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, 2016

OR

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

For the transition period from              to             

Commission File No.: 1-16335

 _________________________________________

Magellan Midstream Partners, L.P.

(Exact name of registrant as specified in its charter)

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

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

(Address of principal executive offices and zip code)

(918) 574-7000

(Registrant’s telephone number, including area code)

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

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

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

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

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

Act).    Yes  £    No  x

As of November 1, 2016, there were 227,783,916 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

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	8
	4.	Investments in Non-Controlled Entities	11
	5.	Inventory	13
	6.	Employee Benefit Plans	13
	7.	Debt	16
	8.	Derivative Financial Instruments	17
	9.	Commitments and Contingencies	23
	10.	Long-Term Incentive Plan	23
	11.	Distributions	25
	12.	Fair Value	25
	13.	Related Party Transactions	27
	14.	Subsequent Events	27
ITEM 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Introduction		28
	Recent Developments		28
	Results of Operations		29
	Distributable Cash Flow		35
	Liquidity and Capital Resources		37
	Off-Balance Sheet Arrangements		38
	Environmental		38
	Other Items		39
ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	41
ITEM 4.		CONTROLS AND PROCEDURES	42
Forward-Looking Statements			43
PART II OTHER INFORMATION
ITEM 1.		LEGAL PROCEEDINGS	45
ITEM 1A.		RISK FACTORS	46
ITEM 2.		UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	46
ITEM 3.		DEFAULTS UPON SENIOR SECURITIES	46
ITEM 4.		MINE SAFETY DISCLOSURES	46
ITEM 5.		OTHER INFORMATION	46
ITEM 6.		EXHIBITS	47

1

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,
	2015			2016			2015			2016
Transportation and terminals revenue	$	410,387		$	413,433		$	1,149,100		$	1,175,748
Product sales revenue	172,731			133,356			455,827			403,607
Affiliate management fee revenue	3,557			4,993			10,478			11,140
Total revenue	586,675			551,782			1,615,405			1,590,495
Costs and expenses:
Operating	147,349			135,286			396,374			392,681
Cost of product sales	85,522			118,242			316,208			327,530
Depreciation and amortization	42,043			47,081			124,180			134,137
General and administrative	37,612			35,800			111,052			111,216
Total costs and expenses	312,526			336,409			947,814			965,564
Earnings of non-controlled entities	15,521			18,576			49,653			51,543
Operating profit	289,670			233,949			717,244			676,474
Interest expense	40,419			50,163			118,009			142,573
Interest income	(310		)	(302		)	(993		)	(1,067		)
Interest capitalized	(3,984		)	(7,877		)	(9,037		)	(21,143		)
Gain on exchange of interest in non-controlled entity	—			—			—			(28,144		)
Other expense (income)	1,706			(3,324		)	(4,554		)	(7,519		)
Income before provision for income taxes	251,839			195,289			613,819			591,774
Provision for income taxes	867			738			1,820			2,294
Net income	$	250,972		$	194,551		$	611,999		$	589,480
Basic net income per limited partner unit	$	1.10		$	0.85		$	2.69		$	2.59
Diluted net income per limited partner unit	$	1.10		$	0.85		$	2.69		$	2.59
Weighted average number of limited partner units outstanding used for basic net income per unit calculation(1)	227,580			227,960			227,540			227,913
Weighted average number of limited partner units outstanding used for diluted net income per unit calculation(1)	227,945			227,999			227,702			227,947

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

See notes to consolidated financial statements.

2

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited, in thousands)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2016			2015			2016
Net income	$	250,972		$	194,551		$	611,999		$	589,480
Other comprehensive income:
Derivative activity:
Net loss on cash flow hedges(1)	(3,410		)	(3,169		)	(16,939		)	(24,278		)
Reclassification of net loss on cash flow hedges to income(1)	388			512			976			1,288
Changes in employee benefit plan assets and benefit obligations recognized in other comprehensive income:
Amortization of prior service credit(2)	(928		)	(973		)	(2,784		)	(2,920		)
Amortization of actuarial loss(2)	1,798			1,452			5,393			4,145
Settlement cost(2)	—			202			—			202
Total other comprehensive loss	(2,152		)	(1,976		)	(13,354		)	(21,563		)
Comprehensive income	$	248,820		$	192,575		$	598,645		$	567,917

(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.

3

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands)

	December 31, 2015			September 30, 2016
ASSETS				(Unaudited)
Current assets:
Cash and cash equivalents	$	28,731		$	291,097
Trade accounts receivable	83,893			126,141
Other accounts receivable	12,701			24,867
Inventory	130,868			123,011
Energy commodity derivatives contracts, net	39,243			—
Energy commodity derivatives deposits	—			30,559
Other current assets	43,418			52,600
Total current assets	338,854			648,275
Property, plant and equipment	6,166,766			6,657,305
Less: Accumulated depreciation	1,347,537			1,471,263
Net property, plant and equipment	4,819,229			5,186,042
Investments in non-controlled entities	765,628			912,419
Long-term receivables	20,374			22,101
Goodwill	53,260			53,260
Other intangibles (less accumulated amortization of $13,709 and $2,010 at December 31, 2015 and September 30, 2016, respectively)	1,856			52,102
Tank bottoms	27,533			35,429
Other noncurrent assets	14,833			10,157
Total assets	$	6,041,567		$	6,919,785
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	104,094		$	101,012
Accrued payroll and benefits	51,764			39,039
Accrued interest payable	51,296			48,903
Accrued taxes other than income	51,587			53,702
Environmental liabilities	15,679			11,711
Deferred revenue	81,627			98,818
Accrued product purchases	31,339			25,156
Energy commodity derivatives contracts, net	—			12,430
Energy commodity derivatives deposits	24,252			—
Current portion of long-term debt, net	250,335			250,020
Other current liabilities	51,099			43,058
Total current liabilities	713,072			683,849
Long-term debt, net	3,189,287			4,073,502
Long-term pension and benefits	77,551			70,416
Other noncurrent liabilities	24,162			29,408
Environmental liabilities	15,759			14,078
Commitments and contingencies
Partners’ capital:
Limited partner unitholders (227,427 units and 227,784 units outstanding at December 31, 2015 and September 30, 2016, respectively)	2,118,086			2,166,445
Accumulated other comprehensive loss	(96,350		)	(117,913		)
Total partners’ capital	2,021,736			2,048,532
Total liabilities and partners’ capital	$	6,041,567		$	6,919,785

See notes to consolidated financial statements.

4

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)

	Nine Months Ended
	September 30,
	2015			2016
Operating Activities:
Net income	$	611,999		$	589,480
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	124,180			134,137
Loss on sale and retirement of assets	4,378			5,397
Earnings of non-controlled entities	(49,653		)	(51,543		)
Distributions of earnings from investments in non-controlled entities	47,236			50,047
Equity-based incentive compensation expense	15,226			14,737
Settlement cost, amortization of prior service credit and actuarial loss	2,609			1,427
Gain on exchange of interest in non-controlled entity	—			(28,144		)
Changes in operating assets and liabilities:
Trade accounts receivable and other accounts receivable	(24,601		)	(49,014		)
Inventory	22,581			7,857
Energy commodity derivatives contracts, net of derivatives deposits	(11,402		)	637
Accounts payable	12,226			5,850
Accrued payroll and benefits	452			(12,725		)
Accrued interest payable	(841		)	(2,393		)
Accrued taxes other than income	6,334			2,115
Accrued product purchases	(23,947		)	(6,183		)
Deferred revenue	4,141			17,191
Current and noncurrent environmental liabilities	(4,864		)	(5,649		)
Other current and noncurrent assets and liabilities	(11,950		)	(34,229		)
Net cash provided by operating activities	724,104			638,995
Investing Activities:
Additions to property, plant and equipment, net(1)	(431,260		)	(517,810		)
Proceeds from sale and disposition of assets	3,178			6,098
Acquisition of business	(54,678		)	—
Investments in non-controlled entities	(133,373		)	(174,900		)
Distributions in excess of earnings of non-controlled entities	9,341			4,500
Net cash used by investing activities	(606,792		)	(682,112		)
Financing Activities:
Distributions paid	(489,535		)	(548,388		)
Net commercial paper repayments	(69,976		)	(244,963		)
Borrowings under long-term notes	499,589			1,142,997
Debt placement costs	(4,754		)	(10,500		)
Net payment on financial derivatives	(42,908		)	(19,287		)
Settlement of tax withholdings on long-term incentive compensation	(17,784		)	(14,376		)
Net cash provided (used) by financing activities	(125,368		)	305,483
Change in cash and cash equivalents	(8,056		)	262,366
Cash and cash equivalents at beginning of period	17,063			28,731
Cash and cash equivalents at end of period	$	9,007		$	291,097
Supplemental non-cash investing and financing activities:
Contribution of property, plant and equipment to a non-controlled entity	$	13,252		$	—
Issuance of limited partner units in settlement of equity-based incentive plan awards	$	8,045		$	7,092
(1)   Additions to property, plant and equipment	$	(439,721	)	$	(514,205	)
Changes in accounts payable and other current liabilities related to capital expenditures	8,461			(3,605		)
Additions to property, plant and equipment, net	$	(431,260	)	$	(517,810	)

See notes to consolidated financial statements.

5

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization, Description of Business and Basis of Presentation

Organization

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

Description of Business

We are principally engaged in the transportation, storage and distribution of refined petroleum products and crude oil.  As of September 30, 2016, 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 2,100 miles of crude oil pipelines and storage facilities with an aggregate storage capacity of approximately 23 million barrels, of which approximately 15 million barrels are used for leased storage; and

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

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.

6

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, 2015, 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, 2016, the results of operations for the three and nine months ended September 30, 2015 and 2016 and cash flows for the nine months ended September 30, 2015 and 2016. The results of operations for the nine months ended September 30, 2016 are not necessarily indicative of the results to be expected for the full year ending December 31, 2016 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, 2015.

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 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which is part of the FASB’s initiative to simplify accounting standards. The guidance requires an entity to make an entity-wide accounting policy election to either estimate the number of awards that are expected to vest or account for forfeitures when they occur, and allows equity classification for awards where employees elect to withhold up to the maximum statutory tax rates in the applicable jurisdictions. The new standard also requires cash paid by employers when directly withholding shares for tax withholding purposes to be classified as a financing activity in the statement of cash flows.

We elected to early adopt ASU 2016-09 during the first quarter of 2016, and this adoption did not have a material impact on our consolidated financial statements. In conjunction with our adoption of this new accounting standard, we have elected to account for equity-based compensation forfeitures as they occur. Additionally, and consistent with our prior accounting policy, we continue to show cash paid when directly withholding shares for tax withholding purposes as a financing activity in our statements of cash flows.

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

7

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which eliminates the industry-specific guidance in U.S. GAAP and produces a single, principles-based method for companies to report revenue in their financial statements. This standard requires companies to make more estimates and use more judgment than under current guidance. In addition, all companies must compile more extensive footnote disclosures about how the revenue numbers were derived. This ASU requires full retrospective, modified retrospective or use of the cumulative effect method during the period of adoption. In July 2015, the FASB extended the effective date of this standard from January 1, 2017 to January 1, 2018. We are currently in the process of evaluating the impact this new standard will have on our 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 New York Mercantile Exchange (“NYMEX”) contracts. See Note 8 – Derivative Financial Instruments for a discussion of our commodity hedging strategies and how our NYMEX contracts impact product sales revenue. All of the petroleum products inventory we physically sell associated with our butane blending and fractionation activities, as well as the barrels from product gains we obtain from our operations, are reported as product sales revenue on our consolidated statements of income.

For the three and nine months ended September 30, 2015 and 2016, product sales revenue included the following (in thousands):

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2015		2016			2015		2016
Physical sale of petroleum products	$	100,829	$	146,006		$	403,395	$	412,045
Change in value of NYMEX contracts	71,902		(12,650		)	52,432		(8,438		)
Total product sales revenue	$	172,731	$	133,356		$	455,827	$	403,607

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.

8

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Three Months Ended September 30, 2015
	(in thousands)
	Refined Products		Crude Oil			Marine Storage			Intersegment Eliminations			Total
Transportation and terminals revenue	$	264,156	$	101,122		$	45,109		$	—		$	410,387
Product sales revenue	171,775		—			956			—			172,731
Affiliate management fee revenue	—		3,211			346			—			3,557
Total revenue	435,931		104,333			46,411			—			586,675
Operating expenses	108,972		24,572			14,700			(895		)	147,349
Cost of product sales	85,341		—			181			—			85,522
Losses (earnings) of non-controlled entities	48		(14,906		)	(663		)	—			(15,521		)
Operating margin	241,570		94,667			32,193			895			369,325
Depreciation and amortization expense	24,333		9,502			7,313			895			42,043
G&A expenses	22,238		9,818			5,556			—			37,612
Operating profit	$	194,999	$	75,347		$	19,324		$	—		$	289,670

	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	95,776		24,628			16,374			(1,492		)	135,286
Cost of product sales	93,761		24,108			373			—			118,242
Losses (earnings) of non-controlled entities	272		(18,180		)	(668		)	—			(18,576		)
Operating margin	183,582		98,723			33,234			1,291			316,830
Depreciation and amortization expense	28,432		9,333			8,025			1,291			47,081
G&A expenses	22,993		8,493			4,314			—			35,800
Operating profit	$	132,157	$	80,897		$	20,895		$	—		$	233,949

9

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Nine Months Ended September 30, 2015
	(in thousands)
	Refined Products		Crude Oil			Marine Storage			Intersegment Eliminations			Total
Transportation and terminals revenue	$	723,156	$	294,023		$	131,921		$	—		$	1,149,100
Product sales revenue	453,737		—			2,090			—			455,827
Affiliate management fee revenue	—		9,449			1,029			—			10,478
Total revenue	1,176,893		303,472			135,040			—			1,615,405
Operating expenses	288,265		65,032			45,916			(2,839		)	396,374
Cost of product sales	315,301		—			907			—			316,208
Losses (earnings) of non-controlled entities	146		(47,735		)	(2,064		)	—			(49,653		)
Operating margin	573,181		286,175			90,281			2,839			952,476
Depreciation and amortization expense	71,742		25,995			23,604			2,839			124,180
G&A expenses	68,730		26,935			15,387			—			111,052
Operating profit	$	432,709	$	233,245		$	51,290		$	—		$	717,244

	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	280,261		66,370			49,897			(3,847		)	392,681
Cost of product sales	300,009		26,469			1,052			—			327,530
Losses (earnings) of non-controlled entities	352		(49,870		)	(2,025		)	—			(51,543		)
Operating margin	531,792		296,363			90,026			3,646			921,827
Depreciation and amortization expense	78,523		28,264			23,704			3,646			134,137
G&A expenses	68,852		27,419			14,945			—			111,216
Operating profit	$	384,417	$	240,680		$	51,377		$	—		$	676,474

10

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. Investments in Non-Controlled Entities

Our investments in non-controlled entities at September 30, 2016 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%
Powder Springs Logistics, LLC (“Powder Springs”)	50%
Saddlehorn Pipeline Company, LLC (“Saddlehorn”)	40%
Seabrook Logistics, LLC (“Seabrook”)	50%
Texas Frontera, LLC (“Texas Frontera”)	50%

In February 2016, we transferred our 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. We recorded these commercial agreements as $43.7 million of intangible assets and $8.3 million of other receivables in our consolidated balance sheets. The intangible assets will be amortized over the 20-year life of the contracts received. The total gain recorded in 2016 was $28.1 million.

The management fees we have recognized from BridgeTex, Osage, Powder Springs, Saddlehorn and Texas Frontera are reported as affiliate management fee revenue on our consolidated statements of income.  In addition, we receive reimbursement from certain of our joint ventures for costs incurred during construction, which we included as reductions to costs and expenses on our consolidated statements of income. These construction cost reimbursements totaled $1.2 million and $2.7 million during the three and nine months ended September 30, 2016, respectively.

We recognized pipeline capacity lease revenue from BridgeTex of $8.9 million and $8.9 million for the three months ended September 30, 2015 and 2016, respectively, and $25.8 million and $26.6 million for the nine months ended September 30, 2015 and 2016, respectively, which we included in transportation and terminals revenue on our consolidated statements of income.

We recognized throughput revenue from Double Eagle of $0.8 million and $0.9 million for the three months ended September 30, 2015 and 2016, respectively, and $2.6 million and $2.5 million for the nine months ended September 30, 2015 and 2016, respectively, which we included in transportation and terminals revenue on our consolidated statements of income.  At December 31, 2015 and September 30, 2016, respectively, we recognized a $0.2 million and $0.3 million trade accounts receivable from Double Eagle.

At September 30, 2016, we recognized $2.9 million, $1.4 million and $0.5 million of other receivables from Saddlehorn, BridgeTex and Powder Springs, respectively, related to the activities detailed above and miscellaneous cost reimbursements. These receivables are reported in our balance sheets as other accounts receivable.

The financial results from 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/losses of non-controlled entities.

11

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

	BridgeTex			All Others			Consolidated
Investments at December 31, 2015	$	495,267		$	270,361		$	765,628
Additional investment	31,503			143,397			174,900
Exchange of investment in non-controlled entity	—			(25,105		)	(25,105		)
Earnings of non-controlled entities:
Proportionate share of earnings	45,990			7,256			53,246
Amortization of excess investment and capitalized interest	(1,529		)	(174		)	(1,703		)
Earnings of non-controlled entities	44,461			7,082			51,543
Less:
Distributions of earnings from investments in non-controlled entities	44,461			5,586			50,047
Distributions in excess of earnings of non-controlled entities	3,333			1,167			4,500
Investments at September 30, 2016	$	523,437		$	388,982		$	912,419

Summarized financial information of our non-controlled entities for the three and nine months ended September 30, 2015 and 2016 follows (in thousands):

	Three Months Ended September 30, 2015						Three Months Ended September 30, 2016
	BridgeTex		All Others		Consolidated		BridgeTex		All Others		Consolidated
Revenue	$	47,555	$	12,530	$	60,085	$	55,843	$	14,022	$	69,865
Net income	$	28,150	$	4,151	$	32,301	$	33,514	$	5,149	$	38,663

	Nine Months Ended September 30, 2015						Nine Months Ended September 30, 2016
	BridgeTex		All Others		Consolidated		BridgeTex		All Others		Consolidated
Revenue	$	146,320	$	33,677	$	179,997	$	155,067	$	35,451	$	190,518
Net income	$	91,806	$	11,525	$	103,331	$	91,981	$	14,907	$	106,888

12

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. Inventory

Inventory at December 31, 2015 and September 30, 2016 was as follows (in thousands):

	December 31, 2015		September 30, 2016
Refined products	$	57,455	$	23,028
Crude oil	28,385		20,475
Transmix	21,297		33,108
Liquefied petroleum gases	17,954		40,684
Additives	5,777		5,716
Total inventory	$	130,868	$	123,011

6. Employee Benefit Plans

We sponsor two pension plans for certain union employees and a pension plan primarily for non-union employees, a postretirement benefit plan for selected employees and a defined contribution plan. The following tables present our consolidated net periodic benefit costs related to the pension and postretirement benefit plans for the three and nine months ended September 30, 2015 and 2016 (in thousands):

	Three Months Ended						Three Months Ended
	September 30, 2015						September 30, 2016
	Pension Benefits			Other  Postretirement Benefits			Pension Benefits			Other  Postretirement Benefits
Components of net periodic benefit costs:
Service cost	$	4,723		$	61		$	4,555		$	53
Interest cost	1,938			109			1,992			148
Expected return on plan assets	(2,009		)	—			(2,235		)	—
Amortization of prior service credit	—			(928		)	(45		)	(928		)
Amortization of actuarial loss	1,577			221			1,161			291
Settlement cost	—			—			202			—
Net periodic benefit cost (credit)	$	6,229		$	(537	)	$	5,630		$	(436	)

13

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Nine Months Ended						Nine Months Ended
	September 30, 2015						September 30, 2016
	Pension Benefits			Other  Postretirement Benefits			Pension Benefits			Other  Postretirement Benefits
Components of net periodic benefit costs:
Service cost	$	14,168		$	183		$	13,648		$	176
Interest cost	5,815			328			5,970			368
Expected return on plan assets	(6,028		)	—			(6,694		)	—
Amortization of prior service credit	—			(2,784		)	(135		)	(2,785		)
Amortization of actuarial loss	4,730			663			3,485			660
Settlement cost	—			—			202			—
Net periodic benefit cost (credit)	$	18,685		$	(1,610	)	$	16,476		$	(1,581	)

Contributions estimated to be paid into the plans in 2016 are $26.0 million and $0.5 million for the pension and other postretirement benefit plans, respectively.

We match our employees’ qualifying contributions to our defined contribution plan, resulting in expense to us. Expenses related to the defined contribution plan were $1.8 million and $2.4 million, respectively, for the three months ended September 30, 2015 and 2016 and $6.8 million and $7.8 million, respectively, for the nine months ended September 30, 2015 and 2016.

14

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Amounts Included in AOCL

The changes in AOCL related to employee benefit plan assets and benefit obligations for the three and nine months ended September 30, 2015 and 2016 were as follows (in thousands):

	Three Months Ended						Three Months Ended
	September 30, 2015						September 30, 2016
Gains (Losses) Included in AOCL	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Beginning balance	$	(60,104	)	$	(3,110	)	$	(60,045	)	$	(5,433	)
Amortization of prior service credit	—			(928		)	(45		)	(928		)
Amortization of actuarial loss	1,577			221			1,161			291
Settlement cost	—			—			202			—
Ending balance	$	(58,527	)	$	(3,817	)	$	(58,727	)	$	(6,070	)

	Nine Months Ended						Nine Months Ended
	September 30, 2015						September 30, 2016
Gains (Losses) Included in AOCL	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Beginning balance	$	(63,257	)	$	(1,696	)	$	(62,279	)	$	(3,945	)
Amortization of prior service credit	—			(2,784		)	(135		)	(2,785		)
Amortization of actuarial loss	4,730			663			3,485			660
Settlement cost	—			—			202			—
Ending balance	$	(58,527	)	$	(3,817	)	$	(58,727	)	$	(6,070	)

15

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. Debt

The carrying amount of our consolidated debt at December 31, 2015 and September 30, 2016 was as follows (in thousands, except as otherwise noted):

	December 31, 2015		September 30, 2016		Weighted-Average Interest Rate for the Nine Months Ended September 30, 2016 (1)
Commercial paper(2)	$	279,801	$	34,880	0.8%
$250.0 million of 5.65% Notes due 2016(3)	250,208		250,020		5.7%
$250.0 million of 6.40% Notes due 2018	254,694		253,298		5.5%
$550.0 million of 6.55% Notes due 2019	562,600		560,042		5.7%
$550.0 million of 4.25% Notes due 2021	553,002		552,620		4.1%
$250.0 million of 3.20% Notes due 2025	247,788		247,967		3.2%
$650.0 million of 5.00% Notes due 2026(2)	—		644,129		5.1%
$250.0 million of 6.40% Notes due 2037	247,230		247,312		6.4%
$250.0 million of 4.20% Notes due 2042	246,142		246,230		4.3%
$550.0 million of 5.15% Notes due 2043	550,819		550,885		5.1%
$250.0 million of 4.20% Notes due 2045	247,338		247,408		4.7%
$500.0 million of 4.25% Notes due 2046(2)	—		488,731		4.8%
Total debt	3,439,622		4,323,522		4.9%
Less: current portion of long-term debt, net	250,335		250,020
Long-term debt, net(4)	$	3,189,287	$	4,073,502

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

(2) These borrowings were outstanding for only a portion of the nine-month period ending September 30, 2016. The weighted-average interest rate for these borrowings was calculated based on the number of days the borrowings were outstanding during the noted period.

(3) These borrowings will mature in October 2016 and are reflected in current debt on our consolidated balance sheets at December 31, 2015 and September 30, 2016.

(4) Long-term debt is presented net of unamortized debt issuance costs of $18.7 million and $27.4 million at December 31, 2015 and September 30, 2016, respectively.

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

The face value of our debt at December 31, 2015 and September 30, 2016 was $3.4 billion and $4.3 billion, respectively. The difference between the face value and carrying value of our debt outstanding is the unamortized portion of terminated fair value hedges and the unamortized discounts and premiums on debt issuances. Realized gains and losses on fair value hedges and note discounts and premiums are being amortized or accreted to the applicable notes over the respective lives of those notes.

2016 Debt Offering

In September 2016, we issued $500.0 million of our 4.25% notes due 2046 in an underwritten public offering. The notes were issued at 98.762% of par. Net proceeds from this offering were approximately $488.7 million, after underwriting discounts and offering expenses of $5.1 million. The net proceeds from this offering were used to repay our 5.65% senior notes when due in October 2016 and to repay borrowings outstanding under our commercial paper program. The remaining proceeds may be used for general partnership purposes, which may include capital expenditures.

16

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In February 2016, we issued $650.0 million of our 5.00% notes due 2026 in an underwritten public offering. The notes were issued at 99.875% of par. Net proceeds from this offering were approximately $643.8 million, after underwriting discounts and offering expenses of $5.4 million. The net proceeds from this offering were used to repay borrowings outstanding under our commercial paper program and for general partnership purposes, including expansion capital.

Other Debt

Revolving Credit Facilities. At September 30, 2016, 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, 2016. Borrowings under this facility may be used for general partnership purposes, including capital expenditures. As of December 31, 2015 and September 30, 2016, respectively, 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.

At September 30, 2016, the total borrowing capacity under our 364-day credit facility was $250.0 million. The maturity date of this credit facility is October 25, 2016. See Note 14 – Subsequent Events for recent information about this credit facility. Any borrowings under this credit facility are classified as current 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 0.080% and 0.225% depending on our credit ratings. The unused commitment fee was 0.100% at September 30, 2016. Borrowings under this facility may be used for general partnership purposes, including capital expenditures. As of December 31, 2015 and September 30, 2016, respectively, there were no borrowings outstanding under this facility.

Commercial Paper Program. The maturities of our commercial paper notes vary, but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. The commercial paper we can issue is limited by the amounts available under our revolving credit facility up to an aggregate principal amount of $1.0 billion and is classified as long-term debt.

8. Derivative Financial Instruments

Interest Rate Derivatives

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

During 2016, we 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, 2016 were recorded on our balance sheets as an other noncurrent liability of $3.5 million, with the offset recorded to other comprehensive income. We account for these agreements as cash flow hedges.

17

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

During 2015 and 2016, we entered into $250.0 million of forward-starting interest rate swap agreements to hedge against the risk of variability of future interest payments on a portion of debt we anticipated issuing in 2016. We accounted for these agreements as cash flow hedges. When we issued $500.0 million of 4.25% notes due 2046 in September 2016, we settled the associated interest rate swap agreements for a loss of $19.3 million. The loss was recorded to other comprehensive income and will be recognized into earnings as an adjustment to our periodic interest expense accruals over the first ten-year payment period of the associated notes. This loss was also reported as a net payment on financial derivatives in the financing activities of our consolidated statements of cash flows in 2016.

Commodity Derivatives

Hedging Strategies

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

We account for the forward physical purchase and sale contracts we use in our butane blending and fractionation activities as normal purchases and sales. Forward contracts that qualify for and are elected as normal purchases and sales are accounted for using traditional accrual accounting.

The NYMEX contracts that we enter into fall into one of three hedge categories:

Hedge Category	Hedge Purpose	Accounting Treatment
Qualifies For Hedge Accounting Treatment
Cash Flow Hedge	To hedge the variability in cash flows related to a forecasted transaction.	The effective portion of changes in the 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 three and nine months ended September 30, 2015 and 2016, none of the commodity hedging contracts we entered into qualified for or were designated as cash flow hedges.

Period changes in the fair value of NYMEX agreements that are accounted for as economic hedges (other than those economic hedges of our butane purchases and our pipeline product overages as discussed below), the effective portion of changes in the fair value of cash flow hedges that are reclassified from AOCL and any ineffectiveness

18

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

associated with hedges related to our commodity activities are recognized currently in earnings as adjustments to product sales.

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

We hold petroleum product inventories that we obtain from overages on our pipeline systems. We use NYMEX contracts that are not designated as hedges for accounting purposes to help manage price changes related to these inventory barrels. Period changes in the fair value of these agreements are recognized currently in earnings as adjustments to operating expense.

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

As outlined in the table below, our open NYMEX contracts at September 30, 2016 were as follows:

Type of Contract/Accounting Methodology	Product Represented by the Contract and Associated Barrels	Maturity Dates
NYMEX - Fair Value Hedges	0.7 million barrels of crude oil	November 2017
NYMEX - Economic Hedges	5.1 million barrels of refined products and crude oil	Between October 2016 and April 2017
NYMEX - Economic Hedges	1.3 million barrels of future purchases of butane	Between October 2016 and April 2017

Energy Commodity Derivatives Contracts and Deposits Offsets

At September 30, 2016, we had made margin deposits of $30.6 million for our NYMEX contracts with our counterparties, which were recorded as a current asset under energy commodity derivatives deposits on our consolidated balance sheets. We have the right to offset the combined fair values of our open NYMEX contracts against our margin deposits under a master netting arrangement for each counterparty; however, we have elected to present the combined fair values of our open NYMEX contracts separately from the related margin deposits on our consolidated balance sheets. Additionally, we have the right to offset the fair values of our NYMEX agreements together for each counterparty, which we have elected to do, and we report the combined net balances on our consolidated balance sheets. A schedule of the derivative amounts we have offset and the deposit amounts we could offset under a master netting arrangement are provided below as of December 31, 2015 and September 30, 2016 (in thousands):

	December 31, 2015
Description	Gross Amounts of Recognized Assets		Gross Amounts of Liabilities Offset in the Consolidated Balance Sheets			Net Amounts of Assets Presented in the Consolidated Balance Sheets(1)		Margin Deposit Amounts Not Offset in the Consolidated Balance Sheets			Net Asset Amount(3)
Energy commodity derivatives	$	48,367	$	(5,646	)	$	42,721	$	(24,252	)	$	18,469

19

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	September 30, 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(2)			Margin Deposit Amounts Not Offset in the Consolidated Balance Sheets		Net Asset Amount(3)
Energy commodity derivatives	$	(15,576	)	$	3,247	$	(12,329	)	$	30,559	$	18,230

(1) Net amount includes energy commodity derivative contracts classified as current assets, net, of $39,243 and noncurrent assets of $3,478.

(2) Net amount includes energy commodity derivative contracts classified as current liabilities, net, of $12,430 and noncurrent assets of $101.

(3) 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, 2015 and 2016 were as follows (in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Derivative Losses Included in AOCL	2015			2016			2015			2016
Beginning balance	$	(29,528	)	$	(50,459	)	$	(16,587	)	$	(30,126	)
Net loss on cash flow hedges	(3,410		)	(3,169		)	(16,939		)	(24,278		)
Reclassification of net loss on cash flow hedges to income	388			512			976			1,288
Ending balance	$	(32,550	)	$	(53,116	)	$	(32,550	)	$	(53,116	)

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, 2015 and 2016 of derivatives accounted for under ASC 815-30, Derivatives and Hedging—Cash Flow Hedges, that were designated as hedging instruments (in thousands):

	Three Months Ended September 30, 2015
	Amount of Loss Recognized in AOCL on Derivative				Location of Loss Reclassified from AOCL into  Income	Amount of Loss Reclassified from AOCL into Income
Derivative Instrument						Effective Portion				Ineffective Portion
Interest rate contracts		$	(3,410	)	Interest expense		$	(388	)		$	—

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

20

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Nine Months Ended September 30, 2015
	Amount of Loss Recognized in AOCL on Derivative				Location of Loss Reclassified from AOCL into  Income	Amount of Loss Reclassified from AOCL into Income
Derivative Instrument						Effective Portion				Ineffective Portion
Interest rate contracts		$	(16,939	)	Interest expense		$	(976	)		$	—

	Nine Months Ended September 30, 2016
	Amount of Loss Recognized in AOCL on Derivative				Location of Loss Reclassified from AOCL into  Income	Amount of Loss Reclassified from AOCL into Income
Derivative Instrument						Effective Portion				Ineffective Portion
Interest rate contracts		$	(24,278	)	Interest expense		$	(1,288	)		$	—

As of September 30, 2016, the net loss estimated to be classified to interest expense over the next twelve months from AOCL is approximately $3.0 million.

During 2015 and 2016, we had open NYMEX contracts on 0.7 million barrels of crude oil that were designated as fair value hedges. Because there was no ineffectiveness recognized on these hedges, the cumulative gains at December 31, 2015 and September 30, 2016 of $27.9 million and $17.6 million, respectively, from these agreements were offset by a cumulative decrease to tank bottoms. The differential between the current spot price and forward price is excluded from the assessment of hedge effectiveness for these fair value hedges. For the three months ended September 30, 2015 and 2016, we recognized a gain (loss) of $(1.7) million and $0.3 million, respectively, and for the nine months ended September 30, 2015 and 2016, we recognized a gain of $4.6 million and $4.5 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.

The following table provides a summary of the effect on our consolidated statements of income for the three and nine months ended September 30, 2015 and 2016 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		2015			2016			2015			2016
NYMEX commodity contracts	Product sales revenue	$	71,902		$	(12,650	)	$	52,432		$	(8,438	)
NYMEX commodity contracts	Operating expenses	14,761			4,212			7,181			(1,192		)
NYMEX commodity contracts	Cost of product sales	(3,767		)	831			(5,847		)	3,643
	Total	$	82,896		$	(7,607	)	$	53,766		$	(5,987	)

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

21

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, 2015 and September 30, 2016 (in thousands):

	December 31, 2015
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
NYMEX commodity contracts	Energy commodity derivatives contracts, net	$	60	Energy commodity derivatives contracts, net	$	—
NYMEX commodity contracts	Other noncurrent assets	3,478		Other noncurrent liabilities	—
Interest rate contracts	Other current assets	2,179		Other current liabilities	653
	Total	$	5,717	Total	$	653

	September 30, 2016
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
NYMEX commodity contracts	Other noncurrent assets	$	101	Other noncurrent liabilities	$	—
Interest rate contracts	Other noncurrent assets	—		Other noncurrent liabilities	3,465
	Total	$	101	Total	$	3,465

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, 2015 and September 30, 2016 (in thousands):

	December 31, 2015
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
NYMEX commodity contracts	Energy commodity derivatives contracts, net	$	44,829	Energy commodity derivatives contracts, net	$	5,646
	September 30, 2016
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
NYMEX commodity contracts	Energy commodity derivatives contracts, net	$	3,146	Energy commodity derivatives contracts, net	$	15,576

22

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. Commitments and Contingencies

Environmental Liabilities

Liabilities recognized for estimated environmental costs were $31.4 million and $25.8 million at December 31, 2015 and September 30, 2016, respectively. We have classified environmental liabilities as current or noncurrent based on management’s estimates regarding the timing of actual payments. Management estimates that expenditures associated with these environmental liabilities will be substantially paid over the next 9 years. Environmental expense 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 $1.3 million and $0.3 million for the three months ended September 30, 2015 and 2016, respectively, and $5.6 million and $4.6 million for the nine months ended September 30, 2015 and 2016, respectively.

Environmental Receivables

Receivables from insurance carriers and other third parties related to environmental matters were $2.6 million at December 31, 2015, of which $0.7 million and $1.9 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 $2.0 million at September 30, 2016, of which $0.8 million and $1.2 million were recorded to other accounts receivable and long-term receivables, respectively, on our consolidated balance sheets.

Other

We are a party to various other claims, legal actions and complaints arising in the ordinary course of business, including without limitation those disclosed in Item 1, Legal Proceedings of Part II of this report on Form 10-Q. While the results cannot be predicted with certainty, management believes the ultimate resolution of these claims, legal actions and complaints after consideration of amounts accrued, insurance coverage or other indemnification arrangements will not have a material adverse effect on our results of operations, financial position or cash flows. See Note 14 – Subsequent Events for additional information about a recent event.

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, 2016 total 3.0 million.

23

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

	Three Months Ended							Nine Months Ended
	September 30, 2015							September 30, 2015
	Equity Method		Liability Method			Total		Equity Method		Liability Method		Total
Performance-based awards:
2013 awards	$	1,673	$	(590	)	$	1,083	$	6,246	$	501	$	6,747
2014 awards	1,497		—			1,497		3,980		—		3,980
2015 awards	1,727		—			1,727		3,687		—		3,687
Time-based awards	380		—			380		812		—		812
Total	$	5,277	$	(590	)	$	4,687	$	14,725	$	501	$	15,226
Allocation of LTIP expense on our consolidated statements of income:
G&A expense						$	4,643					$	15,016
Operating expense						44						210
Total						$	4,687					$	15,226

	Three Months Ended						Nine Months Ended
	September 30, 2016						September 30, 2016
	Equity Method		Liability Method		Total		Equity Method		Liability Method		Total
Performance-based awards:
2014 awards	$	1,780	$	—	$	1,780	$	6,168	$	—	$	6,168
2015 awards	1,208		—		1,208		3,679		—		3,679
2016 awards	1,097		—		1,097		3,240		—		3,240
Time-based awards	593		—		593		1,650		—		1,650
Total	$	4,678	$	—	$	4,678	$	14,737	$	—	$	14,737
Allocation of LTIP expense on our consolidated statements of income:
G&A expense					$	4,637					$	14,623
Operating expense					41						114
Total					$	4,678					$	14,737

In February 2016, 218,046 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, 2018.

In February 2016, we issued 350,552 limited partner units to settle unit award grants to certain employees that vested on December 31, 2015. Further, 6,117 limited partner units were issued during 2016 to settle the equity-based retainers paid to the directors of our general partner.

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

24

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.

11. Distributions

Distributions we paid during 2015 and 2016 were as follows (in thousands, except per unit amounts):

Payment Date	Per Unit Cash Distribution Amount			Total Cash Distribution to Limited Partners
02/13/2015		$	0.6950		$	158,061
05/15/2015		0.7175			163,178
08/14/2015		0.7400			168,296
Through 09/30/2015		2.1525			489,535
11/13/2015		0.7625			173,413
Total		$	2.9150		$	662,948
2/12/2016		$	0.7850		$	178,808
5/13/2016		0.8025			182,797
08/12/2016		0.8200			186,783
Through 09/30/2016		2.4075			548,388
11/14/2016(1)		0.8375			190,769
Total		$	3.2450		$	739,157

(1) Our general partner’s board of directors declared this cash distribution in October 2016 to be paid on November 14, 2016 to unitholders of record at the close of business on October 31, 2016.

12. Fair Value

Recurring

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

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

25

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

• Long-term receivables. These primarily include lease 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, 2015 and September 30, 2016; however, where recent observable market trades were not available, prices were determined using adjustments to the last traded value for that debt issuance or by adjustments to the prices of similar debt instruments of peer entities that are actively traded. The carrying amount of borrowings, if any, under our revolving credit facility and our commercial paper program approximates fair value due to the frequent repricing of these obligations.

Fair Value Measurements - Financial Assets and Liabilities

The following tables summarize the carrying amounts, fair values and recurring fair value measurements recorded or disclosed as of December 31, 2015 and September 30, 2016 based on the three levels established by ASC 820, Fair Value Measurements and Disclosures (in thousands):

	December 31, 2015
Assets (Liabilities)							Fair Value Measurements using:
	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	$	42,721		$	42,721		$	42,721	$	—		$	—
Interest rate contracts	$	1,526		$	1,526		$	—	$	1,526		$	—
Long-term receivables	$	20,374		$	20,374		$	—	$	—		$	20,374
Debt	$	(3,439,622	)	$	(3,284,791	)	$	—	$	(3,284,791	)	$	—

	September 30, 2016
Assets (Liabilities)							Fair Value Measurements using:
	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	$	(12,329	)	$	(12,329	)	$	(12,329	)	$	—		$	—
Interest rate contracts	$	(3,465	)	$	(3,465	)	$	—		$	(3,465	)	$	—
Long-term receivables	$	22,101		$	22,101		$	—		$	—		$	22,101
Debt	$	(4,323,522	)	$	(4,678,925	)	$	—		$	(4,678,925	)	$	—

26

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. Related Party Transactions

Barry R. Pearl is an independent member of our general partner’s board of directors and was also a director of the general partner of Targa Resources Partners, L.P. (“Targa”) through February 29, 2016. In the normal course of business, we purchase butane from subsidiaries of Targa. During Mr. Pearl’s tenure as a director of the general partner of Targa, we made purchases of butane from subsidiaries of Targa of $1.5 million and $14.3 million, respectively, for the three and nine month periods ending September 30, 2015, and $4.7 million for the period from January 1, 2016 through February 29, 2016. These purchases were based on the then-current index prices. We had recognized payables to Targa of $2.0 million at December 31, 2015.

Stacy P. Methvin was elected as an independent member of our general partner’s board of directors on April 23, 2015 and is also a director of one of our customers.  We received tariff revenue from this customer of $4.1 million and $6.7 million, respectively, for the three and nine month periods ending September 30, 2015 and $4.3 million and $12.0 million, respectively, for the three and nine month periods ended September 30, 2016. We recorded receivables of $1.3 million and $1.5 million from this customer at December 31, 2015 and September 30, 2016, respectively.  The tariff revenue we recognized from this customer was in the normal course of business, with rates determined in accordance with published tariffs. 

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

14. Subsequent Events

Recognizable events

No recognizable events occurred subsequent to September 30, 2016.

Non-recognizable events

Renewal of 364-Day Credit Facility. In October 2016, we renewed our 364-day credit facility (see Note 7 - Debt for a description of this facility). The new maturity date is October 19, 2017. All other terms remain the same.

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 possible injuries. The National Transportation Safety Board is investigating the event. On October 21, 2016, the U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration (“PHMSA”) issued a Corrective Action Order to Magellan Ammonia Pipeline, L.P. related to the event, which, among other things, requires PHMSA’s approval prior to re-start of the affected pipeline segment. 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 Securities and Exchange Commission.

Cash Distribution. In October 2016, our general partner’s board of directors declared a quarterly distribution of $0.8375 per unit to be paid on November 14, 2016 to unitholders of record at the close of business on October 31, 2016. The total cash distributions expected to be paid under this declaration are approximately $190.8 million.

27

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, 2016, 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 2,100 miles of crude oil pipelines and storage facilities with an aggregate storage capacity of approximately 23 million barrels, of which approximately 15 million barrels are used for leased storage; and

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

The following discussion provides an analysis of the results for each of our operating segments, an overview of our liquidity and capital resources and other items related to our partnership. The following discussion and analysis should be read in conjunction with (i) our accompanying interim consolidated financial statements and related notes and (ii) our consolidated financial statements, related notes and management’s discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the year ended December 31, 2015.

Recent Developments

Little Rock Pipeline. In July 2016, our Little Rock pipeline began commercial service. This pipeline extends the reach of our existing pipeline system to the Little Rock, Arkansas market with the capacity to ship as much as 75,000 barrels per day of refined products from mid-continent and Gulf Coast refineries.

Saddlehorn Pipeline. In September 2016, Saddlehorn Pipeline Company, LLC (“Saddlehorn”) began commercial service delivering crude oil from the DJ Basin region of Colorado to existing storage facilities in Cushing, Oklahoma. This jointly-owned pipeline system has the capacity to deliver up to 190,000 barrels per day of crude oil. We do not consolidate Saddlehorn in our financial statements; however, we will recognize our 40% share of its profits in our consolidated statements of income as earnings of non-controlled entities.

Cash Distribution. In October 2016, the board of directors of our general partner declared a quarterly cash distribution of $0.8375 per unit for the period of July 1, 2016 through September 30, 2016. This quarterly cash distribution will be paid on November 14, 2016 to unitholders of record on October 31, 2016. Total distributions expected to be paid under this declaration are approximately $190.8 million.

28

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. 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.

29

Three Months Ended September 30, 2015 compared to Three Months Ended September 30, 2016

	Three Months Ended September 30,						Variance Favorable  (Unfavorable)
	2015			2016			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)
Transportation and terminals revenue:
Refined products	$	264.2		$	267.3		$	3.1		1
Crude oil	101.2			100.1			(1.1		)	(1)
Marine storage	45.1			46.2			1.1			2
Intersegment eliminations	—			(0.1		)	(0.1		)	n/a
Total transportation and terminals revenue	410.5			413.5			3.0			1
Affiliate management fee revenue	3.6			5.0			1.4			39
Operating expenses:
Refined products	109.0			95.8			13.2			12
Crude oil	24.5			24.7			(0.2		)	(1)
Marine storage	14.7			16.4			(1.7		)	(12)
Intersegment eliminations	(0.8		)	(1.6		)	0.8			100
Total operating expenses	147.4			135.3			12.1			8
Product margin:
Product sales revenue	172.7			133.3			(39.4		)	(23)
Cost of product sales	85.5			118.2			(32.7		)	(38)
Product margin(1)	87.2			15.1			(72.1		)	(83)
Earnings of non-controlled entities	15.5			18.5			3.0			19
Operating margin	369.4			316.8			(52.6		)	(14)
Depreciation and amortization expense	42.1			47.0			(4.9		)	(12)
G&A expense	37.7			35.8			1.9			5
Operating profit	289.6			234.0			(55.6		)	(19)
Interest expense (net of interest income and interest capitalized)	36.1			42.0			(5.9		)	(16)
Other expense (income)	1.7			(3.3		)	5.0			n/a
Income before provision for income taxes	251.8			195.3			(56.5		)	(22)
Provision for income taxes	0.8			0.7			0.1			13
Net income	$	251.0		$	194.6		$	(56.4	)	(22)
Operating Statistics:
Refined products:
Transportation revenue per barrel shipped	$	1.476		$	1.503
Volume shipped (million barrels):
Gasoline	73.9			72.7
Distillates	38.8			37.3
Aviation fuel	5.6			7.2
Liquefied petroleum gases	3.5			4.1
Total volume shipped	121.8			121.3
Crude oil:
Magellan 100%-owned assets:
Transportation revenue per barrel shipped	$	1.148		$	1.189
Volume shipped (million barrels)	53.6			50.7
Crude oil terminal average utilization (million barrels per month)	13.5			14.8
Select joint venture pipelines:
BridgeTex - volume shipped (million barrels)(2)	18.5			20.6
Marine storage:
Marine terminal average utilization (million barrels per month)	24.3			24.3

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

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

30

Transportation and terminals revenue increased $3.0 million resulting from:

• an increase in refined products revenue of $3.1 million primarily attributable to higher average tariff rates. The average rate per barrel in the current period was favorably impacted by the mid-year 2016 tariff adjustment, which was an approximate 2% average increase over all of our markets. Shipments decreased slightly in the current period primarily due to refinery turnarounds that favorably impacted demand on our system during third quarter 2015, partially offset by volumes from recent growth projects, including our Little Rock pipeline which commenced commercial operations in July 2016. Additionally, revenue from leased storage along our pipeline system increased due to new customer contracts;

• a decrease in crude oil revenue of $1.1 million primarily due to lower volumes on the Longhorn pipeline as shippers utilized historical credits (earned by shipping in excess of their minimum commitments in the past) that were set to expire in the third quarter of 2016. This decline was partially offset by higher revenue from leased storage primarily due to strong demand at our East Houston terminal; and

• an increase in marine storage revenue of $1.1 million primarily due to higher average rates from contract renewals and escalations in the current period.

Affiliate management fee revenue increased $1.4 million, primarily resulting from a one-time start-up fee received from Saddlehorn, which began operations in September 2016.

Operating expenses decreased by $12.1 million primarily resulting from:

• a decrease in refined products expenses of $13.2 million primarily due to lower asset integrity spending related to the timing of tank maintenance work, lower environmental accruals related to historical remediation sites, more favorable product overages in the current period (which reduce operating expenses) and lower asset retirements, partially offset by rental costs related to a pipeline segment we began leasing in third quarter 2016 in connection with our Little Rock pipeline;

• an increase in crude oil expenses of $0.2 million primarily due to higher personnel costs resulting from additional headcount, partially offset by lower power costs; and

• an increase in marine storage expenses of $1.7 million primarily due to higher asset integrity spending related to the timing of tank inspections and maintenance work.

Product sales revenue resulted primarily from our butane blending activities, transmix fractionation and the sale of product gains from our operations. We utilize New York Mercantile Exchange (“NYMEX”) contracts to hedge against changes in the price of petroleum products we expect to sell in the future, and we use butane futures agreements to hedge against changes in the price of butane we expect to purchase in future periods. See Note 8 –Derivative Financial Instruments in Item 1 of Part I for a discussion of our hedging strategies and how our use of NYMEX contracts and butane futures agreements impacts our product margin. Product margin decreased $72.1 million due to losses on NYMEX contracts recognized in third quarter 2016 compared to gains in third quarter 2015. See Other Items—Commodity Derivative Agreements—Impact of Commodity Derivatives on Results of Operations below for more information about our NYMEX contracts.

Earnings of non-controlled entities increased $3.0 million primarily attributable to increased earnings from BridgeTex Pipeline Company, LLC (“BridgeTex”) due to higher shipments in third quarter 2016, as well as earnings from Saddlehorn, which began operating during third quarter 2016.

Depreciation and amortization increased $4.9 million primarily due to expansion capital projects recently placed into service and $2.5 million of asset impairment charges in third quarter 2016, mainly related to an inactive pipeline terminal.

G&A expense decreased $1.9 million primarily due to reduced personnel costs from a lower bonus payout accrual and more overhead costs capitalized, partially offset by higher deferred board of director fees.

31

Interest expense, net of interest income and interest capitalized, increased $5.9 million in third quarter 2016, primarily because our debt balance was higher in the current period compared to the same period in third quarter 2015, partially offset by higher capitalized interest. Our average outstanding debt increased from $3.4 billion in third quarter 2015 to $4.0 billion in third quarter 2016 primarily due to borrowings for expansion capital expenditures, including $650.0 million of senior notes issued in February 2016 and $500.0 million of senior notes issued in September 2016. Our weighted-average interest rate of 4.9% in third quarter 2016 was higher than the 4.7% rate incurred in third quarter 2015.

Other expense (income) was $5.0 million favorable due in part to a more favorable non-cash adjustment for the change in the current period in the differential between the current spot price and forward price on fair value hedges associated with our crude oil tank bottoms. Additionally, other income for the current period includes a break-up fee related to a potential acquisition.

32

Nine Months Ended September 30, 2015 compared to Nine Months Ended September 30, 2016

	Nine Months Ended September 30,						Variance Favorable  (Unfavorable)
	2015			2016			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)
Transportation and terminals revenue:
Refined products	$	723.2		$	739.9		$	16.7		2
Crude oil	294.1			303.2			9.1			3
Marine storage	131.9			132.8			0.9			1
Intersegment eliminations	—			(0.1		)	(0.1		)	n/a
Total transportation and terminals revenue	1,149.2			1,175.8			26.6			2
Affiliate management fee revenue	10.5			11.1			0.6			6
Operating expenses:
Refined products	288.3			280.3			8.0			3
Crude oil	65.0			66.4			(1.4		)	(2)
Marine storage	45.9			49.9			(4.0		)	(9)
Intersegment eliminations	(2.8		)	(3.9		)	1.1			39
Total operating expenses	396.4			392.7			3.7			1
Product margin:
Product sales revenue	455.8			403.6			(52.2		)	(11)
Cost of product sales	316.2			327.5			(11.3		)	(4)
Product margin(1)	139.6			76.1			(63.5		)	(45)
Earnings of non-controlled entities	49.6			51.5			1.9			4
Operating margin	952.5			921.8			(30.7		)	(3)
Depreciation and amortization expense	124.2			134.1			(9.9		)	(8)
G&A expense	111.1			111.2			(0.1		)	—
Operating profit	717.2			676.5			(40.7		)	(6)
Interest expense (net of interest income and interest capitalized)	108.0			120.4			(12.4		)	(11)
Gain on exchange of interest in non-controlled entity	—			(28.1		)	28.1			n/a
Other income	(4.6		)	(7.6		)	3.0			65
Income before provision for income taxes	613.8			591.8			(22.0		)	(4)
Provision for income taxes	1.8			2.3			(0.5		)	(28)
Net income	$	612.0		$	589.5		$	(22.5	)	(4)
Operating Statistics:
Refined products:
Transportation revenue per barrel shipped	$	1.417		$	1.451
Volume shipped (million barrels):
Gasoline	203.3			204.9
Distillates	112.0			110.0
Aviation fuel	16.1			19.6
Liquefied petroleum gases	9.3			9.9
Total volume shipped	340.7			344.4
Crude oil:
Magellan 100%-owned assets:
Transportation revenue per barrel shipped	$	1.104		$	1.325
Volume shipped (million barrels)	157.4			139.5
Crude oil terminal average utilization (million barrels per month)	13.0			14.7
Select joint venture pipelines:
BridgeTex - volume shipped (million barrels)(2)	57.2			58.7
Marine storage:
Marine terminal average utilization (million barrels per month)	24.1			23.6

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

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

33

Transportation and terminals revenue increased $26.6 million resulting from:

• an increase in refined products revenue of $16.7 million primarily attributable to higher average tariff rates and increased shipments. The average rate per barrel in the current period was favorably impacted by the mid-year 2015 tariff rate increase of 4.6% and the mid-year 2016 increase which averaged approximately 2% across all of our markets. Shipments increased 1% in the current period primarily associated with higher gasoline shipments, additional volumes from recent growth projects, including our Little Rock pipeline which commenced commercial operations in July 2016, and increased demand for aviation fuel. Additionally, revenue from leased storage along our pipeline system increased due to new customer contracts;

• an increase in crude oil revenue of $9.1 million primarily due to higher average rates and more shipments on our Longhorn pipeline system, as well as new leased storage contracts. Overall crude oil shipments declined and average rate per barrel increased due to fewer barrels moving on our lower-priced Houston distribution system tariff structure to their ultimate destination. Instead, customers utilized space available on our capacity lease for shipments from BridgeTex pipeline; and

• an increase in marine storage revenue of $0.9 million primarily due to higher average contract renewal rates, other escalations in the current period, and new contracts, partially offset by lower miscellaneous revenue due to lower customer activity.

Affiliate management fee revenue increased $0.6 million primarily resulting from a one-time start-up fee received from Saddlehorn, which began operations in September 2016, partially offset by lower construction management fees received from BridgeTex and lower fees from Osage Pipe Line Company, LLC (“Osage”) due to the transfer of our 50% membership interest in 2016.

Operating expenses decreased by $3.7 million primarily resulting from:

• a decrease in refined products expenses of $8.0 million primarily due to lower asset integrity spending related to the timing of tank maintenance work, lower environmental costs and more favorable product gains (which reduce operating expenses), partially offset by more product handling costs related to the receipt of off-spec product during 2016 and higher asset retirements;

• an increase in crude oil expenses of $1.4 million primarily due to increased personnel costs, additional environmental accruals due to a product release in the current year and higher property taxes, partially offset by lower power costs and more favorable product overages (which reduce operating expenses); and

• an increase in marine storage expenses of $4.0 million primarily due to higher asset integrity spending related to the timing of tank maintenance work.

Product margin decreased $63.5 million compared to 2015 primarily due to losses on NYMEX contracts recognized in 2016 compared to gains in 2015. See Other Items—Commodity Derivative Agreements—Impact of Commodity Derivatives on Results of Operations below for more information about our NYMEX contracts.

Earnings of non-controlled entities increased $1.9 million primarily attributable to increased earnings from Double Eagle Pipeline LLC (“Double Eagle”) due to increased shipments during 2016 and earnings from Saddlehorn, which began operations in September 2016, partially offset by lower earnings from Osage due to the transfer of our 50% membership interest in first quarter 2016.

Depreciation and amortization increased $9.9 million primarily due to expansion capital projects placed into service and $2.5 million of asset impairment charges during 2016 mainly related to an inactive pipeline terminal.

G&A expense was $0.1 million higher primarily due to higher deferred board of director fees, partially offset by a separation fee paid to a former executive in 2015.

Interest expense, net of interest income and interest capitalized, increased $12.4 million in 2016, primarily because our debt balance was higher in the current period compared to the same period in 2015, partially offset by

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higher capitalized interest. Our average outstanding debt increased from $3.3 billion in 2015 to $3.8 billion in 2016 primarily due to borrowings for expansion capital expenditures, including $650.0 million of senior notes issued in February 2016 and $500.0 million of senior notes issued in September 2016. Our weighted-average interest rate of 4.9% in 2016 was higher than the 4.7% rate incurred in 2015.

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

Other income increased $3.0 million primarily due to a break-up fee received in 2016 related to a potential acquisition.

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, 2015 and 2016 to net income, which is its nearest comparable GAAP financial measure, follows (in millions):

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	Nine Months Ended September 30,						Increase (Decrease)
	2015			2016
Net income	$	612.0		$	589.5		$	(22.5	)
Interest expense, net(1)	108.0			120.4			12.4
Depreciation and amortization	124.2			134.1			9.9
Equity-based incentive compensation(2)	(2.6		)	0.4			3.0
Loss on sale and retirement of assets	4.4			5.4			1.0
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)	(54.2		)	10.1			64.3
Derivative gains (losses) recognized in previous periods associated with product sales completed in the period(5)	96.1			38.6			(57.5		)
Lower-of-cost-or-market adjustments(6)	(38.7		)	(2.8		)	35.9
Total commodity-related adjustments	3.2			45.9			42.7
Cash distributions received from non-controlled entities in excess of (less than) earnings for the period	7.5			3.0			(4.5		)
Other(4)	—			3.9			3.9
Adjusted EBITDA	856.7			874.5			17.8
Interest expense, net, excluding debt issuance cost amortization(1)	(106.0		)	(118.1		)	(12.1		)
Maintenance capital(7)	(64.7		)	(86.1		)	(21.4		)
DCF	$	686.0		$	670.3		$	(15.7	)

(1) In 2015, we adopted Accounting Standards Update (“ASU”) No. 2015-03, Interest: Simplifying the Presentation of Debt Issuance Costs. Under this new accounting standard, we have reclassified debt issuance cost amortization expense as interest expense. For the purposes of calculating DCF, we have excluded debt issuance cost amortization from interest expense of $1.9 million and $2.3 million for the nine months ended September 30, 2015 and 2016, respectively.

(2) Because we intend to satisfy vesting of units under our equity-based incentive compensation program with the issuance of limited partner units, expenses related to this program generally are deemed non-cash and added back for DCF purposes. Total equity-based incentive compensation expense for the nine months ended September 30, 2015 and 2016 was $15.2 million and $14.7 million, respectively. However, the figures above include an adjustment for minimum statutory tax withholdings we paid in 2015 and 2016 of $17.8 million and $14.4 million, respectively, for equity-based incentive compensation units that vested on the previous year end, which reduces DCF.

(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 we recorded as intangible assets and other receivables in our consolidated balance sheets.  We recorded a $28.1 million non-cash gain in relation to this transaction.

(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 products are physically sold, the net impact of the associated hedges is included in our determination of DCF.

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

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

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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 $724.1 million and $639.0 million for the nine months ended September 30,2015 and 2016, respectively. The $85.1 million decrease from 2015 to 2016 was due to changes in our working capital, adjustments for non-cash items and lower net income related to activities previously described.

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

Net cash used by investing activities for the nine months ended September 30,2015 and 2016 was $606.8 million and $682.1 million, respectively. 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, which we account for as investments in non-controlled entities. During 2015, we incurred $439.7 million for capital expenditures, which included $64.7 million for maintenance capital and $375.0 million for expansion capital. Also during the 2015 period, we acquired a refined products terminal in the Atlanta, Georgia market for $54.7 million and contributed capital of $133.4 million in conjunction with our joint venture capital projects.

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

Net cash used by financing activities was $125.4 million and net cash provided by financing activities was $305.5 million for the nine months ended September 30, 2015 and 2016, respectively. During 2016, we have 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 have 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 January 2013 equity-based incentive compensation award grants were settled by issuing 350,552 limited partner units and distributing those units to the long-term incentive plan (“LTIP”) participants, resulting in payments of associated tax withholdings of $14.4 million. During 2015, we paid cash distributions of $489.5 million to our unitholders. Additionally, we received net proceeds of $499.6 million from borrowings under long-term notes, which were used in part to repay borrowings outstanding under our commercial paper program and for general partnership purposes, including expansion capital. In connection with the borrowings under long-term notes, we paid $42.9 million in settlement of associated interest rate swap agreements. Also, in January 2015, the cumulative amounts of the January 2012 equity-based incentive compensation award grants were settled by issuing 354,529 limited partner units and distributing those units to the LTIP participants, resulting in payments of associated tax withholdings of $17.8 million.

The quarterly distribution amount related to our third-quarter 2016 financial results (to be paid in fourth quarter 2016) is $0.8375 per unit.  If we are able to meet management’s targeted distribution growth of 10% for 2016 and the number of outstanding limited partner units remains at 227.8 million, total cash distributions of approximately $755.0 million will be paid to our unitholders related to 2016 earnings. Management believes we will have sufficient DCF to fund these distributions.

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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 capital expenditures that increase storage or throughput volumes or develop pipeline connections to new supply sources.

For the nine months ended September 30,2016, our maintenance capital spending was $86.1 million. For 2016, we expect to spend approximately $105.0 million on maintenance capital.

During the first nine months of 2016, we spent $428.1 million for organic growth capital and contributed $174.9 million for capital projects in conjunction with our joint ventures. Based on the progress of expansion projects already underway, we expect to spend approximately $850 million during 2016, $300 million during 2017 and $250 million during 2018 to complete our current projects. These estimates include $335 million to construct our new marine terminal in Pasadena, Texas, including approximately one million barrels of storage on nearly 200 acres of newly-acquired land and a ship dock, which are expected to be operational in early 2019.

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 facilities, as well as from other borrowings or issuances of debt or limited partner units (see Note 7 – Debt of the consolidated financial statements included in Item 1 of Part I of this report for detail of our borrowings and debt outstanding at December 31, 2015 and September 30, 2016). 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

Condensate Splitter. We are constructing a condensate splitter at our terminal in Corpus Christi, Texas based on a commitment from a single customer, an affiliate of Trafigura, AG. The project also includes construction of more than one million barrels of storage, dock improvements and two additional truck rack bays at our terminal as well as pipeline connectivity between our terminal and a nearby facility also used by our customer. Due to construction delays, we currently expect the project to be operational late in the fourth quarter of 2016 and the total cost of the project to be approximately $300 million, approximately one third of which relates to the splitter and the remainder to the related infrastructure. Further delays in the construction, commissioning or testing of the facility could result in additional costs or a delay in our realizing revenues or profits from the project, and in certain circumstances could result in the termination by our customer of its commitment to us as early as first quarter 2017, which could materially reduce the revenues and profits we expect to realize from the project and the value of the splitter.

Commodity Derivative Agreements. Certain of the business activities in which we engage result in our owning various commodities, which exposes us to commodity price risk. We use forward physical commodity contracts and NYMEX contracts to help manage this commodity price risk. We use forward physical contracts to purchase butane and sell refined products. We account for these forward physical contracts as normal purchase and sale contracts, using traditional accrual accounting.  We use NYMEX contracts to hedge against changes in 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 NYMEX contracts that qualify for hedge accounting treatment as either cash flow or fair value hedges, and we use and account for those NYMEX contracts that do not qualify for hedge accounting treatment as economic hedges. As of and for the nine months ended September 30, 2016, our open derivative contracts and the impact of the derivatives we settled during the period were as follows:

Derivative Contracts Designated as Hedges

• NYMEX contracts covering 0.7 million barrels of crude oil to hedge against future price changes of crude oil tank bottoms. These contracts, which we are accounting for as fair value hedges, mature November 2017. Through September 30, 2016, the cumulative amount of gains from these agreements was $17.6 million. The cumulative gains from these fair value hedges were recorded as adjustments to the asset being hedged, and there has been no ineffectiveness recognized for these hedges. We exclude the differential between the current spot price and forward price from our assessment of hedge effectiveness for these fair value hedges. The net change in the amounts excluded from our assessment of hedge effectiveness during the nine months ended September 30, 2016 was a gain of $4.5 million, which we recognized as other income on our consolidated statements of income.

Derivative Contracts Not Designated as Hedges – Open

• NYMEX contracts covering 4.7 million barrels of refined products and crude oil related to our butane blending, fractionation and certain crude oil inventory. These contracts mature between October 2016 and April 2017 and are being accounted for as economic hedges. Through September 30, 2016, the cumulative amount of net unrealized losses associated with these agreements was $13.6 million. We recorded these net losses as an adjustment to product sales revenue, of which $7.0 million of net gains was recognized in 2015 and $20.6 million of net losses was recognized in 2016.

• NYMEX contracts covering 0.4 million barrels of refined products and crude oil related to inventory we carry that resulted from pipeline product overages. These contracts, which mature between October and December 2016, are being accounted for as economic hedges. Through September 30, 2016, the cumulative amount of net unrealized losses associated with these agreements was $2.0 million. We recorded these losses as an adjustment to operating expense, all of which was recognized in 2016.

• NYMEX contracts covering 1.3 million barrels of butane purchases that mature between October 2016 and April 2017, which are being accounted for as economic hedges. Through September 30, 2016, the

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cumulative amount of net unrealized gains associated with these agreements was $3.1 million. We recorded these gains as an adjustment to cost of product sales, of which $0.4 million of net losses was recognized in 2015 and $3.5 million of net gains was recognized in 2016.

Derivative Contracts Not Designated as Hedges – Settled

• NYMEX contracts covering 7.9 million barrels of refined products and crude oil related to economic hedges of products from our butane blending, fractionation and certain crude oil inventory activities that we sold during 2016.  We recognized a gain of $12.2 million in 2016 related to these contracts, which we recorded as an adjustment to product sales revenue.

• NYMEX contracts covering 7.8 million barrels of refined products and crude oil related to economic hedges of product inventories from product overages on our pipeline system that we sold during 2016.  We recognized a gain of $0.8 million in 2016 on the settlement of these contracts, which we recorded as an adjustment to operating expense.

• NYMEX contracts covering 1.1 million barrels related to economic hedges of butane purchases we made during 2016 associated with our butane blending activities.  We recognized a gain of $0.1 million in 2016 on the settlement of these contracts, which we recorded as an adjustment to cost of product sales.

Impact of Commodity Derivatives on Results of Operations

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

	Nine Months Ended September 30, 2015
	Product Sales Revenue		Cost of Product Sales			Operating Expense		Other Income		Net Impact on Net Income
NYMEX gains (losses) recorded on open contracts during the period	$	0.2	$	(0.7	)	$	6.6	$	—	$	6.1
NYMEX gains (losses) recognized on settled contracts during the period	52.2		(5.1		)	0.6		4.6		52.3
Net impact of NYMEX contracts	$	52.4	$	(5.8	)	$	7.2	$	4.6	$	58.4

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

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.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We may be exposed to market risk through changes in commodity prices and interest rates 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 NYMEX 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, 2016, we had commitments under forward purchase and sale contracts used in our butane blending and fractionation activities as follows (in millions):

	Total		< 1 Year		1 - 3 Years
Forward purchase contracts – notional value	$	178.1	$	61.4	$	116.7
Forward purchase contracts – barrels	5.3		1.8		3.5
Forward sales contracts – notional value	$	83.3	$	82.0	$	1.3
Forward sales contracts – barrels	1.4		1.4		—

We use NYMEX contracts to hedge against changes in the price of petroleum products we expect to sell or purchase. Some of these NYMEX contracts qualify for hedge accounting treatment, and we designate and account for these contracts as either cash flow or fair value hedges. We account for those NYMEX contracts that do not qualify for hedge accounting treatment as economic hedges.

At September 30, 2016, we had open NYMEX contracts representing 5.8 million barrels of petroleum products we expect to sell in the future. Additionally, we had open NYMEX contracts for 1.3 million barrels of butane we expect to purchase in the future. At September 30, 2016, the fair value of our open NYMEX contracts was a net liability of $12.3 million.

At September 30, 2016, open NYMEX contracts, primarily sales contracts, representing 5.1 million barrels of petroleum products did not qualify for hedge accounting treatment. A $10.00 per barrel increase in the price of these NYMEX contracts for the related petroleum products would result in a $51.0 million decrease in our operating profit and a $10.00 per barrel decrease in the price of these NYMEX contracts would result in a $51.0 million increase in our operating profit.

At September 30, 2016, we had open NYMEX contracts, primarily purchase contracts, representing 1.3 million barrels of butane we expect to purchase in the future. Relative to these agreements, a $10.00 per barrel increase in the price of butane would result in a $13.0 million increase in our operating profit and a $10.00 per barrel decrease in the price of butane would result in a $13.0 million decrease in our operating profit.

The increases or decreases in operating profit we recognize from our open NYMEX forward sales and price swap contracts would be substantially offset by higher or lower product sales revenue or cost of product sales when the physical sale or purchase of those products occur. These contracts may be for the purchase or sale of product in markets different from those in which we are attempting to hedge our exposure and the resulting hedges may not eliminate all price risks.

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Interest Rate Risk

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

During 2016, we 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 value of these contracts at September 30, 2016 was a net liability of $3.5 million. We account for these agreements as cash flow hedges. A 0.125% decrease in interest rates would result in an increase in the fair value of this liability of approximately $3.0 million. A 0.125% increase in interest rates would result in a favorable impact of approximately $2.7 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, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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Forward-Looking Statements

Certain matters discussed in this Quarterly Report on Form 10-Q include forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act that discuss our expected future results based on current and pending business operations. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. Forward-looking statements can be identified by words such as “anticipates,” “targets,” “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;

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

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

• changes in the financial condition of our customers, vendors, derivatives counterparties, 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 and geothermal energy, increased use of biofuels such as ethanol and biodiesel, increased conservation or fuel efficiency, as well as regulatory developments or other trends that could affect demand for our services;

• changes in the throughput or interruption in service 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 implemented by the Federal Energy Regulatory Commission, the U.S. Surface Transportation Board or state regulatory agencies;

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

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

• an increase in the competition our operations encounter;

• the occurrence of natural disasters, terrorism, operational hazards, equipment failures, system failures or unforeseen interruptions;

• 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;

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

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

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

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

• actions by rating agencies concerning our credit ratings;

• our ability to timely obtain and maintain all necessary approvals, consents and permits required to operate our existing assets and 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 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 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

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

U.S. Oil Recovery, EPA ID No.: TXN000607093 Superfund Site. We have liability at the U.S. Oil Recovery Superfund Site in Pasadena, Texas as a potential responsible party (“PRP”) under Section 107(a) of the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (“CERCLA”). As a result of the EPA’s Administrative Settlement Agreement and Order on Consent for Removal Action, filed August 25, 2011, EPA Region 6, CERCLA Docket No. 06-10-11, we voluntarily entered into the PRP group responsible for the site investigation, stabilization and subsequent site cleanup. We have paid $15,000 associated with the assessment phase. Until this assessment phase has been completed, we cannot reasonably estimate our proportionate share of the remediation costs associated with this site. 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 are in the process of voluntarily entering 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.

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 possible injuries. The National Transportation Safety Board is investigating the event. On October 21, 2016, the U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration (“PHMSA”) issued a Corrective Action Order to Magellan Ammonia Pipeline, L.P. related to the event, which, among other things, requires PHMSA’s approval prior to re-start of the affected pipeline segment. 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 Securities and Exchange Commission.

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.

45

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, 2015, 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.

46

ITEM 6. EXHIBITS

Exhibit Number		Description
Exhibit 4.1*	—	Seventh Supplemental Indenture dated as of September 13, 2016, between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed September 13, 2016).
Exhibit 10.1*	—	First Amendment to 364-Day Credit Agreement, dated as of October 20, 2016, among Magellan Midstream Partners, L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (filed as Exhibit 10.1 to Form 8-K filed October 20, 2016).
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.

____________________

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

47

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, 2016.

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)

48

INDEX TO EXHIBITS

Exhibit Number		Description
Exhibit 4.1*	—	Seventh Supplemental Indenture dated as of September 13, 2016, between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed September 13, 2016).
Exhibit 10.1*	—	First Amendment to 364-Day Credit Agreement, dated as of October 20, 2016, among Magellan Midstream Partners, L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (filed as Exhibit 10.1 to Form 8-K filed October 20, 2016).
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.

____________________

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

49

EX-12

Exhibit 12

MAGELLAN MIDSTREAM PARTNERS, L.P.

RATIO OF EARNINGS TO FIXED CHARGES

(In thousands)

	Year Ended December 31,															Year-to-Date Period Ending September 30, 2016
	2011			2012			2013			2014			2015
EARNINGS:
Income from continuing operations before income taxes, extraordinary gain (loss) and cumulative effect of change in accounting principle*	$	408,669		$	435,331		$	580,575		$	824,745		$	754,975		$	540,231
Add: Fixed charges	110,946			120,321			133,511			146,835			160,044			143,553
Amortization of interest capitalized	739			755			816			900			993			1,350
Distributed income of equity investees	5,598			7,793			3,274			3,086			66,285			50,047
Less: Interest capitalized	(3,174		)	(6,195		)	(14,339		)	(22,803		)	(14,442		)	(21,143		)
Total earnings	$	522,778		$	558,005		$	703,837		$	952,763		$	967,855		$	714,038
FIXED CHARGES:
Interest expense	$	110,700		$	120,068		$	132,887		$	145,862		$	158,895		$	142,573
Rent expense representative of interest factor	246			253			624			973			1,149			980
Total fixed charges	$	110,946		$	120,321		$	133,511		$	146,835		$	160,044		$	143,553
Ratio of earnings to fixed charges	4.7			4.6			5.3			6.5			6.0			5.0

* Excludes income from equity investments.

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Michael N. Mears, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ending September 30, 2016 (this “report”) of Magellan Midstream Partners, L.P. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 2, 2016

/s/ Michael N. Mears

Michael N. Mears, principal executive officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Aaron L.Milford, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ending September 30, 2016 (this “report”) of Magellan Midstream Partners, L.P. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 2, 2016

/s/ Aaron L. Milford

Aaron L. Milford, principal financial and accounting officer

EX-32.1

Exhibit 32.1

The following certification shall not be deemed “filed” for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of that section. Such certification shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent that the registrant specifically incorporates it by reference.

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Magellan Midstream Partners, L.P. (the “Partnership”) for the quarter ending September 30, 2016, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael N. Mears, Chief Executive Officer of Magellan GP, LLC, the General Partner of the Partnership, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

/s/ Michael N. Mears

Michael N. Mears, Chief Executive Officer

Date: November 2, 2016

A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

The following certification shall not be deemed “filed” for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of that section. Such certification shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent that the registrant specifically incorporates it by reference.

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Magellan Midstream Partners, L.P. (the “Partnership”) for the quarter ending September 30, 2016, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Aaron L. Milford, Chief Financial Officer of Magellan GP, LLC, the General Partner of the Partnership, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

/s/ Aaron L. Milford

Aaron L. Milford, Chief Financial Officer

Date: November 2, 2016

A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Nov. 01, 2016
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3
Entity Registrant Name	MAGELLAN MIDSTREAM PARTNERS LP
Entity Central Index Key	0001126975
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		227,783,916

XML

Consolidated Statements Of Income - USD ($) shares in Thousands, $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Income Statement [Abstract]
Transportation and terminals revenue		$ 413,433	$ 410,387	$ 1,175,748	$ 1,149,100
Product sales revenue		133,356	172,731	403,607	455,827
Affiliate management fee revenue		4,993	3,557	11,140	10,478
Total revenue		551,782	586,675	1,590,495	1,615,405
Costs and expenses:
Operating		135,286	147,349	392,681	396,374
Cost of product sales		118,242	85,522	327,530	316,208
Depreciation and amortization		47,081	42,043	134,137	124,180
General and administrative		35,800	37,612	111,216	111,052
Total costs and expenses		336,409	312,526	965,564	947,814
Earnings of non-controlled entities		18,576	15,521	51,543	49,653
Operating profit		233,949	289,670	676,474	717,244
Interest expense		50,163	40,419	142,573	118,009
Interest income		(302)	(310)	(1,067)	(993)
Interest capitalized		(7,877)	(3,984)	(21,143)	(9,037)
Gain on exchange of interest in non-controlled entity		0	0	(28,144)	0
Other expense (income)		(3,324)	1,706	(7,519)	(4,554)
Income before provision for income taxes		195,289	251,839	591,774	613,819
Provision for income taxes		738	867	2,294	1,820
Net income		$ 194,551	$ 250,972	$ 589,480	$ 611,999
Basic net income per limited partner unit		$ 0.85	$ 1.10	$ 2.59	$ 2.69
Diluted net income per limited partner unit		$ 0.85	$ 1.10	$ 2.59	$ 2.69
Weighted average number of limited partner units outstanding used for basic net income per unit calculation(1)	[1]	227,960	227,580	227,913	227,540
Weighted average number of limited partner units outstanding used for diluted net income per unit calculation(1)	[1]	227,999	227,945	227,947	227,702

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

XML

Consolidated Statements Of Comprehensive Income - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Statement of Comprehensive Income [Abstract]
Net income		$ 194,551	$ 250,972	$ 589,480	$ 611,999
Other comprehensive income:
Net loss on cash flow hedges(1)	[1]	(3,169)	(3,410)	(24,278)	(16,939)
Reclassification of net loss on cash flow hedges to income(1)	[1]	512	388	1,288	976
Amortization of prior service credit(2)	[2]	(973)	(928)	(2,920)	(2,784)
Amortization of actuarial loss(2)	[2]	1,452	1,798	4,145	5,393
Settlement cost(2)	[2]	202	0	202	0
Total other comprehensive loss		(1,976)	(2,152)	(21,563)	(13,354)
Comprehensive income		$ 192,575	$ 248,820	$ 567,917	$ 598,645

[1] See Note 8–Derivative Financial Instruments for details of the amount of gain/loss recognized in accumulated other comprehensive loss (“AOCL”) for derivative financial instruments and the amount of gain/loss reclassified from AOCL into income.

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

XML

Consolidated Balance Sheets - USD ($) $ in Thousands		Sep. 30, 2016	Dec. 31, 2015
ASSETS
Cash and cash equivalents		$ 291,097	$ 28,731
Trade accounts receivable		126,141	83,893
Other accounts receivable		24,867	12,701
Inventory		123,011	130,868
Energy commodity derivatives contracts, net		0	39,243
Energy commodity derivatives deposits		30,559	0
Other current assets		52,600	43,418
Total current assets		648,275	338,854
Property, plant and equipment		6,657,305	6,166,766
Less: Accumulated depreciation		1,471,263	1,347,537
Net property, plant and equipment		5,186,042	4,819,229
Investments in non-controlled entities		912,419	765,628
Long-term receivables		22,101	20,374
Goodwill		53,260	53,260
Other intangibles (less accumulated amortization of $13,709 and $2,010 at December 31, 2015 and September 30, 2016, respectively)		52,102	1,856
Tank bottoms		35,429	27,533
Other noncurrent assets		10,157	14,833
Total assets		6,919,785	6,041,567
LIABILITIES AND PARTNERS’ CAPITAL
Accounts payable		101,012	104,094
Accrued payroll and benefits		39,039	51,764
Accrued interest payable		48,903	51,296
Accrued taxes other than income		53,702	51,587
Environmental liabilities		11,711	15,679
Deferred revenue		98,818	81,627
Accrued product purchases		25,156	31,339
Energy commodity derivatives contracts, net		12,430	0
Energy commodity derivatives deposits		0	24,252
Current portion of long-term debt, net		250,020	250,335
Other current liabilities		43,058	51,099
Total current liabilities		683,849	713,072
Long-term debt, net	[1]	4,073,502	3,189,287
Long-term pension and benefits		70,416	77,551
Other noncurrent liabilities		29,408	24,162
Environmental liabilities		14,078	15,759
Commitments and contingencies
Partners’ capital:
Limited partner unitholders (227,427 units and 227,784 units outstanding at December 31, 2015 and September 30, 2016, respectively)		2,166,445	2,118,086
Accumulated other comprehensive loss		(117,913)	(96,350)
Total partners’ capital		2,048,532	2,021,736
Total liabilities and partners’ capital		$ 6,919,785	$ 6,041,567

[1] Long-term debt is presented net of unamortized debt issuance costs of $18.7 million and $27.4 million at December 31, 2015 and September 30, 2016, respectively.

XML

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Other intangibles, accumulated amortization	$ 2,010	$ 13,709
Limited partner unitholders, units outstanding	227,783,916	227,427,247

XML

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Operating Activities:
Net income	$ 589,480	$ 611,999
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	134,137	124,180
Loss on sale and retirement of assets	5,397	4,378
Earnings of non-controlled entities	(51,543)	(49,653)
Distributions of earnings from investments in non-controlled entities	50,047	47,236
Equity-based incentive compensation expense	14,737	15,226
Settlement cost, amortization of prior service credit and actuarial loss	1,427	2,609
Gain on exchange of interest in non-controlled entity	(28,144)	0
Changes in operating assets and liabilities:
Trade accounts receivable and other accounts receivable	(49,014)	(24,601)
Inventory	7,857	22,581
Energy commodity derivatives contracts, net of derivatives deposits	637	(11,402)
Accounts payable	5,850	12,226
Accrued payroll and benefits	(12,725)	452
Accrued interest payable	(2,393)	(841)
Accrued taxes other than income	2,115	6,334
Accrued product purchases	(6,183)	(23,947)
Deferred revenue	17,191	4,141
Current and noncurrent environmental liabilities	(5,649)	(4,864)
Other current and noncurrent assets and liabilities	(34,229)	(11,950)
Net cash provided by operating activities	638,995	724,104
Investing Activities:
Additions to property, plant and equipment, net(1)	(517,810)	(431,260)
Proceeds from sale and disposition of assets	6,098	3,178
Acquisition of business	0	(54,678)
Investments in non-controlled entities	(174,900)	(133,373)
Distributions in excess of earnings of non-controlled entities	4,500	9,341
Net cash used by investing activities	(682,112)	(606,792)
Financing Activities:
Distributions paid	(548,388)	(489,535)
Net commercial paper repayments	(244,963)	(69,976)
Borrowings under long-term notes	1,142,997	499,589
Debt placement costs	(10,500)	(4,754)
Net payment on financial derivatives	(19,287)	(42,908)
Settlement of tax withholdings on long-term incentive compensation	(14,376)	(17,784)
Net cash provided (used) by financing activities	305,483	(125,368)
Change in cash and cash equivalents	262,366	(8,056)
Cash and cash equivalents at beginning of period	28,731	17,063
Cash and cash equivalents at end of period	291,097	9,007
Supplemental non-cash investing and financing activities:
Contribution of property, plant and equipment to a non-controlled entity	0	13,252
Issuance of limited partner units in settlement of equity-based incentive plan awards	7,092	8,045
(1) Additions to property, plant and equipment	(514,205)	(439,721)
Changes in accounts payable and other current liabilities related to capital expenditures	(3,605)	8,461
Additions to property, plant and equipment, net	$ (517,810)	$ (431,260)

XML

Organization, Description of Business And Basis Of Presentation

9 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization, Description of Business and Basis of Presentation

Organization, Description of Business and Basis of Presentation

Organization

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

Description of Business

We are principally engaged in the transportation, storage and distribution of refined petroleum products and crude oil.  As of September 30, 2016, 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 2,100 miles of crude oil pipelines and storage facilities with an aggregate storage capacity of approximately 23 million barrels, of which approximately 15 million barrels are used for leased storage; and

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

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.

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, 2015, 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, 2016, the results of operations for the three and nine months ended September 30, 2015 and 2016 and cash flows for the nine months ended September 30, 2015 and 2016. The results of operations for the nine months ended September 30, 2016 are not necessarily indicative of the results to be expected for the full year ending December 31, 2016 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, 2015.

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 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which is part of the FASB’s initiative to simplify accounting standards. The guidance requires an entity to make an entity-wide accounting policy election to either estimate the number of awards that are expected to vest or account for forfeitures when they occur, and allows equity classification for awards where employees elect to withhold up to the maximum statutory tax rates in the applicable jurisdictions. The new standard also requires cash paid by employers when directly withholding shares for tax withholding purposes to be classified as a financing activity in the statement of cash flows.

We elected to early adopt ASU 2016-09 during the first quarter of 2016, and this adoption did not have a material impact on our consolidated financial statements. In conjunction with our adoption of this new accounting standard, we have elected to account for equity-based compensation forfeitures as they occur. Additionally, and consistent with our prior accounting policy, we continue to show cash paid when directly withholding shares for tax withholding purposes as a financing activity in our statements of cash flows.

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 May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which eliminates the industry-specific guidance in U.S. GAAP and produces a single, principles-based method for companies to report revenue in their financial statements. This standard requires companies to make more estimates and use more judgment than under current guidance. In addition, all companies must compile more extensive footnote disclosures about how the revenue numbers were derived. This ASU requires full retrospective, modified retrospective or use of the cumulative effect method during the period of adoption. In July 2015, the FASB extended the effective date of this standard from January 1, 2017 to January 1, 2018. We are currently in the process of evaluating the impact this new standard will have on our financial statements.

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Product Sales Revenues

9 Months Ended

Sep. 30, 2016

Product Sales Revenue [Abstract]

Product Sales Revenues

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 New York Mercantile Exchange (“NYMEX”) contracts. See Note 8 – Derivative Financial Instruments for a discussion of our commodity hedging strategies and how our NYMEX contracts impact product sales revenue. All of the petroleum products inventory we physically sell associated with our butane blending and fractionation activities, as well as the barrels from product gains we obtain from our operations, are reported as product sales revenue on our consolidated statements of income.

For the three and nine months ended September 30, 2015 and 2016, product sales revenue included the following (in thousands):

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2015		2016			2015		2016
Physical sale of petroleum products	$	100,829	$	146,006		$	403,395	$	412,045
Change in value of NYMEX contracts	71,902		(12,650		)	52,432		(8,438		)
Total product sales revenue	$	172,731	$	133,356		$	455,827	$	403,607

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Segment Disclosures

9 Months Ended

Sep. 30, 2016

Segment Reporting [Abstract]

Segment Disclosures

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, 2015
	(in thousands)
	Refined Products		Crude Oil			Marine Storage			Intersegment Eliminations			Total
Transportation and terminals revenue	$	264,156	$	101,122		$	45,109		$	—		$	410,387
Product sales revenue	171,775		—			956			—			172,731
Affiliate management fee revenue	—		3,211			346			—			3,557
Total revenue	435,931		104,333			46,411			—			586,675
Operating expenses	108,972		24,572			14,700			(895		)	147,349
Cost of product sales	85,341		—			181			—			85,522
Losses (earnings) of non-controlled entities	48		(14,906		)	(663		)	—			(15,521		)
Operating margin	241,570		94,667			32,193			895			369,325
Depreciation and amortization expense	24,333		9,502			7,313			895			42,043
G&A expenses	22,238		9,818			5,556			—			37,612
Operating profit	$	194,999	$	75,347		$	19,324		$	—		$	289,670

	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	95,776		24,628			16,374			(1,492		)	135,286
Cost of product sales	93,761		24,108			373			—			118,242
Losses (earnings) of non-controlled entities	272		(18,180		)	(668		)	—			(18,576		)
Operating margin	183,582		98,723			33,234			1,291			316,830
Depreciation and amortization expense	28,432		9,333			8,025			1,291			47,081
G&A expenses	22,993		8,493			4,314			—			35,800
Operating profit	$	132,157	$	80,897		$	20,895		$	—		$	233,949

	Nine Months Ended September 30, 2015
	(in thousands)
	Refined Products		Crude Oil			Marine Storage			Intersegment Eliminations			Total
Transportation and terminals revenue	$	723,156	$	294,023		$	131,921		$	—		$	1,149,100
Product sales revenue	453,737		—			2,090			—			455,827
Affiliate management fee revenue	—		9,449			1,029			—			10,478
Total revenue	1,176,893		303,472			135,040			—			1,615,405
Operating expenses	288,265		65,032			45,916			(2,839		)	396,374
Cost of product sales	315,301		—			907			—			316,208
Losses (earnings) of non-controlled entities	146		(47,735		)	(2,064		)	—			(49,653		)
Operating margin	573,181		286,175			90,281			2,839			952,476
Depreciation and amortization expense	71,742		25,995			23,604			2,839			124,180
G&A expenses	68,730		26,935			15,387			—			111,052
Operating profit	$	432,709	$	233,245		$	51,290		$	—		$	717,244

	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	280,261		66,370			49,897			(3,847		)	392,681
Cost of product sales	300,009		26,469			1,052			—			327,530
Losses (earnings) of non-controlled entities	352		(49,870		)	(2,025		)	—			(51,543		)
Operating margin	531,792		296,363			90,026			3,646			921,827
Depreciation and amortization expense	78,523		28,264			23,704			3,646			134,137
G&A expenses	68,852		27,419			14,945			—			111,216
Operating profit	$	384,417	$	240,680		$	51,377		$	—		$	676,474

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Investments in Non-Controlled Entities (Notes)

9 Months Ended

Sep. 30, 2016

Equity Method Investments and Joint Ventures [Abstract]

Investments in Non-Controlled Entities

Investments in Non-Controlled Entities

Our investments in non-controlled entities at September 30, 2016 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%
Powder Springs Logistics, LLC (“Powder Springs”)	50%
Saddlehorn Pipeline Company, LLC (“Saddlehorn”)	40%
Seabrook Logistics, LLC (“Seabrook”)	50%
Texas Frontera, LLC (“Texas Frontera”)	50%

In February 2016, we transferred our 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. We recorded these commercial agreements as $43.7 million of intangible assets and $8.3 million of other receivables in our consolidated balance sheets. The intangible assets will be amortized over the 20-year life of the contracts received. The total gain recorded in 2016 was $28.1 million.

The management fees we have recognized from BridgeTex, Osage, Powder Springs, Saddlehorn and Texas Frontera are reported as affiliate management fee revenue on our consolidated statements of income.  In addition, we receive reimbursement from certain of our joint ventures for costs incurred during construction, which we included as reductions to costs and expenses on our consolidated statements of income. These construction cost reimbursements totaled $1.2 million and $2.7 million during the three and nine months ended September 30, 2016, respectively.

We recognized pipeline capacity lease revenue from BridgeTex of $8.9 million and $8.9 million for the three months ended September 30, 2015 and 2016, respectively, and $25.8 million and $26.6 million for the nine months ended September 30, 2015 and 2016, respectively, which we included in transportation and terminals revenue on our consolidated statements of income.

We recognized throughput revenue from Double Eagle of $0.8 million and $0.9 million for the three months ended September 30, 2015 and 2016, respectively, and $2.6 million and $2.5 million for the nine months ended September 30, 2015 and 2016, respectively, which we included in transportation and terminals revenue on our consolidated statements of income.  At December 31, 2015 and September 30, 2016, respectively, we recognized a $0.2 million and $0.3 million trade accounts receivable from Double Eagle.

At September 30, 2016, we recognized $2.9 million, $1.4 million and $0.5 million of other receivables from Saddlehorn, BridgeTex and Powder Springs, respectively, related to the activities detailed above and miscellaneous cost reimbursements. These receivables are reported in our balance sheets as other accounts receivable.

The financial results from 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/losses of non-controlled entities.

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

	BridgeTex			All Others			Consolidated
Investments at December 31, 2015	$	495,267		$	270,361		$	765,628
Additional investment	31,503			143,397			174,900
Exchange of investment in non-controlled entity	—			(25,105		)	(25,105		)
Earnings of non-controlled entities:
Proportionate share of earnings	45,990			7,256			53,246
Amortization of excess investment and capitalized interest	(1,529		)	(174		)	(1,703		)
Earnings of non-controlled entities	44,461			7,082			51,543
Less:
Distributions of earnings from investments in non-controlled entities	44,461			5,586			50,047
Distributions in excess of earnings of non-controlled entities	3,333			1,167			4,500
Investments at September 30, 2016	$	523,437		$	388,982		$	912,419

Summarized financial information of our non-controlled entities for the three and nine months ended September 30, 2015 and 2016 follows (in thousands):

	Three Months Ended September 30, 2015						Three Months Ended September 30, 2016
	BridgeTex		All Others		Consolidated		BridgeTex		All Others		Consolidated
Revenue	$	47,555	$	12,530	$	60,085	$	55,843	$	14,022	$	69,865
Net income	$	28,150	$	4,151	$	32,301	$	33,514	$	5,149	$	38,663

	Nine Months Ended September 30, 2015						Nine Months Ended September 30, 2016
	BridgeTex		All Others		Consolidated		BridgeTex		All Others		Consolidated
Revenue	$	146,320	$	33,677	$	179,997	$	155,067	$	35,451	$	190,518
Net income	$	91,806	$	11,525	$	103,331	$	91,981	$	14,907	$	106,888

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Inventory

9 Months Ended

Sep. 30, 2016

Inventory Disclosure [Abstract]

Inventory

Inventory

Inventory at December 31, 2015 and September 30, 2016 was as follows (in thousands):

	December 31, 2015		September 30, 2016
Refined products	$	57,455	$	23,028
Crude oil	28,385		20,475
Transmix	21,297		33,108
Liquefied petroleum gases	17,954		40,684
Additives	5,777		5,716
Total inventory	$	130,868	$	123,011

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Employee Benefit Plans

9 Months Ended

Sep. 30, 2016

Compensation and Retirement Disclosure [Abstract]

Employee Benefit Plans

Employee Benefit Plans

We sponsor two pension plans for certain union employees and a pension plan primarily for non-union employees, a postretirement benefit plan for selected employees and a defined contribution plan. The following tables present our consolidated net periodic benefit costs related to the pension and postretirement benefit plans for the three and nine months ended September 30, 2015 and 2016 (in thousands):

	Three Months Ended						Three Months Ended
	September 30, 2015						September 30, 2016
	Pension Benefits			Other  Postretirement Benefits			Pension Benefits			Other  Postretirement Benefits
Components of net periodic benefit costs:
Service cost	$	4,723		$	61		$	4,555		$	53
Interest cost	1,938			109			1,992			148
Expected return on plan assets	(2,009		)	—			(2,235		)	—
Amortization of prior service credit	—			(928		)	(45		)	(928		)
Amortization of actuarial loss	1,577			221			1,161			291
Settlement cost	—			—			202			—
Net periodic benefit cost (credit)	$	6,229		$	(537	)	$	5,630		$	(436	)

	Nine Months Ended						Nine Months Ended
	September 30, 2015						September 30, 2016
	Pension Benefits			Other  Postretirement Benefits			Pension Benefits			Other  Postretirement Benefits
Components of net periodic benefit costs:
Service cost	$	14,168		$	183		$	13,648		$	176
Interest cost	5,815			328			5,970			368
Expected return on plan assets	(6,028		)	—			(6,694		)	—
Amortization of prior service credit	—			(2,784		)	(135		)	(2,785		)
Amortization of actuarial loss	4,730			663			3,485			660
Settlement cost	—			—			202			—
Net periodic benefit cost (credit)	$	18,685		$	(1,610	)	$	16,476		$	(1,581	)

Contributions estimated to be paid into the plans in 2016 are $26.0 million and $0.5 million for the pension and other postretirement benefit plans, respectively.

We match our employees’ qualifying contributions to our defined contribution plan, resulting in expense to us. Expenses related to the defined contribution plan were $1.8 million and $2.4 million, respectively, for the three months ended September 30, 2015 and 2016 and $6.8 million and $7.8 million, respectively, for the nine months ended September 30, 2015 and 2016.

Amounts Included in AOCL

The changes in AOCL related to employee benefit plan assets and benefit obligations for the three and nine months ended September 30, 2015 and 2016 were as follows (in thousands):

	Three Months Ended						Three Months Ended
	September 30, 2015						September 30, 2016
Gains (Losses) Included in AOCL	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Beginning balance	$	(60,104	)	$	(3,110	)	$	(60,045	)	$	(5,433	)
Amortization of prior service credit	—			(928		)	(45		)	(928		)
Amortization of actuarial loss	1,577			221			1,161			291
Settlement cost	—			—			202			—
Ending balance	$	(58,527	)	$	(3,817	)	$	(58,727	)	$	(6,070	)

	Nine Months Ended						Nine Months Ended
	September 30, 2015						September 30, 2016
Gains (Losses) Included in AOCL	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Beginning balance	$	(63,257	)	$	(1,696	)	$	(62,279	)	$	(3,945	)
Amortization of prior service credit	—			(2,784		)	(135		)	(2,785		)
Amortization of actuarial loss	4,730			663			3,485			660
Settlement cost	—			—			202			—
Ending balance	$	(58,527	)	$	(3,817	)	$	(58,727	)	$	(6,070	)

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Debt

9 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

Debt

Debt

The carrying amount of our consolidated debt at December 31, 2015 and September 30, 2016 was as follows (in thousands, except as otherwise noted):

	December 31, 2015		September 30, 2016		Weighted-Average Interest Rate for the Nine Months Ended September 30, 2016 (1)
Commercial paper(2)	$	279,801	$	34,880	0.8%
$250.0 million of 5.65% Notes due 2016(3)	250,208		250,020		5.7%
$250.0 million of 6.40% Notes due 2018	254,694		253,298		5.5%
$550.0 million of 6.55% Notes due 2019	562,600		560,042		5.7%
$550.0 million of 4.25% Notes due 2021	553,002		552,620		4.1%
$250.0 million of 3.20% Notes due 2025	247,788		247,967		3.2%
$650.0 million of 5.00% Notes due 2026(2)	—		644,129		5.1%
$250.0 million of 6.40% Notes due 2037	247,230		247,312		6.4%
$250.0 million of 4.20% Notes due 2042	246,142		246,230		4.3%
$550.0 million of 5.15% Notes due 2043	550,819		550,885		5.1%
$250.0 million of 4.20% Notes due 2045	247,338		247,408		4.7%
$500.0 million of 4.25% Notes due 2046(2)	—		488,731		4.8%
Total debt	3,439,622		4,323,522		4.9%
Less: current portion of long-term debt, net	250,335		250,020
Long-term debt, net(4)	$	3,189,287	$	4,073,502

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

(2) These borrowings were outstanding for only a portion of the nine-month period ending September 30, 2016. The weighted-average interest rate for these borrowings was calculated based on the number of days the borrowings were outstanding during the noted period.

(3) These borrowings will mature in October 2016 and are reflected in current debt on our consolidated balance sheets at December 31, 2015 and September 30, 2016.

(4) Long-term debt is presented net of unamortized debt issuance costs of $18.7 million and $27.4 million at December 31, 2015 and September 30, 2016, respectively.

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

The face value of our debt at December 31, 2015 and September 30, 2016 was $3.4 billion and $4.3 billion, respectively. The difference between the face value and carrying value of our debt outstanding is the unamortized portion of terminated fair value hedges and the unamortized discounts and premiums on debt issuances. Realized gains and losses on fair value hedges and note discounts and premiums are being amortized or accreted to the applicable notes over the respective lives of those notes.

2016 Debt Offering

In September 2016, we issued $500.0 million of our 4.25% notes due 2046 in an underwritten public offering. The notes were issued at 98.762% of par. Net proceeds from this offering were approximately $488.7 million, after underwriting discounts and offering expenses of $5.1 million. The net proceeds from this offering were used to repay our 5.65% senior notes when due in October 2016 and to repay borrowings outstanding under our commercial paper program. The remaining proceeds may be used for general partnership purposes, which may include capital expenditures.

In February 2016, we issued $650.0 million of our 5.00% notes due 2026 in an underwritten public offering. The notes were issued at 99.875% of par. Net proceeds from this offering were approximately $643.8 million, after underwriting discounts and offering expenses of $5.4 million. The net proceeds from this offering were used to repay borrowings outstanding under our commercial paper program and for general partnership purposes, including expansion capital.

Other Debt

Revolving Credit Facilities. At September 30, 2016, 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, 2016. Borrowings under this facility may be used for general partnership purposes, including capital expenditures. As of December 31, 2015 and September 30, 2016, respectively, 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.

At September 30, 2016, the total borrowing capacity under our 364-day credit facility was $250.0 million. The maturity date of this credit facility is October 25, 2016. See Note 14 – Subsequent Events for recent information about this credit facility. Any borrowings under this credit facility are classified as current 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 0.080% and 0.225% depending on our credit ratings. The unused commitment fee was 0.100% at September 30, 2016. Borrowings under this facility may be used for general partnership purposes, including capital expenditures. As of December 31, 2015 and September 30, 2016, respectively, there were no borrowings outstanding under this facility.

Commercial Paper Program. The maturities of our commercial paper notes vary, but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. The commercial paper we can issue is limited by the amounts available under our revolving credit facility up to an aggregate principal amount of $1.0 billion and is classified as long-term debt.

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Derivative Financial Instruments

9 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments

Derivative Financial Instruments

Interest Rate Derivatives

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

During 2016, we 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, 2016 were recorded on our balance sheets as an other noncurrent liability of $3.5 million, with the offset recorded to other comprehensive income. We account for these agreements as cash flow hedges.

During 2015 and 2016, we entered into $250.0 million of forward-starting interest rate swap agreements to hedge against the risk of variability of future interest payments on a portion of debt we anticipated issuing in 2016. We accounted for these agreements as cash flow hedges. When we issued $500.0 million of 4.25% notes due 2046 in September 2016, we settled the associated interest rate swap agreements for a loss of $19.3 million. The loss was recorded to other comprehensive income and will be recognized into earnings as an adjustment to our periodic interest expense accruals over the first ten-year payment period of the associated notes. This loss was also reported as a net payment on financial derivatives in the financing activities of our consolidated statements of cash flows in 2016.

Commodity Derivatives

Hedging Strategies

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

We account for the forward physical purchase and sale contracts we use in our butane blending and fractionation activities as normal purchases and sales. Forward contracts that qualify for and are elected as normal purchases and sales are accounted for using traditional accrual accounting.

The NYMEX contracts that we enter into fall into one of three hedge categories:

Hedge Category	Hedge Purpose	Accounting Treatment
Qualifies For Hedge Accounting Treatment
Cash Flow Hedge	To hedge the variability in cash flows related to a forecasted transaction.	The effective portion of changes in the 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 three and nine months ended September 30, 2015 and 2016, none of the commodity hedging contracts we entered into qualified for or were designated as cash flow hedges.

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

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

We hold petroleum product inventories that we obtain from overages on our pipeline systems. We use NYMEX contracts that are not designated as hedges for accounting purposes to help manage price changes related to these inventory barrels. Period changes in the fair value of these agreements are recognized currently in earnings as adjustments to operating expense.

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

As outlined in the table below, our open NYMEX contracts at September 30, 2016 were as follows:

Type of Contract/Accounting Methodology	Product Represented by the Contract and Associated Barrels	Maturity Dates
NYMEX - Fair Value Hedges	0.7 million barrels of crude oil	November 2017
NYMEX - Economic Hedges	5.1 million barrels of refined products and crude oil	Between October 2016 and April 2017
NYMEX - Economic Hedges	1.3 million barrels of future purchases of butane	Between October 2016 and April 2017

Energy Commodity Derivatives Contracts and Deposits Offsets

At September 30, 2016, we had made margin deposits of $30.6 million for our NYMEX contracts with our counterparties, which were recorded as a current asset under energy commodity derivatives deposits on our consolidated balance sheets. We have the right to offset the combined fair values of our open NYMEX contracts against our margin deposits under a master netting arrangement for each counterparty; however, we have elected to present the combined fair values of our open NYMEX contracts separately from the related margin deposits on our consolidated balance sheets. Additionally, we have the right to offset the fair values of our NYMEX agreements together for each counterparty, which we have elected to do, and we report the combined net balances on our consolidated balance sheets. A schedule of the derivative amounts we have offset and the deposit amounts we could offset under a master netting arrangement are provided below as of December 31, 2015 and September 30, 2016 (in thousands):

	December 31, 2015
Description	Gross Amounts of Recognized Assets		Gross Amounts of Liabilities Offset in the Consolidated Balance Sheets			Net Amounts of Assets Presented in the Consolidated Balance Sheets(1)		Margin Deposit Amounts Not Offset in the Consolidated Balance Sheets			Net Asset Amount(3)
Energy commodity derivatives	$	48,367	$	(5,646	)	$	42,721	$	(24,252	)	$	18,469

	September 30, 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(2)			Margin Deposit Amounts Not Offset in the Consolidated Balance Sheets		Net Asset Amount(3)
Energy commodity derivatives	$	(15,576	)	$	3,247	$	(12,329	)	$	30,559	$	18,230

(1) Net amount includes energy commodity derivative contracts classified as current assets, net, of $39,243 and noncurrent assets of $3,478.

(2) Net amount includes energy commodity derivative contracts classified as current liabilities, net, of $12,430 and noncurrent assets of $101.

(3) 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, 2015 and 2016 were as follows (in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Derivative Losses Included in AOCL	2015			2016			2015			2016
Beginning balance	$	(29,528	)	$	(50,459	)	$	(16,587	)	$	(30,126	)
Net loss on cash flow hedges	(3,410		)	(3,169		)	(16,939		)	(24,278		)
Reclassification of net loss on cash flow hedges to income	388			512			976			1,288
Ending balance	$	(32,550	)	$	(53,116	)	$	(32,550	)	$	(53,116	)

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, 2015 and 2016 of derivatives accounted for under ASC 815-30, Derivatives and Hedging—Cash Flow Hedges, that were designated as hedging instruments (in thousands):

	Three Months Ended September 30, 2015
	Amount of Loss Recognized in AOCL on Derivative				Location of Loss Reclassified from AOCL into  Income	Amount of Loss Reclassified from AOCL into Income
Derivative Instrument						Effective Portion				Ineffective Portion
Interest rate contracts		$	(3,410	)	Interest expense		$	(388	)		$	—

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

	Nine Months Ended September 30, 2015
	Amount of Loss Recognized in AOCL on Derivative				Location of Loss Reclassified from AOCL into  Income	Amount of Loss Reclassified from AOCL into Income
Derivative Instrument						Effective Portion				Ineffective Portion
Interest rate contracts		$	(16,939	)	Interest expense		$	(976	)		$	—

	Nine Months Ended September 30, 2016
	Amount of Loss Recognized in AOCL on Derivative				Location of Loss Reclassified from AOCL into  Income	Amount of Loss Reclassified from AOCL into Income
Derivative Instrument						Effective Portion				Ineffective Portion
Interest rate contracts		$	(24,278	)	Interest expense		$	(1,288	)		$	—

As of September 30, 2016, the net loss estimated to be classified to interest expense over the next twelve months from AOCL is approximately $3.0 million.

During 2015 and 2016, we had open NYMEX contracts on 0.7 million barrels of crude oil that were designated as fair value hedges. Because there was no ineffectiveness recognized on these hedges, the cumulative gains at December 31, 2015 and September 30, 2016 of $27.9 million and $17.6 million, respectively, from these agreements were offset by a cumulative decrease to tank bottoms. The differential between the current spot price and forward price is excluded from the assessment of hedge effectiveness for these fair value hedges. For the three months ended September 30, 2015 and 2016, we recognized a gain (loss) of $(1.7) million and $0.3 million, respectively, and for the nine months ended September 30, 2015 and 2016, we recognized a gain of $4.6 million and $4.5 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.

The following table provides a summary of the effect on our consolidated statements of income for the three and nine months ended September 30, 2015 and 2016 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		2015			2016			2015			2016
NYMEX commodity contracts	Product sales revenue	$	71,902		$	(12,650	)	$	52,432		$	(8,438	)
NYMEX commodity contracts	Operating expenses	14,761			4,212			7,181			(1,192		)
NYMEX commodity contracts	Cost of product sales	(3,767		)	831			(5,847		)	3,643
	Total	$	82,896		$	(7,607	)	$	53,766		$	(5,987	)

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, 2015 and September 30, 2016 (in thousands):

	December 31, 2015
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
NYMEX commodity contracts	Energy commodity derivatives contracts, net	$	60	Energy commodity derivatives contracts, net	$	—
NYMEX commodity contracts	Other noncurrent assets	3,478		Other noncurrent liabilities	—
Interest rate contracts	Other current assets	2,179		Other current liabilities	653
	Total	$	5,717	Total	$	653

	September 30, 2016
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
NYMEX commodity contracts	Other noncurrent assets	$	101	Other noncurrent liabilities	$	—
Interest rate contracts	Other noncurrent assets	—		Other noncurrent liabilities	3,465
	Total	$	101	Total	$	3,465

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, 2015 and September 30, 2016 (in thousands):

	December 31, 2015
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
NYMEX commodity contracts	Energy commodity derivatives contracts, net	$	44,829	Energy commodity derivatives contracts, net	$	5,646
	September 30, 2016
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
NYMEX commodity contracts	Energy commodity derivatives contracts, net	$	3,146	Energy commodity derivatives contracts, net	$	15,576

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Commitments And Contingencies

9 Months Ended

Sep. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Environmental Liabilities

Liabilities recognized for estimated environmental costs were $31.4 million and $25.8 million at December 31, 2015 and September 30, 2016, respectively. We have classified environmental liabilities as current or noncurrent based on management’s estimates regarding the timing of actual payments. Management estimates that expenditures associated with these environmental liabilities will be substantially paid over the next 9 years. Environmental expense 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 $1.3 million and $0.3 million for the three months ended September 30, 2015 and 2016, respectively, and $5.6 million and $4.6 million for the nine months ended September 30, 2015 and 2016, respectively.

Environmental Receivables

Receivables from insurance carriers and other third parties related to environmental matters were $2.6 million at December 31, 2015, of which $0.7 million and $1.9 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 $2.0 million at September 30, 2016, of which $0.8 million and $1.2 million were recorded to other accounts receivable and long-term receivables, respectively, on our consolidated balance sheets.

Other

We are a party to various other claims, legal actions and complaints arising in the ordinary course of business, including without limitation those disclosed in Item 1, Legal Proceedings of Part II of this report on Form 10-Q. While the results cannot be predicted with certainty, management believes the ultimate resolution of these claims, legal actions and complaints after consideration of amounts accrued, insurance coverage or other indemnification arrangements will not have a material adverse effect on our results of operations, financial position or cash flows. See Note 14 – Subsequent Events for additional information about a recent event.

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Long-Term Incentive Plan

9 Months Ended

Sep. 30, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Long-Term Incentive Plan

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, 2016 total 3.0 million.

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

	Three Months Ended							Nine Months Ended
	September 30, 2015							September 30, 2015
	Equity Method		Liability Method			Total		Equity Method		Liability Method		Total
Performance-based awards:
2013 awards	$	1,673	$	(590	)	$	1,083	$	6,246	$	501	$	6,747
2014 awards	1,497		—			1,497		3,980		—		3,980
2015 awards	1,727		—			1,727		3,687		—		3,687
Time-based awards	380		—			380		812		—		812
Total	$	5,277	$	(590	)	$	4,687	$	14,725	$	501	$	15,226
Allocation of LTIP expense on our consolidated statements of income:
G&A expense						$	4,643					$	15,016
Operating expense						44						210
Total						$	4,687					$	15,226

	Three Months Ended						Nine Months Ended
	September 30, 2016						September 30, 2016
	Equity Method		Liability Method		Total		Equity Method		Liability Method		Total
Performance-based awards:
2014 awards	$	1,780	$	—	$	1,780	$	6,168	$	—	$	6,168
2015 awards	1,208		—		1,208		3,679		—		3,679
2016 awards	1,097		—		1,097		3,240		—		3,240
Time-based awards	593		—		593		1,650		—		1,650
Total	$	4,678	$	—	$	4,678	$	14,737	$	—	$	14,737
Allocation of LTIP expense on our consolidated statements of income:
G&A expense					$	4,637					$	14,623
Operating expense					41						114
Total					$	4,678					$	14,737

In February 2016, 218,046 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, 2018.

In February 2016, we issued 350,552 limited partner units to settle unit award grants to certain employees that vested on December 31, 2015. Further, 6,117 limited partner units were issued during 2016 to settle the equity-based retainers paid to the directors of our general partner.

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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Distributions

9 Months Ended

Sep. 30, 2016

Distributions Made to Members or Limited Partners [Abstract]

Distributions

Distributions

Distributions we paid during 2015 and 2016 were as follows (in thousands, except per unit amounts):

Payment Date	Per Unit Cash Distribution Amount			Total Cash Distribution to Limited Partners
02/13/2015		$	0.6950		$	158,061
05/15/2015		0.7175			163,178
08/14/2015		0.7400			168,296
Through 09/30/2015		2.1525			489,535
11/13/2015		0.7625			173,413
Total		$	2.9150		$	662,948
2/12/2016		$	0.7850		$	178,808
5/13/2016		0.8025			182,797
08/12/2016		0.8200			186,783
Through 09/30/2016		2.4075			548,388
11/14/2016(1)		0.8375			190,769
Total		$	3.2450		$	739,157

(1) Our general partner’s board of directors declared this cash distribution in October 2016 to be paid on November 14, 2016 to unitholders of record at the close of business on October 31, 2016.

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Fair Value

9 Months Ended

Sep. 30, 2016

Fair Value Disclosures [Abstract]

Fair Value

Fair Value

Recurring

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

• Interest rate contracts. These include forward-starting interest rate swap agreements to hedge against the risk of variability of interest payments on future debt. These contracts are carried at fair value on our consolidated balance sheets and are valued based on an assumed exchange, at the end of each period, in an orderly transaction with a market participant in the market in which the financial instrument is traded. The exchange value was calculated using present value techniques 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 lease 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, 2015 and September 30, 2016; however, where recent observable market trades were not available, prices were determined using adjustments to the last traded value for that debt issuance or by adjustments to the prices of similar debt instruments of peer entities that are actively traded. The carrying amount of borrowings, if any, under our revolving credit facility and our commercial paper program approximates fair value due to the frequent repricing of these obligations.

Fair Value Measurements - Financial Assets and Liabilities

The following tables summarize the carrying amounts, fair values and recurring fair value measurements recorded or disclosed as of December 31, 2015 and September 30, 2016 based on the three levels established by ASC 820, Fair Value Measurements and Disclosures (in thousands):

	December 31, 2015
Assets (Liabilities)							Fair Value Measurements using:
	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	$	42,721		$	42,721		$	42,721	$	—		$	—
Interest rate contracts	$	1,526		$	1,526		$	—	$	1,526		$	—
Long-term receivables	$	20,374		$	20,374		$	—	$	—		$	20,374
Debt	$	(3,439,622	)	$	(3,284,791	)	$	—	$	(3,284,791	)	$	—

	September 30, 2016
Assets (Liabilities)							Fair Value Measurements using:
	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	$	(12,329	)	$	(12,329	)	$	(12,329	)	$	—		$	—
Interest rate contracts	$	(3,465	)	$	(3,465	)	$	—		$	(3,465	)	$	—
Long-term receivables	$	22,101		$	22,101		$	—		$	—		$	22,101
Debt	$	(4,323,522	)	$	(4,678,925	)	$	—		$	(4,678,925	)	$	—

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Related Party Transactions

9 Months Ended

Sep. 30, 2016

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

Barry R. Pearl is an independent member of our general partner’s board of directors and was also a director of the general partner of Targa Resources Partners, L.P. (“Targa”) through February 29, 2016. In the normal course of business, we purchase butane from subsidiaries of Targa. During Mr. Pearl’s tenure as a director of the general partner of Targa, we made purchases of butane from subsidiaries of Targa of $1.5 million and $14.3 million, respectively, for the three and nine month periods ending September 30, 2015, and $4.7 million for the period from January 1, 2016 through February 29, 2016. These purchases were based on the then-current index prices. We had recognized payables to Targa of $2.0 million at December 31, 2015.

Stacy P. Methvin was elected as an independent member of our general partner’s board of directors on April 23, 2015 and is also a director of one of our customers.  We received tariff revenue from this customer of $4.1 million and $6.7 million, respectively, for the three and nine month periods ending September 30, 2015 and $4.3 million and $12.0 million, respectively, for the three and nine month periods ended September 30, 2016. We recorded receivables of $1.3 million and $1.5 million from this customer at December 31, 2015 and September 30, 2016, respectively.  The tariff revenue we recognized from this customer was in the normal course of business, with rates determined in accordance with published tariffs. 

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

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Subsequent Events

9 Months Ended

Sep. 30, 2016

Subsequent Events [Abstract]

Subsequent Events

Subsequent Events

Recognizable events

No recognizable events occurred subsequent to September 30, 2016.

Non-recognizable events

Renewal of 364-Day Credit Facility. In October 2016, we renewed our 364-day credit facility (see Note 7 - Debt for a description of this facility). The new maturity date is October 19, 2017. All other terms remain the same.

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 possible injuries. The National Transportation Safety Board is investigating the event. On October 21, 2016, the U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration (“PHMSA”) issued a Corrective Action Order to Magellan Ammonia Pipeline, L.P. related to the event, which, among other things, requires PHMSA’s approval prior to re-start of the affected pipeline segment. 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 Securities and Exchange Commission.

Cash Distribution. In October 2016, our general partner’s board of directors declared a quarterly distribution of $0.8375 per unit to be paid on November 14, 2016 to unitholders of record at the close of business on October 31, 2016. The total cash distributions expected to be paid under this declaration are approximately $190.8 million.

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Organization, Description of Business And Basis Of Presentation (Accounting Policies) (Policies)

9 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

New Accounting Pronouncements

New Accounting Pronouncements

In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which is part of the FASB’s initiative to simplify accounting standards. The guidance requires an entity to make an entity-wide accounting policy election to either estimate the number of awards that are expected to vest or account for forfeitures when they occur, and allows equity classification for awards where employees elect to withhold up to the maximum statutory tax rates in the applicable jurisdictions. The new standard also requires cash paid by employers when directly withholding shares for tax withholding purposes to be classified as a financing activity in the statement of cash flows.

We elected to early adopt ASU 2016-09 during the first quarter of 2016, and this adoption did not have a material impact on our consolidated financial statements. In conjunction with our adoption of this new accounting standard, we have elected to account for equity-based compensation forfeitures as they occur. Additionally, and consistent with our prior accounting policy, we continue to show cash paid when directly withholding shares for tax withholding purposes as a financing activity in our statements of cash flows.

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 May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which eliminates the industry-specific guidance in U.S. GAAP and produces a single, principles-based method for companies to report revenue in their financial statements. This standard requires companies to make more estimates and use more judgment than under current guidance. In addition, all companies must compile more extensive footnote disclosures about how the revenue numbers were derived. This ASU requires full retrospective, modified retrospective or use of the cumulative effect method during the period of adoption. In July 2015, the FASB extended the effective date of this standard from January 1, 2017 to January 1, 2018. We are currently in the process of evaluating the impact this new standard will have on our financial statements.

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Product Sales Revenues (Tables)

9 Months Ended

Sep. 30, 2016

Product Sales Revenue [Abstract]

Components of Product Sales Revenues

For the three and nine months ended September 30, 2015 and 2016, product sales revenue included the following (in thousands):

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2015		2016			2015		2016
Physical sale of petroleum products	$	100,829	$	146,006		$	403,395	$	412,045
Change in value of NYMEX contracts	71,902		(12,650		)	52,432		(8,438		)
Total product sales revenue	$	172,731	$	133,356		$	455,827	$	403,607

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Segment Disclosures (Tables)

9 Months Ended

Sep. 30, 2016

Segment Reporting [Abstract]

Schedule of Business Segment Reporting Information

	Three Months Ended September 30, 2015
	(in thousands)
	Refined Products		Crude Oil			Marine Storage			Intersegment Eliminations			Total
Transportation and terminals revenue	$	264,156	$	101,122		$	45,109		$	—		$	410,387
Product sales revenue	171,775		—			956			—			172,731
Affiliate management fee revenue	—		3,211			346			—			3,557
Total revenue	435,931		104,333			46,411			—			586,675
Operating expenses	108,972		24,572			14,700			(895		)	147,349
Cost of product sales	85,341		—			181			—			85,522
Losses (earnings) of non-controlled entities	48		(14,906		)	(663		)	—			(15,521		)
Operating margin	241,570		94,667			32,193			895			369,325
Depreciation and amortization expense	24,333		9,502			7,313			895			42,043
G&A expenses	22,238		9,818			5,556			—			37,612
Operating profit	$	194,999	$	75,347		$	19,324		$	—		$	289,670

	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	95,776		24,628			16,374			(1,492		)	135,286
Cost of product sales	93,761		24,108			373			—			118,242
Losses (earnings) of non-controlled entities	272		(18,180		)	(668		)	—			(18,576		)
Operating margin	183,582		98,723			33,234			1,291			316,830
Depreciation and amortization expense	28,432		9,333			8,025			1,291			47,081
G&A expenses	22,993		8,493			4,314			—			35,800
Operating profit	$	132,157	$	80,897		$	20,895		$	—		$	233,949

	Nine Months Ended September 30, 2015
	(in thousands)
	Refined Products		Crude Oil			Marine Storage			Intersegment Eliminations			Total
Transportation and terminals revenue	$	723,156	$	294,023		$	131,921		$	—		$	1,149,100
Product sales revenue	453,737		—			2,090			—			455,827
Affiliate management fee revenue	—		9,449			1,029			—			10,478
Total revenue	1,176,893		303,472			135,040			—			1,615,405
Operating expenses	288,265		65,032			45,916			(2,839		)	396,374
Cost of product sales	315,301		—			907			—			316,208
Losses (earnings) of non-controlled entities	146		(47,735		)	(2,064		)	—			(49,653		)
Operating margin	573,181		286,175			90,281			2,839			952,476
Depreciation and amortization expense	71,742		25,995			23,604			2,839			124,180
G&A expenses	68,730		26,935			15,387			—			111,052
Operating profit	$	432,709	$	233,245		$	51,290		$	—		$	717,244

	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	280,261		66,370			49,897			(3,847		)	392,681
Cost of product sales	300,009		26,469			1,052			—			327,530
Losses (earnings) of non-controlled entities	352		(49,870		)	(2,025		)	—			(51,543		)
Operating margin	531,792		296,363			90,026			3,646			921,827
Depreciation and amortization expense	78,523		28,264			23,704			3,646			134,137
G&A expenses	68,852		27,419			14,945			—			111,216
Operating profit	$	384,417	$	240,680		$	51,377		$	—		$	676,474

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Investments in Non-Controlled Entities (Tables)

9 Months Ended

Sep. 30, 2016

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments

Our investments in non-controlled entities at September 30, 2016 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%
Powder Springs Logistics, LLC (“Powder Springs”)	50%
Saddlehorn Pipeline Company, LLC (“Saddlehorn”)	40%
Seabrook Logistics, LLC (“Seabrook”)	50%
Texas Frontera, LLC (“Texas Frontera”)	50%

In February 2016, we transferred our 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. We recorded these commercial agreements as $43.7 million of intangible assets and $8.3 million of other receivables in our consolidated balance sheets. The intangible assets will be amortized over the 20-year life of the contracts received. The total gain recorded in 2016 was $28.1 million.

The management fees we have recognized from BridgeTex, Osage, Powder Springs, Saddlehorn and Texas Frontera are reported as affiliate management fee revenue on our consolidated statements of income.  In addition, we receive reimbursement from certain of our joint ventures for costs incurred during construction, which we included as reductions to costs and expenses on our consolidated statements of income. These construction cost reimbursements totaled $1.2 million and $2.7 million during the three and nine months ended September 30, 2016, respectively.

We recognized pipeline capacity lease revenue from BridgeTex of $8.9 million and $8.9 million for the three months ended September 30, 2015 and 2016, respectively, and $25.8 million and $26.6 million for the nine months ended September 30, 2015 and 2016, respectively, which we included in transportation and terminals revenue on our consolidated statements of income.

We recognized throughput revenue from Double Eagle of $0.8 million and $0.9 million for the three months ended September 30, 2015 and 2016, respectively, and $2.6 million and $2.5 million for the nine months ended September 30, 2015 and 2016, respectively, which we included in transportation and terminals revenue on our consolidated statements of income.  At December 31, 2015 and September 30, 2016, respectively, we recognized a $0.2 million and $0.3 million trade accounts receivable from Double Eagle.

At September 30, 2016, we recognized $2.9 million, $1.4 million and $0.5 million of other receivables from Saddlehorn, BridgeTex and Powder Springs, respectively, related to the activities detailed above and miscellaneous cost reimbursements. These receivables are reported in our balance sheets as other accounts receivable.

The financial results from 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/losses of non-controlled entities.

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

	BridgeTex			All Others			Consolidated
Investments at December 31, 2015	$	495,267		$	270,361		$	765,628
Additional investment	31,503			143,397			174,900
Exchange of investment in non-controlled entity	—			(25,105		)	(25,105		)
Earnings of non-controlled entities:
Proportionate share of earnings	45,990			7,256			53,246
Amortization of excess investment and capitalized interest	(1,529		)	(174		)	(1,703		)
Earnings of non-controlled entities	44,461			7,082			51,543
Less:
Distributions of earnings from investments in non-controlled entities	44,461			5,586			50,047
Distributions in excess of earnings of non-controlled entities	3,333			1,167			4,500
Investments at September 30, 2016	$	523,437		$	388,982		$	912,419

Summarized financial information of our non-controlled entities for the three and nine months ended September 30, 2015 and 2016 follows (in thousands):

	Three Months Ended September 30, 2015						Three Months Ended September 30, 2016
	BridgeTex		All Others		Consolidated		BridgeTex		All Others		Consolidated
Revenue	$	47,555	$	12,530	$	60,085	$	55,843	$	14,022	$	69,865
Net income	$	28,150	$	4,151	$	32,301	$	33,514	$	5,149	$	38,663

	Nine Months Ended September 30, 2015						Nine Months Ended September 30, 2016
	BridgeTex		All Others		Consolidated		BridgeTex		All Others		Consolidated
Revenue	$	146,320	$	33,677	$	179,997	$	155,067	$	35,451	$	190,518
Net income	$	91,806	$	11,525	$	103,331	$	91,981	$	14,907	$	106,888

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Inventory (Tables)

9 Months Ended

Sep. 30, 2016

Inventory Disclosure [Abstract]

Schedule of Inventory

Inventory at December 31, 2015 and September 30, 2016 was as follows (in thousands):

	December 31, 2015		September 30, 2016
Refined products	$	57,455	$	23,028
Crude oil	28,385		20,475
Transmix	21,297		33,108
Liquefied petroleum gases	17,954		40,684
Additives	5,777		5,716
Total inventory	$	130,868	$	123,011

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Employee Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2016

Compensation and Retirement Disclosure [Abstract]

Schedule Of Consolidated Net Periodic Benefit Costs

The following tables present our consolidated net periodic benefit costs related to the pension and postretirement benefit plans for the three and nine months ended September 30, 2015 and 2016 (in thousands):

	Three Months Ended						Three Months Ended
	September 30, 2015						September 30, 2016
	Pension Benefits			Other  Postretirement Benefits			Pension Benefits			Other  Postretirement Benefits
Components of net periodic benefit costs:
Service cost	$	4,723		$	61		$	4,555		$	53
Interest cost	1,938			109			1,992			148
Expected return on plan assets	(2,009		)	—			(2,235		)	—
Amortization of prior service credit	—			(928		)	(45		)	(928		)
Amortization of actuarial loss	1,577			221			1,161			291
Settlement cost	—			—			202			—
Net periodic benefit cost (credit)	$	6,229		$	(537	)	$	5,630		$	(436	)

	Nine Months Ended						Nine Months Ended
	September 30, 2015						September 30, 2016
	Pension Benefits			Other  Postretirement Benefits			Pension Benefits			Other  Postretirement Benefits
Components of net periodic benefit costs:
Service cost	$	14,168		$	183		$	13,648		$	176
Interest cost	5,815			328			5,970			368
Expected return on plan assets	(6,028		)	—			(6,694		)	—
Amortization of prior service credit	—			(2,784		)	(135		)	(2,785		)
Amortization of actuarial loss	4,730			663			3,485			660
Settlement cost	—			—			202			—
Net periodic benefit cost (credit)	$	18,685		$	(1,610	)	$	16,476		$	(1,581	)

Schedule of Amounts Recognized in Other Comprehensive Income (Loss)

The changes in AOCL related to employee benefit plan assets and benefit obligations for the three and nine months ended September 30, 2015 and 2016 were as follows (in thousands):

	Three Months Ended						Three Months Ended
	September 30, 2015						September 30, 2016
Gains (Losses) Included in AOCL	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Beginning balance	$	(60,104	)	$	(3,110	)	$	(60,045	)	$	(5,433	)
Amortization of prior service credit	—			(928		)	(45		)	(928		)
Amortization of actuarial loss	1,577			221			1,161			291
Settlement cost	—			—			202			—
Ending balance	$	(58,527	)	$	(3,817	)	$	(58,727	)	$	(6,070	)

	Nine Months Ended						Nine Months Ended
	September 30, 2015						September 30, 2016
Gains (Losses) Included in AOCL	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Beginning balance	$	(63,257	)	$	(1,696	)	$	(62,279	)	$	(3,945	)
Amortization of prior service credit	—			(2,784		)	(135		)	(2,785		)
Amortization of actuarial loss	4,730			663			3,485			660
Settlement cost	—			—			202			—
Ending balance	$	(58,527	)	$	(3,817	)	$	(58,727	)	$	(6,070	)

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Debt (Tables)

9 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

Consolidated Debt

onsolidated debt at December 31, 2015 and September 30, 2016 was as follows (in thousands, except as otherwise noted):

	December 31, 2015		September 30, 2016		Weighted-Average Interest Rate for the Nine Months Ended September 30, 2016 (1)
Commercial paper(2)	$	279,801	$	34,880	0.8%
$250.0 million of 5.65% Notes due 2016(3)	250,208		250,020		5.7%
$250.0 million of 6.40% Notes due 2018	254,694		253,298		5.5%
$550.0 million of 6.55% Notes due 2019	562,600		560,042		5.7%
$550.0 million of 4.25% Notes due 2021	553,002		552,620		4.1%
$250.0 million of 3.20% Notes due 2025	247,788		247,967		3.2%
$650.0 million of 5.00% Notes due 2026(2)	—		644,129		5.1%
$250.0 million of 6.40% Notes due 2037	247,230		247,312		6.4%
$250.0 million of 4.20% Notes due 2042	246,142		246,230		4.3%
$550.0 million of 5.15% Notes due 2043	550,819		550,885		5.1%
$250.0 million of 4.20% Notes due 2045	247,338		247,408		4.7%
$500.0 million of 4.25% Notes due 2046(2)	—		488,731		4.8%
Total debt	3,439,622		4,323,522		4.9%
Less: current portion of long-term debt, net	250,335		250,020
Long-term debt, net(4)	$	3,189,287	$	4,073,502

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

(2) These borrowings were outstanding for only a portion of the nine-month period ending September 30, 2016. The weighted-average interest rate for these borrowings was calculated based on the number of days the borrowings were outstanding during the noted period.

(3) These borrowings will mature in October 2016 and are reflected in current debt on our consolidated balance sheets at December 31, 2015 and September 30, 2016.

(4) Long-term debt is presented net of unamortized debt issuance costs of $18.7 million and $27.4 million at December 31, 2015 and September 30, 2016, respectively.

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Derivative Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule Of NYMEX Contracts And Butane Price Swap Purchase Agreements

As outlined in the table below, our open NYMEX contracts at September 30, 2016 were as follows:

Type of Contract/Accounting Methodology	Product Represented by the Contract and Associated Barrels	Maturity Dates
NYMEX - Fair Value Hedges	0.7 million barrels of crude oil	November 2017
NYMEX - Economic Hedges	5.1 million barrels of refined products and crude oil	Between October 2016 and April 2017
NYMEX - Economic Hedges	1.3 million barrels of future purchases of butane	Between October 2016 and April 2017

Derivatives and Offset Amounts

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, 2015 and September 30, 2016 (in thousands):

	December 31, 2015
Description	Gross Amounts of Recognized Assets		Gross Amounts of Liabilities Offset in the Consolidated Balance Sheets			Net Amounts of Assets Presented in the Consolidated Balance Sheets(1)		Margin Deposit Amounts Not Offset in the Consolidated Balance Sheets			Net Asset Amount(3)
Energy commodity derivatives	$	48,367	$	(5,646	)	$	42,721	$	(24,252	)	$	18,469

	September 30, 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(2)			Margin Deposit Amounts Not Offset in the Consolidated Balance Sheets		Net Asset Amount(3)
Energy commodity derivatives	$	(15,576	)	$	3,247	$	(12,329	)	$	30,559	$	18,230

(1) Net amount includes energy commodity derivative contracts classified as current assets, net, of $39,243 and noncurrent assets of $3,478.

(2) Net amount includes energy commodity derivative contracts classified as current liabilities, net, of $12,430 and noncurrent assets of $101.

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

Derivative Gains Included In Accumulated Other Comprehensive Loss (AOCL)

The changes in derivative activity included in AOCL for the three and nine months ended September 30, 2015 and 2016 were as follows (in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Derivative Losses Included in AOCL	2015			2016			2015			2016
Beginning balance	$	(29,528	)	$	(50,459	)	$	(16,587	)	$	(30,126	)
Net loss on cash flow hedges	(3,410		)	(3,169		)	(16,939		)	(24,278		)
Reclassification of net loss on cash flow hedges to income	388			512			976			1,288
Ending balance	$	(32,550	)	$	(53,116	)	$	(32,550	)	$	(53,116	)

Derivatives And Hedging-Cash Flow Hedges

The following tables provide a summary of the effect on our consolidated statements of income for the three and nine months ended September 30, 2015 and 2016 of derivatives accounted for under ASC 815-30, Derivatives and Hedging—Cash Flow Hedges, that were designated as hedging instruments (in thousands):

	Three Months Ended September 30, 2015
	Amount of Loss Recognized in AOCL on Derivative				Location of Loss Reclassified from AOCL into  Income	Amount of Loss Reclassified from AOCL into Income
Derivative Instrument						Effective Portion				Ineffective Portion
Interest rate contracts		$	(3,410	)	Interest expense		$	(388	)		$	—

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

	Nine Months Ended September 30, 2015
	Amount of Loss Recognized in AOCL on Derivative				Location of Loss Reclassified from AOCL into  Income	Amount of Loss Reclassified from AOCL into Income
Derivative Instrument						Effective Portion				Ineffective Portion
Interest rate contracts		$	(16,939	)	Interest expense		$	(976	)		$	—

	Nine Months Ended September 30, 2016
	Amount of Loss Recognized in AOCL on Derivative				Location of Loss Reclassified from AOCL into  Income	Amount of Loss Reclassified from AOCL into Income
Derivative Instrument						Effective Portion				Ineffective Portion
Interest rate contracts		$	(24,278	)	Interest expense		$	(1,288	)		$	—

Derivatives And Hedging-Overall-Subsequent Measurement

The following table provides a summary of the effect on our consolidated statements of income for the three and nine months ended September 30, 2015 and 2016 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		2015			2016			2015			2016
NYMEX commodity contracts	Product sales revenue	$	71,902		$	(12,650	)	$	52,432		$	(8,438	)
NYMEX commodity contracts	Operating expenses	14,761			4,212			7,181			(1,192		)
NYMEX commodity contracts	Cost of product sales	(3,767		)	831			(5,847		)	3,643
	Total	$	82,896		$	(7,607	)	$	53,766		$	(5,987	)

Derivatives And Hedging-Designated

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, 2015 and September 30, 2016 (in thousands):

	December 31, 2015
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
NYMEX commodity contracts	Energy commodity derivatives contracts, net	$	60	Energy commodity derivatives contracts, net	$	—
NYMEX commodity contracts	Other noncurrent assets	3,478		Other noncurrent liabilities	—
Interest rate contracts	Other current assets	2,179		Other current liabilities	653
	Total	$	5,717	Total	$	653

	September 30, 2016
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
NYMEX commodity contracts	Other noncurrent assets	$	101	Other noncurrent liabilities	$	—
Interest rate contracts	Other noncurrent assets	—		Other noncurrent liabilities	3,465
	Total	$	101	Total	$	3,465

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, 2015 and September 30, 2016 (in thousands):

	December 31, 2015
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
NYMEX commodity contracts	Energy commodity derivatives contracts, net	$	44,829	Energy commodity derivatives contracts, net	$	5,646
	September 30, 2016
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
NYMEX commodity contracts	Energy commodity derivatives contracts, net	$	3,146	Energy commodity derivatives contracts, net	$	15,576

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Long-Term Incentive Plan (Tables)

9 Months Ended

Sep. 30, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Equity-Based Incentive Compensation Expense

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

	Three Months Ended							Nine Months Ended
	September 30, 2015							September 30, 2015
	Equity Method		Liability Method			Total		Equity Method		Liability Method		Total
Performance-based awards:
2013 awards	$	1,673	$	(590	)	$	1,083	$	6,246	$	501	$	6,747
2014 awards	1,497		—			1,497		3,980		—		3,980
2015 awards	1,727		—			1,727		3,687		—		3,687
Time-based awards	380		—			380		812		—		812
Total	$	5,277	$	(590	)	$	4,687	$	14,725	$	501	$	15,226
Allocation of LTIP expense on our consolidated statements of income:
G&A expense						$	4,643					$	15,016
Operating expense						44						210
Total						$	4,687					$	15,226

	Three Months Ended						Nine Months Ended
	September 30, 2016						September 30, 2016
	Equity Method		Liability Method		Total		Equity Method		Liability Method		Total
Performance-based awards:
2014 awards	$	1,780	$	—	$	1,780	$	6,168	$	—	$	6,168
2015 awards	1,208		—		1,208		3,679		—		3,679
2016 awards	1,097		—		1,097		3,240		—		3,240
Time-based awards	593		—		593		1,650		—		1,650
Total	$	4,678	$	—	$	4,678	$	14,737	$	—	$	14,737
Allocation of LTIP expense on our consolidated statements of income:
G&A expense					$	4,637					$	14,623
Operating expense					41						114
Total					$	4,678					$	14,737

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Distributions (Tables)

9 Months Ended

Sep. 30, 2016

Distributions Made to Members or Limited Partners [Abstract]

Schedule Of Distributions

Distributions we paid during 2015 and 2016 were as follows (in thousands, except per unit amounts):

Payment Date	Per Unit Cash Distribution Amount			Total Cash Distribution to Limited Partners
02/13/2015		$	0.6950		$	158,061
05/15/2015		0.7175			163,178
08/14/2015		0.7400			168,296
Through 09/30/2015		2.1525			489,535
11/13/2015		0.7625			173,413
Total		$	2.9150		$	662,948
2/12/2016		$	0.7850		$	178,808
5/13/2016		0.8025			182,797
08/12/2016		0.8200			186,783
Through 09/30/2016		2.4075			548,388
11/14/2016(1)		0.8375			190,769
Total		$	3.2450		$	739,157

(1) Our general partner’s board of directors declared this cash distribution in October 2016 to be paid on November 14, 2016 to unitholders of record at the close of business on October 31, 2016.

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Fair Value (Tables)

9 Months Ended

Sep. 30, 2016

Fair Value Disclosures [Abstract]

Schedule Of Fair Value, Assets and Liabilities Measured on Recurring Basis

The following tables summarize the carrying amounts, fair values and recurring fair value measurements recorded or disclosed as of December 31, 2015 and September 30, 2016 based on the three levels established by ASC 820, Fair Value Measurements and Disclosures (in thousands):

	December 31, 2015
Assets (Liabilities)							Fair Value Measurements using:
	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	$	42,721		$	42,721		$	42,721	$	—		$	—
Interest rate contracts	$	1,526		$	1,526		$	—	$	1,526		$	—
Long-term receivables	$	20,374		$	20,374		$	—	$	—		$	20,374
Debt	$	(3,439,622	)	$	(3,284,791	)	$	—	$	(3,284,791	)	$	—

	September 30, 2016
Assets (Liabilities)							Fair Value Measurements using:
	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	$	(12,329	)	$	(12,329	)	$	(12,329	)	$	—		$	—
Interest rate contracts	$	(3,465	)	$	(3,465	)	$	—		$	(3,465	)	$	—
Long-term receivables	$	22,101		$	22,101		$	—		$	—		$	22,101
Debt	$	(4,323,522	)	$	(4,678,925	)	$	—		$	(4,678,925	)	$	—

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Organization, Description of Business and Basis of Presentation (Narrative) (Details) bbl in Millions	Sep. 30, 2016 Terminal bbl mi
Refined Products [Member]
Organization and Description of Business [Line Items]
Number of Pipeline Terminals | Terminal	53
Number of Independent Terminals | Terminal	26
Refined Products [Member] | Refined Products Transportation Services [Member]
Organization and Description of Business [Line Items]
Pipeline Length | mi	9,700
Refined Products [Member] | Ammonia Transportation Services [Member]
Organization and Description of Business [Line Items]
Pipeline Length | mi	1,100
Crude Oil Pipeline and Terminals [Member]
Organization and Description of Business [Line Items]
Pipeline Length | mi	2,100
Storage Capacity | bbl	23
Leasable Storage Capacity | bbl	15
Marine Storage [Member]
Organization and Description of Business [Line Items]
Number of Independent Terminals | Terminal	5
Storage Capacity | bbl	26

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Product Sales Revenues (Components Of Product Sales Revenues) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Product Sales Revenue [Abstract]
Physical sale of petroleum products	$ 146,006	$ 100,829	$ 412,045	$ 403,395
Change in value of NYMEX contracts	(12,650)	71,902	(8,438)	52,432
Total product sales revenue	$ 133,356	$ 172,731	$ 403,607	$ 455,827

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Segment Disclosures (Schedule Of Business Segment Reporting Information) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Segment Reporting Information [Line Items]
Transportation and terminals revenue	$ 413,433	$ 410,387	$ 1,175,748	$ 1,149,100
Product sales revenue	133,356	172,731	403,607	455,827
Affiliate management fee revenue	4,993	3,557	11,140	10,478
Total revenue	551,782	586,675	1,590,495	1,615,405
Operating expenses	135,286	147,349	392,681	396,374
Cost of product sales	118,242	85,522	327,530	316,208
Earnings of non-controlled entities	(18,576)	(15,521)	(51,543)	(49,653)
Operating margin	316,830	369,325	921,827	952,476
Depreciation and amortization expense	47,081	42,043	134,137	124,180
G&A expenses	35,800	37,612	111,216	111,052
Operating profit	233,949	289,670	676,474	717,244
Operating Segments [Member] | Refined Products [Member]
Segment Reporting Information [Line Items]
Transportation and terminals revenue	267,339	264,156	739,931	723,156
Product sales revenue	105,834	171,775	372,061	453,737
Affiliate management fee revenue	218	0	422	0
Total revenue	373,391	435,931	1,112,414	1,176,893
Operating expenses	95,776	108,972	280,261	288,265
Cost of product sales	93,761	85,341	300,009	315,301
Earnings of non-controlled entities	272	48	352	146
Operating margin	183,582	241,570	531,792	573,181
Depreciation and amortization expense	28,432	24,333	78,523	71,742
G&A expenses	22,993	22,238	68,852	68,730
Operating profit	132,157	194,999	384,417	432,709
Operating Segments [Member] | Crude Oil Pipeline and Terminals [Member]
Segment Reporting Information [Line Items]
Transportation and terminals revenue	100,113	101,122	303,181	294,023
Product sales revenue	24,750	0	26,465	0
Affiliate management fee revenue	4,416	3,211	9,686	9,449
Total revenue	129,279	104,333	339,332	303,472
Operating expenses	24,628	24,572	66,370	65,032
Cost of product sales	24,108	0	26,469	0
Earnings of non-controlled entities	(18,180)	(14,906)	(49,870)	(47,735)
Operating margin	98,723	94,667	296,363	286,175
Depreciation and amortization expense	9,333	9,502	28,264	25,995
G&A expenses	8,493	9,818	27,419	26,935
Operating profit	80,897	75,347	240,680	233,245
Operating Segments [Member] | Marine Storage [Member]
Segment Reporting Information [Line Items]
Transportation and terminals revenue	46,182	45,109	132,837	131,921
Product sales revenue	2,772	956	5,081	2,090
Affiliate management fee revenue	359	346	1,032	1,029
Total revenue	49,313	46,411	138,950	135,040
Operating expenses	16,374	14,700	49,897	45,916
Cost of product sales	373	181	1,052	907
Earnings of non-controlled entities	(668)	(663)	(2,025)	(2,064)
Operating margin	33,234	32,193	90,026	90,281
Depreciation and amortization expense	8,025	7,313	23,704	23,604
G&A expenses	4,314	5,556	14,945	15,387
Operating profit	20,895	19,324	51,377	51,290
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Transportation and terminals revenue	(201)	0	(201)	0
Product sales revenue	0	0	0	0
Affiliate management fee revenue	0	0	0	0
Total revenue	(201)	0	(201)	0
Operating expenses	(1,492)	(895)	(3,847)	(2,839)
Cost of product sales	0	0	0	0
Earnings of non-controlled entities	0	0	0	0
Operating margin	1,291	895	3,646	2,839
Depreciation and amortization expense	1,291	895	3,646	2,839
G&A expenses	0	0	0	0
Operating profit	$ 0	$ 0	$ 0	$ 0

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Investments in Non-Controlled Entities (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
	Feb. 29, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Intangible Assets, Net (Excluding Goodwill)		$ 52,102		$ 52,102		$ 1,856
Equity Method Investment, Realized Gain (Loss) on Disposal		0	$ 0	28,144	$ 0
Change in Equity Method Investments [Roll Forward]
Investments at December 31, 2015				765,628
Additional investment				174,900
Exchange of investment in non-controlled entity				(25,105)
Proportionate share of earnings				53,246
Amortization of excess investment and capitalized interest				(1,703)
Earnings of non-controlled entities		18,576	15,521	51,543	49,653
Distributions of earnings from investments in non-controlled entities				50,047	47,236
Distributions in excess of earnings of non-controlled entities				4,500	9,341
Investments at September 30, 2016		912,419		912,419
Equity Method Investment, Summarized Financial Information, Revenue		69,865	60,085	190,518	179,997
Equity Method Investment, Summarized Financial Information, Net Income (Loss)		$ 38,663	32,301	$ 106,888	103,331
BridgeTex [Member]
Schedule of Equity Method Investments [Line Items]
Interest in equity method investment		50.00%		50.00%
Change in Equity Method Investments [Roll Forward]
Investments at December 31, 2015				$ 495,267
Additional investment				31,503
Exchange of investment in non-controlled entity				0
Proportionate share of earnings				45,990
Amortization of excess investment and capitalized interest				(1,529)
Earnings of non-controlled entities				44,461
Distributions of earnings from investments in non-controlled entities				44,461
Distributions in excess of earnings of non-controlled entities				3,333
Investments at September 30, 2016		$ 523,437		523,437
Equity Method Investment, Summarized Financial Information, Revenue		55,843	47,555	155,067	146,320
Equity Method Investment, Summarized Financial Information, Net Income (Loss)		$ 33,514	28,150	$ 91,981	91,806
Double Eagle Pipeline Llc [Member]
Schedule of Equity Method Investments [Line Items]
Interest in equity method investment		50.00%		50.00%
HoustonLink Pipeline Company LLC [Member]
Schedule of Equity Method Investments [Line Items]
Interest in equity method investment		50.00%		50.00%
Powder Springs Logistics, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Interest in equity method investment		50.00%		50.00%
Saddlehorn Pipeline Company [Member]
Schedule of Equity Method Investments [Line Items]
Interest in equity method investment		40.00%		40.00%
Seabrook Logistics, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Interest in equity method investment		50.00%		50.00%
Texas Frontera Llc [Member]
Schedule of Equity Method Investments [Line Items]
Interest in equity method investment		50.00%		50.00%
Osage Pipeline Co [Member]
Schedule of Equity Method Investments [Line Items]
Interest in equity method investment	50.00%
Intangible Assets, Net (Excluding Goodwill)	$ 43,700
Nontrade Receivables	$ 8,300
Finite-Lived Intangible Asset, Useful Life	20 years
Equity Method Investment, Realized Gain (Loss) on Disposal				$ 28,100
All Other Equity Investments [Member]
Change in Equity Method Investments [Roll Forward]
Investments at December 31, 2015				270,361
Additional investment				143,397
Exchange of investment in non-controlled entity				(25,105)
Proportionate share of earnings				7,256
Amortization of excess investment and capitalized interest				(174)
Earnings of non-controlled entities				7,082
Distributions of earnings from investments in non-controlled entities				5,586
Distributions in excess of earnings of non-controlled entities				1,167
Investments at September 30, 2016		$ 388,982		388,982
Equity Method Investment, Summarized Financial Information, Revenue		14,022	12,530	35,451	33,677
Equity Method Investment, Summarized Financial Information, Net Income (Loss)		5,149	4,151	14,907	11,525
Equity Method Investee [Member] | BridgeTex [Member]
Schedule of Equity Method Investments [Line Items]
Related Party Transaction, Other Revenues from Transactions with Related Party		8,900	8,900	26,600	25,800
Accounts Receivable, Related Parties, Current		1,400		1,400
Equity Method Investee [Member] | Double Eagle Pipeline Llc [Member]
Schedule of Equity Method Investments [Line Items]
Related Party Transaction, Other Revenues from Transactions with Related Party		900	$ 800	2,500	$ 2,600
Accounts Receivable, Related Parties, Current		300		300		$ 200
Equity Method Investee [Member] | Powder Springs Logistics, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Accounts Receivable, Related Parties, Current		500		500
Equity Method Investee [Member] | Saddlehorn Pipeline Company [Member]
Schedule of Equity Method Investments [Line Items]
Accounts Receivable, Related Parties, Current		2,900		2,900
Equity Method Investee [Member] | All Other Equity Investments - Construction [Member]
Schedule of Equity Method Investments [Line Items]
Related Party Transaction, Other Revenues from Transactions with Related Party		$ 1,200		$ 2,700

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Inventory (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Inventory Disclosure [Abstract]
Refined products	$ 23,028	$ 57,455
Crude oil	20,475	28,385
Transmix	33,108	21,297
Liquefied petroleum gases	40,684	17,954
Additives	5,716	5,777
Total inventory	$ 123,011	$ 130,868

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Schedule Of Consolidated Net Periodic Benefit Costs (Details) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($) pension_plan	Sep. 30, 2015 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Number of Union Pension Plans | pension_plan			2
Defined Contribution Plan, Cost Recognized	$ 2,400	$ 1,800	$ 7,800	$ 6,800
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year			26,000
Components of net periodic benefit costs:
Service cost	4,555	4,723	13,648	14,168
Interest cost	1,992	1,938	5,970	5,815
Expected return on plan assets	(2,235)	(2,009)	(6,694)	(6,028)
Amortization of prior service credit	(45)	0	(135)	0
Amortization of actuarial loss	1,161	1,577	3,485	4,730
Settlement cost	202	0	202	0
Net periodic benefit cost (credit)	5,630	6,229	16,476	18,685
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year			500
Components of net periodic benefit costs:
Service cost	53	61	176	183
Interest cost	148	109	368	328
Expected return on plan assets	0	0	0	0
Amortization of prior service credit	(928)	(928)	(2,785)	(2,784)
Amortization of actuarial loss	291	221	660	663
Settlement cost	0	0	0	0
Net periodic benefit cost (credit)	$ (436)	$ (537)	$ (1,581)	$ (1,610)

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Employee Benefit Plans Schedule of Amounts Recognized in Other Comprehensive Income (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Changes in AOCL [Roll Forward]
Accumulated other comprehensive loss (Beginning Bal)				$ (96,350)
Amortization of prior service credit	[1]	$ (973)	$ (928)	(2,920)	$ (2,784)
Amortization of actuarial loss	[1]	1,452	1,798	4,145	5,393
Settlement cost	[1]	202	0	202	0
Accumulated other comprehensive loss (Ending Bal)		(117,913)		(117,913)
Pension Plan [Member]
Changes in AOCL [Roll Forward]
Accumulated other comprehensive loss (Beginning Bal)		(60,045)	(60,104)	(62,279)	(63,257)
Amortization of prior service credit		(45)	0	(135)	0
Amortization of actuarial loss		1,161	1,577	3,485	4,730
Settlement cost		202	0	202	0
Accumulated other comprehensive loss (Ending Bal)		(58,727)	(58,527)	(58,727)	(58,527)
Other Postretirement Benefit Plan [Member]
Changes in AOCL [Roll Forward]
Accumulated other comprehensive loss (Beginning Bal)		(5,433)	(3,110)	(3,945)	(1,696)
Amortization of prior service credit		(928)	(928)	(2,785)	(2,784)
Amortization of actuarial loss		291	221	660	663
Settlement cost		0	0	0	0
Accumulated other comprehensive loss (Ending Bal)		$ (6,070)	$ (3,817)	$ (6,070)	$ (3,817)

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

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Debt (Consolidated Debt) (Details) - USD ($)		Sep. 30, 2016	Feb. 29, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Long term debt		$ 4,323,522,000		$ 3,439,622,000
Weighted-Average Interest Rate	[1]	4.90%
Debt Instrument, Face Amount		$ 4,300,000,000.0		3,400,000,000.0
Current portion of long-term debt, net		250,020,000		250,335,000
Long-term debt, net	[2]	4,073,502,000		3,189,287,000
Senior Notes [Member] | Five Point Six Five Percentage Notes Due Two Thousand Sixteen [Member]
Debt Instrument [Line Items]
Long term debt	[3]	$ 250,020,000		250,208,000
Weighted-Average Interest Rate	[1]	5.70%
Debt Instrument, Face Amount		$ 250,000,000.0		$ 250,000,000
Debt Instrument, Interest Rate, Stated Percentage		5.65%		5.65%
Senior Notes [Member] | 6.40% Notes Due 2018 [Member]
Debt Instrument [Line Items]
Long term debt		$ 253,298,000		$ 254,694,000
Weighted-Average Interest Rate	[1]	5.50%
Debt Instrument, Face Amount		$ 250,000,000.0		$ 250,000,000
Debt Instrument, Interest Rate, Stated Percentage		6.40%		6.40%
Senior Notes [Member] | 6.55% Notes Due 2019 [Member]
Debt Instrument [Line Items]
Long term debt		$ 560,042,000		$ 562,600,000
Weighted-Average Interest Rate	[1]	5.70%
Debt Instrument, Face Amount		$ 550,000,000.0		$ 550,000,000
Debt Instrument, Interest Rate, Stated Percentage		6.55%		6.55%
Senior Notes [Member] | 4.25% Notes Due 2021 [Member]
Debt Instrument [Line Items]
Long term debt		$ 552,620,000		$ 553,002,000
Weighted-Average Interest Rate	[1]	4.10%
Debt Instrument, Face Amount		$ 550,000,000.0		$ 550,000,000
Debt Instrument, Interest Rate, Stated Percentage		4.25%		4.25%
Senior Notes [Member] | 3.20% Notes Due 2025 [Member]
Debt Instrument [Line Items]
Long term debt		$ 247,967,000		$ 247,788,000
Weighted-Average Interest Rate	[1]	3.20%
Debt Instrument, Face Amount		$ 250,000,000.0		$ 250,000,000.0
Debt Instrument, Interest Rate, Stated Percentage		3.20%		3.20%
Senior Notes [Member] | Five Point Zero Percentage Notes Due Two Thousand Twenty Six [Member]
Debt Instrument [Line Items]
Long term debt		$ 644,129,000		$ 0
Weighted-Average Interest Rate	[1],[4]	5.10%
Debt Instrument, Face Amount		$ 650,000,000.0	$ 650,000,000.0	$ 0
Debt Instrument, Interest Rate, Stated Percentage		5.00%	5.00%	0.00%
Senior Notes [Member] | 6.40% Notes Due 2037 [Member]
Debt Instrument [Line Items]
Long term debt		$ 247,312,000		$ 247,230,000
Weighted-Average Interest Rate	[1]	6.40%
Debt Instrument, Face Amount		$ 250,000,000.0		$ 250,000,000
Debt Instrument, Interest Rate, Stated Percentage		6.40%		6.40%
Senior Notes [Member] | 4.20% Notes Due 2042 [Member]
Debt Instrument [Line Items]
Long term debt		$ 246,230,000		$ 246,142,000
Weighted-Average Interest Rate	[1]	4.30%
Debt Instrument, Face Amount		$ 250,000,000.0		$ 250,000,000
Debt Instrument, Interest Rate, Stated Percentage		4.20%		4.20%
Senior Notes [Member] | 5.15% Notes Due 2043 [Member]
Debt Instrument [Line Items]
Long term debt		$ 550,885,000		$ 550,819,000
Weighted-Average Interest Rate	[1]	5.10%
Debt Instrument, Face Amount		$ 550,000,000.0		$ 550,000,000.0
Debt Instrument, Interest Rate, Stated Percentage		5.15%		5.15%
Senior Notes [Member] | 4.20% Notes Due 2045 [Member]
Debt Instrument [Line Items]
Long term debt		$ 247,408,000		$ 247,338,000
Weighted-Average Interest Rate	[1]	4.70%
Debt Instrument, Face Amount		$ 250,000,000.0		$ 250,000,000.0
Debt Instrument, Interest Rate, Stated Percentage		4.20%		4.20%
Senior Notes [Member] | Four Point Two Five Percentage Notes Due Two Thousand Forty Six [Member]
Debt Instrument [Line Items]
Long term debt		$ 488,731,000		$ 0
Weighted-Average Interest Rate	[1]	4.80%
Debt Instrument, Face Amount		$ 500,000,000.0		$ 0
Debt Instrument, Interest Rate, Stated Percentage		4.25%		0.00%
Commercial Paper [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Long term debt		$ 34,880,000		$ 279,801,000
Weighted-Average Interest Rate	[1],[4]	0.80%

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

[2] Long-term debt is presented net of unamortized debt issuance costs of $18.7 million and $27.4 million at December 31, 2015 and September 30, 2016, respectively.

[3] These borrowings will mature in October 2016 and are reflected in current debt on our consolidated balance sheets at December 31, 2015 and September 30, 2016.

[4] These borrowings were outstanding for only a portion of the nine-month period ending September 30, 2016. The weighted-average interest rate for these borrowings was calculated based on the number of days the borrowings were outstanding during the noted period.

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Debt (Narrative) (Details) - USD ($)				9 Months Ended
		Sep. 30, 2016	Feb. 29, 2016	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Debt Instrument [Line Items]
Debt Issuance Costs, Net		$ 27,400,000		$ 27,400,000		$ 18,700,000
Debt Instrument, Face Amount		4,300,000,000.0		4,300,000,000.0		3,400,000,000.0
Borrowings under long-term notes				1,142,997,000	$ 499,589,000
Debt placement costs				10,500,000	$ 4,754,000
Long term debt		4,323,522,000		4,323,522,000		3,439,622,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Short-term Debt		0		0		0
Revolving Credit Facility [Member] | Notes Payable to Banks [Member]
Debt Instrument [Line Items]
Borrowing capacity		250,000,000.0		$ 250,000,000.0
Unused commitment fee				0.10%
Debt Instrument, Term				364 days
Revolving Credit Facility [Member] | Minimum [Member] | Notes Payable to Banks [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate				1.00%
Unused commitment fee				0.08%
Revolving Credit Facility [Member] | Maximum [Member] | Notes Payable to Banks [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate				1.625%
Unused commitment fee				0.225%
Senior Notes [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Borrowing capacity		1,000,000,000.0		$ 1,000,000,000.0
Unused commitment fee				0.125%
Long term debt		0		$ 0		0
Obligation for letters of credit		6,300,000		$ 6,300,000		6,300,000
Senior Notes [Member] | Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate				1.00%
Unused commitment fee				0.10%
Senior Notes [Member] | Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate				1.625%
Unused commitment fee				0.275%
Senior Notes [Member] | Commercial Paper [Member]
Debt Instrument [Line Items]
Borrowing capacity		1,000,000,000.0		$ 1,000,000,000.0
Long term debt		34,880,000		$ 34,880,000		279,801,000
Senior Notes [Member] | Commercial Paper [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Term				397 days
Four Point Two Five Percentage Notes Due Two Thousand Forty Six [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 500,000,000.0		$ 500,000,000.0		$ 0
Debt Instrument, Interest Rate, Stated Percentage		4.25%		4.25%		0.00%
Notes At Price		98.762%		98.762%
Borrowings under long-term notes		$ 488,700,000
Debt placement costs		5,100,000
Long term debt		488,731,000		$ 488,731,000		$ 0
Five Point Six Five Percentage Notes Due Two Thousand Sixteen [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 250,000,000.0		$ 250,000,000.0		$ 250,000,000
Debt Instrument, Interest Rate, Stated Percentage		5.65%		5.65%		5.65%
Long term debt	[1]	$ 250,020,000		$ 250,020,000		$ 250,208,000
Five Point Zero Percentage Notes Due Two Thousand Twenty Six [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 650,000,000.0	$ 650,000,000.0	$ 650,000,000.0		$ 0
Debt Instrument, Interest Rate, Stated Percentage		5.00%	5.00%	5.00%		0.00%
Notes At Price			99.875%
Borrowings under long-term notes			$ 643,800,000
Debt placement costs			$ 5,400,000
Long term debt		$ 644,129,000		$ 644,129,000		$ 0

[1] These borrowings will mature in October 2016 and are reflected in current debt on our consolidated balance sheets at December 31, 2015 and September 30, 2016.

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Derivative Financial Instruments (Narrative) (Details) bbl in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016 USD ($) bbl	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($) bbl	Sep. 30, 2015 USD ($)	Dec. 31, 2015 USD ($) bbl
Derivative [Line Items]
Energy commodity derivatives deposits, current asset	$ 30,559,000		$ 30,559,000		$ 0
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months			(3,000,000)
Debt Instrument, Face Amount	$ 4,300,000,000.0		4,300,000,000.0		$ 3,400,000,000.0
Payments for (Proceeds from) Hedge, Financing Activities			$ 19,287,000	$ 42,908,000
Fair Value Hedging [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	0.7		0.7
Fair Value Hedging [Member] | NYMEX Commodity Contracts [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	0.7		0.7		0.7
Cumulative Gains from Fair Value Hedges	$ 17,600,000		$ 17,600,000		$ 27,900,000
Gain (Loss) from Components Excluded from Assessment of Fair Value Hedge Effectiveness, Net	300,000	$ (1,700,000)	4,500,000	$ 4,600,000
Future Debt Issuance 2018 [Member] | Cash Flow Hedging [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative, Notional Amount	100,000,000		100,000,000
Derivative Liability, Fair Value, Gross Liability	3,500,000		3,500,000
Five Point Zero Percentage Notes Due Two Thousand Twenty Six [Member] | Cash Flow Hedging [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative, Notional Amount	250,000,000		250,000,000
Debt Instrument, Face Amount	$ 500,000,000		$ 500,000,000
Debt Instrument, Interest Rate, Stated Percentage	4.25%		4.25%
Payments for (Proceeds from) Hedge, Financing Activities	$ 19,300,000
Maximum Length of Time Hedged in Interest Rate Cash Flow Hedge	10 years

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Derivative Financial Instruments (Schedule Of NYMEX Contracts And Butane Price Swap Purchase Agreements) (Details) bbl in Millions	Sep. 30, 2016 bbl
Fair Value Hedging [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0.7
Economic Hedges [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	5.1
Economic Hedges Futures [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1.3

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Derivative Financial Instruments (Schedule of Derivative Offset Amounts) (Details) - Exchange Traded [Member] - USD ($) $ in Thousands		Sep. 30, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		$ 3,247	$ 48,367
Derivative Liability, Fair Value, Gross Liability		(15,576)	(5,646)
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	[1]		42,721
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	[2]	(12,329)
Derivative, Collateral, Obligation to Return Cash			(24,252)
Derivative, Collateral, Right to Reclaim Cash		30,559
Amount After Offset	[3]	18,230	18,469
Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral		(12,430)
Other Noncurrent Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral			3,478
Derivative Liability, Fair Value, Amount Not Offset Against Collateral		$ 101
Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral			$ 39,243

[1] Net amount includes energy commodity derivative contracts classified as current assets, net, of $39,243 and noncurrent assets of $3,478.

[2] Net amount includes energy commodity derivative contracts classified as current liabilities, net, of $12,430 and noncurrent assets of $101.

[3] Amount represents the maximum loss we would incur if all of our counterparties failed to perform on their derivative contracts.

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Derivative Financial Instruments (Derivative Gains Included In Accumulated Other Comprehensive Loss (AOCL) (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivative Gains Included in AOCI [Roll Forward]
Beginning balance		$ (50,459)	$ (29,528)	$ (30,126)	$ (16,587)
Net gain (loss) on cash flow hedges	[1]	(3,169)	(3,410)	(24,278)	(16,939)
Reclassification of net loss (gain) on cash flow hedges to income	[1]	512	388	1,288	976
Ending balance		$ (53,116)	$ (32,550)	$ (53,116)	$ (32,550)

[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.

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Derivative Financial Instruments (Derivatives And Hedging-Cash Flow Hedges) (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on cash flow hedges	[1]	$ (3,169)	$ (3,410)	$ (24,278)	$ (16,939)
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Interest Rate Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on cash flow hedges		(3,169)	(3,410)	(24,278)	(16,939)
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		(512)	(388)	(1,288)	(976)
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net		$ 0	$ 0	$ 0	$ 0

[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.

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Derivative Financial Instruments (Derivatives And Hedging-Overall-Subsequent Measurement) (Details) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ (7,607)	$ 82,896	$ (5,987)	$ 53,766
NYMEX Commodity Contracts [Member] | Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(12,650)	71,902	(8,438)	52,432
NYMEX Commodity Contracts [Member] | Operating Expenses [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	4,212	14,761	(1,192)	7,181
NYMEX Commodity Contracts [Member] | Cost of Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ 831	$ (3,767)	$ 3,643	$ (5,847)

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Derivative Financial Instruments (Derivatives and Hedging - Designated) (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 101	$ 5,717
Derivative Liability, Fair Value, Gross Liability	3,465	653
Designated as Hedging Instrument [Member] | NYMEX Commodity Contracts [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		60
Designated as Hedging Instrument [Member] | NYMEX Commodity Contracts [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0
Designated as Hedging Instrument [Member] | NYMEX Commodity Contracts [Member] | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	101	3,478
Designated as Hedging Instrument [Member] | NYMEX Commodity Contracts [Member] | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	0
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		2,179
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		653
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	3,465
Not Designated as Hedging Instrument [Member] | NYMEX Commodity Contracts [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,146	44,829
Not Designated as Hedging Instrument [Member] | NYMEX Commodity Contracts [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 15,576	$ 5,646

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Commitments And Contingencies (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Loss Contingencies [Line Items]
Liabilities recognized for estimated environmental costs	$ 25.8		$ 25.8		$ 31.4
Estimated environmental liabilities, years			9 years
Environmental expenses	0.3	$ 1.3	$ 4.6	$ 5.6
Receivables from insurance carriers related to environmental matters	2.0		2.0		2.6
Accounts Receivable [Member]
Loss Contingencies [Line Items]
Receivables from insurance carriers related to environmental matters	0.8		0.8		0.7
Other Noncurrent Assets [Member]
Loss Contingencies [Line Items]
Receivables from insurance carriers related to environmental matters	$ 1.2		$ 1.2		$ 1.9

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Long-Term Incentive Plan (Narrative) (Details) - shares	1 Months Ended	9 Months Ended
	Feb. 29, 2016	Sep. 30, 2016
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Limited partners' capital account, units authorized for issuance		11,900,000
Limited partner unitholders, units remaining available		3,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	218,046
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Management [Member]
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Partners' Capital Account, Units, Unit-based Compensation	350,552
Director [Member]
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Partners' Capital Account, Units, Unit-based Compensation		6,117

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Long-Term Incentive Plan (Equity-Based Incentive Compensation Expense) (Details) - Management [Member] - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Allocation of LTIP expense on consolidated statements of income	$ 4,678	$ 4,687	$ 14,737	$ 15,226
G&A Expense [Member]
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Allocation of LTIP expense on consolidated statements of income	4,637	4,643	14,623	15,016
Operating Expenses [Member]
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Allocation of LTIP expense on consolidated statements of income	41	44	114	210
Equity Method [Member]
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Allocation of LTIP expense on consolidated statements of income	4,678	5,277	14,737	14,725
Liability Method [Member]
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Allocation of LTIP expense on consolidated statements of income	0	(590)	0	501
Performance Based Awards [Member] | Two Thousand Thirteen Awards [Member]
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Allocation of LTIP expense on consolidated statements of income		1,083		6,747
Performance Based Awards [Member] | Two Thousand Thirteen Awards [Member] | Equity Method [Member]
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Allocation of LTIP expense on consolidated statements of income		1,673		6,246
Performance Based Awards [Member] | Two Thousand Thirteen Awards [Member] | Liability Method [Member]
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Allocation of LTIP expense on consolidated statements of income		(590)		501
Performance Based Awards [Member] | Two Thousand Fourteen Awards [Member]
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Allocation of LTIP expense on consolidated statements of income	1,780	1,497	6,168	3,980
Performance Based Awards [Member] | Two Thousand Fourteen Awards [Member] | Equity Method [Member]
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Allocation of LTIP expense on consolidated statements of income	1,780	1,497	6,168	3,980
Performance Based Awards [Member] | Two Thousand Fourteen Awards [Member] | Liability Method [Member]
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Allocation of LTIP expense on consolidated statements of income	0	0	0	0
Performance Based Awards [Member] | Two Thousand Fifteen Awards [Member]
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Allocation of LTIP expense on consolidated statements of income	1,208	1,727	3,679	3,687
Performance Based Awards [Member] | Two Thousand Fifteen Awards [Member] | Equity Method [Member]
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Allocation of LTIP expense on consolidated statements of income	1,208	1,727	3,679	3,687
Performance Based Awards [Member] | Two Thousand Fifteen Awards [Member] | Liability Method [Member]
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Allocation of LTIP expense on consolidated statements of income	0	0	0	0
Performance Based Awards [Member] | Two Thousand Sixteen Awards [Member]
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Allocation of LTIP expense on consolidated statements of income	1,097		3,240
Performance Based Awards [Member] | Two Thousand Sixteen Awards [Member] | Equity Method [Member]
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Allocation of LTIP expense on consolidated statements of income	1,097		3,240
Performance Based Awards [Member] | Two Thousand Sixteen Awards [Member] | Liability Method [Member]
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Allocation of LTIP expense on consolidated statements of income	0		0
Time-Based Awards [Member]
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Allocation of LTIP expense on consolidated statements of income	593	380	1,650	812
Time-Based Awards [Member] | Equity Method [Member]
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Allocation of LTIP expense on consolidated statements of income	593	380	1,650	812
Time-Based Awards [Member] | Liability Method [Member]
Share-based Compensation Arrangements by Share-based Payment Award [Line Items]
Allocation of LTIP expense on consolidated statements of income	$ 0	$ 0	$ 0	$ 0

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Distributions (Schedule Of Distributions) (Details) - USD ($) $ / shares in Units, $ in Thousands									9 Months Ended		12 Months Ended
	Nov. 14, 2016	Aug. 12, 2016	May 13, 2016	Feb. 12, 2016	Nov. 13, 2015	Aug. 14, 2015	May 15, 2015	Feb. 13, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2016	Dec. 31, 2015
Per Unit Cash Distribution Amount		$ 0.8200	$ 0.8025	$ 0.785	$ 0.7625	$ 0.7400	$ 0.7175	$ 0.6950	$ 2.4075	$ 2.1525		$ 2.915
Total Cash Distribution to Limited Partners		$ 186,783	$ 182,797	$ 178,808	$ 173,413	$ 168,296	$ 163,178	$ 158,061	$ 548,388	$ 489,535		$ 662,948
Scenario, Forecast
Per Unit Cash Distribution Amount	$ 0.8375										$ 3.245
Total Cash Distribution to Limited Partners	$ 190,769										$ 739,157

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Fair Value (Schedule Of Carrying Amounts And Fair Values Of Financial Assets/Liabilities) (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | NYMEX Commodity Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset		$ 42,721
Derivative Liability	$ (12,329)
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt	(4,678,925)	(3,284,791)
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Interest Rate Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset		1,526
Derivative Liability	(3,465)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term receivables	22,101	20,374
Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term receivables	22,101	20,374
Debt	(4,678,925)	(3,284,791)
Estimate of Fair Value Measurement [Member] | NYMEX Commodity Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset		42,721
Derivative Liability	(12,329)
Estimate of Fair Value Measurement [Member] | Interest Rate Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset		1,526
Derivative Liability	(3,465)
Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term receivables	22,101	20,374
Debt	(4,323,522)	(3,439,622)
Reported Value Measurement [Member] | NYMEX Commodity Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset		42,721
Derivative Liability	(12,329)
Reported Value Measurement [Member] | Interest Rate Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset		$ 1,526
Derivative Liability	$ (3,465)

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Related Party Transactions (Details) - Director [Member] - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Targa Resource Partners L P [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party		$ 1.5	$ 4.7	$ 14.3
Accounts Payable, Related Parties					$ 2.0
Methvin Company [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Other Revenues from Transactions with Related Party	$ 4.3	$ 4.1	12.0	$ 6.7
Accounts Receivable, Related Parties, Current	$ 1.5		$ 1.5		$ 1.3

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Subsequent Events (Details) - USD ($) $ / shares in Units, $ in Thousands									9 Months Ended		12 Months Ended
	Nov. 14, 2016	Aug. 12, 2016	May 13, 2016	Feb. 12, 2016	Nov. 13, 2015	Aug. 14, 2015	May 15, 2015	Feb. 13, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2016	Dec. 31, 2015
Subsequent Event [Line Items]
Cash distribution per unit		$ 0.8200	$ 0.8025	$ 0.785	$ 0.7625	$ 0.7400	$ 0.7175	$ 0.6950	$ 2.4075	$ 2.1525		$ 2.915
Total cash distributions		$ 186,783	$ 182,797	$ 178,808	$ 173,413	$ 168,296	$ 163,178	$ 158,061	$ 548,388	$ 489,535		$ 662,948
Scenario, Forecast
Subsequent Event [Line Items]
Cash distribution per unit	$ 0.8375										$ 3.245
Total cash distributions	$ 190,769										$ 739,157