MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited, in thousands)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2020		2019		2020
Net income	$	273,038	$	211,638	$	734,404	$	633,045
Other comprehensive income (loss):
Derivative activity:
Net loss on cash flow hedges	(14,181)		0		(25,216)		(10,444)
Reclassification of net loss on cash flow hedges to income	699		896		1,927		2,552
Changes in employee benefit plan assets and benefit obligations recognized in other comprehensive income:
Net actuarial loss	0		0		(10,913)		(333)
Curtailment gain	0		0		0		1,703

Recognition of prior service credit amortization in income	(46)		(46)		(136)		(136)
Recognition of actuarial loss amortization in income	1,412		1,473		4,385		4,462
Recognition of settlement cost in income	439		0		2,499		969
Total other comprehensive income (loss)	(11,677)		2,323		(27,454)		(1,227)
Comprehensive income	$	261,361	$	213,961	$	706,950	$	631,818

Three Months Ended September 30, Nine Months Ended September 30,
2016 2017 2016 2017
Net income $ 194,551
$ 198,500
$ 589,480
$ 631,636
Other comprehensive income:

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

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

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

See notes to consolidated financial statements.

~~Table of Contents~~

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands)


	December 31, 2016			September 30, 2017				December 31, 2019		September 30, 2020
ASSETS				(Unaudited)			ASSETS			(Unaudited)
Current assets:							Current assets:
Cash and cash equivalents	$	14,701		$	1,381		Cash and cash equivalents	$	58,030	$	8,541

Trade accounts receivable	105,689			128,765			Trade accounts receivable	125,440		109,051
Other accounts receivable	25,761			13,349			Other accounts receivable	23,887		27,735
Inventory	134,378			168,762			Inventory	184,399		129,033
Energy commodity derivatives contracts, net	—			1,189
Energy commodity derivatives deposits	49,899			31,735

Commodity derivatives deposits							Commodity derivatives deposits	27,415		14,031
Reimbursable costs							Reimbursable costs	7,878		17,065
Other current assets	39,966			62,247			Other current assets	32,359		35,787
Total current assets	370,394			407,428			Total current assets	459,408		341,243
Property, plant and equipment	6,783,737			7,121,856			Property, plant and equipment	8,431,227		8,319,400
Less: Accumulated depreciation	1,507,996			1,638,351
Less: accumulated depreciation							Less: accumulated depreciation	2,027,193		2,036,351
Net property, plant and equipment	5,275,741			5,483,505			Net property, plant and equipment	6,404,034		6,283,049
Investments in non-controlled entities	931,255			1,066,940			Investments in non-controlled entities	1,240,551		1,211,079
Right-of-use asset, operating leases							Right-of-use asset, operating leases	171,868		152,082
Long-term receivables	23,870			27,166			Long-term receivables	20,782		21,850
Goodwill	53,260			53,260			Goodwill	53,260		52,830
Other intangibles (less accumulated amortization of $2,136 and $1,308 at December 31, 2016 and September 30, 2017, respectively)	51,976			52,845
Other intangibles (less accumulated amortization of $6,255 and $8,575 at December 31, 2019 and September 30, 2020, respectively)							Other intangibles (less accumulated amortization of $6,255 and $8,575 at December 31, 2019 and September 30, 2020, respectively)	47,898		45,578
Restricted cash							Restricted cash	26,569		11,792
Other noncurrent assets	65,577			12,303			Other noncurrent assets	13,359		20,693
Total assets	$	6,772,073		$	7,103,447		Total assets	$	8,437,729	$	8,140,196

LIABILITIES AND PARTNERS’ CAPITAL							LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:							Current liabilities:
Accounts payable	$	77,248		$	120,990		Accounts payable	$	150,992	$	124,612
Accrued payroll and benefits	45,690			40,082			Accrued payroll and benefits	75,511		40,285
Accrued interest payable	65,643			42,257			Accrued interest payable	64,276		49,501
Accrued taxes other than income	50,166			49,844			Accrued taxes other than income	66,007		65,283
Environmental liabilities	10,249			9,870

Deferred revenue	101,891			116,697			Deferred revenue	109,654		92,227
Accrued product liabilities	51,600			119,572			Accrued product liabilities	90,788		79,388
Energy commodity derivatives contracts, net	30,738			14,898
Current portion of long-term debt, net	—			251,439
Commodity derivatives contracts, net							Commodity derivatives contracts, net	10,222		2,888

Current portion of operating lease liability							Current portion of operating lease liability	26,221		27,177

Other current liabilities	48,431			44,065			Other current liabilities	73,205		50,258
Total current liabilities	481,656			809,714			Total current liabilities	666,876		531,619
Long-term operating lease liability							Long-term operating lease liability	144,023		121,764
Long-term debt, net	4,087,192			4,051,411			Long-term debt, net	4,706,075		4,900,311
Long-term pension and benefits	71,461			66,410			Long-term pension and benefits	145,992		142,154
Other noncurrent liabilities	25,868			29,799			Other noncurrent liabilities	59,735		55,904
Environmental liabilities	13,791			10,818

Commitments and contingencies							Commitments and contingencies

Partners’ capital:							Partners’ capital:
Limited partner unitholders (227,784 units and 228,025 units outstanding at December 31, 2016 and September 30, 2017, respectively)	2,193,346			2,229,394
Common unitholders (228,403 units and 223,701 units outstanding at December 31, 2019 and September 30, 2020, respectively)							Common unitholders (228,403 units and 223,701 units outstanding at December 31, 2019 and September 30, 2020, respectively)	2,877,105		2,551,748
Accumulated other comprehensive loss	(101,241		)	(94,099		)	Accumulated other comprehensive loss	(162,077)		(163,304)
Total partners’ capital	2,092,105			2,135,295			Total partners’ capital	2,715,028		2,388,444

Total liabilities and partners’ capital	$	6,772,073		$	7,103,447		Total liabilities and partners’ capital	$	8,437,729	$	8,140,196

See notes to consolidated financial statements.

~~Table of Contents~~

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)


	Nine Months Ended
	September 30,
	2019		2020
Operating Activities:
Net income	$	734,404	$	633,045
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and impairment expense	181,028		193,896
Gain on sale and retirement of assets	(29,227)		(13,330)
Earnings of non-controlled entities	(122,229)		(116,484)
Distributions from operations of non-controlled entities	138,140		152,645
Equity-based incentive compensation expense	22,577		5,580
Settlement gain, amortization of prior service credit and actuarial loss	6,748		3,953


Debt prepayment costs	8,270		12,893
Changes in operating assets and liabilities:

Trade accounts receivable and other accounts receivable	(24,954)		8,253
Inventory	(20,217)		54,127


Accounts payable	29,014		9,040
Accrued payroll and benefits	(13,599)		(35,226)
Accrued interest payable	(15,060)		(14,775)
Accrued taxes other than income	10,282		1,101
Accrued product liabilities	33,402		(11,400)
Deferred revenue	(13,233)		(17,427)


Other current and noncurrent assets and liabilities	(2,749)		(25,786)
Net cash provided by operating activities	922,597		840,105
Investing Activities:
Additions to property, plant and equipment, net(1)	(718,605)		(371,170)

Proceeds from sale and disposition of assets	65,574		334,583



Investments in non-controlled entities	(158,145)		(73,678)
Distributions from returns of investments in non-controlled entities	7,500		0
Deposits received from undivided joint interest third party	68,928		0

Net cash used by investing activities	(734,748)		(110,265)
Financing Activities:
Distributions paid	(688,635)		(697,264)
Net commercial paper borrowings	0		248,000

Borrowings under long-term notes	996,405		499,400
Payments on long-term notes	(550,000)		(550,000)
Debt placement costs	(12,012)		(4,255)
Net payment on financial derivatives	(33,342)		(10,444)

Payments associated with settlement of equity-based incentive compensation	(9,764)		(14,700)
Debt prepayment costs	(8,270)		(12,893)
Repurchases of common units	0		(251,950)

Net cash used by financing activities	(305,618)		(794,106)
Change in cash, cash equivalents and restricted cash	(117,769)		(64,266)
Cash, cash equivalents and restricted cash at beginning of period	309,261		84,599
Cash, cash equivalents and restricted cash at end of period	$	191,492	$	20,333

Supplemental non-cash investing activities:



(1) Additions to property, plant and equipment	$	(775,109)	$	(317,680)
Changes in accounts payable and other current liabilities related to capital expenditures	56,504		(53,490)
Additions to property, plant and equipment, net	$	(718,605)	$	(371,170)

Nine Months Ended
September 30,
2016 2017
Operating Activities:
Net income $ 589,480
$ 631,636
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense 134,137
146,103
Loss (gain) on sale and retirement of assets 5,397
(10,924 )
Earnings of non-controlled entities (51,543 ) (78,173 )
Distributions of earnings from investments in non-controlled entities 50,047
78,562
Equity-based incentive compensation expense 14,737
14,183
Settlement cost, amortization of prior service credit and actuarial loss 1,427
6,658
Gain on exchange of interest in non-controlled entity (28,144 ) —
Changes in operating assets and liabilities:
Trade accounts receivable and other accounts receivable (49,014 ) (14,413 )
Inventory 7,857
(34,384 )
Energy commodity derivatives contracts, net of derivatives deposits 637
1,135
Accounts payable 5,850
15,576
Accrued payroll and benefits (12,725 ) (5,608 )
Accrued interest payable (2,393 ) (23,386 )
Accrued taxes other than income 2,115
(322 )
Accrued product liabilities (6,183 ) 67,972
Deferred revenue 17,191
14,806
Current and noncurrent environmental liabilities (5,649 ) (3,352 )
Other current and noncurrent assets and liabilities (34,229 ) (11,497 )
Net cash provided by operating activities 638,995
794,572
Investing Activities:
Additions to property, plant and equipment, net⁽¹⁾
(517,810 ) (418,239 )
Proceeds from sale and disposition of assets 6,098
44,303
Investments in non-controlled entities (174,900 ) (114,078 )
Distributions in excess of earnings of non-controlled entities 4,500
71,867
Net cash used by investing activities (682,112 ) (416,147 )
Financing Activities:
Distributions paid (548,388 ) (596,854 )
Net commercial paper borrowings (repayments) (244,963 ) 218,984
Borrowings under long-term notes 1,142,997
—
Debt placement costs (10,500 ) —
Net payment on financial derivatives (19,287 ) —
Payments associated with settlement of equity-based incentive compensation (14,376 ) (13,875 )
Net cash provided (used) by financing activities 305,483
(391,745 )
Change in cash and cash equivalents 262,366
(13,320 )
Cash and cash equivalents at beginning of period 28,731
14,701
Cash and cash equivalents at end of period $ 291,097
$ 1,381

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

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

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(Unaudited, in thousands)


	Common Unitholders		Accumulated Other Comprehensive Loss			Total Partners’ Capital
Balance, July 1, 2019	$	2,774,047		$	(136,268)	$	2,637,779
Comprehensive income:
Net income	273,038			—		273,038
Total other comprehensive loss	—			(11,677)		(11,677)
Total comprehensive income (loss)	273,038			(11,677)		261,361
Distributions	(231,258)			—		(231,258)
Equity-based incentive compensation expense	6,773			—		6,773



Other	(199)			—		(199)
Three Months Ended September 30, 2019	$	2,822,401		$	(147,945)	$	2,674,456

Balance, July 1, 2020	$	2,620,365		$	(165,627)	$	2,454,738
Comprehensive income:
Net income	211,638			—		211,638
Total other comprehensive income	—			2,323		2,323
Total comprehensive income	211,638			2,323		213,961
Distributions	(231,245)			—		(231,245)
Equity-based incentive compensation expense	1,169			—		1,169
Repurchases of common units	(49,968)			—		(49,968)


Other	(211)			—		(211)
Three Months Ended September 30, 2020	$	2,551,748		$	(163,304)	$	2,388,444


MAGELLAN MIDSTREAM PARTNERS, L.P. CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL (Continued) (Unaudited, in thousands)

	Common Unitholders		Accumulated Other Comprehensive Loss			Total Partners’ Capital
Balance, January 1, 2019	$	2,763,925		$	(120,491)	$	2,643,434
Comprehensive income:
Net income	734,404			—		734,404
Total other comprehensive loss	—			(27,454)		(27,454)
Total comprehensive income (loss)	734,404			(27,454)		706,950
Distributions	(688,635)			—		(688,635)
Equity-based incentive compensation expense	22,577			—		22,577
Issuance of limited partner units in settlement of equity-based incentive plan awards	480			—		480
Payments associated with settlement of equity-based incentive compensation	(9,764)			—		(9,764)

Other	(586)			—		(586)
Nine Months Ended September 30, 2019	$	2,822,401		$	(147,945)	$	2,674,456

Balance, January 1, 2020	$	2,877,105		$	(162,077)	$	2,715,028
Comprehensive income:
Net income	633,045			—		633,045
Total other comprehensive loss	—			(1,227)		(1,227)
Total comprehensive income (loss)	633,045			(1,227)		631,818
Distributions	(697,264)			—		(697,264)
Equity-based incentive compensation expense	5,580			—		5,580
Repurchases of common units	(251,950)			—		(251,950)
Issuance of limited partner units in settlement of equity-based incentive plan awards	600			—		600
Payments associated with settlement of equity-based incentive compensation	(14,700)			—		(14,700)
Other	(668)			—		(668)
Nine Months Ended September 30, 2020	$	2,551,748		$	(163,304)	$	2,388,444

See notes to consolidated financial statements.

~~Table of Contents~~

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.Organization, Description of Business and Basis of Presentation


1.	~~Organization, Description of Business and Basis of Presentation~~

Organization

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

During first quarter 2020, we completed a reorganization of our reportable segments. This reorganization was effected to reflect changes in the management of our business in conjunction with the sale of 3 of our marine terminals. Following this sale, 2 of our remaining marine terminals were combined with our refined products segment and 1 terminal was combined with our crude oil segment based on the predominant types of product stored at the facilities. Accordingly, we have restated our segment disclosures for all previous periods included in this report.

Description of Business

On March 20, 2020, we sold 3 marine terminals to a subsidiary of Buckeye Partners, L.P. (“Buckeye”) for $251.8 million, net of working capital adjustments. These terminals are located in New Haven, Connecticut, Wilmington, Delaware and Marrero, Louisiana. We recognized a $6.2 million impairment loss related to the sale on our consolidated statements of income.

We are principally engaged in the transportation, storage and distribution of refined petroleum products and crude oil. As of September 30, ~~2017,~~2020, our asset portfolio ~~including the assets of our joint ventures,~~ consisted of:

•our refined products segment, comprised of our ~~9,700-mile~~approximately 9,800-mile refined products pipeline system with 5354 connected terminals, as well as 2625 independent terminals not connected to our pipeline system and ~~our~~ ~~1,100-mile ammonia pipeline system;~~

2 marine storage terminals (1 of which is owned through a joint venture); and

•our crude oil segment, comprised of approximately 2,200 miles of crude oil pipelines, ~~our~~a condensate splitter and ~~storage facilities with an~~37 million barrels of aggregate storage capacity, of ~~approximately 27 million barrels, of~~ which approximately 1625 million barrels are used for contract ~~storage;~~storage. Approximately 1,000 miles of these pipelines, the condensate splitter and

~~our marine storage segment, consisting~~ 30 million barrels of ~~five marine terminals located along coastal waterways with an aggregate~~this storage capacity ~~of approximately 26~~(including 22 million ~~barrels.~~barrels used for contract storage) are wholly-owned, with the remainder owned through joint ventures.

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 crude oil refineries ~~and~~that are primarily used as fuels by consumers. Refined products include gasoline, diesel fuel, aviation fuel, kerosene and heating oil. ~~Collectively, diesel~~Diesel fuel, kerosene and heating oil are referred to as distillates;

•transmix is a mixture of refined products that forms when transported in pipelines. Transmix is fractionated and blended into usable refined products;

•liquefied petroleum gases, or LPGs, are liquids produced as by-products of the crude oil refining process and in connection with natural gas production. LPGs include butane and propane;

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

•blendstocks are products 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 products 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~~, which includes condensate, ~~are~~is a naturally occurring unrefined petroleum product recovered from underground that is used as ~~feedstocks~~feedstock by refineries, splitters and petrochemical facilities;

and

•biofuels, such as ethanol and biodiesel, are ~~increasingly~~fuels derived from living materials and typically blended with other refined products as required by government ~~mandates; and~~

mandates.

~~ammonia~~ ~~is primarily used as a nitrogen fertilizer.~~

~~Except for ammonia, we~~We use the term petroleum products to describe any, or a combination, of the above-noted products.

~~Table of Contents~~

~~MAGELLAN MIDSTREAM PARTNERS, L.P.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

Basis of Presentation

In the opinion of management, our accompanying consolidated financial statements which are unaudited, except for the consolidated balance sheet as of December 31, ~~2016,~~2019, which is derived from our audited financial statements, include all normal and recurring adjustments necessary to present fairly our financial position as of September 30, ~~2017,~~2020, the results of operations for the three and nine months ended September 30, ~~2016~~2019 and ~~2017~~2020 and cash flows for the nine months ended September 30, ~~2016~~2019 and ~~2017.~~2020. The results of operations for the nine months ended September 30, ~~2017~~2020 are not necessarily indicative of the results to be expected for the full year ending December 31, ~~2017~~2020 for several reasons. Profits from our ~~butane~~gas liquids 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 refined products pipeline ~~systems,~~system, 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. Finally, we expect the impact of COVID-19 on demand for petroleum products and the decline in commodity prices to continue to affect our results of operations in the remaining quarter of 2020, resulting in decreased transportation and terminalling revenues and reduced profits from our gas liquids blending activities.

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 Form 8-K filed with the Securities and Exchange Commission on May 4, 2020, which reflects changes in our reporting segments since the filing of our Annual Report on Form 10-K for the year ended December 31, ~~2016~~.2019.

~~In September 2017, we recognized an $18.5 million gain in connection~~Reclassifications

Prior period amounts related to intrastate crude oil volumes shipped by our marketing affiliate have been reclassified from product sales revenue to transportation revenue to conform with the ~~sale of an inactive terminal in Chicago, Illinois, which is not included in operating profit because the gain is not related to our ongoing operations.~~current period’s presentation.

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

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

on the reported amounts of revenue and expense during the reporting periods. Actual results could differ from those estimates.

New Accounting Pronouncements

In ~~March 2017,~~June 2016, the Financial Accounting Standards Board ~~(“FASB”)~~ issued Accounting Standards Update (“ASU”) ~~2017-07,~~ ~~Compensation-Retirement Benefits~~2016-13, Financial Instruments - Credit Losses (Topic ~~715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost~~326). ~~This ASU requires companies that offer postretirement benefits to present the service cost, which~~The new guidance is the amount an employer has to set aside each period to cover the benefits, in the same line item with other employee compensation costs. Other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. Additionally, only the service cost component will be eligibleeffective for ~~capitalization when applicable.~~

~~Public companies must comply with the new requirements under ASU 2017-07 for fiscal years that start~~reporting periods beginning after December 15, ~~2017,~~2019. The standard replaces the incurred loss impairment methodology under current GAAP with a methodology that reflects expected credit losses and requires the ~~amendments must be applied retrospectively except~~use of a forward-looking expected credit loss model for accounts receivables, loans and other financial instruments. The standard requires a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the ~~capitalization change,~~beginning of the first reporting period in which ~~should be applied prospectively. Early adoption~~the guidance is ~~allowed, and we elected to adopt ASU 2017-07~~effective. We adopted the new guidance as of January 1, ~~2017. Prior to adoption, we expensed all components of pension expense through salaries and wages, which impacted operating income. We are now recording only~~2020 using the ~~service component of pension expense to salaries and wages, with the remainder of the expense being recorded to other income and expense below operating profit.~~

~~Table of Contents~~

~~MAGELLAN MIDSTREAM PARTNERS, L.P.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

~~Comparative prior periods have been restated for this change. The changes were not material~~modified retrospective approach related to our ~~financial statements.~~

~~In February 2016, the FASB issued ASU 2016-02,~~ ~~Leases (Topic 842).~~ ~~This ASU requires lessees~~accounts receivables and contract assets, resulting in no cumulative adjustment to ~~recognize a right~~retained earnings. The adoption of use asset and lease liability on the balance sheet for all leases, with the exception of short-term leases. The new accounting model for lessors remains largely the same, although some changes have been made to align it with the new lessee model and the new revenue recognition guidance. This update also requires companies to include additional disclosures regarding their lessee and lessor agreements. Public companies are required to adopt the standard for financial reporting periods that start after December 15, 2018, although early adoption is permitted. We are currently in the process of evaluating the impact this ~~new standard will have on our financial statements.~~

~~In July 2015, the FASB issued ASU 2015-11,~~ ~~Inventory (Topic 330): Simplifying the Measurement of Inventory~~. Prior to this update, reporting entities were required to measure inventory at the lower of cost or market. Market could be replacement cost, net realizable value or net realizable value less an approximately normal profit margin. Under this update, inventory is to be measured at the lower of cost or net realizable value, which is defined as the estimated selling price in the ordinary course of business, less reasonable predictable costs of completion, disposal and transportation. This ASU became effective for fiscal years beginning after December 15, 2016 and interim periods within those fiscal years. We adopted this standard on January 1, 2017, and itguidance did not have a material impact on our ~~results of operations, financial position or cash flows as we have historically measured our inventory at the lower of cost or net realizable value, as described above.~~

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


2.	~~Product Sales Revenue~~

~~The amounts reported as product sales revenue on our~~ consolidated statements of income ~~include revenue from the physical sale of petroleum products and mark-to-market adjustments from exchange-based futures contracts. See Note 8 –~~ ~~Derivative Financial Instruments~~for ~~a discussion of our commodity hedging strategies and how our futures contracts impact product sales revenue.~~

~~For~~ the three and nine ~~months~~month periods ended September 30, ~~2016 and 2017, product sales revenue included the following (in thousands):~~2020.

2.Segment Disclosures

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

~~Table of Contents~~

~~MAGELLAN MIDSTREAM PARTNERS, L.P.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~


3.	~~Segment Disclosures~~

Our reportable segments are strategic business units that offer different products and services. Our segments are managed separately as each segment requires different marketing strategies and business knowledge. Management evaluates performance based on segment operating margin, which includes revenue from affiliates and ~~external~~third-party customers, operating expenses, cost of product sales, other operating (income) expense 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.~~below (presented in thousands). Operating profit includes depreciation, amortization and ~~amortization~~impairment expense and general and administrative (“G&A”) expense that management does not consider when evaluating the core profitability of our separate operating segments.

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

~~Table of Contents~~

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


	Three Months Ended September 30, 2019
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation and terminals revenue	$	352,611	$	155,377	$	(1,556)	$	506,432
Product sales revenue	136,464		8,343		0		144,807
Affiliate management fee revenue	1,764		3,593		0		5,357
Total revenue	490,839		167,313		(1,556)		656,596
Operating expenses	127,328		44,961		(2,902)		169,387
Cost of product sales	100,416		8,341		0		108,757
Other operating (income) expense	(3,249)		3,628		0		379
Earnings of non-controlled entities	(4,142)		(46,047)		0		(50,189)
Operating margin	270,486		156,430		1,346		428,262
Depreciation, amortization and impairment expense	39,660		15,621		1,346		56,627
G&A expense	36,806		14,350		0		51,156
Operating profit	$	194,020	$	126,459	$	0	$	320,479


	Three Months Ended September 30, 2020
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation and terminals revenue	$	320,809	$	154,652	$	(1,930)	$	473,531
Product sales revenue	114,252		5,193		0		119,445
Affiliate management fee revenue	1,579		3,709		0		5,288
Total revenue	436,640		163,554		(1,930)		598,264
Operating expenses	118,579		46,956		(3,553)		161,982
Cost of product sales	86,356		9,763		0		96,119
Other operating (income) expense	(193)		3,056		0		2,863
Earnings of non-controlled entities	(7,134)		(32,001)		0		(39,135)
Operating margin	239,032		135,780		1,623		376,435
Depreciation, amortization and impairment expense	41,620		28,579		1,623		71,822
G&A expense	27,487		10,529		0		38,016
Operating profit	$	169,925	$	96,672	$	0	$	266,597

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

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

~~Table of Contents~~

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


	Nine Months Ended September 30, 2019
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation and terminals revenue	$	1,009,812	$	467,652	$	(3,835)	$	1,473,629
Product sales revenue	478,441		19,350		0		497,791
Affiliate management fee revenue	5,085		10,725		0		15,810
Total revenue	1,493,338		497,727		(3,835)		1,987,230
Operating expenses	362,870		129,431		(7,960)		484,341
Cost of product sales	411,012		19,715		0		430,727
Other operating (income) expense	(9,648)		8,110		0		(1,538)
Earnings of non-controlled entities	(145)		(122,084)		0		(122,229)
Operating margin	729,249		462,555		4,125		1,195,929
Depreciation, amortization and impairment expense	128,724		48,179		4,125		181,028
G&A expense	107,179		42,355		0		149,534
Operating profit	$	493,346	$	372,021	$	0	$	865,367


	Nine Months Ended September 30, 2020
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation and terminals revenue	$	914,887	$	433,947	$	(5,093)	$	1,343,741
Product sales revenue	461,701		20,141		0		481,842
Affiliate management fee revenue	4,676		11,219		0		15,895
Total revenue	1,381,264		465,307		(5,093)		1,841,478
Operating expenses	327,866		139,645		(9,914)		457,597
Cost of product sales	365,314		30,550		0		395,864
Other operating (income) expense	(2,223)		1,684		0		(539)
Earnings of non-controlled entities	(25,946)		(90,538)		0		(116,484)
Operating margin	716,253		383,966		4,821		1,105,040
Depreciation, amortization and impairment expense	128,708		60,367		4,821		193,896
G&A expense	84,802		32,290		0		117,092
Operating profit	$	502,743	$	291,309	$	0	$	794,052

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

~~Table of Contents~~

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3.Revenue from Contracts with Customers


4.	~~Investments in Non-Controlled Entities~~

Statement of Income Disclosures

The following tables provide details of our revenues disaggregated by key activities that comprise our performance obligations by operating segment (in thousands):


	Three Months Ended September 30, 2019
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation	$	208,073	$	95,530	$	0	$	303,603
Terminalling	48,428		3,176		0		51,604
Storage	53,433		30,037		(1,556)		81,914
Ancillary services	36,375		7,278		0		43,653
Lease revenue	6,302		19,356		0		25,658
Transportation and terminals revenue	352,611		155,377		(1,556)		506,432
Product sales revenue	136,464		8,343		0		144,807
Affiliate management fee revenue	1,764		3,593		0		5,357
Total revenue	490,839		167,313		(1,556)		656,596
Revenue not under the guidance of ASC 606, Revenue from Contracts with Customers:
Lease revenue(1)	(6,302)		(19,356)		0		(25,658)
(Gains) losses from futures contracts included in product sales revenue(2)	(17,061)		(564)		0		(17,625)
Affiliate management fee revenue	(1,764)		(3,593)		0		(5,357)
Total revenue from contracts with customers under ASC 606	$	465,712	$	143,800	$	(1,556)	$	607,956

(1) Lease revenue is accounted for under Accounting Standards Codification (“ASC”) 842, Leases.

(2) The impact on product sales revenue from futures contracts falls under the guidance of ASC 815, Derivatives and Hedging.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


	Three Months Ended September 30, 2020
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation	$	192,194	$	90,156	$	0	$	282,350
Terminalling	41,227		5,651		0		46,878
Storage	49,366		32,876		(1,930)		80,312
Ancillary services	32,707		6,828		0		39,535
Lease revenue	5,315		19,141		0		24,456
Transportation and terminals revenue	320,809		154,652		(1,930)		473,531
Product sales revenue	114,252		5,193		0		119,445
Affiliate management fee revenue	1,579		3,709		0		5,288
Total revenue	436,640		163,554		(1,930)		598,264
Revenue not under the guidance of ASC 606, Revenue from Contracts with Customers:
Lease revenue(1)	(5,315)		(19,141)		0		(24,456)
(Gains) losses from futures contracts included in product sales revenue(2)	6,850		884		0		7,734
Affiliate management fee revenue	(1,579)		(3,709)		0		(5,288)
Total revenue from contracts with customers under ASC 606	$	436,596	$	141,588	$	(1,930)	$	576,254

(1) Lease revenue is accounted for under ASC 842, Leases.

(2) The impact on product sales revenue from futures contracts falls under the guidance of ASC 815, Derivatives and Hedging.


	Nine Months Ended September 30, 2019
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation	$	584,662	$	290,754	$	0	$	875,416
Terminalling	138,968		13,146		0		152,114
Storage	162,139		89,313		(3,835)		247,617
Ancillary services	103,287		20,488		0		123,775
Lease revenue	20,756		53,951		0		74,707
Transportation and terminals revenue	1,009,812		467,652		(3,835)		1,473,629
Product sales revenue	478,441		19,350		0		497,791
Affiliate management fee revenue	5,085		10,725		0		15,810
Total revenue	1,493,338		497,727		(3,835)		1,987,230
Revenue not under the guidance of ASC 606, Revenue from Contracts with Customers:
Lease revenue(1)	(20,756)		(53,951)		0		(74,707)
(Gains) losses from futures contracts included in product sales revenue(2)	39,761		1,743		0		41,504
Affiliate management fee revenue	(5,085)		(10,725)		0		(15,810)
Total revenue from contracts with customers under ASC 606	$	1,507,258	$	434,794	$	(3,835)	$	1,938,217

(1) Lease revenue is accounted for under ASC 842, Leases.

(2) The impact on product sales revenue from futures contracts falls under the guidance of ASC 815, Derivatives and Hedging.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


	Nine Months Ended September 30, 2020
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation	$	533,451	$	244,154	$	0	$	777,605
Terminalling	117,916		14,702		0		132,618
Storage	152,933		97,103		(5,093)		244,943
Ancillary services	93,340		20,746		0		114,086
Lease revenue	17,247		57,242		0		74,489
Transportation and terminals revenue	914,887		433,947		(5,093)		1,343,741
Product sales revenue	461,701		20,141		0		481,842
Affiliate management fee revenue	4,676		11,219		0		15,895
Total revenue	1,381,264		465,307		(5,093)		1,841,478
Revenue not under the guidance of ASC 606, Revenue from Contracts with Customers:
Lease revenue(1)	(17,247)		(57,242)		0		(74,489)
(Gains) losses from futures contracts included in product sales revenue(2)	(89,763)		483		0		(89,280)
Affiliate management fee revenue	(4,676)		(11,219)		0		(15,895)
Total revenue from contracts with customers under ASC 606	$	1,269,578	$	397,329	$	(5,093)	$	1,661,814

(1) Lease revenue is accounted for under ASC 842, Leases.

(2) The impact on product sales revenue from futures contracts falls under the guidance of ASC 815, Derivatives and Hedging.

Balance Sheet Disclosures

The following table summarizes our accounts receivable, contract assets and contract liabilities resulting from contracts with customers (in thousands):


	December 31, 2019		September 30, 2020
Accounts receivable from contracts with customers	$	124,701	$	107,317
Contract assets	$	8,071	$	13,834
Contract liabilities	$	111,670	$	94,865

For the three and nine months ended September 30, 2020, respectively, we recognized $9.3 million and $89.3 million of transportation and terminals revenue that was recorded in deferred revenue as of December 31, 2019.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Unfulfilled Performance Obligations

The following table provides the aggregate amount of the transaction price allocated to our unfulfilled performance obligations (“UPOs”) as of September 30, 2020 by operating segment, including the range of years remaining on our contracts with customers and an estimate of revenues expected to be recognized over the next 12 months (dollars in thousands):


	Refined Products		Crude Oil		Total
Balances at September 30, 2020	$	2,137,259	$	1,276,836	$	3,414,095
Remaining terms	1 - 18 years		1 - 11 years
Estimated revenues from UPOs to be recognized in the next 12 months	$	407,914	$	269,156	$	677,070

4.Investments in Non-Controlled Entities

Our investments in non-controlled entities at September 30, ~~2017~~2020 were comprised of:



Entity						Ownership Interest
BridgeTex Pipeline Company, LLC (“BridgeTex”)						~~50%~~30%
Double Eagle Pipeline LLC (“Double Eagle”)						50%
HoustonLink Pipeline Company, LLC (“HoustonLink”)						50%
MVP Terminalling, LLC (“MVP”)						50%
Powder Springs Logistics, LLC (“Powder Springs”)						50%
Saddlehorn Pipeline Company, LLC (“Saddlehorn”)						~~40%~~30%
Seabrook Logistics, LLC (“Seabrook”)						50%
Texas Frontera, LLC (“Texas Frontera”)						50%

~~Recently-Formed Company~~

~~MVP was formed in September 2017 to construct and develop~~In the first quarter of 2020, we sold a ~~refined products marine storage facility along the Houston Ship Channel in Pasadena, Texas. We own a 50% equity~~10% interest in ~~MVP, with~~Saddlehorn to an affiliate of ~~Valero Energy Corporation (“Valero”) owning the other 50%~~Black Diamond Gathering LLC, which is majority-owned by Noble Midstream Partners LP, reducing our ongoing investment in Saddlehorn to a 30% interest. We ~~serve as construction manager~~received $79.9 million in cash from the sale, and ~~operator~~we recorded a gain of ~~the MVP facility. The initial phase of this facility is expected to be operational in early 2019. Upon formation of MVP, we contributed $93.1~~$12.9 million of property, plant and equipment (“PP&E”) to this entity. Concurrently, Valero contributed cash of $46.5 million, which was distributed to us as reimbursement for its portion of the PP&E we contributed. The $46.5 million is reflected as distributions in excess of earnings of non-controlled entities on our consolidated ~~statement~~statements of ~~cash flows.~~income for the nine month period ended September 30, 2020.

We serve as operator of BridgeTex, HoustonLink, MVP, Powder Springs, Saddlehorn, Texas Frontera and the pipeline activities of Seabrook. We receive fees for management services as well as reimbursement or payment to us for certain direct operational payroll and other overhead costs. The management fees we ~~have received~~receive are reported as affiliate management fee revenue on our consolidated statements of income. Cost reimbursements we receive from these entities in connection with our operating services are included as reductions to costs and expenses on our consolidated statements of income and totaled $1.2 million and $0.7 million during the three months ended September 30, ~~2016~~2019 and ~~2017,~~2020, respectively, and ~~$2.7~~$3.8 million and ~~$3.1~~$2.9 million during the nine months ended September 30, ~~2016~~2019 and ~~2017,~~2020, respectively.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

We recorded the following revenue ~~from~~and expense transactions with certain of these non-controlled entities in our consolidated statements of income (in ~~millions)~~thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2020		2019		2020
Transportation and terminals revenue:
BridgeTex, pipeline capacity and storage	$	10,737	$	9,323	$	31,063	$	32,748
Double Eagle, throughput revenue	$	1,582	$	995	$	4,813	$	4,016
Saddlehorn, storage revenue	$	566	$	580	$	1,669	$	1,711
Operating expenses:
Seabrook, storage lease and ancillary services	$	6,267	$	7,175	$	19,417	$	21,553




Other operating income:
Seabrook, gain on sale of air emission credits	$	0	$	0	$	0	$	1,410
MVP, easement sale	$	289	$	0	$	289	$	0

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

~~Table of Contents~~

~~MAGELLAN MIDSTREAM PARTNERS, L.P.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

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


	December 31, 2019
	Trade Accounts Receivable		Other Accounts Receivable		Other Accounts Payable		Long-Term Receivables
BridgeTex	$	392	$	26	$	—	$	—
Double Eagle	$	445	$	—	$	—	$	—
HoustonLink	$	60	$	—	$	—	$	—
MVP	$	—	$	418	$	—	$	—
Powder Springs	$	161	$	—	$	—	$	6,006
Saddlehorn	$	—	$	126	$	—	$	—
Seabrook	$	941	$	—	$	1,349	$	—


										September 30, 2020
	December 31, 2016				September 30, 2017					Trade Accounts Receivable		Other Accounts Receivable		Other Accounts Payable		Long-Term Receivables
BridgeTex									BridgeTex	$	382	$	441	$	225	$	—
Double Eagle									Double Eagle	$	286	$	—	$	—	$	—
	Trade Accounts Receivable		Other Accounts Receivable		Trade Accounts Receivable		Other Accounts Receivable
Double Eagle	$	0.3	$	—	$	0.5	$	—
MVP	$	—	$	—	$	—	$	0.5	MVP	$	—	$	460	$	—	$	—
Powder Springs									Powder Springs	$	—	$	—	$	—	$	8,970
Saddlehorn	$	—	$	0.1	$	—	$	0.1	Saddlehorn	$	—	$	142	$	—	$	—
Seabrook									Seabrook	$	497	$	—	$	4,267	$	—

~~In addition~~We are a party to ~~the transactions noted above, we incurred charges~~a long-term terminalling and storage contract with Seabrook for exclusive use of ~~$9.0 million and $12.9 million for transportation of~~dedicated tankage that provides our customers with crude oil ~~at published spot tariff rates~~storage capacity and dock access for crude oil imports and exports on the BridgeTex pipeline during the three and nine months ended September 30, 2017, respectively. We recorded these charges as cost of product sales in our consolidated statements of income. We also purchased inventory from BridgeTex valued at $2.8 million in September 2017. We recognized an affiliate payable to BridgeTex on our consolidated balance sheets as of September 30, 2017 in the amount of $5.6 million in connection withTexas Gulf Coast (see Note 7 – Leases for more details regarding this ~~activity.~~lease).

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

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

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

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The financial results from MVP, Powder Springs and Texas Frontera are included in our refined products segment and the financial results from BridgeTex, Double Eagle, HoustonLink, Saddlehorn and Seabrook are included in our crude oil segment, each as earnings of non-controlled entities.

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

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

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

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


5.	~~Inventory~~
Investments at 12/31/2019		$	1,240,551
Additional investment		73,678
Sale of ownership interest in Saddlehorn		(66,989)

Earnings of non-controlled entities:
Proportionate share of earnings		117,848

Amortization of excess investment and capitalized interest		(1,364)
Earnings of non-controlled entities		116,484
Less:
Distributions from operations of non-controlled entities		152,645

Investments at 9/30/2020		$	1,211,079

5.Inventory

Inventory at December 31, ~~2016~~2019 and September 30, ~~2017~~2020 was as follows (in thousands):


	December 31, 2019		September 30, 2020
Refined products	$	96,128	$	60,515
Liquefied petroleum gases	29,982		30,155
Transmix	39,546		20,821
Crude oil	12,714		12,872
Additives	6,029		4,670
Total inventory	$	184,399	$	129,033

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


6.	~~Employee Benefit Plans~~

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

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

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6.Debt

Three Months Ended Three Months Ended
September 30, 2016 September 30, 2017

Pension
Benefits

Other Postretirement
Benefits

Pension
Benefits

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

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

Pension
Benefits

Other Postretirement
Benefits

Pension
Benefits

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

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

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~~MAGELLAN MIDSTREAM PARTNERS, L.P.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

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

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

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

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

~~Table of Contents~~

~~MAGELLAN MIDSTREAM PARTNERS, L.P.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~


7.	~~Debt~~

Long-term debt at December 31, ~~2016~~2019 and September 30, ~~2017~~2020 was as follows (in thousands):


	December 31, 2019		September 30, 2020
Commercial paper	$	0	$	248,000

4.25% Notes due 2021	550,000		0
3.20% Notes due 2025	250,000		250,000
5.00% Notes due 2026	650,000		650,000
3.25% Notes due 2030	0		500,000
6.40% Notes due 2037	250,000		250,000
4.20% Notes due 2042	250,000		250,000
5.15% Notes due 2043	550,000		550,000
4.20% Notes due 2045	250,000		250,000
4.25% Notes due 2046	500,000		500,000
4.20% Notes due 2047	500,000		500,000
4.85% Notes due 2049	500,000		500,000
3.95% Notes due 2050	500,000		500,000
Face value of long-term debt	4,750,000		4,948,000
Unamortized debt issuance costs(1)	(35,263)		(37,407)
Net unamortized debt discount(1)	(8,662)		(10,282)



Long-term debt, net	$	4,706,075	$	4,900,311

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

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

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

~~2017~~2020 Debt ~~Offering~~Issuance

~~See Note 14 –~~ ~~Subsequent Events~~In May 2020, we issued $500.0 million of 3.25% senior notes due 2030 in an underwritten public offering. The notes were issued at 99.88% of par. Net proceeds from this offering were approximately $495.2 million after underwriting discounts and offering expenses. The net proceeds from this offering, along with commercial paper borrowings and cash on hand, were used to redeem our $550 million senior notes due in 2021. We recognized $12.9 million of debt prepayment costs as interest expense in our consolidated statements of income related to this early redemption, partially offset by the recognition of a $0.7 million unamortized debt premium, for ~~information about our October 2017 debt issuance.~~the nine months ended September 30, 2020.

Other Debt

Revolving Credit ~~Facilities.~~ Facility. At September 30, ~~2017,~~2020, the total borrowing capacity under our revolving credit facility ~~with a maturity date of October 27, 2020~~maturing in May 2024 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%~~0.875% to ~~1.625%~~1.500% based on our credit ratings. Additionally, an unused commitment fee is assessed at a rate between ~~0.100%~~0.075% and ~~0.275%~~0.200% depending on our credit ratings. The unused commitment fee was 0.125% at September 30, ~~2017.~~2020. Borrowings under this facility may be used for general partnership purposes, including capital expenditures. As of ~~both~~ December 31, ~~2016~~2019 and September 30, ~~2017,~~2020, there were no0 borrowings outstanding under this facility ~~with $6.3~~and $3.5 million was obligated for letters of credit. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheets, but decrease our borrowing capacity ~~under this facility. In October 2017, we extended the maturity date of this facility (see Note 14 –~~ ~~Subsequent Events, for further information).~~

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

~~Table of Contents~~

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Commercial Paper Program. We have a commercial paper program under which we may issue commercial paper notes in an amount up to the available capacity under our $1.0 billion revolving credit facility. The maturities of the commercial paper notes vary, but may not exceed 397 days from the date of issuance. Because the commercial paper we can issue is limited to amounts available under our revolving credit facility, amounts outstanding under the program are classified as long-term debt. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. Commercial paper borrowings outstanding at September 30, 2020 were $248.0 million. The weighted-average interest rate for commercial paper borrowings based on the number of days outstanding was ~~0.8% for the year ended December 31, 2016 and 1.3%~~0.6% for the nine months ended September 30, ~~2017.~~2020.


8.	~~Derivative Financial Instruments~~

~~Interest Rate Derivatives~~7.Leases

Operating Leases – Lessee

Related-Party Operating Lease. We have a long-term terminalling and storage contract with Seabrook for exclusive use of dedicated tankage that provides our customers with crude oil storage capacity and dock access for crude oil imports and exports on the Texas Gulf Coast.

The following tables provide information about our third-party and Seabrook operating leases (dollars in thousands):


	Three Months Ended September 30, 2019						Three Months Ended September 30, 2020
	Third-Party Leases		Seabrook Lease		All Leases		Third-Party Leases		Seabrook Lease		All Leases
Total lease expense	$	6,206	$	6,267	$	12,473	$	6,474	$	7,175	$	13,649

	Nine Months Ended September 30, 2019						Nine Months Ended September 30, 2020
	Third-Party Leases		Seabrook Lease		All Leases		Third-Party Leases		Seabrook Lease		All Leases
Total lease expense	$	17,631	$	19,417	$	37,048	$	18,173	$	21,553	$	39,726


	December 31, 2019						September 30, 2020
	Third-Party Leases		Seabrook Lease		All Leases		Third-Party Leases		Seabrook Lease		All Leases
Current lease liability	$	15,136	$	11,085	$	26,221	$	15,721	$	11,456	$	27,177
Long-term lease liability	$	81,508	$	62,515	$	144,023	$	67,323	$	54,441	$	121,764
Right-of-use asset	$	98,268	$	73,600	$	171,868	$	86,185	$	65,897	$	152,082

8.Employee Benefit Plans

We ~~periodically enter into interest rate derivatives~~sponsor a defined contribution plan in which we match our employees’ qualifying contributions, resulting in additional expense to ~~hedge~~us. Expenses related to the ~~fair value~~defined contribution plan were $2.8 million for each of debt or hedge against variability in interest rates, and we have historically designated these derivatives as fair value or cash flow hedges for accounting purposes. Adjustments resulting from discontinued hedges continue to be recognized in accordance with their historic hedging relationships.

~~We have entered into $100.0 million of forward-starting interest rate swap agreements to hedge against~~ the ~~risk of variability of future interest payments on a portion of debt we anticipate issuing in 2018. The fair values of these contracts at~~three months ended September 30, ~~2017 were recorded on our balance sheets as other current assets of $12.4~~2019 and 2020, and $9.3 million ~~with~~and $9.7 million for the ~~offset recorded to other comprehensive income. We account for these agreements as cash flow hedges.~~nine months ended September 30, 2019 and 2020, respectively.

~~Commodity Derivatives~~

~~Hedging Strategies~~

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

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

~~Table of Contents~~

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

~~The futures contracts~~In addition, we sponsor 2 pension plans, including 1 for all non-union employees and 1 that covers union employees, and a postretirement benefit plan for certain employees. Prior to the March 2020 sale of our New Haven terminal (See Note 1 – Organization, Description of Business and Basis of Presentation), we ~~enter into fall into one of~~sponsored an additional union pension plan that covered union employees at that terminal. Net periodic benefit expense for the three ~~hedge categories:~~



~~Hedge Category~~	~~Hedge Purpose~~	~~Accounting Treatment~~
~~Qualifies For Hedge Accounting Treatment~~
~~Cash Flow Hedge~~	~~To hedge the variability in cash flows related to a forecasted transaction.~~	~~The effective portion of changes in the fair value of the hedge is recorded to accumulated other comprehensive income/loss~~ and ~~reclassified to earnings when the forecasted transaction occurs. Any ineffectiveness is recognized currently in earnings.~~
~~Fair Value Hedge~~	~~To hedge against changes in the fair value of a recognized asset or liability.~~	The effective portion of changes in the fair value of the hedge is recorded as adjustments to the asset or liability being hedged. Any ineffectiveness and amounts excluded from the assessment of hedge effectiveness are recognized currently in earnings.
~~Does Not Qualify For Hedge Accounting Treatment~~
~~Economic Hedge~~	To effectively serve as either a fair value or a cash flow hedge; however, the derivative agreement does not qualify for hedge accounting treatment under Accounting Standards Codification (“ASC”) 815, ~~Derivatives and Hedging~~.	~~Changes in the fair value of these agreements are recognized currently in earnings.~~

~~During the~~ nine months ended September 30, ~~2016~~2019 and ~~2017, none~~2020 was as follows (in thousands):


	Three Months Ended				Three Months Ended
	September 30, 2019				September 30, 2020
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Components of net periodic benefit costs:
Service cost	$	6,260	$	48	$	6,898	$	64
Interest cost	3,026		126		2,738		121
Expected return on plan assets	(2,354)		0		(2,829)		0
Amortization of prior service credit	(46)		0		(46)		0
Amortization of actuarial loss	1,352		60		1,346		127
Settlement cost	439		0		0		0


Net periodic benefit cost	$	8,677	$	234	$	8,107	$	312


	Nine Months Ended				Nine Months Ended
	September 30, 2019				September 30, 2020
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Components of net periodic benefit costs:
Service cost	$	19,145	$	145	$	20,836	$	193
Interest cost	9,136		380		8,251		360
Expected return on plan assets	(7,045)		0		(8,524)		0
Amortization of prior service credit	(136)		0		(136)		0
Amortization of actuarial loss	4,137		248		4,080		382
Settlement cost	2,499		0		969		0
Settlement gain on disposition of assets	0		0		(1,342)		0
Net periodic benefit cost	$	27,736	$	773	$	24,134	$	935

The service component of our net periodic benefit costs is presented in operating expense and G&A expense, and the ~~commodity hedging contracts we entered into qualified for or were designated as cash flow hedges.~~

~~We use futures contracts designated as economic hedges for accounting purposes to hedge against changes~~non-service components are presented in ~~the price of petroleum products that we expect to sell~~other (income) expense in ~~the future. Period changes in the fair value of these agreements are recognized currently in earnings as adjustments to product sales revenue.~~

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

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

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



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

~~Table of Contents~~

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The changes in accumulated other comprehensive loss (“AOCL”) related to employee benefit plan assets and benefit obligations for the three and nine months ended September 30, 2019 and 2020 were as follows (in thousands):

~~Energy~~


	Three Months Ended				Three Months Ended
	September 30, 2019				September 30, 2020
Gains (Losses) Included in AOCL	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Beginning balance	$	(93,876)	$	(6,105)	$	(98,610)	$	(9,269)


Recognition of prior service credit amortization in income	(46)		0		(46)		0
Recognition of actuarial loss amortization in income	1,352		60		1,346		127
Recognition of settlement cost in income	439		0		0		0
Ending balance	$	(92,131)	$	(6,045)	$	(97,310)	$	(9,142)


	Nine Months Ended				Nine Months Ended
	September 30, 2019				September 30, 2020
Gains (Losses) Included in AOCL	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Beginning balance	$	(88,602)	$	(5,409)	$	(104,739)	$	(8,378)
Net actuarial gain (loss)	(10,029)		(884)		813		(1,146)
Curtailment gain	0		0		1,703		0
Recognition of prior service credit amortization in income	(136)		0		(136)		0
Recognition of actuarial loss amortization in income	4,137		248		4,080		382
Recognition of settlement cost in income	2,499		0		969		0
Ending balance	$	(92,131)	$	(6,045)	$	(97,310)	$	(9,142)

Contributions estimated to be paid into the plans in 2020 are $29.3 million and $0.9 million for the pension plans and other postretirement benefit plan, respectively.

9.Long-Term Incentive Plan

The compensation committee of our general partner’s board of directors administers our long-term incentive plan (“LTIP”) covering certain of our employees and the independent 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 common units. The estimated units remaining available under the LTIP at September 30, 2020 total 1.0 million.

Equity-based incentive compensation expense for the three and nine months ended September 30, 2019 and 2020, primarily recorded as G&A expense on our consolidated statements of income, was as follows (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2020		2019		2020
Performance-based awards	$	5,162	$	(1,121)	$	18,123	$	(1,247)
Time-based awards	1,611		2,290		4,454		6,827
Total	$	6,773	$	1,169	$	22,577	$	5,580

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

During 2020, we reduced our LTIP accruals related to performance awards vesting in 2020 and 2021 to reflect the estimated impacts of COVID-19 related reductions in economic activity and the significant decline in commodity prices.

On January 31, 2020, 378,144 unit awards were granted pursuant to our LTIP. These awards included both performance-based and time-based awards and have a three-year vesting period that will end on December 31, 2022.

Basic and Diluted Net Income Per Common Unit

The difference between our actual common units outstanding and our weighted-average number of common units outstanding used to calculate basic net income per unit is due to the impact of: (i) the unit awards issued to non-employee directors and (ii) the weighted average effect of units actually issued or repurchased during a period. The difference between the weighted-average number of common units outstanding used for basic and diluted net income per unit calculations on our consolidated statements of income is primarily due to the dilutive effect of unit awards associated with our LTIP that have not yet vested.

10.Derivative Financial Instruments

Interest Rate Derivatives

In second quarter 2020, upon issuance of $500.0 million of 3.25% notes due 2030, we terminated and settled $100.0 million of treasury lock agreements that we had previously entered into to protect against the variability of future interest payments for a loss of $10.4 million, which was included in our statements of cash flows as a net payment on financial derivatives. These agreements were accounted for as cash flow hedges. The loss was recorded to other comprehensive income and will be recognized into earnings as an adjustment to our periodic interest expense over the term of the hedged transaction in accordance with our hedging strategy.

Commodity Derivatives

Our open futures contracts at September 30, 2020 were as follows:

Type of Contract/Accounting Methodology

Product Represented by the Contract and Associated Barrels

Maturity Dates

Futures - Economic Hedges

3.1 million barrels of refined products and crude oil

Between October 2020 and November 2022

Futures - Economic Hedges

0.6 million barrels of gas liquids

Between October and December 2020

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Commodity Derivatives Contracts and Deposits Offsets

At December 31, ~~2016,~~2019 and September 30, 2020, we had made margin deposits of ~~$49.9~~$27.4 million and $14.0 million, respectively, for our ~~future~~futures contracts with our counterparties, which were recorded as current assets under energy commodity derivatives deposits on our consolidated balance sheets. At September 30, 2017, we had made margin deposits of $31.7 million for our future contracts with our counterparties, which were recorded as current assets under energy commodity derivatives deposits on our consolidated balance sheets. We have the right to offset the combined fair values of our open futures contracts against our margin deposits under a master netting arrangement for each counterparty; however, we have elected to present the combined fair values of our open futures contracts separately from the related margin deposits on our consolidated balance sheets. Additionally, we have the right to offset the fair values of our futures contracts together for each counterparty, which we have elected to do, and we report the combined net balances on our consolidated balance sheets. A schedule of the derivative amounts we have offset and the deposit amounts we could offset under a master netting arrangement are provided below as of December 31, ~~2016~~2019 and September 30, ~~2017~~2020 (in thousands):


Description	Gross Amounts of Recognized Liabilities		Gross Amounts of Assets Offset in the Consolidated Balance Sheets		Net Amounts of Liabilities Presented in the Consolidated Balance Sheets		Margin Deposit Amounts Not Offset in the Consolidated Balance Sheets		Net Asset Amount(1)
As of 12/31/2019	$	(11,033)	$	811	$	(10,222)	$	27,415	$	17,193
As of 9/30/2020	$	(4,386)	$	2,740	$	(1,646)	$	14,031	$	12,385

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

Basis Derivative Agreement

During 2019, we entered into a basis derivative agreement with a joint venture co-owner’s affiliate, and, contemporaneously, that affiliate entered into an intrastate transportation services agreement with the joint venture. Settlements under the basis derivative agreement are determined based on the basis differential of crude oil prices at different market locations and a notional volume of 30,000 barrels per day. As a result, we account for this agreement as a derivative. The agreement will expire in early 2022. We recognize the changes in fair value of this agreement based on forward price curves for crude oil in West Texas and the Houston Gulf Coast in other operating income (expense) in our consolidated statements of income. The liability for this agreement at December 31, 2019 and September 30, 2020 was $17.3 million and $12.3 million, respectively.

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

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


~~(1)~~	~~Amount represents the maximum loss we would incur if all of our counterparties failed to perform on their derivative contracts.~~

Impact of Derivatives on Our Financial Statements

Comprehensive Income

The changes in derivative activity included in AOCL for the three and nine months ended September 30, ~~2016~~2019 and ~~2017~~2020 were as follows (in thousands):


	Three Months Ended						Nine Months Ended							Three Months Ended				Nine Months Ended
	September 30,						September 30,							September 30,				September 30,
Derivative Losses Included in AOCL	2016			2017			2016			2017			Derivative Losses Included in AOCL	2019		2020		2019		2020
Beginning balance	$	(50,459	)	$	(34,804	)	$	(30,126	)	$	(34,776	)	Beginning balance	$	(36,287)	$	(57,748)	$	(26,480)	$	(48,960)
Net gain (loss) on cash flow hedges	(3,169		)	(228		)	(24,278		)	(1,735		)
Net loss on cash flow hedges													Net loss on cash flow hedges	(14,181)		0		(25,216)		(10,444)
Reclassification of net loss on cash flow hedges to income	512			740			1,288			2,219			Reclassification of net loss on cash flow hedges to income	699		896		1,927		2,552
Ending balance	$	(53,116	)	$	(34,292	)	$	(53,116	)	$	(34,292	)	Ending balance	$	(49,769)	$	(56,852)	$	(49,769)	$	(56,852)

~~Table of Contents~~

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

~~Income Statements~~

The following ~~tables provide~~is a summary of the effect on our consolidated statements of income for the three and nine months ended September 30, ~~2016~~2019 and ~~2017~~2020 of derivatives ~~accounted for under ASC 815-30,~~ ~~Derivatives and Hedging—Cash Flow Hedges~~, that were designated as ~~hedging instruments~~cash flow hedges (in thousands):


	Interest Rate Contracts
	Amount of Loss Recognized in AOCL on Derivatives		Location of Loss Reclassified from AOCL into Income	Amount of Loss Reclassified from AOCL into Income
Three Months Ended September 30, 2019	$	(14,181)	Interest expense	$	(699)
Three Months Ended September 30, 2020	$	0	Interest expense	$	(896)
Nine Months Ended September 30, 2019	$	(25,216)	Interest expense	$	(1,927)
Nine Months Ended September 30, 2020	$	(10,444)	Interest expense	$	(2,552)

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

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

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

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

As of September 30, ~~2017,~~2020, the net loss estimated to be classified to interest expense over the next twelve months from AOCL is approximately ~~$3.0~~$3.3 million.

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

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

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

~~Table of Contents~~

~~MAGELLAN MIDSTREAM PARTNERS, L.P.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

The following table provides a summary of the effect on our consolidated statements of income for the three and nine months ended September 30, ~~2016~~2019 and ~~2017~~2020 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																					Amount of Gain (Loss) Recognized on Derivatives
			Three Months Ended								Nine Months Ended													Three Months Ended								Nine Months Ended
	Location of Gain (Loss) Recognized on Derivatives		September 30,								September 30,									Location of Gain (Loss) Recognized on Derivatives				September 30,								September 30,
Derivative Instrument		2016				2017				2016				2017			Derivative Instrument						2019				2020				2019				2020
Futures contracts		Product sales revenue		$	(12,650	)		$	(47,336	)		$	(8,438	)		$	(4,442	)	Futures contracts			Product sales revenue				$	17,626			$	(7,734)			$	(41,504)			$	89,280

Futures contracts	Operating expenses		4,212				663				(1,192		)		663			Futures contracts			Cost of product sales				(5,581)				1,815				(9,456)				(2,529)
Futures contracts	Cost of product sales		831				19,660				3,643				19,713
Basis derivative agreement																		Basis derivative agreement		Other operating income (expense)				(3,910)				(3,155)				(8,869)				(2,654)
	Total		$	(7,607	)		$	(27,013	)		$	(5,987	)		$	15,934				Total				$	8,135			$	(9,074)			$	(59,829)			$	84,097

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

~~Balance Sheets~~

~~The following tables provide a summary of the fair value of derivatives accounted for under ASC 815,~~ ~~Derivatives and Hedging,~~ ~~which are presented on a net basis in our consolidated balance sheets, that were designated as hedging instruments as of December 31, 2016 and September 30, 2017 (in thousands):~~

December 31, 2016
Asset Derivatives Liability Derivatives
Derivative Instrument Balance Sheet Location Fair Value Balance Sheet Location Fair Value
Futures contracts Energy commodity derivatives contracts, net $ —
Energy commodity derivatives contracts, net $ 3,079
Interest rate contracts Other noncurrent assets 14,114
Other noncurrent liabilities —
Total $ 14,114
Total $ 3,079

September 30, 2017
Asset Derivatives Liability Derivatives
Derivative Instrument Balance Sheet Location Fair Value Balance Sheet Location Fair Value
Futures contracts Energy commodity derivatives contracts, net $ 18
Energy commodity derivatives contracts, net $ —
Interest rate contracts Other current assets 12,379
Other current liabilities —
Total $ 12,397
Total $ —

~~Table of Contents~~

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 not designated as hedging instruments as of December 31, ~~2016~~2019 and September 30, ~~2017~~2020 (in thousands):

December 31, 2019

Asset Derivatives

Liability Derivatives

Derivative Instrument

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Futures contracts

Commodity derivatives contracts, net

811

Commodity derivatives contracts, net

11,033

Basis derivative agreement

Other current assets

Other current liabilities

8,457

Basis derivative agreement

Other noncurrent assets

Other noncurrent liabilities

8,847

Total

811

Total

28,337

December 31, 2016

September 30, 2020

Asset Derivatives

Liability Derivatives

Asset Derivatives

Liability Derivatives

Derivative Instrument

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Derivative Instrument

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Futures contracts

Energy commodity derivatives contracts, net

6,060

Energy commodity derivatives contracts, net

33,719

Futures contracts

Commodity derivatives contracts, net

1,095

Commodity derivatives contracts, net

3,983

Futures contracts

Other noncurrent assets

1,645

Other noncurrent assets

403

Basis derivative agreement

Other current assets

Other current liabilities

9,280

Basis derivative agreement

Other noncurrent assets

Other noncurrent liabilities

2,994

Total

2,740

Total

16,660

September 30, 2017

Asset Derivatives

Liability Derivatives

Derivative Instrument

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Futures contracts

Energy commodity derivatives contracts, net

18,958

Energy commodity derivatives contracts, net

32,685


9.	~~Commitments and Contingencies~~

~~Environmental Liabilities~~11.Fair Value

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

~~Environmental Receivables~~

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

~~Other~~

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

We are a party to various other claims, legal actions and complaints arising in the ordinary course of business. While the results cannot be predicted with certainty, management believes the ultimate resolution of these claims, legal actions and complaints after consideration of amounts accrued, insurance coverage or other indemnification arrangements will not have a material adverse effect on our results of operations, financial position or cash flows.

~~Table of Contents~~

~~MAGELLAN MIDSTREAM PARTNERS, L.P.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~


~~10.~~	~~Long-Term Incentive Plan~~

We have a long-term incentive plan (“LTIP”) for certain of our employees and directors of our general partner. The LTIP primarily consists of phantom units and permits the grant of awards covering an aggregate payout of 11.9 million of our limited partner units. The compensation committee of our general partner’s board of directors administers our LTIP. The estimated units remaining available under the LTIP at September 30, 2017 total 2.6 million.

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

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

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

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

~~Basic and Diluted Net Income Per Limited Partner Unit~~

The difference between our actual limited partner units outstanding and our weighted-average number of limited partner units outstanding used to calculate basic net income per unit is due to the impact of: (i) the phantom units issued to non-employee directors and (ii) the weighted average effect of units actually issued during a period. The difference between the weighted-average number of limited partner units outstanding used for basic and diluted net income per unit calculations on our consolidated statements of income is primarily the dilutive effect of phantom unit grants associated with our LTIP that have not yet vested.

~~Table of Contents~~

~~MAGELLAN MIDSTREAM PARTNERS, L.P.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~


~~11.~~	~~Partners’ Capital and Distributions~~

~~Partners’ Capital~~

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

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



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

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

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

~~Distributions~~

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

Payment Date
Per Unit Cash
Distribution
Amount
Total Cash Distribution to Limited Partners
02/12/2016 $ 0.7850
$ 178,808

05/13/2016 0.8025
182,797

08/12/2016 0.8200
186,783

Through 09/30/2016 2.4075
548,388

11/14/2016 0.8375
190,769

Total $ 3.2450
$ 739,157

02/14/2017 $ 0.8550
$ 194,961

05/15/2017 0.8725
198,951

08/14/2017 0.8900
202,942

Through 09/30/2017 2.6175
596,854

11/14/2017⁽¹⁾
0.9050
206,362

Total $ 3.5225
$ 803,216

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

~~Table of Contents~~

~~MAGELLAN MIDSTREAM PARTNERS, L.P.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~


~~12.~~	~~Fair Value~~

Fair Value Methods and Assumptions - Financial Assets and ~~Liabilities.~~Liabilities

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

~~Energy commodity~~•Commodity derivatives contracts. These include exchange-traded futures contracts related to petroleum products. These contracts are carried at fair value on our consolidated balance sheets and are valued based on quoted prices in active markets. See Note 810 – Derivative Financial Instruments for further disclosures regarding these contracts.

~~Interest rate contracts.~~ ~~These include forward-starting interest rate swap agreements to hedge against~~•Basis derivative agreement. During 2019, we entered into a basis derivative agreement with a joint venture co-owner’s affiliate, and, contemporaneously, that affiliate entered into an intrastate transportation services agreement with the ~~risk of variability of interest payments on future debt. These contracts~~joint venture. Settlements under the basis derivative agreement are ~~carried at fair value on our consolidated balance sheets and are valued~~determined based on ~~an assumed exchange,~~the basis differential of crude oil prices at ~~the end~~different market locations and a notional volume 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. See30,000 barrels per day (see Note ~~8 –~~ 10 - Derivative Financial Instrumentsfor further disclosures regarding ~~these~~this agreement). The fair value of this derivative was calculated based on observable market data inputs, including published commodity pricing data and market interest rates. The key inputs in the fair value calculation include the forward price curves for crude oil, the implied forward correlation in crude oil prices between West Texas and the Houston Gulf Coast, and the implied forward volatility for crude oil futures contracts.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

•Long-term receivables. These primarily include payments receivable under a ~~direct-financing~~sales-type 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.

•Guarantees and contractual obligations. At September 30, 2020, these primarily include a long-term contractual obligation we entered into in connection with the sale of our 3 marine terminals to a subsidiary of Buckeye. This obligation requires us to perform certain environmental remediation work on Buckeye’s behalf at the New Haven terminal. The contractual obligation was recorded at fair value on our consolidated balance sheets upon initial recognition and was calculated using our best estimate of potential outcome scenarios to determine our liability for the remediation costs required in this agreement.

•Debt. The fair value of our publicly traded notes was based on the prices of those notes at December 31, ~~2016~~2019 and September 30, ~~2017;~~2020; however, where recent observable market trades were not available, prices were determined using adjustments to the last traded value for that debt issuance or by adjustments to the prices of similar debt instruments of peer entities that are actively traded. The carrying amount of borrowings, if any, under our revolving credit facility and our commercial paper program approximates fair value due to the frequent repricing of these obligations.

Fair Value Measurements - Financial Assets and Liabilities

The following tables summarize the carrying amounts, fair values and fair value measurements recorded or disclosed as of December 31, ~~2016~~2019 and September 30, ~~2017~~2020 based on the three levels established by ASC 820, Fair Value Measurements and Disclosures (in thousands):


	December 31, 2019
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)

Commodity derivatives contracts	$	(10,222)	$	(10,222)	$	(10,222)	$	—	$	—

Basis derivative agreement	$	(17,304)	$	(17,304)	$	—	$	(17,304)
Long-term receivables	$	20,782	$	20,782	$	—	$	—	$	20,782
Guarantees and contractual obligations	$	(408)	$	(408)	$	—	$	—	$	(408)
Debt	$	(4,706,075)	$	(5,192,685)	$	—	$	(5,192,685)	$	—

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

~~Table of Contents~~

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


	September 30, 2020
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)

Commodity derivatives contracts	$	(1,646)	$	(1,646)	$	(1,646)	$	—	$	—



Basis derivative agreement	$	(12,274)	$	(12,274)	$	—	$	(12,274)	$	—
Long-term receivables	$	21,850	$	21,850	$	—	$	—	$	21,850
Guarantees and contractual obligations	$	(11,239)	$	(11,239)	$	—	$	—	$	(11,239)
Debt	$	(4,900,311)	$	(4,872,340)	$	—	$	(4,872,340)	$	—

12.Commitments and Contingencies

Butane Blending Patent Infringement Proceeding

On October 4, 2017, Sunoco Partners Marketing & Terminals L.P. (“Sunoco”) brought an action for patent infringement in the U.S. District Court for the District of Delaware alleging Magellan Midstream Partners, L.P. (“Magellan”) and Powder Springs Logistics, LLC (“Powder Springs”) are infringing patents related to butane blending at the Powder Springs facility located in Powder Springs, Georgia. Sunoco subsequently submitted pleadings alleging that Magellan is also infringing various patents related to butane blending at 9 Magellan facilities, in addition to Powder Springs. Sunoco is seeking monetary damages, attorneys’ fees and a permanent injunction enjoining Magellan and Powder Springs from infringing the subject patents. We deny and are vigorously defending against all claims asserted by Sunoco. Although it is not possible to predict the ultimate outcome, we believe the ultimate resolution of this matter will not have a material adverse impact on our results of operations, financial position or cash flows.

Environmental Liabilities

Liabilities recognized for estimated environmental costs were $14.9 million and $11.9 million at December 31, 2019 and September 30, 2020, respectively. We have classified environmental liabilities as current or noncurrent based on management’s estimates regarding the timing of actual payments. Environmental expenses recognized as a result of changes in our environmental liabilities are generally included in operating expenses on our consolidated statements of income. Environmental expenses were $0.8 million and $0.1 million for the three months ended September 30, 2019 and 2020, respectively, and $4.2 million and $1.3 million for the nine months ended September 30, 2019 and 2020, respectively.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Receivables from insurance carriers and other third parties related to environmental matters were $2.9 million at December 31, 2019, of which $1.8 million and $1.1 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 $1.8 million at September 30, 2020, of which $1.0 million and $0.8 million were recorded to other accounts receivable and long-term receivables, respectively, on our consolidated balance sheets.


~~13.~~	~~Related Party Transactions~~

Other

In first quarter 2020, we entered into a long-term contractual obligation in connection with the sale of 3 marine terminals to Buckeye. This obligation requires us to perform certain environmental remediation work on Buckeye’s behalf at the New Haven terminal. As of September 30, 2020, our consolidated balance sheets reflected a current liability of $0.6 million and a noncurrent liability of $10.2 million to reflect the fair value of this obligation.

We have entered into an agreement to guarantee our 50% pro rata share, up to $25.0 million, of obligations under Powder Springs’ credit facility. As of September 30, 2020, our consolidated balance sheets reflected a $0.4 million other current liability and a corresponding increase in our investment in non-controlled entities on our consolidated balance sheets to reflect the fair value of this guarantee.

We and the non-controlled entities in which we own an interest are a party to various other claims, legal actions and complaints. 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.

13.Related Party Transactions

Stacy P. Methvin is an independent member of our general partner’s board of directors and is also a director of one of our customers. We received tariff, terminalling and other ancillary revenue from this customer of ~~$4.3~~$7.1 million and ~~$4.1~~$8.6 million for the three months ended September 30, ~~2016~~2019 and ~~2017,~~2020, respectively, and ~~$12.0~~$21.4 million and ~~$12.5~~$24.3 million for the nine months ended September 30, ~~2016~~2019 and ~~2017,~~2020, respectively. We recorded receivables of ~~$1.4~~$3.8 million and $3.7 million from this customer at ~~both~~ December 31, ~~2016~~2019 and September 30, ~~2017. The tariff~~2020, respectively. We also received storage and other miscellaneous revenue ~~we recognized~~of $0.1 million and $0.3 million for the three and nine months ended September 30, 2020, respectively, from ~~this customer was in the normal course~~a subsidiary of ~~business, with rates determined in accordance with published tariffs.~~ a separate company for which Stacy Methvin serves as a director.

See Note 4 – Investments in Non-Controlled Entitiesand Note 7 –Leases for ~~a discussion~~details of transactions with our joint ventures.

14.Partners’ Capital and Distributions

Partners’ Capital

Our general partner’s board of directors authorized the repurchase of up to $750 million of our common units through 2022. The timing, price and actual number of common units repurchased will depend on a number of factors including our expected expansion capital spending needs, excess cash available, balance sheet metrics, legal and

~~Table of Contents~~

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

regulatory requirements, market conditions and the trading price of our common units. The repurchase program does not obligate us to acquire any particular amount of common units, and the repurchase program may be suspended or discontinued at any time.

The following table details the changes in the number of our common units outstanding from December 31, 2019 through September 30, 2020:


~~14.~~Common units outstanding on December 31, 2019	~~Subsequent Events~~	228,403,428
Units repurchased during 2020		(4,987,128)
January 2020–Settlement of employee LTIP awards		275,093
During 2020–Other(a)		9,550
Common units outstanding on September 30, 2020		223,700,943

(a) Common units issued to settle the equity-based retainers paid to independent directors of our general partner.

Distributions

Distributions we paid during 2019 and 2020 were as follows (in thousands, except per unit amounts):


Payment Date	Per Unit Cash Distribution Amount			Total Cash Distribution
02/14/2019		$	0.9975		$	227,832
05/15/2019		1.0050			229,545

08/14/2019		1.0125			231,258
Through 09/30/2019		3.0150			688,635
11/14/2019		1.0200			232,971
Total		$	4.0350		$	921,606

02/14/2020		$	1.0275		$	234,774
05/15/2020		1.0275			231,245

08/14/2020		1.0275			231,245
Through 09/30/2020		3.0825			697,264
11/13/2020(a)		1.0275			229,853
Total		$	4.1100		$	927,117

(a) Our general partner’s board of directors declared this cash distribution in October 2020 to be paid on November 13, 2020 to unitholders of record at the close of business on November 6, 2020.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

15.Subsequent Events

Recognizable events

No recognizable events occurred subsequent to September 30, ~~2017.~~2020.

Non-recognizable events

Cash Distribution. In October ~~2017,~~2020, our general partner’s board of directors declared a quarterly cash distribution of ~~$0.905~~$1.0275 per unit for the period of July 1, ~~2017~~2020 through September 30, ~~2017.~~2020. This quarterly cash distribution will be paid on November ~~14, 2017~~13, 2020 to unitholders of record on November ~~2, 2017. The total cash distributions expected to be paid under this declaration are approximately $206.4 million.~~6, 2020.

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

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

~~Table of Contents~~


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

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

Introduction

We are a publicly traded limited partnership principally engaged in the transportation, storage and distribution of refined petroleum products and crude oil. As of September 30, ~~2017,~~2020, our asset portfolio ~~including the assets of our joint ventures,~~ consisted of:

two marine storage terminals (one of which is owned through a joint venture); and

During first quarter 2020, we completed a reorganization of our reportable segments. This reorganization was effected to reflect changes in the management of our business in conjunction with the sale of three of our marine ~~storage segment, consisting~~terminals. Following this sale, two of ~~five~~our remaining marine terminals ~~located along coastal waterways~~were combined with ~~an aggregate storage capacity~~our refined products segment and one terminal was combined with our crude oil segment based on the types of ~~approximately 26 million barrels.~~product stored at the facilities. Accordingly, we have restated our segment disclosures for all previous periods included in this report.

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 Form 8-K filed with the Securities and Exchange Commission on May 4, 2020, which reflects changes in our reporting segments since the filing of our Annual Report on Form 10-K for the year ended December 31, ~~2016~~.2019.

Recent Developments

COVID-19 and Decline in Commodity Prices. This year’s unprecedented events impacting travel and economic activity have significantly reduced demand for refined products in the markets we serve. The related declines in commodity prices have also significantly reduced the value of tender barrels we receive from our transportation customers and the margins we earn from our gas liquids blending activities. The reduction in refined products demand and lower crude oil prices have combined to put significant downward pressure on domestic crude oil production. While we benefit from take-or-pay commitments for the majority of the capacity of our long-haul crude oil pipelines, a sustained reduction in crude oil production could cause delays in the timing of our recognition of revenue from these commitments. These factors have also significantly decreased the creditworthiness of certain of our crude oil transportation customers, resulting in an increased risk of customer defaults. To date, our operations and our employees have successfully adapted to the current environment, enabling our customers to continue benefiting from the services they rely on from our critical infrastructure, and our customers have continued to meet their obligations to us. Given the uncertain timing of a return of refined products demand to historical levels and a recovery in commodity prices, the extent of the impact these events will continue to have on our results of operations is unclear and could be material. However, we do not believe these events will impact our ability to meet any of our financial obligations or result in any significant impairments to our assets.

Cash Distribution. In October ~~2017, the~~2020, our general partner’s board of directors ~~of our general partner~~ declared a quarterly cash distribution of ~~$0.905~~$1.0275 per unit for the period of July 1, ~~2017~~2020 through September 30, ~~2017.~~2020. This quarterly cash distribution will be paid on November ~~14, 2017~~13, 2020 to unitholders of record on November ~~2, 2017. Total distributions expected to be paid under this declaration are approximately $206.4 million.~~

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

6, 2020.

~~Table of Contents~~

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, amortization and ~~amortization~~impairment 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,~~measure but its components of product sales revenue and cost of product sales are determined in accordance with GAAP. Our ~~butane~~gas liquids blending, fractionation and other commodity-related activities generate significant revenue. However, we believe the product margin from these activities, which takes into account the related cost of product sales, better represents its importance to our results of operations.

During first quarter 2020, we revised our reporting segments. See Note 1 – Organization, Description of Business and Basis of Presentation of the consolidated financial statements included in Item 1 of Part I of this report for a discussion of this matter.

~~Table of Contents~~

Three Months Ended September 30, ~~2016~~2019 compared to Three Months Ended September 30, ~~2017~~2020


	Three Months Ended September 30,				Variance Favorable (Unfavorable)
	2019		2020		$ Change		% Change
Financial Highlights ($ in millions, except operating statistics)
Transportation and terminals revenue:
Refined products	$	352.6	$	320.8	$	(31.8)	(9)
Crude oil	155.3		154.6		(0.7)		—
Intersegment eliminations	(1.5)		(1.9)		(0.4)		(27)
Total transportation and terminals revenue	506.4		473.5		(32.9)		(6)
Affiliate management fee revenue	5.3		5.3		—		—
Operating expenses:
Refined products	127.4		118.5		8.9		7
Crude oil	44.9		47.0		(2.1)		(5)
Intersegment eliminations	(3.0)		(3.5)		0.5		17
Total operating expenses	169.3		162.0		7.3		4
Product margin:
Product sales revenue	144.8		119.4		(25.4)		(18)
Cost of product sales	108.7		96.0		12.7		12
Product margin	36.1		23.4		(12.7)		(35)
Other operating income (expense)	(0.4)		(3.0)		(2.6)		(650)
Earnings of non-controlled entities	50.1		39.2		(10.9)		(22)
Operating margin	428.2		376.4		(51.8)		(12)
Depreciation, amortization and impairment expense	56.6		71.8		(15.2)		(27)
G&A expense	51.1		38.0		13.1		26
Operating profit	320.5		266.6		(53.9)		(17)
Interest expense (net of interest income and interest capitalized)	47.3		52.7		(5.4)		(11)
Gain on disposition of assets	(2.6)		—		(2.6)		(100)
Other expense	2.6		1.5		1.1		42
Income before provision for income taxes	273.2		212.4		(60.8)		(22)
Provision for income taxes	0.2		0.8		(0.6)		(300)
Net income	$	273.0	$	211.6	$	(61.4)	(22)
Operating Statistics:
Refined products:
Transportation revenue per barrel shipped	$	1.618	$	1.719
Volume shipped (million barrels):
Gasoline	74.5		71.9
Distillates	47.0		42.5
Aviation fuel	11.1		4.7
Liquefied petroleum gases	3.8		0.1
Total volume shipped	136.4		119.2
Crude oil:
Magellan 100%-owned assets:
Transportation revenue per barrel shipped	$	0.935	$	1.401
Volume shipped (million barrels)(1)	79.2		45.1
Terminal average utilization (million barrels per month)	22.9		25.9
Select joint venture pipelines:
BridgeTex - volume shipped (million barrels)(2)	40.8		30.6
Saddlehorn - volume shipped (million barrels)(3)	17.0		15.1

Three Months Ended September 30,
Variance
Favorable (Unfavorable)
2016 2017 $ Change % Change
Financial Highlights ($ in millions, except operating statistics)
Transportation and terminals revenue:
Refined products $ 267.3
$ 289.0
$ 21.7
8
Crude oil 100.1
116.3
16.2
16
Marine storage 46.2
42.5
(3.7 ) (8)
Intersegment eliminations (0.1 ) (0.8 ) (0.7 ) n/a
Total transportation and terminals revenue 413.5
447.0
33.5
8
Affiliate management fee revenue 5.0
4.9
(0.1 ) (2)
Operating expenses:
Refined products 95.6
118.7
(23.1 ) (24)
Crude oil 24.6
31.2
(6.6 ) (27)
Marine storage 16.3
17.8
(1.5 ) (9)
Intersegment eliminations (1.6 ) (2.3 ) 0.7
44
Total operating expenses 134.9
165.4
(30.5 ) (23)
Product margin:
Product sales revenue 133.3
121.0
(12.3 ) (9)
Cost of product sales 118.2
121.9
(3.7 ) (3)
Product margin 15.1
(0.9 ) (16.0 ) (106)
Earnings of non-controlled entities 18.5
31.2
12.7
69
Operating margin 317.2
316.8
(0.4 ) —
Depreciation and amortization expense 47.0
49.9
(2.9 ) (6)
G&A expense 35.6
37.2
(1.6 ) (4)
Operating profit 234.6
229.7
(4.9 ) (2)
Interest expense (net of interest income and interest capitalized) 42.0
48.3
(6.3 ) (15)
Gain on sale of asset —
(18.5 ) 18.5
n/a
Other expense (income) (2.7 ) 0.5
(3.2 ) n/a
Income before provision for income taxes 195.3
199.4
4.1
2
Provision for income taxes 0.7
0.9
(0.2 ) (29)
Net income $ 194.6
$ 198.5
$ 3.9
2
Operating Statistics:
Refined products:
Transportation revenue per barrel shipped $ 1.503
$ 1.521

Volume shipped (million barrels):
Gasoline 72.7
75.8

Distillates 37.3
41.0

Aviation fuel 7.2
6.7

Liquefied petroleum gases 4.1
3.9

Total volume shipped 121.3
127.4

Crude oil:
Magellan 100%-owned assets:
Transportation revenue per barrel shipped $ 1.189
$ 1.332

Volume shipped (million barrels) 50.7
48.4

Crude oil terminal average utilization (million barrels per month) 14.8
14.9

Select joint venture pipelines:
BridgeTex - volume shipped (million barrels)⁽¹⁾
20.6
25.7

Saddlehorn - volume shipped (million barrels)⁽²⁾
1.2
4.4

Marine storage:
Marine terminal average utilization (million barrels per month) 24.3
22.5

(1) Volume shipped includes shipments related to our crude oil marketing activities. Volume shipped in 2020 reflects a change in the way our customers contract for our services pursuant to which customers are able to utilize crude oil storage capacity at East Houston and dock access at Seabrook. Subsequent to this change, the services we provide no longer include a transportation element. Therefore, revenues related to these services are reflected entirely as terminalling revenues and the related volumes are no longer reflected in our calculation of transportation volumes.

(2) These volumes reflect the total shipments for the BridgeTex pipeline, which is owned ~~50%~~30% by us.

~~(2)~~(3) These volumes reflect the total shipments for the Saddlehorn pipeline, which ~~began operations in September 2016 and is~~was owned 40% by ~~us.~~

us through January 31, 2020 and 30% thereafter.

~~Table of Contents~~

Transportation and terminals revenue ~~increased $33.5~~decreased $32.9 million resulting from:

~~an increase~~•a decrease in refined products revenue of ~~$21.7~~$31.8 million. ~~Shipments increased~~Transportation volumes decreased primarily due to lower demand in the current year associated with the ongoing impact from COVID-19 and related restrictions as well as reduced drilling activity in response to the lower commodity price environment. Revenues also decreased due to the sale of three marine terminals in first quarter 2020 and discontinuation of the ammonia pipeline operations in late 2019. These declines were partially offset by an increase in the average tariff rate in the current period ~~primarily due to stronger demand for refined products~~as well as contributions from the recently-constructed East Houston-to-Hearne pipeline segment that became operational in ~~large part due to higher distillate demand in crude oil production regions~~late 2019 and ~~increased volumes from our Little Rock pipeline extension, which commenced commercial~~the West Texas expansion that began operations in ~~July 2016. Additionally,~~ the ~~current period benefited from~~third quarter of 2020. Average tariff rates increased as a ~~one-time customer payment associated with~~result of the 2020 mid-year adjustment as well as reduced short-haul shipments on the South Texas pipelines, which move at a ~~contract dispute settlement~~lower rate; and ~~higher storage and other ancillary service fees along our pipeline system due to increased customer activity;~~

~~an increase~~•a decrease in crude oil revenue of ~~$16.2 million primarily due to contributions from our new condensate splitter at Corpus Christi that began commercial operations in June 2017. We also benefited from higher volumes~~$0.7 million. Lower third-party spot shipments on our Longhorn pipeline due to less favorable differentials between the Permian Basin and Houston were largely offset by the activities of our marketing affiliate. Average tariff rates increased as ~~shippers utilized historical credits~~a result of lower shipments on our Houston distribution system, which move at a lower rate than longer-haul shipments. Lower transportation volume on our Houston distribution system resulted primarily from a change in the ~~prior year period (earned~~way customers now contract for services at our Seabrook export facility, and was offset by ~~shipping in excess of their minimum commitments in~~incremental revenue from the ~~past) that were set to expire in the third quarter of 2016; and~~

~~a decrease in marine storage revenue of $3.7 million primarily~~related terminal transfer fee. Tender deduction revenues also decreased due to ~~the impact of Hurricane Harvey, which resulted in~~ lower ~~ancillary fees reflecting decreased customer activities and lower storage fees due to delayed project work and some tank damage in third quarter 2017. Otherwise, higher storage rates~~crude oil prices. These declines were partially offset ~~lower utilization during the current period.~~by increased storage revenues as more contract storage was utilized at higher rates.

Operating expenses ~~increased~~decreased by ~~$30.5~~$7.3 million primarily resulting from:

~~an increase~~•a decrease in refined products expenses of ~~$23.1~~$8.9 million primarily due to timing of planned integrity spending as well as no costs in the current period associated with the sold or discontinued assets, partially offset by less favorable product overages (which reduce operating expenses)~~, higher asset integrity spending related to the timing of maintenance work~~; and ~~higher environmental accruals for historical remediation sites;~~

•an increase in crude oil expenses of ~~$6.6~~$2.1 million due to the timing of integrity spending and less favorable product overages.

Product margin decreased $12.7 million primarily due to ~~costs associated with~~recognition of losses on futures contracts in third quarter 2020 compared to gains in 2019, partially offset by higher sales volume related to our ~~new condensate splitter that began commercial operations~~fractionation activities.

Other operating income (expense) was $2.6 million unfavorable primarily due to insurance proceeds received in ~~June 2017 and higher power costs for pipeline movements; and~~third quarter 2019 related to Hurricane Harvey.

~~an increase in marine storage expenses~~Earnings of ~~$1.5~~non-controlled entities decreased $10.9 million primarily due to ~~higher environmental remediation accruals and clean-up work related to Hurricane Harvey, partially offset by more favorable product overages.~~

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

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

~~Earnings of non-controlled entities increased $12.7 million primarily~~ mainly due to ~~increased earnings~~lower volume resulting from ~~BridgeTex mainly attributable to incremental~~less spot shipments ~~(including spot shipments by us; see Note 4 –~~ ~~Investments in Non-Controlled Entities~~ ~~for information about spot shipments that we made~~based on ~~the BridgeTex pipeline in third quarter 2017), as well as additional shipments from BridgeTex’s new Eaglebine origin,~~unfavorable market conditions and ~~higher earnings~~customer use of previously earned credits. We also earned less from Saddlehorn Pipeline Company, LLC (“Saddlehorn”)~~, which began operating during September 2016.~~ due to our reduced ownership interest. These decreases were partially offset by additional earnings from MVP Terminalling, LLC (“MVP”) from the recent start-up of newly-constructed storage and dock assets.

Depreciation, amortization and ~~amortization~~impairment expense increased ~~$2.9~~$15.2 million primarily due to ~~commencement~~the impairment in third quarter 2020 of ~~depreciation of expansion capital projects recently~~certain terminalling assets and more assets placed into service.

G&A expense ~~increased $1.6~~decreased $13.1 million primarily due to ~~higher prospecting costs for potential expansion projects.~~lower incentive compensation accruals to reflect the impacts of COVID-19 related reductions in economic activity and the significant decline in commodity prices.

~~Table of Contents~~

Interest expense, net of interest income and interest capitalized, increased ~~$6.3~~$5.4 million ~~in third quarter 2017,~~ primarily due to lower capitalized interest as a result of lower ongoing construction project spending and higher outstanding debt. Our weighted-average debt outstanding was $4.9 billion in third quarter 2020 compared to $4.6 billion in third quarter 2019. The weighted average interest rate was 4.3% in third quarter 2020 compared to 4.6% in third quarter 2019.

Gain on disposition of assets was $2.6 million unfavorable due to additional gain recorded in third quarter 2019 related to our discontinued Delaware Basin pipeline construction project that was subsequently sold to a third party.

Other expense was $1.1 million favorable due to lower pension-related costs in the current period. Our average outstanding debt increased from $4.0 billion in third quarter 2016 to $4.3 billion in third quarter 2017 primarily due to borrowings for expansion capital expenditures. Our weighted-average interest rate of 4.7% in third quarter 2017 was lower than the 4.9% rate incurred in third quarter 2016.

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

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

~~Table of Contents~~

Nine Months Ended September 30, ~~2016~~2019 compared to Nine Months Ended September 30, ~~2017~~2020


	Nine Months Ended September 30,						Variance Favorable (Unfavorable)					Nine Months Ended September 30,				Variance Favorable (Unfavorable)
	2016			2017			$ Change			% Change		2019		2020		$ Change		% Change
Financial Highlights ($ in millions, except operating statistics)											Financial Highlights ($ in millions, except operating statistics)
Transportation and terminals revenue:											Transportation and terminals revenue:
Refined products	$	739.9		$	808.8		$	68.9		9	Refined products	$	1,009.8	$	914.9	$	(94.9)	(9)
Crude oil	303.2			329.8			26.6			9	Crude oil	467.6		433.9		(33.7)		(7)
Marine storage	132.8			136.7			3.9			3
Intersegment eliminations	(0.1		)	(2.4		)	(2.3		)	n/a	Intersegment eliminations	(3.8)		(5.1)		(1.3)		(34)
Total transportation and terminals revenue	1,175.8			1,272.9			97.1			8	Total transportation and terminals revenue	1,473.6		1,343.7		(129.9)		(9)
Affiliate management fee revenue	11.1			12.9			1.8			16	Affiliate management fee revenue	15.8		15.9		0.1		1
Operating expenses:											Operating expenses:
Refined products	279.9			312.9			(33.0		)	(12)	Refined products	362.9		327.8		35.1		10
Crude oil	66.2			90.0			(23.8		)	(36)	Crude oil	129.4		139.7		(10.3)		(8)
Marine storage	49.8			45.8			4.0			8
Intersegment eliminations	(3.9		)	(6.4		)	2.5			64	Intersegment eliminations	(8.0)		(9.9)		1.9		24
Total operating expenses	392.0			442.3			(50.3		)	(13)	Total operating expenses	484.3		457.6		26.7		6
Product margin:											Product margin:
Product sales revenue	403.6			548.6			145.0			36	Product sales revenue	497.8		481.8		(16.0)		(3)
Cost of product sales	327.5			440.7			(113.2		)	(35)	Cost of product sales	430.7		395.8		34.9		8
Product margin	76.1			107.9			31.8			42	Product margin	67.1		86.0		18.9		28
Other operating income (expense)											Other operating income (expense)	1.5		0.5		(1.0)		(67)
Earnings of non-controlled entities	51.5			78.2			26.7			52	Earnings of non-controlled entities	122.2		116.5		(5.7)		(5)
Operating margin	922.5			1,029.6			107.1			12	Operating margin	1,195.9		1,105.0		(90.9)		(8)
Depreciation and amortization expense	134.1			146.1			(12.0		)	(9)
Depreciation, amortization and impairment expense											Depreciation, amortization and impairment expense	181.0		193.9		(12.9)		(7)
G&A expense	110.8			120.9			(10.1		)	(9)	G&A expense	149.5		117.0		32.5		22
Operating profit	677.6			762.6			85.0			13	Operating profit	865.4		794.1		(71.3)		(8)
Interest expense (net of interest income and interest capitalized)	120.4			143.1			(22.7		)	(19)	Interest expense (net of interest income and interest capitalized)	148.3		168.0		(19.7)		(13)
Gain on sale of asset	—			(18.5		)	18.5			n/a
Gain on exchange of interest in non-controlled entity	(28.1		)	—			(28.1		)	(100)
Other expense (income)	(6.5		)	3.7			(10.2		)	n/a
Gain on disposition of assets											Gain on disposition of assets	(29.0)		(12.9)		(16.1)		(56)
Other expense											Other expense	9.2		3.8		5.4		59
Income before provision for income taxes	591.8			634.3			42.5			7	Income before provision for income taxes	736.9		635.2		(101.7)		(14)
Provision for income taxes	2.3			2.7			(0.4		)	(17)	Provision for income taxes	2.5		2.2		0.3		12
Net income	$	589.5		$	631.6		$	42.1		7	Net income	$	734.4	$	633.0	$	(101.4)	(14)
Operating Statistics:											Operating Statistics:
Refined products:											Refined products:
Transportation revenue per barrel shipped	$	1.451		$	1.489						Transportation revenue per barrel shipped	$	1.600	$	1.658
Volume shipped (million barrels):											Volume shipped (million barrels):
Gasoline	204.9			218.7							Gasoline	207.4		199.4
Distillates	110.0			119.6							Distillates	138.8		127.6
Aviation fuel	19.6			20.2							Aviation fuel	29.8		16.8
Liquefied petroleum gases	9.9			9.6							Liquefied petroleum gases	8.9		0.5
Total volume shipped	344.4			368.1							Total volume shipped	384.9		344.3
Crude oil:											Crude oil:
Magellan 100%-owned assets:											Magellan 100%-owned assets:
Transportation revenue per barrel shipped	$	1.325		$	1.412						Transportation revenue per barrel shipped	$	0.952	$	1.145
Volume shipped (million barrels)	139.5			137.0
Crude oil terminal average utilization (million barrels per month)	14.7			15.5
Volume shipped (million barrels)(1)											Volume shipped (million barrels)(1)	239.1		167.9
Terminal average utilization (million barrels per month)											Terminal average utilization (million barrels per month)	22.7		24.7
Select joint venture pipelines:											Select joint venture pipelines:
BridgeTex - volume shipped (million barrels)⁽¹⁾	58.7			66.4
Saddlehorn - volume shipped (million barrels)⁽²⁾	1.2			12.1
Marine storage:
Marine terminal average utilization (million barrels per month)	23.6			23.4
BridgeTex - volume shipped (million barrels)(2)											BridgeTex - volume shipped (million barrels)(2)	117.3		99.9
Saddlehorn - volume shipped (million barrels)(3)											Saddlehorn - volume shipped (million barrels)(3)	39.4		46.5

(2) These volumes reflect the total shipments for the BridgeTex pipeline, which is owned ~~50%~~30% by us.

~~(2)~~(3) These volumes reflect the total shipments for the Saddlehorn pipeline, which ~~began operations in September 2016 and is~~was owned 40% by ~~us.~~

us through January 31, 2020 and 30% thereafter.

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Transportation and terminals revenue ~~increased $97.1~~decreased $129.9 million resulting from:

~~an increase~~•a decrease in refined products revenue of ~~$68.9~~$94.9 million. ~~Shipments increased~~Transportation volumes decreased primarily due to lower demand during 2020 associated with the ongoing impact from COVID-19 and related restrictions as well as reduced drilling activity in response to the lower commodity price environment. Revenues also decreased due to the sale of three marine terminals in first quarter 2020 and discontinuation of the ammonia pipeline operations in late 2019. These declines were partially offset by an increase in the average tariff rate in the current period as a result of the 2019 and 2020 mid-year adjustments, as well as contributions from the recently-constructed East Houston-to-Hearne pipeline segment that became operational in late 2019 and the West Texas expansion that began operations in the third quarter of 2020; and

•a decrease in crude oil revenue of $33.7 million. Lower third-party spot shipments on our Longhorn pipeline due to less favorable differentials between the Permian Basin and Houston were partially offset by the activities of our marketing affiliate. Average tariff rates increased as a result of lower shipments on our Houston distribution system, which move at a lower rate than longer-haul shipments. Lower transportation volume on our Houston distribution system resulted primarily from a change in the way customers now contract for services at our Seabrook export facility, and was offset by incremental revenue from the related terminal transfer fee. Tender deduction revenues also decreased due to lower crude oil prices. These declines were partially offset by increased storage revenues as more contract storage was utilized at higher rates.

Operating expenses decreased by $26.7 million primarily resulting from:

•a decrease in refined products expenses of $35.1 million primarily due to ~~increased volumes from our Little Rock pipeline extension, which commenced commercial operations in July 2016, and stronger demand for refined products. The average rate per barrel~~timing of planned integrity spending as well as no costs in the current period ~~was favorably impacted by the mid-year 2016 and 2017 tariff adjustments. Additionally, the current period benefited from a one-time customer payment~~ associated with ~~a contract dispute settlement~~the sold or discontinued assets, partially offset by less favorable product overages; and ~~higher storage and other ancillary service fees along our pipeline system due to increased customer activity;~~

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

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

~~Operating expenses increased by $50.3 million primarily resulting from:~~

~~an increase in refined products~~ expenses of ~~$33.0~~$10.3 million ~~primarily~~ due ~~to higher asset integrity spending related~~ to the timing of ~~maintenance work, rental costs for a pipeline segment we began leasing in third quarter 2016 in connection with our Little Rock pipeline, higher compensation costs~~integrity spending and less favorable product ~~overages (which reduce operating expenses), partially offset by favorable property taxes;~~


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

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

Product margin increased ~~$31.8~~$18.9 million primarily due to recognition of gains on futures contracts in the current ~~year~~period compared to losses in ~~the prior year,~~2019, partially offset by lower gas liquids blending margins driven by lower sales volumes and lower commodity prices and unfavorable lower-of-cost-or-net-realizable-value adjustments during 2020 due to the significant decrease in commodity prices.

Other operating income (expense) was $1.0 million unfavorable in 2020 primarily due to insurance settlements received in 2019 related to Hurricane Harvey, partially offset by less losses recognized on ~~product sales. See~~ ~~Other Items—Commodity Derivative Agreements—Impact of Commodity Derivatives on Results of Operations~~ ~~below for more information about our futures contracts.~~a basis derivative agreement during the current period.

Earnings of non-controlled entities ~~increased $26.7~~decreased $5.7 million primarily due to ~~earnings from Saddlehorn, which began operating during third quarter 2016. Additionally,~~lower earnings from BridgeTex ~~were higher mainly attributable to incremental spot shipments (including spot shipments~~and Saddlehorn in 2020, partially offset by ~~us; see Note 4 -~~ ~~Investments in Non-Controlled Entities~~ ~~for information about spot shipments that we made on~~additional earnings from MVP from the ~~BridgeTex pipeline), as well as additional shipments~~recent start-up of newly-constructed storage and dock assets and increased earnings from ~~BridgeTex’s new Eaglebine origin.~~Powder Springs Logistics, LLC (“Powder Springs”).

Depreciation, amortization and ~~amortization~~impairment expense increased ~~$12.0~~$12.9 million primarily due to ~~commencement~~the impairment of ~~depreciation of expansion capital projects recently~~certain terminalling assets in 2020 and more assets placed into service.

G&A expense ~~increased $10.1~~decreased $32.5 million primarily due to ~~higher~~lower incentive compensation ~~costs resulting from an increase~~accruals to reflect the impacts of COVID-19 related reductions in ~~employee headcount mainly as a result of expansion projects, as well as higher prospecting costs.~~economic activity and the significant decline in commodity prices.

Interest expense, net of interest income and interest capitalized, increased ~~$22.7~~$19.7 million ~~in 2017,~~ primarily due to higher outstanding debt and higher costs associated with early debt retirement, as well as lower capitalized interest (due to lower ongoing construction project spending in ~~the current period.~~2020). Our average outstanding debt increased from ~~$3.8~~$4.5 billion in ~~2016~~2019 to ~~$4.2~~$4.9 billion in ~~2017 primarily due to borrowings for expansion capital expenditures.~~2020. Our weighted-average interest rate decreased from 4.6% in 2019 to 4.5% in 2020.

Gain on disposition of ~~4.7% in 2017~~assets was ~~lower than the 4.9% rate incurred in 2016.~~

$16.1 million unfavorable. In ~~2017,~~2020, we recognized ~~an $18.5~~a gain on the sale of a portion of our interest in Saddlehorn of $12.9 million. In 2019, we recognized a deferred gain of $11.0 million related to the 2018 sale of a portion of our investment in BridgeTex, a gain ~~in connection with~~of $12.7 million related to our discontinued Delaware Basin crude oil pipeline construction project that was sold to a third party and a gain of $5.3 million resulting from the sale of an inactive terminal ~~in Chicago, Illinois.~~along our refined products pipeline system.

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

Other expense ~~(income)~~ was ~~$10.2~~$5.4 million ~~unfavorable~~favorable due to ~~higher pension related~~lower pension-related costs in the current period, including higher pension settlements, and a less favorable non-cash adjustment in 2017 for the change in the differential between the current spot price and forward price on fair value hedges associated with our crude oil tank bottoms. Additionally, the 2016 period benefited from a break-up fee related to a potential acquisition.period.

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Distributable Cash Flow

We calculate the non-GAAP measures of distributable cash flow (“DCF”) and adjusted EBITDA in the table below. Management uses DCF as a basis for recommending to our general partner’s board of directors the amount of cash distributions to be paid to our ~~limited partners~~common unitholders each period. Management also uses DCF as a basis for determining the payouts for the performance-based awards issued under our equity-based compensation plan. Adjusted EBITDA is an important measure that we and the investment community use to assess the financial results of an entity. We believe that investors benefit from having access to the same financial measures utilized by management for these evaluations. A reconciliation of DCF and adjusted EBITDA for the nine months ended September 30, ~~2016~~2019 and ~~2017~~2020 to net income, which is its nearest comparable GAAP financial measure, follows (in millions):


	Nine Months Ended September 30,				Increase (Decrease)
	2019		2020
Net income	$	734.4	$	633.0	$	(101.4)
Interest expense, net	148.3		168.0		19.7
Depreciation, amortization and impairment(1)	176.9		193.4		16.5
Equity-based incentive compensation(2)	12.8		(9.1)		(21.9)

Gain on disposition of assets(3)	(16.3)		(10.5)		5.8

Commodity-related adjustments:
Derivative (gains) losses recognized in the period associated with future transactions(4)	13.7		6.7		(7.0)
Derivative gains (losses) recognized in previous periods associated with transactions completed in the period(4)	71.2		(18.9)		(90.1)
Inventory valuation adjustments(5)	(9.7)		9.5		19.2
Total commodity-related adjustments	75.2		(2.7)		(77.9)
Distributions from operations of non-controlled entities in excess of earnings	15.9		36.2		20.3

Adjusted EBITDA	1,147.2		1,008.3		(138.9)
Interest expense, net, excluding debt issuance cost amortization(6)	(137.5)		(152.3)		(14.8)
Maintenance capital(7)	(70.1)		(81.2)		(11.1)
DCF	$	939.6	$	774.8	$	(164.8)

(1) Depreciation, amortization and impairment expense is excluded from DCF to the extent it represents a non-cash expense.

(2) Because we intend to satisfy vesting of unit awards under our equity-based long-term incentive compensation plan with the issuance of common units, expenses related to this plan generally are deemed non-cash and added back for DCF purposes. The amounts above have been reduced by cash payments associated with the plan, which are primarily related to tax withholdings.

(3) Gains on disposition of assets are excluded from DCF to the extent they are not related to our ongoing operations.

(4) Certain derivatives have not been designated as hedges for accounting purposes and the mark-to-market changes of these derivatives are recognized currently in net income. We exclude the net impact of these derivatives from our determination of DCF until the

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

~~(1)~~

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


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

~~(3)~~

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

~~Table~~

transactions are settled and, where applicable, the related products are sold. In the period in which these transactions are settled and any related products are sold, the net impact of ~~Contents~~the derivatives is included in DCF.

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


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

~~(5)~~

Certain derivatives we use as economic hedges have not been designated as hedges for accounting purposes and the mark-to-market changes of these derivatives are recognized currently in earnings. In addition, we have designated certain derivatives we use to hedge our crude oil tank bottoms as fair value hedges and the change in the differential between the current spot price and forward price on these hedges is recognized currently in earnings. We exclude the net impact of both of these adjustments from our determination of DCF until the hedged products are physically sold. In the period in which these hedged products are physically sold, the net impact of the associated hedges is included in our determination of DCF.


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


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


~~(8)~~	Maintenance capital expenditures maintain our existing assets and do not generate incremental DCF (i.e. incremental returns to our unitholders). For this reason, we deduct maintenance capital expenditures to determine DCF.

(6) Interest expense includes $8.3 million of debt prepayment costs in 2019 and $12.9 million in 2020, which are excluded from DCF as they are financing activities and not related to our ongoing operations.

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

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

Operating Activities. ~~Operating cash flows consist of net income adjusted for certain non-cash items and changes in certain assets and liabilities.~~

Net cash provided by operating activities was ~~$639.0~~$922.6 million and ~~$794.6~~$840.1 million for the nine months ended September 30, ~~2016~~ 2019 and ~~2017,~~2020, respectively. The ~~$155.6~~$82.5 million ~~increase~~ decrease in ~~2017~~2020 was due to ~~changes in our working capital, higher~~lower net income as previously described and changes in our working capital, partially offset by adjustments for non-cash ~~items.~~items and distributions in excess of earnings of our non-controlled entities.

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

Net cash used by investing activities for the nine months ended September 30, ~~2016~~2019 and ~~2017~~2020 was ~~$682.1~~$734.7 million and ~~$416.1~~$110.3 million, respectively. During ~~2017,~~the 2020 period, we ~~incurred $443.4~~used $371.2 million for capital expenditures, which included ~~$71.8~~$0.2 million for ~~maintenance capital and $371.6 million~~undivided joint interest projects for ~~expansion capital.~~which cash was received from a third party. Also, during ~~the 2017 period,~~2020, we sold three marine terminals for cash proceeds of $251.8 million and sold a portion of our interest in Saddlehorn for cash proceeds of $79.9 million. Additionally, we contributed capital of ~~$114.1~~$73.7 million in conjunction with our joint venture capital projects, which we account for as investments in non-controlled entities. During ~~2016,~~the 2019 period, we ~~incurred $514.2~~used $718.6 million for capital expenditures, which included ~~$86.1~~$87.9 million for ~~maintenance capital and $428.1 million~~undivided joint interest projects for ~~expansion capital. Also during the 2016 period,~~which cash was received from a third party. Additionally, we contributed net capital of ~~$174.9~~$150.6 million in conjunction with our joint ~~venture~~ventures, of which $145.6 million related to capital projects.

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

Net ~~cash provided by financing activities for the nine months ended September 30, 2016 was $305.5 million, and net~~ cash used by financing activities for the nine months ended September 30, ~~2017~~2019 and 2020 was ~~$391.7 million.~~$305.6 million and $794.1 million, respectively. During ~~2017,~~the 2020 period, we ~~have~~ paid cash distributions of ~~$596.9~~$697.3 million to our ~~unitholders.~~unitholders and made common unit repurchases of $252.0 million. Additionally, we received net proceeds of $499.4 million from the issuance of long-term senior notes and had net commercial paper borrowings ~~during the 2017 period~~of $248.0 million, which were ~~$219.0 million.~~used to repay our $550.0 million of 4.25% notes due 2021. Also, in January ~~2017, the cumulative amounts of the 2014~~2020, our equity-based incentive compensation awards that vested December 31, 2019 were settled by issuing ~~216,679 limited partner~~284,643 common units and distributing those units to the long-term incentive plan (“LTIP”) participants, resulting in payments primarily associated with tax withholdings of ~~$13.9~~$14.7 million. During ~~2016,~~the 2019 period, we paid cash distributions of ~~$548.4~~$688.6 million to our unitholders. Additionally, we received net proceeds of ~~$1.1 billion~~$996.4 million from borrowings under long-term notes, which were used ~~in part~~ to repay our $550.0 million of 6.55% notes due 2019 and outstanding commercial borrowings outstanding under our commercial paper program and for general partnership purposes, including expansion capital. Net commercial paper repayments during 2016 totaled $245.0 million. In connection with certain of the borrowings under long-term notes, we paid $19.3 million in settlement of associated interest rate swap agreements.at that time. Also, in ~~February 2016, the cumulative amounts of the 2013~~January 2019, our equity-based incentive compensation

~~Table of Contents~~

awards that vested December 31, 2018 were settled by issuing ~~350,552 limited partner~~208,268 common units and distributing those units to the LTIP participants, resulting in payments ofprimarily associated with tax withholdings of ~~$14.4~~$9.8 million.

The quarterly distribution amount related to our ~~third quarter 2017~~third-quarter 2020 financial results (to be paid in fourth quarter ~~2017)~~2020) is ~~$0.905~~$1.0275 per unit. If we ~~are able~~were to ~~meet management’s targeted distribution growth of 8% for 2017 and~~continue paying cash distributions at this level on the number of ~~outstanding limited partner~~common units ~~remains at 228.0 million,~~currently outstanding, total cash distributions of approximately ~~$818~~$922 million ~~will~~would be paid to our unitholders related to ~~2017~~2020 earnings. Management believes we will have sufficient DCF to fund these distributions.

During 2020, we initiated our common unit repurchase program, with authorization to repurchase up to $750 million of our common units through 2022. During the nine months ended September 30, 2020, we repurchased 5.0 million of our common units for $252 million. The timing, price and actual number of common units repurchased will depend on a number of factors including our expected expansion capital spending needs, excess cash available,

balance sheet metrics, legal and regulatory requirements, market conditions and the trading price of our common units.

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 and to construct new assets, which we refer to collectively as organic growth projects. Organic growth projects include, for example, capital expenditures that increase storage or throughput volumes or develop pipeline connections to new supply sources.

For the nine months ended September 30, ~~2017,~~ 2020, our maintenance capital spending was ~~$71.8 million~~.$81.2 million. For ~~2017,~~2020, we expect to spend approximately $95 million on maintenance capital.

During the first nine months of ~~2017,~~2020, we spent ~~$371.6~~$236.3 million for ~~organic growth~~our expansion capital projects and contributed ~~$114.1~~$73.7 million for expansion capital projects in conjunction with our joint ventures. Based on the progress of expansion projects already underway, we expect to spend approximately ~~$600 million for expansion capital during 2017, with an additional $800~~$400 million in ~~2018~~2020 and ~~$350~~$40 million in ~~2019~~2021 to complete our current ~~projects, including our recently-announced projects (see Other Items, below).~~projects.

Liquidity

Cash generated from operations is ~~our primary~~a key source of liquidity for funding debt service, maintenance capital expenditures, ~~and~~ quarterly distributions ~~to our unitholders.~~and unit repurchases. Additional liquidity for purposes other than quarterly distributions, such as expansion capital expenditures and debt repayments, is available through borrowings under our commercial paper program and revolving credit facility, as well as from other borrowings or issuances of debt or ~~limited partner~~common units (see Note 76 – Debt and Note 1114 – Partners’ Capital and Distributions of the consolidated financial statements included in Item 1 of Part I of this report for detail of our borrowings and changes in partners’ capital). If capital markets do not ~~permit~~provide us access to capital or the ability to issue additional debt ~~and~~or equity securities on acceptable terms, 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~~Other Items

~~Our operations~~Pipeline Tariff Changes. The Federal Energy Regulatory Commission (“FERC”) regulates the rates charged on our interstate common carrier pipelines. We increased our rates by approximately 2.0% in the 40% of our refined products markets that are subject to ~~federal, state and local environmental laws and regulations. We have accrued liabilities~~the FERC’s index methodology on July 1, 2020. In the 60% of our remaining refined products markets, we increased our rates by an average of nearly 4.5%, for ~~estimated costs~~an overall average refined products rate increase of 3.5%. Most of the tariffs on our crude oil pipelines are established at negotiated rates that generally provide for annual adjustments in line with changes in the FERC index, subject to certain modifications. As a result, we also increased the rates on the majority of 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 assumptionscrude oil pipelines by ~~management. Due to the inherent uncertainties involved~~approximately 2.0% 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.~~July 2020.

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~~Other Items~~

~~Pasadena Marine Terminal Joint Venture.~~ ~~MVP Terminalling, LLC~~The FERC-approved indexing method for the past five years has been the annual change in the producer price index for finished goods plus 1.23%. In June 2020, the FERC issued a Notice of Inquiry (“~~MVP”~~NOI”) ~~was formed in September 2017~~ to ~~construct and develop~~initiate a refined products marine storage facility along the Houston Ship Channel in Pasadena, Texas. The facility will initially include five million barrels of storage, truck loading facilities and two proprietary ship docks. We own a 50% equity interest in MVP, with an affiliate of Valero Energy Corporation (“Valero”) owning the other 50% interest. We serve as construction manager and operatorreview of the ~~MVP facility. A portion of this facility is expected~~rate index to be ~~operational in early 2019, with~~utilized over the ~~remainder expected to be operational in early 2020.~~next five-year period beginning July 1, 2021. The ~~project is estimated to cost approximately $820 million, which will be funded equally by capital contributions from us and Valero.~~

~~East Houston to Hearne, TX Pipeline.~~ In September 2017, we announced plans to expand our refined products pipeline system to handle incremental demand for transportation of gasoline, diesel fuel and jet fuel to central and north Texas markets. Supported by long-term customer commitments, we plan to build an approximately 135-mile pipeline from our terminal in East Houston to Hearne, Texas. We and Valero will each own an undivided joint interestFERC’sproposal in the ~~pipeline, and we will be~~NOI preliminarily recommends the ~~construction manager and operator. In addition, we are making related enhancements to our existing pipeline and terminal infrastructure to handle the incremental volume. Our share~~use of the ~~project is estimated to cost approximately $375 million, with~~producer price index for finished goods plus 0.09% as the new ~~pipeline capacity expected~~index level to ~~be operational in mid-2019.~~

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

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

Commodity Derivative Agreements. Certain of ~~the~~our business activities ~~in which we engage~~ result in our owning various commodities, which exposes us to commodity price risk. We generally use forward physical commodity contracts and exchange-based futures contracts to help manage this commodity price risk. We use forward physical contracts to purchase butane and sell refined products. We account for these forward physical contracts as normal purchase and sale contracts, using traditional accrual accounting. We useexchange-traded futures contracts to hedge against changes in prices of ~~refined products and crude oil~~the commodities that we expect to sell ~~and of butane that we expect to~~or purchase in future periods. We ~~use and account~~also entered into a basis derivative agreement for those futures contracts that qualify for hedge accounting treatment as either cash flow or fair value hedges, and we use and account for those futures contracts that do not qualify for hedge accounting treatment as economic hedges.

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

For further information regarding the quantities of refined products and crude oil hedged at September 30, ~~2017~~2020 and the fair value of open hedge contracts at that date, please see Item 3. Quantitative and Qualitative Disclosures about Market Risk.

~~Table of Contents~~

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

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

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

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


~~ITEM 3.~~	~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~

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~~mitigate 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~~gas liquids blending and fractionation activities, and from managing product overages and shortages associated with our refined products and crude oil ~~pipelines.~~pipelines and terminals. We generally use derivatives such as forward physical contracts and exchange-traded futures contracts to help us manage our commodity price risk.

Forward physical contracts that qualify for and are elected as normal purchases and sales are accounted for using traditional accrual accounting. As of September 30, ~~2017,~~2020, we had commitments under forward purchase and sale contracts as follows (in millions):


	Total		2020		2021-2022
Forward purchase contracts – notional value	$	53.5	$	30.1	$	23.4
Forward purchase contracts – barrels	1.4		0.8		0.6
Forward sales contracts – notional value	$	19.5	$	18.4	$	1.1
Forward sales contracts – barrels	0.4		0.4		—

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

We ~~also~~generally use exchange-traded futures contracts to hedge against changes in the price of the petroleum products we expect to sell or purchase. At September 30, 2017, the fair value of our open futures contracts, representing 5.5 million barrels of petroleum products we expect to sell and 2.1 million barrels of butane we expect to purchase, was a net liability of $13.7 million. These contractsWe did not ~~qualify for~~elect hedge accounting treatment under ASC 815, Derivatives and Hedging, for our open contracts and as a result we accounted for these contracts as economic hedges, with changes in fair value recognized currently in earnings. The fair value of these open futures contracts, representing 3.1 million barrels of petroleum products we expect to sell and 0.6 million barrels of gas liquids we expect to purchase, was a net liability of $1.6 million. With respect to these contracts, a $10.00 per barrel increase (decrease) in the prices of petroleum products we expect to sell would result in a ~~$55.0~~$31.0 million decrease (increase) in our operating profit, while a $10.00 per barrel increase (decrease) in the price of ~~butane~~gas liquids we expect to purchase

would result in ~~$21.0~~a $6.0 million increase (decrease) in our operating profit. These increases or decreases in operating profit would be substantially offset by higher or lower product sales revenue or cost of product sales when the physical sale or purchase of those products occurs. These contracts may be for the purchase or sale of products in markets different from those in which we are attempting to hedge our exposure, and the resulting hedges may not eliminate all price risks.

During 2019, we entered into a basis derivative agreement with a joint venture co-owner’s affiliate, and, contemporaneously, that affiliate entered into an intrastate transportation services agreement with the joint venture. Settlements under the basis derivative agreement are determined based on the basis differential of crude oil prices at different market locations and a notional volume of 30,000 barrels per day. As a result, we are exposed to the differential in the forward price curves for crude oil in West Texas and the Houston Gulf Coast. With respect to this agreement, a $0.50 per barrel increase (decrease) in the differential would result in an approximately $2.0 million increase (decrease) in our operating profit.

Interest Rate Risk

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

~~We entered into $100.0 million~~ As of forward-starting interest rate swap agreements during 2016 to hedge against the risk of variability of future interest payments on a portion of debt we anticipate issuing in 2018. The fair value of these contracts at September 30, 2017 was a net asset of $12.4 million. We account for these agreements as cash flow hedges. A 0.125% decrease in interest rates would result in a decrease in the fair value of this asset of approximately $2.1 million. A 0.125% increase in interest rates would result in an increase in the fair value of approximately $2.0 million.2020, we did not have any variable rate debt outstanding.


~~ITEM 4.~~	~~CONTROLS AND PROCEDURES~~

ITEM 4.CONTROLS AND PROCEDURES

We performed an evaluation of the effectiveness of the design and operation of our ~~disclosure~~“disclosure controls and ~~procedures~~procedures” (as defined in ~~rule 13a-14(c) of~~Rule 13a-15(e) and 15d-15(e) under the Securities Exchange ~~Act)~~Act of 1934, as amended (the “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 (“CEO”) and Chief Financial ~~Officer.~~Officer (“CFO”). Based upon that evaluation, our general partner’s ~~Chief Executive Officer~~CEO and ~~Chief Financial Officer~~CFO concluded that, ~~these~~as of the end of the period covered by this report, our disclosure controls and ~~practices are~~procedures were effective ~~in providing~~to provide 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 in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed so that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to ~~our Chief Executive Officer~~management, including the CEO and ~~Chief Financial Officer~~the CFO, as appropriate, to allow timely decisions regarding required ~~disclosures.~~disclosure. There has been no change in our internal control over financial reporting ~~(as defined in Rule 13a-15(f) of the Securities Exchange Act)~~that occurred during the quarter ended September 30, ~~2017~~2020 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

~~Table of Contents~~

~~Forward-Looking Statements~~

Certain matters discussed in this Quarterly Report on Form 10-Q include forward-looking statements within the meaning of the federal securities laws that discuss our expected future results based on current and pending business operations. Forward-looking statements can be identified by words such as “anticipates,” “believes,” “continue,” “could,” “estimates,” “expects,” “forecasts,” “goal,” “guidance,” “intends,” “may,” “might,” “plans,” “potential,” “projected,” “scheduled,” “should,” “will” and other similar expressions. Although we believe our forward-looking statements are based on reasonable assumptions, statements made regarding future results are not guarantees of future performance and are subject to numerous assumptions, uncertainties and risks that are difficult to predict. Therefore, actual outcomes and results may be materially different from the results stated or implied in such forward-looking statements included in this report.

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

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

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

~~changes in the production of crude oil in the basins served by our pipelines;~~

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

~~changes in the financial condition of our customers, vendors, derivatives counterparties, lenders or joint venture co-owners;~~

our ability to secure financing in the credit and capital markets in amounts and on terms that will allow us to execute our growth strategy, refinance our existing obligations when due and maintain adequate liquidity;

development of alternative energy sources, including but not limited to natural gas, solar power, wind power, electric and battery-powered engines and geothermal energy, increased use of biofuels such as ethanol and biodiesel, increased conservation or fuel efficiency, increased use of electric vehicles, as well as regulatory developments or other trends that could affect demand for our services;

~~changes in the throughput or interruption in service of refined products or crude oil pipelines owned and operated by third parties and connected to our assets;~~

~~changes in demand for storage in our refined products, crude oil or marine terminals;~~

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

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

~~changes in our tariff rates or other terms of service implemented by the Federal Energy Regulatory Commission, the U.S. Surface Transportation Board or state regulatory agencies;~~

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

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

~~an increase in the competition our operations encounter;~~

~~the occurrence of natural disasters, terrorism, protests or political activism, operational hazards, equipment failures, system failures or unforeseen interruptions;~~

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

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

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

~~Table of Contents~~

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

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

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

~~actions by rating agencies concerning our credit ratings;~~

~~our ability to timely obtain and maintain all necessary approvals, consents and permits required to operate our existing assets and to construct, acquire and operate any new or modified assets;~~

our ability to promptly obtain all necessary services, materials, labor, supplies and rights-of-way required for construction of our growth projects, and to complete construction without significant delays, disputes or cost overruns;

~~risks inherent in the use and security of information systems in our business and implementation of new software and hardware;~~

changes in laws and regulations that govern product quality specifications or renewable fuel obligations that could impact our ability to produce gasoline volumes through our butane blending activities or that could require significant capital outlays for compliance;

changes in laws and regulations to which we or our customers are or could become subject, including tax withholding requirements, safety, security, employment, hydraulic fracturing, derivatives transactions, trade and environmental laws and regulations, including laws and regulations designed to address climate change;

~~the cost and effects of legal and administrative claims and proceedings against us or our subsidiaries;~~

the amount of our indebtedness, which could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, place us at competitive disadvantages compared to our competitors that have less debt or have other adverse consequences;

~~the effect of changes in accounting policies;~~

~~the potential that our internal controls may not be adequate, weaknesses may be discovered or remediation of any identified weaknesses may not be successful;~~

~~the ability and intent of our customers, vendors, lenders, joint venture co-owners or other third parties to perform on their contractual obligations to us;~~

~~petroleum product supply disruptions;~~

~~global and domestic repercussions from terrorist activities, including cyber attacks, and the government’s response thereto; and~~

other factors and uncertainties inherent in the transportation, storage and distribution of petroleum products and ammonia, and the operation, acquisition and construction of assets related to such activities.

This list of important factors is not exclusive. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changes in assumptions or otherwise.

~~Table of Contents~~

PART II

OTHER INFORMATION


~~ITEM 1.~~	~~LEGAL PROCEEDINGS~~

ITEM 1.LEGAL PROCEEDINGS

~~Anhydrous Ammonia Event~~.

Butane Blending Patent Infringement Proceeding.On October ~~17, 2016, we experienced~~4, 2017, Sunoco Partners Marketing & Terminals L.P. (“Sunoco”) brought an action for patent infringement in the U.S. District Court for the District of Delaware alleging Magellan Midstream Partners, L.P. (“Magellan”) and Powder Springs Logistics, LLC (“Powder Springs”) are infringing patents related to butane blending at the Powder Springs facility located in Powder Springs, Georgia. Sunoco subsequently submitted pleadings alleging that Magellan is also infringing various patents related to butane blending at nine Magellan facilities, in addition to Powder Springs. Sunoco is seeking monetary damages, attorneys’ fees and a ~~release of anhydrous ammonia on our ammonia pipeline system near Tekamah, Nebraska. The release resulted in a fatality~~permanent injunction enjoining Magellan and ~~other~~Powder Springs from infringing the subject patents. We deny and are vigorously defending against all claims asserted by Sunoco. Although it is not possible ~~injuries. The National Transportation Safety Board is investigating~~to predict the ~~event. We are currently unable to estimate the full impact of this event. However,~~ultimate outcome, we believe the ultimate resolution of this matter will not have a material adverse impact on our ~~financial position and~~ results of operations, isfinancial position or cash flows.

New Tank Construction Proceeding. In May 2020, we received a Notice of Probable Violation and Proposed Civil Penalty from the Pipeline and Hazardous Materials Safety Administration alleging a violation related to a new tank construction project and associated release of product at our terminal in Cushing, Oklahoma. The matter was resolved in September 2020 for approximately $125,000.

Valves and Overfill Protection Systems Proceeding. In October 2019, we received a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order from the Pipeline and Hazardous Materials Safety Administration alleging violations related to the records and maps necessary for the safe operation of remotely controlled valves at two facilities and the failure to inspect the overfill protection system on four breakout tanks at our terminal in Des Moines, Iowa. The penalties associated with these alleged violations could exceed $100,000. While the results cannot be predicted with certainty, we believe the ultimate resolution of this matter will not ~~likely to~~have a material impact on our results of operations, financial position or cash flows.

Hurricane Harvey Enforcement Proceeding. In July 2018, we received a Notice of Enforcement letter from the Texas Commission on Environmental Quality alleging two air emission violations at our Galena Park, Texas terminal that occurred during Hurricane Harvey in third quarter 2017. The penalties associated with these alleged violations could exceed $100,000. While the results cannot be predicted with certainty, we believe the ultimate resolution of this matter will not have a material ~~as defined by the SEC.~~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~~approximately $42,000 associated with the assessment phase. Until this assessment phase has been completed, we cannot reasonably estimate our proportionate share of the remediation costs associated with this site. While the results cannot be reasonably estimated, we believe the ultimate resolution of this matter will not have a material impact on our results of operations, financial position or cash flows.

Lake Calumet Cluster Site, EPA ID No.: ILD000716852 Superfund Site. We have liability at the Lake Calumet Cluster Superfund Site in Chicago, Illinois as a PRP under Sections 107(a) and 113(f)(1) of CERCLA. As a result of the EPA’s Administrative Settlement Agreement and Order for Remedial Investigation/Feasibility Study of June 2013, we voluntarily entered into the PRP group responsible for the investigation, cleanup and installation of an appropriate clay cap over the site. We have paid ~~$8,000~~approximately $9,000 associated with the Remedial

Investigation/Feasibility Study and cleanup costs to date. Our projected portion of the estimated cap installation is $55,000. While the results cannot be predicted with certainty, we believe the ultimate resolution of this matter will not have a material impact on our results of operations, financial position or cash flows.

We and the non-controlled entities in which we own an interest are a party to various other claims, legal actions and ~~complaints arising in the ordinary course of business.~~complaints. 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.

~~Table of Contents~~


~~ITEM 1A.~~	~~RISK FACTORS~~

ITEM 1A.RISK FACTORS

In addition to the information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, ~~2016,~~2019, 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.

The COVID-19 pandemic has adversely affected, and could continue to adversely affect, our business.

The COVID-19 pandemic has negatively impacted the global economy. In response to the pandemic, governments around the world have implemented stringent measures to help reduce the spread of the virus, including stay-at-home orders, travel restrictions and other measures. Due to reductions in economic activity, the world is experiencing reduced demand for petroleum products and depressed petroleum products commodity prices, which has adversely affected our business. Continuing uncertainty regarding the global impact of COVID-19 is likely to result in continued weakness in demand for the services we provide. The reduction in refined products demand and lower crude oil prices have combined to put significant downward pressure on domestic crude oil production, and a sustained reduction in crude oil production could cause delays in the timing of our recognition of revenue from take-or-pay pipeline transportation commitments. These factors have also significantly decreased the creditworthiness of certain of our crude oil transportation customers, resulting in an increased risk of customer defaults. Customers and vendors could also seek to assert claims for relief from some of their obligations on the basis of force majeure. We may also experience disruptions to supply chains and the availability and efficiency of our workforce as a result of the pandemic, which could adversely affect our ability to conduct our business and operations. The extent and duration of the impacts these events will have on our results of operations is unclear but will likely be material and may impact our ability to pay cash distributions.


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

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

~~None.~~

Issuer Purchases of Common Units

In first quarter 2020, we announced that our general partner’s board of directors authorized the repurchase of up to $750 million of our common units through 2022. We intend to purchase our common units from time-to-time through a variety of methods, including open market purchases and negotiated transactions, all in compliance with the rules of the Securities and Exchange Commission and other applicable legal requirements. The timing, price and actual number of common units repurchased will depend on a number of factors including our expected expansion capital spending needs, excess cash available, balance sheet metrics, legal and regulatory requirements, market conditions and the trading price of our common units. The repurchase program does not obligate us to acquire any particular amount of common units, and the repurchase program may be suspended or discontinued at any time.

Activity during 2020 is detailed in the following table:


Period	Total Number of Common Units Purchased	Average Price Paid Per Unit		Total Number of Units Purchased as Part of Publicly Announced Program	Approximate Dollar Value of Units That May Yet Be Purchased under the Program (in millions)
January 1-31, 2020	—	$	—	—	$	750.0
February 1-29, 2020	1,514,719	$	59.19	1,514,719	$	660.4
March 1-31, 2020	2,117,065	$	53.06	2,117,065	$	548.1
First Quarter 2020	3,631,784	$	55.62	3,631,784
April 1-30, 2020	—			—	$	548.1
May 1-31, 2020	—			—	$	548.1
June 1-30, 2020	—			—	$	548.1
Second Quarter 2020	—			—
July 1-31, 2020	—			—	$	548.1
August 1-31, 2020	—			—	$	548.1
September 1-30, 2020	1,355,344	$	36.87	1,355,344	$	498.0
Third Quarter 2020	1,355,344	$	36.87	1,355,344
Year-to-Date 2020	4,987,128	$	50.52	4,987,128


~~ITEM 3.~~	~~DEFAULTS UPON SENIOR SECURITIES~~

ITEM 3.DEFAULTS UPON SENIOR SECURITIES

None.


~~ITEM 4.~~	~~MINE SAFETY DISCLOSURES~~

ITEM 4.MINE SAFETY DISCLOSURES

Not applicable.


~~ITEM 5.~~	~~OTHER INFORMATION~~

ITEM 5.OTHER INFORMATION

None.


~~ITEM 6.~~	~~EXHIBITS~~

ITEM 6.EXHIBITS

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

~~Table of Contents~~

INDEX TO EXHIBITS




Exhibit Number		Description

Exhibit 123.1	—	~~Ratio~~ Amendment No. 4, effective as of ~~earnings~~September 25, 2020, to ~~fixed charges.~~the Fifth Amended and Restated Agreement of Limited Partnership of Magellan Midstream Partners, L.P. dated as of September 28, 2009 (filed as Exhibit 3.1 to Form 8-K filed September 25, 2020).

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

Exhibit 31.2	—	Certification of ~~Aaron L. Milford,~~Jeff Holman, 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,~~Jeff Holman, Chief Financial Officer.

Exhibit 101.INS	—	XBRL Instance ~~Document.~~Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

Exhibit 101.SCH	—	XBRL Taxonomy Extension ~~Schema.~~Schema Document.

Exhibit 101.CAL	—	XBRL Taxonomy Extension Calculation ~~Linkbase.~~Linkbase Document.

Exhibit 101.DEF	—	XBRL Taxonomy Extension Definition ~~Linkbase.~~Linkbase Document.

Exhibit 101.LAB	—	XBRL Taxonomy Extension Label ~~Linkbase.~~Linkbase Document.

Exhibit 101.PRE	—	XBRL Taxonomy Extension Presentation ~~Linkbase.~~Linkbase Document.

~~Table of Contents~~

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized in Tulsa, Oklahoma on ~~November 2, 2017.~~October 30, 2020.


MAGELLAN MIDSTREAM PARTNERS, L.P.

~~MAGELLAN MIDSTREAM PARTNERS, L.P.~~
By:
~~By:~~	Magellan GP, LLC,
		its general partner

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



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



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



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


ITEM 1.				ITEM 1.		CONSOLIDATED FINANCIAL STATEMENTS
					CONSOLIDATED STATEMENTS OF INCOME		4
					CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME		5
ITEM 1.		CONSOLIDATED FINANCIAL STATEMENTS
	CONSOLIDATED STATEMENTS OF INCOME		2		CONSOLIDATED BALANCE SHEETS		6
	CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME		3		CONSOLIDATED STATEMENTS OF CASH FLOWS		7
	CONSOLIDATED BALANCE SHEETS		4		CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL		8
	CONSOLIDATED STATEMENTS OF CASH FLOWS		5		NOTES TO CONSOLIDATED FINANCIAL STATEMENTS:
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS:				1.	Organization, Description of Business and Basis of Presentation	10
	1.	Organization, Description of Business and Basis of Presentation	6		2.	Segment Disclosures	12
	2.	Product Sales Revenue	8		3.	Revenue from Contracts with Customers	15
	3.	Segment Disclosures	9		4.	Investments in Non-Controlled Entities	18
	4.	Investments in Non-Controlled Entities	12		5.	Inventory	20
	5.	Inventory	14		6.	Debt	21
	6.	Employee Benefit Plans	14		7.	Leases	22
	7.	Debt	17		8.	Employee Benefit Plans	22
	8.	Derivative Financial Instruments	18		9.	Long-Term Incentive Plan	24
	9.	Commitments and Contingencies	23		10.	Derivative Financial Instruments	25
	10.	Long-Term Incentive Plan	24		11.	Fair Value	28
	11.	Partners’ Capital and Distributions	25		12.	Commitments and Contingencies	30
	12.	Fair Value	26		13.	Related Party Transactions	31
	13.	Related Party Transactions	27		14.	Partners’ Capital and Distributions	31
	14.	Subsequent Events	28		15.	Subsequent Events	33
ITEM 2.	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		ITEM 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Introduction		29		Introduction		34
	Recent Developments		29		Recent Developments		34
	Results of Operations		30		Results of Operations		35
	Distributable Cash Flow		37		Distributable Cash Flow		41
	Liquidity and Capital Resources		38		Liquidity and Capital Resources		42
	Off-Balance Sheet Arrangements		39		Off-Balance Sheet Arrangements		43
	Environmental		39		Other Items		43
	Other Items		40
ITEM 3.	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	41	ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	44
ITEM 4.	ITEM 4.	CONTROLS AND PROCEDURES	41	ITEM 4.		CONTROLS AND PROCEDURES	45
Forward-Looking Statements			42
PART II OTHER INFORMATION	PART II OTHER INFORMATION			PART II OTHER INFORMATION
ITEM 1.	ITEM 1.	LEGAL PROCEEDINGS	44	ITEM 1.		LEGAL PROCEEDINGS	46
ITEM 1A.	ITEM 1A.	RISK FACTORS	45	ITEM 1A.		RISK FACTORS	47
ITEM 2.	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	45	ITEM 2.		UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	47
ITEM 3.	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	45	ITEM 3.		DEFAULTS UPON SENIOR SECURITIES	48
ITEM 4.	ITEM 4.	MINE SAFETY DISCLOSURES	45	ITEM 4.		MINE SAFETY DISCLOSURES	48
ITEM 5.	ITEM 5.	OTHER INFORMATION	45	ITEM 5.		OTHER INFORMATION	48
ITEM 6.	ITEM 6.	EXHIBITS	45	ITEM 6.		EXHIBITS	48
Index to Exhibits			46
Signatures			47
INDEX TO EXHIBITS				INDEX TO EXHIBITS			49
SIGNATURES				SIGNATURES			50



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



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



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



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




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



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



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

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



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