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

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________

FORM 10-Q



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

For the quarterly period ended September 30, 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 November 2, 2015, there were 227,427,247 outstanding limited partner units of Magellan Midstream Partners, L.P. that trade on the New York Stock Exchange under the ticker symbol "MMP."

Table of Contents

TABLE OF CONTENTS

PART I

FINANCIAL INFORMATION



ITEM 1.		CONSOLIDATED FINANCIAL STATEMENTS
	CONSOLIDATED STATEMENTS OF INCOME		2
	CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME		3
	CONSOLIDATED BALANCE SHEETS		4
	CONSOLIDATED STATEMENTS OF CASH FLOWS		5
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS:
	1.	Organization, Description of Business and Basis of Presentation	6
	2.	Product Sales Revenue	7
	3.	Segment Disclosures	8
	4.	Investments in Non-Controlled Entities	11
	5.	Inventory	13
	6.	Employee Benefit Plans	13
	7.	Debt	15
	8.	Derivative Financial Instruments	16
	9.	Commitments and Contingencies	22
	10.	Long-Term Incentive Plan	22
	11.	Distributions	24
	12.	Fair Value	24
	13.	Related Party Transactions	26
	14.	Subsequent Events	26
ITEM 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Introduction		27
	Recent Developments		27
	Results of Operations		28
	Distributable Cash Flow		34
	Liquidity and Capital Resources		35
	Off-Balance Sheet Arrangements		38
	Environmental		38
	Other Items		38
	New Accounting Pronouncements		41
ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	43
ITEM 4.		CONTROLS AND PROCEDURES	44
Forward-Looking Statements			45
PART II OTHER INFORMATION
ITEM 1.		LEGAL PROCEEDINGS	47
ITEM 1A.		RISK FACTORS	47
ITEM 2.		UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	48
ITEM 3.		DEFAULTS UPON SENIOR SECURITIES	48
ITEM 4.		MINE SAFETY DISCLOSURES	48
ITEM 5.		OTHER INFORMATION	48
ITEM 6.		EXHIBITS	49

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						Nine Months Ended
	September 30,						September 30,
	2014			2015			2014			2015
Transportation and terminals revenue	$	360,517		$	400,944		$	1,031,722		$	1,120,560
Product sales revenue	155,865			172,731			589,585			455,827
Affiliate management fee revenue	5,219			3,557			15,346			10,478
Total revenue	521,601			577,232			1,636,653			1,586,865
Costs and expenses:
Operating	132,387			137,906			330,758			367,834
Cost of product sales	91,591			85,522			398,734			316,208
Depreciation and amortization	38,054			42,043			122,462			124,180
General and administrative	35,377			37,612			109,621			111,052
Total costs and expenses	297,409			303,083			961,575			919,274
Earnings of non-controlled entities	1,645			15,521			4,066			49,653
Operating profit	225,837			289,670			679,144			717,244
Interest expense	34,993			39,779			108,674			116,142
Interest income	(374		)	(310		)	(1,171		)	(993		)
Interest capitalized	(9,205		)	(3,984		)	(21,358		)	(9,037		)
Debt placement fee amortization expense	566			640			1,767			1,867
Other expense (income)	—			1,706			—			(4,554		)
Income before provision for income taxes	199,857			251,839			591,232			613,819
Provision for income taxes	1,237			867			3,798			1,820
Net income	$	198,620		$	250,972		$	587,434		$	611,999
Basic net income per limited partner unit	$	0.87		$	1.10		$	2.59		$	2.69
Diluted net income per limited partner unit	$	0.87		$	1.10		$	2.58		$	2.69
Weighted average number of limited partner units outstanding used for basic net income per unit calculation⁽¹⁾	227,294			227,580			227,242			227,540
Weighted average number of limited partner units outstanding used for diluted net income per unit calculation⁽¹⁾	227,830			227,945			227,422			227,702

(1) See Note 10–Long-Term Incentive Plan for additional information regarding our weighted average unit calculations.

See notes to consolidated financial statements.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited, in thousands)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2015			2014			2015
Net income	$	198,620		$	250,972		$	587,434		$	611,999
Other comprehensive income:
Derivative activity:
Net loss on cash flow hedges⁽¹⁾	(1,830		)	(3,410		)	(5,443		)	(16,939		)
Reclassification of net loss (gain) on cash flow hedges to income⁽¹⁾	119			388			(60		)	976
Changes in employee benefit plan assets and benefit obligations recognized in other comprehensive income:
Amortization of prior service credit⁽²⁾	(928		)	(928		)	(2,751		)	(2,784		)
Amortization of actuarial loss⁽²⁾	985			1,798			3,001			5,393
Settlement cost⁽²⁾	30			—			1,599			—
Total other comprehensive loss	(1,624		)	(2,152		)	(3,654		)	(13,354		)
Comprehensive income	$	196,996		$	248,820		$	583,780		$	598,645

(1) See Note 8–Derivative Financial Instruments for details of the amount of gain/loss recognized in accumulated other comprehensive loss ("AOCL") for derivative financial instruments 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			September 30, 2015
ASSETS				(Unaudited)
Current assets:
Cash and cash equivalents	$	17,063		$	9,007
Trade accounts receivable	84,465			113,760
Other accounts receivable	15,711			11,099
Inventory	157,762			135,181
Energy commodity derivatives contracts, net	87,151			49,172
Energy commodity derivatives deposits	6,184			—
Other current assets	34,331			39,937
Total current assets	402,667			358,156
Property, plant and equipment	5,533,935			5,998,280
Less: Accumulated depreciation	1,204,601			1,317,630
Net property, plant and equipment	4,329,334			4,680,650
Investments in non-controlled entities	613,867			753,568
Long-term receivables	28,611			22,055
Goodwill	53,260			53,260
Other intangibles (less accumulated amortization of $11,526 and $13,029 at December 31, 2014 and September 30, 2015, respectively)	4,573			2,535
Debt placement costs (less accumulated amortization of $8,952 and $10,819 at December 31, 2014 and September 30, 2015, respectively)	18,084			20,971
Tank bottoms and linefill	42,585			36,491
Other noncurrent assets	24,304			38,497
Total assets	$	5,517,285		$	5,966,183
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable	$	97,131		$	123,813
Accrued payroll and benefits	48,298			48,750
Accrued interest payable	45,973			45,132
Accrued taxes other than income	47,888			54,222
Environmental liabilities	10,564			16,575
Deferred revenue	71,142			75,283
Accrued product purchases	44,355			20,408
Energy commodity derivatives contracts, net	5,413			—
Energy commodity derivatives deposits	84,463			49,447
Other current liabilities	80,928			34,932
Total current liabilities	536,155			468,562
Long-term debt	2,982,895			3,407,114
Long-term pension and benefits	75,155			68,681
Other noncurrent liabilities	29,069			24,846
Environmental liabilities	25,778			14,903
Commitments and contingencies
Partners’ capital:
Limited partner unitholders (227,068 units and 227,427 units outstanding at December 31, 2014 and September 30, 2015, respectively)	1,949,773			2,076,971
Accumulated other comprehensive loss	(81,540		)	(94,894		)
Total partners’ capital	1,868,233			1,982,077
Total liabilities and partners' capital	$	5,517,285		$	5,966,183

See notes to consolidated financial statements.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)



	Nine Months Ended
	September 30,
	2014			2015
Operating Activities:
Net income	$	587,434		$	611,999
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	122,462			124,180
Debt placement fee amortization expense	1,767			1,867
Loss on sale and retirement of assets	4,830			4,378
Earnings of non-controlled entities	(4,066		)	(49,653		)
Distributions from investments in non-controlled entities	2,398			47,236
Equity-based incentive compensation expense	17,731			15,226
Amortization of prior service credit, actuarial loss and pension settlement	1,849			2,609
Changes in operating assets and liabilities:
Trade accounts receivable and other accounts receivable	10,929			(24,601		)
Inventory	(15,251		)	22,581
Energy commodity derivatives contracts, net of derivatives deposits	(17,540		)	(11,402		)
Accounts payable	6,483			12,226
Accrued payroll and benefits	(669		)	452
Accrued interest payable	(574		)	(841		)
Accrued taxes other than income	6,596			6,334
Accrued product purchases	(8,584		)	(23,947		)
Deferred revenue	7,484			4,141
Current and noncurrent environmental liabilities	(1,172		)	(4,864		)
Other current and noncurrent assets and liabilities	(8,792		)	(13,817		)
Net cash provided by operating activities	713,315			724,104
Investing Activities:
Additions to property, plant and equipment, net⁽¹⁾	(234,763		)	(431,260		)
Proceeds from sale and disposition of assets	264			3,178
Acquisition of business	—			(54,678		)
Investments in non-controlled entities	(378,220		)	(133,373		)
Distributions in excess of earnings of non-controlled entities	3,918			9,341
Net cash used by investing activities	(608,801		)	(606,792		)
Financing Activities:
Distributions paid	(417,238		)	(489,535		)
Net commercial paper borrowings (repayments)	315,967			(69,976		)
Borrowings under long-term notes	257,713			499,589
Payments on notes	(250,000		)	—
Debt placement costs	(2,912		)	(4,754		)
Net payment on financial derivatives	(3,613		)	(42,908		)
Settlement of tax withholdings on long-term incentive compensation	(14,813		)	(17,784		)
Net cash used by financing activities	(114,896		)	(125,368		)
Change in cash and cash equivalents	(10,382		)	(8,056		)
Cash and cash equivalents at beginning of period	25,235			17,063
Cash and cash equivalents at end of period	$	14,853		$	9,007

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	$	(237,240	)	$	(439,721	)
Changes in accounts payable and other current liabilities related to capital expenditures	2,477			8,461
Additions to property, plant and equipment, net	$	(234,763	)	$	(431,260	)

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 September 30, 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 28 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 13 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 or 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 September 30, 2015, the results of operations for the three and nine months ended September 30, 2014 and 2015 and cash flows for the nine months ended September 30, 2014 and 2015. The results of operations for the nine months ended September 30, 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.

Use of Estimates

The preparation of our consolidated financial statements in conformity with generally accepted accounting principles in the U.S. ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of our consolidated financial statements, as well as their impact on the reported amounts of revenue and expense during the reporting periods. Actual results could differ from those estimates.


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 revenue. All of the petroleum products inventory we physically sell associated with our butane blending and fractionation activities, as well as the barrels from product gains we obtain from our independent and marine terminals, are reported as product sales revenue on our consolidated statements of income. The physical sale of the petroleum products inventory from product gains obtained from our pipeline operations and related activities from terminals physically connected to our pipeline system are reported as adjustments to operating expense.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the three and nine months ended September 30, 2014 and 2015, product sales revenue included the following (in thousands):



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2014			2015		2014		2015
Physical sale of petroleum products	$	108,320		$	100,829	$	555,870	$	403,395
NYMEX contract adjustments:
Change in value of NYMEX contracts that were not designated as hedging instruments associated with our butane blending and fractionation activities	47,546			71,902		33,703		52,432
Other	(1		)	—		12		—
Total NYMEX contract adjustments	47,545			71,902		33,715		52,432
Total product sales revenue	$	155,865		$	172,731	$	589,585	$	455,827


3.	Segment Disclosures

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

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 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.

On May 1, 2015, we acquired a refined products terminal in Atlanta, Georgia for net cash consideration of $54.7 million. As this acquired business is not significant to our consolidated operating results and financial position, pro forma financial information and the purchase price allocation of acquired assets and liabilities have not been presented. The results of the acquired operations subsequent to the acquisition date have been included in the accompanying consolidated financial statements and in the tables below in our refined products operating segment.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Three Months Ended September 30, 2014
	(in thousands)
	Refined Products		Crude Oil			Marine Storage			Intersegment Eliminations			Total
Transportation and terminals revenue	$	237,972	$	78,839		$	43,706		$	—		$	360,517
Product sales revenue	155,134		—			731			—			155,865
Affiliate management fee revenue	—		4,902			317			—			5,219
Total revenue	393,106		83,741			44,754			—			521,601
Operating expenses	101,206		14,375			17,691			(885		)	132,387
Cost of product sales	91,407		—			184			—			91,591
Earnings of non-controlled entities	—		(959		)	(686		)	—			(1,645		)
Operating margin	200,493		70,325			27,565			885			299,268
Depreciation and amortization expense	23,050		6,918			7,201			885			38,054
G&A expenses	22,600		7,635			5,142			—			35,377
Operating profit	$	154,843	$	55,772		$	15,222		$	—		$	225,837



	Three Months Ended September 30, 2015
	(in thousands)
	Refined Products		Crude Oil			Marine Storage			Intersegment Eliminations			Total
Transportation and terminals revenue	$	259,806	$	96,029		$	45,109		$	—		$	400,944
Product sales revenue	171,775		—			956			—			172,731
Affiliate management fee revenue	—		3,211			346			—			3,557
Total revenue	431,581		99,240			46,411			—			577,232
Operating expenses	104,622		19,479			14,700			(895		)	137,906
Cost of product sales	85,341		—			181			—			85,522
Losses (earnings) of non-controlled entities	48		(14,906		)	(663		)	—			(15,521		)
Operating margin	241,570		94,667			32,193			895			369,325
Depreciation and amortization expense	24,333		9,502			7,313			895			42,043
G&A expenses	22,238		9,818			5,556			—			37,612
Operating profit	$	194,999	$	75,347		$	19,324		$	—		$	289,670

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Nine Months Ended September 30, 2014
	(in thousands)
	Refined Products		Crude Oil			Marine Storage			Intersegment Eliminations			Total
Transportation and terminals revenue	$	680,697	$	226,298		$	124,727		$	—		$	1,031,722
Product sales revenue	585,178		—			4,407			—			589,585
Affiliate management fee revenue	—		14,399			947			—			15,346
Total revenue	1,265,875		240,697			130,081			—			1,636,653
Operating expenses	249,665		35,300			48,321			(2,528		)	330,758
Cost of product sales	397,980		—			754			—			398,734
Earnings of non-controlled entities	—		(1,667		)	(2,399		)	—			(4,066		)
Operating margin	618,230		207,064			83,405			2,528			911,227
Depreciation and amortization expense	78,305		20,106			21,523			2,528			122,462
G&A expenses	70,993		21,326			17,302			—			109,621
Operating profit	$	468,932	$	165,632		$	44,580		$	—		$	679,144



	Nine Months Ended September 30, 2015
	(in thousands)
	Refined Products		Crude Oil			Marine Storage			Intersegment Eliminations			Total
Transportation and terminals revenue	$	710,294	$	278,345		$	131,921		$	—		$	1,120,560
Product sales revenue	453,737		—			2,090			—			455,827
Affiliate management fee revenue	—		9,449			1,029			—			10,478
Total revenue	1,164,031		287,794			135,040			—			1,586,865
Operating expenses	275,403		49,354			45,916			(2,839		)	367,834
Cost of product sales	315,301		—			907			—			316,208
Losses (earnings) of non-controlled entities	146		(47,735		)	(2,064		)	—			(49,653		)
Operating margin	573,181		286,175			90,281			2,839			952,476
Depreciation and amortization expense	71,742		25,995			23,604			2,839			124,180
G&A expenses	68,730		26,935			15,387			—			111,052
Operating profit	$	432,709	$	233,245		$	51,290		$	—		$	717,244

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


4.	Investments in Non-Controlled Entities

Our investments in non-controlled entities at September 30, 2015 were 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 ("Powder Springs")		50%
Saddlehorn Pipeline Company, LLC ("Saddlehorn")		40%
Seabrook Logistics, LLC ("Seabrook")		50%
Texas Frontera, LLC ("Texas Frontera")		50%

The management fees we have recognized or will recognize from BridgeTex, Osage, Powder Springs, Saddlehorn, Seabrook and Texas Frontera are or will be reported as affiliate management fee revenue on our consolidated statements of income.

At December 31, 2014 and September 30, 2015, we recognized liabilities of $2.2 million and $0.5 million, respectively, to BridgeTex primarily for pre-paid construction management fees. For the three and nine months ended September 30, 2015, we recognized pipeline capacity lease revenue from BridgeTex of $8.9 million and $25.8 million, respectively, 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. There was no receivable at September 30, 2015.

In third quarter 2015, we purchased surplus pipe from BridgeTex for the amount of $0.6 million. We sold a portion of the pipe purchased from BridgeTex to Saddlehorn for $0.2 million.

We recognized throughput revenue from Double Eagle for the three months ended September 30, 2014 and 2015 of $0.7 million and $0.8 million, respectively, and for the nine months ended September 30, 2014 and 2015 of $2.0 million and $2.6 million, respectively, which we included in transportation and terminals revenue. At December 31, 2014 and September 30, 2015, respectively, we recognized a $0.3 million trade accounts receivable from Double Eagle.

The financial results from Texas Frontera are included in our marine storage segment, the financial results from BridgeTex, Double Eagle, Osage, Saddlehorn and Seabrook 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	16,608			130,017			146,625
Earnings of non-controlled entities:
Proportionate share of earnings	45,903			5,842			51,745
Amortization of excess investment and capitalized interest	(1,529		)	(563		)	(2,092		)
Earnings of non-controlled entities	44,374			5,279			49,653
Less:
Distributions of earnings from investments in non-controlled entities	44,374			2,862			47,236
Distributions in excess of earnings of non-controlled entities	9,341			—			9,341
Investments at September 30, 2015	$	496,615		$	256,953		$	753,568

Summarized financial information of our non-controlled entities for the three and nine months ended September 30, 2014 and 2015 follows (in thousands):



	Three Months Ended September 30, 2014						Three Months Ended September 30, 2015
	BridgeTex		All Others		Consolidated		BridgeTex		All Others		Consolidated
Revenue	$	428	$	8,882	$	9,310	$	47,555	$	12,530	$	60,085
Net income	$	297	$	3,370	$	3,667	$	28,150	$	4,151	$	32,301



	Nine Months Ended September 30, 2014						Nine Months Ended September 30, 2015
	BridgeTex		All Others		Consolidated		BridgeTex		All Others		Consolidated
Revenue	$	428	$	27,346	$	27,774	$	146,320	$	33,677	$	179,997
Net income	$	17	$	9,241	$	9,258	$	91,806	$	11,525	$	103,331

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


5.	Inventory

Inventory at December 31, 2014 and September 30, 2015 was as follows (in thousands):



	December 31, 2014		September 30, 2015
Refined products	$	67,055	$	27,864
Liquefied petroleum gases	37,642		42,984
Transmix	36,867		28,608
Crude oil	10,015		29,626
Additives	6,183		6,099
Total inventory	$	157,762	$	135,181


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 and nine months ended September 30, 2014 and 2015 (in thousands):



	Three Months Ended						Three Months Ended
	September 30, 2014						September 30, 2015
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Components of net periodic benefit costs:
Service cost	$	3,348		$	57		$	4,723		$	61
Interest cost	1,332			126			1,938			109
Expected return on plan assets	(1,588		)	—			(2,009		)	—
Amortization of prior service credit	—			(928		)	—			(928		)
Amortization of actuarial loss	756			229			1,577			221
Settlement cost	30			—			—			—
Net periodic benefit cost (credit)	$	3,878		$	(516	)	$	6,229		$	(537	)

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Nine Months Ended						Nine Months Ended
	September 30, 2014						September 30, 2015
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Components of net periodic benefit costs:
Service cost	$	10,052		$	171		$	14,168		$	183
Interest cost	5,021			379			5,815			328
Expected return on plan assets	(4,775		)	—			(6,028		)	—
Amortization of prior service cost (credit)	33			(2,784		)	—			(2,784		)
Amortization of actuarial loss	2,315			686			4,730			663
Settlement cost	1,599			—			—			—
Net periodic benefit cost (credit)	$	14,245		$	(1,548	)	$	18,685		$	(1,610	)

Contributions estimated to be paid into the plans in 2015 are $21.1 million and $1.2 million for the pension and other postretirement benefit plans, respectively.

We match our employees' qualifying contributions to our defined contribution plan, resulting in expense to us. Expenses related to the defined contribution plan were $1.7 million and $1.8 million, respectively, for the three months ended September 30, 2014 and 2015, and $6.3 million and $6.8 million, respectively, for the nine months ended September 30, 2014 and 2015.

Amounts Included in AOCL

The changes in AOCL related to employee benefit plan assets and benefit obligations for the three and nine months ended September 30, 2014 and 2015 were as follows (in thousands):



	Three Months Ended						Three Months Ended
	September 30, 2014						September 30, 2015
Gains (Losses) Included in AOCL	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Beginning balance	$	(33,023	)	$	1,654		$	(60,104	)	$	(3,110	)
Amortization of prior service credit	—			(928		)	—			(928		)
Amortization of actuarial loss	756			229			1,577			221
Settlement cost	30			—			—			—
Ending balance	$	(32,237	)	$	955		$	(58,527	)	$	(3,817	)



	Nine Months Ended						Nine Months Ended
	September 30, 2014						September 30, 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 cost (credit)	33			(2,784		)	—			(2,784		)
Amortization of actuarial loss	2,315			686			4,730			663
Settlement cost	1,599			—			—			—
Ending balance	$	(32,237	)	$	955		$	(58,527	)	$	(3,817	)

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


7.	Debt

Consolidated debt at December 31, 2014 and September 30, 2015 was as follows (in thousands, except as otherwise noted):



	December 31, 2014		September 30, 2015		Weighted-Average Interest Rate for the Nine Months Ended September 30, 2015 ⁽¹⁾
Commercial paper⁽²⁾	$	296,942	$	226,966	0.5%
$250.0 million of 5.65% Notes due 2016	250,758		250,440		5.7%
$250.0 million of 6.40% Notes due 2018	257,280		255,731		5.4%
$550.0 million of 6.55% Notes due 2019	567,868		565,064		5.7%
$550.0 million of 4.25% Notes due 2021	556,304		555,601		4.0%
$250.0 million of 3.20% Notes due 2025⁽²⁾	—		249,694		3.2%
$250.0 million of 6.40% Notes due 2037	249,017		249,031		6.4%
$250.0 million of 4.20% Notes due 2042	248,406		248,429		4.2%
$550.0 million of 5.15% Notes due 2043	556,320		556,245		5.1%
$250.0 million of 4.20% Notes due 2045⁽²⁾	—		249,913		4.6%
Total debt	$	2,982,895	$	3,407,114	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 nine-month period ending September 30, 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 September 30, 2015 was $2.9 billion and $3.4 billion, respectively. The difference between the face value and carrying value of our 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 $247.6 million, after underwriting discounts and offering expenses of $2.1 million.

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 $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.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Other Debt

Revolving Credit Facility. At September 30, 2015, the total borrowing capacity under our revolving credit facility, with a maturity date of November 2018, was $1.0 billion. Borrowings outstanding under the facility were classified as long-term debt on our consolidated balance sheets. Borrowings under the facility were unsecured and bore interest at LIBOR plus a spread ranging from 1.0% to 1.75% based on our credit ratings. Additionally, an unused commitment fee was assessed at a rate from 0.10% to 0.28%, depending on our credit ratings. The unused commitment fee was 0.125% at September 30, 2015. Borrowings under this facility could be used for general partnership purposes, including capital expenditures. As of September 30, 2015, there were no borrowings outstanding under this facility; however, $5.6 million was obligated for letters of credit. Amounts obligated for letters of credit were not reflected as debt on our consolidated balance sheets but decreased our borrowing capacity under the facility. See Note 14 – Subsequent Events for information about amendments made to our revolving credit facility and a new 364-day credit facility entered into after September 30, 2015.

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, therefore, is classified as long-term debt.


8.	Derivative Financial Instruments

Interest Rate Derivatives

We periodically enter into interest rate derivatives to hedge the fair value of our debt or interest on 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.

Through September 30, 2015, we entered into $150.0 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 anticipate issuing in 2016. The fair value of these contracts at September 30, 2015 was recorded on our balance sheet as an other noncurrent asset of $0.6 million and as an other noncurrent liability of $1.1 million, with the offsets recorded to other comprehensive income. We account for these agreements as cash flow hedges.

During 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 a net payment on financial derivatives in the financing activities of our consolidated statements of cash flows in 2015.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Commodity Derivatives

Hedging Strategies

Our butane blending activities produce gasoline products, and we can reasonably estimate the timing and quantities of sales of these products. We use a combination of NYMEX and forward purchase and sale contracts 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 September 30, 2015, we had commitments under these forward purchase and sale contracts as follows (in millions):



	Notional Value		Barrels
Forward purchase contracts	$	137.5	3.9
Forward sale contracts	$	0.3	—

The NYMEX contracts that we enter into 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 and amounts excluded from the assessment of hedge effectiveness 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 and nine months ended September 30, 2014 and 2015, none of the commodity hedging contracts we entered into qualified for or were designated as cash flow hedges.

Period changes in the fair value of NYMEX agreements that are accounted for as economic hedges (other than those economic hedges of our butane purchases and our pipeline product overages as discussed below), the effective portion of changes in the fair value of cash flow hedges that are reclassified from AOCL and any ineffectiveness associated with hedges related to our commodity activities are recognized currently in earnings as adjustments to product sales.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

We also use NYMEX contracts, which are not designated as hedges for accounting purposes, to economically 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 noncurrent assets on our balance sheet as tank bottoms and linefill. 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 at September 30, 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	5.4 million barrels of refined products and crude oil⁽¹⁾	Between October 2015 and December 2016
NYMEX - Economic Hedges	1.2 million barrels of future purchases of butane	Between October 2015 and December 2016

(1) Of the 5.4 million barrels of products we have economically hedged at September 30, 2015, we had open agreements which swap the pricing on 1.2 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 September 30, 2015, we had received margin deposits of $49.4 million for our NYMEX contracts with our counterparties, which were recorded as a current liability 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 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 contracts 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 together for each counterparty, which we have elected to do, and we report the combined net balances on our consolidated balance sheets. A schedule of the derivative amounts we have offset and the deposit amounts we could offset under a master netting arrangement are provided below as of December 31, 2014 and September 30, 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

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	September 30, 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	$	89,138	$	(10,695	)	$	78,443	$	(49,447	)	$	28,996


(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 $49,172 and noncurrent assets of $29,271.


(3)	This represents the maximum amount of loss we would incur if all of 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 and nine months ended September 30, 2014 and 2015 were as follows (in thousands):



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Derivative Gains (Losses) Included in AOCL	2014			2015			2014			2015
Beginning balance	$	9,835		$	(29,528	)	$	13,627		$	(16,587	)
Net loss on interest rate contract cash flow hedges	(1,830		)	(3,410		)	(5,443		)	(16,939		)
Reclassification of net loss (gain) on cash flow hedges to income	119			388			(60		)	976
Ending balance	$	8,124		$	(32,550	)	$	8,124		$	(32,550	)

Income Statement

The following tables provide a summary of the effect on our consolidated statements of income for the three and nine months ended September 30, 2014 and 2015 of derivatives accounted for under ASC 815-30, Derivatives and Hedging—Cash Flow Hedges, that were designated as cash flow hedging instruments (in thousands):



	Three Months Ended September 30, 2014
	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		$	(1,830	)	Interest expense		$	(119	)		$	—



	Three Months Ended September 30, 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		$	(3,410	)	Interest expense		$	(388	)		$	—

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Nine Months Ended September 30, 2014
	Amount of Loss Recognized in AOCL on Derivative				Location of Gain (Loss) Reclassified from AOCL into Income	Amount of Gain (Loss) Reclassified from AOCL into Income
Derivative Instrument	Amount of Loss Recognized in AOCL on Derivative				Location of Gain (Loss) Reclassified from AOCL into Income	Effective Portion				Ineffective Portion
Interest rate contracts		$	(5,443	)	Interest expense		$	(123	)		$	183



	Nine Months Ended September 30, 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		$	(16,939	)	Interest expense		$	(976	)		$	—

As of September 30, 2015, the net loss estimated to be classified to interest expense over the next twelve months from AOCL is approximately $1.5 million.

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 September 30, 2015 of $13.3 million and $19.4 million, respectively, from these agreements were offset by a cumulative decrease to tank bottoms and linefill. The differential between the current spot price and forward price is excluded from the assessment of hedge effectiveness for these fair value hedges. For the three and nine months ended September 30, 2015, we recognized a gain (loss) of $(1.7) million and $4.6 million, respectively, for the amounts we excluded from the assessment of effectiveness of these fair value hedges, which we reported as other expense/income on our consolidated statements of income.

The following table provides a summary of the effect on our consolidated statements of income for the three and nine months ended September 30, 2014 and 2015 of derivatives accounted for under ASC 815, Derivatives and Hedging, that were not designated as hedging instruments (in thousands):



		Amount of Gain (Loss) Recognized on Derivatives
		Three Months Ended						Nine Months Ended
	Location of Gain (Loss) Recognized on Derivatives	September 30,						September 30,
Derivative Instruments	Location of Gain (Loss) Recognized on Derivatives	2014			2015			2014			2015
NYMEX commodity contracts	Product sales revenue	$	47,545		$	71,902		$	33,715		$	52,432
NYMEX commodity contracts	Operating expenses	4,350			14,761			447			7,181
NYMEX commodity contracts	Cost of product sales	(3,913		)	(3,767		)	(3,137		)	(5,847		)
	Total	$	47,982		$	82,896		$	31,025		$	53,766

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

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 September 30, 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

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

September 30, 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

913

Energy commodity derivatives contracts, net

—

NYMEX commodity contracts

Other noncurrent assets

24,499

Other noncurrent liabilities

—

Interest rate contracts

Other noncurrent assets

574

Other noncurrent liabilities

1,082

Total

25,986

Total

1,082

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 September 30, 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

10,622

September 30, 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

58,685

Energy commodity derivatives contracts, net

10,426

NYMEX commodity contracts

Other noncurrent assets

5,041

Other noncurrent liabilities

269

Total

63,726

Total

10,695

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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 $31.5 million at December 31, 2014 and September 30, 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 expenditures recognized as a result of changes in our environmental liabilities are generally included in operating expenses on our consolidated statements of income. Environmental expenses for the three and nine months ended September 30, 2014 were $3.7 million and $4.1 million, respectively. Environmental expenses for the three and nine months ended September 30, 2015 were $1.3 million and $5.6 million, respectively.

Environmental Receivables

Receivables from insurance carriers and other third parties related to environmental matters were $5.1 million at December 31, 2014, 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 were $2.6 million at September 30, 2015, of which $0.9 million and $1.7 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 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 September 30, 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						Nine Months Ended
	September 30, 2014						September 30, 2014
	Equity Method		Liability Method		Total		Equity Method		Liability Method		Total
Performance/market-based awards:
2012 awards	$	1,022	$	651	$	1,673	$	3,066	$	3,192	$	6,258
2013 awards	1,350		558		1,908		4,726		2,411		7,137
2014 awards	1,101		—		1,101		3,233		—		3,233
Retention awards	296		—		296		1,103		—		1,103
Total	$	3,769	$	1,209	$	4,978	$	12,128	$	5,603	$	17,731

Allocation of LTIP expense on our consolidated statements of income:
G&A expense					$	4,862					$	17,322
Operating expense					116						409
Total					$	4,978					$	17,731



	Three Months Ended							Nine Months Ended
	September 30, 2015							September 30, 2015
	Equity Method		Liability Method			Total		Equity Method		Liability Method		Total
Performance/market-based awards:
2013 awards	$	1,673	$	(590	)	$	1,083	$	6,246	$	501	$	6,747
2014 awards	1,497		—			1,497		3,980		—		3,980
2015 awards	1,727		—			1,727		3,687		—		3,687
Retention awards	380		—			380		812		—		812
Total	$	5,277	$	(590	)	$	4,687	$	14,725	$	501	$	15,226

Allocation of LTIP expense on our consolidated statements of income:
G&A expense						$	4,643					$	15,016
Operating expense						44						210
Total						$	4,687					$	15,226

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

In January 2015, we issued 354,529 limited partner units to settle unit award grants to certain employees that vested on December 31, 2014. Further, 4,461 limited partner units were issued during 2015 to settle the equity-based retainer paid to certain members of our general partner's board of directors.

Basic and Diluted Net Income Per Limited Partner Unit

The difference between our actual limited partner units outstanding and our weighted-average number of limited partner units outstanding used to calculate earnings per unit, is due to the impact of: (i) the phantom units issued to non-employee directors which is included in the calculation of basic and diluted weighted average units

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

outstanding, and (ii) the weighted average effect of units actually issued during a period. The difference between the weighted-average number of limited partner units outstanding used for basic and diluted net income per unit calculations on our consolidated statements of income is primarily the dilutive effect of phantom unit grants associated with our LTIP.


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
Through 09/30/2014		1.8375			417,238
11/14/2014		0.6675			151,568
Total		$	2.5050		$	568,806

02/13/2015		$	0.6950		$	158,061
05/15/2015		0.7175			163,178
08/14/2015		0.7400			168,296
Through 09/30/2015		2.1525			489,535
11/13/2015⁽¹⁾		0.7625			173,413
Total		$	2.9150		$	662,948

(1) Our general partner's board of directors declared this cash distribution on October 22, 2015 to be paid on November 13, 2015 to unitholders of record at the close of business on November 2, 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 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

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 September 30, 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 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 September 30, 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 September 30, 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	$	78,443		$	78,443		$	78,443	$	—		$	—
Interest rate contracts – liabilities	$	(508	)	$	(508	)	$	—	$	(508	)	$	—
Long-term receivables	$	22,055		$	21,681		$	—	$	—		$	21,681
Debt	$	(3,407,114	)	$	(3,420,351	)	$	—	$	(3,420,351	)	$	—

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


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 September 30, 2014 and 2015, we made purchases of butane from subsidiaries of Targa of $0.1 million and $1.5 million, respectively. For the nine months ended September 30, 2014 and 2015, we made purchases of butane from subsidiaries of Targa of $13.9 million and $14.3 million, respectively. These purchases were based on the then-current index prices. We had recognized payables to Targa of $0.9 million and $1.0 million at December 31, 2014 and September 30, 2015, respectively.

Stacy P. Methvin was elected as an independent member of our general partner's board of directors on April 23, 2015 and is also a director of one of our customers. We received tariff revenue of $4.1 million and $6.7 million for the three months ended September 30, 2015 and for the period of April 23, 2015 through September 30, 2015, respectively, and have recorded a $1.3 million receivable from this customer at September 30, 2015. The tariff revenue we recognized from this customer was in the normal course of business, with rates determined in accordance with published tariffs.

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


14.	Subsequent Events

Recognizable events

No recognizable events occurred subsequent to September 30, 2015.

Non-recognizable events

Cash Distribution. In October 2015, our general partner's board of directors declared a quarterly distribution of $0.7625 per unit to be paid on November 13, 2015 to unitholders of record at the close of business on November 2, 2015. The total cash distributions expected to be paid under this declaration are approximately $173.4 million.

Credit Facilities. On October 27, 2015, we entered into a $1.0 billion amended and restated revolving credit facility and a new $250.0 million 364-day revolving credit facility. The $1.0 billion facility matures on October 27, 2020, while the 364-day facility matures on October 25, 2016, subject to a term-out option. We may exercise the term-out option no later than 30 days prior to October 25, 2016 and elect to have all outstanding borrowings converted into a term loan due and payable on October 25, 2018, subject to the payment of a term-out fee. Borrowings under our new credit facilities will be unsecured and bear interest at LIBOR, plus a spread ranging from 1.00% to 1.625% based on our credit ratings and amounts outstanding. Additionally, commitment fees are assessed on undrawn amounts under our $1.0 billion facility at a rate between 0.100% and 0.275% and under our 364-day facility at a rate between 0.080% and 0.225%, subject to our credit ratings. Our commitment fee was 0.125% on our $1.0 billion facility and 0.100% on our 364-day facility at October 27, 2015. Debt placement costs related to our $1.0 billion facility and our 364-day facility of $1.4 million and $0.1 million, respectively, will be amortized over the term of the credit facilities. Borrowings from the credit facilities will be used for general purposes, including capital expenditures.

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

Introduction

We are a publicly traded limited partnership principally engaged in the transportation, storage and distribution of refined petroleum products and crude oil. As of September 30, 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 28 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 13 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

Cash Distribution. In October 2015, the board of directors of our general partner declared a quarterly cash distribution of $0.7625 per unit for the period of July 1, 2015 through September 30, 2015. This quarterly cash distribution will be paid on November 13, 2015 to unitholders of record on November 2, 2015. Total distributions expected to be paid under this declaration are approximately $173.4 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 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 following tables. Operating profit includes expense items, such as depreciation and amortization expense and general and administrative (“G&A”) expense, which management does not focus on when evaluating the core profitability of our separate operating segments. Additionally, product margin, which management primarily uses to evaluate the profitability of our commodity-related activities, is provided in these tables. 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 September 30, 2014 Compared to Three Months Ended September 30, 2015



	Three Months Ended September 30,						Variance Favorable (Unfavorable)
	2014			2015			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)
Transportation and terminals revenue:
Refined products	$	238.0		$	259.8		$	21.8		9
Crude oil	78.8			96.1			17.3			22
Marine storage	43.7			45.1			1.4			3
Total transportation and terminals revenue	360.5			401.0			40.5			11
Affiliate management fee revenue	5.2			3.6			(1.6		)	(31)
Operating expenses:
Refined products	101.2			104.6			(3.4		)	(3)
Crude oil	14.4			19.4			(5.0		)	(35)
Marine storage	17.7			14.7			3.0			17
Intersegment eliminations	(0.9		)	(0.8		)	(0.1		)	(11)
Total operating expenses	132.4			137.9			(5.5		)	(4)
Product margin:
Product sales revenue	155.9			172.7			16.8			11
Cost of product sales	91.6			85.5			6.1			7
Product margin⁽¹⁾	64.3			87.2			22.9			36
Earnings of non-controlled entities	1.7			15.5			13.8			812
Operating margin	299.3			369.4			70.1			23
Depreciation and amortization expense	38.1			42.1			(4.0		)	(10)
G&A expense	35.4			37.7			(2.3		)	(6)
Operating profit	225.8			289.6			63.8			28
Interest expense (net of interest income and interest capitalized)	25.4			35.4			(10.0		)	(39)
Debt placement fee amortization expense	0.6			0.7			(0.1		)	(17)
Other expense	—			1.7			(1.7		)	n/a
Income before provision for income taxes	199.8			251.8			52.0			26
Provision for income taxes	1.2			0.8			0.4			33
Net income	$	198.6		$	251.0		$	52.4		26
Operating Statistics:
Refined products:
Transportation revenue per barrel shipped	$	1.408		$	1.476
Volume shipped (million barrels):
Gasoline	66.2			73.9
Distillates	41.6			38.8
Aviation fuel	6.4			5.6
Liquefied petroleum gases	4.3			3.5
Total volume shipped	118.5			121.8
Crude oil:
Magellan 100%-owned assets:
Transportation revenue per barrel shipped	$	1.304		$	1.148
Volume shipped (million barrels)	44.0			53.6
Crude oil terminal average utilization (million barrels per month)	12.3			13.5
Select joint venture pipelines:
BridgeTex - volume shipped (million barrels)⁽²⁾	0.2			18.5

Marine storage:
Marine terminal average utilization (million barrels per month)	22.9			24.3

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

(2) These volumes reflect the total shipments for the BridgeTex pipeline, which is owned 50% by us.

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Transportation and terminals revenue increased $40.5 million resulting from:

•

an increase in refined products revenue of $21.8 million primarily attributable to higher transportation and related ancillary revenue. Transportation revenue was favorably impacted by both higher rates and a 3% increase in volumes. The average rate per barrel in the current period was impacted by the mid-year 2015 tariff rate increase of 4.6% on virtually all of our tariffs. Volumes were higher primarily due to a 12% increase in shipments of gasoline resulting from refinery turnarounds that increased demand on our system and lower prices that increased overall demand for gasoline, partially offset by 7% lower shipments of distillates principally due to reduced demand from drilling activities in the markets we serve. Additionally, revenue from our ammonia pipeline, independent terminals and leased storage increased;

•

an increase in crude oil revenue of $17.3 million primarily due to revenue received in third quarter 2015 from BridgeTex Pipeline Company, LLC ("BridgeTex") for capacity on our Houston area crude oil distribution system, higher transportation revenue due to increased shipments on our Longhorn pipeline and Houston-area crude oil distribution system, as well as higher terminalling revenue resulting from new leased storage contracts. Transportation revenue per barrel shipped was lower in the current period due to reduced average tariffs resulting from a lower volume of spot shipments on the Longhorn pipeline system, which ship at a higher rate, and more short-haul movements on our Houston-area crude oil distribution system in 2015; and


•	an increase in marine storage revenue of $1.4 million primarily due to higher ancillary fees due to increased customer activity.

Affiliate management fee revenue decreased $1.6 million due to lower construction management fees related to BridgeTex, as the pipeline became operational in late September 2014.

Operating expenses increased by $5.5 million primarily resulting from:


•	an increase in refined products expenses of $3.4 million primarily due to higher asset integrity spending and personnel costs, partially offset by more favorable product overages (which reduce operating expense);


•	an increase in crude oil expenses of $5.0 million primarily due to less favorable product overages (which reduce operating expense), higher pipeline capacity rental fees and higher personnel costs; and


•	a decrease in marine storage expenses of $3.0 million primarily due to lower asset integrity spending and environmental costs.

Product sales revenue resulted from our butane blending activities, transmix fractionation and product gains from our independent and marine 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 increased $22.9 million primarily due to more favorable unrealized gains on our NYMEX contracts and higher realized margins from our fractionation activities. Product margins from our fractionation activities improved primarily because the decrease in our average cost of sales more than offset the impact of lower product sales prices. 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 $13.8 million primarily due to our share of earnings from BridgeTex, which began operations in late September 2014.

Depreciation and amortization increased $4.0 million primarily due to expansion capital projects placed into service.

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G&A expense increased $2.3 million primarily due to higher personnel costs from an increase in employee headcount, partially offset by lower costs associated with deferred board of director compensation resulting from a decrease in the price of our limited partner units in the third quarter of 2015.

Interest expense, net of interest income and interest capitalized, increased $10.0 million in third quarter 2015, primarily because our debt balance was higher in the current period compared to the same period in 2014 and lower capitalized interest since we are no longer capitalizing interest expense related to BridgeTex, which began operations in late September 2014. Our average outstanding debt increased from $3.0 billion in third quarter 2014 to $3.4 billion in third quarter 2015 primarily due to borrowings for expansion capital expenditures, including $500.0 million of senior notes issued in March 2015. Our weighted-average interest rate of 4.7% in third quarter 2015 was unchanged compared to third quarter 2014.

Other expense in third quarter 2015 included a $1.7 million unfavorable non-cash adjustment for the change in the differential between the current spot price and forward price on fair value hedges associated with our crude oil tank bottoms and linefill assets.

Provision for income taxes was $0.4 million favorable due to a reduction in the franchise tax rate for the state of Texas.

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Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2015



	Nine Months Ended September 30,						Variance Favorable (Unfavorable)
	2014			2015			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)
Transportation and terminals revenue:
Refined products	$	680.7		$	710.3		$	29.6		4
Crude oil	226.3			278.4			52.1			23
Marine storage	124.7			131.9			7.2			6
Total transportation and terminals revenue	1,031.7			1,120.6			88.9			9
Affiliate management fee revenue	15.3			10.5			(4.8		)	(31)
Operating expenses:
Refined products	249.7			275.4			(25.7		)	(10)
Crude oil	35.3			49.3			(14.0		)	(40)
Marine storage	48.3			45.9			2.4			5
Intersegment eliminations	(2.5		)	(2.8		)	0.3			12
Total operating expenses	330.8			367.8			(37.0		)	(11)
Product margin:
Product sales revenue	589.6			455.8			(133.8		)	(23)
Cost of product sales	398.7			316.2			82.5			21
Product margin⁽¹⁾	190.9			139.6			(51.3		)	(27)
Earnings of non-controlled entities	4.1			49.6			45.5			1,110
Operating margin	911.2			952.5			41.3			5
Depreciation and amortization expense	122.5			124.2			(1.7		)	(1)
G&A expense	109.6			111.1			(1.5		)	(1)
Operating profit	679.1			717.2			38.1			6
Interest expense (net of interest income and interest capitalized)	86.1			106.1			(20.0		)	(23)
Debt placement fee amortization expense	1.8			1.9			(0.1		)	(6)
Other income	—			(4.6		)	4.6			n/a
Income before provision for income taxes	591.2			613.8			22.6			4
Provision for income taxes	3.8			1.8			2.0			53
Net income	$	587.4		$	612.0		$	24.6		4
Operating Statistics:
Refined products:
Transportation revenue per barrel shipped	$	1.392		$	1.417
Volume shipped (million barrels):
Gasoline	189.7			203.3
Distillates	119.6			112.0
Aviation fuel	17.5			16.1
Liquefied petroleum gases	9.5			9.3
Total volume shipped	336.3			340.7
Crude oil:
Magellan 100%-owned assets:
Transportation revenue per barrel shipped	$	1.222		$	1.104
Volume shipped (million barrels)	132.7			157.4
Crude oil terminal average utilization (million barrels per month)	12.2			13.0
Select joint venture pipelines:
BridgeTex - volume shipped (million barrels)⁽²⁾	0.2			57.2

Marine storage:
Marine terminal average utilization (million barrels per month)	22.8			24.1

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

(2) These volumes reflect the total shipments for the BridgeTex pipeline, which is owned 50% by us.

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Transportation and terminals revenue increased $88.9 million resulting from:

•

an increase in refined products revenue of $29.6 million primarily attributable to higher transportation and related ancillary revenue. Transportation revenue was favorably impacted by both higher rates and volumes. The average rate per barrel in the current period was favorably impacted by the mid-year 2014 and 2015 tariff rate increases of 3.9% and 4.6%, respectively, on virtually all of our tariffs and more long-haul shipments at higher rates. Volumes were higher primarily due to 7% higher shipments of gasoline resulting from refinery turnarounds that increased demand on our system and lower gasoline prices that increased overall demand for gasoline, partially offset by 6% lower shipments of distillates due to reduced demand from drilling activities and wet agricultural conditions in the areas served by our assets earlier in the year. Additionally, revenue from our independent terminals increased primarily from two terminal acquisitions during the last twelve months, and revenue from leased storage and our ammonia pipeline increased;

•

an increase in crude oil revenue of $52.1 million primarily due to revenue received in 2015 from BridgeTex for capacity on our Houston area crude oil distribution system and higher crude oil deliveries on our Longhorn pipeline. Shipments on our Longhorn pipeline averaged approximately 255,000 barrels per day in 2015, an increase of approximately 25,000 barrels per day over the same period in 2014. Additionally, terminalling revenue was higher resulting from new leased storage contracts and from a customer buying out of its remaining storage agreement in 2015. Transportation revenue per barrel shipped was lower in the current period due to reduced average tariffs resulting from a lower volume of spot shipments on the Longhorn pipeline system, which ship at a higher rate, and more short-haul movements on our Houston-area crude oil distribution system in 2015; and


•	an increase in marine storage revenue of $7.2 million primarily due to improved storage utilization and higher ancillary fees reflecting increased activities at our marine facilities.

Affiliate management fee revenue decreased $4.8 million due to lower construction management fees related to BridgeTex, as the pipeline became operational in late September 2014.

Operating expenses increased by $37.0 million primarily resulting from:


•	an increase in refined products expenses of $25.7 million primarily due to higher asset integrity spending and higher personnel costs; and


•	an increase in crude oil expenses of $14.0 million primarily due to less favorable product overages (which reduce operating expense), higher pipeline capacity rental fees, higher power costs associated with moving additional volume in 2015 and higher personnel costs; and


•	a decrease in marine storage expenses of $2.4 million primarily attributable to lower asset integrity costs.

Product margin decreased $51.3 million primarily due to higher unrealized losses on our NYMEX contracts, which were partially offset by higher realized margins from our fractionation and butane blending activities. The higher realized margins from our fractionation and butane blending activities improved primarily because the decrease in our average cost of sales more than offset the impact of lower product sales prices.

Earnings of non-controlled entities increased $45.5 million primarily due to our share of earnings from BridgeTex, which began operations in late September 2014.

Depreciation and amortization increased $1.7 million primarily due to expansion capital projects placed into service and a $1.8 million asset impairment charge recognized in 2015, partially offset by the $9.4 million acceleration of depreciation for pipeline, terminal and related assets during 2014 that we later sold.

G&A expense increased $1.5 million primarily due to higher personnel costs from an increase in employee headcount, partially offset by lower costs associated with deferred board of director compensation resulting from a decrease in the price of our limited partner units in 2015.

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Interest expense, net of interest income and interest capitalized, increased $20.0 million in 2015 primarily due to lower capitalized interest as we are no longer capitalizing interest expense related to BridgeTex, which began operations in late September 2014, as well as higher interest related to new debt issuances. Our average outstanding debt increased from $2.9 billion in 2014 to $3.3 billion in 2015 primarily due to borrowings for expansion capital expenditures, including $500.0 million of senior notes issued in March 2015. Our weighted-average interest rate decreased from 5.0% in 2014 to 4.7% in 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.

Other income included $4.6 million of favorable non-cash adjustments for the change in the differential between the current spot price and forward price on fair value hedges associated with our crude oil tank bottoms and linefill assets.

Provision for income taxes was $2.0 million favorable due to a reduction in the franchise tax rate for the state of Texas.

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 nine months ended September 30, 2014 and 2015 to net income, which is its nearest comparable GAAP financial measure, follows (in millions):



	Nine Months Ended September 30,						Increase (Decrease)
	2014			2015			Increase (Decrease)
Net income	$	587.4		$	612.0		$	24.6
Interest expense, net, and provision for income taxes	89.9			107.9			18.0
Depreciation and amortization expense⁽¹⁾	124.2			126.0			1.8
Equity-based incentive compensation expense⁽²⁾	2.9			(2.6		)	(5.5		)
Asset retirements	4.8			4.4			(0.4		)
Commodity-related adjustments:
Derivative gains recognized in the period associated with future product transactions⁽³⁾	(28.7		)	(54.2		)	(25.5		)
Derivative gains (losses) recognized in previous periods associated with product sales completed in the period⁽⁴⁾	(8.1		)	96.1			104.2
Lower-of-cost-or-market adjustments⁽⁵⁾	2.5			(38.7		)	(41.2		)
Total commodity-related adjustments	(34.3		)	3.2			37.5
Cash distributions of non-controlled entities in excess of earnings	3.6			7.7			4.1
Adjusted EBITDA	778.5			858.6			80.1
Interest expense, net, and provision for income taxes	(89.9		)	(107.9		)	(18.0		)
Maintenance capital⁽⁶⁾	(56.2		)	(64.7		)	(8.5		)
DCF	$	632.4		$	686.0		$	53.6


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

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(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 nine months ended September 30, 2014 and 2015 was $17.7 million and $15.2 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 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 is 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. Operating cash flows consist of net income adjusted for certain non-cash items and changes in certain assets and liabilities.

Net cash provided by operating activities was $713.3 million and $724.1 million for the nine months ended September 30, 2014 and 2015, respectively. The $10.8 million increase from 2014 to 2015 was due to higher net income related to activities previously described, partially offset by changes in our working capital and adjustments to non-cash items.

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

Net cash used by investing activities for the nine months ended September 30, 2014 and 2015 was $608.8 million and $606.8 million, respectively. During 2015, we spent $439.7 million for capital expenditures, which included $64.7 million for maintenance capital and $375.0 million for expansion capital. Also during the 2015 period, we acquired a refined products terminal in the Atlanta, Georgia market for $54.7 million and contributed capital of $133.4 million in conjunction with our joint venture capital projects, which we account for as investments in non-controlled entities. During 2014, we spent $237.2 million for capital expenditures, which included $56.2 million for maintenance capital and $181.0 million for expansion capital. Also during the 2014 period, we contributed capital of $378.2 million in conjunction with our joint venture capital projects (primarily BridgeTex), which we account for as investments in non-controlled entities.

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

Net cash used by financing activities for the nine months ended September 30, 2014 and 2015 was $114.9 million and $125.4 million, respectively. During 2015, we paid cash distributions of $489.5 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

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associated tax withholdings of $17.8 million. During 2014, we paid cash distributions of $417.2 million to our unitholders. Additionally, we received net proceeds of $257.7 million from borrowings under long-term notes and $316.0 million from borrowings under our commercial paper program, which were used in part to repay our $250.0 million of 6.45% notes due June 1, 2014, 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 third-quarter 2015 financial results (to be paid in fourth quarter 2015) is $0.7625 per unit. If we meet management's targeted distribution growth of 15% for 2015 and the 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 nine months ended September 30, 2015, our maintenance capital spending was $64.7 million. For 2015, we expect to spend approximately $85.0 million on maintenance capital.

During the first nine months of 2015, we spent $375.0 million for organic growth capital and $133.4 million for capital projects in conjunction with our joint ventures. Additionally, we spent $54.7 million on a refined products terminal acquired in the Atlanta, Georgia market. Based on the progress of expansion projects already underway, we expect to spend approximately $850 million for expansion capital and joint venture capital contributions during 2015, $700 million in 2016 and another $50 million thereafter to complete our current projects. These spending estimates include our contributions for our 40% interest in Saddlehorn Pipeline Company, LLC ("Saddlehorn").

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Liquidity

Consolidated debt at December 31, 2014 and September 30, 2015 was as follows (in thousands, except as otherwise noted):



	December 31, 2014		September 30, 2015		Weighted-Average Interest Rate for the Nine Months Ended September 30, 2015 ⁽¹⁾
Commercial paper⁽²⁾	$	296,942	$	226,966	0.5%
$250.0 million of 5.65% Notes due 2016	250,758		250,440		5.7%
$250.0 million of 6.40% Notes due 2018	257,280		255,731		5.4%
$550.0 million of 6.55% Notes due 2019	567,868		565,064		5.7%
$550.0 million of 4.25% Notes due 2021	556,304		555,601		4.0%
$250.0 million of 3.20% Notes due 2025⁽²⁾	—		249,694		3.2%
$250.0 million of 6.40% Notes due 2037	249,017		249,031		6.4%
$250.0 million of 4.20% Notes due 2042	248,406		248,429		4.2%
$550.0 million of 5.15% Notes due 2043	556,320		556,245		5.1%
$250.0 million of 4.20% Notes due 2045⁽²⁾	—		249,913		4.6%
Total debt	$	2,982,895	$	3,407,114	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 nine-month period ending September 30, 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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unused commitment fee was assessed at a rate from 0.10% to 0.28%, depending on our credit ratings. The unused commitment fee was 0.125% at September 30, 2015. Borrowings under this facility could be used for general partnership purposes, including capital expenditures. As of September 30, 2015, there were no borrowings outstanding under this facility; however, $5.6 million was obligated for letters of credit. Amounts obligated for letters of credit were not reflected as debt on our consolidated balance sheets but decreased our borrowing capacity under the facility. See Recent Developments above for information about amendments made to our revolving credit facility and a new 364-day credit facility entered into after September 30, 2015.

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

Pipeline Tariff Rates. The Federal Energy Regulatory Commission ("FERC") regulates the rates charged on interstate common carrier pipeline operations primarily through an indexing methodology, which establishes the maximum amount by which tariffs can be adjusted each year. Approximately 40% of our refined products tariffs are subject to this indexing methodology while the remaining 60% of our refined products tariffs can be adjusted at our discretion based on competitive factors. The current FERC-approved indexing method is the annual change in the producer price index for finished goods ("PPI-FG") plus 2.65%. Based on this indexing methodology, we increased virtually all of our tariffs by 4.6% on July 1, 2015.

The FERC is currently assessing the new indexing methodology to be used for the 5-year period beginning July 2016. During June 2015, the FERC initially proposed a new index level between PPI-FG plus 2.0% and PPI-FG plus 2.4%, but the new indexing methodology has not yet been finalized. Through September 2015, the change in PPI-FG for 2015 is approximately negative 3.2%. If the change in this index remains at this level for the full year 2015, we may be required to decrease tariffs in markets that are subject to the FERC’s indexing methodology by approximately 1% in July 2016 based on the FERC’s proposed methodology range.

Collective Bargaining Agreement with the United Steel Workers ("USW"). During second quarter 2015, we reached agreement with the USW, which represents approximately 230 employees assigned to our refined products segment. The current collective bargaining agreement with the USW is effective through January 31, 2019.

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 and NYMEX contracts to help manage this commodity price risk. We use forward physical contracts to

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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 NYMEX contracts 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 and for the nine months ended September 30, 2015, our open derivative contracts and the impact of the derivatives we settled during the period 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 September 30, 2015, the cumulative amount of gains from these agreements was $19.4 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 the nine months ended September 30, 2015 was a gain of $4.6 million, which we recognized as other income on our consolidated statement of income.

Open Derivative Contracts Not Designated as Hedges

•

NYMEX contracts covering 4.4 million barrels of refined products related to our butane blending and fractionation activities. These contracts mature between October 2015 and December 2016 and are being accounted for as economic hedges. Through September 30, 2015, the cumulative amount of net unrealized gains associated with these agreements was $52.2 million. We recorded these gains as an adjustment to product sales revenue, all of which was recognized in 2015.

•

NYMEX contracts covering 1.0 million barrels of refined products and crude oil related to inventory we carry that resulted from pipeline product overages. These contracts, which mature between October and February 2016, are being accounted for as economic hedges. Through September 30, 2015, the cumulative amount of net unrealized gains associated with these agreements was $5.9 million. We recorded these gains as an adjustment to operating expense, of which $5.3 million of net gains was recognized in 2014 and $0.6 million of net gains was recognized in 2015.


•	NYMEX contracts covering 1.2 million barrels of butane purchases that mature between October 2015 and December 2016, which are being accounted for as economic hedges. Through September 30, 2015, the cumulative amount of net unrealized losses associated with these agreements was $5.1 million. We recorded these losses as an adjustment to cost of product sales, all of which was recognized in 2015.

Settled Derivative Contracts


•	We settled NYMEX contracts covering 6.1 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 $0.2 million in 2015 related to these contracts, which we recorded as an adjustment to product sales revenue.


•	We settled NYMEX contracts covering 4.5 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 gain of $6.6 million in 2015 on the settlement of these contracts, which we recorded as an adjustment to operating expense.

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•	We settled NYMEX contracts covering 0.6 million barrels related to economic hedges of butane purchases we made during 2015 associated with our butane blending activities. We recognized a loss of $0.7 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 contracts on our results of operations for the respective periods presented (in millions):



	Nine Months Ended September 30, 2014
	Product Sales Revenue		Cost of Product Sales			Operating Expense			Other Income		Net Impact on Net Income
NYMEX gains (losses) recognized during the period that were associated with economic hedges of physical product sales or purchases during the period	$	3.8	$	0.1		$	(0.6	)	$	—	$	3.3
NYMEX gains (losses) recorded during the period that were associated with products that will be or were sold or purchased in future periods	29.9		(3.2		)	1.0			—		27.7
Net impact of NYMEX contracts	$	33.7	$	(3.1	)	$	0.4		$	—	$	31.0



	Nine Months Ended September 30, 2015
	Product Sales Revenue		Cost of Product Sales			Operating Expense		Other Income		Net Impact on Net Income
NYMEX gains (losses) recognized during the period that were associated with economic hedges of physical product sales or purchases during the period	$	0.2	$	(0.7	)	$	6.6	$	—	$	6.1
NYMEX gains (losses) recorded during the period that were associated with products that will be sold or purchased in future periods	52.2		(5.1		)	0.6		4.6		52.3
Net impact of NYMEX contracts	$	52.4	$	(5.8	)	$	7.2	$	4.6	$	58.4

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 September 30, 2014 and 2015, we made purchases of butane from subsidiaries of Targa of $0.1 million and $1.5 million, respectively. For the nine months ended September 30, 2014 and 2015, we made purchases of butane from subsidiaries of Targa of $13.9 million and $14.3 million, respectively. These purchases were based on the then-current index prices. We had recognized payables to Targa of $0.9 million and $1.0 million at December 31, 2014 and September 30, 2015, respectively.

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The management fees we have recognized or will recognize from BridgeTex, Osage Pipe Line Company LLC ("Osage"), Powder Springs Logistics, LLC ("Powder Springs"), Saddlehorn, Seabrook Logistics, LLC ("Seabrook") and Texas Frontera, LLC ("Texas Frontera") are or will be reported as affiliate management fee revenue on our consolidated statements of income.

In third quarter 2015, we purchased surplus pipe from BridgeTex for the amount of $0.6 million. We sold a portion of the pipe purchased from BridgeTex to Saddlehorn for $0.2 million.

We recognized throughput revenue from Double Eagle Pipeline LLC ("Double Eagle") for the three months ended September 30, 2014 and 2015 of $0.7 million and $0.8 million, respectively, and for the nine months ended September 30, 2014 and 2015 of $2.0 million and $2.6 million, respectively, which we included in transportation and terminals revenue. At December 31, 2014 and September 30, 2015, respectively, we recognized a $0.3 million trade accounts receivable from Double Eagle.

New Accounting Pronouncements

In September 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments, to amend the guidance for amounts that are adjusted in a merger or acquisition. This ASU eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. Instead, an acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. This ASU is effective for fiscal years beginning after December 15, 2015 and interim periods within those fiscal years. Our adoption of this standard is not expected to have a material impact on our results of operations, financial position or cash flows.

In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory. Prior to this update, reporting entities were required to measure inventory at the lower of cost or market. Market could be replacement cost, net realizable value, or net realizable value less an approximately normal profit margin. Under this update, inventory is to be measured at the lower of cost or net realizable value, which is defined as the estimated selling price in the ordinary course of business, less reasonable predictable costs of completion, disposal and transportation. This ASU is effective for fiscal years beginning after December 15, 2015 and interim periods within those fiscal years. Our adoption of this standard will not have a material impact on our results of operations, financial position or cash flows.

In July 2015, the FASB extended the effective date of ASU 2014-09, Revenue from Contracts with Customers, from January 1, 2017 to January 1, 2018.

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In April 2015, the FASB issued ASU 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. In August 2015, the FASB issued ASU 2015-15, Interest-Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements–Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015, EITF Meeting, which provides entities with the option of presenting deferred debt issuance costs related to line-of-credit arrangements as an asset, and subsequently amortizing the deferred costs over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. These amendments will have to be applied for reporting periods that start after December 15, 2015, with early adoption permitted. We plan to adopt these amendments in fourth quarter 2015. 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 a 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.

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ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

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 butane futures contracts to help us manage commodity price risk.

Forward physical contracts that qualify for and are elected as normal purchases and sales are accounted for using traditional accrual accounting. As of September 30, 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	$	137.5	3.9
Forward sale contracts	$	0.3	—

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 NYMEX contracts to hedge against changes in the price of butane that we expect to purchase in future periods. At September 30, 2015, we had open NYMEX contracts representing 6.1 million barrels of petroleum products we expect to sell in the future. Additionally, we had open NYMEX contracts for 1.2 million barrels of butane we expect to purchase in the future. At September 30, 2015, the fair value of our open NYMEX contracts was an asset of $78.4 million.

At September 30, 2015, open NYMEX contracts representing 5.4 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 $54.0 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 $54.0 million increase in our operating profit.

At September 30, 2015, we had open NYMEX contracts representing 1.2 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 $12.0 million increase in our operating profit and a $10.00 per barrel decrease in the price of butane would result in a $12.0 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 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.

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Interest Rate Risk

Our use of variable rate debt and any forecasted issuances of fixed rate debt expose us to interest rate risk.

During 2015, we entered into $150.0 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 anticipate issuing in 2016. The fair value of these contracts at September 30, 2015 was a net liability of $0.5 million. We account for these agreements as cash flow hedges. A 0.125% decrease in the interest rates would result in a decrease in the fair value of these contracts of approximately $1.8 million. A 0.125% increase in the interest rates would result in an increase in the fair value of these contracts of approximately $1.7 million.

At September 30, 2015, we had $227.0 million of commercial paper notes outstanding which represents variable rate debt. We can issue up to $1.0 billion of commercial paper, limited by the amounts available under our revolving credit facility. Considering the amount of commercial paper borrowings outstanding at September 30, 2015, our annual interest expense would change by $0.3 million if rates charged by our commercial paper lenders changed by 0.125%.


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 September 30, 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 requirements, 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

Clean Water Act Information Requests and Claims. 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 near Texas City, Texas in February 2011 (the “Texas Release”). In April 2012, we received a similar information request from the EPA pursuant to Section 308 of the Clean Water Act regarding a pipeline release near Nemaha, Nebraska in December 2011 (the “Nebraska Release”). In October 2015, we received a letter from the U.S. Department of Justice (“DOJ Letter”) stating that the Clean Water Act claims arising out of the Texas Release, the Nebraska Release and a pipeline release near El Dorado, Kansas in May 2015, have all been referred to the U.S. Department of Justice for enforcement. The DOJ Letter proposed a settlement of Clean Water Act claims related to the three releases in the form of an enforceable commitment from us to take certain yet to be determined steps to prevent future releases and a civil penalty of $2.8 million. In response to the DOJ Letter, we will engage in discussions with the U.S. Department of Justice in an effort to settle the Clean Water Act claims on terms that are mutually agreeable. While the results cannot be predicted with certainty, we believe the ultimate resolution of these matters 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. 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 could materially adversely affect our business, financial condition and/or operating results.

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

We are exposed to counterparty risk. Nonpayment, commitment termination or nonperformance by our customers, vendors, lenders or derivative counterparties could materially reduce our revenue, impair our liquidity, increase our expenses or otherwise negatively impact our results of operations, financial position or cash flows and our ability to pay cash distributions.

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We are subject to risks of loss resulting from nonpayment or nonperformance by our customers to whom we extend credit. In addition, we frequently undertake capital expenditures based on commitments from customers upon which we expect to realize the expected return on those expenditures, including take-or-pay commitments from our customers, and nonperformance by our customers of those commitments or termination of those commitments resulting from our inability to timely meet our obligations could result in substantial losses to us.

We utilize third-party vendors to provide various functions, including, for example, certain construction activities, engineering services, facility inspections and operation of certain software systems. Using third parties to provide these functions has the effect of reducing our direct control over the services rendered. The failure of one or more of our third-party providers to deliver the expected services on a timely basis, at the prices we expect and as required by contract could result in significant disruptions, costs to our operation or instances of a contractor’s non-compliance with applicable laws and regulations, which could materially adversely affect our business, financial condition, operating results and cash flows.

We also rely to a significant degree on the banks that lend to us under our commercial paper program and revolving credit facility for financial liquidity, and any failure of those banks to perform on their obligations to us could significantly impair our liquidity. Furthermore, nonpayment by the counterparties to our interest rate and commodity derivatives could expose us to additional interest rate or commodity price risk.

Any take-or-pay commitment terminations or substantial increase in the nonpayment or nonperformance by our customers, vendors, lenders or derivative counterparties could have a material adverse effect on our results of operations, financial position and cash flows and our ability to pay cash distributions.


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

None.


ITEM 3.	DEFAULTS UPON SENIOR SECURITIES

None.


ITEM 4.	MINE SAFETY DISCLOSURES

Not applicable.


ITEM 5.	OTHER INFORMATION

Under our limited partnership agreement and the limited liability company agreement of our general partner, the directors and officers of our general partner are indemnified by us for actions associated with being a director or officer of our general partner to the extent permitted under Delaware law. In order to establish clear procedures and parameters with respect to various aspects of indemnification, including, among other things, determinations of entitlement, payment of indemnification and expense advancement amounts and dispute resolution mechanisms, the board of directors of our general partner has approved a form of indemnification agreement for the directors and officers of our general partner and has authorized us and our general partner to enter into indemnification agreements based on such form with the directors and officers of our general partner. The indemnification agreements provide that we and our general partner will indemnify these directors and officers to the fullest extent permitted under Delaware law, subject to certain presumptions and limitations set forth in the agreements. The indemnification agreements also provide that these directors and officers will be entitled to the advancement of expenses, including reasonable attorneys’ fees, as permitted by applicable law and sets forth the procedures for determining entitlement to and obtaining indemnification and expense advancement. The indemnification

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agreements also provide that we must use commercially reasonable efforts to maintain specified director and officer liability insurance coverage. These indemnification agreements were executed and dated as of November 2, 2015.


ITEM 6.	EXHIBITS



Exhibit Number		Description

Exhibit 10.1	—	Form of Indemnification Agreement by and among Magellan Midstream Partners, L.P., Magellan GP, LLC and the directors and officers of Magellan GP, LLC.

*Exhibit 10.2	—	$1,000,000,000 Amended and Restated Credit Agreement dated as of October 27, 2015 among Magellan Midstream Partners, L.P., the Lenders party thereto, Wells Fargo Bank, National Association, as Administrative Agent and an Issuing Bank, JPMorgan Chase Bank, N.A., as Co-Syndication Agent and an Issuing Bank, and SunTrust Bank, as Co-Syndication Agent and an Issuing Bank (filed as Exhibit 10.1 to Form 8-K filed October 28, 2015).

*Exhibit 10.3	—	$250,000,000 364-Day Credit Agreement dated as of October 27, 2015 among Magellan Midstream Partners, L.P., the Lenders party thereto, Wells Fargo Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, N.A., as Co-Syndication Agent, and SunTrust Bank, as Co-Syndication Agent (filed as Exhibit 10.2 to Form 8-K filed October 28, 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 Aaron L. Milford, principal financial officer.

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

Exhibit 32.2	—	Section 1350 Certification of Aaron L. Milford, Chief Financial Officer.

Exhibit 101.INS	—	XBRL Instance Document.

Exhibit 101.SCH	—	XBRL Taxonomy Extension Schema.

Exhibit 101.CAL	—	XBRL Taxonomy Extension Calculation Linkbase.

Exhibit 101.DEF	—	XBRL Taxonomy Extension Definition Linkbase.

Exhibit 101.LAB	—	XBRL Taxonomy Extension Label Linkbase.

Exhibit 101.PRE	—	XBRL Taxonomy Extension Presentation Linkbase.

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*	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 November 3, 2015.



MAGELLAN MIDSTREAM PARTNERS, L.P.

By:		Magellan GP, LLC,
		its general partner

/s/ Aaron L. Milford
Aaron L. Milford
Chief Financial Officer
(Principal Accounting and Financial Officer)

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INDEX TO EXHIBITS




Exhibit Number		Description

Exhibit 10.1	—	Form of Indemnification Agreement by and among Magellan Midstream Partners, L.P., Magellan GP, LLC and the directors and officers of Magellan GP, LLC.

*Exhibit 10.2	—	$1,000,000,000 Amended and Restated Credit Agreement dated as of October 27, 2015 among Magellan Midstream Partners, L.P., the Lenders party thereto, Wells Fargo Bank, National Association, as Administrative Agent and an Issuing Bank, JPMorgan Chase Bank, N.A., as Co-Syndication Agent and an Issuing Bank, and SunTrust Bank, as Co-Syndication Agent and an Issuing Bank (filed as Exhibit 10.1 to Form 8-K filed October 28, 2015).

*Exhibit 10.3	—	$250,000,000 364-Day Credit Agreement dated as of October 27, 2015 among Magellan Midstream Partners, L.P., the Lenders party thereto, Wells Fargo Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, N.A., as Co-Syndication Agent, and SunTrust Bank, as Co-Syndication Agent (filed as Exhibit 10.2 to Form 8-K filed October 28, 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 Aaron L. Milford, principal financial officer.

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

Exhibit 32.2	—	Section 1350 Certification of Aaron L. Milford, Chief Financial Officer.

Exhibit 101.INS	—	XBRL Instance Document.

Exhibit 101.SCH	—	XBRL Taxonomy Extension Schema.

Exhibit 101.CAL	—	XBRL Taxonomy Extension Calculation Linkbase.

Exhibit 101.DEF	—	XBRL Taxonomy Extension Definition Linkbase.

Exhibit 101.LAB	—	XBRL Taxonomy Extension Label Linkbase.

Exhibit 101.PRE	—	XBRL Taxonomy Extension Presentation Linkbase.

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*	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.