			(1,007		)	98,495
Cost of product sales	135,634		—			545			—			136,179
Losses (earnings) of non-controlled entities	55		(8,924		)	(721		)	—			(9,590		)
Operating margin	183,421		84,650			27,928			1,007			297,006
Depreciation and amortization expense	23,447		8,229			9,014			1,007			41,697
G&A expenses	22,599		8,086			4,813			—			35,498
Operating profit	$	137,375	$	68,335		$	14,101		$	—		$	219,811

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


4.	Investments in Non-Controlled Entities

Recently-Formed Companies

Saddlehorn Pipeline Company, LLC ("Saddlehorn"), which was formed during first quarter 2015, will own an approximate 550-mile pipeline to deliver various grades of crude oil from the DJ Basin, and potentially the broader Rocky Mountain production area, to Cushing, Oklahoma. We have a 40% equity ownership interest in Saddlehorn, with Plains All American Pipeline, L.P. and Anadarko Petroleum Corporation having 40% and 20% equity ownership interests, respectively. We will serve as construction manager and operator of the Saddlehorn system. Subject to receipt of necessary permits and regulatory approvals, the Saddlehorn pipeline is expected to be operational during mid-2016.

Powder Springs Logistics, LLC ("Powder Springs") was recently formed to construct and develop a butane blending system, including 120,000 barrels of butane storage, near Atlanta, Georgia. We have a 50% equity ownership interest in Powder Springs, with an affiliate of Colonial Pipeline Company having the other 50% equity ownership interest. We will serve as construction manager and operator of the Powder Springs facility. This facility is expected to be operational in early 2017.

Our investments in non-controlled entities at March 31, 2015 are comprised of:



Entity		Ownership Interest
BridgeTex Pipeline Company, LLC ("BridgeTex")		50%
Double Eagle Pipeline LLC ("Double Eagle")		50%
Osage Pipe Line Company, LLC ("Osage")		50%
Powder Springs Logistics, LLC		50%
Saddlehorn Pipeline Company, LLC		40%
Texas Frontera, LLC ("Texas Frontera")		50%

The management fees we receive from Texas Frontera, Powder Springs, Saddlehorn and BridgeTex are reported as affiliate management fee revenue on our consolidated statements of income. For the three months ended March 31, 2014 and 2015, we received throughput revenue from Double Eagle of $0.5 million and $0.9 million, respectively, which we recognized as transportation and terminals revenue. At December 31, 2014, we recognized a $0.3 million trade accounts receivable from Double Eagle and at December 31, 2014 and March 31, 2015, we had recognized liabilities of $2.2 million and $1.5 million, respectively, to BridgeTex for pre-paid construction management fees.

In November 2014, we entered into a long-term agreement with BridgeTex for capacity on our Houston area crude oil distribution system. We recognized $8.4 million of revenue from this agreement in first quarter 2015, which we included in transportation and terminals revenue on our consolidated statements of income. We recognized a $2.6 million receivable from BridgeTex at December 31, 2014 associated with this agreement.

The financial results from Texas Frontera are included in our marine storage segment, the financial results from Osage, Double Eagle, BridgeTex and Saddlehorn are included in our crude oil segment and the financial results from Powder Springs are included in our refined products segment as earnings/losses of non-controlled entities.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

A summary of our investments in non-controlled entities follows (in thousands):



	BridgeTex			All Others			Consolidated
Investments at December 31, 2014	$	489,348		$	124,519		$	613,867
Additional investment	7,358			19,645			27,003
Earnings of non-controlled entities:
Proportionate share of earnings	9,019			1,269			10,288
Amortization of excess investment and capitalized interest	(510		)	(188		)	(698		)
Earnings of non-controlled entities	8,509			1,081			9,590
Less:
Distributions of earnings from investments in non-controlled entities	8,509			720			9,229
Distributions in excess of earnings of non-controlled entities	4,565			48			4,613
Investments at March 31, 2015	$	492,141		$	144,477		$	636,618

Summarized financial information of our non-controlled entities as of and for the three months ended March 31, 2015 follows (in thousands):



	BridgeTex		All Others		Consolidated
Current assets	$	50,901	$	21,535	$	72,436
Noncurrent assets	822,132		252,542		1,074,674
Total assets	$	873,033	$	274,077	$	1,147,110
Current liabilities	$	49,618	$	11,019	$	60,637
Noncurrent liabilities	236		1,785		2,021
Total liabilities	$	49,854	$	12,804	$	62,658
Equity	$	823,179	$	261,273	$	1,084,452

Revenue	$	37,136	$	9,520	$	46,656
Net income	$	18,037	$	2,581	$	20,618

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


5.	Inventory

Inventory at December 31, 2014 and March 31, 2015 was as follows (in thousands):



	December 31, 2014		March 31, 2015
Refined products	$	67,055	$	68,279
Liquefied petroleum gases	37,642		38,772
Transmix	36,867		33,721
Crude oil	10,015		14,068
Additives	6,183		6,109
Total inventory	$	157,762	$	160,949


6.	Employee Benefit Plans

We sponsor two pension plans for certain union employees and a pension plan primarily for non-union 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, 2014 and 2015 (in thousands):



	Three Months Ended						Three Months Ended
	March 31, 2014						March 31, 2015
	Pension Benefits			Other Post- Retirement Benefits			Pension Benefits			Other Post- Retirement Benefits
Components of net periodic benefit costs:
Service cost	$	3,352		$	67		$	4,470		$	66
Interest cost	1,659			114			1,869			110
Expected return on plan assets	(1,697		)	—			(1,896		)	—
Amortization of prior service cost (credit)	33			(928		)	—			(928		)
Amortization of actuarial loss	629			195			1,347			225
Net periodic benefit cost (credit)	$	3,976		$	(552	)	$	5,790		$	(527	)

Contributions estimated to be paid into the plans in 2015 are $21.1 million and $1.1 million for the pension and postretirement benefit plans, respectively.

We match our employee's qualifying contributions to our defined contribution plan, resulting in expense to us. Expenses related to the defined contribution plan were $2.6 million and $2.8 million for the three months ended March 31, 2014 and 2015, respectively.

Amounts Included in AOCL

The changes in AOCL related to employee benefit plan assets and benefit obligations for the three months ended March 31, 2014 and 2015 were as follows:

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Three Months Ended						Three Months Ended
	March 31, 2014						March 31, 2015
Gains (Losses) Included in AOCL	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Beginning balance	$	(36,184	)	$	3,053		$	(63,257	)	$	(1,696	)
Amortization of prior service credit	33			(928		)	—			(928		)
Amortization of actuarial loss	629			195			1,347			225
Ending balance	$	(35,522	)	$	2,320		$	(61,910	)	$	(2,399	)


7.	Debt

Consolidated debt at December 31, 2014 and March 31, 2015 was as follows (in thousands, except as otherwise noted):



	December 31, 2014		March 31, 2015		Weighted-Average Interest Rate for the Three Months Ended March 31, 2015 ⁽¹⁾
Commercial paper⁽²⁾	$	296,942	$	—	0.5%
$250.0 million of 5.65% Notes due 2016	250,758		250,652		5.7%
$250.0 million of 6.40% Notes due 2018	257,280		256,764		5.4%
$550.0 million of 6.55% Notes due 2019	567,868		566,939		5.7%
$550.0 million of 4.25% Notes due 2021	556,304		556,071		4.0%
$250.0 million of 3.20% Notes due 2025⁽²⁾	—		249,680		3.2%
$250.0 million of 6.40% Notes due 2037	249,017		249,021		6.4%
$250.0 million of 4.20% Notes due 2042	248,406		248,414		4.2%
$550.0 million of 5.15% Notes due 2043	556,320		556,296		5.1%
$250.0 million of 4.20% Notes due 2045⁽²⁾	—		249,913		4.6%
Total debt	$	2,982,895	$	3,183,750	4.7%


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


(2)	These borrowings were outstanding for only a portion of the three month period ending March 31, 2015. The weighted-average interest rate for these borrowings was calculated based on the number of days the borrowings were outstanding during the noted period.

All of the instruments detailed in the table above are senior indebtedness.

The face value of our debt at December 31, 2014 and March 31, 2015 was $2.9 billion and $3.2 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.

2015 Debt Offerings

In March 2015, we issued $250.0 million of our 3.20% notes due 2025 in an underwritten public offering. The notes were issued at 99.871% of par. Net proceeds from this offering were approximately $247.6 million, after underwriting discounts and offering expenses of $2.1 million.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Also in March 2015, we issued $250.0 million of our 4.20% notes due 2045 in an underwritten public offering. The notes were issued at 99.965% of par. Net proceeds from this offering were approximately $247.3 million, after underwriting discounts and offering expenses of $2.6 million.

The net proceeds from these offerings were used to repay borrowings outstanding under our commercial paper program 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 outstanding under the facility are classified as long-term debt on our consolidated balance sheets. 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, 2015. Borrowings under this facility may be used for general partnership purposes, including capital expenditures. As of March 31, 2015, 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.

Commercial Paper Program. The maturities of our commercial paper notes vary, but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. The commercial paper we can issue is limited by the amounts available under our revolving credit facility up to an aggregate principal amount of $1.0 billion and is, therefore, classified as long-term debt. As of March 31, 2015, there were no commercial paper borrowings outstanding.


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 third and fourth quarter of 2014, we entered into $250.0 million of forward-starting interest rate swap agreements to hedge against the risk of variability of future interest payments on a portion of debt we anticipated issuing in 2015. We accounted for these agreements as cash flow hedges. When we issued the $250.0 million of 4.20% notes due 2045 in first quarter 2015, we settled the associated interest rate swap agreements for a loss of $42.9 million. The loss was recorded to other comprehensive income ($26.5 million and $16.4 million recorded in 2014 and 2015, respectively) 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.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

During 2012, we terminated and settled certain interest rate swap agreements and realized a gain of $11.0 million, which was recorded to other comprehensive income as a deferred cash flow hedging gain. The purpose of these swaps was to hedge against the variability of interest payments on an anticipated debt issuance, which was completed during first quarter 2015. The effective portion of this gain in the amount of $10.6 million at March 31, 2015 will be recognized into earnings as an adjustment to our periodic interest expense over the life of the $250.0 million of 4.20% notes due 2045 that were issued in first quarter 2015.

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 Chicago Mercantile Exchange ("CME") butane futures agreements to help manage commodity price changes, which is intended to mitigate the risk of decline in the product margin realized from our butane blending activities that we choose to hedge. Further, certain of our other commercial operations generate petroleum products. We use NYMEX contracts to hedge against future price changes for some of these commodities.

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, 2015, we had commitments under these forward purchase and sale contracts as follows (in millions):



	Notional Value		Barrels
Forward purchase contracts	$	72.8	1.8
Forward sale contracts	$	4.5	0.1

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 is 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 is 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 fair value of these agreements are recognized currently in earnings.

During the three months ended March 31, 2014 and 2015, none of the commodity hedging contracts we entered into qualified for or were designated as cash flow hedges.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Period changes in the fair value of NYMEX agreements that are accounted for as economic hedges (other than those economic hedges of our pipeline product overages as discussed below), 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 CME-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.

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 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.

Additionally, we hold crude oil barrels that we use for operational purposes which we classify as long-term assets on our balance sheet and which are reported as tank bottom and linefill assets. We use NYMEX contracts to hedge against changes in the price of these crude oil barrels. We record the effective portion of the gains or losses for those contracts that qualify as fair value hedges as adjustments to the assets being hedged and the ineffective portions as well as amounts excluded from the assessment of hedge effectiveness as adjustments to other income or expense.

As outlined in the table below, our open NYMEX contracts and CME butane futures agreements at March 31, 2015 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 December 2015 and November 2016
NYMEX - Economic Hedges⁽¹⁾	3.2 million barrels of refined products and crude oil	Between April 2015 and January 2016
CME Butane Futures Agreements - Economic Hedges	0.3 million barrels of butane	Between April and December 2015

(1) Of the 3.2 million barrels of products we have economically hedged at March 31, 2015, we had open agreements which swap the pricing on 0.1 million of those barrels from New York harbor to Platts Group 3 or Platts Gulf Coast, which are the geographic locations where these barrels will be sold.

Energy Commodity Derivatives Contracts and Deposits Offsets

At March 31, 2015, we had received margin deposits of $31.5 million for our NYMEX and CME contracts with one of our counterparties, which were recorded as a current liability under energy commodity derivatives deposits on our consolidated balance sheet. Additionally, we made margin deposits of $1.1 million for our CME contracts with a second counterparty, 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 CME butane futures agreements against our margin deposits under a master netting arrangement for each counterparty; however, we have elected to present the combined fair values of our open NYMEX and CME 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 CME 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

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

amounts we could offset under a master netting arrangement are provided below as of December 31, 2014 and March 31, 2015 (in thousands):



	December 31, 2014
Description	Gross Amounts of Recognized Assets		Gross Amounts of Liabilities Offset in the Consolidated Balance Sheet			Net Amounts of Assets Presented in the Consolidated Balance Sheet⁽¹⁾		Margin Deposit Amounts Not Offset in the Consolidated Balance Sheet			Net Asset Amount⁽³⁾
Energy commodity derivatives	$	106,764	$	(10,622	)	$	96,142	$	(78,279	)	$	17,863



	March 31, 2015
Description	Gross Amounts of Recognized Assets		Gross Amounts of Liabilities Offset in the Consolidated Balance Sheet			Net Amounts of Assets Presented in the Consolidated Balance Sheet⁽²⁾		Margin Deposit Amounts Not Offset in the Consolidated Balance Sheet			Net Asset Amount⁽³⁾
Energy commodity derivatives	$	55,770	$	(1,691	)	$	54,079	$	(30,412	)	$	23,667


(1)	Net amount includes energy commodity derivative contracts classified as current assets, net, of $87,151, current liabilities of $5,413 and noncurrent assets of $14,404.


(2)	Net amount includes energy commodity derivative contracts classified as current assets, net, of $36,725, current liabilities of $814 and noncurrent assets of $18,168.


(3)	This represents the maximum amount of loss we would incur if our counterparties failed to perform on their derivative contracts.

Impact of Derivatives on Our Financial Statements

Comprehensive Income

The changes in derivative activity included in AOCL for the three months ended March 31, 2014 and 2015 were as follows (in thousands):



	Three Months Ended March 31,
Derivative Gains (Losses) Included in AOCL	2014			2015
Beginning balance	$	13,627		$	(16,587	)
Net loss on interest rate contract cash flow hedges	(3,613		)	(15,465		)
Reclassification of net loss (gain) on cash flow hedges to income	(26		)	200
Ending balance	$	9,988		$	(31,852	)

The following tables provide a summary of the effect on our consolidated statements of income for the three months ended March 31, 2014 and 2015 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, 2014

Amount of Loss Recognized in AOCL on Derivative

Location of Gain Reclassified from AOCL into Income

Amount of Gain Reclassified from AOCL into Income

Derivative Instrument

Effective Portion

Ineffective Portion

Interest rate contracts

(3,613

)

Interest expense

—

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Three Months Ended March 31, 2015
	Amount of Loss Recognized in AOCL on Derivative				Location of Loss Reclassified from AOCL into Income	Amount of Loss Reclassified from AOCL into Income
Derivative Instrument	Amount of Loss Recognized in AOCL on Derivative				Location of Loss Reclassified from AOCL into Income	Effective Portion				Ineffective Portion
Interest rate contracts		$	(15,465	)	Interest expense		$	(200	)		$	—

As of March 31, 2015, the net loss estimated to be classified to interest expense over the next twelve months from AOCL is approximately $1.5 million.

Income Statement

The following table provides a summary of the effect on our consolidated statements of income for the three months ended March 31, 2014 and 2015 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
	Location of Gain (Loss) Recognized on Derivative	March 31,
Derivative Instrument	Location of Gain (Loss) Recognized on Derivative	2014		2015
NYMEX commodity contracts	Product sales revenue	$	2,823	$	3,880
NYMEX commodity contracts	Operating expenses	365		1,303
CME butane futures agreements	Cost of product sales	144		(1,224		)
	Total	$	3,332	$	3,959

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

During 2014 and 2015, we had open NYMEX contracts on 0.7 million barrels of crude oil that were designated as fair value hedges. Because there was no ineffectiveness recognized on these hedges, the cumulative gains at December 31, 2014 and March 31, 2015 of $13.3 million and $17.5 million, respectively, from the agreements were offset by a cumulative decrease to tank bottoms and linefill. We exclude the differential between the current spot price and forward price from our assessment of hedge effectiveness for these fair value hedges. For the three months ended March 31, 2015, we recognized a loss of $0.3 million for the amounts we excluded from the assessment of effectiveness of these fair value hedges, which we reported as other expense on our consolidated statements of income.

Balance Sheet

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, 2014 and March 31, 2015 (in thousands):

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 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

360

Energy commodity derivatives contracts, net

—

NYMEX commodity contracts

Other noncurrent assets

14,404

Other noncurrent liabilities

—

Interest rate contracts

Other current assets

—

Other current liabilities

26,478

Total

14,764

Total

26,478

March 31, 2015

Asset Derivatives

Liability Derivatives

Derivative Instrument

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

NYMEX commodity contracts

Energy commodity derivatives contracts, net

541

Energy commodity derivatives contracts, net

—

NYMEX commodity contracts

Other noncurrent assets

18,168

Other noncurrent liabilities

—

Interest rate contracts

Other noncurrent assets

965

Other noncurrent liabilities

—

Total

19,674

Total

—

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, 2014 and March 31, 2015 (in thousands):

December 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

92,000

Energy commodity derivatives contracts, net

—

CME butane futures agreements

Energy commodity derivatives contracts, net

—

Energy commodity derivatives contracts, net

10,622

Total

92,000

Total

10,622

March 31, 2015

Asset Derivatives

Liability Derivatives

Derivative Instrument

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

NYMEX commodity contracts

Energy commodity derivatives contracts, net

37,061

Energy commodity derivatives contracts, net

CME butane futures agreements

Energy commodity derivatives contracts, net

—

Energy commodity derivatives contracts, net

1,678

Total

37,061

Total

1,691

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


9.	Commitments and Contingencies

Environmental Liabilities

Liabilities recognized for estimated environmental costs were $36.3 million and $36.4 million at December 31, 2014 and March 31, 2015, 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, 2014 and 2015 were $0.3 million and $1.4 million, respectively.

Environmental Receivables

Receivables from insurance carriers and other third parties related to environmental matters at December 31, 2014 were $5.1 million, of which $1.3 million and $3.8 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, 2015 were $5.0 million, of which $1.2 million and $3.8 million were recorded to other accounts receivable and long-term receivables, respectively, on our consolidated balance sheet.

Other

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, 2015 total 1.0 million. The compensation committee of our general partner’s board of directors administers our LTIP.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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



	Three Months Ended
	March 31, 2014
	Equity Method		Liability Method		Total
Performance-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



	Three Months Ended
	March 31, 2015
	Equity Method		Liability Method		Total
Performance/market-based awards:
2013 awards	$	1,519	$	215	$	1,734
2014 awards	1,623		—		1,623
2015 awards	1,019		—		1,019
Retention awards	375		—		375
Total	$	4,536	$	215	$	4,751

Allocation of LTIP expense on our consolidated statements of income:
G&A expense					$	4,689
Operating expense					62
Total					$	4,751

In February 2015, 166,189 phantom unit awards were issued pursuant to our LTIP. These grants included both performance-based and retention awards and have a three-year vesting period.

In January 2015, we issued 358,072 limited partner units, of which 354,529 were issued to settle unit award grants to certain employees that vested on December 31, 2014 and 3,543 were issued to settle the equity-based retainer paid to certain members of our general partner's board of directors.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


11.	Distributions

Distributions we paid during 2014 and 2015 were as follows (in thousands, except per unit amounts):



Payment Date	Per Unit Cash Distribution Amount			Total Cash Distribution to Limited Partners
02/14/2014		$	0.5850		$	132,835
05/15/2014		0.6125			139,079
08/14/2014		0.6400			145,324
11/14/2014		0.6675			151,568
Total		$	2.5050		$	568,806

2/13/2015		$	0.6950		$	158,061
5/15/2015⁽¹⁾		0.7175			163,178
Total		$	1.4125		$	321,239

(1) Our general partner's board of directors declared this cash distribution on April 23, 2015 to be paid on May 15, 2015 to unitholders of record at the close of business on May 4, 2015.


12.	Fair Value

Recurring

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:


•	Energy commodity derivatives contracts. These include NYMEX futures and CME 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.

•

Interest rate contracts. These include forward-starting interest rate swap agreements to hedge against the risk of variability of interest payments on future debt. These contracts are carried at fair value on our consolidated balance sheets and are valued based on an assumed exchange, at the end of each period, in an orderly transaction with a market participant in the market in which the financial instrument is traded. The exchange value was calculated using present value techniques on estimated future cash flows based on forward interest rate curves. 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, 2014 and March 31, 2015; 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 and

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

our commercial paper program approximates fair value due to the frequent repricing of these obligations.

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, 2014 and March 31, 2015, based on the three levels established by ASC 820; Fair Value Measurements and Disclosures (in thousands):



	As of December 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 – assets	$	96,142		$	96,142		$	96,142	$	—		$	—
Interest rate contracts – liabilities	$	(26,478	)	$	(26,478	)	$	—	$	(26,478	)	$	—
Long-term receivables	$	28,611		$	30,200		$	—	$	—		$	30,200
Debt	$	(2,982,895	)	$	(3,212,462	)	$	—	$	(3,212,462	)	$	—



	As of March 31, 2015
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 – assets	$	54,079		$	54,079		$	54,079	$	—		$	—
Interest rate contracts – assets	$	965		$	965		$	—	$	965		$	—
Long-term receivables	$	27,116		$	28,820		$	—	$	—		$	28,820
Debt	$	(3,183,750	)	$	(3,481,995	)	$	—	$	(3,481,995	)	$	—


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 the general partner 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, 2014 and 2015, we made purchases of butane from subsidiaries of Targa of $12.2 million and $8.8 million, respectively. These purchases were based on the then-current index prices. We had recognized payables to Targa of $0.9 million and $1.5 million at December 31, 2014 and March 31, 2015, 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 subsequent to March 31, 2015.

Non-recognizable events

In April 2015, our general partner's board of directors declared a quarterly distribution of $0.7175 per unit to be paid on May 15, 2015 to unitholders of record at the close of business on May 4, 2015. The total cash distributions expected to be paid under this declaration are approximately $163.2 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, 2015, our asset portfolio, including the assets of our joint ventures, consisted of:


•	our refined products segment, comprised of our 9,500-mile refined products pipeline system with 52 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 1,600 miles of crude oil pipelines and storage facilities with an aggregate storage capacity of approximately 21 million barrels, of which 12 million barrels are 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 26 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, 2014.

Recent Developments

Election to our General Partner's Board of Directors. On April 23, 2015, at our annual meeting of limited partners, Stacy P. Methvin was elected to our general partner's board of directors as an independent director.

Saddlehorn Pipeline. During the first quarter of 2015, plans were finalized for the Saddlehorn pipeline, a 550-mile pipeline system to deliver various grades of crude oil from the DJ Basin, and potentially the broader Rocky Mountain production area, to Cushing, Oklahoma. Anadarko Petroleum Corporation ("Anadarko") exercised its option for partial equity ownership, resulting in 40% ownership of Saddlehorn Pipeline Company ("Saddlehorn") by us, with Plains All-American Pipeline, L.P. and Anadarko owning 40% and 20%, respectively. We will serve as construction manager and operator for Saddlehorn. The Saddlehorn pipeline is expected to be operational in mid-2016.

Debt Offerings. During first quarter 2015, we issued $500.0 million of senior notes, consisting of $250.0 million of 3.2% notes due in 2025 and $250.0 million of 4.2% notes due in 2045. See 2015 Debt Offerings under Liquidity below for further discussion of this matter.

Cash Distribution. In April 2015, the board of directors of our general partner declared a quarterly cash distribution of $0.7175 per unit for the period of January 1, 2015 through March 31, 2015. This quarterly cash distribution will be paid on May 15, 2015 to unitholders of record on May 4, 2015. Total distributions expected to be paid under this declaration are approximately $163.2 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 revenue 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, 2014 Compared to Three Months Ended March 31, 2015



	Three Months Ended March 31,						Variance Favorable (Unfavorable)
	2014			2015			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)
Transportation and terminals revenue:
Refined products	$	210.2		$	216.8		$	6.6		3
Crude oil	67.9			86.5			18.6			27
Marine storage	39.5			42.3			2.8			7
Total transportation and terminals revenue	317.6			345.6			28.0			9
Affiliate management fee revenue	4.9			3.4			(1.5		)	(31)
Operating expenses:
Refined products	51.2			70.3			(19.1		)	(37)
Crude oil	9.1			13.9			(4.8		)	(53)
Marine storage	14.1			15.3			(1.2		)	(9)
Intersegment eliminations	(0.8		)	(1.0		)	0.2			25
Total operating expenses	73.6			98.5			(24.9		)	(34)
Product margin:
Product sales revenue	296.1			173.1			(123.0		)	(42)
Cost of product sales	198.0			136.2			61.8			31
Product margin⁽¹⁾	98.1			36.9			(61.2		)	(62)
Earnings of non-controlled entities	0.5			9.6			9.1			1,820
Operating margin	347.5			297.0			(50.5		)	(15)
Depreciation and amortization expense	37.5			41.7			(4.2		)	(11)
G&A expense	34.9			35.5			(0.6		)	(2)
Operating profit	275.1			219.8			(55.3		)	(20)
Interest expense (net of interest income and interest capitalized)	30.7			34.1			(3.4		)	(11)
Debt placement fee amortization expense	0.6			0.6			—			—
Other expense	—			0.3			(0.3		)	n/a
Income before provision for income taxes	243.8			184.8			(59.0		)	(24)
Provision for income taxes	1.2			1.2			—			—
Net income	$	242.6		$	183.6		$	(59.0	)	(24)
Operating Statistics:
Refined products:
Transportation revenue per barrel shipped	$	1.356		$	1.369
Volume shipped (million barrels):
Gasoline	59.8			62.2
Distillates	37.5			36.9
Aviation fuel	5.0			5.2
Liquefied petroleum gases	1.5			1.0
Total volume shipped	103.8			105.3
Crude oil:
Magellan 100%-owned assets:
Transportation revenue per barrel shipped	$	1.113		$	1.112
Volume shipped (million barrels)	41.8			50.0
Crude oil terminal average utilization (million barrels per month)	12.1			12.6
Select joint venture pipelines:
BridgeTex - volume shipped (million barrels) ⁽²⁾	—			15.0

Marine storage:
Marine terminal average utilization (million barrels per month)	22.7			23.6

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

(2) These volumes reflect the total shipments by BridgeTex, of which our ownership interest is 50%.

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Transportation and terminals revenue increased $28.0 million resulting from:

•

an increase in refined products revenue of $6.6 million. Refined products revenue increased primarily due to a 1% increase in transportation volumes, higher weighted average tariff rates and higher ancillary revenues associated with increased activity. Shipments were higher primarily due to increased demand for gasoline in the markets we serve. Tariff rates were favorably impacted by our mid-year 2014 tariff rate increase of 3.9%, partially offset by more shorter-haul shipments (which have a lower rate);

•

an increase in crude oil revenue of $18.6 million primarily due to higher crude oil deliveries on our Longhorn pipeline and capacity revenue received in first quarter 2015 from BridgeTex Pipeline Company, LLC ("BridgeTex") for capacity on our Houston area crude oil distribution system. Shipments on our Longhorn pipeline averaged approximately 250,000 barrels per day in first quarter 2015, an increase of approximately 50,000 barrels per day over first quarter 2014; and


•	an increase in marine storage revenue of $2.8 million primarily due to improved utilization and higher storage rates at our marine facilities.

Affiliate management fee revenue decreased $1.5 million due to lower construction management fees related to BridgeTex.

Operating expenses increased by $24.9 million primarily resulting from:


•	an increase in refined products expenses of $19.1 million primarily due to less favorable product overages (which reduce operating expense) as a result of significantly lower commodity prices in 2015, as well as higher asset integrity spending and additional property taxes; and


•	an increase in crude oil expenses of $4.8 million primarily due to less favorable product overages (which reduce operating expense) as a result of significantly lower commodity prices in 2015 and higher power costs associated with moving additional volume in the current period; and


•	an increase in marine storage expenses of $1.2 million primarily due to higher asset integrity costs and additional asset retirements during the current period.

Product sales revenue primarily resulted from our butane blending activities, transmix fractionation and product gains from our independent terminals. 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, and we use butane futures agreements to hedge against changes in the price of butane we expect to purchase in future periods. See Note 8 –Derivative Financial Instruments in Item 1 – Consolidated Financial Statements for a discussion of our hedging strategies and how our use of NYMEX contracts and butane futures agreements impacts our product margin. Product margin decreased $61.2 million primarily due to the impact of lower commodity prices on physical product sales in the current period as the related gain on the economic hedges was recognized mainly in the prior quarter. See Other Items—Commodity Derivative Agreements—Impact of Commodity Derivatives on Results of Operations below for more information about our NYMEX contracts.

Earnings of non-controlled entities increased $9.1 million primarily due to our share of earnings from BridgeTex, which began operations late in 2014.

Depreciation and amortization increased $4.2 million primarily due to expansion capital projects placed into service over the last year and a $1.8 million charge recognized during first quarter 2015 to write off an office/warehouse building.

G&A expense increased $0.6 million primarily due to higher personnel costs resulting from an increase in employee headcount, partially offset by lower costs associated with deferred board of director compensation due to a decrease in the price of our limited partner units in the first quarter of 2015.

Interest expense, net of interest income and interest capitalized, increased $3.4 million primarily due to lower capitalized interest now that the BridgeTex pipeline project is operational. Our average outstanding debt increased

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from $2.8 billion in first quarter 2014 to $3.1 billion in first quarter 2015 primarily due to borrowings for expansion capital expenditures, including $250.0 million of 3.20% senior notes and $250.0 million of 4.20% senior notes issued in March 2015. Our weighted-average interest rate decreased from 5.2% in first quarter 2014 to 4.7% in first quarter 2015 due to the impact of our commercial paper borrowings and March 2015 debt issuances, which are both at lower rates than the debt we retired in mid-2014.

Distributable Cash Flow

We calculate the non-GAAP measures of distributable cash flow ("DCF") and adjusted EBITDA in the table below. Management uses DCF as a basis for recommending to our general partner's board of directors the amount of cash distributions to be paid to our limited partners each period. Management also uses DCF as a basis for determining the payouts for the performance-based awards issued under our equity-based compensation plan. 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, 2014 and 2015 to net income, which is its nearest comparable GAAP financial measure, follows (in millions):



	Three Months Ended March 31,						Increase
	2014			2015			(Decrease)
Net income	$	242.6		$	183.6		$	(59.0	)
Interest expense, net, and provision for income taxes	31.9			35.3			3.4
Depreciation and amortization expense⁽¹⁾	38.1			42.3			4.2
Equity-based incentive compensation expense⁽²⁾	(9.7		)	(13.0		)	(3.3		)
Asset retirements	1.2			—			(1.2		)
Commodity-related adjustments:
Derivative losses (gains) recognized in the period associated with future product transactions⁽³⁾	(0.1		)	4.5			4.6
Derivative gains (losses) recognized in previous periods associated with product sales completed in the period⁽⁴⁾	(5.3		)	56.4			61.7
Lower-of-cost-or-market adjustments⁽⁵⁾	—			(29.1		)	(29.1		)
Total commodity-related adjustments	(5.4		)	31.8			37.2
Cash distributions of non-controlled entities in excess of earnings	0.4			4.9			4.5
Adjusted EBITDA	299.1			284.9			(14.2		)
Interest expense, net, and provision for income taxes	(31.9		)	(35.3		)	(3.4		)
Maintenance capital⁽⁶⁾	(14.0		)	(16.5		)	(2.5		)
DCF	$	253.2		$	233.1		$	(20.1	)


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

(2)

Because we intend to satisfy vesting of units under our equity-based incentive compensation program with the issuance of limited partner units, expenses related to this program generally are deemed non-cash and added back for DCF purposes. Total equity-based incentive compensation expense for the three months ended March 31, 2014 and 2015 was $5.1 million and $4.8 million, respectively. However, the figures above include an adjustment for minimum statutory tax withholdings we paid in 2014 and 2015 of $14.8 million and $17.8 million, respectively, for equity-based incentive compensation units that vested on the previous year end, which reduce DCF.

(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. In addition, we have designated certain derivatives we use to hedge our crude oil tank bottoms and linefill assets as fair value hedges and the change in the differential between the current spot price and forward price on these hedges is recognized currently in earnings. We exclude the net impact of both of these adjustments from our

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determination of DCF until the hedged products are physically sold. In the period in which these hedged products are physically sold, the net impact of the associated hedges are included in our determination of DCF.


(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 gain or loss realized on the economic hedges in the period that the underlying product sales occur.


(5)	We add the amount of lower-of-cost-or-market (“LCM”) adjustments on inventory and firm purchase commitments we recognize in each applicable period to determine DCF as these are non-cash charges against income. In subsequent periods when we physically sell or purchase the related products, we deduct the LCM adjustments previously recognized to determine DCF.


(6)	Maintenance capital expenditure projects maintain our existing assets and do not generate incremental DCF (i.e. incremental returns to our unitholders). For this reason, we deduct maintenance capital expenditures to determine DCF.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

Operating Activities. Cash provided by operations is net income adjusted for certain non-cash items and changes in certain assets and liabilities.

Net cash provided by operating activities was $270.1 million and $191.1 million for the three months ended March 31, 2014 and 2015, respectively. The $79.0 million decrease from 2014 to 2015 was due to lower net income related to activities previously described and changes in our working capital, slightly offset by adjustments to non-cash items.

Investing Activities. Investing cash flows consist primarily of capital expenditures and investments in non-controlled entities.

Net cash used by investing activities for the three months ended March 31, 2014 and 2015 was $202.5 million and $134.6 million, respectively. During 2015, we spent $127.7 million for capital expenditures, which included $16.5 million for maintenance capital and $111.2 million for expansion capital. Also during the 2015 period, we contributed capital of $13.8 million in conjunction with our joint venture capital projects which we account for as investments in non-controlled entities. 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 the 2014 period, 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.

Financing Activities. Investing cash flows consist primarily of distributions to our unitholders and borrowings and repayments under long-term notes and our commercial paper program.

Net cash provided (used) by financing activities for the three months ended March 31, 2014 and 2015 was $103.8 million and $(20.8) million, respectively. During 2015, we paid cash distributions of $158.1 million to our unitholders. Additionally, we received net proceeds of $499.6 million from borrowings under long-term notes, which were used in part to repay borrowings outstanding under our commercial paper program and for general partnership purposes, including expansion capital. In connection with the borrowings under long-term notes, we paid $42.9 million in settlement of associated interest rate swap agreements. Also, in January 2015, the cumulative amounts of the January 2012 equity-based incentive compensation award grants were settled by issuing 354,529 limited partner units and distributing those units to the long-term incentive plan ("LTIP") participants, resulting in payments of associated tax withholdings of $17.8 million. During 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 LTIP participants, resulting in payments of associated tax withholdings of $14.8 million.

The quarterly distribution amount related to our first-quarter 2015 financial results (to be paid in second quarter 2015) is $0.7175 per unit. If we meet management's targeted distribution growth of 15% for 2015 and the

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number of outstanding limited partner units remains unchanged at 227.4 million, total cash distributions of approximately $683.4 million will be paid to our unitholders related to 2015 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, 2015, our maintenance capital spending was $16.5 million. For 2015, we expect to spend approximately $85 million on maintenance capital.

During the first three months of 2015, we spent $111.2 million for organic growth capital and $13.8 million for capital projects in conjunction with our joint ventures. Based on the progress of expansion projects already underway, we expect to spend approximately $800 million for expansion capital and joint venture capital contributions during 2015, with an additional $400 million in 2016 to complete our current projects. The new spending estimates include our contributions for our 40% interest in Saddlehorn and approximately $55 million for a refined products terminal acquired in the Atlanta, Georgia market on May 1, 2015.

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Liquidity

Consolidated debt at December 31, 2014 and March 31, 2015 was as follows (in thousands, except as otherwise noted):



	December 31, 2014		March 31, 2015		Weighted-Average Interest Rate for the Three Months Ended March 31, 2015 ⁽¹⁾
Commercial paper⁽²⁾	$	296,942	$	—	0.5%
$250.0 million of 5.65% Notes due 2016	250,758		250,652		5.7%
$250.0 million of 6.40% Notes due 2018	257,280		256,764		5.4%
$550.0 million of 6.55% Notes due 2019	567,868		566,939		5.7%
$550.0 million of 4.25% Notes due 2021	556,304		556,071		4.0%
$250.0 million of 3.20% Notes due 2025⁽²⁾	—		249,680		3.2%
$250.0 million of 6.40% Notes due 2037	249,017		249,021		6.4%
$250.0 million of 4.20% Notes due 2042	248,406		248,414		4.2%
$550.0 million of 5.15% Notes due 2043	556,320		556,296		5.1%
$250.0 million of 4.20% Notes due 2045⁽²⁾	—		249,913		4.6%
Total debt	$	2,982,895	$	3,183,750	4.7%


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


(2)	These borrowings were outstanding for only a portion of the three month period ending March 31, 2015. The weighted-average interest rate for these borrowings was calculated based on the number of days the borrowings were outstanding during the noted period.

All of the instruments detailed in the table above are senior indebtedness.

2015 Debt Offerings

The net proceeds from these offerings were used to repay borrowings outstanding under our commercial paper program and for general partnership purposes, including expansion capital.

Other Debt

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rate from 0.10% to 0.28%, depending on our credit ratings. The unused commitment fee was 0.125% at March 31, 2015. Borrowings under this facility may be used for general partnership purposes, including capital expenditures. As of March 31, 2015, 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.

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 forward physical commodity contracts, NYMEX contracts and Chicago Mercantile Exchange ("CME") butane futures agreements to help manage this commodity price risk. We use forward physical contracts to purchase butane and sell refined products. We account for these forward physical contracts as normal purchase and sale contracts, using traditional accrual accounting. We use NYMEX contracts to hedge against changes in the price of refined products and crude oil that 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 CME 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 activities. As of March 31, 2015, our open NYMEX and CME 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 tank bottoms and linefill. These contracts, which we are accounting for as fair value hedges, mature between December 2015 and November 2016. Through March 31, 2015, the cumulative amount of gains from these agreements was $17.5 million. The cumulative gains from these fair value hedges were recorded as adjustments to the asset being hedged, and there has been no ineffectiveness recognized for these hedges. We exclude the differential between the current spot price and forward price from our assessment of hedge effectiveness for these fair value hedges. The net change in the amounts excluded from our assessment of hedge effectiveness during first quarter 2015 was a loss of $0.3 million, which we recognized as other expense on our consolidated statement of income.

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Open Derivative Contracts Not Designated as Hedges

•

NYMEX contracts covering 2.3 million barrels of refined products related to our butane blending and fractionation activities. These contracts mature between April 2015 and January 2016 and are being accounted for as economic hedges. Through March 31, 2015, the cumulative amount of net unrealized gains associated with these agreements was $27.8 million. We recorded these gains as an adjustment to product sales revenue, of which $29.5 million of net gains was recognized in 2014 and $1.7 million of net losses was recognized in 2015.

•

NYMEX contracts covering 0.9 million barrels of refined products and crude oil related to inventory we carry that resulted from pipeline product overages. These contracts, which mature between April and December 2015, are being accounted for as economic hedges. Through March 31, 2015, the cumulative amount of net unrealized gains associated with these agreements was $9.3 million. We recorded these gains as an adjustment to operating expenses, of which $7.2 million was recognized in 2014 and $2.1 million was recognized in 2015.

•

CME-traded butane futures agreements to purchase 0.3 million barrels of butane that mature between April and December 2015, which are being accounted for as economic hedges. Through March 31, 2015, the cumulative amount of net unrealized losses associated with these agreements was $1.7 million. We recorded these losses as an adjustment to cost of product sales, of which $0.7 million was recognized in 2014 and $1.0 million was recognized in 2015.

Settled Derivative Contracts


•	We settled NYMEX contracts covering 3.2 million barrels of refined products related to economic hedges of products from our butane blending and fractionation activities that we sold during 2015. We recognized a gain of $5.6 million in 2015 related to these contracts, which we recorded as an adjustment to product sales revenue.


•	We settled NYMEX contracts covering 1.4 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 2015. We recognized a loss of $0.8 million in 2015 on the settlement of these contracts, which we recorded as an adjustment to operating expense.


•	We settled CME butane futures agreements covering 0.5 million barrels related to economic hedges of butane purchases we made during 2015 associated with our butane blending activities. We recognized a loss of $0.2 million in 2015 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 and CME contracts on our results of operations for the respective periods presented (in millions):

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	Three Months Ended March 31, 2014
	Product Sales Revenue		Cost of Product Sales			Operating Expense			Other Expense		Net Impact on Net Income
NYMEX and CME 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 and CME gains (losses) recorded during the period that were associated with products that will be or were sold or purchased in future periods	0.2		(0.1		)	(0.5		)	—		(0.4		)
Net impact of NYMEX and CME contracts	$	2.8	$	0.1		$	0.4		$	—	$	3.3



	Three Months Ended March 31, 2015
	Product Sales Revenue			Cost of Product Sales			Operating Expense			Other Expense			Net Impact on Net Income
NYMEX and CME gains (losses) recognized during the period that were associated with economic hedges of physical product sales or purchases during the period	$	5.6		$	(0.2	)	$	(0.8	)	$	—		$	4.6
NYMEX and CME gains (losses) recorded during the period that were associated with products that will be sold or purchased in future periods	(1.7		)	(1.0		)	2.1			(0.3		)	(0.9		)
Net impact of NYMEX and CME contracts	$	3.9		$	(1.2	)	$	1.3		$	(0.3	)	$	3.7

Related Party Transactions. Barry R. Pearl is an independent member of our general partner's board of directors and is also a director of the general partner 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, 2014 and 2015, we made purchases of butane from subsidiaries of Targa of $12.2 million and $8.8 million, respectively. These purchases were based on the then-current index prices. We had recognized payables to Targa of $0.9 million and $1.5 million at December 31, 2014 and March 31, 2015, respectively.

The management fees we receive from Texas Frontera, LLC, Powder Springs Logistics, LLC, Saddlehorn and BridgeTex are reported as affiliate management fee revenue on our consolidated statements of income. For the three months ended March 31, 2014 and 2015, we received throughput revenue from Double Eagle Pipeline LLC ("Double Eagle") of $0.5 million and $0.9 million, respectively, which we recognized as transportation and terminals revenue. At December 31, 2014, we recognized a $0.3 million trade accounts receivable from Double Eagle and at December 31, 2014 and March 31, 2015, we had recognized liabilities of $2.2 million and $1.5 million, respectively, to BridgeTex for pre-paid construction management fees.

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New Accounting Pronouncements

In April 2015, the FASB issued Accounting Standards Update ("ASU") No. 2015-03, Interest: Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. Under this update, the costs for issuing debt will be included on the balance sheet as a direct deduction from the debt's value. The amendments will not affect the recognition and measurement of the costs for issuing debt. The amendments will have to be applied for reporting periods that start after December 15, 2015, with early adoption permitted. We plan to adopt this ASU in fourth quarter 2015, and our adoption will not have a material impact on our results of operations, financial position or cash flows.

In April 2015, the FASB issued ASU 2015-04, Practical Expedient for the Measurement Date of an Employer’s Defined Benefit Obligation and Plan Assets. For an entity that has a significant event in an interim period that calls for a re-measurement of defined benefit plan assets and obligations (i.e., a partial settlement), the amendments in this ASU provide a practical expedient that permits the entity to re-measure defined benefit plan assets and obligations using the month-end that is closest to the date of the significant event. This ASU is effective for reporting periods beginning after December 15, 2015. Our adoption of this standard is not expected to have a material impact on our results of operations, financial position or cash flows.

In April 2015, the FASB issued ASU 2015-05, Intangibles-Goodwill and Other-Internal-Use Software: Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement. Where an entity has entered into a cloud computing arrangement, this update requires the entity to capitalize the software license element of arrangements that include a software license. Where the cloud computing arrangement does not include software license the arrangement is to be accounted for as a service contract. This ASU is effective for reporting periods beginning after December 15, 2015. Our adoption of this standard will not have a material impact on our results of operations, financial position or cash flows.

In January 2015, the FASB issued ASU 2015-01, Income Statement –Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items. This ASU eliminates all references to and guidance concerning the classification and presentation of extraordinary items and emphasizes that the nature and effects of an event or transaction deemed unusual in nature or that is expected to occur infrequently should be disclosed on the face of the income statement as a separate component of income from continuing operations, or, alternatively, in notes to the financial statements. The changes are effective for fiscal years, including quarterly reports, beginning after December 15, 2015, with early application permitted (provided it is applied from the beginning of the fiscal year of initial adoption). The new guidance may be applied either prospectively or retrospectively. Our adoption of this ASU will not have a material impact on our results of operations, financial position or cash flows.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

Our commodity price risk primarily arises from our butane blending and fractionation activities, and from managing product imbalances associated with our refined products and crude oil pipelines. We use derivatives such as forward physical contracts, NYMEX petroleum products contracts and CME butane futures contracts to help us manage commodity price risk.

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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, 2015, 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	$	72.8	1.8
Forward sale contracts	$	4.5	0.1

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 as economic hedges. We also use CME-traded butane futures agreements to hedge against changes in the price of butane that we expect to purchase in future periods. At March 31, 2015, we had open NYMEX contracts representing 3.9 million barrels of petroleum products we expect to sell in the future. Additionally, we had open CME butane futures agreements for 0.3 million barrels of butane we expect to purchase in the future. At March 31, 2015, the fair value of our open NYMEX contracts was an asset of $55.8 million and the fair value of our CME-traded butane futures agreements was a liability of $1.7 million.

At March 31, 2015, open NYMEX contracts representing 3.2 million barrels of petroleum products did not qualify for hedge accounting treatment. A $10.00 per barrel increase in the price of these NYMEX contracts for reformulated gasoline blendstock for oxygen blending (“RBOB”) gasoline or heating oil would result in a $32.0 million decrease in our operating profit and a $10.00 per barrel decrease in the price of these NYMEX contracts for RBOB or heating oil would result in a $32.0 million increase in our operating profit.

At March 31, 2015, we had open CME butane futures agreements representing 0.3 million barrels of butane we expect to purchase in the future. Relative to these agreements, a $10.00 per barrel increase in the price of butane would result in a $3.0 million increase in our operating profit and a $10.00 per barrel decrease in the price of butane would result in a $3.0 million decrease in our operating profit.

The increases or decreases in operating profit we recognize from our open NYMEX forward sales and price swap contracts and open CME butane futures agreements would be substantially offset by higher or lower product sales revenue or cost of product sales when the physical sale or purchase of those products occur. 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 and the resulting hedges may not eliminate all price risks.

Interest Rate Risk

In first quarter 2015, we entered into a $50.0 million forward-starting interest rate swap agreement to hedge against the risk of variability of future interest payments on a portion of debt we anticipate issuing in 2016. The fair value of this contract at March 31, 2015 was an asset of $1.0 million. We account for this agreement as a cash flow hedge. A 0.125% decrease in the interest rates would result in a decrease in the fair value of this asset of approximately $0.6 million. A 0.125% increase in the interest rates would result in an increase in the fair value of this asset of approximately $0.6 million.

At March 31, 2015, 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 and amounts outstanding under the facility.

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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, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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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," "projected," "scheduled," "should," "will" 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;


•	decreases in the production of crude oil in the basins served by our pipelines;


•	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 facilities due to geopolitical events, the activities of the Organization of the Petroleum Exporting Countries, changes in U.S. trade policies, technological developments or other factors;


•	our ability to manage interest rate and commodity price exposures;


•	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;

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•	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, hydraulic fracturing, derivatives transactions and environmental laws and regulations, including laws and regulations designed to address climate change;


•	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 petroleum products and ammonia.

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

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 $0.3 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 $1.4 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.

U.S. 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. 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, 2014, 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.

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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 4.1	—	Fourth Supplemental Indenture dated as of March 4, 2015, between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed March 4, 2015).

*Exhibit 4.2	—	Fifth Supplemental Indenture dated as of March 4, 2015, between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.3 to Form 8-K filed March 4, 2015).

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.

____________

* Each such exhibit has heretofore been filed with the Securities and Exchange Commission as part of the filing indicated and is incorporated herein by reference.

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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 5, 2015.



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 4.1	—	Fourth Supplemental Indenture dated as of March 4, 2015, between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed March 4, 2015).

*Exhibit 4.2	—	Fifth Supplemental Indenture dated as of March 4, 2015, between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.3 to Form 8-K filed March 4, 2015).
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.

_____________

* Each such exhibit has heretofore been filed with the Securities and Exchange Commission as part of the filing indicated and is incorporated herein by reference.