Edgar Filing: MAGELLAN MIDSTREAM PARTNERS LP

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________

FORM 10-Q



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

For the quarterly period ended September 30, 2018



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

For the transition period from to

Commission File No.: 1-16335

_________________________________________

Magellan Midstream Partners, L.P.

(Exact name of registrant as specified in its charter)



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

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

(Address of principal executive offices and zip code)

(918) 574-7000

(Registrant’s telephone number, including area code)

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x Accelerated filer £ Non-accelerated filer £

Smaller reporting company £ Emerging growth company £

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

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

Act). Yes £ No x

As of October 31, 2018, there were 228,195,160 outstanding limited partner units of Magellan Midstream Partners, L.P. that trade on the New York Stock Exchange under the ticker symbol “MMP.”

TABLE OF CONTENTS

PART I

FINANCIAL INFORMATION



ITEM 1.		CONSOLIDATED FINANCIAL STATEMENTS
	CONSOLIDATED STATEMENTS OF INCOME		2
	CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME		3
	CONSOLIDATED BALANCE SHEETS		4
	CONSOLIDATED STATEMENTS OF CASH FLOWS		5
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS:
	1.	Organization, Description of Business and Basis of Presentation	6
	2.	Revenue from Contracts with Customers	10
	3.	Segment Disclosures	14
	4.	Investments in Non-Controlled Entities	17
	5.	Inventory	19
	6.	Employee Benefit Plans	19
	7.	Debt	21
	8.	Derivative Financial Instruments	22
	9.	Commitments and Contingencies	26
	10.	Long-Term Incentive Plan	27
	11.	Partners’ Capital and Distributions	29
	12.	Fair Value	30
	13.	Related Party Transactions	31
	14.	Subsequent Events	31
ITEM 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Introduction		32
	Growth Projects and Recent Developments		32
	Results of Operations		33
	Distributable Cash Flow		39
	Liquidity and Capital Resources		40
	Off-Balance Sheet Arrangements		41
	Environmental		42
	Other Items		43
ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	45
ITEM 4.		CONTROLS AND PROCEDURES	46
Forward-Looking Statements			47
PART II OTHER INFORMATION
ITEM 1.		LEGAL PROCEEDINGS	49
ITEM 1A.		RISK FACTORS	50
ITEM 2.		UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	50
ITEM 3.		DEFAULTS UPON SENIOR SECURITIES	50
ITEM 4.		MINE SAFETY DISCLOSURES	50
ITEM 5.		OTHER INFORMATION	50
ITEM 6.		EXHIBITS	50
Index to Exhibits			51
Signatures			52

PART I

FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per unit amounts)

(Unaudited)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2018			2017			2018
Transportation and terminals revenue	$	446,935		$	488,775		$	1,272,845		$	1,392,960
Product sales revenue	121,010			144,403			548,634			552,792
Affiliate management fee revenue	4,903			4,842			12,883			15,138
Total revenue	572,848			638,020			1,834,362			1,960,890
Costs and expenses:
Operating	165,368			172,115			442,254			475,256
Cost of product sales	121,819			120,510			440,670			473,781
Depreciation and amortization	49,909			56,228			146,103			161,726
General and administrative	37,202			47,389			120,876			147,235
Total costs and expenses	374,298			396,242			1,149,903			1,257,998
Earnings of non-controlled entities	31,151			53,795			78,173			130,843
Operating profit	229,701			295,573			762,632			833,735
Interest expense	51,895			55,133			154,653			168,535
Interest capitalized	(3,424		)	(3,099		)	(10,804		)	(13,354		)
Interest income	(240		)	(501		)	(788		)	(1,460		)
Gain on sale of asset	(18,505		)	(353,797		)	(18,505		)	(353,797		)
Other expense	549			1,694			3,762			10,299
Income before provision for income taxes	199,426			596,143			634,314			1,023,512
Provision for income taxes	926			1,609			2,678			3,659
Net income	$	198,500		$	594,534		$	631,636		$	1,019,853
Basic net income per limited partner unit	$	0.87		$	2.60		$	2.77		$	4.47
Diluted net income per limited partner unit	$	0.87		$	2.60		$	2.77		$	4.46
Weighted average number of limited partner units outstanding used for basic net income per unit calculation	228,199			228,397			228,167			228,368
Weighted average number of limited partner units outstanding used for diluted net income per unit calculation	228,260			228,449			228,222			228,412

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited, in thousands)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2018			2017			2018
Net income	$	198,500		$	594,534		$	631,636		$	1,019,853
Other comprehensive income:
Derivative activity:
Net gain (loss) on cash flow hedges	(228		)	6,852			(1,735		)	13,963
Reclassification of net loss on cash flow hedges to income	740			740			2,219			2,219
Changes in employee benefit plan assets and benefit obligations recognized in other comprehensive income:
Net actuarial loss	—			—			—			(5,291		)
Amortization of prior service credit	(45		)	(45		)	(136		)	(136		)
Amortization of actuarial loss	1,568			1,806			4,779			8,623
Settlement cost	289			—			2,015			—
Total other comprehensive income	2,324			9,353			7,142			19,378
Comprehensive income	$	200,824		$	603,887		$	638,778		$	1,039,231

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands)



	December 31, 2017			September 30, 2018
ASSETS				(Unaudited)
Current assets:
Cash and cash equivalents	$	160,840		$	217,423
Trade accounts receivable	138,779			137,618
Other accounts receivable	14,561			24,025
Inventory	182,345			179,366
Energy commodity derivatives deposits	36,690			47,354
Other current assets	63,396			66,221
Total current assets	596,611			672,007
Property, plant and equipment	7,235,468			7,570,759
Less: accumulated depreciation	1,682,633			1,835,824
Net property, plant and equipment	5,552,835			5,734,935
Investments in non-controlled entities	1,082,511			1,005,392
Long-term receivables	27,676			23,520
Goodwill	53,260			53,260
Other intangibles (less accumulated amortization of $1,389 and $2,493 at December 31, 2017 and September 30, 2018, respectively)	52,764			51,660
Restricted cash	15,228			42,807
Other noncurrent assets	13,490			12,087
Total assets	$	7,394,375		$	7,595,668

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	104,852		$	137,169
Accrued payroll and benefits	56,261			53,285
Accrued interest payable	70,657			49,309
Accrued taxes other than income	51,343			52,307
Environmental liabilities	6,235			10,537
Deferred revenue	117,795			121,247
Accrued product liabilities	96,159			80,195
Energy commodity derivatives contracts, net	25,694			32,244
Current portion of long-term debt, net	250,974			552,898
Other current liabilities	56,540			37,873
Total current liabilities	836,510			1,127,064
Long-term debt, net	4,273,518			3,718,607
Long-term pension and benefits	111,305			125,088
Other noncurrent liabilities	30,350			64,425
Environmental liabilities	13,039			13,064
Commitments and contingencies
Partners’ capital:
Limited partner unitholders (228,025 units and 228,195 units outstanding at December 31, 2017 and September 30, 2018, respectively)	2,267,231			2,665,620
Accumulated other comprehensive loss	(137,578		)	(118,200		)
Total partners’ capital	2,129,653			2,547,420
Total liabilities and partners’ capital	$	7,394,375		$	7,595,668

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)



	Nine Months Ended
	September 30,
	2017			2018
Operating Activities:
Net income	$	631,636		$	1,019,853
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	146,103			161,726
Gain on sale and retirement of assets	(10,924		)	(347,541		)
Earnings of non-controlled entities	(78,173		)	(130,843		)
Distributions from operations of non-controlled entities	97,691			147,950
Equity-based incentive compensation expense	14,183			24,612
Settlement cost, amortization of prior service credit and actuarial loss	6,658			8,487
Changes in operating assets and liabilities:
Trade accounts receivable and other accounts receivable	(14,413		)	(8,303		)
Inventory	(34,384		)	2,979
Energy commodity derivatives contracts, net of derivatives deposits	1,135			(4,505		)
Accounts payable	15,576			27,498
Accrued payroll and benefits	(5,608		)	(2,976		)
Accrued interest payable	(23,386		)	(21,348		)
Accrued taxes other than income	(322		)	964
Accrued product liabilities	67,972			(15,964		)
Deferred revenue	14,806			5,353
Current and noncurrent environmental liabilities	(3,352		)	4,327
Other current and noncurrent assets and liabilities	(11,497		)	(8,488		)
Net cash provided by operating activities	813,701			863,781
Investing Activities:
Additions to property, plant and equipment, net⁽¹⁾	(418,239		)	(374,320		)
Proceeds from sale and disposition of assets	44,303			579,448
Investments in non-controlled entities	(114,078		)	(147,048		)
Distributions from returns of investments in non-controlled entities	52,738			1,786
Deposits received from undivided joint interest third party	—			41,571
Net cash provided (used) by investing activities	(435,276		)	101,437
Financing Activities:
Distributions paid	(596,854		)	(642,370		)
Net commercial paper borrowings	218,984			—
Payments on notes	—			(250,000		)
Debt placement costs	—			(326		)
Net receipt on financial derivatives	—			20,925
Payments associated with settlement of equity-based incentive compensation	(13,875		)	(9,285		)
Net cash used by financing activities	(391,745		)	(881,056		)
Change in cash, cash equivalents and restricted cash	(13,320		)	84,162
Cash, cash equivalents and restricted cash at beginning of period	14,701			176,068
Cash, cash equivalents and restricted cash at end of period	$	1,381		$	260,230

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	$	1,669		$	120

⁽¹⁾ Additions to property, plant and equipment	$	(443,439	)	$	(375,599	)
Changes in accounts payable and other current liabilities related to capital expenditures	25,200			1,279
Additions to property, plant and equipment, net	$	(418,239	)	$	(374,320	)

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.	Organization, Description of Business and Basis of Presentation

Organization

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

Description of Business

We are principally engaged in the transportation, storage and distribution of refined petroleum products and crude oil. As of September 30, 2018, our asset portfolio, including the assets of our joint ventures, consisted of:


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


•	our crude oil segment, comprised of approximately 2,200 miles of crude oil pipelines, our condensate splitter and storage facilities with an aggregate storage capacity of approximately 33 million barrels, of which approximately 21 million barrels are used for contract storage; and


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

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


•	refined products are the output from refineries and are primarily used as fuels by consumers. Refined products include gasoline, diesel fuel, aviation fuel, kerosene and heating oil. Collectively, diesel fuel, aviation fuel, kerosene and heating oil are referred to as distillates;


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


•	blendstocks are blended with refined products to change or enhance their characteristics such as increasing a gasoline’s octane or oxygen content. Blendstocks include alkylates, oxygenates and natural gasoline;


•	heavy oils and feedstocks are used as burner fuels or feedstocks for further processing by refineries and petrochemical facilities. Heavy oils and feedstocks include No. 6 fuel oil and vacuum gas oil;


•	crude oil and condensate are used as feedstocks by refineries and petrochemical facilities;


•	biofuels, such as ethanol and biodiesel, are typically blended with other refined products as required by government mandates; and


•	ammonia is primarily used as a nitrogen fertilizer.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Basis of Presentation

In the opinion of management, our accompanying consolidated financial statements which are unaudited, except for the consolidated balance sheet as of December 31, 2017, 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, 2018, the results of operations for the three and nine months ended September 30, 2017 and 2018 and cash flows for the nine months ended September 30, 2017 and 2018. The results of operations for the nine months ended September 30, 2018 are not necessarily indicative of the results to be expected for the full year ending December 31, 2018 for several reasons. Profits from our butane blending activities are realized largely during the first and fourth quarters of each year. Additionally, gasoline demand, which drives transportation volumes and revenues on our refined products pipeline 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.

Pursuant to the rules and regulations of the Securities and Exchange Commission, the financial statements in this report do not include all of the information and notes normally included with financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”). These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2017.

Reclassifications. Prior year amounts related to restricted cash have been reclassified to conform with the 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 on the reported amounts of revenue and expense during the reporting periods. Actual results could differ from those estimates.

Restricted Cash

Restricted cash includes cash held by us, which is contractually required to be used for the construction of fixed assets, and is unavailable for general use. It is classified as noncurrent due to its designation to be used for the construction of noncurrent assets.

Correction of Actuarial Valuation Error

In first quarter 2018, an error was discovered in our third-party actuary’s valuation of our pension liabilities and net periodic pension expenses dating back to 2010. The impacts of the error were not material to any of our prior period financial statements and the cumulative impact was corrected with a one-time adjustment in the first quarter of 2018. As a result, during first quarter 2018, net periodic pension expenses were increased by $16.0 million ($5.7 million operating expense, $3.4 million general and administrative (“G&A”) costs and $6.9 million other expense below operating profit on our consolidated statements of income). In addition, long-term pension and benefits was increased $18.8 million and accumulated other comprehensive loss was increased by $2.8 million on our consolidated balance sheets.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

New Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842). This ASU requires lessees to recognize a right of use asset and lease liability on the balance sheet for all leases, with the exception of short-term leases. The new accounting model for lessors remains largely the same, although some changes have been made to align it with the new lessee model and the new revenue recognition guidance. This update also requires companies to include additional disclosures regarding their lessee and lessor agreements. For public companies, this ASU is effective for fiscal years that start after December 15, 2018, and early adoption is permitted. This standard will not have a material impact on our consolidated statements of income. Based on our current population of leases, we expect the impact of this ASU to increase our assets and liabilities by approximately $80.0 million due to the recognition of right of use assets and lease liabilities.

New Accounting Pronouncements - Adopted January 1, 2018

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. This update changes GAAP’s hedge accounting requirements to simplify some of the specialized treatment’s most complex areas. These simplifications are intended to expand opportunities to use hedge accounting and better align the accounting treatment with existing risk management activities. The ASU is effective for public companies starting after December 15, 2018, and we early-adopted the new standard on January 1, 2018. The adoption of this ASU did not have a material impact on our consolidated financial statements.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments: A Consensus of the FASB Emerging Issues Task Force. This ASU includes a requirement to make an accounting policy election to classify distributions received from equity method investees under either (1) the cumulative earnings approach, where distributions in excess of equity earnings are considered a return of capital and classified as cash inflows from investing activities, or (2) the nature of the distribution approach, where each distribution is evaluated on the basis of the source of the payment and classified as either operating or investing cash inflows. We adopted this standard on January 1, 2018 using the retrospective transition method and made an accounting policy election to use the nature of the distribution approach, which resulted in the following adjustments to our September 30, 2017 comparative statement of cash flows (in thousands):



	Nine Months Ended September 30, 2017, as Reported			ASU 2016-15 Adjustment			Nine Months Ended September 30, 2017, as Adjusted
Operating activities:
Distributions from operations of non-controlled entities	$	78,562		$	19,129		$	97,691
Net cash provided by operating activities	$	794,572		$	19,129		$	813,701

Investing activities:
Distributions from returns of investments in non-controlled entities	$	71,867		$	(19,129	)	$	52,738
Net cash used by investing activities	$	(416,147	)	$	(19,129	)	$	(435,276	)

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). 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. On January 1, 2018, we adopted the new Accounting Standards Codification (“ASC”) 606, Revenue from Contracts with Customers and all related

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

amendments using the modified retrospective method. We recognized the cumulative effect of initially applying the new revenue standard as an adjustment to the opening balance of partners’ capital. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods.

The cumulative effect of the changes made to our consolidated January 1, 2018 balance sheet resulting from the adoption of the new revenue standard was as follows (in thousands):



	Balance at December 31, 2017			Adjustments Due to ASU 2014-09			Balance at January 1, 2018
Assets:
Property, plant and equipment	$	7,235,468		$	8,516		$	7,243,984
Accumulated depreciation	(1,682,633		)	(325		)	(1,682,958		)
Net property, plant and equipment	$	5,552,835		$	8,191		$	5,561,026
Investments in non-controlled entities	$	1,082,511		$	502		$	1,083,013

Liabilities:
Deferred revenue	$	117,795		$	(1,901	)	$	115,894
Other noncurrent liabilities	$	30,350		$	4,619		$	34,969

Partners’ capital:
Limited partner unitholders	$	2,267,231		$	5,975		$	2,273,206

The primary changes impacting our financial statements under the new revenue standard include the requirement for us to estimate deficiencies in our customers’ use of our services contracted as minimum commitments and adjust the amount of revenue recognized in proportion to our customers’ pattern of exercised rights. This change results in accelerating the timing of revenue recognized for specific contracts for which we estimate our customers will not ship their minimum commitments. In addition, we periodically receive payments from customers seeking to expand their access to our pipeline systems and terminals. Prior to the adoption of the new revenue standard, these payments were recorded as reductions to our property, plant and equipment (“PP&E”) expenditures. Under the new revenue standard, these payments are recorded to deferred revenue and other noncurrent liabilities and are recognized as revenue in proportion to the related services provided. The impact of this change increases our revenues, contract liabilities, PP&E and depreciation expense. We expect the impact of the adoption of the new revenue standard, including these changes, to be immaterial to our net income on an ongoing basis.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


2.	Revenue from Contracts with Customers

Adoption of ASC 606, Revenue from Contracts with Customers

The table below provides the amount by which financial statement line items are affected in the current reporting period by the application of the new revenue standard, as compared with the guidance that was in effect before the change (in thousands):



	As Reported		Amounts without adoption of ASC 606		Effect of Change Higher/(Lower)
Statements of Income:
	Three Months Ended September 30, 2018
Transportation and terminals revenue	$	488,775	$	486,801	$	1,974
Depreciation and amortization	$	56,228	$	56,108	$	120

	Nine Months Ended September 30, 2018
Transportation and terminals revenue	$	1,392,960	$	1,383,404	$	9,556
Depreciation and amortization	$	161,726	$	161,486	$	240

Balance Sheet:
	As of September 30, 2018
Assets:
Property, plant and equipment	$	7,570,759	$	7,555,758	$	15,001
Accumulated depreciation	1,835,824		1,835,259		565
Net property, plant and equipment	$	5,734,935	$	5,720,499	$	14,436
Investments in non-controlled entities	$	1,005,392	$	1,004,890	$	502
Liabilities:
Deferred revenue	$	121,247	$	129,458	$	(8,211	)
Other noncurrent liabilities	$	64,425	$	56,567	$	7,858
Partners’ capital:
Limited partner unitholders	$	2,665,620	$	2,650,329	$	15,291

Revenue recognition policies

Revenue is recognized upon the satisfaction of each performance obligation required by our customer contracts. Transportation and terminals revenue is recognized over time as our customers receive the benefits of our service as it is performed on their behalf using an output method based on actual deliveries. Revenue for our storage services is recognized over time using an output method based on the capacity of storage under contract with our customers. Product sales revenue is recognized at a point in time when our customers take control of the commodities purchased. We record back-to-back purchases and sales of petroleum products where we are acting as an agent on a net basis.

We recognize pipeline transportation revenue for crude oil and ammonia shipments when our customers’ product arrives at the customer-designated destination. For shipments of refined products under published tariffs that combine transportation and terminalling services, we recognize revenue when our customers take delivery of their product from our system. For shipments where terminalling services are not included in the tariff, we recognize revenue when our customers’ product arrives at the customer-designated destination. We have certain contracts that

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

require counterparties to ship a minimum volume over an agreed-upon time period, which are contracted as minimum dollar or volume commitments. Revenue pursuant to these take-or-pay contracts is recognized when the customers utilize their committed volumes. Additionally, when we estimate that the customers will not utilize all or a portion of their committed volumes, we recognize revenue in proportion to the pattern of exercised rights for the respective commitment period.

Our interstate common carrier petroleum products pipeline operations are subject to rate regulation by the Federal Energy Regulatory Commission (“FERC”) under the Interstate Commerce Act, the Energy Policy Act of 1992 and rules and orders promulgated pursuant thereto. FERC regulation requires that interstate pipeline rates be filed with the FERC, be posted publicly and be nondiscriminatory and “just and reasonable.” The rates on approximately 40% of the shipments on our refined products pipeline system are regulated by the FERC primarily through an index methodology. As an alternative to cost-of-service or index-based rates, interstate pipeline companies may establish rates by obtaining authority to charge market-based rates in competitive markets or by negotiation with unaffiliated shippers. Approximately 60% of our refined products pipeline system’s markets are either subject to regulations by the states in which we operate or are approved for market-based rates by the FERC, and in both cases these rates can generally be adjusted at our discretion based on market factors. Most of the tariffs on our crude oil pipelines are established by negotiated rates that generally provide for annual adjustments in line with changes in the FERC index, subject to certain modifications.

For both our index-based rates and our market-based rates, our published tariffs serve as contracts, and shippers nominate the volume to be shipped up to a month in advance. These tariffs include provisions which allow us to deduct from our customer’s inventory a small percentage of the products our customers transport on our pipeline systems. We refer to this non-monetary consideration as tender deduction revenue. We receive tender deductions from our customers as consideration for product losses during the transportation of petroleum products within our pipeline systems. Tender deduction revenue is generally recognized as transportation revenue when the customer's transported commodities reach their destination and is recorded at the fair value of the product received on the date received or the contract date, as applicable.

Product sales revenue pricing is contractually specified, and we have determined that each barrel sold represents a separate performance obligation. Transaction prices for our other services including terminalling, storage and ancillary services are typically contracted as a single performance obligation with our customers. In circumstances where multiple performance obligations are contractually required, we allocate the transaction price to the various performance obligations based on their relative standalone selling price.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, 2018
	Refined Products			Crude Oil			Marine Storage			Intersegment Eliminations			Total
Transportation	$	197,235		$	91,086		$	—		$	—		$	288,321
Terminalling	46,213			2,528			616			—			49,357
Storage	25,137			29,094			33,890			(923		)	87,198
Ancillary services	28,808			6,278			5,857			—			40,943
Lease revenue	2,641			16,132			4,183			—			22,956
Transportation and terminals revenue	300,034			145,118			44,546			(923		)	488,775
Product sales revenue	129,926			12,666			1,811			—			144,403
Affiliate management fee revenue	351			3,463			1,028			—			4,842
Total revenue	430,311			161,247			47,385			(923		)	638,020
Revenue not under the guidance of ASC 606:
Lease revenue⁽¹⁾	(2,641		)	(16,132		)	(4,183		)	—			(22,956		)
Losses from futures contracts included in product sales revenue⁽²⁾	24,253			102			—			—			24,355
Affiliate management fee revenue	(351		)	(3,463		)	(1,028		)	—			(4,842		)
Total revenue from contracts with customers under ASC 606	$	451,572		$	141,754		$	42,174		$	(923	)	$	634,577

⁽¹⁾Lease revenue is accounted for under ASC 840, 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, 2018
	Refined Products			Crude Oil			Marine Storage			Intersegment Eliminations			Total
Transportation	$	548,733		$	254,964		$	—		$	—		$	803,697
Terminalling	136,135			2,528			1,920			—			140,583
Storage	75,353			87,620			101,420			(2,753		)	261,640
Ancillary services	83,055			19,512			18,928			—			121,495
Lease revenue	8,216			44,705			12,624			—			65,545
Transportation and terminals revenue	851,492			409,329			134,892			(2,753		)	1,392,960
Product sales revenue	513,634			32,387			6,771			—			552,792
Affiliate management fee revenue	1,000			11,328			2,810			—			15,138
Total revenue	1,366,126			453,044			144,473			(2,753		)	1,960,890
Revenue not under the guidance of ASC 606:
Lease revenue⁽¹⁾	(8,216		)	(44,705		)	(12,624		)	—			(65,545		)
Losses from futures contracts included in product sales revenue⁽²⁾	64,558			5,582			—			—			70,140
Affiliate management fee revenue	(1,000		)	(11,328		)	(2,810		)	—			(15,138		)
Total revenue from contracts with customers under ASC 606	$	1,421,468		$	402,593		$	129,039		$	(2,753	)	$	1,950,347

⁽¹⁾Lease revenue is accounted for under ASC 840, Leases.

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

Balance Sheet Disclosures

We invoice customers on our refined products pipelines for transportation services when their product enters our system. At each period end, we record all invoiced amounts associated with products that have not yet been delivered (in-transit products) as a contract liability. This liability is presented as deferred revenue on our consolidated balance sheets. Deferred revenue is also recorded for pre-payments received in conjunction with take-or-pay contracts, storage contracts and other service offerings in which the service to our customers remains unfulfilled. Additionally, at each period end, we defer the direct costs we have incurred associated with our customers’ in-transit products as contract assets. Contract assets are presented on our consolidated balance sheets as other current assets. These direct costs are estimated based on our per-barrel direct delivery cost for the current period multiplied by the total in-transit barrels in our system at the end of the period multiplied by 50% to reflect the average transportation costs incurred for all products across all of our pipeline systems. We use 50% of the in-transit barrels because that best represents the average delivery point of all barrels in our pipeline system. These contract assets and contract liabilities are determined using judgments and assumptions that management considers reasonable.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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



	January 1, 2018		September 30, 2018
Accounts receivable from contracts with customers	$	133,084	$	135,269
Contract assets	$	8,615	$	8,053
Contract liabilities	$	106,933	$	119,841

For the three and nine months ended September 30, 2018, we recognized $10.7 million and $77.0 million, respectively, of transportation and terminals revenue that was recorded in deferred revenue as of January 1, 2018.

Unfulfilled Performance Obligations

We have certain contracts with customers that represent customer commitments to purchase a minimum amount of our services over specified time periods. These contracts require us to provide services to our customers in the future and result in our having unfulfilled performance obligations (“UPOs”) to our customers related to the periods remaining under each contract. We have UPOs in many of our core business services, including transportation, terminalling and storage services. The UPOs will be recognized as revenue in the future as our customers utilize our services or when we estimate that our customers are not likely to use all or a portion of their commitments.

The following table provides the aggregate amount of the transaction price allocated to our UPOs as of September 30, 2018 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		Marine Storage		Total
Balances at September 30, 2018	$	2,176,871	$	1,419,449	$	341,673	$	3,937,993
Remaining terms	1 - 20 years		1 - 10 years		1 - 6 years
Estimated revenues from UPOs to be recognized in the next 12 months	$	395,872	$	328,844	$	147,795	$	872,511

In computing the value of these future revenues, we have used the current rates in effect as of September 30, 2018 and have not included any estimates for future rate changes due to changes in the FERC index or other contractually negotiated rate escalations. Our UPO balances include the full amount of our customer commitments as of September 30, 2018 through the expiration of the related contracts. The UPO balances disclosed exclude all performance obligations for which the original expected term is one year or less, the consideration is variable or the future use of our services is fully at the discretion of our customers.


3.	Segment Disclosures

Our reportable segments are strategic business units that offer different products and services. Our segments are managed separately as each segment requires different marketing strategies and business knowledge. Management evaluates performance based on segment operating margin, which includes revenue from affiliates and external customers, operating expenses, cost of product sales and earnings of non-controlled entities.

We believe that investors benefit from having access to the same financial measures used by management. Operating margin, which is presented in the following tables, is an important measure used by management to

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 (presented in thousands). Operating profit includes depreciation and amortization expense and G&A expense that management does not consider when evaluating the core profitability of our separate operating segments.



	Three Months Ended September 30, 2017
	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



	Three Months Ended September 30, 2018
	Refined Products			Crude Oil			Marine Storage			Intersegment Eliminations			Total
Transportation and terminals revenue	$	300,034		$	145,118		$	44,546		$	(923	)	$	488,775
Product sales revenue	129,926			12,666			1,811			—			144,403
Affiliate management fee revenue	351			3,463			1,028			—			4,842
Total revenue	430,311			161,247			47,385			(923		)	638,020
Operating expenses	112,279			45,195			17,178			(2,537		)	172,115
Cost of product sales	106,756			11,590			2,164			—			120,510
Earnings of non-controlled entities	(3,393		)	(49,420		)	(982		)	—			(53,795		)
Operating margin	214,669			153,882			29,025			1,614			399,190
Depreciation and amortization expense	30,440			15,145			9,029			1,614			56,228
G&A expense	28,751			12,766			5,872			—			47,389
Operating profit	$	155,478		$	125,971		$	14,124		$	—		$	295,573

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Nine Months Ended September 30, 2017
	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



	Nine Months Ended September 30, 2018
	Refined Products			Crude Oil			Marine Storage			Intersegment Eliminations			Total
Transportation and terminals revenue	$	851,492		$	409,329		$	134,892		$	(2,753	)	$	1,392,960
Product sales revenue	513,634			32,387			6,771			—			552,792
Affiliate management fee revenue	1,000			11,328			2,810			—			15,138
Total revenue	1,366,126			453,044			144,473			(2,753		)	1,960,890
Operating expenses	319,670			109,963			52,835			(7,212		)	475,256
Cost of product sales	434,632			32,401			6,748			—			473,781
Earnings of non-controlled entities	(5,614		)	(122,879		)	(2,350		)	—			(130,843		)
Operating margin	617,438			433,559			87,240			4,459			1,142,696
Depreciation and amortization expense	89,855			40,648			26,764			4,459			161,726
G&A expense	90,825			38,127			18,283			—			147,235
Operating profit	$	436,758		$	354,784		$	42,193		$	—		$	833,735

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


4.	Investments in Non-Controlled Entities

Our investments in non-controlled entities at September 30, 2018 were comprised of:



Entity		Ownership Interest
BridgeTex Pipeline Company, LLC (“BridgeTex”)		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%
Seabrook Logistics, LLC (“Seabrook”)		50%
Texas Frontera, LLC (“Texas Frontera”)		50%

In September 2018, we sold a 20% interest in BridgeTex to an affiliate of OMERS Infrastructure Management, Inc. (“OMERS”), which reduced our ongoing investment in BridgeTex to a 30% interest. We received $578.5 million in cash from the sale, and we recorded a gain of $353.8 million on our consolidated statements of income. See Note 9 – Commitments and Contingencies for details regarding our indemnity to OMERS that was recorded in relation to the sale.

We serve as operator of BridgeTex, HoustonLink, MVP, Powder Springs, Saddlehorn, Texas Frontera and the pipeline activities of Seabrook. We receive fees for management services as well as reimbursement or payment to us for certain direct operational payroll and other overhead costs. The management fees we have received are reported as affiliate management fee revenue on our consolidated statements of income. Cost reimbursements we receive from these entities in connection with our operating services are included as reductions to costs and expenses on our consolidated statements of income and totaled $0.7 million and $0.9 million during the three months ended September 30, 2017 and 2018, respectively, and $3.1 million and $2.6 million during the nine months ended September 30, 2017 and 2018, respectively.

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2018		2017		2018
Transportation and terminals revenue:
BridgeTex, pipeline capacity	$	9.1	$	9.9	$	27.0	$	29.5
Double Eagle, throughput revenue	$	1.3	$	1.0	$	3.1	$	3.9
Saddlehorn, storage revenue	$	0.5	$	0.5	$	1.6	$	1.6
Operating costs:
Seabrook, storage and ancillary services	$	—	$	4.0	$	—	$	4.0
Product sales revenue:
Powder Springs, butane sales	$	—	$	—	$	—	$	4.9
Cost of product sales:
Powder Springs, butane purchases	$	—	$	—	$	—	$	0.4

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):



	December 31, 2017						September 30, 2018
	Trade Accounts Receivable		Other Accounts Receivable		Other Accounts Payable		Trade Accounts Receivable		Other Accounts Receivable		Other Accounts Payable
BridgeTex	$	—	$	—	$	—	$	0.2	$	0.1	$	—
Double Eagle	$	0.5	$	—	$	—	$	0.3	$	—	$	—
HoustonLink	$	—	$	—	$	0.1	$	—	$	—	$	—
MVP	$	—	$	0.4	$	—	$	—	$	1.2	$	—
Powder Springs	$	—	$	0.9	$	—	$	—	$	2.1	$	—
Saddlehorn	$	—	$	0.1	$	—	$	—	$	0.2	$	—
Seabrook	$	—	$	0.2	$	—	$	—	$	—	$	2.1

The financial results from MVP and Texas Frontera are included in our marine storage segment, the financial results from BridgeTex, Double Eagle, HoustonLink, 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.

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




Investments at December 31, 2017	$	1,082,511
Additional investment	147,048
Sale of ownership interest in BridgeTex	(205,776		)
Other adjustments	502
Earnings of non-controlled entities:
Proportionate share of earnings	132,647
Amortization of excess investment and capitalized interest	(1,804		)
Earnings of non-controlled entities	130,843
Less:
Distributions from operations of non-controlled entities	147,950
Distributions from returns of investments in non-controlled entities	1,786
Investments at September 30, 2018	$	1,005,392

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


5.	Inventory

Inventory at December 31, 2017 and September 30, 2018 was as follows (in thousands):



	December 31, 2017		September 30, 2018
Refined products	$	73,845	$	60,390
Liquefied petroleum gases	45,553		53,080
Transmix	33,319		43,588
Crude oil	23,763		16,129
Additives	5,865		6,179
Total inventory	$	182,345	$	179,366


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 $2.0 million and $2.7 million for the three months ended September 30, 2017 and 2018, respectively, and $7.4 million and $8.8 million for the nine months ended September 30, 2017 and 2018, respectively.

Additionally, we sponsor two union pension plans that cover certain union employees, a pension plan for all non-union employees and a postretirement benefit plan for certain employees. Net periodic benefit expense for the three and nine months ended September 30, 2017 and 2018 was as follows (in thousands):



	Three Months Ended					Three Months Ended
	September 30, 2017					September 30, 2018
	Pension Benefits			Other Postretirement Benefits		Pension Benefits			Other Postretirement Benefits
Components of net periodic benefit costs:
Service cost	$	5,125		$	51	$	6,424		$	58
Interest cost	2,466			111		2,816			104
Expected return on plan assets	(2,566		)	—		(3,055		)	—
Amortization of prior service credit	(45		)	—		(45		)	—
Amortization of actuarial loss	1,406			162		1,659			147
Settlement cost	289			—		—			—
Net periodic benefit cost	$	6,675		$	324	$	7,799		$	309

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Nine Months Ended					Nine Months Ended
	September 30, 2017					September 30, 2018
	Pension Benefits			Other Postretirement Benefits		Pension Benefits			Other Postretirement Benefits
Components of net periodic benefit costs:
Service cost	$	15,373		$	182	$	28,393		$	174
Interest cost	7,398			356		12,054			312
Expected return on plan assets	(7,699		)	—		(9,057		)	—
Amortization of prior service credit	(136		)	—		(136		)	—
Amortization of actuarial loss	4,217			562		8,182			441
Settlement cost	2,015			—		—			—
Net periodic benefit cost	$	21,168		$	1,100	$	39,436		$	927

The service component of our net periodic benefit costs is presented in operating expense and G&A expense, and the non-service components are presented in other expense in our consolidated statements of income.

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, 2017 and 2018 were as follows (in thousands):



	Three Months Ended						Three Months Ended
	September 30, 2017						September 30, 2018
Gains (Losses) Included in AOCL	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Beginning balance	$	(54,138	)	$	(7,481	)	$	(96,352	)	$	(6,036	)
Amortization of prior service credit	(45		)	—			(45		)	—
Amortization of actuarial loss	1,406			162			1,659			147
Settlement cost	289			—			—			—
Ending balance	$	(52,488	)	$	(7,319	)	$	(94,738	)	$	(5,889	)



	Nine Months Ended						Nine Months Ended
	September 30, 2017						September 30, 2018
Gains (Losses) Included in AOCL	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Beginning balance	$	(58,584	)	$	(7,881	)	$	(97,226	)	$	(6,597	)
Net actuarial gain (loss)	—			—			(5,558		)	267
Amortization of prior service credit	(136		)	—			(136		)	—
Amortization of actuarial loss	4,217			562			8,182			441
Settlement cost	2,015			—			—			—
Ending balance	$	(52,488	)	$	(7,319	)	$	(94,738	)	$	(5,889	)

The net periodic benefit costs and AOCL presented in the tables above for the nine month period ending September 30, 2018 include one-time corrections made in first quarter 2018 resulting from an error in our third-party actuary’s valuation of our pension liabilities and net periodic pension expenses. See Note 1 – Organization, Description of Business and Basis of Presentation for more details regarding this error correction.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Contributions estimated to be paid into the plans in 2018 are $31.7 million and $0.6 million for the pension plans and other postretirement benefit plan, respectively.


7.	Debt

Long-term debt at December 31, 2017 and September 30, 2018 was as follows (in thousands):



	December 31, 2017			September 30, 2018
Commercial paper	$	—		$	—
6.40% Notes due 2018	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
4.20% Notes due 2047	500,000			500,000
Face value of long-term debt	4,550,000			4,300,000
Unamortized debt issuance costs⁽¹⁾	(29,472		)	(27,683		)
Net unamortized debt premium (discount)⁽¹⁾	215			(2,127		)
Net unamortized amount of gains from historical fair value hedges⁽¹⁾	3,749			1,315
Long-term debt, net, including current portion	4,524,492			4,271,505
Less: current portion of long-term debt, net	250,974			552,898
Long-term debt, net	$	4,273,518		$	3,718,607


(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.

Other Debt

Revolving Credit Facilities. At September 30, 2018, the total borrowing capacity under our revolving credit facility maturing October 26, 2022 was $1.0 billion. Any borrowings outstanding under this facility are classified as long-term debt on our consolidated balance sheets. Borrowings under this facility are unsecured and bear interest at LIBOR plus a spread ranging from 1.000% to 1.625% based on our credit ratings. Additionally, an unused commitment fee is assessed at a rate between 0.100% and 0.275% depending on our credit ratings. The unused commitment fee was 0.125% at September 30, 2018. Borrowings under this facility may be used for general partnership purposes, including capital expenditures. As of both December 31, 2017 and September 30, 2018, there were no borrowings outstanding under this facility, with $6.3 million obligated for letters of credit. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheets, but decrease our borrowing capacity under this facility.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Commercial Paper Program. We have a commercial paper program under which we may issue commercial paper notes in an amount up to the available capacity under our $1.0 billion revolving credit facility. The maturities of the commercial paper notes vary, but may not exceed 397 days from the date of issuance. Because the commercial paper we can issue is limited to amounts available under our revolving credit facility, amounts outstanding under the program are classified as long-term debt. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. The weighted-average interest rate for commercial paper borrowings based on the number of days outstanding was 1.3% for the year ended December 31, 2017 and 2.3% for the nine months ended September 30, 2018.


8.	Derivative Financial Instruments

Interest Rate Derivatives

We periodically enter into interest rate derivatives to hedge the fair value of debt or hedge against variability in interest rates. We record any ineffectiveness on interest rate derivatives designated as hedging instruments to interest expense and the change in fair value of interest rate derivatives that we do not designate as hedging instruments to other income or expense in our results of operations. For the effective portion of interest rate cash flow hedges, we record the noncurrent portion of unrealized gains or losses as an adjustment to other comprehensive income with the current portion recorded as an adjustment to interest expense. For the effective portion of fair value hedges on long-term debt, we record the noncurrent portion of gains or losses as an adjustment to long-term debt with the current portion recorded as an adjustment to interest expense. Adjustments resulting from discontinued hedges continue to be recognized in accordance with their historic hedging relationships.

During 2018, we entered into $200.0 million of treasury lock agreements to protect against the risk of variability of a portion of debt issuances we anticipate to occur in 2018 and 2019. The fair value of these interest rate derivative agreements at September 30, 2018 was recorded as a current asset of $5.2 million, with the offset recorded to other comprehensive income. We account for these agreements as cash flow hedges.

We entered into $100.0 million of interest rate swap agreements in 2016 to protect against the variability of future interest payments on a portion of debt we anticipated issuing in 2018. These agreements were accounted for as cash flow hedges. In September 2018, we terminated and settled these agreements for a gain of $20.9 million. The gain was recorded to other comprehensive income and will be recognized into earnings as an adjustment to our periodic interest accruals over the life of the expected debt issuance.

Commodity Derivatives

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-traded 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, whereby changes in the mark-to-market values of such contracts are not recognized in income; rather the revenues and expenses associated with such transactions are recognized during the period when commodities are physically delivered or received. Physical forward commodity contracts subject to this exception are evaluated for the probability of future delivery and are periodically tested once the

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

forecasted period has passed to determine whether similar forward contracts are probable of physical delivery in the future.

We record the effective portion of the gains or losses for commodity-based contracts designated as fair value hedges as adjustments to the assets being hedged and the ineffective portions as well as amounts excluded from the assessment of hedge effectiveness as adjustments to other income or expense. We recognize the change in fair value of economic hedges that hedge against changes in the price of petroleum products that we expect to sell or purchase in the future currently in earnings as adjustments to product sales revenue, cost of product sales or operating expenses, as applicable.

Our open futures contracts at September 30, 2018 were as follows:



Type of Contract/Accounting Methodology	Product Represented by the Contract and Associated Barrels	Maturity Dates
Futures - Economic Hedges	5.4 million barrels of refined products and crude oil	Between October 2018 and April 2019
Futures - Economic Hedges	1.7 million barrels of butane and natural gasoline	Between October 2018 and April 2019

Energy Commodity Derivatives Contracts and Deposits Offsets

At December 31, 2017 and September 30, 2018, we had margin deposits of $36.7 million and $47.4 million, respectively, 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, 2017 and September 30, 2018 (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⁽²⁾			Margin Deposit Amounts Not Offset in the Consolidated Balance Sheets		Net Asset Amount⁽¹⁾
As of December 31, 2017	$	(38,936	)	$	12,851	$	(26,085	)	$	36,690	$	10,605
As of September 30, 2018	$	(55,087	)	$	22,843	$	(32,244	)	$	47,354	$	15,110


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


(2)	Net amount includes energy commodity derivative contracts classified as current liabilities of $25,694 and noncurrent liabilities of $391 at December 31, 2017. Net amount includes energy commodity derivative contracts classified as current liabilities of $32,244 at September 30, 2018.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, 2017 and 2018 were as follows (in thousands):



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Derivative Losses Included in AOCL	2017			2018			2017			2018
Beginning balance	$	(34,804	)	$	(25,165	)	$	(34,776	)	$	(33,755	)
Net gain (loss) on cash flow hedges	(228		)	6,852			(1,735		)	13,963
Reclassification of net loss on cash flow hedges to income	740			740			2,219			2,219
Ending balance	$	(34,292	)	$	(17,573	)	$	(34,292	)	$	(17,573	)

The following is a summary of the effect on our consolidated statements of income for the three and nine months ended September 30, 2017 and 2018 of derivatives that were designated as cash flow hedges (in thousands):



	Interest Rate Contracts
	Amount of Gain (Loss) Recognized in AOCL on Derivative			Location of Loss Reclassified from AOCL into Income	Amount of Loss Reclassified from AOCL into Income
Three Months Ended September 30, 2017	$	(228	)	Interest expense	$	(740	)



Three Months Ended September 30, 2018	$	6,852	Interest expense	$	(740	)



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



Nine Months Ended September 30, 2018	$	13,963	Interest expense	$	(2,219	)

As of September 30, 2018, the net loss estimated to be classified to interest expense over the next twelve months from AOCL is approximately $2.3 million. This amount relates to the amortization of losses on interest rate contracts over the life of the related debt instruments.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

We used futures contracts designated as fair value hedges to hedge against changes in the fair value of crude oil that was contractually reserved as tank bottoms and included with other noncurrent assets on our consolidated balance sheets. During September 2017, as a result of contract renegotiations, we sold a portion of the tank bottoms, settled the related hedges and transferred the permanent portion of the tank bottoms from noncurrent assets to PP&E. The effective portions of the fair value gains or losses on these futures contracts were offset by fair value gains or losses on the crude oil, and there was no ineffectiveness recognized. 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 crude oil were as follows (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2018			2017			2018
Gain (loss) recognized in other income/expense on derivatives (futures contracts)	$	(1,661	)	$	122		$	5,107		(427	)
Gain (loss) recognized in other income/expense on hedged item (crude oil)	$	1,661		$	(122	)	$	(5,107	)	427

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 and nine months ended September 30, 2017, we recognized a gain of $0.7 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.

The following table provides a summary of the effect on our consolidated statements of income for the three and nine months ended September 30, 2017 and 2018 of derivatives accounted for as economic hedges (in thousands):



		Amount of Gain (Loss) Recognized on Derivatives
		Three Months Ended						Nine Months Ended
	Location of Gain (Loss) Recognized on Derivatives	September 30,						September 30,
Derivative Instrument	Location of Gain (Loss) Recognized on Derivatives	2017			2018			2017			2018
Futures contracts	Product sales revenue	$	(47,336	)	$	(24,354	)	$	(4,442	)	$	(70,140	)
Futures contracts	Operating expenses	663			—			663			—
Futures contracts	Cost of product sales	19,660			11,665			19,713			16,058
	Total	$	(27,013	)	$	(12,689	)	$	15,934		$	(54,082	)

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

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, which are presented on a net basis in our consolidated balance sheets, that were designated as hedging instruments as of December 31, 2017 and September 30, 2018 (in thousands):

December 31, 2017

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

173

Interest rate contracts

Other current assets

12,177

Other current liabilities

—

Total

12,177

Total

173

September 30, 2018

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

189

Interest rate contracts

Other current assets

5,215

Other current liabilities

—

Total

5,215

Total

189

The following tables provide a summary of the fair value of derivatives, which are presented on a net basis in our consolidated balance sheets, that were not designated as hedging instruments as of December 31, 2017 and September 30, 2018 (in thousands):

December 31, 2017

Asset Derivatives

Liability Derivatives

Derivative Instrument

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Futures contracts

Energy commodity derivatives contracts, net

12,605

Energy commodity derivatives contracts, net

38,126

Futures contracts

Other noncurrent assets

246

Other noncurrent liabilities

637

Total

12,851

Total

38,763

September 30, 2018

Asset Derivatives

Liability Derivatives

Derivative Instrument

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Futures contracts

Energy commodity derivatives contracts, net

22,843

Energy commodity derivatives contracts, net

54,898


9.	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”) have infringed patents relating to butane

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

blending at the Powder Springs facility located in Powder Springs, Georgia. Sunoco has since submitted pleadings alleging that Magellan has also infringed various patents relating to butane blending at nine Magellan facilities, in addition to Powder Springs. Sunoco is seeking an undetermined amount of damages, attorneys’ fees and a permanent injunction enjoining Magellan and Powder Springs from infringing on 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, based on our current understanding of the applicable facts and law, that 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 $19.3 million and $23.6 million at December 31, 2017 and September 30, 2018, 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 $3.0 million and $5.5 million for the three months ended September 30, 2017 and 2018, respectively, and $7.5 million and $10.8 million for the nine months ended September 30, 2017 and 2018, respectively.

Environmental Receivables

Receivables from insurance carriers and other third parties related to environmental matters were $7.2 million at December 31, 2017, of which $0.5 million and $6.7 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 $6.7 million at September 30, 2018, of which $0.7 million and $6.0 million were recorded to other accounts receivable and long-term receivables, respectively, on our consolidated balance sheets.

Other

In connection with the sale of part of our interest in BridgeTex (see Note 4 – Investments in Non-Controlled Entities), we agreed to indemnify an affiliate of OMERS for certain claims involving BridgeTex. The maximum obligation is limited to the net proceeds we received. We probability-weighted potential outcome scenarios to estimate the value of such indemnification obligations. As a result, we reduced the gain recognized on the transaction by $16.0 million and recorded the same estimate in other noncurrent liabilities on our consolidated balance sheets this period. We believe, however, that the most likely outcome is that no significant liability will result from such obligations.

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, 2018, 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 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.


10.	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 limited partner units. The estimated units remaining available under the LTIP at September 30, 2018 total 2.1 million.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2018		2017		2018
Performance-based awards	$	2,728	$	7,087	$	12,119	$	22,176
Time-based awards	738		846		2,064		2,436
Total	$	3,466	$	7,933	$	14,183	$	24,612

Allocation of LTIP expense on our consolidated statements of income:
G&A expense	$	3,430	$	7,867	$	14,062	$	24,412
Operating expense	36		66		121		200
Total	$	3,466	$	7,933	$	14,183	$	24,612

On February 1, 2018, 294,054 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, 2020.

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 unit awards 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 unit awards associated with our LTIP that have not yet vested.

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 have been issued pursuant to this program.

The following table details the changes in the number of our limited partner units outstanding from December 31, 2017 through September 30, 2018:



Limited partner units outstanding on December 31, 2017		228,024,556
January 2018–Settlement of employee LTIP awards		168,913
During 2018–Other^(a)		1,691
Limited partner units outstanding on September 30, 2018		228,195,160

(a) Limited partner units issued to settle the equity-based retainer paid to an independent director of our general partner.

Distributions

Distributions we paid during 2017 and 2018 were as follows (in thousands, except per unit amounts):



Payment Date	Per Unit Cash Distribution Amount			Total Cash Distribution to Limited Partners
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		0.9050			206,362
Total		$	3.5225		$	803,216

02/14/2018		$	0.9200		$	209,940
05/15/2018		0.9375			213,933
08/14/2018		0.9575			218,497
Through 09/30/2018		2.8150			642,370
11/14/2018^(a)		0.9775			223,061
Total		$	3.7925		$	865,431

(a) Our general partner’s board of directors declared this cash distribution in October 2018 to be paid on November 14, 2018 to unitholders of record at the close of business on November 7, 2018.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


12.	Fair Value

Fair Value Methods and Assumptions - Financial Assets and Liabilities.

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


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

•

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


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

•

Debt. The fair value of our publicly traded notes was based on the prices of those notes at December 31, 2017 and September 30, 2018; 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, 2017 and September 30, 2018 based on the three levels established by ASC 820, Fair Value Measurements and Disclosures (in thousands):



	December 31, 2017
Assets (Liabilities)							Fair Value Measurements using:
Assets (Liabilities)	Carrying Amount			Fair Value			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Energy commodity derivatives contracts	$	(26,085	)	$	(26,085	)	$	(26,085	)	$	—		$	—
Interest rate contracts	$	12,177		$	12,177		$	—		$	12,177		$	—
Long-term receivables	$	27,676		$	27,676		$	—		$	—		$	27,676
Debt	$	(4,524,492	)	$	(4,826,480	)	$	—		$	(4,826,480	)	$	—

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	September 30, 2018
Assets (Liabilities)							Fair Value Measurements using:
Assets (Liabilities)	Carrying Amount			Fair Value			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Energy commodity derivatives contracts	$	(32,244	)	$	(32,244	)	$	(32,244	)	$	—		$	—
Interest rate contracts	$	5,215		$	5,215		$	—		$	5,215		$	—
Long-term receivables	$	23,520		$	23,520		$	—		$	—		$	23,520
Debt	$	(4,271,505	)	$	(4,314,870	)	$	—		$	(4,314,870	)	$	—


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 and other ancillary revenue from this customer of $4.1 million and $6.0 million for the three months ended September 30, 2017 and 2018, respectively, and $12.5 million and $14.4 million for the nine months ended September 30, 2017 and 2018, respectively. We recorded receivables of $1.6 million and $3.0 million from this customer at December 31, 2017 and September 30, 2018, respectively. The tariff revenue we recognized from this customer was in the normal course of business, with rates determined in accordance with published tariffs.

See Note 4 – Investments in Non-Controlled Entities for details of transactions with our joint ventures.


14.	Subsequent Events

Recognizable events

No recognizable events occurred subsequent to September 30, 2018.

Non-recognizable events

Cash Distribution. In October 2018, our general partner’s board of directors declared a quarterly distribution of $0.9775 per unit for the period of July 1, 2018 through September 30, 2018. This quarterly cash distribution will be paid on November 14, 2018 to unitholders of record on November 7, 2018. The total cash distributions expected to be paid under this declaration are approximately $223.1 million.


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, 2018, our asset portfolio, including the assets of our joint ventures, consisted of:


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


•	our crude oil segment, comprised of approximately 2,200 miles of crude oil pipelines, our condensate splitter and storage facilities with an aggregate storage capacity of approximately 33 million barrels, of which approximately 21 million barrels are used for contract storage; and


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

The following discussion provides an analysis of the results for each of our operating segments, an overview of our liquidity and capital resources and other items related to our partnership. The following discussion and analysis should be read in conjunction with (i) our accompanying interim consolidated financial statements and related notes and (ii) our consolidated financial statements, related notes and management’s discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the year ended December 31, 2017.

Growth Projects

Permian Gulf Coast Pipeline. In September 2018, we announced plans for a joint project with Energy Transfer LP, MPLX LP and Delek US Holdings, Inc. to construct a new 30-inch diameter common carrier pipeline to transport crude oil from the Permian Basin to the Texas Gulf Coast region. The 600-mile pipeline system has received sufficient commitments to proceed with construction and is expected to be operational in mid-2020, subject to receipt of customary regulatory and board approvals of the respective entities. As currently contemplated, we expect our portion of this project to cost approximately $500 million.

West Texas Expansion. In response to shipper demand and in connection with our previously-announced East Houston to Hearne, Texas pipeline project, we are expanding the western leg of our refined petroleum products pipeline system in Texas to approximately 175,000 barrels per day (bpd) from our current capacity of 100,000 bpd. The expansion is supported by long-term customer commitments and will be accomplished by a combination of increased pipeline diameter along our existing route and construction of 140 miles of new pipe. We expect this project to cost a total of approximately $500 million, with the expanded capacity available mid-2020, subject to receipt of all necessary permits and approvals.

Recent Developments

Investment in BridgeTex Pipeline Company, LLC (“BridgeTex”). In September 2018, we sold a 20% interest in BridgeTex to an affiliate of OMERS Infrastructure Management, Inc., which reduced our ongoing investment in BridgeTex to a 30% interest. We received $578.5 million in cash from the sale, and we recorded a gain of $353.8 million on our consolidated statements of income. We continue to serve as the operator of BridgeTex.

Cash Distribution. In October 2018, the board of directors of our general partner declared a quarterly cash distribution of $0.9775 per unit for the period of July 1, 2018 through September 30, 2018. This quarterly cash

distribution will be paid on November 14, 2018 to unitholders of record on November 7, 2018. Total distributions expected to be paid under this declaration are approximately $223.1 million.

Results of Operations

We believe that investors benefit from having access to the same financial measures utilized by management. Operating margin, which is presented in the following tables, is an important measure used by management to evaluate the economic performance of our core operations. Operating margin is not a generally accepted accounting principles (“GAAP”) measure, but the components of operating margin are computed using amounts that are determined in accordance with GAAP. A reconciliation of operating margin to operating profit, which is its nearest comparable GAAP financial measure, is included in the following tables. Operating profit includes expense items, such as depreciation and amortization expense and general and administrative (“G&A”) expense, which management does not focus on when evaluating the core profitability of our separate operating segments. Additionally, product margin, which management primarily uses to evaluate the profitability of our commodity-related activities, is provided in this table. Product margin is a non-GAAP measure; however, its components of product sales and cost of product sales are determined in accordance with GAAP. Our butane blending, fractionation and other commodity-related activities generate significant revenue. We believe the product margin from these activities, which takes into account the related cost of product sales, better represents its importance to our results of operations.

In first quarter 2018, an error was discovered in our third-party actuary’s valuation of our pension liabilities and net periodic pension expenses dating back to 2010. The impacts of the error were not material to any of our prior period financial statements and were corrected in first quarter 2018. As a result, our financial results for the nine months ended September 30, 2018 include a one-time $16.0 million pension correction, which included a $5.7 million increase to operating expenses, $3.4 million increase to G&A costs and $6.9 million increase to other expense below operating profit. See Note 1 – Organization, Description of Business and Basis of Presentation in Item 1 of Part I of this report for further information.

Three Months Ended September 30, 2017 compared to Three Months Ended September 30, 2018



	Three Months Ended September 30,						Variance Favorable (Unfavorable)
	2017			2018			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)
Transportation and terminals revenue:
Refined products	$	289.0		$	300.0		$	11.0		4
Crude oil	116.3			145.1			28.8			25
Marine storage	42.5			44.6			2.1			5
Intersegment eliminations	(0.8		)	(0.9		)	(0.1		)	(13)
Total transportation and terminals revenue	447.0			488.8			41.8			9
Affiliate management fee revenue	4.9			4.8			(0.1		)	(2)
Operating expenses:
Refined products	118.7			112.3			6.4			5
Crude oil	31.2			45.2			(14.0		)	(45)
Marine storage	17.8			17.1			0.7			4
Intersegment eliminations	(2.3		)	(2.5		)	0.2			9
Total operating expenses	165.4			172.1			(6.7		)	(4)
Product margin:
Product sales revenue	121.0			144.4			23.4			19
Cost of product sales	121.9			120.6			1.3			1
Product margin	(0.9		)	23.8			24.7			n/a
Earnings of non-controlled entities	31.2			53.8			22.6			72
Operating margin	316.8			399.1			82.3			26
Depreciation and amortization expense	49.9			56.2			(6.3		)	(13)
G&A expense	37.2			47.4			(10.2		)	(27)
Operating profit	229.7			295.5			65.8			29
Interest expense (net of interest income and interest capitalized)	48.3			51.5			(3.2		)	(7)
Gain on sale of asset	(18.5		)	(353.8		)	335.3			1,812
Other expense	0.5			1.7			(1.2		)	(240)
Income before provision for income taxes	199.4			596.1			396.7			199
Provision for income taxes	0.9			1.5			(0.6		)	(67)
Net income	$	198.5		$	594.6		$	396.1		200
Operating Statistics:
Refined products:
Transportation revenue per barrel shipped	$	1.521		$	1.600
Volume shipped (million barrels):
Gasoline	75.8			73.4
Distillates	41.0			45.6
Aviation fuel	6.7			8.1
Liquefied petroleum gases	3.9			4.4
Total volume shipped	127.4			131.5
Crude oil:
Magellan 100%-owned assets:
Transportation revenue per barrel shipped	$	1.332		$	1.266
Volume shipped (million barrels)	48.4			62.8
Crude oil terminal average utilization (million barrels per month)	14.9			16.0
Select joint venture pipelines:
BridgeTex - volume shipped (million barrels)⁽¹⁾	25.7			36.5
Saddlehorn - volume shipped (million barrels)⁽²⁾	4.4			6.7
Marine storage:
Marine terminal average utilization (million barrels per month)	22.5			22.6

(1) These volumes reflect the total shipments for the BridgeTex pipeline, which was owned 50% by us through September 28, 2018 and 30% thereafter.

(2) These volumes reflect the total shipments for the Saddlehorn pipeline, which is owned 40% by us.

Transportation and terminals revenue increased $41.8 million resulting from:


•	an increase in refined products revenue of $11.0 million. Higher shipments in the current period resulted from stronger demand for refined products in large part due to increased distillate demand in crude oil production regions. Additionally, the average rate per barrel in the current period was favorably impacted by the mid-year tariff adjustments;

•

an increase in crude oil revenue of $28.8 million primarily due to more spot shipments on the Longhorn pipeline due to the favorable pricing differential between the Permian Basin and Houston which resulted in more volume at a higher average rate. We also benefited from higher volumes from our condensate splitter at Corpus Christi, higher volumes on our Houston distribution system and higher revenues from new system storage and ancillary services that we provided to our shippers in conjunction with capacity from our storage contracts with Seabrook Logistics, LLC (“Seabrook”). Overall, the average crude oil rate per barrel decreased between periods due to significantly higher volumes on our Houston distribution system, which move at a lower rate; and


•	an increase in marine storage revenue of $2.1 million primarily due to higher rates and more ancillary fees reflecting increased customer activity as the prior year was negatively impacted by Hurricane Harvey.

Operating expenses increased by $6.7 million primarily resulting from:


•	a decrease in refined products expenses of $6.4 million primarily due to more favorable product overages (which reduce operating expenses) partially offset by higher property taxes due to a favorable adjustment in the 2017 period and more integrity spending in the current year;


•	an increase in crude oil expenses of $14.0 million primarily due to fees we paid to Seabrook for contract storage and ancillary services that we utilized to provide services to our shippers, higher environmental accruals, higher power costs and less favorable product overages; and


•	a decrease in marine storage expenses of $0.7 million primarily due to environmental accruals and clean-up work related to Hurricane Harvey that negatively impacted the 2017 period.

Product sales revenue resulted primarily from our butane blending activities, transmix fractionation and the sale of tender deductions and product overages 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 increased $24.7 million primarily due to lower unrealized losses on futures contracts recognized in the current period compared to third quarter 2017.

Earnings of non-controlled entities increased $22.6 million primarily due to increased earnings from BridgeTex mainly attributable to incremental shipments related to new commitments that began in first quarter 2018 for recently added pipeline capacity and more spot shipments due to the favorable pricing differential between the Permian Basin and Houston. Earnings from Saddlehorn Pipeline Company, LLC (“Saddlehorn”) were higher as well primarily as a result of a contractual step-up in committed shipments beginning September 2017 and again in September 2018. Increased butane blending volumes and margins resulted in higher earnings from Powder Springs Logistics, LLC (“Powder Springs”), and recently completed construction of additional storage contributed to higher earnings from Seabrook.

Depreciation and amortization expense increased $6.3 million primarily due to the commencement of expansion capital projects recently placed into service.

G&A expense increased $10.2 million primarily due to higher personnel costs resulting from an increase in employee headcount as a result of the growth of our business and higher incentive compensation expense due to company performance in 2018.

Interest expense, net of interest income and interest capitalized, increased $3.2 million in third quarter 2018. Our average outstanding debt increased from $4.3 billion in third quarter 2017 to $4.7 billion in third quarter 2018 primarily due to borrowings for expansion capital expenditures. Our weighted-average interest rate in third quarter 2018 was 4.6% compared to 4.7% in third quarter 2017.

Gain on sale of asset was $335.3 million favorable. We recognized a $353.8 million gain on the sale of a portion of our interest in BridgeTex in third quarter 2018 (see Note 4 – Investments in Non-Controlled Entities in Item 1 of Part I for further details about this sale). In third quarter 2017, we recognized an $18.5 million gain in connection with the sale of an inactive terminal along our refined products pipeline system.

Other expense was $1.2 million unfavorable primarily due to less favorable valuation adjustments associated with our crude oil tank bottoms.

Provision for income taxes was $0.6 million unfavorable primarily due to higher earnings in the current period.

Nine Months Ended September 30, 2017 compared to Nine Months Ended September 30, 2018



	Nine Months Ended September 30,						Variance Favorable (Unfavorable)
	2017			2018			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)
Transportation and terminals revenue:
Refined products	$	808.8		$	851.5		$	42.7		5
Crude oil	329.8			409.3			79.5			24
Marine storage	136.7			134.9			(1.8		)	(1)
Intersegment eliminations	(2.4		)	(2.7		)	(0.3		)	(13)
Total transportation and terminals revenue	1,272.9			1,393.0			120.1			9
Affiliate management fee revenue	12.9			15.1			2.2			17
Operating expenses:
Refined products	312.9			319.7			(6.8		)	(2)
Crude oil	90.0			110.0			(20.0		)	(22)
Marine storage	45.8			52.8			(7.0		)	(15)
Intersegment eliminations	(6.4		)	(7.2		)	0.8			13
Total operating expenses	442.3			475.3			(33.0		)	(7)
Product margin:
Product sales revenue	548.6			552.8			4.2			1
Cost of product sales	440.7			473.8			(33.1		)	(8)
Product margin	107.9			79.0			(28.9		)	(27)
Earnings of non-controlled entities	78.2			130.8			52.6			67
Operating margin	1,029.6			1,142.6			113.0			11
Depreciation and amortization expense	146.1			161.7			(15.6		)	(11)
G&A expense	120.9			147.2			(26.3		)	(22)
Operating profit	762.6			833.7			71.1			9
Interest expense (net of interest income and interest capitalized)	143.1			153.7			(10.6		)	(7)
Gain on sale of asset	(18.5		)	(353.8		)	335.3			1,812
Other expense	3.7			10.3			(6.6		)	(178)
Income before provision for income taxes	634.3			1,023.5			389.2			61
Provision for income taxes	2.7			3.6			(0.9		)	(33)
Net income	$	631.6		$	1,019.9		$	388.3		61
Operating Statistics:
Refined products:
Transportation revenue per barrel shipped	$	1.489		$	1.524
Volume shipped (million barrels):
Gasoline	218.7			219.0
Distillates	119.6			132.7
Aviation fuel	20.2			21.3
Liquefied petroleum gases	9.6			10.4
Total volume shipped	368.1			383.4
Crude oil:
Magellan 100%-owned assets:
Transportation revenue per barrel shipped	$	1.412		$	1.325
Volume shipped (million barrels)	137.0			168.4
Crude oil terminal average utilization (million barrels per month)	15.5			16.1
Select joint venture pipelines:
BridgeTex - volume shipped (million barrels)⁽¹⁾	66.4			100.0
Saddlehorn - volume shipped (million barrels)⁽²⁾	12.1			18.5
Marine storage:
Marine terminal average utilization (million barrels per month)	23.4			22.6

(1) These volumes reflect the total shipments for the BridgeTex pipeline, which was owned 50% by us through September 28, 2018 and 30% thereafter.

(2) These volumes reflect the total shipments for the Saddlehorn pipeline, which is owned 40% by us.

Transportation and terminals revenue increased $120.1 million resulting from:


•	an increase in refined products revenue of $42.7 million. Shipments increased in the current period primarily due to stronger demand for refined products in large part due to higher distillate demand in crude oil production regions. We also benefited from higher storage and other ancillary service fees along our pipeline system due to increased customer activity;

•

an increase in crude oil revenue of $79.5 million primarily due to revenues from our condensate splitter at Corpus Christi that began commercial operations in June 2017, as well as more spot shipments on the Longhorn pipeline due to the favorable pricing differential between the Permian Basin and Houston which resulted in more volume at a higher average rate. Overall, the average crude rate per barrel decreased between periods due to significantly higher volumes on our Houston distribution system, which move at a lower rate; and


•	a decrease in marine storage revenue of $1.8 million primarily due to lower utilization resulting from the timing of maintenance work and the impact of tanks damaged by Hurricane Harvey.

Operating expenses increased by $33.0 million primarily resulting from:


•	an increase in refined products expenses of $6.8 million primarily due to higher personnel costs, which include a one-time pension correction, higher asset integrity spending and higher property taxes, partially offset by more favorable product overages;

•

an increase in crude oil expenses of $20.0 million primarily due to costs associated with our condensate splitter that began commercial operations in June 2017, fees we paid to Seabrook for contract storage and ancillary services that we utilized to provide services to our shippers, higher power costs associated with increased pipeline movements and higher personnel costs resulting from higher incentive compensation accrual as well as a one-time pension correction; and


•	an increase in marine storage expenses of $7.0 million primarily due to higher personnel costs mainly resulting from higher incentive compensation accrual as well as a one-time pension correction, combined with demolition costs incurred in connection with the expansion of our Galena Park, Texas dock facilities in 2018.

Product margin decreased $28.9 million primarily due to lower butane blending volumes and higher butane costs, resulting in lower butane blending margins.

Earnings of non-controlled entities increased $52.6 million primarily due to increased earnings from BridgeTex attributable to incremental shipments related to new commitments that began in 2018 for recently added pipeline capacity and increased spot shipments. Earnings from Saddlehorn were higher primarily due to a contractual step-up in committed shipments beginning September 2017. Earnings from Powder Springs and Double Eagle Pipeline LLC (“Double Eagle”) were also higher, and completed construction of additional storage contributed to higher earnings from Seabrook.

Depreciation and amortization expense increased $15.6 million primarily due to the commencement of expansion capital projects recently placed into service.

G&A expense increased $26.3 million primarily due to higher personnel costs resulting from an increase in employee headcount as a result of the growth of our business and higher incentive compensation expense due to company performance in 2018, as well as an increase from a one-time pension correction.

Interest expense, net of interest income and interest capitalized, increased $10.6 million in 2018 primarily due to higher outstanding debt in the current period. Our average outstanding debt increased from $4.2 billion in 2017 to $4.6 billion in 2018 primarily due to borrowings for expansion capital expenditures. Our weighted-average interest rate of 4.7% in 2018 was comparable to 2017.

Gain on sale of asset was $335.3 million favorable. We recognized a $353.8 million gain on the sale of a portion of our interest in BridgeTex in 2018. In 2017, we recognized an $18.5 million gain in connection with the sale of an inactive terminal along our refined products pipeline system.

Other expense was $6.6 million unfavorable primarily due to a one-time pension correction in 2018 and less favorable valuation adjustments associated with our crude oil tank bottoms, partially offset by a payment received in second quarter 2018 related to a 2016 asset transfer.

Provision for income taxes was $0.9 million unfavorable primarily due to higher earnings in the current period.

Distributable Cash Flow

We calculate the non-GAAP measures of distributable cash flow (“DCF”) and adjusted EBITDA in the table below. Management uses DCF as a basis for recommending to our general partner’s board of directors the amount of cash distributions to be paid to our limited partners each period. Management also uses DCF as a basis for determining the payouts for the performance-based awards issued under our equity-based compensation plan. Adjusted EBITDA is an important measure that we and the investment community use to assess the financial results of an entity. We believe that investors benefit from having access to the same financial measures utilized by management for these evaluations. A reconciliation of DCF and adjusted EBITDA for the nine months ended September 30, 2017 and 2018 to net income, which is its nearest comparable GAAP financial measure, follows (in millions):



	Nine Months Ended September 30,						Increase (Decrease)
	2017			2018			Increase (Decrease)
Net income	$	631.6		$	1,019.9		$	388.3
Interest expense, net	143.1			153.7			10.6
Depreciation and amortization	146.1			161.7			15.6
Equity-based incentive compensation⁽¹⁾	0.3			15.3			15.0
Loss on sale and retirement of assets	7.6			6.3			(1.3		)
Gain on sale of asset⁽²⁾	(18.5		)	(351.2		)	(332.7		)
Commodity-related adjustments:
Derivative losses recognized in the period associated with future product transactions⁽³⁾	13.5			33.9			20.4
Derivative losses recognized in previous periods associated with product sales completed in the period⁽³⁾	(25.5		)	(38.9		)	(13.4		)
Inventory valuation adjustments⁽⁴⁾	4.0			0.2			(3.8		)
Total commodity-related adjustments	(8.0		)	(4.8		)	3.2
Distributions from operations of non-controlled entities in excess of earnings	19.5			17.1			(2.4		)
Other⁽⁵⁾	3.8			3.7			(0.1		)
Adjusted EBITDA	925.5			1,021.7			96.2
Interest expense, net, excluding debt issuance cost amortization	(140.6		)	(151.3		)	(10.7		)
Maintenance capital⁽⁶⁾	(71.8		)	(63.1		)	8.7
DCF	$	713.1		$	807.3		$	94.2


(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. The equity-based compensation adjustment for the nine months ended September 30, 2017 and 2018 was $14.2 million and $24.6 million, respectively.

However, the figures above include adjustments of $13.9 million and $9.3 million, respectively, for cash payments associated with our equity-based incentive compensation plan, which primarily include tax withholdings.


(2)	In September 2018, we recognized a $353.8 million gain from the sale of a portion of our interest in BridgeTex, of which $351.2 million has been deducted from the calculation of DCF, as it is not related to our ongoing operations. The remaining $2.6 million represents a purchase price adjustment related to September operations and, as such, is included in DCF.

In September 2017, we recognized an $18.5 million gain in connection with the sale of an inactive terminal along our refined products pipeline system, which has been deducted from the calculation of DCF because it is not related to our ongoing operations.

(3) Certain derivatives we use as economic hedges have not been designated as hedges for accounting purposes and the mark-to-market changes of these derivatives are recognized currently in net income. We exclude the net impact of these hedges from our determination of DCF until the related products are physically sold. In the period in which these hedged products are physically sold, the net impact of the associated hedges is included in our determination of DCF.


(4)	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.

(5)

Other adjustments in 2018 include a $3.6 million one-time adjustment recorded to partners’ capital as required by our adoption of Accounting Standards Update 2014-09, Revenue from Contracts with Customers. The amount represents cash that we had previously received for deficiency payments, but did not yet recognize in net income under the previous revenue recognition standard. Other adjustments in 2017 are comprised of payments received from HollyFrontier Corporation in conjunction with the February 2016 Osage Pipe Line Company, LLC ("Osage") exchange transaction. These payments replaced distributions we would have received had the Osage transaction not occurred and are, therefore, included in our calculation of DCF.


(6)	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 $813.7 million and $863.8 million for the nine months ended September 30, 2017 and 2018, respectively. The $50.1 million increase in 2018 was due to higher net income as previously described, partially offset by adjustments for non-cash items and changes in our working capital.

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, 2017 was $435.3 million and net cash provided by investing activities for the nine months ended September 30, 2018 was $101.4 million. During the 2018 period, we sold a portion of our interest in BridgeTex for cash proceeds of $578.5 million. Also during the 2018 period, we incurred $375.6 million for capital expenditures, which included $63.1 million for maintenance capital, $276.1 million for our expansion capital projects and $36.4 million for undivided joint interest projects for which cash was received from a third party. Additionally, we contributed capital of $147.0 million in conjunction with our joint venture capital projects, which we account for as investments in non-controlled entities. During the 2017 period, we incurred $443.4 million for capital expenditures, which included $71.8 million for maintenance capital and $371.6 million for expansion capital, and we contributed capital of $114.1 million in conjunction with our joint venture capital projects.

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

Net cash used by financing activities for the nine months ended September 30, 2017 and 2018 was $391.7 million and $881.1 million, respectively. During the 2018 period, we paid cash distributions of $642.4 million to our unitholders and repaid our $250.0 million of 6.40% notes due 2018. Also, in January 2018, our equity-based incentive compensation awards that vested December 31, 2017 were settled by issuing 168,913 limited partner units and distributing those units to the long-term incentive plan (“LTIP”) participants, resulting in payments primarily

associated with tax withholdings of $9.3 million. During the 2017 period, we paid cash distributions of $596.9 million to our unitholders. Additionally, net commercial paper borrowings during the 2017 period were $219.0 million. Also, in January 2017, the cumulative amounts of our LTIP awards that vested December 31, 2016 were settled by issuing 216,679 limited partner units and distributing those units to the LTIP participants, resulting in payments primarily associated with tax withholdings of $13.9 million.

The quarterly distribution amount related to our third quarter 2018 financial results (to be paid in fourth quarter 2018) is $0.9775 per unit. If we are able to meet management’s targeted distribution growth of 8% during 2018 and the number of outstanding limited partner units remains at 228.2 million, total cash distributions of approximately $885 million will be paid to our unitholders related to 2018 financial results. Management believes we will have sufficient cash flows to fund these distributions.

Capital Requirements

Our businesses require continual investments to maintain, upgrade or enhance existing operations and to ensure compliance with safety and environmental regulations. Capital spending consists primarily of:


•	Maintenance capital expenditures. These expenditures include costs required to maintain equipment reliability and safety and to address environmental or other regulatory requirements rather than to generate incremental DCF; and

•

Expansion capital expenditures. These expenditures are undertaken primarily to generate incremental DCF and include costs to acquire additional assets to grow our business and to expand or upgrade our existing facilities, which we refer to as organic growth projects. Organic growth projects include, for example, capital expenditures that increase storage or throughput volumes or develop pipeline connections to new supply sources.

For the nine months ended September 30, 2018, our maintenance capital spending was $63.1 million. For 2018, we expect to spend approximately $90 million on maintenance capital.

During the first nine months of 2018, we spent $276.1 million for our expansion capital projects and contributed $147.0 million for capital projects in conjunction with our joint ventures. Based on the progress of expansion projects already underway, including expansion of the western leg of our refined products pipeline system in Texas and our share of spending for the Permian Gulf Coast pipeline, we expect to spend approximately $800 million in 2018, $1.3 billion in 2019 and $400 million in 2020 to complete our current projects.

Liquidity

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

Off-Balance Sheet Arrangements

None.

Environmental

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

Other Items

FERC Policy Change. In March and July 2018, the FERC issued a revised policy statement and order on rehearing in which it expressed a general policy that it will no longer permit an income tax allowance to be included in the cost-of-service rates for interstate pipelines structured as pass-through entities. The FERC also indicated that it will incorporate the effects of the revised policy statement in its review of the oil pipeline index level to be effective July 1, 2021. We do not have cost-of-service rates that would be immediately impacted by this policy change. The majority of our tariffs are at market-based or negotiated rates; however, approximately 40% of the shipments on our refined products pipeline system are regulated by the FERC through an indexing methodology. Further, some of our negotiated crude oil tariffs utilize the FERC indexing methodology as a basis for future tariff rate escalations subject to certain negotiated modifications. Depending on how the FERC incorporates its most recent tax policy statement into its next index review, to become effective in 2021, our ability to increase our index-based rates could be negatively impacted. However, we believe the ultimate resolution of this matter will not have a material impact on our results of operation, financial position or cash flows.

Longhorn Pipeline Contracts Renewal. The initial term of our contracts for the Longhorn pipeline expired on September 30, 2018. All committed shippers have now either elected to extend their contracts under current terms for an additional two years or have executed new contracts with lower incentive tariff rates and terms up to 10 years, resulting in an average contract term of five years and a lower average tariff rate. We do not expect the reduced tariff to have a material impact on our results of operations, financial position or cash flows.

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

As of September 30, 2018, 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 and fractionation activities. These contracts were accounted for as economic hedges, with the change in fair value of contracts that hedge future sales recorded to product sales, and the change in fair value of contracts that hedge future purchases recorded to cost of product sales.

For further information regarding the quantities of refined products and crude oil hedged at September 30, 2018 and the fair value of open hedge contracts at that date, please see Item 3. Quantitative and Qualitative Disclosures about Market Risk.

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, 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



	Nine Months Ended September 30, 2018
	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	$	(51.7	)	$	20.8		$	—	$	—	$	(30.9	)
Losses recognized on settled futures contracts during the period	(18.4		)	(4.7		)	—		—		(23.1		)
Net impact of futures contracts	$	(70.1	)	$	16.1		$	—	$	—	$	(54.0	)

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


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

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

Forward physical contracts that qualify for and are elected as normal purchases and sales are accounted for using traditional accrual accounting. As of September 30, 2018, we had commitments under forward purchase and sale contracts as follows (in millions):



	Total		2018		2019 - 2020
Forward purchase contracts – notional value	$	242.2	$	122.9	$	119.3
Forward purchase contracts – barrels	4.7		2.4		2.3
Forward sales contracts – notional value	$	61.6	$	46.2	$	15.4
Forward sales contracts – barrels	0.7		0.5		0.2

We also use exchange-traded futures contracts to hedge against changes in the price of petroleum products we expect to sell or purchase. Virtually all of our open contracts did not qualify for hedge accounting treatment under ASC 815, Derivatives and Hedging, and we accounted for these contracts as economic hedges, with changes in fair value recognized currently in earnings. The fair value of these open futures contracts, representing 5.4 million barrels of petroleum products we expect to sell and 1.7 million barrels of butane we expect to purchase, was a net liability of $32.1 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 $54.0 million decrease (increase) in our operating profit, while a $10.00 per barrel increase (decrease) in the price of butane we expect to purchase would result in $17.0 million increase (decrease) in our operating profit. These increases or decreases in operating profit would be substantially offset by higher or lower product sales revenue or cost of product sales when the physical sale or purchase of those products occurs. These contracts may be for the purchase or sale of products in markets different from those in which we are attempting to hedge our exposure, and the resulting hedges may not eliminate all price risks.

Interest Rate Risk

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

We have entered into $200.0 million of interest rate derivatives to protect against the risk of variability of interest payments on debt we anticipate issuing in the future. The fair value of these contracts at September 30, 2018 was a net asset of $5.2 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 $4.8 million. A 0.125% increase in interest rates would result in an increase in the fair value of approximately $4.6 million.


ITEM 4.	CONTROLS AND PROCEDURES

We performed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in rule 13a-14(c) of the Securities Exchange Act) as of the end of the period covered by the date of this report. We performed this evaluation under the supervision and with the participation of our management, including our general partner’s Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that these disclosure controls and practices are effective in providing reasonable assurance that all required disclosures are included in the current report. Additionally, these disclosure controls and practices are effective in ensuring that information required to be disclosed is accumulated and communicated to our Chief Executive Officer and Chief Financial Officer to allow timely decisions regarding required disclosures. There has been no change in our internal control over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act) during the quarter ended September 30, 2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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;


•	population decreases in the markets served by our refined products pipeline system and changes in consumer preferences, driving patterns or rates of automobile ownership;


•	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 FERC, 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, sabotage, protests or 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;


•	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 or the interpretations of such laws that govern our butane blending activities, including the potential applicability of the Carmack Amendment, which broadly covers claims for damage or loss incurred to goods transported by a carrier in interstate commerce, to such activities, or changes regarding product quality specifications or renewable fuel obligations that impact our ability to produce gasoline volumes through our butane blending activities or that 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, our subsidiaries or our joint ventures;


•	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.

PART II

OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

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”) have infringed patents relating to butane blending at the Powder Springs facility located in Powder Springs, Georgia. Sunoco has since submitted pleadings alleging that Magellan has also infringed various patents relating to butane blending at nine Magellan facilities, in addition to Powder Springs. Sunoco is seeking an undetermined amount of damages, attorneys’ fees and a permanent injunction enjoining Magellan and Powder Springs from infringing on 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, based on our current understanding of the applicable facts and law, that the ultimate resolution of this matter will not have a material adverse impact on our results of operations, financial position or cash flows.

Hurricane Harvey Enforcement Proceeding. On July 10, 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 impact on our results of operations, financial position or cash flows.

Clean Air Act Enforcement Proceeding. In June 2017, we received an enforcement letter from the U.S. Department of Justice (“DOJ”) regarding a referral from the U.S. Environmental Protection Agency (“EPA”) relating to alleged Clean Air Act violations at our terminals in Mason City, Iowa, Great Bend and Kansas City, Kansas and Omaha, Nebraska. In 2018, the DOJ and EPA notified us of their intent to impose penalties as a result of these alleged violations which could exceed $100,000. We have been in active settlement discussions with the DOJ and EPA to settle these alleged violations on terms that are mutually agreeable. 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.

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

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


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, 2017, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not our only risks. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also could materially adversely affect our business, financial condition or operating results.


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

None.


ITEM 3.	DEFAULTS UPON SENIOR SECURITIES

None.


ITEM 4.	MINE SAFETY DISCLOSURES

Not applicable.


ITEM 5.	OTHER INFORMATION

None.


ITEM 6.	EXHIBITS

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

INDEX TO EXHIBITS




Exhibit Number		Description

Exhibit 2.1*	—	Membership Interest Purchase Agreement dated August 20, 2018 by and among Plains Pipeline, L.P., Magellan OLP, L.P. and Mapleleaf Midstream, LLC (filed as Exhibit 2.1 to Form 8-K filed August 24, 2018).

Exhibit 12	—	Ratio of earnings to fixed charges.

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

Exhibit 31.2	—	Certification of Aaron L. Milford, principal financial officer.

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

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

Exhibit 101.INS	—	XBRL Instance Document.

Exhibit 101.SCH	—	XBRL Taxonomy Extension Schema.

Exhibit 101.CAL	—	XBRL Taxonomy Extension Calculation Linkbase.

Exhibit 101.DEF	—	XBRL Taxonomy Extension Definition Linkbase.

Exhibit 101.LAB	—	XBRL Taxonomy Extension Label Linkbase.

Exhibit 101.PRE	—	XBRL Taxonomy Extension Presentation Linkbase.

_______________________

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

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 1, 2018.



MAGELLAN MIDSTREAM PARTNERS, L.P.

By:		Magellan GP, LLC,
		its general partner

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