Magellan Midstream Partners, L.P. - Quarter Report: 2017 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, 2017



£	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, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x Accelerated filer £ Non-accelerated filer £ (Do not check if a smaller reporting company)

Smaller reporting company £ Emerging growth company £

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. £

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 1, 2017, there were 228,024,556 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	8
	3.	Segment Disclosures	9
	4.	Investments in Non-Controlled Entities	12
	5.	Inventory	14
	6.	Employee Benefit Plans	14
	7.	Debt	17
	8.	Derivative Financial Instruments	18
	9.	Commitments and Contingencies	23
	10.	Long-Term Incentive Plan	24
	11.	Partners’ Capital and Distributions	25
	12.	Fair Value	26
	13.	Related Party Transactions	27
	14.	Subsequent Events	28
ITEM 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Introduction		29
	Recent Developments		29
	Results of Operations		30
	Distributable Cash Flow		37
	Liquidity and Capital Resources		38
	Off-Balance Sheet Arrangements		39
	Environmental		39
	Other Items		40
ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	41
ITEM 4.		CONTROLS AND PROCEDURES	41
Forward-Looking Statements			42
PART II OTHER INFORMATION
ITEM 1.		LEGAL PROCEEDINGS	44
ITEM 1A.		RISK FACTORS	45
ITEM 2.		UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	45
ITEM 3.		DEFAULTS UPON SENIOR SECURITIES	45
ITEM 4.		MINE SAFETY DISCLOSURES	45
ITEM 5.		OTHER INFORMATION	45
ITEM 6.		EXHIBITS	45
Index to Exhibits			46
Signatures			47

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,
	2016			2017			2016			2017
Transportation and terminals revenue	$	413,433		$	446,935		$	1,175,748		$	1,272,845
Product sales revenue	133,356			121,010			403,607			548,634
Affiliate management fee revenue	4,993			4,903			11,140			12,883
Total revenue	551,782			572,848			1,590,495			1,834,362
Costs and expenses:
Operating	134,915			165,368			392,011			442,254
Cost of product sales	118,242			121,819			327,530			440,670
Depreciation and amortization	47,081			49,909			134,137			146,103
General and administrative	35,584			37,202			110,814			120,876
Total costs and expenses	335,822			374,298			964,492			1,149,903
Earnings of non-controlled entities	18,576			31,151			51,543			78,173
Operating profit	234,536			229,701			677,546			762,632
Interest expense	50,163			51,895			142,573			154,653
Interest income	(302		)	(240		)	(1,067		)	(788		)
Interest capitalized	(7,877		)	(3,424		)	(21,143		)	(10,804		)
Gain on sale of asset	—			(18,505		)	—			(18,505		)
Gain on exchange of interest in non-controlled entity	—			—			(28,144		)	—
Other expense (income)	(2,737		)	549			(6,447		)	3,762
Income before provision for income taxes	195,289			199,426			591,774			634,314
Provision for income taxes	738			926			2,294			2,678
Net income	$	194,551		$	198,500		$	589,480		$	631,636
Basic net income per limited partner unit	$	0.85		$	0.87		$	2.59		$	2.77
Diluted net income per limited partner unit	$	0.85		$	0.87		$	2.59		$	2.77
Weighted average number of limited partner units outstanding used for basic net income per unit calculation⁽¹⁾	227,960			228,199			227,913			228,167
Weighted average number of limited partner units outstanding used for diluted net income per unit calculation⁽¹⁾	227,999			228,260			227,947			228,222

(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,
	2016			2017			2016			2017
Net income	$	194,551		$	198,500		$	589,480		$	631,636
Other comprehensive income:
Derivative activity:
Net gain (loss) on cash flow hedges⁽¹⁾	(3,169		)	(228		)	(24,278		)	(1,735		)
Reclassification of net (gain) loss on cash flow hedges to income⁽¹⁾	512			740			1,288			2,219
Changes in employee benefit plan assets and benefit obligations recognized in other comprehensive income:
Amortization of prior service credit⁽²⁾	(973		)	(45		)	(2,920		)	(136		)
Amortization of actuarial loss⁽²⁾	1,452			1,568			4,145			4,779
Settlement cost⁽²⁾	202			289			202			2,015
Total other comprehensive income (loss)	(1,976		)	2,324			(21,563		)	7,142
Comprehensive income	$	192,575		$	200,824		$	567,917		$	638,778

⁽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, 2016			September 30, 2017
ASSETS				(Unaudited)
Current assets:
Cash and cash equivalents	$	14,701		$	1,381
Trade accounts receivable	105,689			128,765
Other accounts receivable	25,761			13,349
Inventory	134,378			168,762
Energy commodity derivatives contracts, net	—			1,189
Energy commodity derivatives deposits	49,899			31,735
Other current assets	39,966			62,247
Total current assets	370,394			407,428
Property, plant and equipment	6,783,737			7,121,856
Less: Accumulated depreciation	1,507,996			1,638,351
Net property, plant and equipment	5,275,741			5,483,505
Investments in non-controlled entities	931,255			1,066,940
Long-term receivables	23,870			27,166
Goodwill	53,260			53,260
Other intangibles (less accumulated amortization of $2,136 and $1,308 at December 31, 2016 and September 30, 2017, respectively)	51,976			52,845
Other noncurrent assets	65,577			12,303
Total assets	$	6,772,073		$	7,103,447

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	77,248		$	120,990
Accrued payroll and benefits	45,690			40,082
Accrued interest payable	65,643			42,257
Accrued taxes other than income	50,166			49,844
Environmental liabilities	10,249			9,870
Deferred revenue	101,891			116,697
Accrued product liabilities	51,600			119,572
Energy commodity derivatives contracts, net	30,738			14,898
Current portion of long-term debt, net	—			251,439
Other current liabilities	48,431			44,065
Total current liabilities	481,656			809,714
Long-term debt, net	4,087,192			4,051,411
Long-term pension and benefits	71,461			66,410
Other noncurrent liabilities	25,868			29,799
Environmental liabilities	13,791			10,818
Commitments and contingencies
Partners’ capital:
Limited partner unitholders (227,784 units and 228,025 units outstanding at December 31, 2016 and September 30, 2017, respectively)	2,193,346			2,229,394
Accumulated other comprehensive loss	(101,241		)	(94,099		)
Total partners’ capital	2,092,105			2,135,295
Total liabilities and partners’ capital	$	6,772,073		$	7,103,447

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,
	2016			2017
Operating Activities:
Net income	$	589,480		$	631,636
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	134,137			146,103
Loss (gain) on sale and retirement of assets	5,397			(10,924		)
Earnings of non-controlled entities	(51,543		)	(78,173		)
Distributions of earnings from investments in non-controlled entities	50,047			78,562
Equity-based incentive compensation expense	14,737			14,183
Settlement cost, amortization of prior service credit and actuarial loss	1,427			6,658
Gain on exchange of interest in non-controlled entity	(28,144		)	—
Changes in operating assets and liabilities:
Trade accounts receivable and other accounts receivable	(49,014		)	(14,413		)
Inventory	7,857			(34,384		)
Energy commodity derivatives contracts, net of derivatives deposits	637			1,135
Accounts payable	5,850			15,576
Accrued payroll and benefits	(12,725		)	(5,608		)
Accrued interest payable	(2,393		)	(23,386		)
Accrued taxes other than income	2,115			(322		)
Accrued product liabilities	(6,183		)	67,972
Deferred revenue	17,191			14,806
Current and noncurrent environmental liabilities	(5,649		)	(3,352		)
Other current and noncurrent assets and liabilities	(34,229		)	(11,497		)
Net cash provided by operating activities	638,995			794,572
Investing Activities:
Additions to property, plant and equipment, net⁽¹⁾	(517,810		)	(418,239		)
Proceeds from sale and disposition of assets	6,098			44,303
Investments in non-controlled entities	(174,900		)	(114,078		)
Distributions in excess of earnings of non-controlled entities	4,500			71,867
Net cash used by investing activities	(682,112		)	(416,147		)
Financing Activities:
Distributions paid	(548,388		)	(596,854		)
Net commercial paper borrowings (repayments)	(244,963		)	218,984
Borrowings under long-term notes	1,142,997			—
Debt placement costs	(10,500		)	—
Net payment on financial derivatives	(19,287		)	—
Payments associated with settlement of equity-based incentive compensation	(14,376		)	(13,875		)
Net cash provided (used) by financing activities	305,483			(391,745		)
Change in cash and cash equivalents	262,366			(13,320		)
Cash and cash equivalents at beginning of period	28,731			14,701
Cash and cash equivalents at end of period	$	291,097		$	1,381

Supplemental non-cash investing and financing activities:
Contribution of property, plant and equipment to a non-controlled entity	$	—		$	93,051
Issuance of limited partner units in settlement of equity-based incentive plan awards	$	7,092		$	1,669

⁽¹⁾ Additions to property, plant and equipment	$	(514,205	)	$	(443,439	)
Changes in accounts payable and other current liabilities related to capital expenditures	(3,605		)	25,200
Additions to property, plant and equipment, net	$	(517,810	)	$	(418,239	)

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. Magellan Midstream Partners, L.P. is a Delaware limited partnership and its 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 its 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, 2017, our asset portfolio, including the assets of our joint ventures, consisted of:


•	our refined products segment, comprised of our 9,700-mile refined products pipeline system with 53 terminals as well as 26 independent terminals not connected to our pipeline system and our 1,100-mile ammonia pipeline system;


•	our crude oil segment, comprised of approximately 2,200 miles of crude oil pipelines, our condensate splitter and storage facilities with an aggregate storage capacity of approximately 27 million barrels, of which approximately 16 million barrels are used for contract 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.

Terminology common in our industry includes the following terms, which describe products that we transport, store and distribute through our pipelines and terminals:


•	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, 2016, 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, 2017, the results of operations for the three and nine months ended September 30, 2016 and 2017 and cash flows for the nine months ended September 30, 2016 and 2017. The results of operations for the nine months ended September 30, 2017 are not necessarily indicative of the results to be expected for the full year ending December 31, 2017 for several reasons. Profits from our butane 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 impacts the profits from our commodity activities and, to a lesser extent, the volume of petroleum products we transport 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 U.S. generally accepted accounting principles (“GAAP”). 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, 2016.

In September 2017, we recognized an $18.5 million gain in connection with the sale of an inactive terminal in Chicago, Illinois, which is not included in operating profit because the gain is not related to our ongoing operations.

Use of Estimates

The preparation of our consolidated financial statements in conformity with 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.

New Accounting Pronouncements

In March 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-07, Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This ASU requires companies that offer postretirement benefits to present the service cost, which is the amount an employer has to set aside each period to cover the benefits, in the same line item with other employee compensation costs. Other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. Additionally, only the service cost component will be eligible for capitalization when applicable.

Public companies must comply with the new requirements under ASU 2017-07 for fiscal years that start after December 15, 2017, and the amendments must be applied retrospectively except for the capitalization change, which should be applied prospectively. Early adoption is allowed, and we elected to adopt ASU 2017-07 as of January 1, 2017. Prior to adoption, we expensed all components of pension expense through salaries and wages, which impacted operating income. We are now recording only the service component of pension expense to salaries and wages, with the remainder of the expense being recorded to other income and expense below operating profit.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Comparative prior periods have been restated for this change. The changes were not material to our financial statements.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). This ASU requires lessees to recognize a right of use asset and lease liability on the balance sheet for all leases, with the exception of short-term leases. The new accounting model for lessors remains largely the same, although some changes have been made to align it with the new lessee model and the new revenue recognition guidance. This update also requires companies to include additional disclosures regarding their lessee and lessor agreements. Public companies are required to adopt the standard for financial reporting periods that start after December 15, 2018, although early adoption is permitted. We are currently in the process of evaluating the impact this new standard will have on our financial statements.

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 became effective for fiscal years beginning after December 15, 2016 and interim periods within those fiscal years. We adopted this standard on January 1, 2017, and it did not have a material impact on our results of operations, financial position or cash flows as we have historically measured our inventory at the lower of cost or net realizable value, as described above.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This ASU amends the existing accounting standards for revenue recognition and is based on the principle that revenue should be recognized to depict the transfer of goods or services to a customer at an amount that reflects the consideration a company expects to receive in exchange for those goods or services. We will adopt this ASU as required on January 1, 2018, and we expect to use the modified retrospective method that will result in a cumulative effect adjustment as of the date of adoption. We do not expect the adoption of this ASU to have a material impact on our consolidated financial statements.


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 mark-to-market adjustments from exchange-based futures contracts. See Note 8 – Derivative Financial Instruments for a discussion of our commodity hedging strategies and how our futures contracts impact product sales revenue.

For the three and nine months ended September 30, 2016 and 2017, product sales revenue included the following (in thousands):



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2017			2016			2017
Physical sale of petroleum products	$	146,006		$	168,346		$	412,045		$	553,076
Change in value of futures contracts	(12,650		)	(47,336		)	(8,438		)	(4,442		)
Total product sales revenue	$	133,356		$	121,010		$	403,607		$	548,634

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


3.	Segment Disclosures

Our reportable segments are strategic business units that offer different products and services. Our segments are managed separately 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”) expense that management does not consider when evaluating the core profitability of our separate operating segments.



	Three Months Ended September 30, 2016
	(in thousands)
	Refined Products		Crude Oil			Marine Storage			Intersegment Eliminations			Total
Transportation and terminals revenue	$	267,339	$	100,113		$	46,182		$	(201	)	$	413,433
Product sales revenue	105,834		24,750			2,772			—			133,356
Affiliate management fee revenue	218		4,416			359			—			4,993
Total revenue	373,391		129,279			49,313			(201		)	551,782
Operating expenses	95,535		24,547			16,325			(1,492		)	134,915
Cost of product sales	93,761		24,108			373			—			118,242
(Earnings) losses of non-controlled entities	272		(18,180		)	(668		)	—			(18,576		)
Operating margin	183,823		98,804			33,283			1,291			317,201
Depreciation and amortization expense	28,432		9,333			8,025			1,291			47,081
G&A expense	22,853		8,445			4,286			—			35,584
Operating profit	$	132,538	$	81,026		$	20,972		$	—		$	234,536

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Three Months Ended September 30, 2017
	(in thousands)
	Refined Products		Crude Oil			Marine Storage			Intersegment Eliminations			Total
Transportation and terminals revenue	$	289,030	$	116,305		$	42,501		$	(901	)	$	446,935
Product sales revenue	107,175		12,370			1,465			—			121,010
Affiliate management fee revenue	353		3,703			847			—			4,903
Total revenue	396,558		132,378			44,813			(901		)	572,848
Operating expenses	118,665		31,163			17,723			(2,183		)	165,368
Cost of product sales	103,391		16,630			1,798			—			121,819
(Earnings) losses of non-controlled entities	700		(31,244		)	(607		)	—			(31,151		)
Operating margin	173,802		115,829			25,899			1,282			316,812
Depreciation and amortization expense	27,469		12,584			8,574			1,282			49,909
G&A expense	23,808		9,266			4,128			—			37,202
Operating profit	$	122,525	$	93,979		$	13,197		$	—		$	229,701



	Nine Months Ended September 30, 2016
	(in thousands)
	Refined Products		Crude Oil			Marine Storage			Intersegment Eliminations			Total
Transportation and terminals revenue	$	739,931	$	303,181		$	132,837		$	(201	)	$	1,175,748
Product sales revenue	372,061		26,465			5,081			—			403,607
Affiliate management fee revenue	422		9,686			1,032			—			11,140
Total revenue	1,112,414		339,332			138,950			(201		)	1,590,495
Operating expenses	279,822		66,228			49,808			(3,847		)	392,011
Cost of product sales	300,009		26,469			1,052			—			327,530
(Earnings) losses of non-controlled entities	352		(49,870		)	(2,025		)	—			(51,543		)
Operating margin	532,231		296,505			90,115			3,646			922,497
Depreciation and amortization expense	78,523		28,264			23,704			3,646			134,137
G&A expense	68,589		27,333			14,892			—			110,814
Operating profit	$	385,119	$	240,908		$	51,519		$	—		$	677,546

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Nine Months Ended September 30, 2017
	(in thousands)
	Refined Products		Crude Oil			Marine Storage			Intersegment Eliminations			Total
Transportation and terminals revenue	$	808,818	$	329,813		$	136,702		$	(2,488	)	$	1,272,845
Product sales revenue	509,068		34,876			4,690			—			548,634
Affiliate management fee revenue	1,035		10,311			1,537			—			12,883
Total revenue	1,318,921		375,000			142,929			(2,488		)	1,834,362
Operating expenses	312,911		89,991			45,753			(6,401		)	442,254
Cost of product sales	396,292		37,814			6,564			—			440,670
(Earnings) losses of non-controlled entities	167		(76,388		)	(1,952		)	—			(78,173		)
Operating margin	609,551		323,583			92,564			3,913			1,029,611
Depreciation and amortization expense	81,440		35,947			24,803			3,913			146,103
G&A expense	75,429		30,376			15,071			—			120,876
Operating profit	$	452,682	$	257,260		$	52,690		$	—		$	762,632

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


4.	Investments in Non-Controlled Entities

Our investments in non-controlled entities at September 30, 2017 were comprised of:



Entity		Ownership Interest
BridgeTex Pipeline Company, LLC (“BridgeTex”)		50%
Double Eagle Pipeline LLC (“Double Eagle”)		50%
HoustonLink Pipeline Company, LLC (“HoustonLink”)		50%
MVP Terminalling, LLC (“MVP”)		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%

Recently-Formed Company

MVP was formed in September 2017 to construct and develop a refined products marine storage facility along the Houston Ship Channel in Pasadena, Texas. We own a 50% equity interest in MVP, with an affiliate of Valero Energy Corporation (“Valero”) owning the other 50% interest. We serve as construction manager and operator of the MVP facility. The initial phase of this facility is expected to be operational in early 2019. Upon formation of MVP, we contributed $93.1 million of property, plant and equipment (“PP&E”) to this entity. Concurrently, Valero contributed cash of $46.5 million, which was distributed to us as reimbursement for its portion of the PP&E we contributed. The $46.5 million is reflected as distributions in excess of earnings of non-controlled entities on our consolidated statement of cash flows.

We serve as operator of BridgeTex, HoustonLink, MVP, Powder Springs, Saddlehorn, Texas Frontera and the pipeline activities of Seabrook. We receive fees for management services as well as reimbursement or payment to us for certain direct operational payroll and other overhead costs. The management fees we have received are reported as affiliate management fee revenue on our consolidated statements of income. Cost reimbursements we receive from these entities in connection with our operating services are included as reductions to costs and expenses on our consolidated statements of income and totaled $1.2 million and $0.7 million during the three months ended September 30, 2016 and 2017, respectively, and $2.7 million and $3.1 million during the nine months ended September 30, 2016 and 2017, respectively.

We recorded the following revenue from certain of these non-controlled entities in our consolidated statements of income (in millions):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2017		2016		2017
Transportation and terminals revenue:
BridgeTex, capacity lease	$	8.9	$	9.1	$	26.6	$	27.0
Double Eagle, throughput revenue	$	0.9	$	1.3	$	2.5	$	3.1
Saddlehorn, storage revenue	$	—	$	0.5	$	—	$	1.6

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Our consolidated balance sheets reflected the following balances related to our investments in non-controlled entities (in millions):



	December 31, 2016				September 30, 2017
	Trade Accounts Receivable		Other Accounts Receivable		Trade Accounts Receivable		Other Accounts Receivable
Double Eagle	$	0.3	$	—	$	0.5	$	—
MVP	$	—	$	—	$	—	$	0.5
Saddlehorn	$	—	$	0.1	$	—	$	0.1

In addition to the transactions noted above, we incurred charges of $9.0 million and $12.9 million for transportation of crude oil at published spot tariff rates on the BridgeTex pipeline during the three and nine months ended September 30, 2017, respectively. We recorded these charges as cost of product sales in our consolidated statements of income. We also purchased inventory from BridgeTex valued at $2.8 million in September 2017. We recognized an affiliate payable to BridgeTex on our consolidated balance sheets as of September 30, 2017 in the amount of $5.6 million in connection with this activity.

In January 2017, we entered into an agreement to guarantee our 50% pro rata share, up to $50.0 million, of obligations under Powder Springs’ credit facility. As of September 30, 2017, our consolidated balance sheet reflected a $0.8 million other current liability and a corresponding increase in our investment in non-controlled entities on our consolidated balance sheet to reflect the fair value of this guarantee.

In February 2016, we transferred a 50% membership interest in Osage Pipe Line Company, LLC (“Osage”) to an affiliate of HollyFrontier Corporation. In conjunction with this transaction, we entered into several commercial agreements with affiliates of HollyFrontier Corporation, which we recorded at that time as a $43.7 million intangible asset and an $8.3 million other receivable on our consolidated balance sheets. The intangible asset will be amortized over the 20-year life of the contracts received. We recognized a $28.1 million non-cash gain in 2016 in relation to this transaction.

The financial results from MVP and Texas Frontera are included in our marine storage segment, the financial results from BridgeTex, Double Eagle, HoustonLink, 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, each as earnings of non-controlled entities.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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




Investments at December 31, 2016	$	931,255
Additional investment⁽¹⁾	207,941
Earnings of non-controlled entities:
Proportionate share of earnings	79,949
Amortization of excess investment and capitalized interest	(1,776		)
Earnings of non-controlled entities	78,173
Less:
Distributions of earnings from investments in non-controlled entities	78,562
Distributions in excess of earnings of non-controlled entities⁽²⁾	71,867
Investments at September 30, 2017	$	1,066,940

(1) Includes our $93.1 million contribution of PP&E to MVP.

(2) Includes the $46.5 million distribution to us from MVP as reimbursement for the PP&E we contributed, as well as an additional distribution of $6.2 million not related to the ongoing operations of non-controlled entities.


5.	Inventory

Inventory at December 31, 2016 and September 30, 2017 was as follows (in thousands):



	December 31, 2016		September 30, 2017
Refined products	$	54,285	$	51,667
Transmix	28,319		45,160
Liquefied petroleum gases	24,868		51,540
Crude oil	20,839		13,884
Additives	6,067		6,511
Total inventory	$	134,378	$	168,762


6.	Employee Benefit Plans

We sponsor a defined contribution plan in which we match our employees' qualifying contributions, resulting in additional expense to us. Expenses related to the defined contribution plan were $2.4 million and $2.0 million for the three months ended September 30, 2016 and 2017, respectively, and $7.8 million and $7.4 million for the nine months ended September 30, 2016 and 2017, respectively.

Additionally, we sponsor two union pension plans that cover certain union employees and a pension plan for all non-union employees, and a postretirement benefit plan for selected employees. Net periodic benefit expense for the three and nine months ended September 30, 2016 and 2017 was as follows (in thousands):

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	Three Months Ended						Three Months Ended
	September 30, 2016						September 30, 2017
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Components of net periodic benefit costs:
Service cost	$	4,555		$	53		$	5,125		$	51
Interest cost⁽¹⁾	1,992			148			2,466			111
Expected return on plan assets⁽¹⁾	(2,235		)	—			(2,566		)	—
Amortization of prior service credit⁽¹⁾	(45		)	(928		)	(45		)	—
Amortization of actuarial loss⁽¹⁾	1,161			291			1,406			162
Settlement cost⁽¹⁾	202			—			289			—
Net periodic benefit cost (credit)	$	5,630		$	(436	)	$	6,675		$	324



	Nine Months Ended						Nine Months Ended
	September 30, 2016						September 30, 2017
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Components of net periodic benefit costs:
Service cost	$	13,648		$	176		$	15,373		$	182
Interest cost⁽¹⁾	5,970			368			7,398			356
Expected return on plan assets⁽¹⁾	(6,694		)	—			(7,699		)	—
Amortization of prior service credit⁽¹⁾	(135		)	(2,785		)	(136		)	—
Amortization of actuarial loss⁽¹⁾	3,485			660			4,217			562
Settlement cost⁽¹⁾	202			—			2,015			—
Net periodic benefit cost (credit)	$	16,476		$	(1,581	)	$	21,168		$	1,100

⁽¹⁾Upon adoption of ASU 2017-07, Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, these components of net periodic benefit cost (credit) are reported on the consolidated statements of income as other expense (income). See Note 1 – Organization, Description of Business and Basis of Presentation - New Accounting Pronouncements for further details about this accounting change.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The changes in AOCL related to employee benefit plan assets and benefit obligations for the three and nine months ended September 30, 2016 and 2017 were as follows (in thousands):



	Three Months Ended						Three Months Ended
	September 30, 2016						September 30, 2017
Gains (Losses) Included in AOCL	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Beginning balance	$	(60,045	)	$	(5,433	)	$	(54,138	)	$	(7,481	)
Amortization of prior service credit	(45		)	(928		)	(45		)	—
Amortization of actuarial loss	1,161			291			1,406			162
Settlement cost	202			—			289			—
Ending balance	$	(58,727	)	$	(6,070	)	$	(52,488	)	$	(7,319	)



	Nine Months Ended						Nine Months Ended
	September 30, 2016						September 30, 2017
Gains (Losses) Included in AOCL	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Beginning balance	$	(62,279	)	$	(3,945	)	$	(58,584	)	$	(7,881	)
Amortization of prior service credit	(135		)	(2,785		)	(136		)	—
Amortization of actuarial loss	3,485			660			4,217			562
Settlement cost	202			—			2,015			—
Ending balance	$	(58,727	)	$	(6,070	)	$	(52,488	)	$	(7,319	)

Contributions estimated to be paid into the plans in 2017 are $26.5 million and $0.4 million for the pension and other postretirement benefit plans, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


7.	Debt

Long-term debt at December 31, 2016 and September 30, 2017 was as follows (in thousands):



	December 31, 2016			September 30, 2017
Commercial paper	$	50,000		$	269,000
6.40% Notes due 2018	250,000			250,000
6.55% Notes due 2019	550,000			550,000
4.25% Notes due 2021	550,000			550,000
3.20% Notes due 2025	250,000			250,000
5.00% Notes due 2026	650,000			650,000
6.40% Notes due 2037	250,000			250,000
4.20% Notes due 2042	250,000			250,000
5.15% Notes due 2043	550,000			550,000
4.20% Notes due 2045	250,000			250,000
4.25% Notes due 2046	500,000			500,000
Face value of long-term debt	4,100,000			4,319,000
Unamortized debt issuance costs⁽¹⁾	(26,948		)	(25,106		)
Net unamortized debt premium⁽¹⁾	6,530			4,241
Net unamortized amount of gains from historical fair value hedges⁽¹⁾	7,610			4,715
Long-term debt, net, including current portion	4,087,192			4,302,850
Less: Current portion of long-term debt, net	—			251,439
Long-term debt, net	$	4,087,192		$	4,051,411

(1) Debt issuance costs, note discounts and premiums and realized gains and losses of historical fair value hedges are being amortized or accreted to the applicable notes over the respective lives of those notes.

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

2017 Debt Offering

See Note 14 – Subsequent Events for information about our October 2017 debt issuance.

Other Debt

Revolving Credit Facilities. At September 30, 2017, the total borrowing capacity under our revolving credit facility with a maturity date of October 27, 2020 was $1.0 billion. Any borrowings outstanding under this facility are classified as long-term debt on our consolidated balance sheets. Borrowings under this facility are unsecured and bear interest at LIBOR plus a spread ranging from 1.000% to 1.625% based on our credit ratings. Additionally, an unused commitment fee is assessed at a rate between 0.100% and 0.275% depending on our credit ratings. The unused commitment fee was 0.125% at September 30, 2017. Borrowings under this facility may be used for general partnership purposes, including capital expenditures. As of both December 31, 2016 and September 30, 2017, there were no borrowings outstanding under this facility, with $6.3 million obligated for letters of credit. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheets, but decrease our borrowing capacity under this facility. In October 2017, we extended the maturity date of this facility (see Note 14 – Subsequent Events, for further information).

At September 30, 2017, the total borrowing capacity under our 364-day credit facility was $250.0 million, and the unused commitment fee was 0.1%. As of both December 31, 2016 and September 30, 2017, there were no

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

borrowings outstanding under this facility. This credit facility matured on October 19, 2017 and was not renewed.

Commercial Paper Program. We have a commercial paper program under which we may issue commercial paper notes in an amount up to the available capacity under our $1.0 billion revolving credit facility. The maturities of the commercial paper notes vary, but may not exceed 397 days from the date of issuance. Because the commercial paper we can issue is limited to amounts available under our revolving credit facility, amounts outstanding under the program are classified as long-term debt. 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 weighted-average interest rate for commercial paper borrowings based on the number of days outstanding was 0.8% for the year ended December 31, 2016 and 1.3% for the nine months ended September 30, 2017.


8.	Derivative Financial Instruments

Interest Rate Derivatives

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

We have entered into $100.0 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 2018. The fair values of these contracts at September 30, 2017 were recorded on our balance sheets as other current assets of $12.4 million, with the offset recorded to other comprehensive income. We account for these agreements as cash flow hedges.

Commodity Derivatives

Hedging Strategies

Our butane blending activities produce gasoline, and we can reasonably estimate the timing and quantities of sales of these products. We use a combination of exchange-based commodities futures contracts and forward purchase and sale contracts to help manage commodity price changes and mitigate the risk of decline in the product margin realized from our butane blending activities. Further, certain of our other commercial operations generate petroleum products, and we also use futures contracts to hedge against price changes for some of these commodities.

Forward physical purchase and sale contracts that qualify for and are elected as normal purchases and sales are accounted for using traditional accrual accounting.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The futures 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 fair 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 fair 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 are 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 nine months ended September 30, 2016 and 2017, none of the commodity hedging contracts we entered into qualified for or were designated as cash flow hedges.

We use futures contracts designated as economic hedges for accounting purposes to hedge against changes in the price of petroleum products that we expect to sell in the future. Period changes in the fair value of these agreements are recognized currently in earnings as adjustments to product sales revenue.

We also use futures contracts designated as economic hedges for accounting purposes to hedge against changes in the price of butane and natural gasoline we expect to purchase in the future. Period changes in the fair value of these agreements are recognized currently in earnings as adjustments to cost of product sales.

Additionally, we held certain crude oil tank bottoms which we classified as noncurrent assets and included with other noncurrent assets on our consolidated balance sheets. We used futures contracts to hedge against changes in the fair value of these assets. We recorded the effective portion of the gains or losses for those contracts that qualify as fair value hedges as adjustments to the asset being hedged and the ineffective portions as well as amounts excluded from the assessment of hedge effectiveness as adjustments to other income or expense. During September 2017, as a result of contract renegotiation, we sold a portion of the tank bottoms, settled the related hedges and transferred the remaining tank bottoms from noncurrent assets to PP&E.

As outlined in the table below, our open futures contracts at September 30, 2017 were as follows:



Type of Contract/Accounting Methodology	Product Represented by the Contract and Associated Barrels	Maturity Dates
Futures - Economic Hedges	5.5 million barrels of refined products and crude oil	Between October 2017 and April 2018
Futures - Economic Hedges	2.1 million barrels of butane and natural gasoline	Between October 2017 and April 2018

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Energy Commodity Derivatives Contracts and Deposits Offsets

At December 31, 2016, we had made margin deposits of $49.9 million for our future contracts with our counterparties, which were recorded as current assets under energy commodity derivatives deposits on our consolidated balance sheets. At September 30, 2017, we had made margin deposits of $31.7 million for our future contracts with our counterparties, which were recorded as current assets under energy commodity derivatives deposits on our consolidated balance sheets. We have the right to offset the combined fair values of our open futures 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 futures contracts separately from the related margin deposits on our consolidated balance sheets. Additionally, we have the right to offset the fair values of our futures contracts 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, 2016 and September 30, 2017 (in thousands):



	December 31, 2016
Description	Gross Amounts of Recognized Liabilities			Gross Amounts of Assets Offset in the Consolidated Balance Sheets		Net Amounts of Liabilities Presented in the Consolidated Balance Sheets			Margin Deposit Amounts Not Offset in the Consolidated Balance Sheets		Net Asset Amount⁽¹⁾
Energy commodity derivatives	$	(36,798	)	$	6,060	$	(30,738	)	$	49,899	$	19,161



	September 30, 2017
Description	Gross Amounts of Recognized Liabilities			Gross Amounts of Assets Offset in the Consolidated Balance Sheets		Net Amounts of Liabilities Presented in the Consolidated Balance Sheets			Margin Deposit Amounts Not Offset in the Consolidated Balance Sheets		Net Asset Amount⁽¹⁾
Energy commodity derivatives	$	(32,685	)	$	18,976	$	(13,709	)	$	31,735	$	18,026


(1)	Amount represents the maximum 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, 2016 and 2017 were as follows (in thousands):



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Derivative Losses Included in AOCL	2016			2017			2016			2017
Beginning balance	$	(50,459	)	$	(34,804	)	$	(30,126	)	$	(34,776	)
Net gain (loss) on cash flow hedges	(3,169		)	(228		)	(24,278		)	(1,735		)
Reclassification of net loss on cash flow hedges to income	512			740			1,288			2,219
Ending balance	$	(53,116	)	$	(34,292	)	$	(53,116	)	$	(34,292	)

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Income Statements

The following tables provide a summary of the effect on our consolidated statements of income for the three and nine months ended September 30, 2016 and 2017 of derivatives accounted for under ASC 815-30, Derivatives and Hedging—Cash Flow Hedges, that were designated as hedging instruments (in thousands):



	Interest Rate Contracts
	Amount of Loss Recognized in AOCL on Derivative			Location of Loss Reclassified from AOCL into Income	Amount of Loss Reclassified from AOCL into Income
	Amount of Loss Recognized in AOCL on Derivative			Location of Loss Reclassified from AOCL into Income	Effective Portion			Ineffective Portion
Three Months Ended September 30, 2016	$	(3,169	)	Interest expense	$	(512	)	$	—



Three Months Ended September 30, 2017	$	(228	)	Interest expense	$	(740	)	$	—



Nine Months Ended September 30, 2016	$	(24,278	)	Interest expense	$	(1,288	)	$	—



Nine Months Ended September 30, 2017	$	(1,735	)	Interest expense	$	(2,219	)	$	—

As of September 30, 2017, the net loss estimated to be classified to interest expense over the next twelve months from AOCL is approximately $3.0 million.

Until September 2017, we had used futures contracts designated as fair value hedges under ASC 815-25, Derivatives and Hedging–Fair Value Hedges, to hedge against changes in the fair value of crude oil that was contractually reserved as tank bottoms and included with other noncurrent assets on our consolidated balance sheets. The effective portions of the fair value gains or losses on these futures contracts were offset by fair value gains or losses on the tank bottoms. There was no ineffectiveness recognized on these hedges. The cash flows from settled contracts were recorded in operating activities in our consolidated statements of cash flows. The gains (losses) on these futures contracts and the underlying tank bottoms were as follows (in millions):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2017		2016		2017
Gain (loss) recognized in other income/expense on derivatives (futures contracts)	0.4		(1.7	)	(5.8	)	5.1
Loss (gain) recognized in other income/expense on hedged item (tank bottoms)	(0.4	)	1.7		5.8		(5.1	)

The differential between the current spot price and forward price was excluded from the assessment of hedge effectiveness for these fair value hedges. For the three months ended September 30, 2016 and 2017, we recognized a gain of $0.3 million and $0.7 million, respectively, and for the nine months ended September 30, 2016 and 2017, we recognized a gain of $4.5 million and $2.4 million, respectively, for the amounts we excluded from the assessment of effectiveness of these fair value hedges, which we reported as other (income) expense on our consolidated statements of income.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table provides a summary of the effect on our consolidated statements of income for the three and nine months ended September 30, 2016 and 2017 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 Instrument	Location of Gain (Loss) Recognized on Derivatives	2016			2017			2016			2017
Futures contracts	Product sales revenue	$	(12,650	)	$	(47,336	)	$	(8,438	)	$	(4,442	)
Futures contracts	Operating expenses	4,212			663			(1,192		)	663
Futures contracts	Cost of product sales	831			19,660			3,643			19,713
	Total	$	(7,607	)	$	(27,013	)	$	(5,987	)	$	15,934

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

Balance Sheets

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, 2016 and September 30, 2017 (in thousands):

December 31, 2016

Asset Derivatives

Liability Derivatives

Derivative Instrument

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Futures contracts

Energy commodity derivatives contracts, net

—

Energy commodity derivatives contracts, net

3,079

Interest rate contracts

Other noncurrent assets

14,114

Other noncurrent liabilities

—

Total

14,114

Total

3,079

September 30, 2017

Asset Derivatives

Liability Derivatives

Derivative Instrument

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Futures contracts

Energy commodity derivatives contracts, net

—

Interest rate contracts

Other current assets

12,379

Other current liabilities

—

Total

12,397

Total

—

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following tables provide a summary of the fair value of derivatives accounted for under ASC 815, Derivatives and Hedging, which are presented on a net basis in our consolidated balance sheets, that were not designated as hedging instruments as of December 31, 2016 and September 30, 2017 (in thousands):

December 31, 2016

Asset Derivatives

Liability Derivatives

Derivative Instrument

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Futures contracts

Energy commodity derivatives contracts, net

6,060

Energy commodity derivatives contracts, net

33,719

September 30, 2017

Asset Derivatives

Liability Derivatives

Derivative Instrument

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Futures contracts

Energy commodity derivatives contracts, net

18,958

Energy commodity derivatives contracts, net

32,685


9.	Commitments and Contingencies

Environmental Liabilities

Liabilities recognized for estimated environmental costs were $24.0 million and $20.7 million at December 31, 2016 and September 30, 2017, respectively. We have classified environmental liabilities as current or noncurrent based on management’s estimates regarding the timing of actual payments. Environmental expenses recognized as a result of changes in our environmental liabilities are generally included in operating expenses on our consolidated statements of income. Environmental expenses were $0.3 million and $3.0 million for the three months ended September 30, 2016 and 2017, respectively, and $4.6 million and $7.5 million for the nine months ended September 30, 2016 and 2017, respectively.

Environmental Receivables

Receivables from insurance carriers and other third parties related to environmental matters were $4.1 million at December 31, 2016, of which $0.6 million and $3.5 million were recorded to other accounts receivable and long-term receivables, respectively, on our consolidated balance sheets. Receivables from insurance carriers and other third parties related to environmental matters were $6.3 million at September 30, 2017, of which $0.7 million and $5.6 million were recorded to other accounts receivable and long-term receivables, respectively, on our consolidated balance sheets.

Other

See Note 4 – Investments in Non-Controlled Entities for detail of our guarantee on behalf of Powder Springs.

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 results of operations, financial position or cash flows.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


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 11.9 million of our limited partner units. The compensation committee of our general partner’s board of directors administers our LTIP. The estimated units remaining available under the LTIP at September 30, 2017 total 2.6 million.

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2017		2016		2017
Performance-based awards:
2014 awards	$	1,780	$	—	$	6,168	$	28
2015 awards	1,208		164		3,679		3,388
2016 awards	1,097		1,266		3,240		4,907
2017 awards	—		1,298		—		3,796
Time-based awards	593		738		1,650		2,064
Total	$	4,678	$	3,466	$	14,737	$	14,183

Allocation of LTIP expense on our consolidated statements of income:
G&A expense	$	4,637	$	3,430	$	14,623	$	14,062
Operating expense	41		36		114		121
Total	$	4,678	$	3,466	$	14,737	$	14,183

On February 2, 2017, 207,445 phantom unit awards were issued pursuant to our LTIP. These grants included both performance-based and time-based phantom unit awards and have a three-year vesting period that will end on December 31, 2019.

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 basic net income per unit is due to the impact of: (i) the phantom units issued to non-employee directors 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 that have not yet vested.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


11.	Partners’ Capital and Distributions

Partners’ Capital

In May 2017, we filed a prospectus supplement to the shelf registration statement for our continuous equity offering program (which we refer to as an at-the-market program, or “ATM”) pursuant to which we may issue up to $750.0 million of common units in amounts, at prices and on terms to be determined by market conditions at the time. The net proceeds from any sales under the ATM, after deducting the sales agents’ commissions and our offering expenses, will be used for general partnership purposes, including repayment of indebtedness or capital expenditures. No units were issued pursuant to this program during the current period.

The following table details the changes in the number of our limited partner units outstanding from January 1, 2017 through September 30, 2017:



Limited partner units outstanding on January 1, 2017		227,783,916
January 2017–Settlement of 2014 awards^(a)		216,679
During 2017–Other^(b)		23,961
Limited partner units outstanding on September 30, 2017		228,024,556

(a) Limited partner units issued to settle long-term incentive plan awards to certain employees that vested on December 31, 2016.

(b) Limited partner units issued to settle the equity-based retainers paid to certain independent directors of our general partner and the final payment of deferred director compensation to a former director.

Distributions

Distributions we paid during 2016 and 2017 were as follows (in thousands, except per unit amounts):



Payment Date	Per Unit Cash Distribution Amount			Total Cash Distribution to Limited Partners
02/12/2016		$	0.7850		$	178,808
05/13/2016		0.8025			182,797
08/12/2016		0.8200			186,783
Through 09/30/2016		2.4075			548,388
11/14/2016		0.8375			190,769
Total		$	3.2450		$	739,157

02/14/2017		$	0.8550		$	194,961
05/15/2017		0.8725			198,951
08/14/2017		0.8900			202,942
Through 09/30/2017		2.6175			596,854
11/14/2017⁽¹⁾		0.9050			206,362
Total		$	3.5225		$	803,216

(a) Our general partner’s board of directors declared this cash distribution in October 2017 to be paid on November 14, 2017 to unitholders of record at the close of business on November 2, 2017.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


12.	Fair Value

Fair Value Methods and Assumptions - Financial Assets and Liabilities.

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


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

•

Interest rate contracts. These include forward-starting interest rate swap agreements to hedge against the risk of variability of interest payments on future debt. These contracts are carried at fair value on our consolidated balance sheets and are valued based on an assumed exchange, at the end of each period, in an orderly transaction with a market participant in the market in which the financial instrument is traded. The exchange value was calculated using present value techniques on estimated future cash flows based on forward interest rate curves. See Note 8 – Derivative Financial Instruments for further disclosures regarding these contracts.


•	Long-term receivables. These primarily include payments receivable under a direct-financing leasing arrangement and cost reimbursement payments receivable. These receivables were recorded at fair value on our consolidated balance sheets, using then-current market rates to estimate the present value of future cash flows.

•

Debt. The fair value of our publicly traded notes was based on the prices of those notes at December 31, 2016 and September 30, 2017; 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 fair value measurements recorded or disclosed as of December 31, 2016 and September 30, 2017 based on the three levels established by ASC 820, Fair Value Measurements and Disclosures (in thousands):



	December 31, 2016
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	$	(30,738	)	$	(30,738	)	$	(30,738	)	$	—		$	—
Interest rate contracts	$	14,114		$	14,114		$	—		$	14,114		$	—
Long-term receivables	$	23,870		$	23,870		$	—		$	—		$	23,870
Debt	$	(4,087,192	)	$	(4,262,321	)	$	—		$	(4,262,321	)	$	—

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	September 30, 2017
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	$	(13,709	)	$	(13,709	)	$	(13,709	)	$	—		$	—
Interest rate contracts	$	12,379		$	12,379		$	—		$	12,379		$	—
Long-term receivables	$	27,166		$	27,166		$	—		$	—		$	27,166
Debt	$	(4,302,850	)	$	(4,562,570	)	$	—		$	(4,562,570	)	$	—


13.	Related Party Transactions

Stacy P. Methvin is an independent member of our general partner’s board of directors and is also a director of one of our customers. We received tariff revenue from this customer of $4.3 million and $4.1 million for the three months ended September 30, 2016 and 2017, respectively, and $12.0 million and $12.5 million for the nine months ended September 30, 2016 and 2017, respectively. We recorded receivables of $1.4 million from this customer at both December 31, 2016 and September 30, 2017. 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 transactions with our joint ventures.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


14.	Subsequent Events

Recognizable events

No recognizable events occurred subsequent to September 30, 2017.

Non-recognizable events

Cash Distribution. In October 2017, our general partner’s board of directors declared a quarterly distribution of $0.905 per unit for the period of July 1, 2017 through September 30, 2017. This quarterly cash distribution will be paid on November 14, 2017 to unitholders of record on November 2, 2017. The total cash distributions expected to be paid under this declaration are approximately $206.4 million.

Debt Offering. On October 3, 2017, we issued $500.0 million of 4.20% notes due 2047 in an underwritten public offering. The notes were issued at 99.341% of par. Net proceeds from this offering were approximately $491.6 million, after underwriting discounts and offering expenses of $5.1 million. The net proceeds from this offering were used to repay borrowings outstanding under our commercial paper program. The remaining proceeds may be used for general partnership purposes, including capital expenditures.

Credit Facility Extension. On October 26, 2017, we extended the maturity date of our revolving credit facility with a total borrowing capacity of $1.0 billion to October 26, 2022. All other terms remain the same.

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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, 2017, our asset portfolio, including the assets of our joint ventures, consisted of:


•	our refined products segment, comprised of our 9,700-mile refined products pipeline system with 53 terminals as well as 26 independent terminals not connected to our pipeline system and our 1,100-mile ammonia pipeline system;


•	our crude oil segment, comprised of approximately 2,200 miles of crude oil pipelines, our condensate splitter and storage facilities with an aggregate storage capacity of approximately 27 million barrels, of which approximately 16 million barrels are used for contract 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, 2016.

Recent Developments

Cash Distribution. In October 2017, the board of directors of our general partner declared a quarterly cash distribution of $0.905 per unit for the period of July 1, 2017 through September 30, 2017. This quarterly cash distribution will be paid on November 14, 2017 to unitholders of record on November 2, 2017. Total distributions expected to be paid under this declaration are approximately $206.4 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 revenue. However, 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, 2016 compared to Three Months Ended September 30, 2017



	Three Months Ended September 30,						Variance Favorable (Unfavorable)
	2016			2017			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)
Transportation and terminals revenue:
Refined products	$	267.3		$	289.0		$	21.7		8
Crude oil	100.1			116.3			16.2			16
Marine storage	46.2			42.5			(3.7		)	(8)
Intersegment eliminations	(0.1		)	(0.8		)	(0.7		)	n/a
Total transportation and terminals revenue	413.5			447.0			33.5			8
Affiliate management fee revenue	5.0			4.9			(0.1		)	(2)
Operating expenses:
Refined products	95.6			118.7			(23.1		)	(24)
Crude oil	24.6			31.2			(6.6		)	(27)
Marine storage	16.3			17.8			(1.5		)	(9)
Intersegment eliminations	(1.6		)	(2.3		)	0.7			44
Total operating expenses	134.9			165.4			(30.5		)	(23)
Product margin:
Product sales revenue	133.3			121.0			(12.3		)	(9)
Cost of product sales	118.2			121.9			(3.7		)	(3)
Product margin	15.1			(0.9		)	(16.0		)	(106)
Earnings of non-controlled entities	18.5			31.2			12.7			69
Operating margin	317.2			316.8			(0.4		)	—
Depreciation and amortization expense	47.0			49.9			(2.9		)	(6)
G&A expense	35.6			37.2			(1.6		)	(4)
Operating profit	234.6			229.7			(4.9		)	(2)
Interest expense (net of interest income and interest capitalized)	42.0			48.3			(6.3		)	(15)
Gain on sale of asset	—			(18.5		)	18.5			n/a
Other expense (income)	(2.7		)	0.5			(3.2		)	n/a
Income before provision for income taxes	195.3			199.4			4.1			2
Provision for income taxes	0.7			0.9			(0.2		)	(29)
Net income	$	194.6		$	198.5		$	3.9		2
Operating Statistics:
Refined products:
Transportation revenue per barrel shipped	$	1.503		$	1.521
Volume shipped (million barrels):
Gasoline	72.7			75.8
Distillates	37.3			41.0
Aviation fuel	7.2			6.7
Liquefied petroleum gases	4.1			3.9
Total volume shipped	121.3			127.4
Crude oil:
Magellan 100%-owned assets:
Transportation revenue per barrel shipped	$	1.189		$	1.332
Volume shipped (million barrels)	50.7			48.4
Crude oil terminal average utilization (million barrels per month)	14.8			14.9
Select joint venture pipelines:
BridgeTex - volume shipped (million barrels)⁽¹⁾	20.6			25.7
Saddlehorn - volume shipped (million barrels)⁽²⁾	1.2			4.4
Marine storage:
Marine terminal average utilization (million barrels per month)	24.3			22.5

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

(2) These volumes reflect the total shipments for the Saddlehorn pipeline, which began operations in September 2016 and is owned 40% by us.

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Transportation and terminals revenue increased $33.5 million resulting from:

•

an increase in refined products revenue of $21.7 million. Shipments increased in the current period primarily due to stronger demand for refined products in large part due to higher distillate demand in crude oil production regions and increased volumes from our Little Rock pipeline extension, which commenced commercial operations in July 2016. Additionally, the current period benefited from a one-time customer payment associated with a contract dispute settlement and higher storage and other ancillary service fees along our pipeline system due to increased customer activity;

•

an increase in crude oil revenue of $16.2 million primarily due to contributions from our new condensate splitter at Corpus Christi that began commercial operations in June 2017. We also benefited from higher volumes on our Longhorn pipeline as shippers utilized historical credits in the prior year period (earned by shipping in excess of their minimum commitments in the past) that were set to expire in the third quarter of 2016; and


•	a decrease in marine storage revenue of $3.7 million primarily due to the impact of Hurricane Harvey, which resulted in lower ancillary fees reflecting decreased customer activities and lower storage fees due to delayed project work and some tank damage in third quarter 2017. Otherwise, higher storage rates partially offset lower utilization during the current period.

Operating expenses increased by $30.5 million primarily resulting from:


•	an increase in refined products expenses of $23.1 million primarily due to less favorable product overages (which reduce operating expenses), higher asset integrity spending related to the timing of maintenance work and higher environmental accruals for historical remediation sites;


•	an increase in crude oil expenses of $6.6 million primarily due to costs associated with our new condensate splitter that began commercial operations in June 2017 and higher power costs for pipeline movements; and


•	an increase in marine storage expenses of $1.5 million primarily due to higher environmental remediation accruals and clean-up work related to Hurricane Harvey, partially offset by more favorable product overages.

Product sales revenue resulted primarily from our butane blending activities, transmix fractionation, crude oil marketing activities and the sale of tender deductions and product gains from our operations. We utilize futures contracts to hedge against changes in the price of petroleum products we expect to sell in future periods, as well as to hedge against changes in the price of butane we expect to purchase. See Note 8 – Derivative Financial Instruments in Item 1 of Part I for a discussion of our hedging strategies and how our use of futures contracts impacts our product margin, and Other Items – Commodity Derivative Agreements – Impact of Commodity Derivatives on Results of Operations below for more information about our futures contracts. Product margin decreased $16.0 million primarily due to higher butane costs, resulting in lower butane blending

margins, as well as lower margins from crude oil marketing activities due primarily to transportation charges we paid to BridgeTex Pipeline Company, LLC (“BridgeTex”), which we record as cost of product sales.

Earnings of non-controlled entities increased $12.7 million primarily due to increased earnings from BridgeTex mainly attributable to incremental spot shipments (including spot shipments by us; see Note 4 – Investments in Non-Controlled Entities for information about spot shipments that we made on the BridgeTex pipeline in third quarter 2017), as well as additional shipments from BridgeTex’s new Eaglebine origin, and higher earnings from Saddlehorn Pipeline Company, LLC (“Saddlehorn”), which began operating during September 2016.

Depreciation and amortization expense increased $2.9 million primarily due to commencement of depreciation of expansion capital projects recently placed into service.

G&A expense increased $1.6 million primarily due to higher prospecting costs for potential expansion projects.

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Interest expense, net of interest income and interest capitalized, increased $6.3 million in third quarter 2017, primarily due to lower capitalized interest and higher outstanding debt in the current period. Our average outstanding debt increased from $4.0 billion in third quarter 2016 to $4.3 billion in third quarter 2017 primarily due to borrowings for expansion capital expenditures. Our weighted-average interest rate of 4.7% in third quarter 2017 was lower than the 4.9% rate incurred in third quarter 2016.

In third quarter 2017, we recognized an $18.5 million gain in connection with the sale of an inactive terminal in Chicago, Illinois.

Other expense (income) was $3.2 million unfavorable primarily due to the 2016 period benefiting from a break-up fee related to a potential acquisition.

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Nine Months Ended September 30, 2016 compared to Nine Months Ended September 30, 2017



	Nine Months Ended September 30,						Variance Favorable (Unfavorable)
	2016			2017			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)
Transportation and terminals revenue:
Refined products	$	739.9		$	808.8		$	68.9		9
Crude oil	303.2			329.8			26.6			9
Marine storage	132.8			136.7			3.9			3
Intersegment eliminations	(0.1		)	(2.4		)	(2.3		)	n/a
Total transportation and terminals revenue	1,175.8			1,272.9			97.1			8
Affiliate management fee revenue	11.1			12.9			1.8			16
Operating expenses:
Refined products	279.9			312.9			(33.0		)	(12)
Crude oil	66.2			90.0			(23.8		)	(36)
Marine storage	49.8			45.8			4.0			8
Intersegment eliminations	(3.9		)	(6.4		)	2.5			64
Total operating expenses	392.0			442.3			(50.3		)	(13)
Product margin:
Product sales revenue	403.6			548.6			145.0			36
Cost of product sales	327.5			440.7			(113.2		)	(35)
Product margin	76.1			107.9			31.8			42
Earnings of non-controlled entities	51.5			78.2			26.7			52
Operating margin	922.5			1,029.6			107.1			12
Depreciation and amortization expense	134.1			146.1			(12.0		)	(9)
G&A expense	110.8			120.9			(10.1		)	(9)
Operating profit	677.6			762.6			85.0			13
Interest expense (net of interest income and interest capitalized)	120.4			143.1			(22.7		)	(19)
Gain on sale of asset	—			(18.5		)	18.5			n/a
Gain on exchange of interest in non-controlled entity	(28.1		)	—			(28.1		)	(100)
Other expense (income)	(6.5		)	3.7			(10.2		)	n/a
Income before provision for income taxes	591.8			634.3			42.5			7
Provision for income taxes	2.3			2.7			(0.4		)	(17)
Net income	$	589.5		$	631.6		$	42.1		7
Operating Statistics:
Refined products:
Transportation revenue per barrel shipped	$	1.451		$	1.489
Volume shipped (million barrels):
Gasoline	204.9			218.7
Distillates	110.0			119.6
Aviation fuel	19.6			20.2
Liquefied petroleum gases	9.9			9.6
Total volume shipped	344.4			368.1
Crude oil:
Magellan 100%-owned assets:
Transportation revenue per barrel shipped	$	1.325		$	1.412
Volume shipped (million barrels)	139.5			137.0
Crude oil terminal average utilization (million barrels per month)	14.7			15.5
Select joint venture pipelines:
BridgeTex - volume shipped (million barrels)⁽¹⁾	58.7			66.4
Saddlehorn - volume shipped (million barrels)⁽²⁾	1.2			12.1
Marine storage:
Marine terminal average utilization (million barrels per month)	23.6			23.4

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

(2) These volumes reflect the total shipments for the Saddlehorn pipeline, which began operations in September 2016 and is owned 40% by us.

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Transportation and terminals revenue increased $97.1 million resulting from:

•

an increase in refined products revenue of $68.9 million. Shipments increased in the current period primarily due to increased volumes from our Little Rock pipeline extension, which commenced commercial operations in July 2016, and stronger demand for refined products. The average rate per barrel in the current period was favorably impacted by the mid-year 2016 and 2017 tariff adjustments. Additionally, the current period benefited from a one-time customer payment associated with a contract dispute settlement and higher storage and other ancillary service fees along our pipeline system due to increased customer activity;


•	an increase in crude oil revenue of $26.6 million primarily due to contributions from our new condensate splitter at Corpus Christi that began commercial operations in June 2017, higher deficiency revenue for volume committed but not moved on our Houston distribution system and higher volumes on our Longhorn pipeline; and


•	an increase in marine storage revenue of $3.9 million primarily due to higher storage rates and additional ancillary fees reflecting increased customer activities at our marine facilities, partially offset by slightly lower utilization mainly due to timing of maintenance work.

Operating expenses increased by $50.3 million primarily resulting from:

•

an increase in refined products expenses of $33.0 million primarily due to higher asset integrity spending related to the timing of maintenance work, rental costs for a pipeline segment we began leasing in third quarter 2016 in connection with our Little Rock pipeline, higher compensation costs and less favorable product overages (which reduce operating expenses), partially offset by favorable property taxes;


•	an increase in crude oil expenses of $23.8 million primarily due to less favorable product overages, higher compensation and other costs associated with our new condensate splitter that began commercial operations in June 2017 and more asset integrity spending during the current year; and


•	a decrease in marine storage expenses of $4.0 million primarily due to favorable product overages.

Product margin increased $31.8 million primarily due to recognition of gains on futures contracts in the current year compared to losses in the prior year, partially offset by lower margins on product sales. See Other Items—Commodity Derivative Agreements—Impact of Commodity Derivatives on Results of Operations below for more information about our futures contracts.

Earnings of non-controlled entities increased $26.7 million primarily due to earnings from Saddlehorn, which began operating during third quarter 2016. Additionally, earnings from BridgeTex were higher mainly attributable to incremental spot shipments (including spot shipments by us; see Note 4 - Investments in Non-Controlled Entities for information about spot shipments that we made on the BridgeTex pipeline), as well as additional shipments from BridgeTex’s new Eaglebine origin.

Depreciation and amortization expense increased $12.0 million primarily due to commencement of depreciation of expansion capital projects recently placed into service.

G&A expense increased $10.1 million primarily due to higher compensation costs resulting from an increase in employee headcount mainly as a result of expansion projects, as well as higher prospecting costs.

Interest expense, net of interest income and interest capitalized, increased $22.7 million in 2017, primarily due to higher outstanding debt and lower capitalized interest in the current period. Our average outstanding debt increased from $3.8 billion in 2016 to $4.2 billion in 2017 primarily due to borrowings for expansion capital expenditures. Our weighted-average interest rate of 4.7% in 2017 was lower than the 4.9% rate incurred in 2016.

In 2017, we recognized an $18.5 million gain in connection with the sale of an inactive terminal in Chicago, Illinois.

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In 2016, we recognized a $28.1 million non-cash gain related to the transfer of our 50% membership interest in Osage. See Note 4 – Investments in Non-Controlled Entities of the consolidated financial statements included in Item 1 of this report for more details regarding this transaction.

Other expense (income) was $10.2 million unfavorable due to higher pension related costs in the current period, including higher pension settlements, and a less favorable non-cash adjustment in 2017 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. Additionally, the 2016 period benefited from a break-up fee related to a potential acquisition.

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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, 2016 and 2017 to net income, which is its nearest comparable GAAP financial measure, follows (in millions):



	Nine Months Ended September 30,						Increase (Decrease)
	2016			2017			Increase (Decrease)
Net income	$	589.5		$	631.6		$	42.1
Interest expense, net	120.4			143.1			22.7
Depreciation and amortization	134.1			146.1			12.0
Equity-based incentive compensation⁽¹⁾	0.4			0.3			(0.1		)
Loss on sale and retirement of assets	5.4			7.6			2.2
Gain on sale of asset⁽²⁾	—			(18.5		)	(18.5		)
Gain on exchange of interest in non-controlled entity⁽³⁾	(28.1		)	—			28.1
Commodity-related adjustments:
Derivative (gains) losses recognized in the period associated with future product transactions⁽⁵⁾	10.1			13.5			3.4
Derivative gains (losses) recognized in previous periods associated with product sales completed in the period⁽⁵⁾	38.6			(25.5		)	(64.1		)
Inventory valuation adjustments⁽⁶⁾	(2.8		)	4.0			6.8
Total commodity-related adjustments	45.9			(8.0		)	(53.9		)
Cash distributions received from non-controlled entities in excess of earnings⁽⁷⁾	3.0			19.5			16.5
Other⁽⁴⁾	3.9			3.8			(0.1		)
Adjusted EBITDA	874.5			925.5			51.0
Interest expense, net, excluding debt issuance cost amortization	(118.1		)	(140.6		)	(22.5		)
Maintenance capital⁽⁸⁾	(86.1		)	(71.8		)	14.3
DCF	$	670.3		$	713.1		$	42.8

(1)

Because we intend to satisfy vesting of unit awards under our equity-based incentive compensation plan with the issuance of limited partner units, expenses related to this plan generally are deemed non-cash and added back for DCF purposes. Total equity-based incentive compensation expense for the nine months ended September 30, 2016 and 2017 was $14.7 million and $14.2 million, respectively. However, the figures above include adjustments of $14.4 million and $13.9 million, respectively, for cash payments associated with our equity-based incentive compensation plan, which primarily include tax withholdings.


(2)	In September 2017, we recognized an $18.5 million gain in connection with the sale of an inactive terminal in Chicago, Illinois, which has been deducted from the calculation of DCF because it is not related to our ongoing operations.

(3)

In February 2016, we transferred our 50% membership interest in Osage to an affiliate of HollyFrontier Corporation (“HFC”). In conjunction with this transaction, we entered into several commercial agreements with affiliates of HFC, which were recorded as intangible assets and other receivables on our consolidated balance sheets. We recorded a $28.1 million non-cash gain in relation to this transaction.

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(4)	In conjunction with the February 2016 Osage transaction, HFC agreed to make certain payments to us until HFC completes a connection to our El Paso terminal. These payments replace distributions we would have received had the Osage transaction not occurred and are, therefore, included in our calculation of DCF.

(5)

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 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.


(6)	We adjust the amount of lower-of-cost-or-market adjustments related to inventory and firm purchase commitments and valuations of short positions recognized each period as these are non-cash items. In subsequent periods when we physically sell or purchase the related products, we adjust DCF for the valuation adjustments previously recognized.


(7)	The cash distributions received from non-controlled entities in excess of earnings only includes cash flows from ongoing operations of those entities. See Note 4 – Investments in Non-Controlled Entities in Item 1 of Part I of this report for more detailed information.


(8)	Maintenance capital expenditures 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 $639.0 million and $794.6 million for the nine months ended September 30, 2016 and 2017, respectively. The $155.6 million increase in 2017 was due to changes in our working capital, higher net income as previously described and adjustments for non-cash items.

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

Net cash used by investing activities for the nine months ended September 30, 2016 and 2017 was $682.1 million and $416.1 million, respectively. During 2017, we incurred $443.4 million for capital expenditures, which included $71.8 million for maintenance capital and $371.6 million for expansion capital. Also during the 2017 period, we contributed capital of $114.1 million in conjunction with our joint venture capital projects, which we account for as investments in non-controlled entities. During 2016, we incurred $514.2 million for capital expenditures, which included $86.1 million for maintenance capital and $428.1 million for expansion capital. Also during the 2016 period, we contributed capital of $174.9 million in conjunction with our joint venture capital projects.

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 provided by financing activities for the nine months ended September 30, 2016 was $305.5 million, and net cash used by financing activities for the nine months ended September 30, 2017 was $391.7 million. During 2017, we have paid cash distributions of $596.9 million to our unitholders. Additionally, net commercial paper borrowings during the 2017 period were $219.0 million. Also, in January 2017, the cumulative amounts of the 2014 equity-based incentive compensation awards were settled by issuing 216,679 limited partner units and distributing those units to the long-term incentive plan (“LTIP”) participants, resulting in payments primarily associated with tax withholdings of $13.9 million. During 2016, we paid cash distributions of $548.4 million to our unitholders. Additionally, we received net proceeds of $1.1 billion 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. Net commercial paper repayments during 2016 totaled $245.0 million. In connection with certain of the borrowings under long-term notes, we paid $19.3 million in settlement of associated interest rate swap agreements. Also, in February 2016, the cumulative amounts of the 2013 equity-based incentive compensation

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awards were settled by issuing 350,552 limited partner units and distributing those units to the LTIP participants, resulting in payments of associated tax withholdings of $14.4 million.

The quarterly distribution amount related to our third quarter 2017 financial results (to be paid in fourth quarter 2017) is $0.905 per unit. If we are able to meet management’s targeted distribution growth of 8% for 2017 and the number of outstanding limited partner units remains at 228.0 million, total cash distributions of approximately $818 million will be paid to our unitholders related to 2017 earnings. Management believes we will have sufficient DCF 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 DCF; and

•

Expansion capital expenditures. These expenditures are undertaken primarily to generate incremental DCF 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, for example, capital expenditures that increase storage or throughput volumes or develop pipeline connections to new supply sources.

For the nine months ended September 30, 2017, our maintenance capital spending was $71.8 million. For 2017, we expect to spend approximately $95 million on maintenance capital.

During the first nine months of 2017, we spent $371.6 million for organic growth capital and contributed $114.1 million for capital projects in conjunction with our joint ventures. Based on the progress of expansion projects already underway, we expect to spend approximately $600 million for expansion capital during 2017, with an additional $800 million in 2018 and $350 million in 2019 to complete our current projects, including our recently-announced projects (see Other Items, below).

Liquidity

Cash generated from operations is our primary source of liquidity for funding debt service, maintenance capital expenditures and quarterly distributions to our unitholders. Additional liquidity for purposes other than quarterly distributions, such as expansion capital expenditures and debt repayments, is available through borrowings under our commercial paper program and revolving credit facility, as well as from other borrowings or issuances of debt or limited partner units (see Note 7 – Debt and Note 11 – Partners’ Capital and Distributions of the consolidated financial statements included in Item 1 of Part I of this report for detail of our borrowings and changes in partners’ capital). If capital markets do not permit us to issue additional debt and equity securities, our business may be adversely affected, and we may not be able to acquire additional assets and businesses, fund organic growth projects or continue paying cash distributions at the current level.

Off-Balance Sheet Arrangements

None.

Environmental

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

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Other Items

Pasadena Marine Terminal Joint Venture. MVP Terminalling, LLC (“MVP”) was formed in September 2017 to construct and develop a refined products marine storage facility along the Houston Ship Channel in Pasadena, Texas. The facility will initially include five million barrels of storage, truck loading facilities and two proprietary ship docks. We own a 50% equity interest in MVP, with an affiliate of Valero Energy Corporation (“Valero”) owning the other 50% interest. We serve as construction manager and operator of the MVP facility. A portion of this facility is expected to be operational in early 2019, with the remainder expected to be operational in early 2020. The project is estimated to cost approximately $820 million, which will be funded equally by capital contributions from us and Valero.

East Houston to Hearne, TX Pipeline. In September 2017, we announced plans to expand our refined products pipeline system to handle incremental demand for transportation of gasoline, diesel fuel and jet fuel to central and north Texas markets. Supported by long-term customer commitments, we plan to build an approximately 135-mile pipeline from our terminal in East Houston to Hearne, Texas. We and Valero will each own an undivided joint interest in the pipeline, and we will be the construction manager and operator. In addition, we are making related enhancements to our existing pipeline and terminal infrastructure to handle the incremental volume. Our share of the project is estimated to cost approximately $375 million, with the new pipeline capacity expected to be operational in mid-2019.

Delaware Basin Crude Oil and Condensate Pipeline. Also in September 2017, we announced plans to begin construction of a new Delaware Basin pipeline originating in Wink, Texas to handle delivery of crude oil and condensate to Crane, Texas. The new Wink pipeline will be approximately 60 miles and will have an initial capacity of 250,000 barrels per day, with the ability to expand to more than 600,000 barrels per day if warranted by industry demand. We expect this project to cost approximately $150 million and to be operational in mid-2019.

Impact of Hurricane Harvey. During the third quarter of 2017, Hurricane Harvey hit the Texas Gulf Coast, disrupting our operations located in the Houston and Corpus Christi areas for a limited time. No significant asset damage occurred, and the impacted facilities are now operational. We currently estimate the total negative DCF impact of Hurricane Harvey to be approximately $20 million, net of expected insurance reimbursements. Of the total, approximately $10 million reduced third-quarter DCF ($8 million of which negatively impacted third-quarter net income) with the remainder associated with clean-up and repair activities to be completed in future periods.

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 exchange-based futures contracts to help manage this commodity price risk. We use forward physical contracts to purchase butane and sell refined products. We account for these forward physical contracts as normal purchase and sale contracts, using traditional accrual accounting. We use futures contracts to hedge against changes in prices of refined products and crude oil that we expect to sell and of butane that we expect to purchase in future periods. We use and account for those futures contracts that qualify for hedge accounting treatment as either cash flow or fair value hedges, and we use and account for those futures contracts that do not qualify for hedge accounting treatment as economic hedges.

As of September 30, 2017, our open derivative contracts and the impact of the derivatives we settled during the period were comprised of futures contracts used to hedge sales and purchases of refined products, crude oil and butane related to our tender deductions, product overages, butane blending, fractionation and certain crude oil inventory activities. These contracts were accounted for as economic hedges, with the change in fair value of contracts that hedge future sales recorded to product sales, and the change in fair value of contracts that hedge future purchases recorded to cost of product sales.

For further information regarding the quantities of refined products and crude oil hedged at September 30, 2017 and the fair value of open hedge contracts at that date, please see Item 3. Quantitative and Qualitative Disclosures about Market Risk.

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



	Nine Months Ended September 30, 2016
	Product Sales Revenue			Cost of Product Sales		Operating Expense			Other Income		Net Impact on Net Income
Gains (losses) recorded on open futures contracts during the period	$	(20.6	)	$	3.5	$	(2.0	)	$	4.5	$	(14.6	)
Gains (losses) recognized on settled futures contracts during the period	12.2			0.1		0.8			—		13.1
Net impact of futures contracts	$	(8.4	)	$	3.6	$	(1.2	)	$	4.5	$	(1.5	)



	Nine Months Ended September 30, 2017
	Product Sales Revenue			Cost of Product Sales		Operating Expense		Other Income		Net Impact on Net Income
Gains (losses) recorded on open futures contracts during the period	$	(31.6	)	$	17.2	$	0.7	$	2.4	$	(11.3	)
Gains recognized on settled futures contracts during the period	27.2			2.5		—		—		29.7
Net impact of futures contracts	$	(4.4	)	$	19.7	$	0.7	$	2.4	$	18.4

Related Party Transactions. See Note 13 – Related Party Transactions in Item 1 of Part I of this report for detail of our related party transactions.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We may be exposed to market risk through changes in commodity prices and interest rates and 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 overages associated with our refined products and crude oil pipelines. We use derivatives such as forward physical contracts and exchange-traded 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, 2017, we had commitments under forward purchase and sale contracts as follows (in millions):



	Total		< 1 Year		1 - 4 Years
Forward purchase contracts – notional value	$	195.9	$	107.9	$	88.0
Forward purchase contracts – barrels	4.4		2.2		2.2
Forward sales contracts – notional value	$	69.5	$	49.0	$	20.5
Forward sales contracts – barrels	1.1		0.8		0.3

We also use exchange-traded futures contracts to hedge against changes in the price of petroleum products we expect to sell or purchase. At September 30, 2017, the fair value of our open futures contracts, representing 5.5 million barrels of petroleum products we expect to sell and 2.1 million barrels of butane we expect to purchase, was a net liability of $13.7 million. These contracts did not qualify for hedge accounting treatment under ASC 815, Derivatives and Hedging, and we accounted for these contracts as economic hedges, with changes in fair value recognized currently in earnings. With respect to these contracts, a $10.00 per barrel increase (decrease) in the prices of petroleum products we expect to sell would result in a $55.0 million decrease (increase) in our operating profit, while a $10.00 per barrel increase (decrease) in the price of butane we expect to purchase would result in $21.0 million increase (decrease) in our operating profit. These increases or decreases in operating profit 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 occurs. These contracts may be for the purchase or sale of products in markets different from those in which we are attempting to hedge our exposure, and the resulting hedges may not eliminate all price risks.

Interest Rate Risk

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

We entered into $100.0 million of forward-starting interest rate swap agreements during 2016 to hedge against the risk of variability of future interest payments on a portion of debt we anticipate issuing in 2018. The fair value of these contracts at September 30, 2017 was a net asset of $12.4 million. We account for these agreements as cash flow hedges. A 0.125% decrease in interest rates would result in a decrease in the fair value of this asset of approximately $2.1 million. A 0.125% increase in interest rates would result in an increase in the fair value of approximately $2.0 million.


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, 2017 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 the federal securities laws that discuss our expected future results based on current and pending business operations. 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 are subject to numerous assumptions, uncertainties and risks that are difficult to predict. Therefore, actual outcomes and results may be materially different from the results stated or implied in such forward-looking statements included in this report.

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


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


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


•	changes in 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, lenders or joint venture co-owners;


•	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, electric and battery-powered engines and geothermal energy, increased use of biofuels such as ethanol and biodiesel, increased conservation or fuel efficiency, increased use of electric vehicles, as well as regulatory developments or other trends that could affect demand for our services;


•	changes in the throughput or interruption in service of 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 and demand patterns for our facilities due to geopolitical events, the activities of the Organization of the Petroleum Exporting Countries, changes in U.S. trade policies or in laws governing the importing and exporting of petroleum products, technological developments or other factors;


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


•	changes in our tariff rates or other terms of service 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, protests or political activism, operational hazards, equipment failures, system failures or unforeseen interruptions;


•	our ability to obtain adequate levels of insurance at a reasonable cost, and the potential for losses to exceed the insurance coverage we do obtain;


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


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

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•	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 to construct, acquire and operate 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 butane blending activities or that could require significant capital outlays for compliance;


•	changes in laws and regulations to which we or our customers are or could become subject, including tax withholding requirements, safety, security, employment, hydraulic fracturing, derivatives transactions, trade 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 and intent of our customers, vendors, lenders, joint venture co-owners or other 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, and the operation, acquisition and construction of assets related to such activities.

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

Anhydrous Ammonia Event. On October 17, 2016, we experienced a release of anhydrous ammonia on our ammonia pipeline system near Tekamah, Nebraska. The release resulted in a fatality and other possible injuries. The National Transportation Safety Board is investigating the event. We are currently unable to estimate the full impact of this event. However, we believe the impact on our financial position and results of operations is not likely to be material as defined by the SEC.

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. While the results cannot be reasonably estimated, we believe the ultimate resolution of this matter will not have a material impact on our results of operations, financial position or cash flows.

Lake Calumet Cluster Site, EPA ID No.: ILD000716852 Superfund Site. We have liability at the Lake Calumet Cluster Superfund Site in Chicago, Illinois as a PRP under Sections 107(a) and 113(f)(1) of CERCLA. As a result of the EPA’s Administrative Settlement Agreement and Order for Remedial Investigation/Feasibility Study of June 2013, we voluntarily entered into the PRP group responsible for the investigation, cleanup and installation of an appropriate clay cap over the site. We have paid $8,000 associated with the Remedial Investigation/Feasibility Study and cleanup costs to date. Our projected portion of the estimated cap installation is $55,000. While the results cannot be predicted with certainty, we believe the ultimate resolution of this matter will not have a material impact on our results of operations, financial position or cash flows.

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.

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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, 2016, 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 or operating results.


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

None.


ITEM 3.	DEFAULTS UPON SENIOR SECURITIES

None.


ITEM 4.	MINE SAFETY DISCLOSURES

Not applicable.


ITEM 5.	OTHER INFORMATION

None.


ITEM 6.	EXHIBITS

The exhibits listed below on the Index to Exhibits are filed or incorporated by reference as part of this report.

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INDEX TO EXHIBITS




Exhibit Number		Description

Exhibit 12	—	Ratio of earnings to fixed charges.

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

Exhibit 31.2	—	Certification of 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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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 2, 2017.



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)