10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended December 31, 2021

or

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

Commission file number 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)	(I.R.S. 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)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Common Units	MMP	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes  ☒   No  o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes  ☐ No  ☒

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  ☒  No  o

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 such files).  Yes  ☒  No  o

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 ☒  Accelerated filer o  Non-accelerated filer o  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. o

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of

the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.

7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes  ☐ No  ☒

The aggregate market value of the registrant’s voting and non-voting common units held by non-affiliates computed by reference to the price at which the common units were last sold as of June 30, 2021 was $10,802,833,233.

As of February 16, 2022, there were 212,393,262 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement prepared for the solicitation of proxies in connection with the 2022 Annual Meeting of Limited Partners are to be incorporated by reference in Part III of this Form 10-K.

TABLE OF CONTENTS

		Page
	PART I
ITEM 1.	Business	3
ITEM 1A.	Risk Factors	17
ITEM 1B.	Unresolved Staff Comments	32
ITEM 2.	Properties	32
ITEM 3.	Legal Proceedings	33
ITEM 4.	Mine Safety Disclosures	33
	PART II
ITEM 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	34
ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	37
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk	50
ITEM 8.	Financial Statements and Supplementary Data	51
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	104
ITEM 9A.	Controls and Procedures	104
ITEM 9B.	Other Information	104
	PART III
ITEM 10.	Directors, Executive Officers and Corporate Governance	105
ITEM 11.	Executive Compensation	105
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	105
ITEM 13.	Certain Relationships and Related Transactions and Director Independence	105
ITEM 14.	Principal Accountant Fees and Services	105
	PART IV
ITEM 15.	Exhibits and Financial Statement Schedules	106

Forward-Looking Statements

Except for statements of historical fact, all statements in this Annual Report on Form 10-K constitute forward-looking statements within the meaning of the federal securities laws. Forward-looking statements may be identified by words like “anticipates,” “believes,” “cause,” “continue,” “could,” “depend,” “develop,” “estimates,” “expects,” “forecasts,” “goal,” “guidance,” “have,” “impact,” “implement,” “increase,” “intends,” “lead,” “maintain,” “may,” “might,” “plans,” “potential,” “possible,” “projected,” “reduce,” “remain,” “result,” “scheduled,” “seek,” “should,” “will,” “would” and other similar words or expressions. The absence of such words or expressions does not necessarily mean the statements are not forward-looking. Although we believe our forward-looking statements are reasonable, 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, including those described in Part I, Item 1A – Risk Factors of this Annual Report. Actual outcomes and results may be materially different from the results stated or implied in such forward-looking statements included in this report. You should not put any undue reliance on any forward-looking statement.

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

•changes in demand for refined products, crude oil or liquefied petroleum gases;

•price fluctuations for refined products, crude oil or liquefied petroleum gases 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, including market and macro-economic disruptions resulting from pandemics and related governmental responses;

•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 business strategy, refinance our existing obligations when due and maintain adequate liquidity;

•development and increasing use of alternative sources of energy transportation, including but not limited to electric and battery-powered motors, natural gas, hydrogen and renewable fuels such as ethanol, biodiesel and renewable diesel, as well as increased conservation or fuel efficiency and regulatory or technological developments that could affect demand for our services;

•changes in population 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 product quality, 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 transportation, storage or other services we provide for refined products or crude oil;

•changes in supply and demand patterns for our facilities due to geopolitical events, the activities of the Organization of the Petroleum Exporting Countries (“OPEC”) and other non-OPEC oil producing countries with large production capacity, changes in U.S. trade policies or in laws governing the importing or exporting of petroleum products;

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

•changes in our tariff rates or other terms of service required by the Federal Energy Regulatory Commission or state regulatory agencies;

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

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

•an increase in the competition our operations encounter, including the effects of capacity over-build in the areas where we operate;

•the occurrence of natural disasters, epidemics, terrorism, cyberattacks, sabotage, protests, activism, operational hazards, equipment failures, system failures or other unforeseen interruptions, as well as global and domestic repercussions from and any government responses to any such events;

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•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 interpretation or increased assessments under existing forms of taxation;

•our ability to identify expansion projects, accretive acquisitions and joint ventures with acceptable expected returns and to complete these projects on time and at projected costs;

•our ability to consummate announced divestitures;

•our ability to successfully execute our capital allocation priorities including unit repurchases with acceptable expected returns;

•the effect of changes in accounting policies and 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 maintenance and operation of our current assets and construction of our growth projects, 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 interpretation of laws and regulations that govern our gas liquids blending activities or changes regarding product quality specifications or renewable fuel obligations that impact our ability to produce gasoline volumes through our gas liquids blending activities or that require significant capital outlays for compliance;

•changes in laws and regulations or the interpretation of laws and regulations to which we or our customers are or could become subject, including those related to tax withholding requirements, safety, security, employment, hydraulic fracturing, derivatives transactions, trade and the environment, 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 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 their contractual obligations to us;

•petroleum product supply disruptions; and

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

This list of important factors is not exhaustive. The forward-looking statements in this Annual Report speak only as of the date hereof, and 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, unless required by law.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

FORM 10-K

PART I

Item 1. Business

(a) General Development of Business

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 formed in August 2000, and our common units are traded on the New York Stock Exchange under the ticker symbol “MMP.” Magellan GP, LLC, a wholly-owned Delaware limited liability company, serves as our general partner. The board of directors of our general partner is referred to herein as our “board”.

In June 2021, we entered into an agreement to sell our independent terminals network comprised of 26 refined petroleum products terminals with approximately six million barrels of storage located primarily in the southeastern United States (“U.S.”) to Buckeye Partners, L.P. for $435 million. The sale is expected to close upon the receipt of required regulatory approval. These assets and the related results of operations, financial position and cash flows have been classified as discontinued operations. Unless indicated otherwise, the information provided in this report relates only to our continuing operations.

(b) [Reserved.]

(c) Narrative Description of Business

We are principally engaged in the transportation, storage and distribution of refined petroleum products and crude oil. As of December 31, 2021, our asset portfolio, excluding assets associated with discontinued operations, consisted of:

•our refined products segment, comprised of our approximately 9,800-mile refined petroleum products pipeline system with 54 terminals and two marine storage terminals (one of which is owned through a joint venture); and

•our crude oil segment, comprised of approximately 2,200 miles of crude oil pipelines, a condensate splitter and 39 million barrels of aggregate storage capacity, of which approximately 29 million barrels are used for contract storage. Approximately 1,000 miles of these pipelines, the condensate splitter and 31 million barrels of this storage capacity (including 25 million barrels used for contract storage) are wholly-owned, with the remainder owned through joint ventures.

Industry Background

The U.S. petroleum products transportation and distribution system links sources of crude oil supply with refineries and ultimately with end users of petroleum products. This system is comprised of a network of pipelines, terminals, storage facilities, waterborne vessels, railcars and trucks. For transportation of petroleum products, pipelines are generally the most reliable, lowest cost, least carbon intensive and safest alternative for intermediate and long-haul movements between different markets. Throughout the distribution system, terminals play a key role in facilitating product movements by providing storage, distribution, blending and other ancillary services.

The following terms are commonly used in our industry to describe products that we transport, store, distribute or otherwise handle through our petroleum pipelines and terminals:

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

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

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

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

•crude oil, which includes condensate, is a naturally occurring unrefined petroleum product recovered from underground that is used as feedstock by refineries, splitters and petrochemical facilities.

We use the term petroleum products to describe any, or a combination, of the above-noted products. In addition, we handle, store and distribute renewable fuels, such as ethanol and biodiesel.

Description of Our Businesses

REFINED PRODUCTS

Our refined products segment consists of our refined products pipeline system and two marine terminals. Our refined products pipeline system is the longest common carrier pipeline system for refined products and LPGs in the U.S., extending approximately 9,800 miles from the Texas Gulf Coast and covering a 15-state area across the central U.S. The system includes approximately 47 million barrels of aggregate usable storage capacity at 54 terminals. Our Galena Park marine terminal is located along the Houston Ship Channel and has 13 million barrels of wholly-owned storage capacity and one million barrels of storage capacity that we own through a joint venture. Our Pasadena marine terminal, which we own through a joint venture, is also located along the Houston Ship Channel and has storage capacity of five million barrels.

Our refined products segment accounted for the following percentages of our consolidated revenue, operating margin and total assets:

	Year Ended December 31,
	2019	2020	2021
Percent of consolidated revenue	75%	74%	77%
Percent of consolidated operating margin	61%	65%	72%
Percent of consolidated total assets	61%	61%	61%

See Note 4 – Segment Disclosures in the accompanying consolidated financial statements in Item 8 for a description of the non-generally accepted accounting principles (“GAAP”) measure of operating margin and additional financial information about our refined products segment.

Operations. Transportation, Terminalling and Ancillary Services. During 2021, approximately 70% of the refined products segment’s revenue (excluding product sales revenue) was generated from transportation tariffs on volumes shipped on our refined products pipeline system. These transportation tariffs vary depending upon where the product originates, where ultimate delivery occurs and any applicable discounts. All transportation rates and discounts are in published tariffs filed with the Federal Energy Regulatory Commission (“FERC”) or appropriate state agency. Included as part of these tariffs are charges for terminalling and storage of products at 31 of our pipeline system’s 54 terminals. Revenue from terminalling and storage at the other 23 terminals on our refined products pipeline system is derived from privately negotiated rates. Under our tariffs, we are allowed to deduct prescribed quantities of the products our shippers transport on our pipelines, which are commonly referred to as “tender deductions,” to compensate us for lost product during shipment due to metering inaccuracies, intermingling of products between batches (transmix), evaporation or other events that result in volume shortages during the shipment process. In return for these tender deductions, our customers receive a guaranteed delivery of the gross

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volume of products they ship with us, less the amount of our tender deductions, irrespective of the actual amount of product shortages we incur during the shipment process.

In 2021, the products transported on our refined products pipeline system were comprised of 56% gasoline, 38% distillates and 6% aviation fuel and LPGs. Our refined products pipeline system generates additional revenue from providing pipeline capacity and tank storage services, as well as providing services such as terminalling, ethanol and biodiesel unloading and loading, additive injection, custom blending, laboratory testing and data services to shippers, which are performed under a mix of “as needed,” monthly and long-term agreements.

Our marine terminals generate revenue primarily by providing storage and related services, including dock capabilities, pursuant to privately negotiated contracts.

Commodity-Related Activities. Substantially all of the transportation, throughput and storage services we provide are for third parties, and we do not take title to their products. We do take title to products related to tender deductions, product overages, gas liquids blending and fractionation activities. The sales of these products generate product sales revenue.

Our gas liquids blending activity primarily involves purchasing butane and blending it into gasoline, which creates additional gasoline available for us to sell. This activity is limited by seasonal changes in gasoline vapor pressure specifications and by the varying quality of the gasoline delivered to us. When the differential between the cost of gas liquids and the price of gasoline fluctuates, the product margin we earn from these activities is impacted. We generally hedge the economic margin from this blending activity by entering into forward physical or derivative contracts at the time we purchase the related gas liquids. These blending activities accounted for approximately 68% of the total product margin for the refined products segment during 2021.

We also operate three fractionators along our pipeline system that separate transmix into gasoline and diesel fuel. In addition to fractionating the transmix that results from our pipeline operations, we also purchase and fractionate transmix from third parties and sell the resulting refined products.

Product margin from commodity-related activities in our refined products segment was $104.7 million, $98.6 million and $133.8 million for the years ended December 31, 2019, 2020 and 2021, respectively. The amount of margin we earn from these activities and related hedges fluctuates with changes in petroleum prices (see Note 14 –Derivative Financial Instruments to the consolidated financial statements included in Item 8 of this report for further information regarding our hedging activities). Product margin is a non-GAAP financial measure, but its components are determined in accordance with GAAP. Product margin, which is calculated as product sales revenue less cost of product sales, is used by management to evaluate the profitability of our commodity-related activities. The components of product margin included in operating profit, the nearest GAAP measurement, are provided in Note 4—Segment Disclosures to the consolidated financial statements included in Item 8 of this report.

Joint Venture Activities. We own a 50% interest in Powder Springs Logistics, LLC (“Powder Springs”), a joint venture with an affiliate of Colonial Pipeline Company, which owns a gas liquids blending system near Atlanta, Georgia. We serve as operator of the Powder Springs assets.

We own a 50% interest in Texas Frontera, LLC (“Texas Frontera”), a joint venture with an affiliate of Petroleos Mexicanos (PEMEX), which owns approximately one million barrels of storage at our Galena Park terminal. We serve as operator of the Texas Frontera assets.

We own an approximately 25% interest in MVP Terminalling, LLC (“MVP”), a joint venture with an affiliate of Valero Energy Corporation and an undisclosed financial investor. MVP owns a refined products marine storage terminal along the Houston Ship Channel in Pasadena, Texas, including over five million barrels of storage, two ship docks and truck loading facilities. We serve as operator of the MVP assets. See Note 7 - Investments in Non-Controlled Entities to the consolidated financial statements included in Item 8 of this report for further information regarding the sale of a portion of our interest in MVP in 2021.

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Markets and Competition. Shipments originate on our refined products pipeline system from direct connections to refineries or through interconnections with other pipelines or terminals for transportation and ultimate distribution to retail gasoline stations, truck stops, railroads, airports and other end users. Through direct refinery connections and interconnections with other interstate pipelines, our refined products system can access nearly 50% of U.S. refining capacity, and in particular is well-connected to Texas Gulf Coast and Mid-Continent refineries. As a result of its extensive connections to multiple refining regions, our pipeline system is well positioned to accommodate demand or supply shifts that may occur.

Our system is dependent on the ability of refiners and marketers to meet the demand for refined products in the markets they serve through shipments on our pipeline system. Demand for refined products is influenced by many factors, including driving patterns and consumer preferences, economic conditions, population changes, government regulations, changes in vehicle fuel efficiency and development of alternative energy sources. Excluding recent disruptions from the COVID-19 pandemic, demand for refined products in the market areas served by our pipeline system has historically been stable. We generally rely on recent historical trends on our system and third-party forecasts in assessing future refined products demand, and those forecasts vary both by forecaster and by product. While increases in vehicle efficiency and more widespread penetration of electric vehicles are generally expected to reduce demand for gasoline over time, distillate demand is expected to be less affected, while demand for aviation fuel is expected to grow. The most recently published projections by the Energy Information Administration suggest that overall demand for refined products in the areas that include markets served by our pipeline system will remain relatively stable over the next 10 years.

In 2021, approximately 60% of the products transported on our refined products pipeline system originated from direct refinery connections and 40% originated from connections with other pipelines or terminals. Our system is directly connected to and receives product from the following 17 refineries:

Major Origins—Refineries (Listed Alphabetically)

Company	Refinery Location
Cenovus Energy	Superior, WI
CHS	McPherson, KS
CVR Energy	Coffeyville, KS
CVR Energy	Wynnewood, OK
Flint Hills Resources	Pine Bend, MN
HollyFrontier	El Dorado, KS
HollyFrontier	Tulsa, OK
Marathon	St. Paul, MN
Marathon	El Paso, TX
Marathon	Galveston Bay, TX
Par Pacific	Newcastle, WY
Phillips 66	Ponca City, OK
Sinclair	Evansville, WY
Suncor Energy	Commerce City, CO
Valero	Ardmore, OK
Valero	Houston, TX
Valero	Texas City, TX

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Our system is also supplied by connections to multiple pipelines and terminals, including those shown in the table below:

Major Origins—Pipelines and Terminals (Listed Alphabetically)

Pipeline/Terminal	Connection Location	Source of Product
BP	Manhattan, IL	Whiting, IN refinery
CHS	Fargo, ND	Laurel, MT refinery
Delek	El Paso and Odessa, TX	Big Spring, TX refinery
Enterprise	El Dorado, KS	Conway, KS storage
Explorer	Mt. Vernon, MO; Glenpool, OK; Dallas, East Houston and Pasadena, TX	Various Gulf Coast refineries
ExxonMobil	Pasadena, TX	Baytown, TX refinery
Holly Energy Partners	Duncan, OK; El Paso, TX	Big Spring, TX refinery, Artesia, NM refinery
Kinder Morgan	Galena Park and Pasadena, TX	Various Gulf Coast refineries and imports
Magellan	Galena Park, TX	Various Gulf Coast refineries and imports
MVP	Pasadena, TX	Various Gulf Coast refineries and imports
NuStar Energy	Denver, CO; El Dorado, KS; Minneapolis, MN	Various OK & KS refineries, Mandan, ND refinery, McKee, TX refinery
ONEOK	Des Moines, IA; Wayne, IL; Plattsburg, MO	Bushton, KS storage and Chicago, IL area refineries
Phillips 66	Denver, CO; Kansas City, KS; Pasadena, TX; Casper, WY	Borger, TX refinery, various Billings, MT refineries, Sweeney, TX refinery
Shell	East Houston, TX	Deer Park, TX refinery

In certain markets, barge, truck or rail provide an alternative source for transporting refined products; however, pipelines are generally the most reliable, lowest cost, least carbon intensive and safest alternative for refined products movements between different markets. As a result, our pipeline system’s top competitors are other pipelines that serve the same markets.

Competition with other pipeline systems is based primarily on transportation charges, quality of customer service, proximity to end users and long-standing customer relationships. However, given the different supply sources on each pipeline, commodity prices at either the origin or destination point on a pipeline may outweigh transportation costs when customers choose which pipeline to use.

Another form of competition for pipelines is the use of exchange agreements among shippers. Under these agreements, a potential shipper agrees to supply a market near its refinery or terminal in exchange for receiving supply from another refinery or terminal in a different market. These agreements allow the two parties to reduce or eliminate the volumes transported and, therefore, the transportation fees paid to us. We compete with these alternatives through price incentives and through long-term commercial arrangements with potential exchange partners.

Government mandates increasingly require and regulatory incentives promote the use of renewable fuels, including ethanol, biodiesel and other renewable fuels. Pipelines have historically not shipped ethanol or biodiesel in significant quantities, but rather they are typically transported by railroad, truck or barge to terminal facilities where they are then blended into the fuel stream.  The increased use of ethanol and biodiesel has and will continue to compete with shipments on our pipeline system.  Our terminals have the necessary infrastructure to blend ethanol and certain locations blend biodiesel with refined products, and we earn revenue for these services. In addition, we have the potential to and recently began moving blended renewable fuels on our pipeline system in limited quantities.

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Our marine storage terminals compete with other terminals with respect to location, price, versatility and services provided. The competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.

Customers and Contracts. Our refined products pipeline system provides services to several different types of customers, including refiners, wholesalers, retailers, traders, railroads, airlines and regional farm cooperatives. End markets for refined products deliveries are primarily retail gasoline stations, truck stops, farm cooperatives, railroad fueling depots, military bases and commercial airports. Published tariffs serve as contracts, and shippers nominate the volume to be shipped up to a month in advance. In addition, we enter into agreements with shippers that commonly result in payment, volume or term commitments in exchange for reduced tariff rates or expansion capital spending on our part. For 2021, approximately 50% of the shipments on our pipeline system were subject to these supplemental agreements. The average remaining life of these agreements was approximately five years as of December 31, 2021. While many of these supplemental agreements do not represent guaranteed volumes, they do reflect a significant level of shipper commitment to our refined products pipeline system.

For the year ended December 31, 2021, our refined products pipeline system had approximately 60 transportation customers. The top 10 shippers primarily included independent refining companies, integrated oil companies and traders. Revenue attributable to these top 10 shippers for the year ended December 31, 2021 represented 37% of total revenue for our refined products segment and 57% of revenue excluding product sales.

Customers of our marine terminals include refiners, marketers and traders. As of December 31, 2021, approximately 67% of our marine storage capacity available for contract, including the storage capacity of our joint ventures, was subject to agreements with terms in excess of one year or that renew on an annual basis at our customers’ option. The weighted average remaining life of our marine storage contracts was approximately two years as of December 31, 2021. These contracts obligate the customer to pay for terminal capacity reserved even if not used by the customer.

Product sales are primarily to trading and marketing companies active in the markets we serve. These sales agreements are generally short-term in nature.

CRUDE OIL

Our crude oil segment is comprised of approximately 2,200 miles of crude oil pipelines, a condensate splitter and storage facilities with an aggregate storage capacity of approximately 39 million barrels, of which 29 million barrels are used for contract storage. Approximately 1,000 miles of these pipelines, the condensate splitter and 31 million barrels of this storage capacity (including 25 million barrels used for contract storage) are wholly-owned, with the remainder owned through joint ventures.

The joint ventures in our crude oil segment are BridgeTex Pipeline Company, LLC (“BridgeTex”), Double Eagle Pipeline LLC (“Double Eagle”), HoustonLink Pipeline Company, LLC (“HoustonLink”), Saddlehorn Pipeline Company, LLC (“Saddlehorn”) and Seabrook Logistics, LLC (“Seabrook”).

Our crude oil segment accounted for the following percentages of our consolidated revenue, operating margin and total assets:

	Year Ended December 31,
	2019	2020	2021
Percent of consolidated revenue	25%	26%	23%
Percent of consolidated operating margin	39%	35%	28%
Percent of consolidated total assets	34%	35%	35%

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See Note 4 – Segment Disclosures in the accompanying consolidated financial statements in Item 8 for additional financial information about our crude oil segment.

Operations. Our crude oil assets are strategically located to serve crude oil supply, trading and demand centers. Revenue is generated primarily through transportation tariffs on our crude oil pipelines, storage fees from our crude oil terminals, pipeline capacity fees and tolling fees from our condensate splitter. In addition, we earn revenue for ancillary services including terminal throughput fees. We generally do not take title to the products we ship or store for our crude oil customers. Our tariffs provide for tender deductions to compensate us for lost product during shipment due to metering inaccuracies, evaporation or other events that result in volume losses during the shipment process, and we take title to these products. We also take title to products in connection with our crude oil marketing activities.

Our 450-mile Longhorn pipeline has the capacity to transport approximately 275,000 barrels per day (“bpd”) of crude oil from the Permian Basin in West Texas to Houston, Texas. Shipments originate on the Longhorn pipeline via trucks or interconnections with crude oil gathering systems owned by third parties and are delivered to our terminal at East Houston or to various points on the Houston Ship Channel, including multiple refineries connected to our Houston distribution system.

Our East Houston terminal includes approximately nine million barrels of crude oil storage, with approximately six million barrels used for contract storage and three million barrels dedicated to the operation of the Longhorn and BridgeTex pipelines. (See discussion of our BridgeTex joint venture under Joint Venture Activities below). Our East Houston terminal is also connected to our Houston distribution system and to third-party pipelines. Currently, Argus’ West Texas Intermediate (“WTI”) Houston price assessment is based on trades at the terminal, and the terminal is a delivery point for the recently initiated Midland WTI American Gulf Coast futures contract traded on the Intercontinental Exchange.

Our Houston distribution system consists of more than 100 miles of pipeline that connect our East Houston terminal through several interchanges to various points, including multiple refineries throughout the Houston area and crude oil import and export facilities, including through the facility owned by Seabrook discussed below. In addition, it is directly connected to other third-party crude oil pipelines providing us access to crude oil from the Permian and Eagle Ford basins, the strategic crude oil trading hub in Cushing, Oklahoma and crude oil imports.

Our Cushing terminal consists of approximately 13 million barrels of crude oil storage, all of which is used for contract storage. The facility primarily receives and distributes crude oil via the multiple common carrier pipelines that terminate in and originate from the Cushing crude oil trading hub, including the pipeline owned by our Saddlehorn joint venture discussed below, as well as short-haul pipeline connections with neighboring crude oil terminals.

We own approximately 400 miles of pipeline in Kansas and Oklahoma used for crude oil service. A portion of these pipelines is leased to third parties, and we earn revenue from these pipeline segments for capacity leased even if not used by the customers.

Our Corpus Christi terminal includes approximately four million barrels of storage, with a portion used for contract storage and a portion used in conjunction with our Double Eagle joint venture discussed below. This terminal receives product primarily from barges and pipelines that connect to our terminal for further distribution to end users by trucks, pipeline or waterborne vessels. Our 50,000 bpd condensate splitter with approximately two million barrels of related storage is also located at our terminal in Corpus Christi.

Crude Oil Marketing Activities. Our crude oil marketing activities primarily involve purchasing and selling crude oil to be shipped on our Texas crude oil pipelines to facilitate intrastate shipments and maximize profitability on our crude oil pipeline assets. Earnings from these activities are primarily based on the differential in market prices for crude oil between our origin and destination points.

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Joint Venture Activities. We own a 30% interest in BridgeTex, a joint venture with an affiliate of Plains All American Pipeline, L.P. (“Plains”) and an affiliate of OMERS Infrastructure Management Inc. BridgeTex owns an approximately 400-mile pipeline capable of transporting up to 440,000 bpd of Permian Basin crude oil to our East Houston terminal. We serve as the operator of BridgeTex. We also have a long-term lease agreement with BridgeTex to provide it with capacity on our Houston distribution system.

We own a 50% interest in Double Eagle, a joint venture with an affiliate of Kinder Morgan, Inc. (“Kinder”), that transports condensate from the Eagle Ford basin in South Texas via an approximately 200-mile pipeline to our terminal in Corpus Christi or to an inter-connecting pipeline that transports product to the Houston area. An affiliate of Kinder serves as the operator of Double Eagle. We have entered into a terminal throughput agreement which provides Double Eagle access to our Corpus Christi terminal.

We own a 50% interest in HoustonLink, a joint venture with an affiliate of TC Energy Corporation (“TC Energy”). HoustonLink owns a crude oil pipeline connecting TC Energy’s Houston terminal, which is a termination point for TC Energy’s Marketlink pipeline, to our nearby East Houston terminal. We serve as operator of HoustonLink.

We own a 30% interest in Saddlehorn, a joint venture with an affiliate of Plains, an affiliate of Western Midstream Partners, L.P. and an affiliate of Black Diamond Gathering LLC (which is majority-owned by Chevron Corporation). Saddlehorn owns an undivided joint interest in an approximately 600-mile pipeline, capable of transporting up to 290,000 bpd of crude oil from the DJ Basin as well as other Rocky Mountain production regions to storage facilities in Cushing, including our Cushing terminal. We serve as operator of Saddlehorn and also have a long-term agreement to provide storage for Saddlehorn at our Cushing terminal.

We own a 50% interest in Seabrook, a joint venture with an affiliate of LBC Tank Terminals, LLC (“LBC”). Seabrook owns approximately four million barrels of crude oil storage (three million barrels of which is used for contract storage) located in Seabrook, Texas, a pipeline connecting Seabrook’s storage facilities through a third-party pipeline to a Houston-area refinery and another pipeline connecting its facility to our Houston distribution system. LBC serves as operator of the Seabrook terminal and the general and administrative operator of the entity, while we serve as operator of the Seabrook pipelines. In addition, we have a long-term lease agreement with Seabrook that we utilize to provide our customers with crude oil storage capacity and dock access for crude oil imports and exports on the Texas Gulf Coast.

Markets and Competition. Market conditions experienced by our crude oil pipelines vary significantly by location. The Longhorn and BridgeTex pipelines deliver Permian Basin production to trading and demand centers in the Houston area, and consequently depend on the level of production in the Permian Basin for supply. Demand for shipments to the Houston area is driven primarily by the utilization of West Texas crude oil by Gulf Coast refineries and the price for crude oil on the Gulf Coast relative to its price in alternative markets, including export markets. Permian Basin production varies based on numerous factors including overall crude oil prices and changes in costs of production, while Gulf Coast demand for Permian Basin production also fluctuates based on relative prices for competing crude oil or changes by refineries to their crude oil processing slates, as well as by overall domestic and international demand for petroleum products. The Longhorn and BridgeTex pipelines compete with alternative outlets for Permian Basin production, including pipelines that transport crude oil to the Cushing crude oil trading hub as well as other pipelines that transport Permian Basin crude to Houston, Corpus Christi or Nederland. These pipelines also compete with truck and rail alternatives for Permian Basin barrels. Further, these pipelines indirectly compete with other alternatives for delivering similar quality crude oil to the Gulf Coast, including pipelines from other producing regions such as the Mid-Continent, Bakken, Eagle Ford or Gulf of Mexico, as well as waterborne imports. Competition is based primarily on tariff rates, proximity to supply sources and demand centers, connectivity, service offerings, crude quality and customer relationships.

Volumes transported on our Houston distribution system are driven by supply of crude oil delivered into our system from the basins connected by our pipelines or third party pipelines, as well as by takeaway demand from the various connections off our system in the Houston area. Our Houston distribution system competes with other

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distribution systems in the Houston area based primarily on rates, connectivity to supply sources and demand centers, customer service, crude quality and customer relationships.

Our crude oil storage in Cushing serves customers who value Cushing’s location as an interchange point for numerous interstate pipelines, including Saddlehorn, and its status as a crude oil trading hub. Demand for crude oil storage in Cushing could be affected by changes in crude oil pipeline flows that change the volume of crude oil that flows through or is stored in Cushing, as well as by developments of alternative trading hubs that reduce Cushing’s relative importance. In addition, demand for our storage services in Cushing could be affected by crude oil price volatility or price structures or by regulatory or financial conditions that affect the ability of our customers to store or trade crude oil. We compete in Cushing with numerous other storage providers, with competition based on a combination of connectivity, storage rates and other terms, customer service and customer relationships.

The Double Eagle pipeline depends on condensate production from the Eagle Ford basin for its supply and competes primarily with other pipelines and supply alternatives that are capable of transporting condensate from the Eagle Ford production area. Competition is based primarily on tariff rates, connectivity, customer service and customer relationships. Eagle Ford production may vary based on numerous factors including overall crude oil prices and changes in costs of production. Demand for our storage at Corpus Christi is subject to similar market conditions and competitive forces.

Our condensate splitter at our Corpus Christi terminal depends on condensate production and overall demand for products derived from condensate, including naphthas and distillates. Our splitter competes with other facilities in the Gulf Coast region including other splitters and refineries, as well as export alternatives.

The Saddlehorn pipeline depends on crude oil production primarily from the DJ Basin and broader Rocky Mountain region for its supply and competes primarily with other pipelines and supply alternatives that are capable of transporting crude oil from these production areas. Competition is based primarily on tariff rates, connectivity, customer service, crude quality and customer relationships. The demand for Saddlehorn’s services could be affected by changes in DJ Basin crude oil production and additional investment in competing transportation alternatives out of the basin, as well as the status of Cushing as a crude oil trading hub. DJ Basin production may vary based on numerous factors including overall crude oil prices and changes in costs of production.

Customers and Contracts. We ship crude oil as a common carrier for several different types of customers, including crude oil producers and end users, such as refiners and marketing and trading companies, including our marketing affiliate. Published transportation tariffs filed with the FERC or the appropriate state agency serve as contracts to ship on our crude oil pipelines, and shippers nominate volumes to be transported up to a month in advance, with rates varying by origin, destination and product grade. We typically reserve at least 10% of the shipping capacity of our pipelines for spot shippers. Spot barrel movements on our pipelines generally ship at higher rates than those charged to committed shippers. Generally, we seek to secure long-term commitments to support our long-haul crude oil pipeline assets. The majority of the capacity on our Longhorn pipeline is supported by take-or-pay commitments. At December 31, 2021, approximately 75% of the capacity of our Longhorn pipeline was subject to commitments with a weighted average remaining life of approximately six years. Our Houston distribution system is generally not subject to long-term commitments. As of December 31, 2021, approximately 80% of our crude oil storage available for contract was under agreements with terms in excess of one year or that renew on an annual basis at our customers’ option. The weighted average remaining life of our storage contracts was approximately three years as of December 31, 2021. These agreements obligate the customer to pay for storage capacity reserved even if not used by the customer. Our BridgeTex and Saddlehorn joint ventures also have take-or-pay customer commitments. At December 31, 2021, approximately 70% of the capacity of the BridgeTex pipeline was subject to commitments with a weighted average remaining life of four years. At December 31, 2021, approximately 80% of the capacity of the Saddlehorn pipeline was subject to commitments with a weighted average remaining life of five years. Additionally, we have a tolling agreement with one customer for the exclusive use of our condensate splitter in Corpus Christi, the initial term of which expires in 2023.

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GENERAL BUSINESS INFORMATION

Commodity Positions and Hedges

Our policy is generally to purchase only those products necessary to conduct our normal business activities. We generally do not acquire physical inventory, futures contracts or other derivative instruments for the purpose of speculating on commodity price changes. Our gas liquids blending, fractionation and petroleum products marketing activities result in our carrying significant levels of petroleum products inventories. In addition, we hold positions related to tender deductions and product overages. We use forward physical contracts and derivative instruments to hedge against commodity price changes and manage risks associated with our various commodity purchase and sale activities. Our risk management policies and procedures are designed to monitor our derivative instrument positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity to help ensure that our hedging activities address the risks inherent in our commodity positions.

Regulation

Tariff Regulation. Our interstate common carrier pipeline operations are subject to rate regulation by the FERC under the Interstate Commerce Act, the Energy Policy Act of 1992 and related rules and orders. FERC regulation requires that interstate liquids pipeline rates be filed with the FERC, be posted publicly, be “just and reasonable” and not be unduly discriminatory. Rate changes and the overall level of our rates may be subject to challenge by the FERC or shippers. If challenged and the FERC determines that our rates are not “just and reasonable,” we may be required to reduce our rates and pay refunds for up to two years of over-earning. The rates on approximately 30% of the shipments on our refined products pipeline system are regulated by the FERC primarily through an index methodology. For the five-year period beginning July 1, 2021, the indexing method initially provided for annual changes in rates by a percentage equal to the change in the producer price index for finished goods (“PPI-FG”) plus 0.78%. Upon rehearing, the FERC lowered the index to PPI-FG minus 0.21% to be effective March 1, 2022. As an alternative to cost-of-service or index-based rates, interstate liquids pipeline companies may establish rates by obtaining authority to charge market-based rates in competitive markets or by negotiation with unaffiliated shippers. Approximately 70% 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 long-haul crude oil pipelines are established by negotiated rates that provide for annual adjustments in line with changes in the FERC index, subject to certain modifications.

Some shipments on our pipeline systems that move within a single state are considered to be in intrastate commerce. The rates, terms and conditions of service offered by our intrastate pipelines are subject to certain regulations with respect to such intrastate transportation by state regulatory authorities in the states of Colorado, Kansas, Minnesota, Oklahoma, Texas and Wyoming. Such state regulatory authorities could limit our ability to increase our rates or to set rates based on our costs, or could order us to reduce our rates and require the payment of refunds to shippers if our rates are found to have been unjust.

Commodity Market Regulation. Our conduct in petroleum markets and in hedging our exposure to commodity price fluctuations must comply with various laws and regulations that prohibit market manipulation, including those under the Energy Independence and Security Act of 2007 and the Commodity Exchange Act, as well as regulations promulgated by the Commodity Futures Trading Commission and the Federal Trade Commission.

Renewable Fuel Standard.  We are an obligated party under the Renewable Fuel Standard (“RFS”) promulgated by the Environmental Protection Agency (“EPA”) and are required to satisfy our Renewable Volume Obligation (“RVO”) on an annual basis. To meet the RVO, the gasoline we produce in our gas liquids blending activities must either contain the mandated renewable fuel components, or credits must be purchased to cover any shortfall. We generally satisfy our RVO requirements through the purchase of credits, known as Renewable Identification Numbers (“RINs”).  As the RFS program is currently structured, the RVO of all obligated parties may increase over time unless adjusted by the EPA. The ability to incorporate increasing volumes of renewable fuel

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components into fuel products and the availability of RINs may be limited, which could increase our costs to comply with the RFS standards or limit our ability to blend.

Income Taxes. We are a partnership for income tax purposes and therefore are not subject to federal or state income taxes for most of the states in which we operate. The tax on our net income is borne by our unitholders through allocation to them of their share of our taxable income. Net income for financial statement purposes may differ significantly from taxable income allocated to unitholders because of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each unitholder’s tax attributes is not available to us.

As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations and Internal Revenue Service pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, we could be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2019, 2020 and 2021, our qualifying income met the statutory requirement.

Environmental, Maintenance, Safety & Security

General. The operation of our pipeline systems, terminals and associated facilities is subject to strict and complex laws and regulations relating to the protection of the environment, workplace safety and physical and cybersecurity. These laws and regulations govern many aspects of our business including the work environment, the generation and disposal of waste, discharge of process and storm water, air emissions, remediation requirements and facility design requirements to protect against releases into the environment and breaches in the security of our systems. We believe our assets are designed, operated and maintained in material compliance with these laws and regulations.

Environmental. Our estimates for remediation liabilities assume that we will be able to use traditionally acceptable remediation and monitoring methods, as well as associated engineering or institutional controls, to comply with applicable regulatory requirements. These estimates include the cost of performing environmental assessments, remediation and monitoring of the impacted environment such as soils, groundwater and surface water conditions. Our recorded environmental liabilities are estimates and total remediation costs may differ from current estimated amounts.

We may experience future releases of regulated materials into the environment or discover historical releases that were previously unidentified. While an asset integrity and maintenance program designed to prevent, promptly detect and address releases is an integral part of our operations, damages and liabilities arising out of any environmental release from our assets identified in the future could have a material adverse affect on our results of operations, financial position or cash flow.

Liabilities recognized for estimated environmental costs were $13.5 million and $9.8 million at December 31, 2020 and 2021, respectively. Environmental liabilities have been classified as current or noncurrent based on management’s estimates regarding the timing of actual payments. We have insurance policies that provide coverage for remediation costs and certain liabilities arising from sudden and accidental releases of products applicable to all of our assets.

Hazardous Substances and Wastes. Our operations are subject to various laws and regulations that relate to the release of hazardous substances and solid wastes into water or soils. For instance, the Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment.

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Our operations generate wastes, including hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. We are not currently required to comply with a substantial portion of the RCRA requirements as our operations routinely generate only small quantities of hazardous wastes, and we are not a hazardous waste treatment, storage or disposal facility operator that is required to obtain a RCRA hazardous waste permit. While RCRA currently exempts a number of wastes from being subject to hazardous waste requirements, including many oil and gas exploration and production wastes, the EPA could consider the adoption of stricter disposal standards for non-hazardous wastes. Moreover, it is possible that additional wastes, which could include non-hazardous wastes currently generated during operations, may be designated as hazardous wastes. Hazardous wastes are subject to more rigorous and costly storage and disposal requirements than non-hazardous wastes. Changes in the regulations could materially increase our expenses.

We own or lease properties where hydrocarbons have been handled for many years, during which operating and disposal standards have evolved. Although we believe we have utilized operating and disposal practices that at least met prevailing industry standards, hydrocarbons or other wastes may have been disposed of or released on, under or from the properties owned or leased by us or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties were previously operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed of or released by prior owners or operators, to remediate contaminated property, including groundwater contaminated by prior owners or operators, or to make capital improvements to prevent future contamination.

Water Discharges. Our operations can result in the discharge of pollutants, including crude oil and refined products, and are subject to the Oil Pollution Act (“OPA”) and Clean Water Act (“CWA”). The OPA and CWA subject owners of facilities to strict, joint and potentially significant liability for removal costs and certain other consequences of a product spill such as natural resource damages, where the product spills into regulated waters, along federal shorelines or in the exclusive economic zone of the U.S. In the event of a product spill from one of our facilities into regulated waters, substantial liabilities could be imposed. States in which we operate have also enacted similar laws. The CWA imposes restrictions and strict controls regarding the discharge of pollutants into regulated waters. This law and comparable state laws require that permits be obtained to discharge pollutants into regulated waters and impose substantial potential liability for non-compliance. Compliance with these laws is not expected to have a material adverse effect on our business.

Air Emissions. Our operations are subject to the federal Clean Air Act (“CAA”) and comparable state and local laws and regulations, which regulate emissions of air pollutants from various industrial sources, including certain of our facilities, and impose various operating, monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or increase air emissions, obtain and strictly comply with air permits and regulations containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe that our business will not be materially adversely affected by such requirements.

Greenhouse Gas Emissions. The EPA has adopted regulations under existing provisions of the CAA that require certain large stationary sources to obtain pre-construction permits and operating permits for greenhouse gas emissions. In addition, the EPA requires the monitoring and reporting of greenhouse gas emissions from certain large greenhouse gas emissions sources, including petroleum facilities.

Federal and state legislative and regulatory initiatives may attempt to further address climate change or control or limit greenhouse gas emissions. Although it is not possible at this time to predict how they would impact our business, any such future laws or regulations could adversely affect demand for the products that we transport, store and distribute. Depending on the particular programs adopted, they could also increase our costs to operate and

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maintain our facilities by requiring that we measure and report our emissions, install new emission controls on our facilities, acquire allowances to authorize our emissions, pay any taxes related to our emissions and administer and manage an emissions program, among other things. We may be unable to include some or all of such increased costs in the rates charged to our customers and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before the FERC or state regulatory agencies and the provisions of any final legislation or implementing regulations.

Finally, many scientific studies conclude that increasing concentrations of greenhouse gases in the Earth’s atmosphere affect climate changes, which could result in the increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, there may be an increased potential for adverse effects on our business.

Pipeline Safety and Maintenance. Our pipeline systems are subject to regulation by the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”) under the Hazardous Liquid Pipeline Safety Act of 1979, as amended (“HLPSA”). The HLPSA prescribes and enforces minimum federal safety standards for the transportation of hazardous liquids by pipeline, including the design, construction, testing, operation and maintenance, spill response planning and overall reporting and management related to our pipeline facilities. In addition to the amended HLPSA covered in Title 49 of the Code of Federal Regulations, subsequent statutes provide the framework for the pipeline hazardous liquid safety program and include provisions related to PHMSA’s authorities, administration and regulatory activities. Over the past several years, PHMSA has taken steps to expand the regulation of rural gathering lines and impose a number of reporting and inspection requirements on regulated pipelines, and additional requirements are expected in the future. For example, PHMSA is advancing rulemaking regarding rupture detection, the installation of remotely controlled valves on newly constructed or entirely replaced hazardous liquid pipelines, regulations to address idle pipe status and revisions to the required repair criteria for integrity assessments. We believe that compliance with such regulatory changes will not have a material adverse effect on our business.

In addition to regulations applicable to all of our pipelines, we have undertaken additional obligations to mitigate potential risks to health, safety and the environment on our Longhorn pipeline. Our compliance with these incremental obligations is subject to the oversight of the U.S. Department of Transportation through PHMSA.

States are largely preempted by federal law from regulating pipeline safety for interstate lines, but most states are certified by the U.S. Department of Transportation to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include requirements for pipeline or facility design and management.

Our marine terminals along coastal waterways are subject to U.S. Coast Guard regulations and comparable state and municipal statutes relating to the design, installation, construction, testing, operation, replacement and management of these assets.

Safety. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes, which, among other things, require us to organize and disclose information about the hazardous materials used in our operations. Certain parts of this information must be reported to employees, contractors, state and local governmental authorities and local citizens upon request. We are subject to OSHA process safety management regulations and EPA risk management plan rules that are designed to identify and establish procedures to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. Compliance with these laws is not expected to have a material adverse effect on our business.

Security. We are subject to both physical and cybersecurity regulations depending on the nature of the facility. Some of our assets are regulated by the U.S. Department of Transportation, the EPA, the U.S. Coast Guard and the Department of Homeland Security (“DHS”). Compliance with these regulations is achieved by creating physical

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and cybersecurity plans, physical security standards, marine terminal security drills and annual security audits of both marine and DHS-regulated facilities. Compliance with these laws is not expected to have a material adverse effect on our business.

Title or Interest to Real Property Assets

Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property, and in some instances, these rights-of-way have limited terms that may require periodic renegotiation or, if such negotiations are unsuccessful, may require us to seek to exercise the power of eminent domain where such remedy is available. Several rights-of-way for our pipelines and other real property assets are shared with other pipelines and by third parties. In many instances, lands over which rights-of-way have been obtained are subject to prior liens, which may not have been subordinated to the right-of-way grants. We have obtained permits from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets and state highways, and in some instances, these permits are revocable at the election of the grantor. We have also obtained permits or easements from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election. In some cases, properties for pipeline purposes are purchased in fee. In some states and under some circumstances, we have the right of eminent domain to acquire rights-of-way and land necessary for our pipelines. In some circumstances, a pipeline may be categorized as abandoned under certain governmental regulations, which may give rise to claims that the underlying easement(s) or permit(s) have been abandoned as well and may require the removal of our pipelines.

Some of the leases, easements, rights-of-way, permits and licenses that have been transferred to us are only transferable with the consent of the grantor of these rights, which in some instances is a governmental entity. We believe that we have obtained or will obtain sufficient third-party consents, permits and authorizations to operate our business in all material respects.

We believe that we have satisfactory title or interest to all of our real property assets. In some cases, title or interest to our real property assets are subject to encumbrances, such as land use restrictions and/or covenants related to environmental contamination, liens for current taxes and other burdens and easements, restrictions and other encumbrances to which the underlying properties were subject to at the time of acquisition. We do not believe any of these burdens should materially detract from the value of our real property assets or should materially interfere with their use in the operation of our business.

Human Capital

As of December 31, 2021, we had 1,715 employees, primarily concentrated in the central and Gulf Coast regions of the U.S. There were 854 employees assigned to our refined products segment, 253 employees assigned to our crude oil segment and 526 employees assigned to provide G&A services.  We also had 82 employees assigned to our discontinued operations. Approximately 13% of our employees are represented by the United Steel Workers (“USW”) and covered by a collective bargaining agreement that expired at the end of January 2022. We are operating under a 24-hour rolling extension of this agreement while negotiations for a new agreement continue. Management expects that we will be able to successfully negotiate a new long-term agreement with the USW; however, a prolonged work stoppage by a majority of these employees could have a material adverse effect on our business.

We provide a competitive benefits package designed to attract and retain a skilled and diverse workforce. Our benefits package includes access to life and health insurance, paid parental leave, a defined benefit pension plan, a 401(k) plan and participation in our annual incentive program (“AIP”). Our performance-based AIP is intended to encourage all employees to make decisions that support our company’s financial, environmental, safety and cultural metrics. We also provide a long-term incentive plan for our management team and key employees that is aligned with our long-term financial performance.

Investing in employee training and development is crucial to retaining top talent and developing our employees into subject matter experts and leaders who solve challenges, fuel innovation and move our business strategy

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forward. Employees receive training focused on safety, leadership, respect, regulatory compliance and company policies, including our code of ethics and business conduct. In addition, we offer comprehensive on-the-job training programs for facility operations and site specific requirements, to provide our employees the knowledge they need to safely and compliantly operate our assets.

(d) [Reserved.]

(e) Available Information

Our internet address is www.magellanlp.com. We make available free of charge on or through our website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission.

Item 1A. Risk Factors

The nature of our business activities subjects us to a wide variety of hazards and risks. The following is a summary and a description of the most significant risks relating to our business activities that we have identified. In addition to the factors discussed elsewhere in this Annual Report on Form 10-K, you should carefully consider the risks and uncertainties described below, which could have a material adverse effect on our business, which, as used throughout this report, includes our financial condition, our results of operations and our ability to make cash distributions. You should also consider the interrelationship and potential compounding effects if multiple risks are realized. These risks are not the only risks that we face. Our business could be impacted by additional risks and uncertainties not currently known or that we currently believe to be immaterial.

Risk Factor Summary

The following is a summary of the most significant risks relating to our business activities that we have identified. If any of these risks actually occur, our business could be materially adversely affected. For a more complete understanding of our material risk factors, this summary should be read in conjunction with the detailed description of our risk factors which follows this section.

Changes in demand for and supply of petroleum products

•Unfavorable changes in the demand for the petroleum products that we transport, store and distribute could cause our revenue to decline or be more volatile;

•A decrease in crude oil production in the basins served by our crude oil pipelines could reduce our revenues;

•Our business is subject to the risk of capacity overbuilds in the markets in which we operate;

•Decreased activities of producers, gathering systems, refineries and petroleum pipelines owned and operated by others on which we depend to supply our assets could reduce demand for our services;

•A decrease in contract renewals or renewals at lower rates or shorter terms could cause our revenue to

decline or be more volatile.

Commodity price volatility

•Fluctuations in prices of petroleum products that we purchase and sell could adversely affect our results of operations;

•Reduced volatility in energy prices or new government regulations could discourage our storage customers from holding positions in petroleum products;

•The volume of crude oil we transport and the tariff rates we collect for transportation services partially depend upon unpredictable market differentials between the origin and destination points of our pipelines.

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Capital investment and financial risks

•Our distributions and unit repurchases are not guaranteed to occur, and reductions to either may result in a loss of investor confidence and a decrease in the market value of our units;

•Environmental, Social and Governance (“ESG”) investment criteria used by many investors may diminish investor interest in our partnership and reduce the value of our common units and our access to capital;

•We are exposed to counterparty risk and nonpayment or nonperformance by our customers, vendors, joint venture co-owners, lenders or derivative counterparties;

•Expansion projects or acquisitions may encounter unanticipated costs, and expansion projects as well as potential acquisitions or divestitures could experience unanticipated delays or fail to be completed.

Operational hazards

•Our business involves many hazards and operational risks, the occurrence of which could adversely affect our business;

•Failure of critical information technology systems may impact our ability to operate our assets or manage our businesses.

Cyberattacks, terrorism and other external threats

•Cyberattacks and terrorist attacks could result in increased costs or other damage to our business;

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

Regulatory risks

•Our operations are subject to extensive environmental, health, safety and other laws and regulations that

impose significant requirements and costs on us;

•Our customers are subject to extensive environmental, health, safety and other laws and regulations, and any new laws or regulations or changes in the interpretation of existing laws and regulations could result in decreased demand for our services;

•Rate regulation, challenges by shippers of the rates we charge on our pipelines or changes in the jurisdictional characterization of our assets or activities by federal, state or local regulatory agencies may reduce the amount of cash we generate;

•Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the products that we transport, store or distribute.

MLP structural risks

•Our status as a publicly traded partnership prevents our equity from being included in many prominent equity indices, which reduces the demand for our units from passive investment funds. In addition, some individual investors or investment funds may be unable or unwilling to invest in us for reasons related to our status as a partnership for federal income tax purposes.

Tax risks

•Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as the applicable state and local laws of the various jurisdictions in which we conduct business. The IRS could treat us as a corporation, or we could otherwise become subject to a material amount of entity-level taxation for state or local tax purposes.

General risk factors

•Our business could be affected adversely by union disputes and strikes or work stoppages by our unionized employees.

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Risks Related to Our Business

The following is a description of the most significant risks relating to our business activities that we have identified. You should carefully consider the risks and uncertainties described below, which could have a material adverse effect on our business.

Changes in demand for and supply of petroleum products

        Our financial results depend on the demand for the petroleum products that we transport, store and distribute. Unfavorable economic conditions, technological changes, regulatory developments or other factors in the U.S. or global marketplace could result in lower demand for these products for a sustained period of time.

Any sustained decrease in demand for petroleum products in the markets served by our pipelines or terminals could result in a significant reduction in the volume of products that we transport, store or distribute, and thereby reduce our cash flow and our ability to pay distributions. Global economic conditions have from time to time resulted in reduced demand for the products transported and stored by our pipelines and terminals and consequently for the services that we provide. Our financial results may also be affected by uncertain or changing economic conditions within certain regions or by supply or demand shifts between regions. If economic and market conditions remain uncertain or adverse conditions persist for an extended period, we could experience adverse impacts to our business.

Other factors that could lead to a decrease in demand for the petroleum products we transport, store and distribute include:

•an increase in the use of alternative sources of energy transportation, including but not limited to electric and battery-powered motors, natural gas, hydrogen and renewable fuels such as ethanol, biodiesel and renewable diesel. Several governments and automobile manufacturers have announced plans to significantly reduce or eliminate the use of traditional petroleum fuel powered vehicles, and significant increases in the production of electric vehicles are widely expected. In addition, current U.S. laws and regulations require an increase in the quantity of ethanol, biodiesel and other qualifying renewable fuels used in transportation fuels. Increases in the use of such alternative fuels could have a material adverse impact on the volume of petroleum-based fuels transported, stored or distributed on our pipelines or terminals;

•an increase in transportation fuel economy, whether as a result of a shift by consumers to more fuel-efficient vehicles, technological advances by manufacturers or federal, state or international regulations. Government regulations require increasing improvements in fuel economy standards. These standards are intended to reduce demand for petroleum products and could reduce demand for our services;

•changes in population or changes in consumer preferences, rates of automobile ownership or driving patterns in the markets we serve;

•an increase or decrease in the market prices of petroleum products, which may reduce supply or demand. Petroleum product prices have been volatile in recent years, and that volatility may continue in ways that we are unable to predict;

•higher fuel taxes, including carbon tax, or other governmental or regulatory actions that increase the cost of the products we handle; and

•lower exports of petroleum products to global markets resulting from weak economic conditions, regulatory restrictions, changing preferences for the type of petroleum products we export or preferences for alternative energy sources.

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        A decrease in crude oil production in the basins served by our crude oil pipelines could adversely impact our business.

Numerous factors can cause reductions in crude oil production in the regions served by our pipelines, including, among other factors, lower overall crude oil prices, regional price or product quality differences, higher costs of crude oil production, exhaustion of reserves, weather or other natural causes, epidemics, adverse regulatory or legal developments, disruptions in financial or credit markets that inhibit production, or lower overall demand for crude oil and the products derived from crude oil. Crude oil prices have historically exhibited significant volatility and are influenced by, among other factors, worldwide and domestic supplies of and demand for crude oil, political and economic developments in often-volatile producing regions, actions taken by OPEC and other non-OPEC countries with large production capacity, technological developments, government regulations, taxes, policies regarding the importing and exporting of crude oil and conditions in global financial markets.

We are unable to predict future prices of crude oil or what impact the crude price environment will have on future production overall or specifically on production in the basins we serve. Lower production in the regions served by our pipelines could result in lower shipments of uncommitted volume or could cause us to be unable to renew our contracts at existing volumes or rates. A significant reduction in the volume of products that we transport or the rates we are able to charge for such transportation services or both could adversely impact our business.

        Our business is subject to the risk of capacity overbuilds in the markets in which we operate.

We and our joint ventures have made significant investments in new energy infrastructure to meet market demand, as have several of our competitors. The increased infrastructure investments combined with production declines in key basins served by our pipelines has resulted in take away capacity that significantly exceeds current and future estimated production. For example, excess capacity has created a highly competitive environment that has decreased the crude oil price differential between the Permian Basin and end markets, including Houston, which has reduced the demand for our services resulting in decreases to volumes transported and lower rates we are able to charge to our customers. When infrastructure investments in the markets we serve, including our own investments, result in capacity that exceeds the demand in those markets, our facilities could be underutilized, and we could be forced to reduce the rates we charge for our services, which could adversely affect our business.

        We depend on producers, gathering systems, refineries and pipelines owned and operated by others to supply our assets, and any closures, interruptions or reduced activity levels at these facilities may adversely affect our business.

We depend on crude oil production and on connections with gathering systems, refineries and petroleum pipelines owned and operated by third parties to supply our assets. We cannot control or predict the amount of crude oil that will be delivered to us by the gathering systems and pipelines that supply our crude oil assets, nor can we control or predict the output of refineries that supply our refined products pipelines and terminals. Changes in the quality or quantity of this crude oil production, outages at these refineries or reduced or interrupted throughput on these gathering systems or pipelines due to weather-related or other natural causes, competitive forces, testing, line repair, damage, reduced operating pressures or other causes could reduce shipments on our pipelines or result in our being unable to receive products at or deliver products from our terminals or receive products for processing at our condensate splitter, any of which could adversely affect our business.

Refineries that supply or are supplied by our facilities are subject to regulatory developments, including but not limited to low carbon fuel standards, regulations regarding fuel specifications, plant emissions and safety and security requirements that could significantly increase the cost of their operations and reduce their operating margins. In addition, the profitability of the refineries that supply our facilities is subject to regional and global supply and demand dynamics that are difficult to predict. A period of sustained weak demand or increased costs could make refining uneconomic for some refineries, including those directly or indirectly connected to our refined products and crude oil pipelines. The closure of a refinery that delivers product to or receives crude from our pipelines could reduce the volumes we transport. Further, the closure of these or other refineries could result in our

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customers electing to store and distribute petroleum products through their proprietary terminals, which could result in a reduction in demand for our storage services.

        A decrease in contract renewals or renewals at lower rates or shorter terms could cause our revenue to decline or be more volatile, which could adversely impact our business.

A significant portion of the revenue we earn from transportation, storage and processing services is received pursuant to multi-year contracts negotiated with our customers. Many of those contracts require our customers to pay for our services regardless of market conditions during the contract period. Changing market conditions, including changes in petroleum product supply or demand patterns, competitive factors, forward-price structure, financial market conditions, regulations, accounting rules or other factors could cause our customers to be unwilling to renew their contracts with us when those contracts terminate, or make them willing to renew only at lower rates or for shorter contract periods. Failure by our customers to renew any of their contracts with us on terms and at rates substantially similar to our existing contracts could result in lower utilization of our assets or cause our revenues to decline or be more volatile, any of which could adversely affect our business.

Commodity pricing volatility

        We hedge our exposure to price fluctuations for our petroleum products purchase and sale activities by utilizing physical purchase and sale agreements and derivatives. These hedging arrangements do not eliminate all price risks, and fluctuations in prices of petroleum products that we purchase and sell could adversely affect our business. Further, non-compliance with our risk management policies and procedures could adversely affect our business.

We purchase and sell commodities related to our gas liquids blending, fractionation and petroleum products marketing activities, as well as product generated by the operations of our pipelines and terminals. We also maintain product inventory related to these activities. Significant fluctuations in market prices of petroleum products could result in material unrealized gains or losses on transactions we enter to hedge our exposure to commodity price changes. To the extent these hedges do not qualify for hedge accounting treatment or are not designated as hedges, or if they result in material amounts of ineffectiveness, we could experience material fluctuations in our results of operations. In addition, significant fluctuation in market prices of petroleum products could result in material losses or lower profits from these activities.

Our product purchases, sales and hedging operations involve the risk of non-compliance with our risk management policies. We cannot assure that our processes and procedures will detect and prevent all violations of our risk management policies, particularly if deception or other intentional misconduct is involved. Such violations could result in material losses. Further, our requirement to post material amounts of margin in connection with our hedges could negatively impact our liquidity and our ability to pay distributions to our unitholders.

        Reduced volatility in energy prices or new government regulations could discourage our storage customers from holding positions in petroleum products, which could adversely affect our business.

The demand for our storage services has resulted in part from our customers’ desire to have the ability to take advantage of profit opportunities created by the volatility in prices of petroleum products. Periods of prolonged stability in petroleum product prices or trends of declining prices could reduce demand for our storage services. If federal, state or international regulations are passed that discourage our customers from storing these commodities, demand for our storage services could decrease, in which case we may be unable to identify customers willing to contract for such services or be forced to reduce the rates we charge for our services. The realization of any of these risks could adversely affect our business.

        The volume of crude oil we transport and the tariff rates we collect for transportation services partially depend upon unpredictable market differentials between the origin and destination points of our pipelines.

Our tariff rates are established in accordance with federal and state regulations which, in general, permit us to negotiate rates with shippers so long as such negotiated rates are not unduly discriminatory among similarly situated shippers. Applicable regulations and our obligations to certain classes of committed shippers may limit our ability to change our tariff rates. When the difference in market prices for crude oil between our origin points and our

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destination points is lower than our tariff rates, the volume of product we transport could decline or the revenue we collect could decrease. For example, when the posted tariff rate for transportation on the Longhorn pipeline is higher than the market differential, as experienced in 2020 and 2021, it is uneconomical for shippers to use Longhorn to move volumes from the Permian Basin to Houston. As a result, we experience lower revenues during such periods, which adversely impacts our business.

Capital investment and financial risks

        Our distributions and unit repurchases are not guaranteed to occur, and reductions to either may result in a loss of investor confidence and a decrease in the market value of our units.

Neither our distributions nor any unit repurchases are guaranteed to occur. The cash that we generate from operations could decrease or fail to meet expectations, either of which could reduce our ability to pay distributions and repurchase our common units.

The amount of cash we can distribute to our unitholders principally depends upon the cash we generate from our operations, and the amount of cash we generate from operations is affected by numerous factors beyond our control, fluctuates from quarter to quarter and may change over time. Significant or sustained reductions in the cash generated by our operations would reduce our ability to pay distributions.

Additionally, our board has authorized the repurchase of our common units for the next several years. Our unit repurchase program does not obligate us to acquire a specific number of units during any period, and our decision to commence, discontinue or resume repurchases in any period will depend on many factors, including our expected expansion capital spending, excess cash available, balance sheet metrics, legal and regulatory requirements, market conditions and the trading price of our units. Any failure to pay distributions at expected levels or the discontinuation of our unit repurchase program could result in a loss of investor confidence and a decrease in our unit price.

        ESG investment criteria used by many investors may diminish investor interest in our partnership and reduce the value of our common units and our access to capital.

Investor advocacy groups, certain institutional investors and many investment funds have increased their focus on ESG-related criteria in recent years. In particular, numerous investment firms, banks, insurance companies and other financial institutions have made pledges to reduce their carbon emissions, which in many cases may involve their reducing or eliminating their investments in organizations involved in the production, transport and use of fossil fuels. In connection with this trend, investor demand for and valuation of our common units may decline, and our access to the debt and equity capital necessary to finance our growth projects and to refinance our existing debt obligations when due may be reduced, either of which would adversely affect our business.

        We do not have the same flexibility as other types of organizations to accumulate cash and retained earnings to protect against illiquidity in the future, and we rely on access to capital to fund acquisitions and growth projects and to refinance existing debt obligations. Unfavorable developments in capital markets could limit our ability to obtain funding or require us to secure funding on terms that could limit our financial flexibility, reduce our liquidity, dilute the interests of our existing unitholders and otherwise adversely affect our business.

Our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash, after taking into account reserves established by our board for commitments and contingencies, including capital investments, operating costs and debt service requirements. We do not accumulate equity in the form of retained earnings in a manner typical of many other forms of organization, including most traditional public corporations, and so are more likely than those organizations to require issuances of additional debt or equity to provide liquidity and capital resources.

We consider and pursue growth projects and acquisitions as part of our efforts to increase cash available for distribution to our unitholders. These transactions may occur at any time and may be significant in size relative to our existing assets and operations. We generally do not retain sufficient cash flow to finance growth projects or acquisitions, and consequently we require access to external sources of capital to finance our growth capital

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spending. Similarly, we generally do not retain sufficient cash flow to repay our indebtedness when it matures, and we rely on new capital to refinance these obligations. Limitations on our access to capital, including on our ability to issue additional debt and equity, could result from events or causes beyond our control, and could include, among other factors, decreases in our creditworthiness or profitability, significant increases in interest rates, increases in the risk premium generally required by investors or in the premium required specifically for investments in energy-related companies or master limited partnerships, and decreases in the availability of credit available for organizations involved with carbon-based fuels or the tightening of terms required by lenders. Any limitations on our access to capital on satisfactory terms could impair our ability to execute on our strategies and meeting debt obligations, resulting in the dilution of the interests of our existing unitholders, and adversely impact our business.

        We are exposed to counterparty risk and nonperformance by our customers, vendors, joint venture co-owners, lenders or derivative counterparties could materially reduce our revenue, increase our expenses, impair our liquidity or otherwise negatively impact our business.

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers to whom we extend credit. In addition, we frequently undertake capital expenditures based on commitments from customers from which we expect to realize the expected return on those expenditures, including take-or-pay commitments from our customers. Nonperformance by our customers of those commitments could result in substantial losses to us. Nonperformance by customers who back our growth projects could significantly impact our expected return from those projects.

We have numerous joint ventures that require cooperation with and performance by co-owners. Nonperformance by our joint venture co-owners could result in increased costs or delays that could decrease our returns on our joint ventures.

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

We also rely to a significant degree on the banks that lend to us under our revolving credit facility for financial liquidity, and any failure of those banks to perform on their obligations to us could significantly impair our liquidity. Furthermore, nonpayment by the counterparties to our interest rate and commodity derivatives could expose us to additional interest rate or commodity price risk. Any substantial increase in the nonpayment or nonperformance by our customers, vendors, lenders or derivative counterparties could have an adverse effect on our business.

        Changes in price levels could negatively impact our revenue, our expenses, or both, which could adversely affect our business.

The operation of our assets and the execution of expansion projects require significant expenditures for labor, materials, property, equipment and services. Recent inflationary pressures in the U.S. could materially increase our expenses or capital costs, and we may not be able to pass these increased costs to our customers in the form of higher fees for our services. Because we use the FERC’s PPI-based price indexing methodology to establish tariff rates in certain markets served by our pipelines, our revenues are impacted by changes in price levels. In periods of general price deflation, the ceiling level provided by the FERC’s index methodology could decrease requiring us to reduce our index-based rates, even if the actual costs we incur to operate our assets increase. Changes in price levels that lead to decreases in our revenue or increases in the prices we pay to operate and maintain our assets could adversely affect our business.

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         Expansion projects or acquisitions may encounter unanticipated costs, and expansion projects as well as potential acquisitions or divestitures could experience unanticipated delays or fail to be completed.

We may pursue expansion projects or acquisitions that require us to make significant capital investments, which could include new borrowings necessary to finance the projects. As a result, our indebtedness relative to our earnings could increase, particularly in situations where our expansion projects or acquisitions do not meet our earnings projections. Acquisitions and expansion projects involve numerous risks, including difficulties in the assimilation of the related assets and operations, inefficiencies and difficulties that arise due to unfamiliarity with the new assets and the businesses or geographic areas associated with them, as well as the diversion of management’s attention from other business concerns. Unexpected costs and other challenges may arise whenever new assets are put in service or businesses with different operations or management are combined, and we may discover previously unknown liabilities associated with assets or businesses we acquire.

Expansion projects typically require us to secure and retain required permits and rights-of-way in order to complete and operate the new infrastructure, and our inability to do so in a timely manner could result in significant delays or cost overruns. Our ability to secure required permits and rights-of-way or otherwise proceed with construction of our expansion projects could also encounter opposition from political activists, who may attempt to delay energy infrastructure construction through protests, lawsuits and other means. In addition, acquisitions and divestitures typically involve extensive negotiations and numerous conditions that must be met by us and our transaction counterparties before a transaction can be completed, often including review by government agencies such as the Federal Trade Commission or other approval or consent processes over which we may have no control. The failure to meet these conditions could result in significant delays to such transactions or prevent their being completed entirely.

Any cost overruns or unanticipated delays in the completion or commercial development of our expansion projects or acquisitions could reduce the anticipated returns on these investments, and any delay or failure to complete acquisitions or divestitures could interfere with our capital allocation priorities or otherwise adversely affect our business.

        The amount and timing of distributions to us from our joint ventures is not entirely within our control, and we may be unable to cause our joint ventures to take or refrain from taking certain actions in accordance with our best interests.

As of December 31, 2021, we were engaged in eight joint ventures, all of which are in the form of limited liability companies (“LLC”), in which we share control with other entities according to the relevant joint venture agreements. Those agreements provide that the respective LLC management committees, including our representatives along with the representatives of the other owners of those LLCs, determine the amount and timing of distributions. Our joint ventures may establish separate financing arrangements that contain restrictive covenants that may limit or restrict the LLC’s ability to make distributions to us under certain circumstances. Any inability to generate cash or restrictions on distributions we receive from our joint ventures could materially impair our results. In addition, if we are unable to agree with our joint venture co-owners on a significant matter, it could result in delays, litigation or operational impasses that could result in a material adverse effect on that joint venture’s business. If the matter is significant to us, it could result in an adverse effect on our business.

Operational hazards

        Our business involves many hazards and operational risks, and measures to maintain our physical assets may not be adequate. The occurrence of a significant event or accident, or non-compliance with our policies and procedures could adversely affect our business.

Our operations are subject to many hazards inherent in the transportation and distribution of petroleum products, including releases and fires. In addition, our operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and earthquakes. The risk of natural disasters and other operational risks could result in material losses due to personal injury or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage, and may result in curtailment or suspension of our related operations. Some of our assets are located in or near high consequence areas such as residential and

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commercial centers or sensitive environments, and the potential damages are even greater in these areas. We utilize operational and safety policies and procedures, risk management systems and technologies to manage the physical asset risks associated with our pipeline systems and storage tanks. Failure of those management systems and technologies, non-compliance with policies or failure to otherwise adequately monitor and maintain the condition of our assets could compromise integrity and result in increased maintenance or remediation expenditures and an increased risk of product releases and associated costs and liabilities. Any significant event or accident could adversely affect our business.

        Our insurance coverage may not be adequate to cover losses sustained, and we may experience increased costs and decreased availability of insurance options.

We are not fully insured against all hazards or operational risks related to our businesses, and the insurance we carry requires that we meet certain deductibles before we can collect for any covered losses we sustain. If a significant accident or event occurs that is not fully insured, it could adversely affect our business.

Premiums and deductibles for our insurance policies could escalate as a result of market conditions or losses experienced by us or by other companies. In some instances, insurance could become unavailable or available only for reduced amounts of coverage. Increases in the cost of insurance or the inability to obtain insurance at rates that we consider commercially reasonable could adversely affect our business.

        Failure of critical information technology systems may materially impact our ability to operate our assets or manage our businesses.

We utilize information technology systems to operate our assets and manage our businesses. Some of these systems are proprietary systems that require specialized programming capabilities, while others are based upon or rely on technology that has been in service for many years. Failures of these systems could result in a failure of critical operational or financial controls and lead to a disruption of our operations, commercial activities or financial processes. Such failures could adversely affect our business.

Cyberattacks, terrorism and other external threats

        Cyberattacks or other information security breaches that circumvent security measures taken by us or others with whom we conduct business or share information could result in increased costs, interruptions or other damages to our business.

We rely on our information technology infrastructure to process, transmit and store electronic information, including data we use to operate our assets. In addition, we rely on third-party systems, including for example the electric grid and cloud-based software services, which could also experience security breaches or cyberattacks, and the failure of which could have a material adverse effect on the operation of our assets. We and our third-party providers face cybersecurity and other security threats to our information technology infrastructure, including threats to our control systems and safety systems that operate our pipelines and other assets. We could face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from state-sponsored groups, “hacktivists” or private individuals. The threat of terrorist attacks subjects our operations to increased risks and increased costs as new regulations require us to work with government agencies to verify our information technology systems are sufficiently designed to prevent and deter attacks against our assets. We could also face attempts to obtain unauthorized access by targeted acts of deception against individuals with legitimate access to physical locations or information.

Breaches in our information technology infrastructure or physical facilities, or other disruptions including those arising from theft, vandalism, fraud or unethical conduct, could result in damage to our assets, business interruptions, mitigation expense, safety incidents, damage to people, property and the environment, reputational damage, potential liability or the loss of contracts, and could adversely affect our business.

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        Terrorist attacks aimed at our facilities or that impact our customers or the markets we serve could adversely affect our business.

The U.S. government has issued warnings that energy assets in general, and the nation’s pipeline and terminal infrastructure in particular, may be targets of terrorist organizations. Any terrorist attack on our facilities, those of our customers or, in some cases, on energy infrastructure owned by others, could have a material adverse effect on our business. Similarly, any terrorist attack that severely disrupts the markets we serve could adversely affect our business.

        The COVID-19 pandemic and government responses thereto have adversely affected and could continue to adversely affect our business.

The COVID-19 pandemic has negatively impacted the global economy. In response to the pandemic, governments around the world implemented stringent measures to reduce the spread of the virus, including stay-at-home orders, travel restrictions, vaccine mandates, workplace safety measures and other regulations. As a result of the pandemic and these measures, economic activity has declined around the world resulting in reduced demand for petroleum products, which adversely affected our business. It is difficult to predict the impact of further variants or outbreaks or government responses thereto on economic activity or our operations, either of which could adversely affect our business.

Regulatory risks

        Our operations are subject to extensive environmental, health, safety and other laws and regulations that impose significant requirements, costs and liabilities on us. These requirements, costs and liabilities could increase as a result of new laws or regulations or changes in the interpretation, implementation or enforcement of existing laws and regulations. Our customers are also subject to extensive environmental, health, safety and other laws and regulations, and any new laws or regulations or changes in the interpretation, implementation or enforcement of existing laws and regulations, including laws and regulations related to hydraulic fracturing, could result in decreased demand for our services.

Our operations are subject to extensive federal, state and local laws and regulations relating to the protection or preservation of the environment, natural resources and human health and safety, including but not limited to the CAA, RCRA, OPA, CWA, CERCLA, HLPSA, Endangered Species Act (“ESA”), Migratory Bird Treaty Act (“MBTA”), the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 and OSHA. Such laws and regulations affect almost all aspects of our operations and generally require us to obtain and comply with various environmental registrations, licenses, permits, credits, inspections and other approvals. We incur substantial costs to comply with these laws and regulations, and any failure to comply may expose us to civil, criminal and administrative fees, fines and penalties and interruptions in our operations that could have an adverse impact on our business. For example, if an accidental release or spill of petroleum products, chemicals or other hazardous substances occurs at or from our pipelines, storage or other facilities, we may experience significant operational disruptions, and we may have to pay a significant amount to remediate the release or spill, pay government penalties, address natural resource damages, compensate for human exposure and property damage, install costly pollution control equipment or undertake a combination of these and other measures. The resulting costs and liabilities could adversely affect our business. In addition, emission controls required under the CAA and other similar laws could require significant capital expenditures at our facilities.

Liability under such laws and regulations may be incurred without regard to fault, including latent conditions that we did not cause. Private parties, including the owners of properties through which our pipelines pass, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with such laws and regulations or for personal injury or property damage. Our insurance does not cover all environmental risks and costs, including potential fines and penalties, and may not provide sufficient coverage in the event an environmental claim is made against us.

The laws and regulations that affect our operations, and the enforcement thereof, have become increasingly stringent over time. These laws and regulations may be further revised or new laws or regulations may be adopted or become applicable to us. For instance, in 2021 the Transportation Security Administration released new pipeline

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cybersecurity directives requiring mitigation measures to protect against attacks on information technology and operational technology systems and the development and implementation of a cybersecurity contingency and recovery plan. In 2019, PHMSA modified its existing hazardous liquid pipeline regulations, requiring integrity assessments at least once every 10 years for pipeline segments located outside of high consequence areas (“HCAs”) and requires all pipelines in HCAs to be capable of accommodating in-line inspection tools within 20 years. In addition, changes in permitting processes, such as the Nationwide Permit Program under the CWA, could impact our ability to develop new projects or maintain our existing assets. Compliance with such legislative and regulatory changes could increase our compliance costs, make it more difficult to construct or maintain our assets and have an adverse effect on our business.

Our customers are also subject to extensive laws and regulations, and new laws or regulations could adversely affect their businesses. For example, several of our most significant customers operate refineries that could be significantly impacted by changes in environmental or health-related laws or regulations. In addition, we have made significant investments in crude oil and condensate storage and transportation projects that serve customers that largely depend on production techniques, such as hydraulic fracturing, that have been scrutinized by governmental authorities and have encountered political opposition that could result in increased regulatory costs and restrictions. Any changes in laws or regulations, or in the interpretation, implementation or enforcement of existing laws and regulations, that impose significant costs or liabilities on our customers could reduce demand for our services and adversely affect our business.

        Rate regulation, challenges by shippers of the rates we charge for transportation on our pipelines or changes in the jurisdictional characterization of our assets or activities by federal, state or local regulatory agencies may reduce the amount of cash we generate.

The FERC regulates the rates we can charge and the terms and conditions we can offer for interstate transportation service on our pipelines. State regulatory authorities regulate the rates we can charge and the terms and conditions we can offer for intrastate movements on our pipelines. The determination of the interstate or intrastate character of shipments on our pipelines may change over time, which may change the regulatory framework and the rates we are allowed to charge for transportation and other related services. Shippers may protest our pipeline tariff filings, and the FERC or state regulatory authorities may investigate and require changes to tariff terms as a result of the protests or complaints. Further, other than for rates set under market-based rate authority, the FERC may order refunds of amounts collected under interstate rates that are determined to be in excess of a just and reasonable level. State regulatory authorities could take similar measures for intrastate tariffs. In addition, shippers may challenge by complaint the lawfulness of tariff rates that have become final and effective. If existing rates are determined to be in excess of a just and reasonable level, we could be required to pay refunds to shippers, reduce rates and make other concessions.

The FERC’s ratemaking methodologies may limit our ability to set rates based on our actual costs or may delay the use of rates that reflect increased costs. The FERC’s primary ratemaking methodology applicable to us is price indexing. We use this methodology to establish our rates in approximately 30% of the markets serviced by our refined products pipelines. The FERC’s indexing methodology is subject to review every five years and currently allows a pipeline to change its rates each year to a new ceiling level, which is calculated as the previous year’s ceiling level multiplied by a percentage. When the ceiling level is negative, we are required to reduce our rates that are subject to the FERC’s price indexing methodology.

The FERC and most relevant state regulatory authorities allow us to establish rates based on conditions in competitive markets without regard to the FERC’s index level or our cost-of-service. We establish market-based rates in approximately 70% of the markets for our refined products pipelines. The tariffs on most of our crude oil pipelines are at negotiated rates, but are still subject to regulation by the FERC or state agencies and subject to protest by shippers. If we were to lose our market-based rate authority, or if our negotiated rates were determined to not be just and reasonable, we could be required to establish rates on some other basis, such as our cost-of-service. Establishing our rates through a cost-of-service filing could be expensive, unsuccessful, or result in tariff reductions, which could adversely affect our business.

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        Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the products that we transport, store or distribute.

Federal and state legislative and regulatory initiatives in the U.S., as well as those in other countries, have attempted to and will continue to address climate change and control or limit greenhouse gas emissions. Although it is not possible to predict how they will impact our business, any such laws or regulations could adversely affect demand for the products that we transport, store and distribute. Depending on the particular programs adopted, they could also increase our costs to operate and maintain our facilities by requiring that we measure and report our emissions, install new emission controls on our facilities, acquire allowances to authorize our emissions, pay taxes related to our emissions and administer and manage an emissions program, among other things. We may be unable to include some or all of such increased costs in the rates charged to our customers and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before the FERC or state regulatory agencies and the provisions of any final legislation or implementing regulations.

Finally, certain scientific studies conclude that increasing concentrations of greenhouse gases in the Earth’s atmosphere affect climate changes and that such changes could result in the increased frequency and severity of storms, floods and other climatic events. If any such effects occur, there may be adverse effects on our business.

        Our gas liquids blending activities subject us to federal regulations that govern renewable fuel requirements in the U.S.

The Energy Independence and Security Act of 2007 expanded the required use of renewable fuels in the U.S. Each year, the EPA establishes an RVO requirement for refiners and fuel manufacturers based on overall quotas established by the federal government. By virtue of our gas liquids blending activity and resulting gasoline production, we are an obligated party and receive an annual RVO from the EPA. We typically purchase renewable energy credits, called RINs, to meet this obligation. RINs are generated when a gallon of renewable fuels such as ethanol or biodiesel is produced. RINs may be separated when the renewable fuel is blended into gasoline or diesel, at which point the RIN is available for use in compliance or is available for sale on the open market. Increases in the cost or decreases in the availability of RINs could have an adverse impact on our business.

        Our business is subject to federal, state, local and international laws and regulations that govern the quality specifications of the petroleum products that we store, transport or sell.

Petroleum products that we store and transport are sold by our customers for consumption into the public market. Various federal, state and local agencies, as well as international regulatory bodies, have the authority to prescribe specific product quality specifications for commodities sold into the public market. Changes in product quality specifications or blending requirements could reduce demand, reduce our throughput volume, require us to incur additional handling costs or require capital expenditures. For instance, different product specifications for different markets impact the fungibility of the products in our system and could require the construction of additional storage. If we are unable to recover these costs through increased revenue, our business could be adversely affected.

In addition, changes in the quality of the products we receive on our pipelines, or changes in the product specifications in the markets we serve, could reduce or eliminate our ability to blend products, which would result in a reduction of our revenue and operating profit from blending activities. Any such reduction of our revenue or operating profit could have an adverse effect on our business.

        We do not own all of the property on which our pipelines and facilities are located, and we rely on securing and retaining adequate rights-of-way and permits in order to operate our existing assets and complete growth projects.

We do not own all of the land on which our pipelines and facilities are located. As such, we are subject to the possibility of increased costs to retain necessary land use. We typically obtain the rights to construct and operate our pipelines on land owned by third parties and sometimes those rights are only for a specific period of time and may result in decommissioning or new acquisition costs when our rights expire. In addition, some of our facilities cross Native American lands pursuant to rights-of-way of limited terms. We may not be able to utilize the right of eminent

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domain in some jurisdictions and in some circumstances, such as land owned by Native American tribes or other government entities. Our ability to secure required permits and rights-of-way or otherwise proceed with construction of our new projects could encounter opposition from activists who may attempt to delay construction through protests and other means. The loss of these rights, through our inability to acquire or renew right-of-way contracts or otherwise, could have an adverse effect on our business.

MLP structural risks, including risks to unitholders

        Our status as a partnership prevents our equity from being included in many prominent equity indices, which reduces the demand for our units from passive investment funds. In addition, some individual investors or investment funds may be unable or unwilling to invest in us for reasons related to our status as a partnership for federal income tax purposes. Limitations on the demand for our units because we are a partnership could affect the trading liquidity and valuation of our units and could make it more difficult for us to raise funds by issuing additional equity.

Because we are a partnership for federal income tax purposes, we are a pass-through entity and are not generally subject to entity-level taxation, and distributions to our unitholders are not taxed as dividends. Instead, our unitholders are treated as partners and allocated their proportionate share of our income, which is reported to them on schedule K-1 and which could subject them to other taxes, including state and local taxes imposed by the jurisdictions in which we conduct business. This taxation and reporting arrangement is different from and less common than the arrangement that prevails among most publicly traded companies and may create complexities that could discourage some investors or investment funds from investing in us. In addition, the methodologies of most indices of publicly traded equities exclude publicly traded partnerships, and as a result many passive investment funds are prevented from investing in our equity. The inability or unwillingness of individual investors or investment funds to invest in us reduces demand for our units. This lower demand could result in lower trading liquidity in our equity, which could in turn cause greater volatility in our unit price, a lower unit price, or both. In addition, a reduction in demand for our units could make it less possible or less attractive for us to raise funds through issuances of additional equity, which could in turn reduce our financial flexibility or raise our cost of capital. Our status as a publicly traded partnership is required by our partnership agreement and can only be changed by a vote of our unitholders. A majority of our unitholders may prefer and our management may estimate and advise our unitholders that it is in their best interest that we continue to benefit from the tax attributes of a publicly traded partnership despite these potential impacts of lower demand for our units on our trading liquidity or valuation.

        Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units and has other governance differences from typical corporations.

Unitholders’ voting rights are restricted by a provision in our partnership agreement stating that any units held by a person that owns 20% or more of any class of our common units then outstanding, other than our general partner and its affiliates, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence our management. As a result of this provision, the trading price of our common units may be lower than other forms of equity ownership due to the absence of a takeover premium in the trading price or other governance differences.

        Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Our unitholders could be liable for any and all of our obligations as if they were a general partner if a court or government agency were to determine that we were conducting business in a state but had not complied with that particular state’s partnership statute. Our unitholders’ rights to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement may constitute

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“control” of our business which could result in our unitholders being liable for all of our obligations as if they were a general partner.

        Our partnership agreement replaces our general partner’s fiduciary duties to our common unitholders with contractual standards governing its duties and restricts the remedies available to our common unitholders for actions that might otherwise constitute breaches of fiduciary duty by our general partner.

Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner and its officers and directors would otherwise be held by state fiduciary law and replaces those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its sole discretion, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing. In addition, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that whenever our general partner is permitted or required to make a decision, in its capacity as our general partner, it may make the decision in good faith and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law or any other law, rule or regulation. In addition, our general partner and its officers and directors will not be liable for monetary damages to us or our unitholders resulting from any act or omission taken in good faith. In the absence of bad faith, our general partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with our partnership agreement.

Tax risks

        Our tax treatment or the tax treatment of our unitholders could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. From time to time the U.S. government considers substantive changes to the existing federal income tax laws that affect publicly traded partnerships. We are unable to predict whether any such additional legislation or any other tax-related proposals will ultimately be enacted. Moreover, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Any such changes could adversely impact a unitholder’s investment in our common units.

At the state level, changes in current state law may subject us to additional entity-level taxation by individual states. States frequently evaluate ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may reduce the cash available for distribution to our unitholders.

        If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

The IRS has made no determination as to our status as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders as the costs will reduce our cash available for distribution.

        The IRS may challenge aspects of our proration method, and, if successful, we would be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The U.S. Department of Treasury and the IRS issued Treasury

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Regulations that permit publicly traded partnerships to use a monthly simplifying convention that is similar to ours, but they do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to successfully challenge this method, we could be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

     We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, including when we issue additional units, we must determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of our common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

Our unitholders are required to pay taxes on their share of our income, including their share of gains on any dispositions of assets, even if they do not receive any distributions from us.

Our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, including any gains we realize from dispositions of assets. This tax obligation will exist even if our unitholders receive no distributions from us, and any distributions our unitholders may receive from us may be less than their share of our taxable income or even less than the actual tax liability that results from that income.

Tax gain or loss on disposition of our common units could be more or less than expected.

If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to our unitholders in excess of the total net taxable income they were allocated for a common unit, which decreased their tax basis in that common unit, will, in effect, become taxable income to our unitholders if the common unit is sold at a price greater than their tax basis in that common unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of nonrecourse liabilities, if our unitholders sell their common units, they may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities and foreign persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans, individual retirement accounts (known as IRAs) and foreign persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to foreign persons will be reduced by withholding taxes at the highest applicable effective tax rate, and foreign persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. Upon the sale, exchange or other disposition of a common unit by a foreign person, the transferee is generally required to withhold 10% of the amount realized on such sale, exchange or other disposition if any portion of the gain on such sale, exchange or other disposition would be treated as effectively connected with a U.S. trade or business. The U.S. Department of the Treasury and the IRS have issued final regulations providing guidance on the application of these rules for transfers of certain publicly

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traded partnership interests, including transfers of our common units. Under these regulations, the “amount realized” on a transfer of our common units will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and such broker will generally be responsible for the relevant withholding obligations. Distributions to foreign persons may also be subject to additional withholding under these rules to the extent a portion of a distribution is attributable to an amount in excess of our cumulative net income that has not previously been distributed. The U.S. Department of the Treasury and the IRS have provided that these rules will generally not apply to transfers of, or distributions on, our common units occurring before January 1, 2023.

Our unitholders may be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.

In addition to federal income taxes, our unitholders may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders may be required to file tax returns and pay taxes in some or all of these various jurisdictions or be subject to penalties for failure to comply with those requirements. We currently own assets and conduct business in 22 states, most of which impose a personal income tax.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.

For tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Generally, we expect to elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, but there can be no assurance that such election will be made, or applicable, in all circumstances. If we are unable to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, our current unitholders may bear some or all of the economic burden resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced.

General risk factors

        Our business could be affected adversely by union disputes and strikes or work stoppages by our unionized employees.

As of December 31, 2021, approximately 13% of our workforce was covered by a collective bargaining agreement that expired at the end of January 2022. We could experience a work stoppage in the future as a result of disagreements with the labor union. A prolonged work stoppage could have an adverse effect on our business.

Item 1B.Unresolved Staff Comments

None.

Item 2.Properties

See Item 1(c) for a description of the locations and general character of our material properties.

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Item 3.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”) are infringing patents related to butane blending at the Powder Springs facility located in Powder Springs, Georgia. Sunoco subsequently submitted pleadings alleging that Magellan is also infringing various patents related to butane blending at eight Magellan facilities, in addition to Powder Springs. Sunoco sought monetary damages, attorneys’ fees and a permanent injunction enjoining Powder Springs from infringing the subject patents. We have vigorously defended against all claims asserted by Sunoco. A jury trial concluded on December 6, 2021, at which the jury found Magellan willfully infringed the three patents in suit and awarded damages of approximately $9.4 million against Magellan relating to the eight Magellan facilities at issue. The jury further found that Powder Springs willfully infringed the one patent at issue relating to the Powder Springs facility and awarded approximately $2.8 million against Magellan and Powder Springs relating to that facility. Sunoco has requested that the court enhance the damages award based upon the jury’s finding of willfulness and that the court award additional damages and pre- and post-judgment interest. Magellan and Powder Springs have filed post-trial pleadings opposing Sunoco’s request for enhanced damages and challenging the findings of liability and willfulness. The final determination of the trial court is subject to future appeals by either or both parties to the litigation. Although it is not possible to predict the ultimate outcome, we believe the final resolution of this matter will not have a material adverse impact on our business.

Hurricane Harvey Enforcement Proceeding. In July 2018, we received a Notice of Enforcement letter from the Texas Commission on Environmental Quality alleging two air emission violations at our Galena Park, Texas terminal that occurred during Hurricane Harvey in third quarter 2017. The penalties associated with these alleged violations could exceed $300,000. While the outcome cannot be predicted with certainty, we believe the ultimate resolution of this matter will not have a material adverse effect on our business.

We and the non-controlled entities in which we own an interest are a party to various other claims, legal actions and complaints. While the results cannot be predicted with certainty, management believes the ultimate resolution of these claims, legal actions and complaints, after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect on our business.  

Item 4.Mine Safety Disclosures

Not applicable.

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PART II

Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common units are listed and traded on the New York Stock Exchange under the ticker symbol “MMP.” At the close of business on February 16, 2022, we had 212,393,262 common units outstanding that were owned by approximately 170,000 record holders and beneficial owners (held in street name).

For information regarding common units that may be issued pursuant to our long-term incentive plan, see Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

We currently pay quarterly distributions of $1.0375 per common unit and are targeting annual distribution growth for 2022 similar to the increase provided in 2021; however, we cannot guarantee that this increase will be provided or that future distributions will continue at current levels.

In 2020, we initiated a $750 million common unit repurchase program, which allowed us to repurchase units through 2022. We completed the repurchases authorized under this program in September 2021. In October 2021, this program was expanded by $750 million to allow unit purchases totaling $1.5 billion through December 31, 2024. We intend to purchase our common units from time-to-time through a variety of methods, including open market purchases and negotiated transactions, all in compliance with Securities Exchange Act Rules 10b-18, 10b5-1 or both and other applicable legal requirements. The timing, price and actual number of common units repurchased will depend on a number of factors including our expected expansion capital spending, excess cash available, balance sheet metrics, legal and regulatory requirements, market conditions and the trading price of our common units. The program does not obligate us to acquire any particular amount of common units, and the repurchase program may be suspended or discontinued at any time.

The table below reflects our common units repurchased during 2020 and 2021 and inception-to-date.

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Period	Total Number of Common Units Purchased	Average Price Paid Per Unit		Total Number of Units Purchased as Part of Publicly Announced Program	Approximate Dollar Value of Units That May Yet Be Purchased under the Program (in millions)(a)
Year Ended 2020	5,568,260	$	49.74	5,568,260	$	1,223.1
January 1-31, 2021	—	—		—	$	1,223.1
February 1-28, 2021	—	—		—	$	1,223.1
March 1-31, 2021	—	—		—	$	1,223.1
First Quarter 2021	—	—		—
April 1-30, 2021	—	—		—	$	1,223.1
May 1-31, 2021	1,723,188	$	47.77	1,723,188	$	1,140.7
June 1-30, 2021	—	—		—	$	1,140.7
Second Quarter 2021	1,723,188	$	47.77	1,723,188
July 1-31, 2021	251,947	$	47.24	251,947	$	1,128.8
August 1-31, 2021	6,289,504	$	47.94	6,289,504	$	827.3
September 1-30, 2021	1,572,941	$	49.14	1,572,941	$	750.0
Third Quarter 2021	8,114,392	$	48.15	8,114,392
October 1-31, 2021	—	—		—	$	750.0
November 1-30, 2021	665,921	$	48.05	665,921	$	718.0
December 1-31, 2021	391,327	$	46.00	391,327	$	700.0
Fourth Quarter 2021	1,057,248	$	47.29	1,057,248
Year Ended 2021	10,894,828	$	48.01	10,894,828
Total Inception-to-Date	16,463,088			16,463,088

(a) Our program has $1.5 billion authorized for unit repurchases, which includes $750 million approved in 2020 and an additional $750 million approved in October 2021. Our program will expire on December 31, 2024.

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Unitholder Return Performance

The following graph compares the total unitholder return performance of our common units with the performance of (i) the Alerian MLP Infrastructure Index (“AMZI”), (ii) the Standard & Poor’s 500 Stock Index (“S&P 500”) and (iii) the Standard & Poor's 500 Energy Index ("S&P 500 Energy"). The graph assumes that $100 was invested in our common units and each comparison index beginning on December 31, 2016 and that all distributions or dividends were reinvested on a quarterly basis. The AMZI is a composite of energy infrastructure master limited partnerships, whose constituents earn the majority of their cash flow from midstream activities involving energy commodities and whose trading volume and market capitalization meet certain additional criteria.  The S&P 500 Energy is a subindex of the S&P 500 that includes those companies classified as members of the energy sector.

 

	12/31/2016	12/31/2017	12/31/2018	12/31/2019	12/31/2020	12/31/2021
MMP	$100	$98	$84	$98	$73	$88
AMZI	$100	$91	$80	$86	$59	$83
S&P 500	$100	$122	$116	$153	$181	$233
S&P 500 Energy	$100	$99	$81	$91	$60	$93

The information provided in this section is being furnished to and not filed with the SEC. As such, this information is neither subject to Regulation 14A or 14C nor to the liabilities of Section 18 of the Exchange Act.

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Item 7.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 December 31, 2021, our asset portfolio, excluding assets associated with discontinued operations, consisted of:

•our refined products segment, comprised of our approximately 9,800-mile refined petroleum products pipeline system with 54 terminals and two marine storage terminals (one of which is owned through a joint venture); and

•our crude oil segment, comprised of approximately 2,200 miles of crude oil pipelines, a condensate splitter and 39 million barrels of aggregate storage capacity, of which approximately 29 million barrels are used for contract storage. Approximately 1,000 miles of these pipelines, the condensate splitter and 31 million barrels of this storage capacity (including 25 million barrels used for contract storage) are wholly-owned, with the remainder owned through joint ventures.

The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included in this annual report on Form 10-K for the year ended December 31, 2021.

See Item 1. Business for a detailed description of our business.

Overview

Resiliency and Recovery. Overall, 2021 was a year of resiliency and recovery for our nation and us. As the country moved toward reopening and resumed travel, economic and drilling activity, we benefited from a robust return of demand for gasoline, diesel fuel and aviation fuel. We are honored to serve our country by Moving What Moves America®, ensuring safe and reliable access to the essential fuels that enable our everyday lives.

Efficiency and discipline remain key to our strategy. Through our ongoing business optimization efforts, we have identified significant cost savings and process improvements throughout the organization. Started in late 2019, this initiative has served us well to ensure we are operating as efficiently as possible, especially considering the current inflationary environment, while safeguarding the integrity of our assets. Improved refined products demand as well as our successes in improving efficiency contributed to the solid financial results we achieved this year.

We also regularly review our asset portfolio for opportunities to unlock incremental value for investors. During 2021, we sold a portion of our interest in our Pasadena, Texas marine terminal joint venture, while retaining a meaningful position in this strategic export facility. We also agreed to sell our independent terminals network, comprised of 26 locations primarily in the southeastern United States. Though we still await regulatory approval for this sale, we expect to close by mid-2022.

Disciplined Approach to Capital Allocation. We have a proven track record of delivering superior returns on invested capital. Although the current environment for new large-scale projects is challenging, we continue to assess additional capital investments to create future value for our investors. We currently plan to spend $50 million in 2022 to complete projects already committed, including expansions of our pipeline system to transport additional refined products to New Mexico and Colorado. Both of these expansions are fully underwritten by commitments from strong counterparties and provide attractive returns, underscoring the flexibility of our network to respond to changing market dynamics.

We also delivered value to our investors with nearly $525 million of equity repurchases during the year as well as an increase to our quarterly cash distribution. In total, we returned $1.4 billion to our investors during 2021 through a combination of consistent cash distributions and equity repurchases, an increase of 19% over 2020.

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Essential Services. Energy transition and the long-term outlook for petroleum products have become recent topics of interest. However, the global pandemic and mid-2021 fuel emergency resulting from a third-party U.S. pipeline cyberattack served as strong reminders that our nation and the world very much depend on an abundance of crude oil and refined petroleum products to function. People expect gasoline will be readily accessible for their daily commutes and family activities, that diesel fuel will be available for farmers to harvest crops and for truckers to transport retail goods. The well-being of our entire economy depends on these essential fuels.

We expect our business to stay healthy for decades. Industry and government forecasts project petroleum products to remain essential to our nation’s everyday lives for many years to come. The fundamental features of our business strategy are proven, and we will adapt as the needs of our customers and markets evolve.

Living our Principles. Our most important social responsibility is to safely and reliably transport and store the fuels that our nation relies on every day. For two decades, we have focused on long-term, sustainable operations in all aspects of our business. Our dedicated workforce spends significant time and resources each year to ensure the integrity of our assets and to protect the communities where we live and work. Further, our employees are empowered to make decisions every day that align with our fundamental focus on safety to ensure our company’s success.

To reinforce the importance of this responsibility, our annual incentive program for all employees has been linked to key environmental and safety metrics since the very beginning. In addition, Magellan has designed a responsible governance structure, with an independent board elected by our investors, and fostered a culture considered to be an industry leader for integrity, trustworthiness and simply doing the right thing.

Recent Developments

Leadership Changes. On January 25, 2022, Michael N. Mears notified the partnership of his decision to retire from his positions of President, Chief Executive Officer and Chairman of the Board of Directors effective on April 30, 2022. Our board elected Barry R. Pearl, currently the independent Lead Director, as Chairman of the Board and also elected Aaron L. Milford as Chief Executive Officer and President effective May 1, 2022. Mr. Milford currently serves as Chief Operating Officer and has served in such capacity since 2019. He served as Senior Vice President and Chief Financial Officer from 2015 to 2019 and various positions of increasing responsibility since joining us and our predecessor in 1995.

Mark B. Roles was elected by our board as Senior Vice President, Commercial - Refined Products, effective May 22, 2021. Mr. Roles has held Vice President level positions since 2014 and various positions of increasing responsibilities in commercial and operations since joining us and our predecessor in 1998.

Distribution. In January 2022, our board declared a quarterly distribution of $1.0375 per unit for the period of October 1, 2021 through December 31, 2021. This quarterly distribution was paid on February 14, 2022 to unitholders of record on February 7, 2022.

Equity Repurchase Program. In October 2021, our board expanded our unit repurchase program by $750 million for a total of $1.5 billion and extended the program through 2024. The expanded program allows unit repurchases in compliance with Securities Exchange Act Rules 10b-18, 10b5-1 or both.

Discontinued Operations. In June 2021, we entered into an agreement to sell our independent terminals network comprised of 26 refined petroleum products terminals with approximately six million barrels of storage located primarily in the southeastern U.S. The sale is expected to close upon the receipt of required regulatory approval. The related results of operations, financial position and cash flows have been classified as discontinued operations for all periods presented. See Note 3 - Discontinued Operations and Assets Held for Sale under Item 8. Financial Statements and Supplementary Data of this report for further details.

Sale of Partial Interest in MVP Terminalling, LLC. In April 2021, we sold nearly half of our membership interest in MVP and received proceeds of $272.1 million. Following the sale, we own approximately 25% of MVP and remain the operator of the facility.

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Results of Operations

We believe that investors benefit from having access to the same financial measures utilized by management. Operating margin, which is presented in the following table, 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 table. Operating profit includes expense items, such as depreciation, amortization and impairment expense and general and administrative (“G&A”) expense, which management does not focus on when evaluating the core profitability of our 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 but the components of product sales revenue and cost of product sales are determined in accordance with GAAP. Our gas liquids blending, fractionation and other commodity-related activities generate significant revenue. However, we believe the product margin from these activities, which takes into account the related cost of product sales, better represents its importance to our results of operations.

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Year Ended December 31, 2020 Compared to Year Ended December 31, 2021

	Year Ended December 31,				Variance Favorable (Unfavorable)
	2020		2021		$ Change		% Change
Financial Highlights ($ in millions, except operating statistics)
Transportation and terminals revenue:
Refined products	$	1,190.4	$	1,338.5	$	148.1	12
Crude oil	559.5		466.2		(93.3)		(17)
Intersegment eliminations	(6.6)		(5.8)		0.8		12
Total transportation and terminals revenue	1,743.3		1,798.9		55.6		3
Affiliate management fee revenue	21.2		21.2		—		—
Operating expenses:
Refined products	411.8		416.7		(4.9)		(1)
Crude oil	189.2		165.4		23.8		13
Intersegment eliminations	(13.2)		(12.4)		(0.8)		(6)
Total operating expenses	587.8		569.7		18.1		3
Product margin:
Product sales revenue	557.5		913.0		355.5		64
Cost of product sales	468.2		780.0		(311.8)		(67)
Product margin	89.3		133.0		43.7		49
Other operating income (expense)	0.1		2.8		2.7		2,700
Earnings of non-controlled entities	153.3		154.4		1.1		1
Operating margin	1,419.4		1,540.6		121.2		9
Depreciation, amortization and impairment expense	243.1		227.9		15.2		6
G&A expense	171.2		206.3		(35.1)		(21)
Operating profit	1,005.1		1,106.4		101.3		10
Interest expense (net of interest income and interest capitalized)	221.8		225.9		(4.1)		(2)
Gain on disposition of assets	(12.9)		(75.0)		62.1		481
Other (income) expense	5.2		20.9		(15.7)		(302)
Income from continuing operations before provision for income taxes	791.0		934.6		143.6		18
Provision for income taxes	2.9		2.3		0.6		21
Income from continuing operations	788.1		932.3		144.2		18
Income from discontinued operations	28.9		49.7		20.8		72
Net income	$	817.0	$	982.0	$	165.0	20
Operating Statistics
Refined products:
Transportation revenue per barrel shipped	$	1.675	$	1.715
Volume shipped (million barrels):
Gasoline	270.8		303.8
Distillates	175.5		205.6
Aviation fuel	21.6		30.5
Liquefied petroleum gases	0.9		0.9
Total volume shipped	468.8		540.8
Crude oil:
Magellan 100%-owned assets:
Transportation revenue per barrel shipped(1)	$	1.028	$	0.815
Volume shipped (million barrels)(1)	229.9		189.6
Terminal average utilization (million barrels per month)	25.2		24.9
Select joint venture pipelines:
BridgeTex - volume shipped (million barrels)(2)	132.0		112.1
Saddlehorn - volume shipped (million barrels)(3)	61.6		77.6

(1) Includes shipments related to our crude oil marketing activities.

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

(3) These volumes reflect the total shipments for the Saddlehorn pipeline, which was owned 40% by us through January 31, 2020 and 30% thereafter.

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Transportation and terminals revenue increased by $55.6 million, resulting from:

•an increase in refined products revenue of $148.1 million primarily due to increased transportation revenue as a result of higher volumes versus the pandemic levels of 2020 due to the recovery in travel, economic and drilling activity as well as additional contributions from our Texas pipeline expansion projects. Revenues also benefited from an increase in the average tariff rate in the current period as a result of the 2020 and 2021 mid-year adjustments. These favorable items were partially offset by the absence of revenues in the current period associated with the three marine terminals we sold in March 2020 and lower storage revenues due to lower utilization and lower rates following recent contract expirations; and

•a decrease in crude oil revenue of $93.3 million primarily due to lower average tariff rates, less volume shipped and reduced storage revenues. Average tariff rates decreased primarily as a result of the late 2020 expiration of several higher-priced contracts on our Longhorn pipeline. In addition, deficiency revenue recognized in the year-ago period did not recur in 2021. Transportation volumes also declined partially due to those Longhorn contract expirations, with much of this volume replaced by activities of our marketing affiliate, as well as lower volumes shipped on our Houston distribution system. Storage revenues decreased primarily due to the 2020 period benefiting from increased short-term storage utilization at higher rates with recent contract renewals at lower rates.

Operating expenses decreased $18.1 million, resulting from:

•an increase in refined products expenses of $4.9 million primarily due to higher asset integrity spending related to the timing of maintenance work and higher compensation costs, partially offset by more favorable product overages and the absence of costs in the current period associated with the divested marine terminals; and

•a decrease in crude oil expenses of $23.8 million primarily due to lower power costs as a result of our recent optimization efforts as well as gains on power hedges driven by the winter storm in first quarter 2021, lower fees paid to Seabrook for ancillary services and lower integrity spending related to the timing of maintenance work.

Product margin increased $43.7 million primarily due to higher margins and higher sales volume on our fractionator and refined over/short activities, the sale of a portion of the linefill related to our crude marketing activities, and lower losses recognized in the current year on futures contracts. See Note 14 – Derivative Financial Instruments in Item 8. Financial Statements and Supplementary Data, as well as Other Items – Commodity Derivative Agreements below, for more information about our futures contracts.

Other operating income was $2.7 million favorable primarily due to sales of air emission credits.

Earnings of non-controlled entities increased $1.1 million primarily due to increased earnings from Saddlehorn primarily due to higher volumes shipped and increased earnings from MVP due to a favorable revenue adjustment, partially offset by lower earnings from BridgeTex related to decreased uncommitted shipments based on unfavorable market conditions as well as lower earnings from Seabrook due to lower transportation and storage revenues and increased depreciation costs in the current period.

Depreciation, amortization and impairment expense decreased $15.2 million primarily due to the impairment of certain terminalling assets in 2020.

G&A expense increased $35.1 million primarily due to higher incentive compensation costs as a result of improved financial results, as well as higher benefits costs in 2021.

Interest expense, net of interest income and interest capitalized, increased $4.1 million in 2021 primarily due to higher outstanding debt. Otherwise, lower capitalized interest as a result of reduced ongoing expansion capital spending was more than offset by debt prepayment costs in the 2020 period. Our average outstanding debt increased

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from $4.9 billion in 2020 to $5.1 billion in 2021. Our weighted average interest rates remained the same during both annual periods at 4.4%.

Gain on disposition of assets was $62.1 million favorable. We recognized a gain of $75.0 million in 2021 primarily from the sale of a portion of our interest in MVP and a gain of $12.9 million in 2020 due to the sale of a portion of our interest in Saddlehorn.

Other expense was $15.7 million unfavorable primarily due to amounts recognized in 2021 related to certain legal matters.

Income from discontinued operations increased by $20.8 million due to improved product margin for our independent terminals as a result of higher gas liquids blending volume sold at higher margins, as well as less depreciation now that the assets are classified as held for sale.

For a comparative discussion of the years ended December 31, 2019 and 2020, see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations” in our 2020 Annual Report on Form 10-K .

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Adjusted EBITDA, Distributable Cash Flow and Free Cash Flow

In the following tables, we present the financial measures of Adjusted EBITDA, Distributable Cash Flow (“DCF”) and Free Cash Flow (“FCF”), which are non-GAAP measures. These measures include the results of our discontinued operations.

Adjusted EBITDA is an important measure utilized by management and the investment community to assess the financial results of a company. A reconciliation of adjusted EBITDA to net income, the nearest comparable GAAP measure, is included in the table below.

Our partnership agreement requires that all of our available cash, less amounts reserved by our board, be distributed to our unitholders. DCF is used by management to determine the amount of cash that our operations generated, after maintenance capital spending, that is available for distribution to our unitholders, as well as a basis for recommending to our board the amount of distributions to be paid each period. We also use DCF as the basis for calculating our performance-based equity long-term incentive compensation. A reconciliation of DCF to net income, the nearest comparable GAAP measure, is included in the table below.

FCF is a financial metric used by many investors and others in the financial community to measure the amount of cash generated by a company during a period after accounting for all investing activities, including both maintenance and expansion capital spending, as well as proceeds from divestitures. We believe FCF is important to the financial community as it reflects the amount of cash available for distributions, additional expansion capital opportunities, equity repurchases, debt reduction or other partnership uses. A reconciliation of FCF to net income and to net cash provided by operating activities, the nearest comparable GAAP measure, is included in the following tables.

Since the non-GAAP measures presented here include adjustments specific to us, they may not be comparable to similarly-titled measures of other companies.

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Adjusted EBITDA, DCF and FCF are non-GAAP measures. A reconciliation of each of these measures to net income for the years ended December 31, 2020 and 2021 is as follows (in millions):

	Year Ended December 31,
	2020		2021
Net income	$	817.0	$	982.0
Interest expense, net	221.8		225.9
Depreciation, amortization and impairment(1)	254.6		233.9
Equity-based incentive compensation(2)	(2.7)		15.6
Gain on disposition of assets(3)	(10.5)		(70.6)
Commodity-related adjustments:
Derivative (gains) losses recognized in the period associated with future transactions(4)	29.3		27.7
Derivative gains (losses) recognized in previous periods associated with transactions completed in the period(4)	(20.9)		(36.8)
Inventory valuation adjustments(5)	5.8		2.1
Total commodity-related adjustments	14.2		(7.0)
Distributions from operations of non-controlled entities in excess of earnings	54.2		38.9
Adjusted EBITDA	1,348.6		1,418.7
Interest expense, net, excluding debt issuance cost amortization(6)	(205.4)		(222.8)
Maintenance capital(7)	(98.7)		(77.6)
Distributable cash flow	$	1,044.5	$	1,118.3
Expansion capital(8)	(354.4)		(73.0)
Proceeds from disposition of assets(3)	334.9		270.7
Free cash flow	1,025.0		1,316.0
Distributions paid	(927.1)		(906.4)
Free cash flow after distributions	$	97.9	$	409.6

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

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

(3)    Gains on disposition of assets are excluded from DCF to the extent they are not related to our ongoing operations, while proceeds from disposition of assets exclude the related gains to the extent they are already included in our calculation of DCF.

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

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

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

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

(8)    Includes additions to property, plant and equipment (excluding maintenance capital and capital-related changes in accounts payable and other current liabilities), acquisitions and investments in non-controlled entities, net of distributions from returns of investments in non-controlled entities and deposits from undivided joint interest third parties.

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A reconciliation of FCF to net cash provided by operating activities for the years ended December 31, 2020 and 2021, is as follows (in millions):

	Year Ended December 31,
	2020		2021
Net cash provided by operating activities	$	1,107.5	$	1,196.2
Changes in operating assets and liabilities	37.1		9.7
Net cash provided (used) in investing activities	(199.4)		118.1
Payments associated with settlement of equity-based incentive compensation	(14.7)		(6.2)
Settlement cost, amortization of prior service credit and actuarial loss	(6.7)		(8.4)
Changes in accrued capital items	79.7		7.8
Commodity-related adjustments(1)	14.2		(7.0)
Other	7.3		5.8
Free cash flow	1,025.0		1,316.0
Distributions paid	(927.1)		(906.4)
Free cash flow after distributions	$	97.9	$	409.6

(1) Please refer to the preceding table for a description of these commodity-related adjustments.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

Operating Activities. Net cash provided by operating activities was $1,107.5 million and $1,196.2 million for the years ended December 31, 2020 and 2021, respectively. The $88.7 million increase from 2020 to 2021 was due to higher net income as previously described and changes in our working capital, partially offset by adjustments for non-cash items and distributions in excess of earnings of our non-controlled entities.

Investing Activities. Net cash used by investing activities for the year ended December 31, 2020 was $199.4 million and net cash provided by investing activities for the year ended December 31, 2021 was $118.1 million. During 2021, we used $148.6 million for capital expenditures. Also, during 2021, we sold a portion of our interest in MVP for cash proceeds of $272.1 million. During 2020, we used $424.1 million for capital expenditures, which included $0.2 million for undivided joint interest projects for which cash was received from a third party. Also, during 2020, we sold three marine terminals for cash proceeds of $251.8 million and sold a portion of our interest in Saddlehorn for cash proceeds of $79.9 million. Additionally, we made net capital contributions of $94.6 million to our joint ventures, which we account for as investments in non-controlled entities.

Financing Activities. Net cash used by financing activities for the years ended December 31, 2020 and 2021 was $970.3 million and $1,327.7 million, respectively. During 2021, we paid distributions of $906.4 million to our unitholders and made common unit repurchases of $523.1 million. Additionally, we had net commercial paper borrowings of $108.0 million. Also, in January 2021, our equity-based incentive compensation awards that vested December 31, 2020 were settled by issuing 163,007 common units and distributing those units to the long-term incentive plan (“LTIP”) participants, resulting in payments primarily associated with tax withholdings of $6.2 million. During 2020, we paid distributions of $927.1 million to our unitholders and made common unit repurchases of $276.9 million. Additionally, we received net proceeds of $828.4 million from the issuance of long-term senior notes, which were used to repay our $550.0 million of 4.25% notes due 2021 and outstanding commercial paper borrowings at that time. Also, in January 2020, our equity-based incentive compensation awards that vested December 31, 2019 were settled by issuing 284,643 common units and distributing those units to the LTIP participants, resulting in payments primarily associated with tax withholdings of $14.7 million.

The quarterly distribution amount related to fourth-quarter 2021 earnings was $1.0375 per unit, which was paid in February 2022. Based on the number of common units currently outstanding and our current quarterly

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distribution, total distributions paid to our unitholders related to 2022 earnings would be $881 million. Management believes we will have sufficient DCF to fund these distributions.

For a discussion of cash flows for the year ended December 31, 2019, see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” in our 2020 Annual Report on Form 10-K.

Capital Requirements

Capital spending for our business consists primarily of:

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

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

During 2021, our maintenance capital spending was $77.6 million, including $3.8 million for discontinued operations. For 2022, we expect to spend approximately $80 million on maintenance capital projects.

During 2021, we spent $67.4 million for our expansion capital projects, including $0.4 million for discontinued operations, and contributed $5.6 million for expansion capital projects in conjunction with our joint ventures. Based on the progress of expansion projects already underway, we expect to spend approximately $50 million in 2022 to complete our current slate of expansion capital projects.

Liquidity

Cash generated from operations is a key source of liquidity for funding debt service, maintenance capital expenditures, quarterly distributions and repurchases of common units. Additional liquidity for purposes other than quarterly distributions, such as expansion capital expenditures, is available through borrowings under our commercial paper program and revolving credit facility, as well as from other borrowings or issuances of debt or common units (see Note 10 – Debt and Note 19 – Partners’ Capital and Distributions in Item 8. Financial Statements and Supplementary Data of this report for detail of our borrowings and changes in partners’ capital).

Off-Balance Sheet Arrangements

None.

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Other Items

Pipeline Tariff Changes. The Federal Energy Regulatory Commission (“FERC”) regulates the rates charged on interstate common carrier pipelines. The tariff rates on approximately 30% of our refined products shipments have been regulated by the FERC primarily through an annual index methodology, and nearly all the remaining rates are adjustable at our discretion based on market factors. The current 5-year FERC index began July 1, 2021 and was initially based on the change in the producer price index for finished goods (“PPI-FG”) plus 0.78%. Upon rehearing the FERC lowered the index to PPI-FG minus 0.21% effective March 1, 2022. Based on this methodology and preliminary PPI-FG estimates, we expect to increase our index rates by approximately 8.7% on July 1, 2022. While we continue to evaluate the remaining 70% of our refined products markets, we generally intend to increase rates in those markets by an average of 5%, resulting in an overall average refined products mid-year tariff increase of approximately 6%. Most of the tariffs on our long-haul crude oil pipelines are established at negotiated rates that generally provide for annual adjustments in line with changes in the FERC index, subject to certain modifications. We expect to increase the rates on our long-haul crude oil pipelines between 2% and 5% in July 2022.

Collective Bargaining Agreement. Approximately 13% of our employees are represented by the United Steel Workers (“USW”) and covered by a collective bargaining agreement that expired at the end of January 2022. We are operating under a 24-hour rolling extension of this agreement while negotiations for a new agreement continue. Management expects that we will be able to successfully negotiate a new long-term agreement with the USW; however, a prolonged work stoppage by a majority of these employees could have a material adverse effect on our business.

Commodity Derivative Agreements. Certain of our business activities result in our owning various commodities, which exposes us to commodity price risk. We use forward physical commodity contracts and derivative instruments to hedge against changes in prices of commodities that we expect to sell or purchase in future periods.

For further information regarding the quantities of refined products and crude oil hedged at December 31, 2021 and the fair value of open hedge contracts at that date, please see Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

Related Party Transactions. See Note 18 – Related Party Transactions in Item 8. Financial Statements and Supplementary Data of this report for detail of our related party transactions.

Critical Accounting Estimates

Our management has discussed the development and selection of the following critical accounting estimates with the audit committee of our board, which has reviewed and approved these disclosures.

Pension Obligations

We sponsor a pension plan covering union employees and a pension plan for non-union employees. Various estimates and assumptions directly affect net periodic benefit expense and obligations for these plans. These estimates and assumptions include the expected long-term rate of return on plan assets, discount rates and the expected rate of compensation increases. Management reviews these assumptions annually and makes adjustments as necessary.

The discount rate directly affects the measurement of the benefit obligations of our pension benefit plans. The objective of the discount rate is to determine the amount, if invested at the December 31 measurement date in a portfolio of high-quality fixed income securities, that would provide the necessary cash flows to make benefit payments when due. Decreases in the discount rate increase the obligation and generally increase the related expense, while increases in the discount rate have the opposite effect. Changes in general economic and market

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conditions that affect interest rates on long-term high-quality fixed income securities as well as the duration of our plans’ liabilities affect our estimate of the discount rate.

We estimate the long-term expected rate of return on plan assets using expectations of capital market results, which includes an analysis of historical results as well as forward-looking projections. We base these capital market expectations on a long-term period and on our investment strategy and asset allocation. We develop our estimates using input from several external sources, including consultation with our third-party independent investment consultant. We develop the forward-looking capital market projections using a consensus of expectations by economists for inflation and dividend yield, along with expected changes in risk premiums. Because our determined rate is an estimate of future results, it could be significantly different from actual results. The expected rate of return on plan assets are long-term in nature; therefore, short-term market performance does not significantly affect our estimated long-term expected rate of return.

The expected rate of compensation increases represents average long-term salary increases. An increase in this rate causes the pension obligation and expense to increase.

The following table presents the estimated increase (decrease) in net periodic benefit expense and obligations that would result from a 1% change in the specified assumption (in millions):

	Benefit Expense						Benefit Obligation
	1% Increase			1% Decrease			1% Increase			1% Decrease
Pension benefits:
Discount rate		$	(4.6)		$	5.5		$	(49.8)		$	61.9
Expected long-term rate of return on plan assets		$	(3.0)		$	3.0		$	—		$	—
Rate of compensation increase		$	5.1		$	(5.0)		$	30.2		$	(29.7)

The following table sets forth the increase (decrease) in our pension funding based on our current funding policy assuming a 1% change in the specified criterion (in millions):

	1% Increase	1% Decrease
Rate of compensation increase	$0.6	$(0.6)

Impairment of Long-Lived Assets, Goodwill and Investments

Impairment of Long-Lived Assets. Long-lived assets, including fixed assets and intangibles, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Such indicators include, among others, the nature of the asset, the projected future economic benefit of the asset, changes in regulatory and political environments and historical and future cash flow and profitability measurements. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, we recognize an impairment charge for the excess of carrying value of the asset over its estimated fair value.

Goodwill. The goodwill relating to each of our reporting units is tested for impairment annually as well as when an event or change in circumstances indicates an impairment may have occurred. Under GAAP, we have the option to first assess qualitative factors to determine whether it is more likely than not that the fair value of one of our reporting units is greater than its carrying amount. If, after assessing the totality of events or circumstances, we determine it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, we are not required to perform any further testing. However, if we conclude otherwise, we perform the first step of a two-step impairment test by calculating the fair value of the reporting unit and comparing the fair value with the carrying amount of the reporting unit. If the fair value of the reporting unit is less than its carrying value, an impairment loss is recorded to the extent that the implied fair value of the goodwill of the reporting unit is less than its carrying value. We have the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test.

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For purposes of performing the impairment test for goodwill, our reporting units are our refined products and crude oil segments.  In 2019 and 2020, we elected to perform the qualitative goodwill impairment test and concluded it was more likely than not that the fair value of each of our reporting units was greater than its carrying amount. In 2021, we elected to perform the quantitative goodwill impairment test and began with step one of the test as required by GAAP. Based on this assessment, we calculated that the fair value of each of our reporting units was greater than its carrying amount. Based on this assessment, we concluded goodwill was not impaired.

Determination as to whether and how much goodwill or long-lived assets are impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses and the outlook for national or regional market supply and demand conditions. We base the impairment reviews and calculations used in our impairment tests on assumptions that are consistent with our business plans and long-term investment decisions. See Note 6 – Property, Plant and Equipment, Goodwill and Other Intangibles in Item 8. Financial Statements and Supplementary Data for additional information regarding impairments of goodwill and long-lived assets.

Investments. We evaluate investments in non-controlled entities for impairment whenever events or circumstances indicate that there is an other-than-temporary loss in value of the investment. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in our consolidated financial statements as an impairment charge.

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Item 7A.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 gas liquids blending activities, fractionation activities and petroleum products marketing activities, as well as from managing product overages and shortages associated with our refined products and crude oil pipelines and terminals. We use forward physical contracts and derivative instruments 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 December 31, 2021, we had commitments under forward purchase and sale contracts as follows (in millions):

	Total		< 1 Year		1 – 4 Years		> 5 Years
Forward purchase contracts – notional value	$	377.4	$	122.6	$	135.6	$	119.2
Forward purchase contracts – barrels	9.2		2.0		3.6		3.6
Forward sales contracts – notional value	$	24.9	$	24.9	$	—	$	—
Forward sales contracts – barrels	0.3		0.3		—		—

We generally use derivative instruments including exchange-traded futures contracts and over-the-counter forward contracts to hedge against changes in the price of petroleum products we expect to sell or purchase. We did not elect hedge accounting treatment under Accounting Standards Codification 815, Derivatives and Hedging for our open contracts and as a result we accounted for these contracts as economic hedges, with changes in fair value recognized currently in earnings. The fair value of these open contracts, representing 3.3 million barrels of petroleum products we expect to sell and 0.6 million barrels of gas liquids we expect to purchase, was a net liability of $17.2 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 $33.0 million decrease (increase) in our operating profit, while a $10.00 per barrel increase (decrease) in the price of gas liquids we expect to purchase would result in a $6.0 million increase (decrease) in our operating profit. These increases or decreases in operating profit would be substantially offset by higher or lower product sales revenue or cost of product sales when the physical sale or purchase of those products occurs, respectively. 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 related hedges may not eliminate all price risks.

Interest Rate Risk

Our use of variable rate debt and any future issuances of fixed rate debt expose us to interest rate risk. As of December 31, 2021, we had $108.0 million of variable rate commercial paper outstanding.

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Item 8.    Financial Statements and Supplementary Data

Management’s Annual Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of its internal control over financial reporting as of December 31, 2021. In making this assessment, it used the criteria set forth in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework. As a result of this assessment management has concluded that, as of December 31, 2021, its internal control over financial reporting is effective based on those criteria.

Ernst & Young LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2021. The report, which expresses an unqualified opinion on the effectiveness of our internal control over financial reporting as of December 31, 2021, is included herein under the heading “Report of Independent Registered Public Accounting Firm” relative to internal control over financial reporting.

By:	/S/    MICHAEL N. MEARS
	Chairman of the Board, President, Chief Executive Officer and Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.

By:	/S/    JEFF HOLMAN
	Senior Vice President, Chief Financial Officer and Treasurer of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.

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Report of Independent Registered Public Accounting Firm

To the Common Unitholders of Magellan Midstream Partners, L.P. and the Board of Directors of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Magellan Midstream Partners, L.P. (the Partnership) as of December 31, 2021 and 2020, the related consolidated statements of income, comprehensive income, partners’ capital and cash flows for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 17, 2022 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the account or disclosures to which it relates.

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	Defined Benefit Pension Obligation
Description of the Matter	At December 31, 2021, the Partnership’s defined benefit pension obligation was $423 million and exceeded the fair value of pension plan assets of $295 million, resulting in a net pension obligation of $128 million. As discussed in Note 12 to the consolidated financial statements, the Partnership reviews and updates the assumptions used to measure the defined benefit pension obligation on an annual basis. Auditing the pension obligation was complex due to the judgmental nature of certain actuarial assumptions used in the measurement process, including the discount rate, mortality rates, retirement rate and future compensation levels. The projected benefit obligation was sensitive to these assumptions.
How We Addressed the Matter in Our Audit	We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Partnership’s review of the defined benefit pension obligation calculations, the significant actuarial assumptions and the data inputs provided to the third-party actuary. To test the defined benefit pension obligation, our audit procedures included, among others, evaluating the methodology used, the significant actuarial assumptions discussed above and the underlying data used in the measurement process. We compared the actuarial assumptions used by management to historical trends and evaluated the change in the defined benefit pension obligation from the prior year resulting from the change in service cost, interest cost, actuarial gains and losses, benefit payments, contributions and other activities. We involved our actuarial specialists to assist with our procedures. Those procedures included, among others, evaluating management’s methodology for determining the discount rate that reflects the maturity and duration of the benefit payments and that is used to measure the defined benefit pension obligation. We compared the projected cash flows used in the current year measurement of the pension obligation to those in the prior year and compared the current year benefits paid to the prior year projected payments. To evaluate the future mortality rates, retirement rate and future compensation levels, we assessed whether the information is consistent with publicly available information, and whether any market data adjusted for entity-specific adjustments were applied. We also tested the completeness and accuracy of the underlying data, including the participant data used in the actuarial calculations.

/s/ Ernst & Young LLP

We have served as the Partnership’s auditor since 1999.

Tulsa, Oklahoma

February 17, 2022

53

Report of Independent Registered Public Accounting Firm

To the Common Unitholders of Magellan Midstream Partners, L.P. and the Board of Directors of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.

Opinion on Internal Control Over Financial Reporting

We have audited Magellan Midstream Partners, L.P.’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Magellan Midstream Partners, L.P. (the Partnership) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Partnership as of December 31, 2021 and 2020, the related consolidated statements of income, comprehensive income, partners’ capital and cash flows for each of the three years in the period ended December 31, 2021, and the related notes and our report dated February 17, 2022 expressed an unqualified opinion thereon.

Basis for Opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

An entity’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. An entity’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the entity; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the entity are being made only in accordance with authorizations of management and directors of the entity; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the entity’s assets that could have a material effect on the financial statements.

54

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 17, 2022

55

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(In millions, except per unit amounts)

	Year Ended December 31,
	2019		2020		2021
Transportation and terminals revenue	$	1,913.9	$	1,743.3	$	1,798.9
Product sales revenue	665.8		557.5		913.0
Affiliate management fee revenue	21.2		21.2		21.2
Total revenue	2,600.9		2,322.0		2,733.1
Costs and expenses:
Operating	616.4		587.8		569.7
Cost of product sales	560.9		468.2		780.0
Depreciation, amortization and impairment	230.7		243.1		227.9
General and administrative	194.2		171.2		206.3
Total costs and expenses	1,602.2		1,470.3		1,783.9
Other operating income (expense)	3.0		0.1		2.8
Earnings of non-controlled entities	169.0		153.3		154.4
Operating profit	1,170.7		1,005.1		1,106.4
Interest expense	221.1		234.1		228.1
Interest capitalized	(19.3)		(11.3)		(1.7)
Interest income	(3.3)		(1.0)		(0.5)
Gain on disposition of assets	(29.0)		(12.9)		(75.0)
Other (income) expense	11.8		5.2		20.9
Income from continuing operations before provision for income taxes	989.4		791.0		934.6
Provision for income taxes	1.4		2.9		2.3
Income from continuing operations	988.0		788.1		932.3
Income from discontinued operations	32.8		28.9		49.7
Net income	$	1,020.8	$	817.0	$	982.0
Earnings per common unit
Basic:
Continuing operations	$	4.32	$	3.49	$	4.24
Discontinued operations	0.14		0.13		0.23
Net income per common unit	$	4.46	$	3.62	$	4.47
Weighted average number of common units outstanding	228.7		225.5		219.6
Diluted:
Continuing operations	$	4.32	$	3.49	$	4.24
Discontinued operations	0.14		0.13		0.23
Net income per common unit	$	4.46	$	3.62	$	4.47
Weighted average number of common units outstanding	228.8		225.5		219.8

See notes to consolidated financial statements.

56

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)

	Year Ended December 31,
	2019		2020		2021
Net income	$	1,020.8	$	817.0	$	982.0
Other comprehensive income (loss):
Derivative activity:
Net loss on cash flow hedges	(25.2)		(9.5)		—
Reclassification of net loss on cash flow hedges to income	2.7		3.5		3.5
Changes in employee benefit plan assets and benefit obligations recognized in other comprehensive income:
Net actuarial gain (loss)	(27.3)		(23.5)		16.3
Curtailment gain	—		1.7		—
Recognition of prior service credit amortization in income	(0.2)		(0.2)		(0.2)
Recognition of actuarial loss amortization in income	5.8		5.9		6.0
Recognition of settlement cost in income	2.6		1.0		2.6
Total other comprehensive income (loss)	(41.6)		(21.1)		28.2
Comprehensive income	$	979.2	$	795.9	$	1,010.2

See notes to consolidated financial statements.

57

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In millions)

	December 31,
	2020		2021
ASSETS
Current assets:
Cash and cash equivalents	$	13.0	$	2.0
Trade accounts receivable	103.6		135.2
Other accounts receivable	37.1		34.6
Inventory	158.2		281.1
Commodity derivatives contracts, net	—		1.4
Commodity derivatives deposits	34.2		46.3
Assets held for sale	15.1		299.5
Other current assets	43.9		43.1
Total current assets	405.1		843.2
Property, plant and equipment	7,943.8		8,045.9
Less: accumulated depreciation	1,956.9		2,141.2
Net property, plant and equipment	5,986.9		5,904.7
Investments in non-controlled entities	1,213.9		980.8
Right-of-use asset, operating leases	166.1		174.2
Long-term receivables	22.8		10.1
Goodwill	50.1		50.1
Other intangibles (less accumulated amortization of $9.2 and $11.9 at December 31, 2020 and 2021, respectively)	44.9		43.2
Restricted cash	9.4		7.0
Noncurrent assets held for sale	277.6		—
Other noncurrent assets	20.2		16.7
Total assets	$	8,197.0	$	8,030.0
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	98.0	$	109.5
Accrued payroll and benefits	52.1		74.9
Accrued interest payable	59.0		59.0
Accrued taxes other than income	67.7		76.5
Deferred revenue	98.6		92.5
Accrued product liabilities	75.2		153.5
Commodity derivatives contracts, net	21.6		18.6
Current portion of operating lease liability	27.5		25.8
Liabilities held for sale	8.4		15.8
Other current liabilities	50.5		53.5
Total current liabilities	558.6		679.6
Long-term debt, net	4,978.7		5,088.8
Long-term operating lease liability	137.5		147.3
Long-term pension and benefits	163.8		145.0
Long-term liabilities held for sale	1.5		—
Other noncurrent liabilities	53.1		69.5
Commitments and contingencies
Partners’ capital:
Common unitholders (223.1 units and 212.4 units outstanding at December 31, 2020 and 2021, respectively)	2,487.0		2,054.8
Accumulated other comprehensive loss	(183.2)		(155.0)
Total partners’ capital	2,303.8		1,899.8
Total liabilities and partners’ capital	$	8,197.0	$	8,030.0

See notes to consolidated financial statements.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

	Year Ended December 31,
	2019		2020		2021
Operating Activities:
Net income	$	1,020.8	$	817.0	$	982.0
Adjustments to reconcile net income to net cash provided by operating activities:
Income from discontinued operations	(32.8)		(28.9)		(49.7)
Depreciation, amortization and impairment expense	230.7		243.1		227.9
Gain on disposition of assets	(29.0)		(12.9)		(75.0)
Earnings of non-controlled entities	(169.0)		(153.3)		(154.4)
Distributions from operations of non-controlled entities	203.6		207.6		193.3
Equity-based incentive compensation expense	24.0		12.0		21.8
Settlement cost, amortization of prior service credit and actuarial loss	8.2		6.7		8.4
Debt extinguishment costs	8.3		12.9		—
Changes in operating assets and liabilities (Note 9)	2.1		(37.1)		(9.7)
Net cash provided by operating activities of continuing operations	1,266.9		1,067.1		1,144.6
Net cash provided by operating activities of discontinued operations	53.2		40.4		51.6
Net cash provided by operating activities	1,320.1		1,107.5		1,196.2
Investing Activities:
Additions to property, plant and equipment, net(1)	(923.2)		(424.1)		(148.6)
Proceeds from disposition of assets	65.4		334.8		275.1
Investments in non-controlled entities	(212.4)		(95.1)		(5.6)
Distributions from returns of investments in non-controlled entities	8.5		0.5		—
Deposits received from undivided joint interest third party	75.3		—		—
Net cash provided (used) by investing activities of continuing operations	(986.4)		(183.9)		120.9
Net cash used by investing activities of discontinued operations	(19.8)		(15.5)		(2.8)
Net cash provided (used) by investing activities	(1,006.2)		(199.4)		118.1
Financing Activities:
Distributions paid	(921.6)		(927.1)		(906.4)
Repurchase of common units	—		(276.9)		(523.1)
Net commercial paper borrowings	—		—		108.0
Borrowings under long-term notes	996.4		828.4		—
Payments on notes	(550.0)		(550.0)		—
Debt placement costs	(12.0)		(7.6)		—
Debt extinguishment costs	(8.3)		(12.9)		—
Net payment on financial derivatives	(33.3)		(9.5)		—
Payments associated with settlement of equity-based incentive compensation	(9.8)		(14.7)		(6.2)
Net cash used by financing activities	(538.6)		(970.3)		(1,327.7)
Change in cash, cash equivalents and restricted cash	(224.7)		(62.2)		(13.4)
Cash, cash equivalents and restricted cash at beginning of period	309.3		84.6		22.4
Cash, cash equivalents and restricted cash at end of period	$	84.6	$	22.4	$	9.0
Supplemental non-cash investing and financing activities:
(1) Additions to property, plant and equipment	$	(959.8)	$	(344.4)	$	(140.8)
Changes in current liabilities related to capital expenditures	36.6		(79.7)		(7.8)
Additions to property, plant and equipment, net	$	(923.2)	$	(424.1)	$	(148.6)

See notes to consolidated financial statements.

59

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(In millions)

	Common Unitholders		Accumulated Other Comprehensive Loss			Total Partners’ Capital
Balance, January 1, 2019	$	2,763.9		$	(120.5)	$	2,643.4
Comprehensive income:
Net income	1,020.8			—		1,020.8
Total other comprehensive loss	—			(41.6)		(41.6)
Total comprehensive income (loss)	1,020.8			(41.6)		979.2
Distributions	(921.6)			—		(921.6)
Equity-based incentive compensation expense	24.0			—		24.0
Issuance of common units in settlement of equity-based incentive plan awards	0.5			—		0.5
Payments associated with settlement of equity-based incentive compensation	(9.8)			—		(9.8)
Other	(0.7)			—		(0.7)
Balance, December 31, 2019	2,877.1			(162.1)		2,715.0
Comprehensive income:
Net income	817.0			—		817.0
Total other comprehensive loss	—			(21.1)		(21.1)
Total comprehensive income (loss)	817.0			(21.1)		795.9
Distributions	(927.1)			—		(927.1)
Repurchase of common units	(276.9)			—		(276.9)
Equity-based incentive compensation expense	12.0			—		12.0
Issuance of common units in settlement of equity-based incentive plan awards	0.6			—		0.6
Payments associated with settlement of equity-based incentive compensation	(14.7)			—		(14.7)
Other	(1.0)			—		(1.0)
Balance, December 31, 2020	2,487.0			(183.2)		2,303.8
Comprehensive income:
Net income	982.0			—		982.0
Total other comprehensive income	—			28.2		28.2
Total comprehensive income (loss)	982.0			28.2		1,010.2
Distributions	(906.4)			—		(906.4)
Repurchase of common units	(523.1)			—		(523.1)
Equity-based incentive compensation expense	21.8			—		21.8
Issuance of common units in settlement of equity-based incentive plan awards	0.5			—		0.5
Payments associated with settlement of equity-based incentive compensation	(6.2)			—		(6.2)
Other	(0.8)			—		(0.8)
Balance, December 31, 2021	$	2,054.8		$	(155.0)	$	1,899.8

See notes to consolidated financial statements.

60

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Description of Business

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 our common units are traded on the New York Stock Exchange under the ticker symbol “MMP.” Magellan GP, LLC, a wholly owned Delaware limited liability company, serves as our general partner. The board of directors of our general partner is referred to herein as our “board”.

Description of Business

We are principally engaged in the transportation, storage and distribution of refined petroleum products and crude oil. As of December 31, 2021, our asset portfolio, excluding assets associated with discontinued operations, consisted of:

•our refined products segment, comprised of our approximately 9,800-mile refined petroleum products pipeline system with 54 terminals and two marine storage terminals (one of which is owned through a joint venture); and

•our crude oil segment, comprised of approximately 2,200 miles of crude oil pipelines, a condensate splitter and 39 million barrels of aggregate storage capacity, of which approximately 29 million barrels are used for contract storage. Approximately 1,000 miles of these pipelines, the condensate splitter and 31 million barrels of this storage capacity (including 25 million barrels used for contract storage) are wholly-owned, with the remainder owned through joint ventures.

Description of Products

The following terms are commonly used in our industry to describe products that we transport, store, distribute or otherwise handle through our petroleum pipelines and terminals:

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

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

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

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

•crude oil, which includes condensate, is a naturally occurring unrefined petroleum product recovered from underground that is used as feedstock by refineries, splitters and petrochemical facilities.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

We use the term petroleum products to describe any, or a combination, of the above-noted products. In addition, we handle, store and distribute renewable fuels, such as ethanol and biodiesel.

2.Summary of Significant Accounting Policies

Significant Accounting Policies

Basis of Presentation. Our consolidated financial statements include our refined products and crude oil operating segments. We consolidate all entities in which we have a controlling ownership interest. We apply the equity method of accounting to investments in entities over which we exercise significant influence but do not control. We eliminate all intercompany transactions.

In June 2021, we entered into an agreement to sell our independent terminals network comprised of 26 refined petroleum products terminals with approximately six million barrels of storage located primarily in the southeastern United States (“U.S.”). The sale is expected to close upon the receipt of required regulatory approval. The related results of operations, financial position and cash flows have been classified as discontinued operations for all periods presented (see Note 3 – Discontinued Operations and Assets Held for Sale for additional details). Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.

Reclassifications. Certain prior period amounts have been reclassified to conform with the current period’s presentation, including amounts related to our discontinued operations.

Use of Estimates. The preparation of our consolidated financial statements in conformity with U.S. generally accepted accounting principles (“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.

Cash Equivalents. Cash and cash equivalents include demand and time deposits and funds that own highly marketable securities with original maturities of three months or less when acquired. We periodically assess the financial condition of the institutions where we hold these funds, and at December 31, 2020 and 2021, we believed our credit risk relative to these funds was minimal.

Restricted Cash. Restricted cash includes cash that we are contractually required to use 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.

Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable represent valid claims against customers. We recognize accounts receivable when we sell products or render services and collection of the receivable is probable. We extend credit terms to certain customers after a review of various credit indicators. We establish an allowance for doubtful accounts using an expected credit loss approach and evaluate reserves no less than quarterly to determine their adequacy. Judgments relative to at-risk accounts include the customers’ current financial condition, the customers’ historical relationship with us and current and projected economic conditions. We write off accounts receivable when we deem an account uncollectible.

Product Overages and Shortages. Each period end we measure the volume of each type of product in our pipeline systems and terminals, which is compared to the volumes of our customers’ inventories (as adjusted for tender deductions).  To the extent the product volumes in our pipeline systems and terminals exceed the volumes of our customers’ book inventories, we recognize a gain from the product overage and increase our product inventories. To the extent the product in our pipeline systems and terminals is less than our customers’ book inventories, we

62

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

recognize a loss from the product shortage and we record a liability for product owed to our customers.  The product overages we recognize are recorded based on market prices, and the resulting inventory is carried at weighted average cost.  The product shortages we recognize are recorded based on our weighted average cost.  Additionally, when product shortages result in a net short inventory position, the related liability is recorded based on period-end market prices.  Product overages and shortages as well as adjustments to the value of net short inventory positions are recorded in operating expenses on our consolidated statements of income.

Income Taxes. We are a partnership for income tax purposes and therefore are not subject to federal or state income taxes for most of the states in which we operate. The tax on our net income is borne by our unitholders through allocation to them of their share of our taxable income. Net income for financial statement purposes may differ significantly from taxable income allocated to unitholders because of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each unitholder’s tax attributes is not available to us.

The amounts recognized as provision for income taxes in our consolidated statements of income are primarily

comprised of partnership-level taxes levied by the state of Texas. This tax is based on revenues less direct costs of sale for our assets apportioned to the state of Texas.

Net Income Per Unit. We calculate basic net income per common unit for each period by dividing net income by the weighted average number of common units outstanding. The difference between our actual common units outstanding and our weighted average number of common units outstanding used to calculate net income per common unit is due to the impact of: (i) the phantom units issued to our independent directors, which are included in the calculation of basic and diluted weighted average units outstanding and (ii) the weighted average effect of units actually issued or repurchased during a period.  The difference between the weighted average number of common units outstanding used for basic and diluted net income per unit calculations on our consolidated statements of income is primarily the dilutive effect of phantom unit awards granted pursuant to our long-term incentive plan, which have not yet vested in periods where contingent performance metrics have been met.

Index of Additional Significant Accounting Policies

Discontinued Operations and Assets Held for Sale	Note 3 – Discontinued Operations and Assets Held for Sale
Revenue from Contracts with Customers	Note 5 – Revenue
Property, Plant and Equipment	Note 6 – Property, Plant and Equipment, Goodwill and Other Intangibles
Goodwill and Other Intangible Assets	Note 6 – Property, Plant and Equipment, Goodwill and Other Intangibles
Investments in Non-Controlled Entities	Note 7 – Investments in Non-Controlled Entities
Inventory	Note 8 – Inventory
Leases	Note 11 – Leases
Pension and Postretirement Medical and Life Benefit Obligations	Note 12 – Employee Benefit Plans
Equity-Based Incentive Compensation	Note 13 – Long-Term Incentive Plan
Derivative Financial Instruments	Note 14 – Derivative Financial Instruments
Contingencies and Environmental	Note 16 – Commitments and Contingencies

63

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

New Accounting Pronouncements

We evaluate new Accounting Standards Codifications (“ASC”) and updates issued by the Financial Accounting Standards Board on an ongoing basis. There are no new accounting pronouncements that we anticipate will have a material impact on our financial statements.

3.    Discontinued Operations and Assets Held for Sale

In June 2021, we entered into an agreement to sell our independent terminals network comprised of 26 refined petroleum products terminals with approximately six million barrels of storage located primarily in the southeastern U.S. to Buckeye Partners, L.P. (“Buckeye”) for $435 million. The sale is expected to close upon the receipt of required regulatory approval. The related results of operations, which were previously included in our refined products segment, have been classified as discontinued operations.

Summarized Results of Discontinued Operations

The following table provides the summarized results that have been reclassified from continuing operations to discontinued operations on the consolidated statements of income for the years ended December 31, 2019, 2020 and 2021 (in millions):

	Year Ended December 31,
	2019		2020		2021
Transportation and terminals revenue	$	56.8	$	51.4	$	53.3
Product sales revenue	70.3		54.2		83.7
Total revenue	127.1		105.6		137.0
Costs and expenses:
Operating	17.9		13.4		11.2
Cost of product sales	58.5		45.5		66.5
Depreciation, amortization and impairment	15.4		15.6		7.1
General and administrative	2.5		2.2		2.5
Total costs and expenses	94.3		76.7		87.3
Income from discontinued operations	$	32.8	$	28.9	$	49.7

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

Summarized Assets and Liabilities of Discontinued Operations

The following table provides the summarized assets and liabilities classified as held for sale on the consolidated balance sheets as of December 31, 2020 and 2021 (in millions):

	Year Ended December 31,
	2020		2021
Assets:
Trade accounts receivable	$	5.6	$	6.3
Inventory	9.2		17.0
Net property, plant and equipment	274.9		272.0
Goodwill	2.7		2.7
Other assets	0.3		1.5
Total assets classified as held for sale	$	292.7	$	299.5
Liabilities:
Accounts payable	$	2.0	$	3.7
Accrued product liabilities	4.0		8.4
Other liabilities	3.9		3.7
Total liabilities classified as held for sale	$	9.9	$	15.8

4.    Segment Disclosures

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

We believe that investors benefit from having access to the same financial measures used by management. Operating margin, which is presented in the following tables, is an important measure used by management to evaluate the economic performance of our core operations. Operating margin is not a GAAP measure, but the components of operating margin are computed using amounts that are determined in accordance with GAAP. A reconciliation of operating margin to operating profit, which is its nearest comparable GAAP financial measure, is included in the tables below. Operating profit includes depreciation, amortization and impairment expense and general and administrative (“G&A”) expense that management does not consider when evaluating the core profitability of our separate operating segments.

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	Year Ended December 31, 2019
	(in millions)
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation and terminals revenue	$	1,299.0	$	620.3	$	(5.4)	$	1,913.9
Product sales revenue	637.5		28.3		—		665.8
Affiliate management fee revenue	6.7		14.5		—		21.2
Total revenue	1,943.2		663.1		(5.4)		2,600.9
Operating expense	454.0		173.3		(10.9)		616.4
Cost of product sales	532.8		28.1		—		560.9
Other operating (income) expense	(10.2)		7.2		—		(3.0)
Earnings of non-controlled entities	(8.1)		(160.9)		—		(169.0)
Operating margin	974.7		615.4		5.5		1,595.6
Depreciation, amortization and impairment expense	158.7		66.5		5.5		230.7
G&A expense	138.3		55.9		—		194.2
Operating profit	$	677.7	$	493.0	$	—	$	1,170.7
Additions to long-lived assets	$	785.1	$	74.2			$	859.3
	As of December 31, 2019
	(in millions)
Segment assets	$	5,116.4	$	2,894.7			$	8,011.1
Assets held for sale							295.5
Corporate assets							131.1
Total assets							$	8,437.7
Goodwill	$	38.5	$	12.1			$	50.6
Investments in non-controlled entities	$	422.4	$	818.2			$	1,240.6

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	Year Ended December 31, 2020
	(in millions)
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation and terminals revenue	$	1,190.4	$	559.5	$	(6.6)	$	1,743.3
Product sales revenue	524.4		33.1		—		557.5
Affiliate management fee revenue	6.3		14.9		—		21.2
Total revenue	1,721.1		607.5		(6.6)		2,322.0
Operating expense	411.8		189.2		(13.2)		587.8
Cost of product sales	425.8		42.4		—		468.2
Other operating (income) expense	(3.2)		3.1		—		(0.1)
Earnings of non-controlled entities	(32.5)		(120.8)		—		(153.3)
Operating margin	919.2		493.6		6.6		1,419.4
Depreciation, amortization and impairment expense	159.9		76.6		6.6		243.1
G&A expense	123.5		47.7		—		171.2
Operating profit	$	635.8	$	369.3	$	—	$	1,005.1
Additions to long-lived assets	$	277.5	$	56.4			$	333.9
	As of December 31, 2020
	(in millions)
Segment assets	$	4,977.0	$	2,836.9			$	7,813.9
Assets held for sale							292.7
Corporate assets							90.4
Total assets							$	8,197.0
Goodwill	$	38.0	$	12.1			$	50.1
Investments in non-controlled entities	$	429.2	$	784.7			$	1,213.9

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	Year Ended December 31, 2021
	(in millions)
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation and terminals revenue	$	1,338.5	$	466.2	$	(5.8)	$	1,798.9
Product sales revenue	763.9		149.1		—		913.0
Affiliate management fee revenue	6.4		14.8		—		21.2
Total revenue	2,108.8		630.1		(5.8)		2,733.1
Operating expense	416.7		165.4		(12.4)		569.7
Cost of product sales	630.1		149.9		—		780.0
Other operating (income) expense	(6.9)		4.1		—		(2.8)
Earnings of non-controlled entities	(34.4)		(120.0)		—		(154.4)
Operating margin	1,103.3		430.7		6.6		1,540.6
Depreciation, amortization and impairment expense	153.9		67.4		6.6		227.9
G&A expense	147.8		58.5		—		206.3
Operating profit	$	801.6	$	304.8	$	—	$	1,106.4
Additions to long-lived assets	$	88.9	$	41.1			$	130.0
	As of December 31, 2021
	(in millions)
Segment assets	$	4,880.0	$	2,780.7			$	7,660.7
Assets held for sale							299.5
Corporate assets							69.8
Total assets							$	8,030.0
Goodwill	$	38.0	$	12.1			$	50.1
Investments in non-controlled entities	$	232.8	$	748.0			$	980.8

5. Revenue

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 on a net basis.

We recognize pipeline transportation revenue for crude oil 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 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

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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 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 related rules and orders. FERC regulation requires that interstate pipeline rates be filed with the FERC, be posted publicly, be “just and reasonable” and not be unduly discriminatory. The rates on approximately 30% 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 liquid pipeline companies may establish rates by obtaining authority to charge market-based rates in competitive markets or by negotiation with unaffiliated shippers. Approximately 70% 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.

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Statements of Income Disclosures

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

	Year Ended December 31, 2019
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation	$	787.7	$	381.6	$	—	$	1,169.3
Terminalling	139.9		17.8		—		157.7
Storage	214.9		119.3		(5.4)		328.8
Ancillary services	128.6		28.4		—		157.0
Lease revenue	27.9		73.2		—		101.1
Transportation and terminals revenue	1,299.0		620.3		(5.4)		1,913.9
Product sales revenue	637.5		28.3		—		665.8
Affiliate management fee revenue	6.7		14.5		—		21.2
Total revenue	1,943.2		663.1		(5.4)		2,600.9
Revenue not under the guidance of ASC 606, Revenue from Contracts with Customers:
Lease revenue	(27.9)		(73.2)		—		(101.1)
(Gains) losses from futures contracts included in product sales revenue	63.5		3.0		—		66.5
Affiliate management fee revenue	(6.7)		(14.5)		—		(21.2)
Total revenue from contracts with customers under ASC 606	$	1,972.1	$	578.4	$	(5.4)	$	2,545.1

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	Year Ended December 31, 2020
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation	$	742.9	$	305.4	$	—	$	1,048.3
Terminalling	109.6		21.5		—		131.1
Storage	199.3		129.0		(6.6)		321.7
Ancillary services	114.9		26.9		—		141.8
Lease revenue	23.7		76.7		—		100.4
Transportation and terminals revenue	1,190.4		559.5		(6.6)		1,743.3
Product sales revenue	524.4		33.1		—		557.5
Affiliate management fee revenue	6.3		14.9		—		21.2
Total revenue	1,721.1		607.5		(6.6)		2,322.0
Revenue not under the guidance of ASC 606, Revenue from Contracts with Customers:
Lease revenue	(23.7)		(76.7)		—		(100.4)
(Gains) losses from futures contracts included in product sales revenue	(56.8)		3.6		—		(53.2)
Affiliate management fee revenue	(6.3)		(14.9)		—		(21.2)
Total revenue from contracts with customers under ASC 606	$	1,634.3	$	519.5	$	(6.6)	$	2,147.2

	Year Ended December 31, 2021
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation	$	915.7	$	228.8	$	—	$	1,144.5
Terminalling	100.1		17.0		—		117.1
Storage	177.1		114.8		(5.8)		286.1
Ancillary services	125.2		29.9		—		155.1
Lease revenue	20.4		75.7		—		96.1
Transportation and terminals revenue	1,338.5		466.2		(5.8)		1,798.9
Product sales revenue	763.9		149.1		—		913.0
Affiliate management fee revenue	6.4		14.8		—		21.2
Total revenue	2,108.8		630.1		(5.8)		2,733.1
Revenue not under the guidance of ASC 606, Revenue from Contracts with Customers:
Lease revenue	(20.4)		(75.7)		—		(96.1)
(Gains) losses from futures contracts included in product sales revenue	(127.2)		(16.0)		—		(143.2)
Affiliate management fee revenue	(6.4)		(14.8)		—		(21.2)
Total revenue from contracts with customers under ASC 606	$	1,954.8	$	523.6	$	(5.8)	$	2,472.6

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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. We also record contract liabilities for payments received in conjunction with take-or-pay contracts, storage contracts and other service offerings in which the service to our customers remains unfulfilled. These liabilities are presented as deferred revenue and other noncurrent liabilities on our consolidated balance sheets. We recognize contract assets for costs incurred to obtain new customer contracts. Additionally, at each period end, we defer a portion of the costs incurred associated with our customers’ in-transit products based on our per-barrel direct delivery costs and the average delivery point for all barrels in our system. These contract assets are presented on our consolidated balance sheets as other current and noncurrent assets. Contract assets and contract liabilities are determined using judgments and assumptions that management considers reasonable.

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

	December 31, 2020		December 31, 2021
Accounts receivable from contracts with customers	$	103.3	$	134.8
Contract assets	$	12.2	$	12.5
Contract liabilities	$	102.7	$	100.1

For the year ended December 31, 2021, we recognized $80.9 million of transportation and terminals revenue that was recorded in deferred revenue as of December 31, 2020.

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 us 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. 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 December 31, 2021 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 millions):

	Refined Products		Crude Oil		Total
Amounts as of December 31, 2021	$	1,874.5	$	1,069.8	$	2,944.3
Remaining terms	1 - 17 years		1 - 10 years
Estimated revenues from UPOs to be recognized in the next 12 months	$	368.9	$	257.4	$	626.3

In computing the value of these future revenues, we have used the current rates in effect as of December 31, 2021 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

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as of December 31, 2021 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.

6.    Property, Plant and Equipment, Goodwill and Other Intangibles

Property, Plant and Equipment

Property, plant and equipment consists primarily of pipeline, pipeline-related equipment, storage tanks and processing equipment. We state property, plant and equipment at cost except for certain acquired assets recorded at fair value on their respective acquisition dates and impaired assets. We record impaired assets at fair value on the last impairment evaluation date for which an adjustment was required.

We assign asset lives based on reasonable estimates when we place an asset into service. Subsequent events could cause us to change our estimates, which would affect the future calculation of depreciation expense.

When we sell or retire property, plant and equipment, we remove its carrying value and the related accumulated depreciation from our accounts and record any associated gains or losses on our consolidated statements of income in the period of sale or disposition.

We capitalize expenditures to replace existing assets and retire the replaced assets. We capitalize expenditures when they extend the useful life, increase the productivity or capacity, or improve the safety or efficiency of the asset. We capitalize direct project costs such as labor and materials as incurred. Indirect project costs, such as overhead, are capitalized based on a percentage of direct labor charged to the respective capital project. We charge expenditures for maintenance, repairs and minor replacements to operating expense in the period incurred.

During construction, we capitalize interest on construction projects undergoing preparation for use and when total budgeted project costs exceed $0.5 million. The interest we capitalize is based on the weighted average interest rate of our debt. The weighted average rates used to capitalize interest on borrowed funds were 4.6%, 4.4% and 4.4% for the years ended December 31, 2019, 2020 and 2021, respectively.

Property, plant and equipment consisted of the following (in millions):

					Estimated  Depreciable Lives
	December 31,
	2020		2021
Construction work-in-progress	$	122.0	$	89.5
Land and rights-of-way	373.9		374.3
Buildings	119.7		121.8		10 to 53 years
Storage tanks	1,952.7		1,986.7		10 to 49 years
Pipeline and station equipment	3,325.9		3,386.0		10 to 59 years
Processing equipment	1,769.4		1,826.4		3 to 56 years
Other	280.2		261.2		3 to 53 years
Property, plant and equipment, gross	$	7,943.8	$	8,045.9

Other includes total interest capitalized on assets placed in service as of December 31, 2020 and 2021 of $96.2 million and $98.7 million, respectively. Depreciation expense for the years ended December 31, 2019, 2020 and 2021 was $227.5 million, $240.5 million and $225.2 million, respectively.

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Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying value may not be recoverable. In reviewing for impairment, the carrying value of such assets is compared to the estimated undiscounted future cash flows expected from the use of the assets and their eventual disposition. If such cash flows are not sufficient to support the asset’s recorded value, an impairment charge is recognized to reduce the carrying value of the long-lived asset to its estimated fair value. The determination of future cash flows as well as the estimated fair value of long-lived assets involves significant estimates on the part of management.

In accordance with ASC, 360 Plant, Property and Equipment, we ceased recording depreciation and amortization for the assets held for sale in June 2021.

Goodwill

We record the excess of purchase price over the fair value of the tangible and identifiable intangible assets acquired and liabilities assumed in a business acquisition (or combination) as goodwill. The goodwill relating to each of our reporting units is tested for impairment annually as well as when an event or change in circumstances indicates an impairment may have occurred.

For purposes of performing the impairment test for goodwill, our reporting units are our refined products and crude oil segments.  In 2019 and 2020, we elected to complete the qualitative goodwill impairment test and concluded it was more likely than not that the fair value of each of our reporting units was greater than its carrying amount. In 2021, we elected to perform the quantitative assessment for purposes of our annual goodwill impairment test and calculated that the fair value of each of our reporting units was greater than the carrying amount. Based on this assessment, we concluded goodwill was not impaired.

Other Intangibles

Other intangible assets with finite lives are amortized over their estimated useful lives of 7 years up to 30 years. The weighted average asset life of our other intangible assets at December 31, 2021 was approximately 16 years. We adjust the useful lives of our other intangible assets if events or circumstances indicate there has been a change in the remaining useful lives. We eliminate from our balance sheets the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. During the years ended December 31, 2019, 2020 and 2021, amortization of other intangible assets was $3.3 million, $2.7 million and $2.7 million, respectively.

7.     Investments in Non-Controlled Entities

We account for interests in affiliates that we do not control using the equity method of accounting. Under this method, an investment is recorded at our acquisition cost or capital contributions, as adjusted by contractual terms, plus equity in earnings or losses since acquisition or formation, plus interest capitalized, less distributions received and amortization of interest capitalized and excess net investment. Excess net investment is the amount by which our investment in a non-controlled entity exceeded our proportionate share of the book value of the net assets of that investment. We amortize excess net investment over the weighted average depreciable asset lives of the equity investee. Our unamortized excess net investment was $33.0 million and $32.0 million at December 31, 2020 and 2021, respectively. The amount of unamortized excess investment is primarily related to our investment in BridgeTex. We evaluate equity method investments for impairment whenever events or circumstances indicate that there is an other-than-temporary loss in value of the investment. In the event that we determine that the loss in value of an investment is other-than-temporary, we would record a charge to earnings to adjust the carrying value to fair value. We recognized no equity investment impairments during 2019, 2020 and 2021.

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Our equity investments in non-controlled entities at December 31, 2021 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”)	25%
Powder Springs Logistics, LLC (“Powder Springs”)	50%
Saddlehorn Pipeline Company, LLC (“Saddlehorn”)	30%
Seabrook Logistics, LLC (“Seabrook”)	50%
Texas Frontera, LLC (“Texas Frontera”)	50%

In April 2021, we sold nearly half of our membership interest in MVP. As a result of the sale, we received proceeds of $272.1 million and recorded a gain of $70.4 million on our consolidated statements of income. Following the sale, we own approximately 25% of MVP and remain the operator of the facility.

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 receive are reported as affiliate management fee revenue on our consolidated statements of income. Cost reimbursements we receive from these entities in connection with our operating services are included as reductions to costs and expenses on our consolidated statements of income and totaled $5.3 million, $3.6 million and $2.5 million, respectively, for the years ended December 31, 2019, 2020 and 2021.

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

	Year Ended December 31,
	2019		2020		2021
Transportation and terminals revenue:
BridgeTex, pipeline capacity and storage	$	41.8	$	42.3	$	43.7
Double Eagle, throughput revenue	$	6.2	$	4.9	$	3.0
Saddlehorn, storage revenue	$	2.2	$	2.5	$	2.3
Operating expense:
Seabrook, storage lease and ancillary services	$	25.9	$	29.1	$	19.7
Product sales revenue:
Seabrook, product sales	$	0.3	$	—	$	—
Other operating income:
MVP, easement sale	$	0.3	$	—	$	—
Seabrook, gain on sale of air emission credits	$	—	$	1.4	$	0.4

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

	December 31, 2020
	Trade Accounts Receivable		Other Accounts Receivable		Other Accounts Payable		Long-Term Receivables
BridgeTex	$	0.4	$	—	$	1.0	$	—
Double Eagle	$	0.3	$	—	$	—	$	—
HoustonLink	$	—	$	—	$	0.1	$	—
MVP	$	—	$	0.5	$	2.3	$	—
Powder Springs	$	—	$	—	$	—	$	10.2
Saddlehorn	$	—	$	0.1	$	—	$	—
Seabrook	$	—	$	—	$	7.3	$	—

	December 31, 2021
	Trade Accounts Receivable		Other Accounts Receivable		Other Accounts Payable		Long-Term Receivables
BridgeTex	$	1.2	$	—	$	0.3	$	—
Double Eagle	$	0.2	$	—	$	—	$	—
HoustonLink	$	—	$	—	$	0.2	$	—
MVP	$	—	$	0.6	$	2.2	$	—
Powder Springs	$	—	$	—	$	—	$	—
Saddlehorn	$	—	$	0.2	$	—	$	—
Seabrook	$	—	$	0.1	$	3.2	$	—

We entered into a long-term terminalling and storage contract with Seabrook for exclusive use of dedicated tankage that provides our customers with crude oil storage capacity and dock access for crude oil imports and exports on the Texas Gulf Coast (see Note 11 – Leases for more details regarding this lease).

We also made purchases of transmix from MVP throughout the year totaling $7.6 million.

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

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A summary of our investments in non-controlled entities (representing only our proportionate interests) follows (in millions):

Investments at December 31, 2020	$	1,213.9
Additional investment	5.6
Sale of ownership interests	(199.8)
Earnings of non-controlled entities:
Proportionate share of earnings	156.2
Amortization of excess investment and capitalized interest	(1.8)
Earnings of non-controlled entities	154.4
Less:
Distributions from operations of non-controlled entities	193.3
Investments at December 31, 2021	$	980.8

Summarized financial information of our non-controlled entities (representing 100% of the interests in these entities) follows (in millions):

	December 31,
	2020		2021
Current assets	$	243.8	$	227.0
Noncurrent assets	2,846.7		2,795.7
Total assets	$	3,090.5	$	3,022.7
Current liabilities	$	143.6	$	178.6
Noncurrent liabilities	57.5		59.5
Total liabilities	$	201.1	$	238.1
Equity	$	2,889.4	$	2,784.6

	Year Ended December 31,
	2019		2020		2021
Revenue	$	782.0	$	752.7	$	733.1
Net income	$	507.5	$	471.4	$	463.4

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8.    Inventory

Inventory is comprised primarily of refined products, crude oil, liquefied petroleum gases and transmix and is stated and relieved at the lower of average cost or net realizable value.

Inventory at December 31, 2020 and 2021 was as follows (in millions):

	December 31,
	2020		2021
Refined products	$	72.0	$	138.0
Crude oil	32.4		25.4
Liquefied petroleum gases	25.0		42.0
Transmix	23.4		72.4
Additives	5.4		3.3
Total inventory	$	158.2	$	281.1

9.    Consolidated Statements of Cash Flows

Changes in the components of operating assets and liabilities are as follows (in millions):

	Year Ended December 31,
	2019		2020		2021
Trade accounts receivable and other accounts receivable	$	(20.3)	$	(0.9)	$	(29.1)
Inventory	2.7		14.0		(122.9)
Accounts payable	(1.9)		4.5		16.0
Accrued payroll and benefits	4.8		(22.3)		22.8
Accrued interest payable	1.0		(5.3)		—
Accrued taxes other than income	12.6		4.4		8.8
Deferred revenue	(11.4)		(10.7)		(6.1)
Accrued product liabilities	15.9		(8.5)		78.3
Other current and noncurrent assets and liabilities	(1.3)		(12.3)		22.5
Total	$	2.1	$	(37.1)	$	(9.7)

Other current and noncurrent assets and liabilities above exclude certain non-cash items that were reflected in the consolidated balance sheets but were not reflected in the statements of cash flows. At December 31, 2019 and 2020, the long-term pension and benefits liability was increased by $27.0 million and $21.5 million, respectively, resulting in a corresponding increase in accumulated other comprehensive loss (“AOCL”). At December 31, 2021, the long-term pension and benefits liability was decreased by $16.3 million, resulting in a corresponding decrease in AOCL.

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10.    Debt

Long-term debt at December 31, 2020 and 2021 was as follows (in millions): 

	December 31,
	2020		2021
Commercial paper	$	—	$	108.0
3.20% Notes due 2025	250.0		250.0
5.00% Notes due 2026	650.0		650.0
3.25% Notes due 2030	500.0		500.0
6.40% Notes due 2037	250.0		250.0
4.20% Notes due 2042	250.0		250.0
5.15% Notes due 2043	550.0		550.0
4.20% Notes due 2045	250.0		250.0
4.25% Notes due 2046	500.0		500.0
4.20% Notes due 2047	500.0		500.0
4.85% Notes due 2049	500.0		500.0
3.95% Notes due 2050	800.0		800.0
Face value of long-term debt	5,000.0		5,108.0
Unamortized debt issuance costs(1)	(40.1)		(37.8)
Net unamortized debt premium(1)	18.8		18.6
Long-term debt, net	$	4,978.7	$	5,088.8

(1)    Debt issuance costs and note discounts and premiums 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.

At December 31, 2021, maturities of our senior notes were as follows: $0 in 2022 through 2024; $250 million in 2025; and $4.75 billion thereafter.

Other Debt

Revolving Credit Facility. At December 31, 2021, the total borrowing capacity under our revolving credit facility maturing in May 2024 was $1.0 billion. Any borrowings outstanding under this facility are classified as long-term debt on our consolidated balance sheets. Borrowings under the facility are unsecured and bear interest at LIBOR plus a spread ranging from 0.875% to 1.500% based on our credit ratings. Additionally, an unused commitment fee is assessed at a rate between 0.075% and 0.200% depending on our credit ratings. The unused commitment fee was 0.125% at December 31, 2021. Borrowings under this facility may be used for general purposes, including capital expenditures. As of December 31, 2020 and 2021, there were no borrowings outstanding under this facility and $3.5 million was obligated for letters of credit. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheets, but decrease our borrowing capacity under this facility.

Our revolving credit facility requires us to maintain a specified ratio of consolidated debt to EBITDA (as defined in the credit agreement) of no greater than 5.0 to 1.0. In addition, the revolving credit facility and the indentures under which our senior notes were issued contain covenants that limit our ability to, among other things, incur indebtedness secured by certain liens or encumber our assets, engage in certain sale-leaseback transactions and

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consolidate, merge or dispose of all or substantially all of our assets. We were in compliance with these covenants as of and during the year ended December 31, 2021.

Commercial Paper Program. We have a commercial paper program under which we may issue commercial paper notes in an amount up to the available capacity under our $1.0 billion revolving credit facility. The maturities of the commercial paper notes vary, but may not exceed 397 days from the date of issuance. Because the commercial paper we can issue is limited to amounts available under our revolving credit facility, amounts outstanding under the program are classified as long-term debt. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. The weighted average interest rate for commercial paper borrowings based on the number of days outstanding was 0.4% and 0.2% for the year ended December 31, 2020 and 2021, respectively. There was $108.0 million outstanding under this program at December 31, 2021.

During the years ending December 31, 2019, 2020 and 2021, total cash payments for interest on all indebtedness, excluding the impact of related interest rate swap agreements, were $217.1 million, $234.5 million and $221.6 million, respectively.

11.    Leases

We have both lessee and lessor arrangements. Our leases are evaluated at inception or at any subsequent modification. Depending on the terms, leases are classified as either operating or finance leases if we are the lessee, or as operating, sales-type or direct financing leases if we are the lessor, as appropriate under ASC 842, Leases.  Our lessee arrangements primarily include a terminalling and storage contract where we have exclusive use of dedicated tankage, leased pipelines and office buildings. Our lessor arrangements include pipeline capacity and storage contracts and our condensate splitter tolling agreement that qualify as operating leases under ASC 842. In addition, we have a long-term throughput and deficiency agreement with a customer that is being accounted for as a sales-type lease under ASC 842.

In accordance with ASC 842, we have made an accounting policy election to not apply the standard to lessee arrangements with a term of one year or less and no purchase option that is reasonably certain of exercise. We will continue to account for these short-term arrangements by recognizing payments and expenses as incurred, without recording a lease liability and right-of-use asset.

We have also made an accounting policy election for both our lessee and lessor arrangements to combine lease and non-lease components. This election is applied to all of our lease arrangements as our non-lease components do not result in significant timing differences in the recognition of rental expenses or income.

Operating Leases – Lessee

We recognize a lease liability for each lease based on the present value of remaining minimum fixed rental payments (which includes payments under any renewal option that we are reasonably certain to exercise), using a discount rate that approximates the rate of interest we would have to pay to borrow on a collateralized basis over a similar term. We also recognize a right-of-use asset for each lease, valued at the lease liability, adjusted for prepaid or accrued rent balances existing at the time of initial recognition. The lease liability and right-of-use asset are reduced over the term of the lease as payments are made and the assets are used.

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

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Minimum fixed rental payments are recognized on a straight-line basis over the life of the lease as costs and expenses on our consolidated statements of income. Variable and short-term rental payments are recognized as costs and expenses as they are incurred. Variable payments consist of amounts that exceed the contractual minimum rental payment (for example, payment increases tied to a change in a market index). Future minimum rental payments under operating leases with initial terms greater than one year as of December 31, 2021 are as follows (in millions):

	Third Party Leases		Seabrook Lease		All Leases
2022	$	21.2	$	9.9	$	31.1
2023	21.4		9.9		31.3
2024	21.7		9.7		31.4
2025	21.8		6.6		28.4
2026	12.5		6.6		19.1
Thereafter	34.1		17.6		51.7
Total future minimum rental payments	132.7		60.3		193.0
Present value discount	12.1		7.8		19.9
Total operating lease liability	$	120.6	$	52.5	$	173.1

The following tables provide a summary of the effect on our consolidated statements of income for the years ended December 31, 2019, 2020 and 2021 (in millions):

	Year Ended December 31, 2019
	Third Party Leases		Seabrook Lease		All Leases
Fixed lease expense	$	19.2	$	10.8	$	30.0
Short-term lease expense	1.6		—		1.6
Variable lease expense	3.0		15.0		18.1
Total lease expense	$	23.8	$	25.8	$	49.7

	Year Ended December 31, 2020
	Third Party Leases		Seabrook Lease		All Leases
Fixed lease expense	$	19.2	$	14.3	$	33.5
Short-term lease expense	1.3		—		1.3
Variable lease expense	4.1		14.8		18.9
Total lease expense	$	24.6	$	29.1	$	53.7

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	Year Ended December 31, 2021
	Third Party Leases		Seabrook Lease		All Leases
Fixed lease expense	$	21.0	$	12.7	$	33.7
Short-term lease expense	1.7		—		1.7
Variable lease expense	3.4		6.8		10.2
Total lease expense	$	26.1	$	19.5	$	45.6

The following table provides a summary of the effect on our consolidated balance sheets as of December 31, 2020 and 2021 (dollars in millions):

	As of and for the Year Ended
	December 31, 2020									December 31, 2021
	Third Party Leases			Seabrook Lease			All Leases			Third Party Leases			Seabrook Lease			All Leases
Current lease liability	$	17.1		$	10.4		$	27.5		$	17.8		$	8.0		$	25.8
Long-term lease liability	$	85.0		$	52.5		$	137.5		$	102.8		$	44.5		$	147.3
Right-of-use asset	$	103.2		$	62.9		$	166.1		$	121.7		$	52.5		$	174.2
Operating cash flows for operating leases	$	24.1		$	29.1		$	53.2		$	26.2		$	19.5		$	45.7
Weighted average remaining lease term (years)	6			7			7			7			7			7
Weighted average discount  rate	3.7		%	4.0		%	3.8		%	3.0		%	4.1		%	3.4		%

Operating Leases – Lessor

We recognize fixed rental income on a straight-line basis over the life of the lease as revenue on our consolidated statements of income. Variable rental payments are recognized as revenue in the period in which the circumstances on which the variable lease payments are based occur.

Future minimum payments receivable under operating leases with initial terms greater than one year as of December 31, 2021 are estimated as follows (in millions):

2022	$	24.9
2023	25.2
2024	21.9
2025	13.8
2026	13.1
Thereafter	32.9
Total	$	131.8

We recognized variable lease revenue of $58.4 million, $61.4 million and $61.0 million, respectively, for the years ended December 31, 2019, 2020 and 2021, primarily related to our condensate splitter.

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At December 31, 2021, property, plant and equipment utilized by our customers in operating lease arrangements consisted of: $216.9 million of processing equipment; $56.4 million of storage tanks; $47.5 million of pipeline and station equipment; and $29.0 million of other assets. The processing equipment primarily relates to our condensate splitter.

Sales-Type Lease – Lessor

We entered into a long-term throughput and deficiency agreement with a customer on a pipeline and related assets that we constructed in Texas and New Mexico, which contains minimum volume/payment commitments. Our customer has the option to purchase this pipeline and related assets at the end of the lease term for a nominal amount. This agreement is accounted for as a sales-type lease under ASC 842. The net investment under this arrangement as of December 31, 2020 and 2021 was as follows (in millions):

	December 31, 2020		December 31, 2021
Total minimum lease payments receivable	$	14.0	$	12.2
Less: Unearned income	2.3		1.8
Recorded net investment in sales-type lease	$	11.7	$	10.4

The net investment in this sales-type lease was classified in the consolidated balance sheets as follows (in millions):

	December 31, 2020		December 31, 2021
Other accounts receivable	$	1.2	$	1.3
Long-term receivables	10.5		9.1
Total	$	11.7	$	10.4

Future minimum payments receivable under this sales-type lease for the next five years are $1.7 million each year with $3.5 million due thereafter.

12.    Employee Benefit Plans

Our pension and postretirement benefit liabilities represent the funded status of the present value of benefit obligations of our employee benefit plans. We develop pension, postretirement medical and life benefit costs from third-party actuarial valuations. We establish actuarial assumptions to anticipate future events and use those assumptions when calculating the expense and liabilities related to these plans. These factors include assumptions management makes concerning expected investment return on plan assets, discount rates, health care costs trend rates, turnover rates and rates of future compensation increases, among others. In addition, we use subjective factors such as withdrawal and mortality rates to develop actuarial valuations. Management reviews and updates these assumptions on an annual basis. The actuarial assumptions that we use may differ from actual results due to changing market rates or other factors. These differences could affect the amount of pension and postretirement medical and life benefit expense we will recognize in future periods.

Defined Contribution Plan. 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, including expenses related to discontinued operations, were $11.4 million, $12.2 million and $10.6 million in 2019, 2020 and 2021, respectively.

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Defined Benefit Plans. We sponsor two pension plans, including one for non-union employees and one for union employees, and a postretirement benefit plan for certain employees. The annual measurement date of these plans is December 31.

The following table presents the changes in benefit obligations and plan assets for pension benefits and other postretirement benefits, as well as the end-of-period accumulated benefit obligation, including amounts related to discontinued operations, for the years ended December 31, 2020 and 2021 (in millions):

	Pension Benefits				Other Postretirement Benefits
	2020		2021		2020		2021
Change in benefit obligations:
Benefit obligations at beginning of year	$	381.2	$	443.6	$	15.2	$	17.3
Service cost	27.7		28.2		0.3		0.3
Interest cost	11.0		9.5		0.5		0.4
Plan participants’ contributions	—		—		0.6		0.8
Actuarial (gain) loss	53.2		(19.4)		2.5		0.9
Benefits paid	(23.1)		(29.2)		(1.8)		(1.9)
Curtailment gain	(1.7)		—		—		—
Settlement payments	(4.7)		(9.3)		—		—
Benefit obligations at end of year	443.6		423.4		17.3		17.8
Change in plan assets:
Fair value of plan assets at beginning of year	249.2		295.7		—		—
Employer contributions	29.3		27.6		1.2		1.1
Plan participants’ contributions	—		—		0.6		0.8
Actual return on plan assets	43.6		9.7		—		—
Benefits paid	(23.1)		(29.2)		(1.8)		(1.9)
Settlement payments	(3.3)		(9.3)		—		—
Fair value of plan assets at end of year	295.7		294.5		—		—
Funded status at end of year	$	(147.9)	$	(128.9)	$	(17.3)	$	(17.8)
Accumulated benefit obligations	$	324.8	$	305.0

At December 31, 2020 and 2021, the accumulated benefit obligations of each of our plans exceeded the fair value of the related plan’s assets.

The pension plans’ actuarial gain in 2021 of $19.4 million is primarily due to the impact of increases in the discount rates used to calculate the benefit obligations, partially offset by demographic changes. The pension benefit obligations experienced an actuarial loss of $53.2 million in 2020 primarily due to the impact of decreases in the discount rates used to calculate the benefit obligations, partially offset by changes in salary assumptions and higher asset returns.

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The following table summarizes information for pension plans with obligations in excess of plan assets (in millions):

	December 31,
	2020		2021
Plans with a projected benefit obligation in excess of plan assets:
Projected benefit obligation	$	443.6	$	423.4
Fair value of plan assets	$	295.7	$	294.5
Plans with an accumulated benefit obligation in excess of plan assets:
Accumulated benefit obligation	$	324.8	$	305.0
Fair value of plan assets	$	295.7	$	294.5

Amounts recognized in the consolidated balance sheets included in these financial statements were as follows (in millions):

	Pension Benefits				Other Postretirement Benefits
	2020		2021		2020		2021
Amounts recognized in consolidated balance sheets:
Current accrued benefit cost	$	—	$	—	$	1.4	$	1.7
Long-term pension and benefits	147.9		128.9		15.9		16.1
	147.9		128.9		17.3		17.8
Accumulated other comprehensive loss:
Net actuarial loss	(120.5)		(95.3)		(10.4)		(10.7)
Prior service credit	2.7		2.5		—		—
	(117.8)		(92.8)		(10.4)		(10.7)
Net amount of liabilities and accumulated other comprehensive loss recognized in consolidated balance sheets	$	30.1	$	36.1	$	6.9	$	7.1

Net periodic benefit expense for the years ended December 31, 2019, 2020 and 2021 was as follows (in millions): 

	Pension Benefits						Other Postretirement Benefits
	2019		2020		2021		2019		2020		2021
Components of net periodic benefit costs:
Service cost	$	25.4	$	27.7	$	28.2	$	0.2	$	0.3	$	0.3
Interest cost	12.2		11.0		9.5		0.5		0.5		0.4
Expected return on plan assets	(9.4)		(11.4)		(11.9)		—		—		—
Amortization of prior service credit	(0.2)		(0.2)		(0.2)		—		—		—
Amortization of actuarial loss	5.5		5.4		5.4		0.3		0.4		0.6
Settlement cost	2.6		1.0		2.6		—		—		—
Settlement gain on disposition of assets	—		(1.3)		—		—		—		—
Net periodic benefit cost	$	36.1	$	32.2	$	33.6	$	1.0	$	1.2	$	1.3

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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 (income) expense in our consolidated statements of income.

Changes in plan assets and benefit obligations recognized in other comprehensive income (loss) during 2019, 2020 and 2021 were as follows (in millions):

	Pension Benefits						Other Postretirement Benefits
	2019		2020		2021		2019		2020		2021
Beginning balance	$	(88.6)	$	(104.7)	$	(117.8)	$	(5.4)	$	(8.4)	$	(10.4)
Net actuarial gain (loss)	(24.0)		(21.0)		17.2		(3.3)		(2.5)		(0.9)
Amortization of prior service credit	(0.2)		(0.2)		(0.2)		—		—		—
Amortization of actuarial loss	5.5		5.4		5.4		0.3		0.5		0.6
Curtailment gain	—		1.7		—		—		—		—
Settlement cost	2.6		1.0		2.6		—		—		—
Amount recognized in other comprehensive loss	(16.1)		(13.1)		25.0		(3.0)		(2.0)		(0.3)
Ending balance	$	(104.7)	$	(117.8)	$	(92.8)	$	(8.4)	$	(10.4)	$	(10.7)

Actuarial gains and losses are amortized over the average future service period of the current active plan participants expected to receive benefits. The corridor approach is used to determine when actuarial gains and losses are to be amortized and is equal to 10% of the greater of the projected benefit obligation or the market related value of plan assets. The amount of gain or loss in excess of the calculated corridor is subject to amortization.

The weighted average rate assumptions used to determine projected benefit obligations were as follows:

	Pension Benefits		Other Postretirement Benefits
	2020	2021	2020	2021
Discount rate	2.23%	2.61%	2.30%	2.64%
Rate of compensation increase	4.53%	6.51%	n/a	n/a
Cash balance interest crediting rate	1.70%	1.94%	n/a	n/a

The weighted average rate assumptions used to determine net pension and other postretirement benefit plans expense were as follows:

 

	Pension Benefits			Other Postretirement Benefits
	For the Year Ended December 31,			For the Year Ended December 31,
	2019	2020	2021	2019	2020	2021
Discount rate	3.98%	3.01%	2.23%	4.08%	3.06%	2.30%
Rate of compensation increase	6.48%	4.58%	4.53%	n/a	n/a	n/a
Expected rate of return on plan assets	6.00%	4.50%	4.10%	n/a	n/a	n/a
Cash balance interest crediting rate	2.78%	2.16%	1.70%	n/a	n/a	n/a

The non-pension postretirement benefit plans provide for retiree contributions and contain other cost-sharing features such as deductibles and coinsurance. The accounting for these plans anticipates future cost sharing that is consistent with management’s expressed intent to increase the retiree contribution rate generally in line with health care cost increases.

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The annual assumed rate of increase in the health care cost trend rate for 2022 is 6.0% decreasing systematically to 5.08% by 2029 for pre-65 year old participants.

The fair values of the pension plan assets at December 31, 2020 were as follows (in millions):

Asset Category	Total		Quoted Prices in Active  Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Domestic equity securities:(1)
Small-cap fund	$	5.8	$	5.8	$	—	$	—
Mid-cap fund	5.8		5.8		—		—
Large-cap fund	47.6		47.6		—		—
International equity fund	29.9		29.9		—		—
Fixed income securities:(1)
Short-term bond fund	4.2		4.2		—		—
Intermediate-term bond fund	34.9		34.9		—		—
Long-term investment grade bond funds	161.0		161.0		—		—
Other:
Short-term investment fund	6.3		6.3		—		—
Group annuity contract	0.2		—		—		0.2
Fair value of plan assets	$	295.7	$	295.5	$	—	$	0.2

(1) We hold equity and fixed income securities through investments in mutual funds, which are dedicated to each category as indicated.

The fair values of the pension plan assets at December 31, 2021 were as follows (in millions):

Asset Category	Total		Quoted Prices in Active  Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Domestic equity securities(1):
Small-cap fund	$	6.1	$	6.1	$	—	$	—
Mid-cap fund	6.0		6.0		—		—
Large-cap fund	48.0		48.0		—		—
International equity fund	30.1		30.1		—		—
Fixed income securities(1):
Long-term investment grade bond funds	197.1		197.1		—		—
Other:
Short-term investment fund	7.0		7.0		—		—
Group annuity contract	0.2		—		—		0.2
Fair value of plan assets	$	294.5	$	294.3	$	—	$	0.2

(1) We hold equity and fixed income securities through investments in mutual funds, which are dedicated to each category as indicated.

As reflected in the tables above, Level 3 activity was not material.

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The investment strategies for the various funds held as pension plan assets by asset category are as follows: 

Asset Category	Fund’s Investment Strategy
Domestic equity securities:
Small-cap fund	Seeks to track performance of the Center for Research in Security Prices (“CRSP”) US Small Cap Index
Mid-cap fund	Seeks to track performance of the CRSP US Mid Cap Index
Large-cap fund	Seeks to track performance of the Standard & Poor’s 500 Index
International equity fund	Seeks to track performance of the FTSE Global All Cap ex US Index
Fixed income securities:
Short-term bond fund	Seeks current income with limited price volatility through investment in primarily high quality bonds with short-term maturities
Intermediate-term bond fund	Seeks moderate and sustainable level of current income by investing primarily in high quality fixed income securities with maturities from five to ten years
Long-term investment grade bond funds	Seek high and sustainable current income through investment primarily in long-term investment grade debt securities
Other:
Short-term investment funds	Invest in high quality short-term money market instruments issued by the U.S. Treasury
Group annuity contract	Earns interest quarterly equal to the effective yield of the 91-day U.S. Treasury bill

The expected long-term rate of return on plan assets was determined by combining a review of projected returns, historical returns of portfolios with assets similar to the current portfolios of the union and non-union pension plans and target weightings of each asset classification. Our investment objective for the assets within the pension plans is to earn a return that meets or exceeds the growth of obligations that result from interest and changes in the discount rate, while avoiding excessive risk. Defined diversification goals are set in order to reduce the risk of wide swings in the market value from year to year, or of incurring large losses that may result from concentrated positions. As a result, our plan assets have no significant concentrations of credit risk. Additionally, liquidity risks are minimized because the funds that the plans have invested in are publicly traded. We evaluate risks based on the potential impact to the predictability of contribution requirements, probability of under-funding, expected risk-adjusted returns and investment return volatility. Funds are invested with multiple investment managers. Our liabilities are calculated using rates defined by the Pension Protection Act of 2006. Approximately 70% of the plans’ investments are allocated to fixed-income securities and invested to match the durations of the plans’ short, intermediate and long-term pension liabilities, with the amount invested in each duration reflecting that duration’s proportion of the plans’ liabilities. The remaining approximately 30% of the plans’ investments are allocated to equity securities.

The target allocation and actual weighted average asset allocation percentages at December 31, 2020 and 2021 were as follows:

	2020		2021
	Actual	Target	Actual	Target
Equity securities	30%	30%	30%	30%
Fixed income securities	68%	67%	67%	70%
Other	2%	3%	3%	—%

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As of December 31, 2021, the benefit amounts expected to be paid from plan assets through December 31, 2031 were as follows (in millions): 

	Pension Benefits		Other Postretirement Benefits
2022	$	16.2	$	1.7
2023	$	18.1	$	1.5
2024	$	21.6	$	1.3
2025	$	22.4	$	1.3
2026	$	27.4	$	1.2
2027 through 2031	$	147.9	$	4.0

Contributions estimated to be paid by us into the plans in 2022 are $37.2 million and $1.7 million for the pension and other postretirement benefit plans, respectively.

13.    Long-Term Incentive Plan

The compensation committee of our board administers our long-term incentive plan (“LTIP”) covering certain of our employees and the independent directors of our general partner. In April 2021, our compensation committee and our limited partners approved an amendment to the LTIP increasing the number of common units available for issuance from 11.9 million to 13.7 million. The LTIP primarily consists of phantom units. The estimated units remaining available under the LTIP at December 31, 2021 totaled approximately 2.4 million. The awards include: (i) performance-based awards issued to certain officers and other key employees (“performance-based awards”), (ii) time-based awards issued to certain officers and other key employees (“time-based awards,” and together with performance-based awards, “employee awards”) and (iii) awards issued to independent members of our board (“director awards”) that may be deferred and if deferred may be paid in cash. All of the awards include distribution equivalent rights, except non-deferred director awards.

The LTIP requires employee awards to be settled in our common units, except the settlement of distribution equivalents, which we pay in cash. As a result, we classify employee awards as equity. Fair value for these awards is determined on the grant date, and we recognize this value as compensation expense ratably over the requisite service period, which is the vesting period of each award. The vesting period for employee awards is generally three years; however, certain awards have been issued with shorter vesting periods while others have vesting periods of up to four years. Because employee awards contain distribution equivalent rights, the fair value of our employee awards is based on the closing price of our units on the grant date.

Payouts for performance-based awards are subject to the attainment of a financial metric. Additionally, the 2019 performance-based awards, which vested on December 31, 2021, were subject to an adjustment for our total unitholder return (the “TUR adjustment”), and the fair value of these awards was adjusted for the fair value of the TUR adjustment. The TUR adjustment is based on our total unitholder return at the end of the three-year vesting period of the awards in relation to the total unitholder returns of certain peer entities. The financial metric for the performance-based awards is our distributable cash flow per unit excluding commodity-related activities for the last year of the three-year vesting period as compared to established threshold, target and stretch levels. The payouts for the performance-related component of the awards can range from 0%, for results below threshold, up to 200%, for actual results at stretch or above. Payouts related to time-based awards are based solely on the completion of the requisite service period by the employee and contain no provisions that provide for a payout other than the original number of units awarded and the associated distribution equivalents.

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Performance-based awards are subject to forfeiture if a participant’s employment is terminated for any reason other than for termination within two years of a change-in-control that occurs on an involuntary basis without cause or on a voluntary basis for good cause, or due to retirement, disability or death prior to the vesting date.  These awards can vest early under certain circumstances following a change in control. Time-based awards are subject to forfeiture if a participant’s employment is terminated for any reason other than retirement, death or disability prior to the vesting date, or as the result of certain other employment restrictions. If an employee award recipient retires, dies or becomes disabled prior to the end of the vesting period, the award is prorated based upon months of employment completed during the vesting period, and the award is settled shortly after the end of the vesting period.

Compensation expense for our equity awards is calculated as the number of unit awards less forfeitures, multiplied by the grant date fair value of those awards, multiplied by the percentage of the requisite service period completed at each period end, multiplied by the expected payout percentage, less previously-recognized compensation expense.

Non-deferred director awards are paid in units valued on the grant date, with compensation expense calculated as the number of units awarded multiplied by the fair value of those units at that date. We classify deferred director awards as liability awards because they may be settled in cash. Because deferred director awards have distribution equivalent rights, the fair value of these awards equals the closing price of our units at the measurement date. Compensation expense for deferred director awards is calculated as the number of units awarded, multiplied by the fair value of those awards on the measurement date, less previously-recognized compensation expense.

Non-Vested Unit Awards

The following table includes the changes during the current fiscal year in the number of non-vested units that have been granted by the compensation committee. The amounts below do not include adjustments for above-target or below-target performance.

	Performance-Based Awards			Time-Based Awards			Total Awards
	Number of Unit Awards	Weighted Average Fair Value		Number of Unit Awards	Weighted Average Fair Value		Number of Unit Awards	Weighted Average Fair Value
Non-vested units - 1/1/2021	340,164	$	62.35	353,544	$	61.07	693,708	$	61.70
Units granted during 2021	281,823	$	40.85	301,873	$	40.99	583,696	$	40.92
Units vested during 2021	(161,484)	$	63.62	(168,204)	$	60.76	(329,688)	$	62.16
Units forfeited during 2021	(14,578)	$	51.23	(16,699)	$	50.92	(31,277)	$	51.06
Non-vested units - 12/31/21	445,925	$	48.66	470,514	$	48.67	916,439	$	48.67

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The table below summarizes the total non-vested unit awards outstanding, including estimated targeted financial performance adjustments, to determine our total equity-based liability accrual.

Grant Date	Non-Vested Unit Awards	Performance Adjustment to Unit Awards	Total Unit Award Accrual	Vesting Date	Unrecognized Compensation Expense (in millions)(a)
Performance-based awards:
2020 awards	171,400	(51,420)	119,980	12/31/2022	$	2.4
2021 awards	274,525	68,631	343,156	12/31/2023	9.3
Time-based awards:
2022 vesting date	178,911	—	178,911	12/31/2022	3.7
2023 vesting date	291,603	—	291,603	12/31/2023	8.3
Total	916,439	17,211	933,650		$	23.7

(a) Unrecognized compensation expense will be recognized over the remaining vesting period of the awards.

Weighted Average Fair Value

The weighted average fair value of awards granted during 2019, 2020 and 2021 was as follows:

	Performance-Based Awards			Time-Based Awards
	Number of Unit Awards	Weighted Average Fair Value		Number of Unit Awards	Weighted Average Fair Value
Units granted during 2019	182,834	$	63.65	195,031	$	62.91
Units granted during 2020	189,632	$	61.16	198,450	$	61.18
Units granted during 2021	281,823	$	40.85	301,873	$	40.99

Vested Unit Awards

The table below sets forth the numbers and values of units that vested in each of the three years ended December 31, 2021. The vested common units include adjustments for above-target financial and market performance.

Vesting Date	Vested Common Units	Fair Value of Unit Awards on Vesting Date (in millions)	Intrinsic Value of Unit Awards on Vesting Date (in millions)
12/31/2019	436,629	$31.0	$27.5
12/31/2020	235,127	$15.2	$10.0
12/31/2021	316,336	$19.3	$14.7

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Cash Flow Effects of LTIP Settlements

The difference between the common units issued to the participants and the total number of unit awards vested primarily represents the tax withholdings associated with the award settlement, which we pay in cash.

Settlement Date	Number of Common Units Issued, Net of Tax Withholdings	Tax Withholdings and Other Cash Payments (in millions)	Employer Taxes (in millions)	Total Cash Payments (in millions)
January 2019	199,792	$9.8	$0.9	$10.7
January 2020	275,093	$14.7	$1.3	$16.0
January 2021	150,435	$6.2	$0.7	$6.9

Compensation Expense Summary

Equity-based incentive compensation expense for 2019, 2020 and 2021, primarily recorded as G&A expense on our consolidated statements of income, was as follows (in millions):

	Year Ended December 31,
	2019		2020		2021
Performance awards	$	17.9	$	3.1	$	11.2
Time-based awards	$	6.1	$	8.9	$	10.6
Total	$	24.0	$	12.0	$	21.8

14.    Derivative Financial Instruments

We use derivative instruments to manage market price risks associated with inventories, interest rates and certain forecasted transactions. For those instruments that qualify for hedge accounting, the accounting treatment depends on their intended use and their designation. We classify derivative financial instruments qualifying for hedge accounting treatment into two categories: (1) cash flow hedges and (2) fair value hedges. We execute cash flow hedges to hedge against the variability in cash flows related to a forecasted transaction and execute fair value hedges to hedge against the changes in the value of a recognized asset or liability. At the inception of a hedged transaction, we document the relationship between the hedging instrument and the hedged item, the risk management objectives and the methods used for assessing and testing hedge effectiveness. We also assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows or fair value of the hedged item. If we determine that a derivative originally designated as a cash flow or fair value hedge is no longer highly effective, we discontinue hedge accounting prospectively and record the change in the fair value of the derivative in current earnings. The changes in fair value of derivative financial instruments that are not designated as hedges for accounting purposes, which we refer to as economic hedges, are included in current earnings.

As part of our risk management process, we assess the creditworthiness of the financial and other institutions with which we execute financial derivatives. Such financial instruments involve the risk of non-performance by the counterparty, which could result in material losses to us.

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Interest Rate Derivatives

We periodically enter into interest rate derivatives to hedge the fair value of debt or hedge against variability in

interest rates. For interest rate cash flow hedges, we record the unrealized gains or losses as an adjustment to other comprehensive income. The realized gains and losses from our cash flow hedges are recognized into earnings as an adjustment to our periodic interest expense over the life of the related debt issuance. For fair value hedges on long-term debt, we record the unrealized gains or losses as an adjustment to long-term debt, and realized amounts as an adjustment to our periodic interest expense. Adjustments resulting from discontinued hedges continue to be recognized in accordance with their historic hedging relationships.

In December 2020, upon issuance of an additional $300.0 million of 3.95% notes due 2050, we terminated and settled treasury lock agreements that we had previously entered into to protect against the variability of interest payments on this anticipated debt issuance for a gain of $1.0 million, which was included in our statements of cash flows as a net receipt on financial derivatives. These agreements were accounted for as cash flow hedges. The gain was recorded to other comprehensive income (loss) and will be recognized into earnings as an adjustment to our periodic interest expense over the term of the life of the associated notes.

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

In August 2019, upon issuance of our $500.0 million of 3.95% notes due 2050, we terminated and settled treasury lock agreements we had previously entered into to protect against the variability of interest payments on this anticipated debt issuance for a loss of $25.3 million, which was included in our statements of cash flows as a net payment on financial derivatives.  These agreements were accounted for as cash flow hedges. The loss was recorded to other comprehensive income (loss) and will be recognized into earnings as an adjustment to our periodic interest expense over the life of the associated notes.

In January 2019, upon issuance of $500.0 million of 4.85% notes due 2049, we terminated and settled treasury lock agreements that we had previously entered into to protect against the variability of interest payments on this anticipated debt issuance for a loss of $8.0 million, which was included in our statements of cash flows as a net payment on financial derivatives. These agreements were accounted for as cash flow hedges. The loss was recorded to other comprehensive income (loss) and will be recognized into earnings as an adjustment to our periodic interest expense over the life of the associated notes.

Commodity Derivatives

Our gas liquids 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 and over-the-counter commodity derivatives contracts and forward physical purchase and sale contracts to help manage commodity price changes and mitigate the risk of decline in the product margin realized from our gas liquids blending activities. Further, certain of our other commercial operations and marketing activities involve petroleum products inventories, and we also use derivatives contracts to hedge against price changes for some of these inventories.

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 costs associated with such transactions are recognized during

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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 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 derivative 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 December 31, 2021 were as follows:

Type of Contract/ Accounting Methodology	Product Represented by the Contract and Associated Barrels	Maturity Dates
Commodity derivatives contract - Economic hedges	3.3 million barrels of refined products and crude oil	Between January and November 2022
Commodity derivatives contract - Economic hedges	0.6 million barrels of gas liquids	Between January and April 2022

Commodity Derivatives Contracts and Deposits Offsets

At December 31, 2020 and 2021, we had made margin deposits of $34.2 million and $46.3 million, respectively, for our commodity derivatives contracts with our counterparties, which were recorded as current assets under commodity derivatives deposits on our consolidated balance sheets. We have the right to offset the combined fair values of our open derivatives 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 derivatives contracts separately from the related margin deposits on our consolidated balance sheets. Additionally, we have the right to offset the fair values of our derivatives 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 master netting arrangements are provided below as of December 31, 2020 and 2021 (in millions):

Description	Gross Amounts of Recognized Liabilities		Gross Amounts of Assets Offset in the Consolidated Balance Sheets		Net Amounts of Liabilities Presented in the Consolidated Balance Sheets		Margin Deposit Amounts Not Offset in the Consolidated Balance Sheets		Net Asset Amount(1)
As of December 31, 2020	$	(21.7)	$	1.2	$	(20.5)	$	34.2	$	13.7
As of December 31, 2021	$	(22.3)	$	5.1	$	(17.2)	$	46.3	$	29.1

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

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Basis Derivative Agreement

During 2019, we entered into a basis derivative agreement with a joint venture co-owner’s affiliate, and, contemporaneously, that affiliate entered into an intrastate transportation services agreement with the joint venture. Settlements under the basis derivative agreement are determined based on the basis differential of crude oil prices at different market locations and a notional volume of 30,000 barrels per day. As a result, we account for this agreement as a derivative. The agreement will expire in early 2022. We recognize the changes in fair value of this agreement based on forward price curves for crude oil in West Texas and the Houston Gulf Coast in other operating income (expense) in our consolidated statements of income. The liability for this agreement at December 31, 2020 and 2021, respectively, was $10.2 million and $1.5 million.

Impact of Derivatives on Our Financial Statements

Comprehensive Income

The changes in derivative activity included in AOCL for the years ended December 31, 2019, 2020 and 2021 were as follows (in millions):

	Year Ended December 31,
Derivative Losses Included in AOCL	2019		2020		2021
Beginning balance	$	(26.5)	$	(49.0)	$	(55.0)
Net loss on cash flow hedges	(25.2)		(9.5)		—
Reclassification of net loss on cash flow hedges to income	2.7		3.5		3.5
Ending balance	$	(49.0)	$	(55.0)	$	(51.5)

The following is a summary of the effect on our consolidated statements of income for the years ended December 31, 2019, 2020 and 2021 of derivatives that were designated as cash flow hedges (in millions):

	Interest Rate Contracts
	Amount of Loss Recognized in AOCL on  Derivatives			Location of Loss Reclassified from AOCL into Income	Amount of Loss Reclassified from AOCL into Income
Year Ended December 31, 2019		$	(25.2)	Interest expense		$	(2.7)
Year Ended December 31, 2020		$	(9.5)	Interest expense		$	(3.5)
Year Ended December 31, 2021		$	—	Interest expense		$	(3.5)

As of December 31, 2021, the net loss estimated to be classified to interest expense over the next twelve months from AOCL is approximately $3.5 million. This amount relates to the amortization of losses on interest rate contracts over the life of the related debt instruments.

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The following table provides a summary of the effect on our consolidated statements of income for the years ended December 31, 2019, 2020 and 2021 of derivatives that were not designated as hedging instruments (in millions):

		Amount of Gain (Loss) Recognized on Derivatives
		Year Ended December 31,
Derivative Instrument	Location of Gain (Loss) Recognized on Derivatives	2019		2020		2021
Commodity derivatives contracts	Product sales revenue	$	(66.5)	$	53.2	$	(143.2)
Commodity derivatives contracts	Cost of product sales	(0.2)		0.3		21.1
Basis derivative agreement	Other operating income (expense)	(10.2)		(4.3)		(5.6)
	Total	$	(76.9)	$	49.2	$	(127.7)

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

Balance Sheets

The following tables provide a summary of the fair value of derivatives, which are presented on a net basis in our consolidated balance sheets, that were not designated as hedging instruments as of December 31, 2020 and 2021 (in millions):

	December 31, 2020
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity derivatives contracts	Commodity derivatives contracts, net	$	0.1	Commodity derivatives contracts, net	$	21.7
Commodity derivatives contracts	Other noncurrent assets	1.1		Other noncurrent liabilities	—
Basis derivative agreement	Other current assets	—		Other current liabilities	8.8
Basis derivative agreement	Other noncurrent assets	—		Other noncurrent liabilities	1.4
	Total	$	1.2	Total	$	31.9
	December 31, 2021
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity derivatives contracts	Commodity derivatives contracts, net	$	5.1	Commodity derivatives contracts, net	$	22.3
Basis derivative agreement	Other current assets	—		Other current liabilities	1.5
	Total	$	5.1	Total	$	23.8

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15.    Fair Value Disclosures

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:

•Commodity derivatives contracts. These include exchange-traded and over-the-counter derivative contracts related to petroleum products. These contracts are carried at fair value on our consolidated balance sheets. The exchange-traded contracts are valued based on quoted prices in active markets, while the over-the-counter contracts are valued based on observable market data inputs including published commodity pricing data. See Note 14 – Derivative Financial Instruments for further disclosures regarding these contracts.

•Basis derivative agreement. During 2019, we entered into a basis derivative agreement with a joint venture co-owner’s affiliate, and, contemporaneously, that affiliate entered into an intrastate transportation services agreement with the joint venture. Settlements under the basis derivative agreement are determined based on the basis differential of crude oil prices at different market locations and a notional volume of 30,000 barrels per day (see Note 14 - Derivative Financial Instruments for further disclosures regarding this agreement). The fair value of this derivative was calculated based on observable market data inputs, including published commodity pricing data and market interest rates. The key inputs in the fair value calculation include the forward price curves for crude oil, the implied forward correlation in crude oil prices between West Texas and the Houston Gulf Coast, and the implied forward volatility for crude oil futures contracts.

•Long-term receivables. These include payments receivable under a sales-type leasing arrangement and cost reimbursement agreements. 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.

•Contractual obligations. At December 31, 2021, these primarily included a long-term contractual obligation we entered into in connection with the 2020 sale of three marine terminals to a subsidiary of Buckeye Partners, L.P. (“Buckeye”). This obligation requires us to perform certain environmental remediation work on Buckeye’s behalf at the New Haven, Connecticut terminal.  This contractual obligation was recorded at fair value on our consolidated balance sheets upon initial recognition and was calculated using our best estimate of potential outcome scenarios to determine our liability for the remediation costs required in this agreement.

•Debt. The fair value of our publicly traded notes was based on the prices of those notes at December 31, 2020 and 2021; 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.

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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, 2020 and 2021, based on the three levels established by ASC 820; Fair Value Measurements and Disclosures (in millions):

					Fair Value Measurements as of December 31, 2020 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)
Commodity derivatives contracts	$	(20.5)	$	(20.5)	$	(20.5)	$	—	$	—
Basis derivative agreement	$	(10.2)	$	(10.2)	$	—	$	(10.2)	$	—
Long-term receivables	$	22.8	$	22.8	$	—	$	—	$	22.8
Contractual obligations	$	(11.2)	$	(11.2)	$	—	$	—	$	(11.2)
Debt	$	(4,978.7)	$	(5,880.9)	$	—	$	(5,880.9)	$	—

					Fair Value Measurements as of December 31, 2021 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)
Commodity derivatives contracts	$	(17.2)	$	(17.2)	$	(18.6)	$	1.4	$	—
Basis derivative agreement	$	(1.5)	$	(1.5)	$	—	$	(1.5)	$	—
Long-term receivables	$	10.1	$	10.1	$	—	$	—	$	10.1
Contractual obligations	$	(9.8)	$	(9.8)	$	—	$	—	$	(9.8)
Debt	$	(5,088.8)	$	(5,711.5)	$	—	$	(5,711.5)	$	—

16.    Commitments and Contingencies

Certain conditions may exist as of the date our consolidated financial statements are issued that could result in a loss to us, but which will only be resolved when one or more future events occur or fail to occur. Our management assesses such contingent liabilities, which inherently involves significant judgment. In assessing loss contingencies related to legal proceedings that are pending against us or for unasserted claims that may result in proceedings, our management, with input from legal counsel, evaluates the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.

Environmental expenditures are charged to operating expense or capitalized based on the nature of the expenditures. We record environmental liabilities independently of any potential claim for recovery. Accruals related to environmental matters are generally determined based on site-specific plans for remediation, taking into account currently available facts, existing technologies and presently enacted laws and regulations. Accruals for environmental matters reflect our prior remediation experience and include an estimate for costs such as fees paid to contractors, outside engineering and consulting firms. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remediation feasibility study. Such accruals are adjusted as further information develops or circumstances change. The determination of the accrual amounts recorded for environmental liabilities includes significant judgments and assumptions made by

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management. The use of alternate judgments and assumptions could result in the recognition of different levels of environmental remediation costs.

We maintain specific insurance coverage, which may cover all or portions of certain environmental expenditures less a deductible. We recognize receivables in cases where we consider the realization of reimbursements of remediation costs as probable.

We recognize liabilities for other commitments and contingencies when, after analyzing the available information, we determine it is probable that an asset has been impaired, or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. When we can estimate a range of probable loss, we accrue the most likely amount within that range, or if no amount is more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as incurred.

Butane Blending Patent Infringement Proceeding

On October 4, 2017, Sunoco Partners Marketing & Terminals L.P. (“Sunoco”) brought an action for patent infringement in the U.S. District Court for the District of Delaware alleging Magellan Midstream Partners, L.P. (“Magellan”) and Powder Springs Logistics, LLC (“Powder Springs”) are infringing patents relating to butane blending at the Powder Springs facility located in Powder Springs, Georgia. Sunoco subsequently submitted pleadings alleging that Magellan is also infringing various patents related to butane blending at eight Magellan facilities, in addition to Powder Springs. Sunoco sought monetary damages, attorneys’ fees and a permanent injunction enjoining Powder Springs from infringing the subject patents. We have vigorously defended against all claims asserted by Sunoco. A jury trial concluded on December 6, 2021, at which the jury found Magellan willfully infringed the three patents in suit and awarded damages of approximately $9.4 million against Magellan relating to the eight Magellan facilities at issue. The jury further found that Powder Springs willfully infringed the one patent at issue relating to the Powder Springs facility and awarded approximately $2.8 million against Magellan and Powder Springs relating to that facility. Sunoco requested that the the court enhance the damages award based upon the jury’s finding of willfulness, and that the court award additional damages and pre- and post-judgment interest. Magellan and Powder Springs have filed post-trial pleadings opposing Sunoco’s request for enhanced damages and to otherwise challenge the finding of liability and willfulness. The final determination of the trial court is subject to potential future appeals by either or both parties to the litigation.The amounts we have accrued in relation to the claims are immaterial, and although it is not possible to predict the ultimate outcome, we believe the final 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 $13.5 million and $9.8 million at December 31, 2020 and December 31, 2021, 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 included in operating expenses on our consolidated statements of income. Environmental expenses were $3.8 million, $3.4 million and $3.2 million for the years ended December 31, 2019, 2020 and 2021, respectively.

Other

In first quarter 2020, we entered into a long-term contractual obligation in connection with the sale of three marine terminals to Buckeye.  This obligation requires us to perform certain environmental remediation work on Buckeye’s behalf in New Haven, Connecticut.  At December 31, 2020 our consolidated balance sheets included a current liability of $0.6 million and a noncurrent liability of $10.2 million, and as of December 31, 2021, our

99

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

consolidated balance sheets reflected a current liability of $0.5 million and a noncurrent liability of $8.9 million, reflecting the fair values of these obligations.

We have entered into an agreement to guarantee our 50% pro rata share, up to $25.0 million, of contractual obligations under Powder Springs’ credit facility. As of December 31, 2020 and 2021, our consolidated balance sheets reflected a $0.4 million other current liability and a corresponding increase in our investment in non-controlled entities on our consolidated balance sheets to reflect the fair value of this guarantee.

We and the non-controlled entities in which we own an interest are a party to various other claims, legal actions and complaints. While the results cannot be predicted with certainty, management believes the ultimate resolution of these claims, legal actions and complaints after consideration of amounts accrued, insurance coverage or other indemnification arrangements will not have a material adverse effect on our business.

17.    Concentration of Risks

We transport, store and distribute petroleum products for refiners, producers, marketers, traders and end users of those products. Our revenue producing activities are concentrated in the central U.S. Concentrations of customers may affect our overall credit risk as our customers may be similarly affected by changes in economic, regulatory or other factors. We generally secure transportation and storage revenue with warehouseman’s liens. We periodically evaluate the financial condition and creditworthiness of our customers and require additional security as we deem necessary.

As of December 31, 2021, we had 1,715 employees, primarily concentrated in the central and Gulf Coast regions of the U.S. There were 854 employees assigned to our refined products segment, 253 employees assigned to our crude oil segment and 526 employees assigned to provide G&A services.  We also had 82 employees assigned to our discontinued operations. Approximately 13% of our employees are represented by the United Steel Workers and covered by a collective bargaining agreement that expired at the end of January 2022.

18.    Related Party Transactions

Stacy Methvin is an independent member of our general partner’s board of directors and also serves as a director of one of our customers.  We received tariff, terminalling and other ancillary revenue from this customer of $29.6 million, $37.4 million and $65.2 million for the periods ending December 31, 2019, 2020 and 2021, respectively. We recorded a receivable of $3.9 million and $5.4 million from this customer at December 31, 2020 and 2021, respectively.  We occasionally have transmix settlements with this customer as well. Additionally, we received storage and other miscellaneous revenue of $0.5 million for the period ending December 31, 2020 and $0.3 million for the period ending December 31, 2021 from a subsidiary of a separate company for which Stacy Methvin served as a director until August 31, 2021.

See Note 7 – Investments in Non-Controlled Entities and Note 11 – Leases for a discussion of transactions with our joint ventures.

100

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

19.    Partners’ Capital and Distributions

Partners’ Capital

Our board authorized the repurchase of up to $1.5 billion of our common units through 2024. The timing, price and actual number of common units repurchased will depend on a number of factors including our expected expansion capital spending needs, excess cash available, balance sheet metrics, legal and regulatory requirements, market conditions and the trading price of our common units. The repurchase program does not obligate us to acquire any particular amount of common units, and the repurchase program may be suspended or discontinued at any time.

The following table details the changes in the number of our common units outstanding from January 1, 2019 through December 31, 2021:

Common units outstanding on January 1, 2019	228,195,160
February 2019—Settlement of employee LTIP awards	199,792
During 2019—Other(1)	8,476
Common units outstanding on December 31, 2019	228,403,428
Units repurchased during 2020	(5,568,260)
February 2020—Settlement of employee LTIP awards	275,093
During 2020—Other(1)	9,550
Common units outstanding on December 31, 2020	223,119,811
Units repurchased during 2021	(10,894,828)
January 2021—Settlement of employee LTIP awards	150,435
During 2021—Other(1)	12,572
Common units outstanding on December 31, 2021	212,387,990

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

Our partnership agreement allows us to issue additional partnership securities for any partnership purpose at any time and from time to time for consideration and on terms and conditions as our general partner determines, all without approval by our unitholders.

Common unitholders have the following rights, among others:

•right to receive distributions of our available cash within 45 days after the end of each quarter;

•right to elect the members of our board;

•right to remove Magellan GP, LLC as our general partner upon a 100% vote of outstanding unitholders;

•right to transfer common unit ownership to substitute common unitholders;

•right to receive an annual report, containing audited financial statements and a report on those financial statements by our independent public accountants, within 120 days after the close of the fiscal year end;

•right to receive information reasonably required for tax reporting purposes within 90 days after the close of the calendar year;

•right to vote according to the unitholder’s percentage interest in us at any meeting that may be called by our general partner; and

•right to inspect our books and records at the unitholder’s own expense.

In the event of liquidation, we would distribute all property and cash in excess of that required to discharge all liabilities to the unitholders in proportion to the positive balances in their respective capital accounts. The common unitholders’ liability is generally limited to their investment.

101

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

Distributions

Distributions we paid during 2019, 2020 and 2021 were as follows (in millions, except per unit amounts):

Payment Date	Per Unit  Distribution Amount		Total Distribution
2/14/2019	$	0.9975	$	227.8
5/15/2019	1.0050		229.5
8/14/2019	1.0125		231.3
11/14/2019	1.0200		233.0
Total	$	4.0350	$	921.6
2/14/2020	$	1.0275	$	234.8
5/15/2020	1.0275		231.2
8/14/2020	1.0275		231.2
11/13/2020	1.0275		229.9
Total	$	4.1100	$	927.1
2/12/2021	$	1.0275	$	229.4
5/14/2021	1.0275		229.0
8/13/2021	1.0275		226.6
11/12/2021	1.0375		221.4
Total	$	4.1200	$	906.4

20.     Subsequent Events

Recognizable events

No recognizable events have occurred subsequent to December 31, 2021.

Non-recognizable events

On January 25, 2022, Michael N. Mears notified the partnership of his decision to retire from his positions of President, Chief Executive Officer and Chairman of the Board of Directors effective on April 30, 2022. Our board elected Barry R. Pearl, currently the independent Lead Director, as Chairman of the Board and also elected Aaron L. Milford as Chief Executive Officer and President effective May 1, 2022. Mr. Milford currently serves as Chief Operating Officer and has served in such capacity since 2019. He served as Senior Vice President and Chief Financial Officer from 2015 to 2019 and various positions of increasing responsibility since joining us and our predecessor in 1995.

Approximately 13% of our employees are represented by the United Steel Workers and covered by a collective bargaining agreement that expired at the end of January 2022. We are operating under a 24-hour rolling extension of this agreement while negotiations for a new agreement continue.

On February 14, 2022, we paid distributions of $1.0375 per unit on our outstanding common units to unitholders of record at the close of business on February 7, 2022.

102

Quarterly Financial Data (unaudited)

Summarized quarterly financial data is as follows (in millions, except per unit amounts):

2020	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Revenue	$	748.3	$	439.5	$	576.4	$	557.8
Total costs and expenses	$	476.3	$	280.3	$	353.1	$	360.6
Operating margin	$	411.2	$	293.4	$	365.6	$	349.2
Income from continuing operations	$	276.0	$	129.9	$	204.7	$	177.5
Income from discontinued operations	$	11.7	$	3.9	$	6.9	$	6.4
Net income	$	287.7	$	133.8	$	211.6	$	183.9
Basic net income per common unit	$	1.26	$	0.59	$	0.94	$	0.82
Diluted net income per common unit	$	1.26	$	0.59	$	0.94	$	0.82
2021
Revenue	$	631.1	$	653.6	$	639.1	$	809.3
Total costs and expenses	$	398.8	$	429.3	$	400.4	$	555.4
Operating margin	$	371.6	$	375.2	$	385.7	$	408.1
Income from continuing operations	$	212.7	$	264.9	$	221.3	$	233.4
Income from discontinued operations	$	8.6	$	15.5	$	15.3	$	10.3
Net income	$	221.3	$	280.4	$	236.6	$	243.7
Basic net income per common unit	$	0.99	$	1.26	$	1.08	$	1.14
Diluted net income per common unit	$	0.99	$	1.26	$	1.08	$	1.14

103

Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A.Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We performed an evaluation of the effectiveness of the design and operation of our “disclosure controls and procedures” (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this report. We performed this evaluation under the supervision and with the participation of our management, including our general partner’s Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”). Based upon that evaluation, our general partner’s CEO and CFO concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed so that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to management, including the CEO and the CFO, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting that occurred during the quarter ended December 31, 2021 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

See “Management’s Annual Report on Internal Control Over Financial Reporting” set forth in Item 8. Financial Statements and Supplementary Data.

Item 9B.Other Information

None.

104

PART III

Item 10.Directors, Executive Officers and Corporate Governance

The information regarding the directors and executive officers of our general partner and our governance required by Items 401, 405, 406 and 407(c)(3), (d)(4) and (d)(5) of Regulation S-K will be presented in our definitive proxy statement to be filed pursuant to Regulation 14A (our “Proxy Statement”) under the following captions, which information is to be incorporated by reference herein:

•Director Election Proposal;

•Executive Officers of our General Partner;

•Section 16(a) Beneficial Ownership Reporting Compliance;

•Code of Ethics;

•Governance – Director Nominations; and

•Governance – Board Committees.

Item 11.Executive Compensation

The information regarding executive compensation required by Items 402 and 407(e)(4) and (e)(5) of Regulation S-K will be presented in our Proxy Statement under the following captions, which information is to be incorporated by reference herein:

•Compensation of Directors and Executive Officers;

•Governance – Compensation Committee – Interlocks and Insider Participation; and

•Compensation of Directors and Executive Officers – Compensation Committee Report.

Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information regarding securities authorized for issuance under equity compensation plans and security ownership required by Items 201(d) and 403 of Regulation S-K will be presented in our Proxy Statement under the following captions, which information is to be incorporated by reference herein:

•Securities Authorized for Issuance Under Equity Compensation Plans; and

•Security Ownership of Certain Beneficial Owners and Management.

Item 13.Certain Relationships and Related Transactions, and Director Independence

The information regarding certain relationships and related transactions and director independence required by Items 404 and 407(a) of Regulation S-K will be presented in our Proxy Statement under the following captions, which information is to be incorporated by reference herein:

•Transactions with Related Persons, Promoters and Certain Control Persons; and

•Governance – Director Independence.

Item 14.Principal Accountant Fees and Services

The information regarding principal accountant fees and services required by Item 9(e) of Schedule 14A of the Exchange Act will be presented in our Proxy Statement under the caption “Independent Auditor Proposal,” which information is to be incorporated by reference herein.

105

PART IV

Item 15.    Exhibits and Financial Statement Schedules

(a)1 and (a)2.

	Page
Financial Statements
Report of Independent Registered Public Accounting Firm (PCAOB ID 42)	52
Consolidated statements of income for the three years ended December 31, 2021	56
Consolidated statements of comprehensive income for the three years ended December 31, 2021	57
Consolidated balance sheets at December 31, 2020 and 2021	58
Consolidated statements of cash flows for the three years ended December 31, 2021	59
Consolidated statement of partners’ capital for the three years ended December 31, 2021	60
Notes 1 through 20 to consolidated financial statements	61
Not covered by reports of independent auditors:
Quarterly financial data (unaudited)	103

We have omitted all other required schedules since the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the financial statements and notes thereto.

(a)3, (b) and (c). The exhibits listed below on the Index to Exhibits are filed or incorporated by reference as part of this annual report.

106

Index to Exhibits

Exhibit No.	Description
Exhibit 3
*(a)	Certificate of Limited Partnership of Magellan Midstream Partners, L.P. dated August 30, 2000, as amended on November 15, 2002 and August 12, 2003 (filed as Exhibit 3.1 to Form 10-Q filed November 10, 2003).
*(b)	Fifth Amended and Restated Agreement of Limited Partnership of Magellan Midstream Partners, L.P. dated September 28, 2009 (filed as Exhibit 3.1 to Form 8-K filed September 30, 2009).
*(c)	Amendment No. 1 dated October 27, 2011 to Fifth Amended and Restated Agreement of Limited Partnership of Magellan Midstream Partners, L.P. dated September 28, 2009 (filed as Exhibit 3.1 to Form 8-K filed October 28, 2011).
*(d)	Amendment No. 2 dated January 16, 2017 to Fifth Amended and Restated Agreement of Limited Partnership of Magellan Midstream Partners, L.P. dated September 28, 2009 (filed as Exhibit 3.2 to Form 8-K filed January 17, 2017).
*(e)	Amendment No. 3 dated October 25, 2018 to Fifth Amended and Restated Agreement of Limited Partnership of Magellan Midstream Partners, L.P. dated September 28, 2009 (filed as Exhibit 3.1 to Form 8-K filed October 26, 2018).
*(f)	Amendment No. 4 dated September 25, 2020 to Fifth Amended and Restated Agreement of Limited Partnership of Magellan Midstream Partners, L.P. dated September 28, 2009 (filed as Exhibit 3.1 to Form 8-K filed September 25, 2020).
*(g)	Amended and Restated Certificate of Formation of Magellan GP, LLC dated November 15, 2002, as amended on August 12, 2003 (filed as Exhibit 3(f) to Form 10-K filed March 10, 2004).
*(h)	Third Amended and Restated Limited Liability Company Agreement of Magellan GP, LLC dated September 28, 2009 (filed as Exhibit 3.2 to Form 8-K filed September 30, 2009).
*(i)	Amendment No. 1 dated January 16, 2017 to Third Amended and Restated Limited Liability Company Agreement of Magellan GP, LLC dated September 28, 2009 (filed as Exhibit 3.1 to Form 8-K filed January 17, 2017).
*(j)	Amendment No. 2 dated January 25, 2022 to Third Amended and Restated Limited Liability Company Agreement of Magellan GP, LLC dated September 28, 2009 (filed as Exhibit 3.1 to Form 8-K filed January 31, 2022).
Exhibit 4
*(a)	Indenture dated as of April 19, 2007 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to Form 8-K filed April 20, 2007).
*(b)	First Supplemental Indenture dated as of April 19, 2007 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed April 20, 2007).

*(c)	Indenture dated as of August 11, 2010 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to Form 8-K filed August 16, 2010).
*(d)	Second Supplemental Indenture dated as of November 9, 2012 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed November 9, 2012).
*(e)	Third Supplemental Indenture dated as of October 10, 2013 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed October 10, 2013).
*(f)	Fourth Supplemental Indenture dated as of March 4, 2015 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed March 4, 2015).
*(g)	Fifth Supplemental Indenture dated as of March 4, 2015 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.3 to Form 8-K filed March 4, 2015).
*(h)	Sixth Supplemental Indenture dated as of February 29, 2016 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed February 29, 2016).
*(i)	Seventh Supplemental Indenture dated as of September 13, 2016 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed September 13, 2016).
*(j)	Eighth Supplemental Indenture dated as of October 3, 2017 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed October 3, 2017).
*(k)	Ninth Supplemental Indenture dated as of January 18, 2019 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed January 18, 2019).
*(l)	Tenth Supplemental Indenture dated as of August 19, 2019 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed August 19, 2019).
*(m)	Eleventh Supplemental Indenture dated as of May 20, 2020 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed May 20, 2020).
*(n)	Description of Securities (filed as Exhibit 4(o) to Form 10-K filed February 18, 2020).
Exhibit 10
*(a)	Amended and Restated Magellan Midstream Partners Long-Term Incentive Plan dated January 26, 2021 (filed as Exhibit 10(a) to Form 10-K filed February 18, 2021).
*(b)	Amendment No. 1 dated April 1, 2021 to Magellan Midstream Partners Long-Term Incentive Plans (filed as Exhibit 10.2 to Form 10-Q filed April 29, 2021).

107

Exhibit No.	Description
(c)	Description of Magellan 2022 Annual Incentive Program.
(d)	Magellan GP, LLC Non-Management Director Compensation Program effective January 1, 2022.
*(e)	Amended and Restated Director Deferred Compensation Plan effective January 28, 2014 (filed as Exhibit 10(d) to Form 10-K filed February 24, 2014).
*(f)	$1,000,000,000 Second Amended and Restated Credit Agreement dated as of October 26, 2017 among Magellan Midstream Partners, L.P., the Lenders party thereto, Wells Fargo Bank, National Association, as Administrative Agent and an Issuing Bank, JPMorgan Chase Bank, N.A., as Co-Syndication Agent and an Issuing Bank, and SunTrust Bank, as Co-Syndication Agent and an Issuing Bank (filed as Exhibit 10.1 to Form 8-K filed October 27, 2017).
*(g)	First Amendment to Second Amended and Restated Credit Agreement dated as of May 17, 2019 among Magellan Midstream Partners, L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (filed as Exhibit 10.2 to Form 8-K filed May 22, 2019).
*(h)	Magellan Midstream Holdings GP, LLC Executive Severance Pay Plan and Summary Plan Description, amended and restated effective April 1, 2021 (filed as Exhibit 10.1 to Form 10-Q filed April 29, 2021).
(i)	Form of 2022 Performance Based Phantom Unit Agreement for awards granted pursuant to the Magellan Midstream Partners Long-Term Incentive Plan.
(j)	Form of 2022 Retention Phantom Unit Agreement for awards granted pursuant to the Magellan Midstream Partners Long-Term Incentive Plan.
*(k)	Form of Commercial Paper Dealer Agreement between Magellan Midstream Partners, L.P., as Issuer, and the Dealer party thereto (filed as Exhibit 10.1 to Form 8-K filed April 22, 2014).
*(l)	Form of Indemnification Agreement by and among Magellan Midstream Partners, L.P., Magellan GP, LLC and the directors and officers of Magellan GP, LLC (filed as Exhibit 10.1 to Form 10-Q filed November 3, 2015).
*(m)	Equity Purchase Agreement between Magellan OLP, L.P., as Seller, and Buckeye Partners, L.P., as Buyer, dated June 9, 2021 (filed as Exhibit 10.1 to Form 10-Q filed July 29, 2021).
(n)	Retention Agreement dated January 31, 2020 between Magellan Midstream Holdings GP, LLC and Melanie Little.
*(o)	Retirement Agreement dated January 28, 2022 between Michael N. Mears and Magellan GP, LLC (filed as Exhibit 10.1 to Form 8-K filed January 31, 2022).
Exhibit 14
*(a)	Code of Ethics dated February 1, 2011 by Michael N. Mears, principal executive officer (filed as Exhibit 14(a) to Form 10-K filed February 25, 2011).
*(b)	Code of Ethics dated May 1, 2019 by Jeff L. Holman, principal financial and accounting officer (filed as Exhibit 14(b) to Form 10-K filed February 18, 2020).
Exhibit 21	Subsidiaries of Magellan Midstream Partners, L.P.
Exhibit 23	Consent of Independent Registered Public Accounting Firm.
Exhibit 31
(a)	Certification of Michael N. Mears, principal executive officer.
(b)	Certification of Jeff Holman, principal financial officer.
Exhibit 32
(a)	Section 1350 Certification of Michael N. Mears, Chief Executive Officer.
(b)	Section 1350 Certification of Jeff Holman, Chief Financial Officer.
Exhibit 101.INS	XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
Exhibit 101.SCH	XBRL Taxonomy Extension Schema.
Exhibit 101.CAL	XBRL Taxonomy Extension Calculation Linkbase.
Exhibit 101.DEF	XBRL Taxonomy Extension Definition Linkbase.
Exhibit 101.LAB	XBRL Taxonomy Extension Label Linkbase.
Exhibit 101.PRE	XBRL Taxonomy Extension Presentation Linkbase.

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

108

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

MAGELLAN MIDSTREAM PARTNERS, L.P. (Registrant)
By:	MAGELLAN GP, LLC, its general partner
By:	/s/  JEFF HOLMAN
	Jeff Holman Senior Vice President, Chief Financial Officer and Treasurer

Date: February 17, 2022

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacity and on the dates indicated.

109

Signature	Title	Date
/s/    MICHAEL N. MEARS	Chairman of the Board and Principal Executive Officer of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.	February 17, 2022
Michael N. Mears
/s/    JEFF HOLMAN	Principal Financial and Accounting Officer of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.	February 17, 2022
Jeff Holman
/s/    WALTER R. ARNHEIM	Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.	February 17, 2022
Walter R. Arnheim
/s/    ROBERT G. CROYLE	Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.	February 17, 2022
Robert G. Croyle
/s/    LORI A. GOBILLOT	Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.	February 17, 2022
Lori A. Gobillot
/s/    EDWARD J. GUAY	Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.	February 17, 2022
Edward J. Guay
/s/    CHANSOO JOUNG	Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.	February 17, 2022
Chansoo Joung
/s/    STACY P. METHVIN	Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.	February 17, 2022
Stacy P. Methvin
/s/    JAMES R. MONTAGUE	Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.	February 17, 2022
James R. Montague
/s/    BARRY R. PEARL	Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.	February 17, 2022
Barry R. Pearl

110

EX-10.C

Exhibit 10(c)

2022 Annual Incentive Program Summary

Magellan's 2022 Annual Incentive Program (“AIP”) is a discretionary bonus program to encourage individual activities that will improve the overall financial and operational performance of Magellan Midstream Partners, L.P. (“Magellan”). The 2022 AIP payout will be based on a combination of Magellan's performance and individual performance as determined by results achieved in the 2022 calendar year.

A “Funding Metric” has been established that sets a floor of performance for Magellan below which no payout for any metric will be made. An “Overriding Financial Trigger” has been set to allow for the results of the overall financial performance of Magellan to override the individual financial metrics set for Magellan. It is intended to address a possible condition where, even though one of the financial metrics is down, Magellan's overall financial performance is extremely strong. The AIP has financial metrics that are used to measure profitability as well as metrics for environmental, safety and culture performance. Goals for levels of achievement have been set for each metric. Payouts under the AIP begin after the threshold level of performance is achieved and the maximum payout occurs if results reach the stretch targets.

If target performance is achieved, 100% of the calculated payout is eligible to be paid under the AIP. If stretch performance is achieved, 200% of the calculated payout is eligible to be paid. If threshold is achieved, 50% of the calculated payout is eligible to be paid. If the results are lower than threshold, 0% of the calculated payout is eligible to be paid. The calculated payout percentage for performance between threshold and target, or between target and stretch, will be interpolated. Fifty percent (50%) of each eligible employee’s payout is subject to a personal performance adjustment.

Employees are eligible for the 2022 AIP if a regular full-time or part-time employee with a standard hour classification of 20 or more hours per week, including employees on military leave. Ineligible employees include, but are not limited to, employees on leave without pay, limited scope employees, contract employees, those whose employment ended prior to the award payout and employees with zero eligible earnings in the calendar year.

To be eligible to receive a payout, an employee must be employed during the calendar year including the last day of the calendar year and through the time the award is actually paid. Exceptions to this requirement will be made where a participant's employment is terminated as a result of retirement, death or the participant becomes eligible for long-term disability. Such employees will be eligible for a prorated award based on their compensation earned in the portion of the year worked prior to the employment termination or disability event. A participant, whose employment is terminated anytime between the end of the calendar year, but prior to the distribution of the payout under any other circumstances, will forfeit any award payable under the AIP. Forfeited awards will be allocated to all other eligible employees.

Eligible earnings include an employee's regular base pay and eligible overtime pay for the period in which the employee is a participant in the AIP, including, but not limited to, hours worked during a normal workday, Paid Time Off (PTO), short term disability, holiday pay, jury duty pay, bereavement pay and shift differentials, but excludes extraordinary compensation such as geographical differentials. Eligible earnings will exclude any unused PTO paid out due to the employment retirement, termination or disability event.

After the eligible payout is determined based on Magellan's metric results, an adjustment may be made based on the employee's individual performance. This adjustment, if applied, would adjust 50% of an employee's eligible incentive payout based on management's assessment of the employee's performance on individual goals and the employee's performance of job responsibilities. This adjustment can range from 0% to 200% of the 50% amount that is subject to the personal performance adjustment.

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2022 Annual Incentive Program Metrics

FUNDING METRIC

MetricThreshold

Distributable Cash Flow Funding occurs at greater than or equal to $881 million

The threshold funding metric is based upon the amount of distributable cash flow required for Magellan to maintain its 2021 fourth quarter distribution rate to unitholders throughout 2022.

OVERRIDING FINANCIAL TRIGGER

MetricTrigger

EBITDA less Maintenance Capital (including commodities) The combined financial metrics will be reset to the greater of actual metric results or a Target level payout at results of $1,387 million or more.

PERFORMANCE GOALS

($ in Millions)

Metrics	Weight	Threshold	Target	Stretch
EBITDA less Maintenance Capital (1) (2)	65%	$1,024	$1,121	$1,193
Commodities (1)(3)	10%	$126	$159	$194
Environmental, Safety & Culture Performance	25%	Discretionary	Discretionary	Discretionary

________________

(1) The overriding financial trigger will change the payout to at least a target level payout for the financial metrics when overall financial results have exceeded the trigger. The combined financial metrics will be reset to the greater of actual metric results or Target Level payouts when Magellan’s EBITDA less Maintenance Capital (including commodities) is $1,387 million or more

(2) EBITDA less Maintenance Capital includes any margin earned from crude oil and refined product marketing activities but excludes all other commodity-related activity.

(3) Commodities exclude any margin earned from crude oil and refined product marketing activities.

METRIC ADJUSTMENTS

If an acquisition occurs during the year, the financial metrics may be adjusted to reflect the impact of the transaction. The Environmental, Safety & Culture Performance actual results may exclude acquisitions until the new locations have a full calendar year to become compliant with Magellan’s System Integrity Plan policies and procedures.

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EX-10.D

Exhibit 10(d)

Magellan GP, LLC

Non-Management Director

Compensation Program

Effective January 1, 2022

	Compensation	Timing of Payment(1)
Annual Board Retainer:(2) Cash Common Units	$80,000 $135,000(3)	Paid quarterly as of January 1st, April 1st, July 1st and October 1st As of January 1st
Annual Chair Retainer:(2) Audit Committee Compensation Committee Conflicts Committee Nominating and Governance Committee Sustainability Committee Lead Director Independent Board Chair	$20,000 $20,000 $10,000 $15,000 $15,000 $20,000 $75,000	Paid quarterly as of January 1st, April 1st, July 1st and October 1st
Meeting Fees: Board Meeting Fees Committee Meeting Fees	$1,500 per meeting $1,500 per meeting	Paid quarterly as of January 1st, April 1st, July 1st and October 1st

1.For newly elected directors or a newly appointed committee chair, the annual board retainer and annual chair retainer, if applicable, are payable pro-rata for the year of election.

2.Directors who resign from the board or relinquish their role of committee chair after a payment date has occurred, but prior to the payment having been received, will receive a pro-rata annual board retainer and annual chair retainer for the period of time between the payment date and the resignation/relinquishment.

3.The number of common units to be issued for the annual board retainer will be determined based on the closing price on the first business day immediately following the January 1st payment date.

EX-10.I

Exhibit 10(i)

FORM OF PERFORMANCE BASED PHANTOM UNIT AGREEMENT

THIS PERFORMANCE BASED PHANTOM UNIT AGREEMENT (this “Agreement”) is by and between Magellan GP, LLC (the “Company”) and [PARTICIPANT NAME] (the “Participant”).

1.Grant of Phantom Units. The Company hereby grants to the Participant effective February 9, 2022 (the “Effective Date”), subject to the terms and conditions of the Magellan Midstream Partners Long-Term Incentive Plan, as amended and restated (the “Plan”), and this Agreement, the right to be eligible to receive a grant of [__________] phantom units, with tandem distribution equivalent rights (“DERs”), of Magellan Midstream Partners, L.P. (the “Partnership”). These Units, including the tandem DERs, are referred to in this Agreement as “Phantom Units” during the Restricted Period (as defined in Section 4) and “Units” after the Restricted Period. The number of Units received at the end of the Restricted Period will be determined based on performance criteria, employment status at that time and any other relevant provisions of the Plan and this Agreement. Until the Phantom Units vest and are paid, the Participant shall have no rights as a unitholder of the Partnership with respect to the Phantom Units.

2.Incorporation of Plan. The Plan is incorporated herein by reference, and all capitalized terms used herein, but not defined herein, shall have the meanings set forth in the Plan. The Participant acknowledges receipt of a copy of the Plan and hereby accepts the Phantom Units subject to all the terms and provisions of the Plan and this Agreement.

3.Compensation Committee of the Board - Decisions and Interpretations. The Participant agrees to accept as binding, conclusive and final all decisions and interpretations of the Compensation Committee of the Board (the “Committee”) of the Company with respect to any questions arising under the Plan and this Agreement. Participants shall have no right to petition or request the Committee to review, or bring an appeal to the Committee regarding, any decisions or interpretations of the Committee hereunder.

4.Restricted Period of Phantom Units. The Restricted Period begins on the Effective Date and ends on the first of the following events to occur:

a.December 31, 2024; or

b.Your Termination of Affiliation (excluding any transfer to an Affiliate of the Company) with the Company, voluntarily for Good Reason, or involuntarily (other than due to Cause) within two years following a Change of Control as set forth in the Plan.

5.Payment of Phantom Units and DERs.

a.Eligibility. To be eligible to receive a payout of the Phantom Units at the end of the Restricted Period, the Participant must be employed by the Company or its Affiliates at the end of the Restricted Period, or must have terminated employment during the Restricted Period due to Retirement, death or Disability.

b.Determination of Payout Amount. The final determination of the payout level of the Phantom Units will be based upon the performance metric outlined in Paragraph 7 and additional conditions outlined in Paragraph 8.

c.DERs. At the end of the Restricted Period, the Company will pay to the Participant, or the Participant’s legal representative, the value of the DERs on the gross number of Units awarded to the Participant pursuant to the terms of this Agreement. The value of the DERs shall be the amount of all distributions per Unit that would have been earned and paid during the Restricted Period on the gross number of Units awarded, and no interest shall be paid on such amount. Such payment of the DERs shall be in cash and subject to tax withholding requirements.

d.Timing of Payout. Subject to legal or contractual obligations, the Company will deliver to the Participant, or the Participant’s legal representative, as soon as practicable after the final determination of payout levels by the Committee, a number of Units equal in value to the number of Phantom Units calculated pursuant to Paragraphs 7 and 8, less the number of Units required to cover tax withholding requirements.

6.Termination of Employment Due to Retirement, Death or Disability. In the event a Participant’s employment with the Company or its Affiliates terminates prior to the end of the Restricted Period due to Retirement, death or Disability, the initial target grant of Phantom Units will be prorated based upon the Participant’s months of employment between January 1, 2022 and December 31, 2024. Such prorated amount will continue to be restricted and subject to the terms of this Agreement until the Restricted Period ends as provided in Section 4.a above. All Phantom Units in excess of the prorated amount shall be forfeited.

7.Performance Metric.

	Payout Schedule
2024 Distributable Cash Flow (“DCF”) per Unit (excluding commodity-related activity)	Threshold 50% Payout Level	Target 100% Payout Level	Stretch 200% Payout Level
	$X.XX	$X.XX	$X.XX

8.Determination of Payout Level. The number of Units to be paid to the Participant will be determined based on performance relative to the performance metric payout schedule in Paragraph 7. No payout will occur for results below the 50% payout level. The payout for results achieved between each payout level will be interpolated.

9.Other Provisions.

a.The Participant understands and agrees that payments under this Agreement shall not be used for, or in the determination of, any other payment or benefit under any continuing agreement, plan, policy, practice or arrangement providing for the making of any payment or the provision of any benefits to or for the Participant or the Participant’s beneficiaries or representatives, including, without limitation, any employment agreement, any change of control severance protection plan or any employee benefit plan as defined in Section 3(3) of ERISA, including, but not limited to qualified and non-qualified retirement plans.

b.Except as otherwise provided herein and in the Plan, in the event that the Participant’s employment with the Company or its Affiliates, or its or their successors, terminates prior to the vesting of the Phantom Units granted under this Agreement, such Phantom Units shall be forfeited.

c.By signing this Agreement, the Participant represents and agrees that he or she will keep the terms, amount and fact of this Agreement completely confidential, and that, unless required to do so by law, he or she will not hereafter disclose any information concerning this Agreement to anyone including, but not limited to, any past, present or prospective employee or applicant for employment of the Company or its Affiliates and any past, present or prospective customer of the Company, the Partnership or their Affiliates.

d.Neither the Phantom Units, nor the Participant’s interest in the Phantom Units, may be sold, assigned, transferred, pledged, hedged or otherwise disposed of or encumbered at any time prior to the vesting and payment of such Phantom Units under this Agreement.

e.If the Participant at any time forfeits any or all of the Phantom Units pursuant to this Agreement, the Participant agrees that all of the Participant’s rights to and interest in the Phantom Units shall terminate upon forfeiture without payment of consideration.

f.In the event a Participant’s employment with the Company or its Affiliates terminates prior to the end of the Restricted Period due to death, the DERs associated with the pro-rated vesting amount shall be paid to the beneficiary or beneficiaries as designated by the Participant in the electronic system of record. If no designation of beneficiary was made, the DERs payment will default to the Participant’s estate.

g.With respect to the right to receive payment of the Phantom Units under this Agreement, nothing contained herein shall give the Participant any rights that are greater than those of a general creditor of the Company.

10.Notices. All notices to the Company required hereunder shall be in writing and delivered by hand or by mail, addressed to Magellan GP, LLC, One Williams Center, Mail Drop 32, Tulsa, Oklahoma 74172, Attention: Compensation Department. Notices shall become effective upon their receipt by the Company if delivered in the forgoing manner.

Magellan GP, LLC

By: /s/ Michael N. Mears

Michael N. Mears

President and Chief Executive Officer

Magellan GP, LLC

Dated: February 9, 2022

EX-10.J

Exhibit 10(j)

FORM OF RETENTION PHANTOM UNIT AGREEMENT

THIS RETENTION PHANTOM UNIT AGREEMENT (this “Agreement”) is by and between Magellan GP, LLC (the “Company”) and [PARTICIPANT NAME] (the “Participant”).

1.Grant of Phantom Units. The Company hereby grants to the Participant effective February 9, 2022(the “Effective Date”), subject to the terms and conditions of the Magellan Midstream Partners Long-Term Incentive Plan, as amended and restated (the “Plan”), and this Agreement, the right to be eligible to receive a grant of [__________]phantom units, with tandem distribution equivalent rights (“DERs”), of Magellan Midstream Partners, L.P. (the “Partnership”). These phantom units, including the tandem DERs, are referred to in this Agreement as “Phantom Units” during the Restricted Period (as defined in Section 4) and “Units” after the Restricted Period. Until the Phantom Units vest and are paid, the Participant shall have no rights as a unitholder of the Partnership with respect to the Phantom Units.

2.Incorporation of Plan. The Plan is hereby incorporated herein by reference, and all capitalized terms used herein, but not defined herein, shall have the meanings set forth in the Plan. The Participant acknowledges receipt of a copy of the Plan and hereby accepts the Phantom Units subject to all the terms and provisions of the Plan and this Agreement.

3.Compensation Committee of the Board - Decisions and Interpretations. The Participant agrees to accept as binding, conclusive and final all decisions and interpretations of the Compensation Committee of the Board (the “Committee”) of the Company with respect to any questions arising under the Plan and this Agreement. Participants shall have no right to petition or request the Committee to review, or bring an appeal to the Committee regarding, any decisions or interpretations of the Committee hereunder.

4.Restricted Period of Phantom Units. The Restricted Period begins on the Effective Date and ends on the first of the following events to occur:

a.December 31, 2024; or

b.Your Termination of Affiliation (excluding any transfer to an Affiliate of the Company) with the Company, voluntarily for Good Reason or involuntarily (other than due to Cause), within two years following a Change of Control as set forth in the Plan.

5.Eligibility to Receive Units. The Participant will be eligible to receive a payout of the Phantom Units hereunder only if the Participant has been employed by the Company or its Affiliates, or its or their successors, continuously throughout the Restricted Period and continues to be so employed on the last day of the Restricted Period, unless the Participant terminates employment during the Restricted Period due to Retirement, death or Disability, in which case, the Phantom Units will vest as provided in Section 7 below.

6.Payment of Units and DERs. Subject to legal or contractual obligations and Participant’s eligibility to receive a payout of the Phantom Units as set forth in Section 5, the Company will deliver to the Participant, or the Participant’s legal representative, as soon as practicable after the Restricted Period, a number of Units equal to the number of vested Phantom Units net of any Units used to satisfy all or part of tax withholding requirements. The number of Units required to cover tax withholding requirements will be based on the closing price of the Units on the last business day of the Restricted Period. In addition, as soon as practicable after the end of the Restricted Period, the Company will pay to the Participant, or the Participant’s legal representative, the value of the DERs on the gross number of Units awarded to the Participant pursuant to the terms of this

Agreement. The value of the DERs shall be the amount of all distributions per Unit that would have been earned and paid during the Restricted Period on the gross number of Units awarded, and no interest shall be paid on such amount. Such payment of the DERs shall be in cash and subject to tax withholding requirements.

7.Termination of Employment Due to Retirement, Death or Disability. In the event a Participant’s employment with the Company or its Affiliates terminates prior to the end of the Restricted Period due to Retirement, death or Disability and on the date of such termination due to Retirement, death or Disability the Participant would have met the eligibility requirements of Section 5, the initial target grant of Phantom Units will be prorated based upon the Participant’s months of employment between January 1, 2022 and December 31, 2024. Such prorated amount will continue to be restricted and subject to the terms of this Agreement until the Restricted Period ends. All Phantom Units in excess of the prorated amount shall be forfeited.

8. Other Provisions.

a.The Participant understands and agrees that payments under this Agreement shall not be used for, or in the determination of, any other payment or benefit under any continuing agreement, plan, policy, practice or arrangement providing for the making of any payment or the provision of any benefits to or for the Participant or to the Participant’s beneficiaries or representatives, including, without limitation, any employment agreement, any change of control severance protection plan or any employee benefit plan as defined in Section 3(3) of ERISA, including, but not limited to qualified and non-qualified retirement plans.

b.Except as otherwise provided herein, in the event that the Participant’s employment with the Company or its Affiliates, or its or their successors, terminates for any reason prior to the end of the Restricted Period, such Phantom Units shall be forfeited.

c.By signing this Agreement, the Participant represents and agrees that he or she will keep the terms, amount and fact of this Agreement completely confidential, and that, unless required to do so by law, he or she will not hereafter disclose any information concerning this Agreement to anyone including, but not limited to, any past, present or prospective employee or applicant for employment of the Company or its Affiliates and any past, present or prospective customer of the Company, the Partnership or their Affiliates.

d.Neither the Phantom Units, nor the Participant’s interest in the Phantom Units, may be sold, assigned, transferred, pledged, hedged or otherwise disposed of or encumbered at any time prior to the vesting and payment of such Phantom Units under this Agreement.

e.If the Participant at any time forfeits any or all of the Phantom Units pursuant to this Agreement, the Participant agrees that all of the Participant’s rights to and interest in the forfeited Phantom Units, including the tandem DERs, shall terminate upon forfeiture without payment of consideration.

f.In the event a Participant’s employment with the Company or its Affiliates terminates prior to the end of the Restricted Period due to death, the DERs associated with the pro-rated vesting amount shall be paid to the beneficiary or beneficiaries as designated by the Participant in the electronic system of record. If no designation of beneficiary was made, the DERs payment will default to the Participant’s estate.

g.With respect to the right to receive payment of the Phantom Units under this Agreement, nothing contained herein shall give the Participant any rights that are greater than those of a general creditor of the Company.

9. Notices. All notices to the Company required hereunder shall be in writing and delivered by hand or by mail, addressed to Magellan GP, LLC, One Williams Center, Mail Drop 32, Tulsa, Oklahoma 74172, Attention: Compensation Department. Notices shall become effective upon their receipt by the Company if delivered in the forgoing manner.

Magellan GP, LLC

By: /s/ Michael N. Mears

Michael N. Mears

President and Chief Executive Officer

Magellan GP, LLC

Dated: February 9, 2022

EX-10.N

Exhibit 10(n)

RETENTION AGREEMENT

THIS RETENTION AGREEMENT (this “Agreement”) is by and between Magellan Midstream Holdings GP, LLC (the “Company”) and Melanie Little (the “Employee”).

1.Retention Award. The Company hereby grants to the Employee, effective January 31, 2020 (the “Effective Date”), the right to be eligible to receive a total award of $150,000.00 (the “Retention Award”), subject to the satisfaction of all conditions described in this Agreement.

2.Eligibility to Receive Retention Award.

a.If: (i) the Employee is employed by the Company or its affiliates, or its or their successors, continuously from the Effective Date through December 31, 2022; and (ii) the Employee’s job performance throughout such time period is satisfactory, as determined by the Company in its discretion, the Company will pay the Employee $150,000.00, subject to all applicable withholdings and deductions required by law, in a lump sum on or about the first regularly scheduled pay date in January 2023.

b.If the Employee’s employment with the Company or its affiliates, or its or their successors, terminates for any reason prior to December 31, 2022, the Employee shall forfeit any right to receive the payment described in Section 2.a.

3. Other Provisions.

a.The Employee understands and agrees that the payment under this Agreement shall not be used for, or included in the determination of, any other payment or benefit under any continuing agreement, plan, policy, practice or arrangement providing for the making of any payment or the provision of any benefits to or for the Employee or the Employee’s beneficiaries or representatives, including, without limitation, any employment agreement, any change of control severance protection plan or any employee benefit plan as defined in Section 3(3) of ERISA, including, but not limited to qualified and non-qualified retirement plans.

b.By signing this Agreement, the Employee represents and agrees that she will keep the terms, amount and fact of this Agreement completely confidential, and that, unless required to do so by law, she will not hereafter disclose any information concerning this Agreement to anyone including, but not limited to, any past, present or prospective employee or applicant for employment of the Company or its affiliates and any past, present or prospective customer of the Company or its affiliates.

c.Neither the Retention Award nor the Employee’s interest in the Retention Award, may be sold, assigned, transferred, pledged, hedged or otherwise disposed of or encumbered at any time prior to the payment of such Retention Award under this Agreement.

d.With respect to the right to receive payment of the Retention Award under this Agreement, nothing contained herein shall give the Employee any rights that are greater than those of a general creditor of the Company.

e.It is intended that this Agreement satisfies the requirements of the short-term deferral exception from Section 409A of the Internal Revenue Code and shall be interpreted and administered in accordance with such intent.

f.This Agreement shall be governed by and construed in accordance with the laws of the state in which the Employee is employed by the Company or its affiliates, or its or their successors, to the extent not preempted by federal law, without regard to conflicts of laws principles that would result in the application of the laws of another state. Any action or proceeding to enforce or interpret the terms of this Agreement shall be brought only in a state or federal court located in the county in which the Employee is employed by the Company or its affiliates, or its or their successors. By acceptance of this Agreement, the Employee irrevocably submits to the exclusive jurisdiction of such courts and waives the defense of inconvenient forum to the maintenance of any such action or proceeding in such venue.

g.This Agreement contains all of the understandings and representations between the Company and the Employee relating to the Retention Award and supersedes all prior and contemporaneous understandings, discussions, agreements, and representations, both written and oral, with respect to any retention bonus.

h.Nothing in this Agreement constitutes a promise of continued employment of the Employee by the Company or its affiliates, or its or their successors. This Agreement does not change the Employee’s status as an at-will employee, thus the Company and the Employee can terminate the employment relationship at any time.

i.This Agreement may not be amended or modified unless in writing signed by an authorized representative of the Company and the Employee.

4. Notices. All notices to the Company required hereunder shall be in writing and delivered by hand or by mail, addressed to Magellan Midstream Holdings GP, LLC, One Williams Center, Mail Drop 32, Tulsa, Oklahoma 74172, Attention: Compensation Department. Notices shall become effective upon their receipt by the Company if delivered in the foregoing manner.

Magellan Midstream Holdings GP, LLC

    By: /s/ Michael N. Mears

Michael N. Mears

President and Chief Executive Officer

Magellan Midstream Holdings GP, LLC

    Dated: January 31, 2020

Accepted and agreed to:

By: /s/ Melanie Little

Melanie Little

Dated: February 27, 2020

EX-21

EXHIBIT 21

LIST OF SUBSIDIARIES AS OF DECEMBER 31, 2021

Magellan Midstream Partners, L.P., a Delaware limited partnership and the Registrant

Magellan GP, LLC, a Delaware limited liability company and the general partner of the Registrant

Magellan Ammonia Pipeline, L.P., a Delaware limited partnership

Magellan Asset Services GP, LLC, a Delaware limited liability company

Magellan Asset Services, L.P., a Delaware limited partnership

Magellan Crude Oil Pipeline Company GP, LLC, a Delaware limited liability company

Magellan Crude Oil Pipeline Company, L.P., a Delaware limited partnership

Magellan Logistics & Services GP, LLC, a Delaware limited liability company

Magellan Logistics & Services, L.P., a Delaware limited partnership

Magellan Midstream Holdings GP, LLC, a Delaware limited liability company

Magellan NGL, LLC, a Delaware limited liability company

Magellan OLP, L.P., a Delaware limited partnership

Magellan Operating Company, LLC, a Delaware limited partnership

Magellan Operating GP, LLC, a Delaware limited liability company

Magellan Pipeline Company, L.P., a Delaware limited partnership

Magellan Pipeline GP, LLC, a Delaware limited liability company

Magellan Pipeline Terminals GP, LLC, a Delaware limited liability company

Magellan Pipeline Terminals, L.P., a Delaware limited partnership

Magellan Pipelines Holdings GP, LLC, a Delaware limited liability company

Magellan Pipelines Holdings, L.P., a Delaware limited partnership

Magellan Processing GP, LLC, a Delaware limited liability company

Magellan Processing, L.P., a Delaware limited partnership

Magellan Terminals Holdings, L.P., a Delaware limited partnership

MGG GP Holdings, LLC, a Delaware limited liability company

EX-23

Exhibit 23

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following Registration Statements:

1.Registration Statement (Form S-3ASR No. 333-253266) of Magellan Midstream Partners, L.P. (the Partnership),

2.Registration Statement (Form S-8 No. 333-255623) pertaining to the Long-Term Incentive Plan of the Partnership,

3.Registration Statement (Form S-8 No. 333-212836) pertaining to the Long-Term Incentive Plan of the Partnership,

4.Registration Statement (Form S-8 No. 333-176062) pertaining to the Long-Term Incentive Plan of the Partnership,

5.Registration Statement (Form S-8 No. 333-71670) pertaining to the Long-Term Incentive Plan of the Partnership, as amended by Post-Effective Amendment No. 1, and

6.Registration Statement (Form S-8 No. 333-147206) pertaining to the Long-Term Incentive Plan of the Partnership;

of our reports dated February 17, 2022, with respect to the consolidated financial statements of the Partnership and the effectiveness of internal control over financial reporting of the Partnership included in this Annual Report (Form 10-K) of the Partnership for the year ended December 31, 2021.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 17, 2021

EX-31.A

Exhibit 31(a)

CERTIFICATION

I, Michael N. Mears, certify that:

1.    I have reviewed this Annual Report on Form 10-K for the fiscal year ending December 31, 2021 (this “report”) of Magellan Midstream Partners, L.P. (the “registrant”);

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

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

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

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

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

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

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

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

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

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

Date: February 17, 2022

/s/ Michael N. Mears

Michael N. Mears, principal executive officer

EX-31.B

Exhibit 31(b)

CERTIFICATION

I, Jeff Holman, certify that:

1.    I have reviewed this Annual Report on Form 10-K for the fiscal year ending December 31, 2021 (this “report”) of Magellan Midstream Partners, L.P. (the “registrant”);

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

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

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

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

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

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

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

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

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

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

Date: February 17, 2022

/s/ Jeff Holman

Jeff Holman, principal financial and accounting officer

EX-32.A

Exhibit 32(a)

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

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of Magellan Midstream Partners, L.P. (the “Partnership”) for the fiscal year ending December 31, 2021, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael N. Mears, Chief Executive Officer of Magellan GP, LLC, the General Partner of the Partnership, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ Michael N. Mears

Michael N. Mears, Chief Executive Officer

Date: February 17, 2022

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

EX-32.B

Exhibit 32(b)

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

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of Magellan Midstream Partners, L.P. (the “Partnership”) for the fiscal year ending December 31, 2021, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jeff Holman, Chief Financial Officer of Magellan GP, LLC, the General Partner of the Partnership, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ Jeff Holman

Jeff Holman, Chief Financial Officer

Date: February 17, 2022

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

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Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2021	Feb. 16, 2022	Jun. 30, 2021
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
Document Transition Report	false
Entity File Number	1-16335
Entity Registrant Name	Magellan Midstream Partners, L.P.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	73-1599053
Entity Address, Address Line One	One Williams Center
Entity Address, Address Line Two	P.O. Box 22186
Entity Address, City or Town	Tulsa
Entity Address, State or Province	OK
Entity Address, Postal Zip Code	74121-2186
City Area Code	918
Local Phone Number	574-7000
Title of 12(b) Security	Common Units
Trading Symbol	MMP
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 10,802,833,233
Entity Common Stock, Shares Outstanding (in shares)		212,393,262
Documents Incorporated by Reference	Portions of the registrant’s Proxy Statement prepared for the solicitation of proxies in connection with the 2022 Annual Meeting of Limited Partners are to be incorporated by reference in Part III of this Form 10-K.
Amendment Flag	false
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	FY
Entity Central Index Key	0001126975
Current Fiscal Year End Date	--12-31

XML

Audit Information	12 Months Ended
	Dec. 31, 2021
Audit Information [Abstract]
Auditor Name	Ernst & Young LLP
Auditor Firm ID	42
Auditor Location	Tulsa, Oklahoma

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Consolidated Statements of Income - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Total revenue	$ 2,733.1	$ 2,322.0	$ 2,600.9
Costs and expenses:
Operating	569.7	587.8	616.4
Cost of product sales	780.0	468.2	560.9
Depreciation, amortization and impairment	227.9	243.1	230.7
General and administrative	206.3	171.2	194.2
Total costs and expenses	1,783.9	1,470.3	1,602.2
Other operating income (expense)	2.8	0.1	3.0
Earnings of non-controlled entities	154.4	153.3	169.0
Operating profit	1,106.4	1,005.1	1,170.7
Interest expense	228.1	234.1	221.1
Interest capitalized	(1.7)	(11.3)	(19.3)
Interest income	(0.5)	(1.0)	(3.3)
Gain on disposition of assets	(75.0)	(12.9)	(29.0)
Other (income) expense	20.9	5.2	11.8
Income from continuing operations before provision for income taxes	934.6	791.0	989.4
Provision for income taxes	2.3	2.9	1.4
Income from continuing operations	932.3	788.1	988.0
Income from discontinued operations	49.7	28.9	32.8
Net income	$ 982.0	$ 817.0	$ 1,020.8
Earnings per common unit - Basic
Continuing operations (in dollars per share)	$ 4.24	$ 3.49	$ 4.32
Discontinued operations (in dollars per share)	0.23	0.13	0.14
Net income per common unit (in dollars per share)	4.47	3.62	4.46
Earnings per common unit - Diluted
Continuing operations (in dollars per share)	4.24	3.49	4.32
Discontinued operations (in dollars per share)	0.23	0.13	0.14
Net income per common unit (in dollars per share)	$ 4.47	$ 3.62	$ 4.46
Weighted average number of common units outstanding used for basic net income per unit calculation (in shares)	219.6	225.5	228.7
Weighted average number of common units outstanding used for diluted net income per unit calculation (in shares)	219.8	225.5	228.8
Transportation and terminals revenue
Total revenue	$ 1,798.9	$ 1,743.3	$ 1,913.9
Product sales revenue
Total revenue	913.0	557.5	665.8
Affiliate management fee revenue
Total revenue	$ 21.2	$ 21.2	$ 21.2

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Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Net income	$ 982.0	$ 817.0	$ 1,020.8
Derivative activity:
Net loss on cash flow hedges	0.0	(9.5)	(25.2)
Reclassification of net loss on cash flow hedges to income	3.5	3.5	2.7
Changes in employee benefit plan assets and benefit obligations recognized in other comprehensive income:
Net actuarial gain (loss)	16.3	(23.5)	(27.3)
Curtailment gain	0.0	1.7	0.0
Recognition of prior service credit amortization in income	(0.2)	(0.2)	(0.2)
Recognition of actuarial loss amortization in income	6.0	5.9	5.8
Recognition of settlement cost in income	2.6	1.0	2.6
Total other comprehensive income (loss)	28.2	(21.1)	(41.6)
Comprehensive income	$ 1,010.2	$ 795.9	$ 979.2

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Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Current assets:
Cash and cash equivalents	$ 2.0	$ 13.0
Trade accounts receivable	135.2	103.6
Other accounts receivable	34.6	37.1
Inventory	281.1	158.2
Commodity derivatives contracts, net	1.4	0.0
Commodity derivatives deposits	46.3	34.2
Assets held for sale	299.5	15.1
Other current assets	43.1	43.9
Total current assets	843.2	405.1
Property, plant and equipment	8,045.9	7,943.8
Less: accumulated depreciation	2,141.2	1,956.9
Net property, plant and equipment	5,904.7	5,986.9
Investments in non-controlled entities	980.8	1,213.9
Right-of-use asset, operating leases	174.2	166.1
Long-term receivables	10.1	22.8
Goodwill	50.1	50.1
Other intangibles (less accumulated amortization of $9.2 and $11.9 at December 31, 2020 and 2021, respectively)	43.2	44.9
Restricted cash	7.0	9.4
Noncurrent assets held for sale	0.0	277.6
Other noncurrent assets	16.7	20.2
Total assets	8,030.0	8,197.0
Current liabilities:
Accounts payable	109.5	98.0
Accrued payroll and benefits	74.9	52.1
Accrued interest payable	59.0	59.0
Accrued taxes other than income	76.5	67.7
Deferred revenue	92.5	98.6
Accrued product liabilities	153.5	75.2
Commodity derivatives contracts, net	18.6	21.6
Current portion of operating lease liability	25.8	27.5
Liabilities held for sale	15.8	8.4
Other current liabilities	53.5	50.5
Total current liabilities	679.6	558.6
Long-term operating lease liability	147.3	137.5
Long-term debt, net	5,088.8	4,978.7
Long-term pension and benefits	145.0	163.8
Long-term liabilities held for sale	0.0	1.5
Other noncurrent liabilities	69.5	53.1
Commitments and contingencies
Partners’ capital:
Common unitholders (223.1 units and 212.4 units outstanding at December 31, 2020 and 2021, respectively)	2,054.8	2,487.0
Accumulated other comprehensive loss	(155.0)	(183.2)
Total partners’ capital	1,899.8	2,303.8
Total liabilities and partners’ capital	$ 8,030.0	$ 8,197.0

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Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Statement of Financial Position [Abstract]
Other intangibles, accumulated amortization	$ 11.9	$ 9.2
Common unitholders, units outstanding (in shares)	212,387,990	223,119,811

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating Activities:
Net income	$ 982.0	$ 817.0	$ 1,020.8
Adjustments to reconcile net income to net cash provided by operating activities:
Income from discontinued operations	(49.7)	(28.9)	(32.8)
Depreciation, amortization and impairment expense	227.9	243.1	230.7
Gain on disposition of assets	(75.0)	(12.9)	(29.0)
Earnings of non-controlled entities	(154.4)	(153.3)	(169.0)
Distributions from operations of non-controlled entities	193.3	207.6	203.6
Equity-based incentive compensation expense	21.8	12.0	24.0
Settlement cost, amortization of prior service credit and actuarial loss	8.4	6.7	8.2
Debt extinguishment costs	0.0	12.9	8.3
Changes in operating assets and liabilities (Note 9)	(9.7)	(37.1)	2.1
Net cash provided by operating activities of continuing operations	1,144.6	1,067.1	1,266.9
Net cash provided by operating activities of discontinued operations	51.6	40.4	53.2
Net cash provided by operating activities	1,196.2	1,107.5	1,320.1
Investing Activities:
Additions to property, plant and equipment, net	(148.6)	(424.1)	(923.2)
Proceeds from disposition of assets	275.1	334.8	65.4
Investments in non-controlled entities	(5.6)	(95.1)	(212.4)
Distributions from returns of investments in non-controlled entities	0.0	0.5	8.5
Deposits received from undivided joint interest third party	0.0	0.0	75.3
Net cash provided (used) by investing activities of continuing operations	120.9	(183.9)	(986.4)
Net cash used by investing activities of discontinued operations	(2.8)	(15.5)	(19.8)
Net cash provided (used) by investing activities	118.1	(199.4)	(1,006.2)
Financing Activities:
Distributions paid	(906.4)	(927.1)	(921.6)
Repurchase of common units	(523.1)	(276.9)	0.0
Net commercial paper borrowings	108.0	0.0	0.0
Borrowings under long-term notes	0.0	828.4	996.4
Payments on notes	0.0	(550.0)	(550.0)
Debt placement costs	0.0	(7.6)	(12.0)
Debt extinguishment costs	0.0	(12.9)	(8.3)
Net payment on financial derivatives	0.0	(9.5)	(33.3)
Payments associated with settlement of equity-based incentive compensation	(6.2)	(14.7)	(9.8)
Net cash used by financing activities	(1,327.7)	(970.3)	(538.6)
Change in cash, cash equivalents and restricted cash	(13.4)	(62.2)	(224.7)
Cash, cash equivalents and restricted cash at beginning of period	22.4	84.6	309.3
Cash, cash equivalents and restricted cash at end of period	9.0	22.4	84.6
Supplemental non-cash investing and financing activities:
Additions to property, plant and equipment	(140.8)	(344.4)	(959.8)
Changes in current liabilities related to capital expenditures	(7.8)	(79.7)	36.6
Additions to property, plant and equipment, net	$ (148.6)	$ (424.1)	$ (923.2)

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Consolidated Statement of Partners' Capital - USD ($) $ in Millions	Total	Common Unitholders	Accumulated Other Comprehensive Loss
Beginning balance at Dec. 31, 2018	$ 2,643.4	$ 2,763.9	$ (120.5)
Comprehensive income:
Net income	1,020.8	1,020.8
Total other comprehensive income (loss)	(41.6)		(41.6)
Comprehensive income	979.2	1,020.8	(41.6)
Distributions	(921.6)	(921.6)
Equity-based incentive compensation expense	24.0	24.0
Issuance of common units in settlement of equity-based incentive plan awards	0.5	0.5
Payments associated with settlement of equity-based incentive compensation	(9.8)	(9.8)
Other	(0.7)	(0.7)
Ending balance at Dec. 31, 2019	2,715.0	2,877.1	(162.1)
Comprehensive income:
Net income	817.0	817.0
Total other comprehensive income (loss)	(21.1)		(21.1)
Comprehensive income	795.9	817.0	(21.1)
Distributions	(927.1)	(927.1)
Equity-based incentive compensation expense	12.0	12.0
Repurchase of common units	(276.9)	(276.9)
Issuance of common units in settlement of equity-based incentive plan awards	0.6	0.6
Payments associated with settlement of equity-based incentive compensation	(14.7)	(14.7)
Other	(1.0)	(1.0)
Ending balance at Dec. 31, 2020	2,303.8	2,487.0	(183.2)
Comprehensive income:
Net income	982.0	982.0
Total other comprehensive income (loss)	28.2		28.2
Comprehensive income	1,010.2	982.0	28.2
Distributions	(906.4)	(906.4)
Equity-based incentive compensation expense	21.8	21.8
Repurchase of common units	(523.1)	(523.1)
Issuance of common units in settlement of equity-based incentive plan awards	0.5	0.5
Payments associated with settlement of equity-based incentive compensation	(6.2)	(6.2)
Other	(0.8)	(0.8)
Ending balance at Dec. 31, 2021	$ 1,899.8	$ 2,054.8	$ (155.0)

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Organization and Description of Business

12 Months Ended

Dec. 31, 2021

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Description of Business

Organization and Description of Business

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 our common units are traded on the New York Stock Exchange under the ticker symbol “MMP.” Magellan GP, LLC, a wholly owned Delaware limited liability company, serves as our general partner. The board of directors of our general partner is referred to herein as our “board”.

Description of Business

We are principally engaged in the transportation, storage and distribution of refined petroleum products and crude oil. As of December 31, 2021, our asset portfolio, excluding assets associated with discontinued operations, consisted of:

•our refined products segment, comprised of our approximately 9,800-mile refined petroleum products pipeline system with 54 terminals and two marine storage terminals (one of which is owned through a joint venture); and

•our crude oil segment, comprised of approximately 2,200 miles of crude oil pipelines, a condensate splitter and 39 million barrels of aggregate storage capacity, of which approximately 29 million barrels are used for contract storage. Approximately 1,000 miles of these pipelines, the condensate splitter and 31 million barrels of this storage capacity (including 25 million barrels used for contract storage) are wholly-owned, with the remainder owned through joint ventures.

Description of Products

The following terms are commonly used in our industry to describe products that we transport, store, distribute or otherwise handle through our petroleum pipelines and terminals:

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

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

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

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

•crude oil, which includes condensate, is a naturally occurring unrefined petroleum product recovered from underground that is used as feedstock by refineries, splitters and petrochemical facilities.

We use the term petroleum products to describe any, or a combination, of the above-noted products. In addition, we handle, store and distribute renewable fuels, such as ethanol and biodiesel.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Significant Accounting Policies

Basis of Presentation. Our consolidated financial statements include our refined products and crude oil operating segments. We consolidate all entities in which we have a controlling ownership interest. We apply the equity method of accounting to investments in entities over which we exercise significant influence but do not control. We eliminate all intercompany transactions.

In June 2021, we entered into an agreement to sell our independent terminals network comprised of 26 refined petroleum products terminals with approximately six million barrels of storage located primarily in the southeastern United States (“U.S.”). The sale is expected to close upon the receipt of required regulatory approval. The related results of operations, financial position and cash flows have been classified as discontinued operations for all periods presented (see Note 3 – Discontinued Operations and Assets Held for Sale for additional details). Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.

Reclassifications. Certain prior period amounts have been reclassified to conform with the current period’s presentation, including amounts related to our discontinued operations.

Use of Estimates. The preparation of our consolidated financial statements in conformity with U.S. generally accepted accounting principles (“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.

Cash Equivalents. Cash and cash equivalents include demand and time deposits and funds that own highly marketable securities with original maturities of three months or less when acquired. We periodically assess the financial condition of the institutions where we hold these funds, and at December 31, 2020 and 2021, we believed our credit risk relative to these funds was minimal.

Restricted Cash. Restricted cash includes cash that we are contractually required to use 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.

Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable represent valid claims against customers. We recognize accounts receivable when we sell products or render services and collection of the receivable is probable. We extend credit terms to certain customers after a review of various credit indicators. We establish an allowance for doubtful accounts using an expected credit loss approach and evaluate reserves no less than quarterly to determine their adequacy. Judgments relative to at-risk accounts include the customers’ current financial condition, the customers’ historical relationship with us and current and projected economic conditions. We write off accounts receivable when we deem an account uncollectible.

Product Overages and Shortages. Each period end we measure the volume of each type of product in our pipeline systems and terminals, which is compared to the volumes of our customers’ inventories (as adjusted for tender deductions).  To the extent the product volumes in our pipeline systems and terminals exceed the volumes of our customers’ book inventories, we recognize a gain from the product overage and increase our product inventories. To the extent the product in our pipeline systems and terminals is less than our customers’ book inventories, we

recognize a loss from the product shortage and we record a liability for product owed to our customers.  The product overages we recognize are recorded based on market prices, and the resulting inventory is carried at weighted average cost.  The product shortages we recognize are recorded based on our weighted average cost.  Additionally, when product shortages result in a net short inventory position, the related liability is recorded based on period-end market prices.  Product overages and shortages as well as adjustments to the value of net short inventory positions are recorded in operating expenses on our consolidated statements of income.

Income Taxes. We are a partnership for income tax purposes and therefore are not subject to federal or state income taxes for most of the states in which we operate. The tax on our net income is borne by our unitholders through allocation to them of their share of our taxable income. Net income for financial statement purposes may differ significantly from taxable income allocated to unitholders because of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each unitholder’s tax attributes is not available to us.

The amounts recognized as provision for income taxes in our consolidated statements of income are primarily

comprised of partnership-level taxes levied by the state of Texas. This tax is based on revenues less direct costs of sale for our assets apportioned to the state of Texas.

Net Income Per Unit. We calculate basic net income per common unit for each period by dividing net income by the weighted average number of common units outstanding. The difference between our actual common units outstanding and our weighted average number of common units outstanding used to calculate net income per common unit is due to the impact of: (i) the phantom units issued to our independent directors, which are included in the calculation of basic and diluted weighted average units outstanding and (ii) the weighted average effect of units actually issued or repurchased during a period.  The difference between the weighted average number of common units outstanding used for basic and diluted net income per unit calculations on our consolidated statements of income is primarily the dilutive effect of phantom unit awards granted pursuant to our long-term incentive plan, which have not yet vested in periods where contingent performance metrics have been met.

Index of Additional Significant Accounting Policies

Discontinued Operations and Assets Held for Sale	Note 3 – Discontinued Operations and Assets Held for Sale
Revenue from Contracts with Customers	Note 5 – Revenue
Property, Plant and Equipment	Note 6 – Property, Plant and Equipment, Goodwill and Other Intangibles
Goodwill and Other Intangible Assets	Note 6 – Property, Plant and Equipment, Goodwill and Other Intangibles
Investments in Non-Controlled Entities	Note 7 – Investments in Non-Controlled Entities
Inventory	Note 8 – Inventory
Leases	Note 11 – Leases
Pension and Postretirement Medical and Life Benefit Obligations	Note 12 – Employee Benefit Plans
Equity-Based Incentive Compensation	Note 13 – Long-Term Incentive Plan
Derivative Financial Instruments	Note 14 – Derivative Financial Instruments
Contingencies and Environmental	Note 16 – Commitments and Contingencies

New Accounting Pronouncements

We evaluate new Accounting Standards Codifications (“ASC”) and updates issued by the Financial Accounting Standards Board on an ongoing basis. There are no new accounting pronouncements that we anticipate will have a material impact on our financial statements.

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Discontinued Operations and Assets Held for Sale

12 Months Ended

Dec. 31, 2021

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations and Assets Held for Sale

Discontinued Operations and Assets Held for Sale

In June 2021, we entered into an agreement to sell our independent terminals network comprised of 26 refined petroleum products terminals with approximately six million barrels of storage located primarily in the southeastern U.S. to Buckeye Partners, L.P. (“Buckeye”) for $435 million. The sale is expected to close upon the receipt of required regulatory approval. The related results of operations, which were previously included in our refined products segment, have been classified as discontinued operations.

Summarized Results of Discontinued Operations

The following table provides the summarized results that have been reclassified from continuing operations to discontinued operations on the consolidated statements of income for the years ended December 31, 2019, 2020 and 2021 (in millions):

	Year Ended December 31,
	2019		2020		2021
Transportation and terminals revenue	$	56.8	$	51.4	$	53.3
Product sales revenue	70.3		54.2		83.7
Total revenue	127.1		105.6		137.0
Costs and expenses:
Operating	17.9		13.4		11.2
Cost of product sales	58.5		45.5		66.5
Depreciation, amortization and impairment	15.4		15.6		7.1
General and administrative	2.5		2.2		2.5
Total costs and expenses	94.3		76.7		87.3
Income from discontinued operations	$	32.8	$	28.9	$	49.7

Summarized Assets and Liabilities of Discontinued Operations

The following table provides the summarized assets and liabilities classified as held for sale on the consolidated balance sheets as of December 31, 2020 and 2021 (in millions):

	Year Ended December 31,
	2020		2021
Assets:
Trade accounts receivable	$	5.6	$	6.3
Inventory	9.2		17.0
Net property, plant and equipment	274.9		272.0
Goodwill	2.7		2.7
Other assets	0.3		1.5
Total assets classified as held for sale	$	292.7	$	299.5
Liabilities:
Accounts payable	$	2.0	$	3.7
Accrued product liabilities	4.0		8.4
Other liabilities	3.9		3.7
Total liabilities classified as held for sale	$	9.9	$	15.8

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Segment Disclosures

12 Months Ended

Dec. 31, 2021

Segment Reporting [Abstract]

Segment Disclosures

Segment Disclosures

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

We believe that investors benefit from having access to the same financial measures used by management. Operating margin, which is presented in the following tables, is an important measure used by management to evaluate the economic performance of our core operations. Operating margin is not a GAAP measure, but the components of operating margin are computed using amounts that are determined in accordance with GAAP. A reconciliation of operating margin to operating profit, which is its nearest comparable GAAP financial measure, is included in the tables below. Operating profit includes depreciation, amortization and impairment expense and general and administrative (“G&A”) expense that management does not consider when evaluating the core profitability of our separate operating segments.

	Year Ended December 31, 2019
	(in millions)
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation and terminals revenue	$	1,299.0	$	620.3	$	(5.4)	$	1,913.9
Product sales revenue	637.5		28.3		—		665.8
Affiliate management fee revenue	6.7		14.5		—		21.2
Total revenue	1,943.2		663.1		(5.4)		2,600.9
Operating expense	454.0		173.3		(10.9)		616.4
Cost of product sales	532.8		28.1		—		560.9
Other operating (income) expense	(10.2)		7.2		—		(3.0)
Earnings of non-controlled entities	(8.1)		(160.9)		—		(169.0)
Operating margin	974.7		615.4		5.5		1,595.6
Depreciation, amortization and impairment expense	158.7		66.5		5.5		230.7
G&A expense	138.3		55.9		—		194.2
Operating profit	$	677.7	$	493.0	$	—	$	1,170.7
Additions to long-lived assets	$	785.1	$	74.2			$	859.3
	As of December 31, 2019
	(in millions)
Segment assets	$	5,116.4	$	2,894.7			$	8,011.1
Assets held for sale							295.5
Corporate assets							131.1
Total assets							$	8,437.7
Goodwill	$	38.5	$	12.1			$	50.6
Investments in non-controlled entities	$	422.4	$	818.2			$	1,240.6

	Year Ended December 31, 2020
	(in millions)
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation and terminals revenue	$	1,190.4	$	559.5	$	(6.6)	$	1,743.3
Product sales revenue	524.4		33.1		—		557.5
Affiliate management fee revenue	6.3		14.9		—		21.2
Total revenue	1,721.1		607.5		(6.6)		2,322.0
Operating expense	411.8		189.2		(13.2)		587.8
Cost of product sales	425.8		42.4		—		468.2
Other operating (income) expense	(3.2)		3.1		—		(0.1)
Earnings of non-controlled entities	(32.5)		(120.8)		—		(153.3)
Operating margin	919.2		493.6		6.6		1,419.4
Depreciation, amortization and impairment expense	159.9		76.6		6.6		243.1
G&A expense	123.5		47.7		—		171.2
Operating profit	$	635.8	$	369.3	$	—	$	1,005.1
Additions to long-lived assets	$	277.5	$	56.4			$	333.9
	As of December 31, 2020
	(in millions)
Segment assets	$	4,977.0	$	2,836.9			$	7,813.9
Assets held for sale							292.7
Corporate assets							90.4
Total assets							$	8,197.0
Goodwill	$	38.0	$	12.1			$	50.1
Investments in non-controlled entities	$	429.2	$	784.7			$	1,213.9

	Year Ended December 31, 2021
	(in millions)
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation and terminals revenue	$	1,338.5	$	466.2	$	(5.8)	$	1,798.9
Product sales revenue	763.9		149.1		—		913.0
Affiliate management fee revenue	6.4		14.8		—		21.2
Total revenue	2,108.8		630.1		(5.8)		2,733.1
Operating expense	416.7		165.4		(12.4)		569.7
Cost of product sales	630.1		149.9		—		780.0
Other operating (income) expense	(6.9)		4.1		—		(2.8)
Earnings of non-controlled entities	(34.4)		(120.0)		—		(154.4)
Operating margin	1,103.3		430.7		6.6		1,540.6
Depreciation, amortization and impairment expense	153.9		67.4		6.6		227.9
G&A expense	147.8		58.5		—		206.3
Operating profit	$	801.6	$	304.8	$	—	$	1,106.4
Additions to long-lived assets	$	88.9	$	41.1			$	130.0
	As of December 31, 2021
	(in millions)
Segment assets	$	4,880.0	$	2,780.7			$	7,660.7
Assets held for sale							299.5
Corporate assets							69.8
Total assets							$	8,030.0
Goodwill	$	38.0	$	12.1			$	50.1
Investments in non-controlled entities	$	232.8	$	748.0			$	980.8

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Revenue

12 Months Ended

Dec. 31, 2021

Revenue from Contract with Customer [Abstract]

Revenue

Revenue

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 on a net basis.

We recognize pipeline transportation revenue for crude oil 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 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 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 related rules and orders. FERC regulation requires that interstate pipeline rates be filed with the FERC, be posted publicly, be “just and reasonable” and not be unduly discriminatory. The rates on approximately 30% 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 liquid pipeline companies may establish rates by obtaining authority to charge market-based rates in competitive markets or by negotiation with unaffiliated shippers. Approximately 70% 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.

Statements of Income Disclosures

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

	Year Ended December 31, 2019
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation	$	787.7	$	381.6	$	—	$	1,169.3
Terminalling	139.9		17.8		—		157.7
Storage	214.9		119.3		(5.4)		328.8
Ancillary services	128.6		28.4		—		157.0
Lease revenue	27.9		73.2		—		101.1
Transportation and terminals revenue	1,299.0		620.3		(5.4)		1,913.9
Product sales revenue	637.5		28.3		—		665.8
Affiliate management fee revenue	6.7		14.5		—		21.2
Total revenue	1,943.2		663.1		(5.4)		2,600.9
Revenue not under the guidance of ASC 606, Revenue from Contracts with Customers:
Lease revenue	(27.9)		(73.2)		—		(101.1)
(Gains) losses from futures contracts included in product sales revenue	63.5		3.0		—		66.5
Affiliate management fee revenue	(6.7)		(14.5)		—		(21.2)
Total revenue from contracts with customers under ASC 606	$	1,972.1	$	578.4	$	(5.4)	$	2,545.1

	Year Ended December 31, 2020
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation	$	742.9	$	305.4	$	—	$	1,048.3
Terminalling	109.6		21.5		—		131.1
Storage	199.3		129.0		(6.6)		321.7
Ancillary services	114.9		26.9		—		141.8
Lease revenue	23.7		76.7		—		100.4
Transportation and terminals revenue	1,190.4		559.5		(6.6)		1,743.3
Product sales revenue	524.4		33.1		—		557.5
Affiliate management fee revenue	6.3		14.9		—		21.2
Total revenue	1,721.1		607.5		(6.6)		2,322.0
Revenue not under the guidance of ASC 606, Revenue from Contracts with Customers:
Lease revenue	(23.7)		(76.7)		—		(100.4)
(Gains) losses from futures contracts included in product sales revenue	(56.8)		3.6		—		(53.2)
Affiliate management fee revenue	(6.3)		(14.9)		—		(21.2)
Total revenue from contracts with customers under ASC 606	$	1,634.3	$	519.5	$	(6.6)	$	2,147.2

	Year Ended December 31, 2021
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation	$	915.7	$	228.8	$	—	$	1,144.5
Terminalling	100.1		17.0		—		117.1
Storage	177.1		114.8		(5.8)		286.1
Ancillary services	125.2		29.9		—		155.1
Lease revenue	20.4		75.7		—		96.1
Transportation and terminals revenue	1,338.5		466.2		(5.8)		1,798.9
Product sales revenue	763.9		149.1		—		913.0
Affiliate management fee revenue	6.4		14.8		—		21.2
Total revenue	2,108.8		630.1		(5.8)		2,733.1
Revenue not under the guidance of ASC 606, Revenue from Contracts with Customers:
Lease revenue	(20.4)		(75.7)		—		(96.1)
(Gains) losses from futures contracts included in product sales revenue	(127.2)		(16.0)		—		(143.2)
Affiliate management fee revenue	(6.4)		(14.8)		—		(21.2)
Total revenue from contracts with customers under ASC 606	$	1,954.8	$	523.6	$	(5.8)	$	2,472.6

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. We also record contract liabilities for payments received in conjunction with take-or-pay contracts, storage contracts and other service offerings in which the service to our customers remains unfulfilled. These liabilities are presented as deferred revenue and other noncurrent liabilities on our consolidated balance sheets. We recognize contract assets for costs incurred to obtain new customer contracts. Additionally, at each period end, we defer a portion of the costs incurred associated with our customers’ in-transit products based on our per-barrel direct delivery costs and the average delivery point for all barrels in our system. These contract assets are presented on our consolidated balance sheets as other current and noncurrent assets. Contract assets and contract liabilities are determined using judgments and assumptions that management considers reasonable.

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

	December 31, 2020		December 31, 2021
Accounts receivable from contracts with customers	$	103.3	$	134.8
Contract assets	$	12.2	$	12.5
Contract liabilities	$	102.7	$	100.1

For the year ended December 31, 2021, we recognized $80.9 million of transportation and terminals revenue that was recorded in deferred revenue as of December 31, 2020.

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 us 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. 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 December 31, 2021 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 millions):

	Refined Products		Crude Oil		Total
Amounts as of December 31, 2021	$	1,874.5	$	1,069.8	$	2,944.3
Remaining terms	1 - 17 years		1 - 10 years
Estimated revenues from UPOs to be recognized in the next 12 months	$	368.9	$	257.4	$	626.3

In computing the value of these future revenues, we have used the current rates in effect as of December 31, 2021 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 December 31, 2021 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.

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Property, Plant and Equipment and Other Intangibles

12 Months Ended

Dec. 31, 2021

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment and Other Intangibles

Property, Plant and Equipment, Goodwill and Other Intangibles

Property, Plant and Equipment

Property, plant and equipment consists primarily of pipeline, pipeline-related equipment, storage tanks and processing equipment. We state property, plant and equipment at cost except for certain acquired assets recorded at fair value on their respective acquisition dates and impaired assets. We record impaired assets at fair value on the last impairment evaluation date for which an adjustment was required.

We assign asset lives based on reasonable estimates when we place an asset into service. Subsequent events could cause us to change our estimates, which would affect the future calculation of depreciation expense.

When we sell or retire property, plant and equipment, we remove its carrying value and the related accumulated depreciation from our accounts and record any associated gains or losses on our consolidated statements of income in the period of sale or disposition.

We capitalize expenditures to replace existing assets and retire the replaced assets. We capitalize expenditures when they extend the useful life, increase the productivity or capacity, or improve the safety or efficiency of the asset. We capitalize direct project costs such as labor and materials as incurred. Indirect project costs, such as overhead, are capitalized based on a percentage of direct labor charged to the respective capital project. We charge expenditures for maintenance, repairs and minor replacements to operating expense in the period incurred.

During construction, we capitalize interest on construction projects undergoing preparation for use and when total budgeted project costs exceed $0.5 million. The interest we capitalize is based on the weighted average interest rate of our debt. The weighted average rates used to capitalize interest on borrowed funds were 4.6%, 4.4% and 4.4% for the years ended December 31, 2019, 2020 and 2021, respectively.

Property, plant and equipment consisted of the following (in millions):

					Estimated  Depreciable Lives
	December 31,
	2020		2021
Construction work-in-progress	$	122.0	$	89.5
Land and rights-of-way	373.9		374.3
Buildings	119.7		121.8		10 to 53 years
Storage tanks	1,952.7		1,986.7		10 to 49 years
Pipeline and station equipment	3,325.9		3,386.0		10 to 59 years
Processing equipment	1,769.4		1,826.4		3 to 56 years
Other	280.2		261.2		3 to 53 years
Property, plant and equipment, gross	$	7,943.8	$	8,045.9

Other includes total interest capitalized on assets placed in service as of December 31, 2020 and 2021 of $96.2 million and $98.7 million, respectively. Depreciation expense for the years ended December 31, 2019, 2020 and 2021 was $227.5 million, $240.5 million and $225.2 million, respectively.

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying value may not be recoverable. In reviewing for impairment, the carrying value of such assets is compared to the estimated undiscounted future cash flows expected from the use of the assets and their eventual disposition. If such cash flows are not sufficient to support the asset’s recorded value, an impairment charge is recognized to reduce the carrying value of the long-lived asset to its estimated fair value. The determination of future cash flows as well as the estimated fair value of long-lived assets involves significant estimates on the part of management.

In accordance with ASC, 360 Plant, Property and Equipment, we ceased recording depreciation and amortization for the assets held for sale in June 2021.

Goodwill

We record the excess of purchase price over the fair value of the tangible and identifiable intangible assets acquired and liabilities assumed in a business acquisition (or combination) as goodwill. The goodwill relating to each of our reporting units is tested for impairment annually as well as when an event or change in circumstances indicates an impairment may have occurred.

For purposes of performing the impairment test for goodwill, our reporting units are our refined products and crude oil segments.  In 2019 and 2020, we elected to complete the qualitative goodwill impairment test and concluded it was more likely than not that the fair value of each of our reporting units was greater than its carrying amount. In 2021, we elected to perform the quantitative assessment for purposes of our annual goodwill impairment test and calculated that the fair value of each of our reporting units was greater than the carrying amount. Based on this assessment, we concluded goodwill was not impaired.

Other Intangibles

Other intangible assets with finite lives are amortized over their estimated useful lives of 7 years up to 30 years. The weighted average asset life of our other intangible assets at December 31, 2021 was approximately 16 years. We adjust the useful lives of our other intangible assets if events or circumstances indicate there has been a change in the remaining useful lives. We eliminate from our balance sheets the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. During the years ended December 31, 2019, 2020 and 2021, amortization of other intangible assets was $3.3 million, $2.7 million and $2.7 million, respectively.

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Investments in Non-Controlled Entities

12 Months Ended

Dec. 31, 2021

Equity Method Investments and Joint Ventures [Abstract]

Investments in Non-Controlled Entities

Investments in Non-Controlled EntitiesWe account for interests in affiliates that we do not control using the equity method of accounting. Under this method, an investment is recorded at our acquisition cost or capital contributions, as adjusted by contractual terms, plus equity in earnings or losses since acquisition or formation, plus interest capitalized, less distributions received and amortization of interest capitalized and excess net investment. Excess net investment is the amount by which our investment in a non-controlled entity exceeded our proportionate share of the book value of the net assets of that investment. We amortize excess net investment over the weighted average depreciable asset lives of the equity investee. Our unamortized excess net investment was $33.0 million and $32.0 million at December 31, 2020 and 2021, respectively. The amount of unamortized excess investment is primarily related to our investment in BridgeTex. We evaluate equity method investments for impairment whenever events or circumstances indicate that there is an other-than-temporary loss in value of the investment. In the event that we determine that the loss in value of an investment is other-than-temporary, we would record a charge to earnings to adjust the carrying value to fair value. We recognized no equity investment impairments during 2019, 2020 and 2021.

Our equity investments in non-controlled entities at December 31, 2021 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”)	25%
Powder Springs Logistics, LLC (“Powder Springs”)	50%
Saddlehorn Pipeline Company, LLC (“Saddlehorn”)	30%
Seabrook Logistics, LLC (“Seabrook”)	50%
Texas Frontera, LLC (“Texas Frontera”)	50%

In April 2021, we sold nearly half of our membership interest in MVP. As a result of the sale, we received proceeds of $272.1 million and recorded a gain of $70.4 million on our consolidated statements of income. Following the sale, we own approximately 25% of MVP and remain the operator of the facility.

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 receive are reported as affiliate management fee revenue on our consolidated statements of income. Cost reimbursements we receive from these entities in connection with our operating services are included as reductions to costs and expenses on our consolidated statements of income and totaled $5.3 million, $3.6 million and $2.5 million, respectively, for the years ended December 31, 2019, 2020 and 2021.

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

	Year Ended December 31,
	2019		2020		2021
Transportation and terminals revenue:
BridgeTex, pipeline capacity and storage	$	41.8	$	42.3	$	43.7
Double Eagle, throughput revenue	$	6.2	$	4.9	$	3.0
Saddlehorn, storage revenue	$	2.2	$	2.5	$	2.3
Operating expense:
Seabrook, storage lease and ancillary services	$	25.9	$	29.1	$	19.7
Product sales revenue:
Seabrook, product sales	$	0.3	$	—	$	—
Other operating income:
MVP, easement sale	$	0.3	$	—	$	—
Seabrook, gain on sale of air emission credits	$	—	$	1.4	$	0.4

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

	December 31, 2020
	Trade Accounts Receivable		Other Accounts Receivable		Other Accounts Payable		Long-Term Receivables
BridgeTex	$	0.4	$	—	$	1.0	$	—
Double Eagle	$	0.3	$	—	$	—	$	—
HoustonLink	$	—	$	—	$	0.1	$	—
MVP	$	—	$	0.5	$	2.3	$	—
Powder Springs	$	—	$	—	$	—	$	10.2
Saddlehorn	$	—	$	0.1	$	—	$	—
Seabrook	$	—	$	—	$	7.3	$	—

	December 31, 2021
	Trade Accounts Receivable		Other Accounts Receivable		Other Accounts Payable		Long-Term Receivables
BridgeTex	$	1.2	$	—	$	0.3	$	—
Double Eagle	$	0.2	$	—	$	—	$	—
HoustonLink	$	—	$	—	$	0.2	$	—
MVP	$	—	$	0.6	$	2.2	$	—
Powder Springs	$	—	$	—	$	—	$	—
Saddlehorn	$	—	$	0.2	$	—	$	—
Seabrook	$	—	$	0.1	$	3.2	$	—

We entered into a long-term terminalling and storage contract with Seabrook for exclusive use of dedicated tankage that provides our customers with crude oil storage capacity and dock access for crude oil imports and exports on the Texas Gulf Coast (see Note 11 – Leases for more details regarding this lease).

We also made purchases of transmix from MVP throughout the year totaling $7.6 million.

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

A summary of our investments in non-controlled entities (representing only our proportionate interests) follows (in millions):

Investments at December 31, 2020	$	1,213.9
Additional investment	5.6
Sale of ownership interests	(199.8)
Earnings of non-controlled entities:
Proportionate share of earnings	156.2
Amortization of excess investment and capitalized interest	(1.8)
Earnings of non-controlled entities	154.4
Less:
Distributions from operations of non-controlled entities	193.3
Investments at December 31, 2021	$	980.8

Summarized financial information of our non-controlled entities (representing 100% of the interests in these entities) follows (in millions):

	December 31,
	2020		2021
Current assets	$	243.8	$	227.0
Noncurrent assets	2,846.7		2,795.7
Total assets	$	3,090.5	$	3,022.7
Current liabilities	$	143.6	$	178.6
Noncurrent liabilities	57.5		59.5
Total liabilities	$	201.1	$	238.1
Equity	$	2,889.4	$	2,784.6

	Year Ended December 31,
	2019		2020		2021
Revenue	$	782.0	$	752.7	$	733.1
Net income	$	507.5	$	471.4	$	463.4

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Inventory

12 Months Ended

Dec. 31, 2021

Inventory Disclosure [Abstract]

Inventory

Inventory

Inventory is comprised primarily of refined products, crude oil, liquefied petroleum gases and transmix and is stated and relieved at the lower of average cost or net realizable value.

Inventory at December 31, 2020 and 2021 was as follows (in millions):

	December 31,
	2020		2021
Refined products	$	72.0	$	138.0
Crude oil	32.4		25.4
Liquefied petroleum gases	25.0		42.0
Transmix	23.4		72.4
Additives	5.4		3.3
Total inventory	$	158.2	$	281.1

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Supplemental Cash Flows Information

12 Months Ended

Dec. 31, 2021

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flows Information

Consolidated Statements of Cash Flows

Changes in the components of operating assets and liabilities are as follows (in millions):

	Year Ended December 31,
	2019		2020		2021
Trade accounts receivable and other accounts receivable	$	(20.3)	$	(0.9)	$	(29.1)
Inventory	2.7		14.0		(122.9)
Accounts payable	(1.9)		4.5		16.0
Accrued payroll and benefits	4.8		(22.3)		22.8
Accrued interest payable	1.0		(5.3)		—
Accrued taxes other than income	12.6		4.4		8.8
Deferred revenue	(11.4)		(10.7)		(6.1)
Accrued product liabilities	15.9		(8.5)		78.3
Other current and noncurrent assets and liabilities	(1.3)		(12.3)		22.5
Total	$	2.1	$	(37.1)	$	(9.7)

Other current and noncurrent assets and liabilities above exclude certain non-cash items that were reflected in the consolidated balance sheets but were not reflected in the statements of cash flows. At December 31, 2019 and 2020, the long-term pension and benefits liability was increased by $27.0 million and $21.5 million, respectively, resulting in a corresponding increase in accumulated other comprehensive loss (“AOCL”). At December 31, 2021, the long-term pension and benefits liability was decreased by $16.3 million, resulting in a corresponding decrease in AOCL.

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Debt

12 Months Ended

Dec. 31, 2021

Debt Disclosure [Abstract]

Debt

Debt

Long-term debt at December 31, 2020 and 2021 was as follows (in millions): 

	December 31,
	2020		2021
Commercial paper	$	—	$	108.0
3.20% Notes due 2025	250.0		250.0
5.00% Notes due 2026	650.0		650.0
3.25% Notes due 2030	500.0		500.0
6.40% Notes due 2037	250.0		250.0
4.20% Notes due 2042	250.0		250.0
5.15% Notes due 2043	550.0		550.0
4.20% Notes due 2045	250.0		250.0
4.25% Notes due 2046	500.0		500.0
4.20% Notes due 2047	500.0		500.0
4.85% Notes due 2049	500.0		500.0
3.95% Notes due 2050	800.0		800.0
Face value of long-term debt	5,000.0		5,108.0
Unamortized debt issuance costs(1)	(40.1)		(37.8)
Net unamortized debt premium(1)	18.8		18.6
Long-term debt, net	$	4,978.7	$	5,088.8

(1)    Debt issuance costs and note discounts and premiums 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.

At December 31, 2021, maturities of our senior notes were as follows: $0 in 2022 through 2024; $250 million in 2025; and $4.75 billion thereafter.

Other Debt

Revolving Credit Facility. At December 31, 2021, the total borrowing capacity under our revolving credit facility maturing in May 2024 was $1.0 billion. Any borrowings outstanding under this facility are classified as long-term debt on our consolidated balance sheets. Borrowings under the facility are unsecured and bear interest at LIBOR plus a spread ranging from 0.875% to 1.500% based on our credit ratings. Additionally, an unused commitment fee is assessed at a rate between 0.075% and 0.200% depending on our credit ratings. The unused commitment fee was 0.125% at December 31, 2021. Borrowings under this facility may be used for general purposes, including capital expenditures. As of December 31, 2020 and 2021, there were no borrowings outstanding under this facility and $3.5 million was obligated for letters of credit. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheets, but decrease our borrowing capacity under this facility.

Our revolving credit facility requires us to maintain a specified ratio of consolidated debt to EBITDA (as defined in the credit agreement) of no greater than 5.0 to 1.0. In addition, the revolving credit facility and the indentures under which our senior notes were issued contain covenants that limit our ability to, among other things, incur indebtedness secured by certain liens or encumber our assets, engage in certain sale-leaseback transactions and

consolidate, merge or dispose of all or substantially all of our assets. We were in compliance with these covenants as of and during the year ended December 31, 2021.

Commercial Paper Program. We have a commercial paper program under which we may issue commercial paper notes in an amount up to the available capacity under our $1.0 billion revolving credit facility. The maturities of the commercial paper notes vary, but may not exceed 397 days from the date of issuance. Because the commercial paper we can issue is limited to amounts available under our revolving credit facility, amounts outstanding under the program are classified as long-term debt. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. The weighted average interest rate for commercial paper borrowings based on the number of days outstanding was 0.4% and 0.2% for the year ended December 31, 2020 and 2021, respectively. There was $108.0 million outstanding under this program at December 31, 2021.

During the years ending December 31, 2019, 2020 and 2021, total cash payments for interest on all indebtedness, excluding the impact of related interest rate swap agreements, were $217.1 million, $234.5 million and $221.6 million, respectively.

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Leases

12 Months Ended

Dec. 31, 2021

Leases [Abstract]

Leases

Leases

We have both lessee and lessor arrangements. Our leases are evaluated at inception or at any subsequent modification. Depending on the terms, leases are classified as either operating or finance leases if we are the lessee, or as operating, sales-type or direct financing leases if we are the lessor, as appropriate under ASC 842, Leases.  Our lessee arrangements primarily include a terminalling and storage contract where we have exclusive use of dedicated tankage, leased pipelines and office buildings. Our lessor arrangements include pipeline capacity and storage contracts and our condensate splitter tolling agreement that qualify as operating leases under ASC 842. In addition, we have a long-term throughput and deficiency agreement with a customer that is being accounted for as a sales-type lease under ASC 842.

In accordance with ASC 842, we have made an accounting policy election to not apply the standard to lessee arrangements with a term of one year or less and no purchase option that is reasonably certain of exercise. We will continue to account for these short-term arrangements by recognizing payments and expenses as incurred, without recording a lease liability and right-of-use asset.

We have also made an accounting policy election for both our lessee and lessor arrangements to combine lease and non-lease components. This election is applied to all of our lease arrangements as our non-lease components do not result in significant timing differences in the recognition of rental expenses or income.

Operating Leases – Lessee

We recognize a lease liability for each lease based on the present value of remaining minimum fixed rental payments (which includes payments under any renewal option that we are reasonably certain to exercise), using a discount rate that approximates the rate of interest we would have to pay to borrow on a collateralized basis over a similar term. We also recognize a right-of-use asset for each lease, valued at the lease liability, adjusted for prepaid or accrued rent balances existing at the time of initial recognition. The lease liability and right-of-use asset are reduced over the term of the lease as payments are made and the assets are used.

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

Minimum fixed rental payments are recognized on a straight-line basis over the life of the lease as costs and expenses on our consolidated statements of income. Variable and short-term rental payments are recognized as costs and expenses as they are incurred. Variable payments consist of amounts that exceed the contractual minimum rental payment (for example, payment increases tied to a change in a market index). Future minimum rental payments under operating leases with initial terms greater than one year as of December 31, 2021 are as follows (in millions):

	Third Party Leases		Seabrook Lease		All Leases
2022	$	21.2	$	9.9	$	31.1
2023	21.4		9.9		31.3
2024	21.7		9.7		31.4
2025	21.8		6.6		28.4
2026	12.5		6.6		19.1
Thereafter	34.1		17.6		51.7
Total future minimum rental payments	132.7		60.3		193.0
Present value discount	12.1		7.8		19.9
Total operating lease liability	$	120.6	$	52.5	$	173.1

The following tables provide a summary of the effect on our consolidated statements of income for the years ended December 31, 2019, 2020 and 2021 (in millions):

	Year Ended December 31, 2019
	Third Party Leases		Seabrook Lease		All Leases
Fixed lease expense	$	19.2	$	10.8	$	30.0
Short-term lease expense	1.6		—		1.6
Variable lease expense	3.0		15.0		18.1
Total lease expense	$	23.8	$	25.8	$	49.7

	Year Ended December 31, 2020
	Third Party Leases		Seabrook Lease		All Leases
Fixed lease expense	$	19.2	$	14.3	$	33.5
Short-term lease expense	1.3		—		1.3
Variable lease expense	4.1		14.8		18.9
Total lease expense	$	24.6	$	29.1	$	53.7

	Year Ended December 31, 2021
	Third Party Leases		Seabrook Lease		All Leases
Fixed lease expense	$	21.0	$	12.7	$	33.7
Short-term lease expense	1.7		—		1.7
Variable lease expense	3.4		6.8		10.2
Total lease expense	$	26.1	$	19.5	$	45.6

The following table provides a summary of the effect on our consolidated balance sheets as of December 31, 2020 and 2021 (dollars in millions):

	As of and for the Year Ended
	December 31, 2020									December 31, 2021
	Third Party Leases			Seabrook Lease			All Leases			Third Party Leases			Seabrook Lease			All Leases
Current lease liability	$	17.1		$	10.4		$	27.5		$	17.8		$	8.0		$	25.8
Long-term lease liability	$	85.0		$	52.5		$	137.5		$	102.8		$	44.5		$	147.3
Right-of-use asset	$	103.2		$	62.9		$	166.1		$	121.7		$	52.5		$	174.2
Operating cash flows for operating leases	$	24.1		$	29.1		$	53.2		$	26.2		$	19.5		$	45.7
Weighted average remaining lease term (years)	6			7			7			7			7			7
Weighted average discount  rate	3.7		%	4.0		%	3.8		%	3.0		%	4.1		%	3.4		%

Operating Leases – Lessor

We recognize fixed rental income on a straight-line basis over the life of the lease as revenue on our consolidated statements of income. Variable rental payments are recognized as revenue in the period in which the circumstances on which the variable lease payments are based occur.

Future minimum payments receivable under operating leases with initial terms greater than one year as of December 31, 2021 are estimated as follows (in millions):

2022	$	24.9
2023	25.2
2024	21.9
2025	13.8
2026	13.1
Thereafter	32.9
Total	$	131.8

We recognized variable lease revenue of $58.4 million, $61.4 million and $61.0 million, respectively, for the years ended December 31, 2019, 2020 and 2021, primarily related to our condensate splitter.

At December 31, 2021, property, plant and equipment utilized by our customers in operating lease arrangements consisted of: $216.9 million of processing equipment; $56.4 million of storage tanks; $47.5 million of pipeline and station equipment; and $29.0 million of other assets. The processing equipment primarily relates to our condensate splitter.

Sales-Type Lease – Lessor

We entered into a long-term throughput and deficiency agreement with a customer on a pipeline and related assets that we constructed in Texas and New Mexico, which contains minimum volume/payment commitments. Our customer has the option to purchase this pipeline and related assets at the end of the lease term for a nominal amount. This agreement is accounted for as a sales-type lease under ASC 842. The net investment under this arrangement as of December 31, 2020 and 2021 was as follows (in millions):

	December 31, 2020		December 31, 2021
Total minimum lease payments receivable	$	14.0	$	12.2
Less: Unearned income	2.3		1.8
Recorded net investment in sales-type lease	$	11.7	$	10.4

The net investment in this sales-type lease was classified in the consolidated balance sheets as follows (in millions):

	December 31, 2020		December 31, 2021
Other accounts receivable	$	1.2	$	1.3
Long-term receivables	10.5		9.1
Total	$	11.7	$	10.4

Future minimum payments receivable under this sales-type lease for the next five years are $1.7 million each year with $3.5 million due thereafter.

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2021

Retirement Benefits [Abstract]

Compensation and Employee Benefit Plans

Employee Benefit Plans

Our pension and postretirement benefit liabilities represent the funded status of the present value of benefit obligations of our employee benefit plans. We develop pension, postretirement medical and life benefit costs from third-party actuarial valuations. We establish actuarial assumptions to anticipate future events and use those assumptions when calculating the expense and liabilities related to these plans. These factors include assumptions management makes concerning expected investment return on plan assets, discount rates, health care costs trend rates, turnover rates and rates of future compensation increases, among others. In addition, we use subjective factors such as withdrawal and mortality rates to develop actuarial valuations. Management reviews and updates these assumptions on an annual basis. The actuarial assumptions that we use may differ from actual results due to changing market rates or other factors. These differences could affect the amount of pension and postretirement medical and life benefit expense we will recognize in future periods.

Defined Contribution Plan. 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, including expenses related to discontinued operations, were $11.4 million, $12.2 million and $10.6 million in 2019, 2020 and 2021, respectively.

Defined Benefit Plans. We sponsor two pension plans, including one for non-union employees and one for union employees, and a postretirement benefit plan for certain employees. The annual measurement date of these plans is December 31.

The following table presents the changes in benefit obligations and plan assets for pension benefits and other postretirement benefits, as well as the end-of-period accumulated benefit obligation, including amounts related to discontinued operations, for the years ended December 31, 2020 and 2021 (in millions):

	Pension Benefits				Other Postretirement Benefits
	2020		2021		2020		2021
Change in benefit obligations:
Benefit obligations at beginning of year	$	381.2	$	443.6	$	15.2	$	17.3
Service cost	27.7		28.2		0.3		0.3
Interest cost	11.0		9.5		0.5		0.4
Plan participants’ contributions	—		—		0.6		0.8
Actuarial (gain) loss	53.2		(19.4)		2.5		0.9
Benefits paid	(23.1)		(29.2)		(1.8)		(1.9)
Curtailment gain	(1.7)		—		—		—
Settlement payments	(4.7)		(9.3)		—		—
Benefit obligations at end of year	443.6		423.4		17.3		17.8
Change in plan assets:
Fair value of plan assets at beginning of year	249.2		295.7		—		—
Employer contributions	29.3		27.6		1.2		1.1
Plan participants’ contributions	—		—		0.6		0.8
Actual return on plan assets	43.6		9.7		—		—
Benefits paid	(23.1)		(29.2)		(1.8)		(1.9)
Settlement payments	(3.3)		(9.3)		—		—
Fair value of plan assets at end of year	295.7		294.5		—		—
Funded status at end of year	$	(147.9)	$	(128.9)	$	(17.3)	$	(17.8)
Accumulated benefit obligations	$	324.8	$	305.0

At December 31, 2020 and 2021, the accumulated benefit obligations of each of our plans exceeded the fair value of the related plan’s assets.

The pension plans’ actuarial gain in 2021 of $19.4 million is primarily due to the impact of increases in the discount rates used to calculate the benefit obligations, partially offset by demographic changes. The pension benefit obligations experienced an actuarial loss of $53.2 million in 2020 primarily due to the impact of decreases in the discount rates used to calculate the benefit obligations, partially offset by changes in salary assumptions and higher asset returns.

The following table summarizes information for pension plans with obligations in excess of plan assets (in millions):

	December 31,
	2020		2021
Plans with a projected benefit obligation in excess of plan assets:
Projected benefit obligation	$	443.6	$	423.4
Fair value of plan assets	$	295.7	$	294.5
Plans with an accumulated benefit obligation in excess of plan assets:
Accumulated benefit obligation	$	324.8	$	305.0
Fair value of plan assets	$	295.7	$	294.5

Amounts recognized in the consolidated balance sheets included in these financial statements were as follows (in millions):

	Pension Benefits				Other Postretirement Benefits
	2020		2021		2020		2021
Amounts recognized in consolidated balance sheets:
Current accrued benefit cost	$	—	$	—	$	1.4	$	1.7
Long-term pension and benefits	147.9		128.9		15.9		16.1
	147.9		128.9		17.3		17.8
Accumulated other comprehensive loss:
Net actuarial loss	(120.5)		(95.3)		(10.4)		(10.7)
Prior service credit	2.7		2.5		—		—
	(117.8)		(92.8)		(10.4)		(10.7)
Net amount of liabilities and accumulated other comprehensive loss recognized in consolidated balance sheets	$	30.1	$	36.1	$	6.9	$	7.1

Net periodic benefit expense for the years ended December 31, 2019, 2020 and 2021 was as follows (in millions): 

	Pension Benefits						Other Postretirement Benefits
	2019		2020		2021		2019		2020		2021
Components of net periodic benefit costs:
Service cost	$	25.4	$	27.7	$	28.2	$	0.2	$	0.3	$	0.3
Interest cost	12.2		11.0		9.5		0.5		0.5		0.4
Expected return on plan assets	(9.4)		(11.4)		(11.9)		—		—		—
Amortization of prior service credit	(0.2)		(0.2)		(0.2)		—		—		—
Amortization of actuarial loss	5.5		5.4		5.4		0.3		0.4		0.6
Settlement cost	2.6		1.0		2.6		—		—		—
Settlement gain on disposition of assets	—		(1.3)		—		—		—		—
Net periodic benefit cost	$	36.1	$	32.2	$	33.6	$	1.0	$	1.2	$	1.3

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 (income) expense in our consolidated statements of income.

Changes in plan assets and benefit obligations recognized in other comprehensive income (loss) during 2019, 2020 and 2021 were as follows (in millions):

	Pension Benefits						Other Postretirement Benefits
	2019		2020		2021		2019		2020		2021
Beginning balance	$	(88.6)	$	(104.7)	$	(117.8)	$	(5.4)	$	(8.4)	$	(10.4)
Net actuarial gain (loss)	(24.0)		(21.0)		17.2		(3.3)		(2.5)		(0.9)
Amortization of prior service credit	(0.2)		(0.2)		(0.2)		—		—		—
Amortization of actuarial loss	5.5		5.4		5.4		0.3		0.5		0.6
Curtailment gain	—		1.7		—		—		—		—
Settlement cost	2.6		1.0		2.6		—		—		—
Amount recognized in other comprehensive loss	(16.1)		(13.1)		25.0		(3.0)		(2.0)		(0.3)
Ending balance	$	(104.7)	$	(117.8)	$	(92.8)	$	(8.4)	$	(10.4)	$	(10.7)

Actuarial gains and losses are amortized over the average future service period of the current active plan participants expected to receive benefits. The corridor approach is used to determine when actuarial gains and losses are to be amortized and is equal to 10% of the greater of the projected benefit obligation or the market related value of plan assets. The amount of gain or loss in excess of the calculated corridor is subject to amortization.

The weighted average rate assumptions used to determine projected benefit obligations were as follows:

	Pension Benefits		Other Postretirement Benefits
	2020	2021	2020	2021
Discount rate	2.23%	2.61%	2.30%	2.64%
Rate of compensation increase	4.53%	6.51%	n/a	n/a
Cash balance interest crediting rate	1.70%	1.94%	n/a	n/a

The weighted average rate assumptions used to determine net pension and other postretirement benefit plans expense were as follows:

 

	Pension Benefits			Other Postretirement Benefits
	For the Year Ended December 31,			For the Year Ended December 31,
	2019	2020	2021	2019	2020	2021
Discount rate	3.98%	3.01%	2.23%	4.08%	3.06%	2.30%
Rate of compensation increase	6.48%	4.58%	4.53%	n/a	n/a	n/a
Expected rate of return on plan assets	6.00%	4.50%	4.10%	n/a	n/a	n/a
Cash balance interest crediting rate	2.78%	2.16%	1.70%	n/a	n/a	n/a

The non-pension postretirement benefit plans provide for retiree contributions and contain other cost-sharing features such as deductibles and coinsurance. The accounting for these plans anticipates future cost sharing that is consistent with management’s expressed intent to increase the retiree contribution rate generally in line with health care cost increases.

The annual assumed rate of increase in the health care cost trend rate for 2022 is 6.0% decreasing systematically to 5.08% by 2029 for pre-65 year old participants.

The fair values of the pension plan assets at December 31, 2020 were as follows (in millions):

Asset Category	Total		Quoted Prices in Active  Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Domestic equity securities:(1)
Small-cap fund	$	5.8	$	5.8	$	—	$	—
Mid-cap fund	5.8		5.8		—		—
Large-cap fund	47.6		47.6		—		—
International equity fund	29.9		29.9		—		—
Fixed income securities:(1)
Short-term bond fund	4.2		4.2		—		—
Intermediate-term bond fund	34.9		34.9		—		—
Long-term investment grade bond funds	161.0		161.0		—		—
Other:
Short-term investment fund	6.3		6.3		—		—
Group annuity contract	0.2		—		—		0.2
Fair value of plan assets	$	295.7	$	295.5	$	—	$	0.2

(1) We hold equity and fixed income securities through investments in mutual funds, which are dedicated to each category as indicated.

The fair values of the pension plan assets at December 31, 2021 were as follows (in millions):

Asset Category	Total		Quoted Prices in Active  Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Domestic equity securities(1):
Small-cap fund	$	6.1	$	6.1	$	—	$	—
Mid-cap fund	6.0		6.0		—		—
Large-cap fund	48.0		48.0		—		—
International equity fund	30.1		30.1		—		—
Fixed income securities(1):
Long-term investment grade bond funds	197.1		197.1		—		—
Other:
Short-term investment fund	7.0		7.0		—		—
Group annuity contract	0.2		—		—		0.2
Fair value of plan assets	$	294.5	$	294.3	$	—	$	0.2

(1) We hold equity and fixed income securities through investments in mutual funds, which are dedicated to each category as indicated.

As reflected in the tables above, Level 3 activity was not material.

The investment strategies for the various funds held as pension plan assets by asset category are as follows: 

Asset Category	Fund’s Investment Strategy
Domestic equity securities:
Small-cap fund	Seeks to track performance of the Center for Research in Security Prices (“CRSP”) US Small Cap Index
Mid-cap fund	Seeks to track performance of the CRSP US Mid Cap Index
Large-cap fund	Seeks to track performance of the Standard & Poor’s 500 Index
International equity fund	Seeks to track performance of the FTSE Global All Cap ex US Index
Fixed income securities:
Short-term bond fund	Seeks current income with limited price volatility through investment in primarily high quality bonds with short-term maturities
Intermediate-term bond fund	Seeks moderate and sustainable level of current income by investing primarily in high quality fixed income securities with maturities from five to ten years
Long-term investment grade bond funds	Seek high and sustainable current income through investment primarily in long-term investment grade debt securities
Other:
Short-term investment funds	Invest in high quality short-term money market instruments issued by the U.S. Treasury
Group annuity contract	Earns interest quarterly equal to the effective yield of the 91-day U.S. Treasury bill

The expected long-term rate of return on plan assets was determined by combining a review of projected returns, historical returns of portfolios with assets similar to the current portfolios of the union and non-union pension plans and target weightings of each asset classification. Our investment objective for the assets within the pension plans is to earn a return that meets or exceeds the growth of obligations that result from interest and changes in the discount rate, while avoiding excessive risk. Defined diversification goals are set in order to reduce the risk of wide swings in the market value from year to year, or of incurring large losses that may result from concentrated positions. As a result, our plan assets have no significant concentrations of credit risk. Additionally, liquidity risks are minimized because the funds that the plans have invested in are publicly traded. We evaluate risks based on the potential impact to the predictability of contribution requirements, probability of under-funding, expected risk-adjusted returns and investment return volatility. Funds are invested with multiple investment managers. Our liabilities are calculated using rates defined by the Pension Protection Act of 2006. Approximately 70% of the plans’ investments are allocated to fixed-income securities and invested to match the durations of the plans’ short, intermediate and long-term pension liabilities, with the amount invested in each duration reflecting that duration’s proportion of the plans’ liabilities. The remaining approximately 30% of the plans’ investments are allocated to equity securities.

The target allocation and actual weighted average asset allocation percentages at December 31, 2020 and 2021 were as follows:

	2020		2021
	Actual	Target	Actual	Target
Equity securities	30%	30%	30%	30%
Fixed income securities	68%	67%	67%	70%
Other	2%	3%	3%	—%

As of December 31, 2021, the benefit amounts expected to be paid from plan assets through December 31, 2031 were as follows (in millions): 

	Pension Benefits		Other Postretirement Benefits
2022	$	16.2	$	1.7
2023	$	18.1	$	1.5
2024	$	21.6	$	1.3
2025	$	22.4	$	1.3
2026	$	27.4	$	1.2
2027 through 2031	$	147.9	$	4.0

Contributions estimated to be paid by us into the plans in 2022 are $37.2 million and $1.7 million for the pension and other postretirement benefit plans, respectively.

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Long-Term Incentive Plan

12 Months Ended

Dec. 31, 2021

Share-based Payment Arrangement [Abstract]

Long-Term Incentive Plan

Long-Term Incentive Plan

The compensation committee of our board administers our long-term incentive plan (“LTIP”) covering certain of our employees and the independent directors of our general partner. In April 2021, our compensation committee and our limited partners approved an amendment to the LTIP increasing the number of common units available for issuance from 11.9 million to 13.7 million. The LTIP primarily consists of phantom units. The estimated units remaining available under the LTIP at December 31, 2021 totaled approximately 2.4 million. The awards include: (i) performance-based awards issued to certain officers and other key employees (“performance-based awards”), (ii) time-based awards issued to certain officers and other key employees (“time-based awards,” and together with performance-based awards, “employee awards”) and (iii) awards issued to independent members of our board (“director awards”) that may be deferred and if deferred may be paid in cash. All of the awards include distribution equivalent rights, except non-deferred director awards.

The LTIP requires employee awards to be settled in our common units, except the settlement of distribution equivalents, which we pay in cash. As a result, we classify employee awards as equity. Fair value for these awards is determined on the grant date, and we recognize this value as compensation expense ratably over the requisite service period, which is the vesting period of each award. The vesting period for employee awards is generally three years; however, certain awards have been issued with shorter vesting periods while others have vesting periods of up to four years. Because employee awards contain distribution equivalent rights, the fair value of our employee awards is based on the closing price of our units on the grant date.

Payouts for performance-based awards are subject to the attainment of a financial metric. Additionally, the 2019 performance-based awards, which vested on December 31, 2021, were subject to an adjustment for our total unitholder return (the “TUR adjustment”), and the fair value of these awards was adjusted for the fair value of the TUR adjustment. The TUR adjustment is based on our total unitholder return at the end of the three-year vesting period of the awards in relation to the total unitholder returns of certain peer entities. The financial metric for the performance-based awards is our distributable cash flow per unit excluding commodity-related activities for the last year of the three-year vesting period as compared to established threshold, target and stretch levels. The payouts for the performance-related component of the awards can range from 0%, for results below threshold, up to 200%, for actual results at stretch or above. Payouts related to time-based awards are based solely on the completion of the requisite service period by the employee and contain no provisions that provide for a payout other than the original number of units awarded and the associated distribution equivalents.

Performance-based awards are subject to forfeiture if a participant’s employment is terminated for any reason other than for termination within two years of a change-in-control that occurs on an involuntary basis without cause or on a voluntary basis for good cause, or due to retirement, disability or death prior to the vesting date.  These awards can vest early under certain circumstances following a change in control. Time-based awards are subject to forfeiture if a participant’s employment is terminated for any reason other than retirement, death or disability prior to the vesting date, or as the result of certain other employment restrictions. If an employee award recipient retires, dies or becomes disabled prior to the end of the vesting period, the award is prorated based upon months of employment completed during the vesting period, and the award is settled shortly after the end of the vesting period.

Compensation expense for our equity awards is calculated as the number of unit awards less forfeitures, multiplied by the grant date fair value of those awards, multiplied by the percentage of the requisite service period completed at each period end, multiplied by the expected payout percentage, less previously-recognized compensation expense.

Non-deferred director awards are paid in units valued on the grant date, with compensation expense calculated as the number of units awarded multiplied by the fair value of those units at that date. We classify deferred director awards as liability awards because they may be settled in cash. Because deferred director awards have distribution equivalent rights, the fair value of these awards equals the closing price of our units at the measurement date. Compensation expense for deferred director awards is calculated as the number of units awarded, multiplied by the fair value of those awards on the measurement date, less previously-recognized compensation expense.

Non-Vested Unit Awards

The following table includes the changes during the current fiscal year in the number of non-vested units that have been granted by the compensation committee. The amounts below do not include adjustments for above-target or below-target performance.

	Performance-Based Awards			Time-Based Awards			Total Awards
	Number of Unit Awards	Weighted Average Fair Value		Number of Unit Awards	Weighted Average Fair Value		Number of Unit Awards	Weighted Average Fair Value
Non-vested units - 1/1/2021	340,164	$	62.35	353,544	$	61.07	693,708	$	61.70
Units granted during 2021	281,823	$	40.85	301,873	$	40.99	583,696	$	40.92
Units vested during 2021	(161,484)	$	63.62	(168,204)	$	60.76	(329,688)	$	62.16
Units forfeited during 2021	(14,578)	$	51.23	(16,699)	$	50.92	(31,277)	$	51.06
Non-vested units - 12/31/21	445,925	$	48.66	470,514	$	48.67	916,439	$	48.67

The table below summarizes the total non-vested unit awards outstanding, including estimated targeted financial performance adjustments, to determine our total equity-based liability accrual.

Grant Date	Non-Vested Unit Awards	Performance Adjustment to Unit Awards	Total Unit Award Accrual	Vesting Date	Unrecognized Compensation Expense (in millions)(a)
Performance-based awards:
2020 awards	171,400	(51,420)	119,980	12/31/2022	$	2.4
2021 awards	274,525	68,631	343,156	12/31/2023	9.3
Time-based awards:
2022 vesting date	178,911	—	178,911	12/31/2022	3.7
2023 vesting date	291,603	—	291,603	12/31/2023	8.3
Total	916,439	17,211	933,650		$	23.7

(a) Unrecognized compensation expense will be recognized over the remaining vesting period of the awards.

Weighted Average Fair Value

The weighted average fair value of awards granted during 2019, 2020 and 2021 was as follows:

	Performance-Based Awards			Time-Based Awards
	Number of Unit Awards	Weighted Average Fair Value		Number of Unit Awards	Weighted Average Fair Value
Units granted during 2019	182,834	$	63.65	195,031	$	62.91
Units granted during 2020	189,632	$	61.16	198,450	$	61.18
Units granted during 2021	281,823	$	40.85	301,873	$	40.99

Vested Unit Awards

The table below sets forth the numbers and values of units that vested in each of the three years ended December 31, 2021. The vested common units include adjustments for above-target financial and market performance.

Vesting Date	Vested Common Units	Fair Value of Unit Awards on Vesting Date (in millions)	Intrinsic Value of Unit Awards on Vesting Date (in millions)
12/31/2019	436,629	$31.0	$27.5
12/31/2020	235,127	$15.2	$10.0
12/31/2021	316,336	$19.3	$14.7

Cash Flow Effects of LTIP Settlements

The difference between the common units issued to the participants and the total number of unit awards vested primarily represents the tax withholdings associated with the award settlement, which we pay in cash.

Settlement Date	Number of Common Units Issued, Net of Tax Withholdings	Tax Withholdings and Other Cash Payments (in millions)	Employer Taxes (in millions)	Total Cash Payments (in millions)
January 2019	199,792	$9.8	$0.9	$10.7
January 2020	275,093	$14.7	$1.3	$16.0
January 2021	150,435	$6.2	$0.7	$6.9

Compensation Expense Summary

Equity-based incentive compensation expense for 2019, 2020 and 2021, primarily recorded as G&A expense on our consolidated statements of income, was as follows (in millions):

	Year Ended December 31,
	2019		2020		2021
Performance awards	$	17.9	$	3.1	$	11.2
Time-based awards	$	6.1	$	8.9	$	10.6
Total	$	24.0	$	12.0	$	21.8

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Derivative Financial Instruments

12 Months Ended

Dec. 31, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments

Derivative Financial Instruments

We use derivative instruments to manage market price risks associated with inventories, interest rates and certain forecasted transactions. For those instruments that qualify for hedge accounting, the accounting treatment depends on their intended use and their designation. We classify derivative financial instruments qualifying for hedge accounting treatment into two categories: (1) cash flow hedges and (2) fair value hedges. We execute cash flow hedges to hedge against the variability in cash flows related to a forecasted transaction and execute fair value hedges to hedge against the changes in the value of a recognized asset or liability. At the inception of a hedged transaction, we document the relationship between the hedging instrument and the hedged item, the risk management objectives and the methods used for assessing and testing hedge effectiveness. We also assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows or fair value of the hedged item. If we determine that a derivative originally designated as a cash flow or fair value hedge is no longer highly effective, we discontinue hedge accounting prospectively and record the change in the fair value of the derivative in current earnings. The changes in fair value of derivative financial instruments that are not designated as hedges for accounting purposes, which we refer to as economic hedges, are included in current earnings.

As part of our risk management process, we assess the creditworthiness of the financial and other institutions with which we execute financial derivatives. Such financial instruments involve the risk of non-performance by the counterparty, which could result in material losses to us.

Interest Rate Derivatives

We periodically enter into interest rate derivatives to hedge the fair value of debt or hedge against variability in

interest rates. For interest rate cash flow hedges, we record the unrealized gains or losses as an adjustment to other comprehensive income. The realized gains and losses from our cash flow hedges are recognized into earnings as an adjustment to our periodic interest expense over the life of the related debt issuance. For fair value hedges on long-term debt, we record the unrealized gains or losses as an adjustment to long-term debt, and realized amounts as an adjustment to our periodic interest expense. Adjustments resulting from discontinued hedges continue to be recognized in accordance with their historic hedging relationships.

In December 2020, upon issuance of an additional $300.0 million of 3.95% notes due 2050, we terminated and settled treasury lock agreements that we had previously entered into to protect against the variability of interest payments on this anticipated debt issuance for a gain of $1.0 million, which was included in our statements of cash flows as a net receipt on financial derivatives. These agreements were accounted for as cash flow hedges. The gain was recorded to other comprehensive income (loss) and will be recognized into earnings as an adjustment to our periodic interest expense over the term of the life of the associated notes.

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

In August 2019, upon issuance of our $500.0 million of 3.95% notes due 2050, we terminated and settled treasury lock agreements we had previously entered into to protect against the variability of interest payments on this anticipated debt issuance for a loss of $25.3 million, which was included in our statements of cash flows as a net payment on financial derivatives.  These agreements were accounted for as cash flow hedges. The loss was recorded to other comprehensive income (loss) and will be recognized into earnings as an adjustment to our periodic interest expense over the life of the associated notes.

In January 2019, upon issuance of $500.0 million of 4.85% notes due 2049, we terminated and settled treasury lock agreements that we had previously entered into to protect against the variability of interest payments on this anticipated debt issuance for a loss of $8.0 million, which was included in our statements of cash flows as a net payment on financial derivatives. These agreements were accounted for as cash flow hedges. The loss was recorded to other comprehensive income (loss) and will be recognized into earnings as an adjustment to our periodic interest expense over the life of the associated notes.

Commodity Derivatives

Our gas liquids 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 and over-the-counter commodity derivatives contracts and forward physical purchase and sale contracts to help manage commodity price changes and mitigate the risk of decline in the product margin realized from our gas liquids blending activities. Further, certain of our other commercial operations and marketing activities involve petroleum products inventories, and we also use derivatives contracts to hedge against price changes for some of these inventories.

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 costs 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 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 derivative 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 December 31, 2021 were as follows:

Type of Contract/ Accounting Methodology	Product Represented by the Contract and Associated Barrels	Maturity Dates
Commodity derivatives contract - Economic hedges	3.3 million barrels of refined products and crude oil	Between January and November 2022
Commodity derivatives contract - Economic hedges	0.6 million barrels of gas liquids	Between January and April 2022

Commodity Derivatives Contracts and Deposits Offsets

At December 31, 2020 and 2021, we had made margin deposits of $34.2 million and $46.3 million, respectively, for our commodity derivatives contracts with our counterparties, which were recorded as current assets under commodity derivatives deposits on our consolidated balance sheets. We have the right to offset the combined fair values of our open derivatives 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 derivatives contracts separately from the related margin deposits on our consolidated balance sheets. Additionally, we have the right to offset the fair values of our derivatives 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 master netting arrangements are provided below as of December 31, 2020 and 2021 (in millions):

Description	Gross Amounts of Recognized Liabilities		Gross Amounts of Assets Offset in the Consolidated Balance Sheets		Net Amounts of Liabilities Presented in the Consolidated Balance Sheets		Margin Deposit Amounts Not Offset in the Consolidated Balance Sheets		Net Asset Amount(1)
As of December 31, 2020	$	(21.7)	$	1.2	$	(20.5)	$	34.2	$	13.7
As of December 31, 2021	$	(22.3)	$	5.1	$	(17.2)	$	46.3	$	29.1

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

Basis Derivative Agreement

During 2019, we entered into a basis derivative agreement with a joint venture co-owner’s affiliate, and, contemporaneously, that affiliate entered into an intrastate transportation services agreement with the joint venture. Settlements under the basis derivative agreement are determined based on the basis differential of crude oil prices at different market locations and a notional volume of 30,000 barrels per day. As a result, we account for this agreement as a derivative. The agreement will expire in early 2022. We recognize the changes in fair value of this agreement based on forward price curves for crude oil in West Texas and the Houston Gulf Coast in other operating income (expense) in our consolidated statements of income. The liability for this agreement at December 31, 2020 and 2021, respectively, was $10.2 million and $1.5 million.

Impact of Derivatives on Our Financial Statements

Comprehensive Income

The changes in derivative activity included in AOCL for the years ended December 31, 2019, 2020 and 2021 were as follows (in millions):

	Year Ended December 31,
Derivative Losses Included in AOCL	2019		2020		2021
Beginning balance	$	(26.5)	$	(49.0)	$	(55.0)
Net loss on cash flow hedges	(25.2)		(9.5)		—
Reclassification of net loss on cash flow hedges to income	2.7		3.5		3.5
Ending balance	$	(49.0)	$	(55.0)	$	(51.5)

The following is a summary of the effect on our consolidated statements of income for the years ended December 31, 2019, 2020 and 2021 of derivatives that were designated as cash flow hedges (in millions):

	Interest Rate Contracts
	Amount of Loss Recognized in AOCL on  Derivatives			Location of Loss Reclassified from AOCL into Income	Amount of Loss Reclassified from AOCL into Income
Year Ended December 31, 2019		$	(25.2)	Interest expense		$	(2.7)
Year Ended December 31, 2020		$	(9.5)	Interest expense		$	(3.5)
Year Ended December 31, 2021		$	—	Interest expense		$	(3.5)

As of December 31, 2021, the net loss estimated to be classified to interest expense over the next twelve months from AOCL is approximately $3.5 million. This amount relates to the amortization of losses on interest rate contracts over the life of the related debt instruments.

The following table provides a summary of the effect on our consolidated statements of income for the years ended December 31, 2019, 2020 and 2021 of derivatives that were not designated as hedging instruments (in millions):

		Amount of Gain (Loss) Recognized on Derivatives
		Year Ended December 31,
Derivative Instrument	Location of Gain (Loss) Recognized on Derivatives	2019		2020		2021
Commodity derivatives contracts	Product sales revenue	$	(66.5)	$	53.2	$	(143.2)
Commodity derivatives contracts	Cost of product sales	(0.2)		0.3		21.1
Basis derivative agreement	Other operating income (expense)	(10.2)		(4.3)		(5.6)
	Total	$	(76.9)	$	49.2	$	(127.7)

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

Balance Sheets

The following tables provide a summary of the fair value of derivatives, which are presented on a net basis in our consolidated balance sheets, that were not designated as hedging instruments as of December 31, 2020 and 2021 (in millions):

	December 31, 2020
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity derivatives contracts	Commodity derivatives contracts, net	$	0.1	Commodity derivatives contracts, net	$	21.7
Commodity derivatives contracts	Other noncurrent assets	1.1		Other noncurrent liabilities	—
Basis derivative agreement	Other current assets	—		Other current liabilities	8.8
Basis derivative agreement	Other noncurrent assets	—		Other noncurrent liabilities	1.4
	Total	$	1.2	Total	$	31.9
	December 31, 2021
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity derivatives contracts	Commodity derivatives contracts, net	$	5.1	Commodity derivatives contracts, net	$	22.3
Basis derivative agreement	Other current assets	—		Other current liabilities	1.5
	Total	$	5.1	Total	$	23.8

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Fair Value Disclosures

12 Months Ended

Dec. 31, 2021

Fair Value Disclosures [Abstract]

Fair Value Disclosures

Fair Value Disclosures

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:

•Commodity derivatives contracts. These include exchange-traded and over-the-counter derivative contracts related to petroleum products. These contracts are carried at fair value on our consolidated balance sheets. The exchange-traded contracts are valued based on quoted prices in active markets, while the over-the-counter contracts are valued based on observable market data inputs including published commodity pricing data. See Note 14 – Derivative Financial Instruments for further disclosures regarding these contracts.

•Basis derivative agreement. During 2019, we entered into a basis derivative agreement with a joint venture co-owner’s affiliate, and, contemporaneously, that affiliate entered into an intrastate transportation services agreement with the joint venture. Settlements under the basis derivative agreement are determined based on the basis differential of crude oil prices at different market locations and a notional volume of 30,000 barrels per day (see Note 14 - Derivative Financial Instruments for further disclosures regarding this agreement). The fair value of this derivative was calculated based on observable market data inputs, including published commodity pricing data and market interest rates. The key inputs in the fair value calculation include the forward price curves for crude oil, the implied forward correlation in crude oil prices between West Texas and the Houston Gulf Coast, and the implied forward volatility for crude oil futures contracts.

•Long-term receivables. These include payments receivable under a sales-type leasing arrangement and cost reimbursement agreements. 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.

•Contractual obligations. At December 31, 2021, these primarily included a long-term contractual obligation we entered into in connection with the 2020 sale of three marine terminals to a subsidiary of Buckeye Partners, L.P. (“Buckeye”). This obligation requires us to perform certain environmental remediation work on Buckeye’s behalf at the New Haven, Connecticut terminal.  This contractual obligation was recorded at fair value on our consolidated balance sheets upon initial recognition and was calculated using our best estimate of potential outcome scenarios to determine our liability for the remediation costs required in this agreement.

•Debt. The fair value of our publicly traded notes was based on the prices of those notes at December 31, 2020 and 2021; 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, 2020 and 2021, based on the three levels established by ASC 820; Fair Value Measurements and Disclosures (in millions):

					Fair Value Measurements as of December 31, 2020 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)
Commodity derivatives contracts	$	(20.5)	$	(20.5)	$	(20.5)	$	—	$	—
Basis derivative agreement	$	(10.2)	$	(10.2)	$	—	$	(10.2)	$	—
Long-term receivables	$	22.8	$	22.8	$	—	$	—	$	22.8
Contractual obligations	$	(11.2)	$	(11.2)	$	—	$	—	$	(11.2)
Debt	$	(4,978.7)	$	(5,880.9)	$	—	$	(5,880.9)	$	—

					Fair Value Measurements as of December 31, 2021 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)
Commodity derivatives contracts	$	(17.2)	$	(17.2)	$	(18.6)	$	1.4	$	—
Basis derivative agreement	$	(1.5)	$	(1.5)	$	—	$	(1.5)	$	—
Long-term receivables	$	10.1	$	10.1	$	—	$	—	$	10.1
Contractual obligations	$	(9.8)	$	(9.8)	$	—	$	—	$	(9.8)
Debt	$	(5,088.8)	$	(5,711.5)	$	—	$	(5,711.5)	$	—

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Certain conditions may exist as of the date our consolidated financial statements are issued that could result in a loss to us, but which will only be resolved when one or more future events occur or fail to occur. Our management assesses such contingent liabilities, which inherently involves significant judgment. In assessing loss contingencies related to legal proceedings that are pending against us or for unasserted claims that may result in proceedings, our management, with input from legal counsel, evaluates the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.

Environmental expenditures are charged to operating expense or capitalized based on the nature of the expenditures. We record environmental liabilities independently of any potential claim for recovery. Accruals related to environmental matters are generally determined based on site-specific plans for remediation, taking into account currently available facts, existing technologies and presently enacted laws and regulations. Accruals for environmental matters reflect our prior remediation experience and include an estimate for costs such as fees paid to contractors, outside engineering and consulting firms. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remediation feasibility study. Such accruals are adjusted as further information develops or circumstances change. The determination of the accrual amounts recorded for environmental liabilities includes significant judgments and assumptions made by

management. The use of alternate judgments and assumptions could result in the recognition of different levels of environmental remediation costs.

We maintain specific insurance coverage, which may cover all or portions of certain environmental expenditures less a deductible. We recognize receivables in cases where we consider the realization of reimbursements of remediation costs as probable.

We recognize liabilities for other commitments and contingencies when, after analyzing the available information, we determine it is probable that an asset has been impaired, or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. When we can estimate a range of probable loss, we accrue the most likely amount within that range, or if no amount is more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as incurred.

Butane Blending Patent Infringement Proceeding

On October 4, 2017, Sunoco Partners Marketing & Terminals L.P. (“Sunoco”) brought an action for patent infringement in the U.S. District Court for the District of Delaware alleging Magellan Midstream Partners, L.P. (“Magellan”) and Powder Springs Logistics, LLC (“Powder Springs”) are infringing patents relating to butane blending at the Powder Springs facility located in Powder Springs, Georgia. Sunoco subsequently submitted pleadings alleging that Magellan is also infringing various patents related to butane blending at eight Magellan facilities, in addition to Powder Springs. Sunoco sought monetary damages, attorneys’ fees and a permanent injunction enjoining Powder Springs from infringing the subject patents. We have vigorously defended against all claims asserted by Sunoco. A jury trial concluded on December 6, 2021, at which the jury found Magellan willfully infringed the three patents in suit and awarded damages of approximately $9.4 million against Magellan relating to the eight Magellan facilities at issue. The jury further found that Powder Springs willfully infringed the one patent at issue relating to the Powder Springs facility and awarded approximately $2.8 million against Magellan and Powder Springs relating to that facility. Sunoco requested that the the court enhance the damages award based upon the jury’s finding of willfulness, and that the court award additional damages and pre- and post-judgment interest. Magellan and Powder Springs have filed post-trial pleadings opposing Sunoco’s request for enhanced damages and to otherwise challenge the finding of liability and willfulness. The final determination of the trial court is subject to potential future appeals by either or both parties to the litigation.The amounts we have accrued in relation to the claims are immaterial, and although it is not possible to predict the ultimate outcome, we believe the final 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 $13.5 million and $9.8 million at December 31, 2020 and December 31, 2021, 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 included in operating expenses on our consolidated statements of income. Environmental expenses were $3.8 million, $3.4 million and $3.2 million for the years ended December 31, 2019, 2020 and 2021, respectively.

Other

In first quarter 2020, we entered into a long-term contractual obligation in connection with the sale of three marine terminals to Buckeye.  This obligation requires us to perform certain environmental remediation work on Buckeye’s behalf in New Haven, Connecticut.  At December 31, 2020 our consolidated balance sheets included a current liability of $0.6 million and a noncurrent liability of $10.2 million, and as of December 31, 2021, our

consolidated balance sheets reflected a current liability of $0.5 million and a noncurrent liability of $8.9 million, reflecting the fair values of these obligations.

We have entered into an agreement to guarantee our 50% pro rata share, up to $25.0 million, of contractual obligations under Powder Springs’ credit facility. As of December 31, 2020 and 2021, our consolidated balance sheets reflected a $0.4 million other current liability and a corresponding increase in our investment in non-controlled entities on our consolidated balance sheets to reflect the fair value of this guarantee.

We and the non-controlled entities in which we own an interest are a party to various other claims, legal actions and complaints. While the results cannot be predicted with certainty, management believes the ultimate resolution of these claims, legal actions and complaints after consideration of amounts accrued, insurance coverage or other indemnification arrangements will not have a material adverse effect on our business.

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Concentration of Risks

12 Months Ended

Dec. 31, 2021

Risks and Uncertainties [Abstract]

Concentration of Risks

Concentration of Risks

We transport, store and distribute petroleum products for refiners, producers, marketers, traders and end users of those products. Our revenue producing activities are concentrated in the central U.S. Concentrations of customers may affect our overall credit risk as our customers may be similarly affected by changes in economic, regulatory or other factors. We generally secure transportation and storage revenue with warehouseman’s liens. We periodically evaluate the financial condition and creditworthiness of our customers and require additional security as we deem necessary.

As of December 31, 2021, we had 1,715 employees, primarily concentrated in the central and Gulf Coast regions of the U.S. There were 854 employees assigned to our refined products segment, 253 employees assigned to our crude oil segment and 526 employees assigned to provide G&A services.  We also had 82 employees assigned to our discontinued operations. Approximately 13% of our employees are represented by the United Steel Workers and covered by a collective bargaining agreement that expired at the end of January 2022.

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Related Party Transactions

12 Months Ended

Dec. 31, 2021

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

Stacy Methvin is an independent member of our general partner’s board of directors and also serves as a director of one of our customers.  We received tariff, terminalling and other ancillary revenue from this customer of $29.6 million, $37.4 million and $65.2 million for the periods ending December 31, 2019, 2020 and 2021, respectively. We recorded a receivable of $3.9 million and $5.4 million from this customer at December 31, 2020 and 2021, respectively.  We occasionally have transmix settlements with this customer as well. Additionally, we received storage and other miscellaneous revenue of $0.5 million for the period ending December 31, 2020 and $0.3 million for the period ending December 31, 2021 from a subsidiary of a separate company for which Stacy Methvin served as a director until August 31, 2021.

See Note 7 – Investments in Non-Controlled Entities and Note 11 – Leases for a discussion of transactions with our joint ventures.

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Partners' Capital and Distributions

12 Months Ended

Dec. 31, 2021

Partners' Capital Notes [Abstract]

Partners' Capital and Distributions

Partners’ Capital and Distributions

Partners’ Capital

Our board authorized the repurchase of up to $1.5 billion of our common units through 2024. The timing, price and actual number of common units repurchased will depend on a number of factors including our expected expansion capital spending needs, excess cash available, balance sheet metrics, legal and regulatory requirements, market conditions and the trading price of our common units. The repurchase program does not obligate us to acquire any particular amount of common units, and the repurchase program may be suspended or discontinued at any time.

The following table details the changes in the number of our common units outstanding from January 1, 2019 through December 31, 2021:

Common units outstanding on January 1, 2019	228,195,160
February 2019—Settlement of employee LTIP awards	199,792
During 2019—Other(1)	8,476
Common units outstanding on December 31, 2019	228,403,428
Units repurchased during 2020	(5,568,260)
February 2020—Settlement of employee LTIP awards	275,093
During 2020—Other(1)	9,550
Common units outstanding on December 31, 2020	223,119,811
Units repurchased during 2021	(10,894,828)
January 2021—Settlement of employee LTIP awards	150,435
During 2021—Other(1)	12,572
Common units outstanding on December 31, 2021	212,387,990

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

Our partnership agreement allows us to issue additional partnership securities for any partnership purpose at any time and from time to time for consideration and on terms and conditions as our general partner determines, all without approval by our unitholders.

Common unitholders have the following rights, among others:

•right to receive distributions of our available cash within 45 days after the end of each quarter;

•right to elect the members of our board;

•right to remove Magellan GP, LLC as our general partner upon a 100% vote of outstanding unitholders;

•right to transfer common unit ownership to substitute common unitholders;

•right to receive an annual report, containing audited financial statements and a report on those financial statements by our independent public accountants, within 120 days after the close of the fiscal year end;

•right to receive information reasonably required for tax reporting purposes within 90 days after the close of the calendar year;

•right to vote according to the unitholder’s percentage interest in us at any meeting that may be called by our general partner; and

•right to inspect our books and records at the unitholder’s own expense.

In the event of liquidation, we would distribute all property and cash in excess of that required to discharge all liabilities to the unitholders in proportion to the positive balances in their respective capital accounts. The common unitholders’ liability is generally limited to their investment.

Distributions

Distributions we paid during 2019, 2020 and 2021 were as follows (in millions, except per unit amounts):

Payment Date	Per Unit  Distribution Amount		Total Distribution
2/14/2019	$	0.9975	$	227.8
5/15/2019	1.0050		229.5
8/14/2019	1.0125		231.3
11/14/2019	1.0200		233.0
Total	$	4.0350	$	921.6
2/14/2020	$	1.0275	$	234.8
5/15/2020	1.0275		231.2
8/14/2020	1.0275		231.2
11/13/2020	1.0275		229.9
Total	$	4.1100	$	927.1
2/12/2021	$	1.0275	$	229.4
5/14/2021	1.0275		229.0
8/13/2021	1.0275		226.6
11/12/2021	1.0375		221.4
Total	$	4.1200	$	906.4

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Subsequent Events

12 Months Ended

Dec. 31, 2021

Subsequent Events [Abstract]

Subsequent Events

Subsequent Events

Recognizable events

No recognizable events have occurred subsequent to December 31, 2021.

Non-recognizable events

On January 25, 2022, Michael N. Mears notified the partnership of his decision to retire from his positions of President, Chief Executive Officer and Chairman of the Board of Directors effective on April 30, 2022. Our board elected Barry R. Pearl, currently the independent Lead Director, as Chairman of the Board and also elected Aaron L. Milford as Chief Executive Officer and President effective May 1, 2022. Mr. Milford currently serves as Chief Operating Officer and has served in such capacity since 2019. He served as Senior Vice President and Chief Financial Officer from 2015 to 2019 and various positions of increasing responsibility since joining us and our predecessor in 1995.

Approximately 13% of our employees are represented by the United Steel Workers and covered by a collective bargaining agreement that expired at the end of January 2022. We are operating under a 24-hour rolling extension of this agreement while negotiations for a new agreement continue.

On February 14, 2022, we paid distributions of $1.0375 per unit on our outstanding common units to unitholders of record at the close of business on February 7, 2022.

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Summary of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation. Our consolidated financial statements include our refined products and crude oil operating segments. We consolidate all entities in which we have a controlling ownership interest. We apply the equity method of accounting to investments in entities over which we exercise significant influence but do not control. We eliminate all intercompany transactions.

Reclassifications

Reclassifications. Certain prior period amounts have been reclassified to conform with the current period’s presentation, including amounts related to our discontinued operations.

Use of Estimates

Use of Estimates. The preparation of our consolidated financial statements in conformity with U.S. generally accepted accounting principles (“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.

Cash Equivalents

Cash Equivalents. Cash and cash equivalents include demand and time deposits and funds that own highly marketable securities with original maturities of three months or less when acquired. We periodically assess the financial condition of the institutions where we hold these funds, and at December 31, 2020 and 2021, we believed our credit risk relative to these funds was minimal.

Restricted Cash

Restricted Cash. Restricted cash includes cash that we are contractually required to use 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.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable represent valid claims against customers. We recognize accounts receivable when we sell products or render services and collection of the receivable is probable. We extend credit terms to certain customers after a review of various credit indicators. We establish an allowance for doubtful accounts using an expected credit loss approach and evaluate reserves no less than quarterly to determine their adequacy. Judgments relative to at-risk accounts include the customers’ current financial condition, the customers’ historical relationship with us and current and projected economic conditions. We write off accounts receivable when we deem an account uncollectible.

Product Overages and Shortages

Product Overages and Shortages. Each period end we measure the volume of each type of product in our pipeline systems and terminals, which is compared to the volumes of our customers’ inventories (as adjusted for tender deductions).  To the extent the product volumes in our pipeline systems and terminals exceed the volumes of our customers’ book inventories, we recognize a gain from the product overage and increase our product inventories. To the extent the product in our pipeline systems and terminals is less than our customers’ book inventories, we recognize a loss from the product shortage and we record a liability for product owed to our customers.  The product overages we recognize are recorded based on market prices, and the resulting inventory is carried at weighted average cost.  The product shortages we recognize are recorded based on our weighted average cost.  Additionally, when product shortages result in a net short inventory position, the related liability is recorded based on period-end market prices.  Product overages and shortages as well as adjustments to the value of net short inventory positions are recorded in operating expenses on our consolidated statements of income.

Income Taxes

Income Taxes. We are a partnership for income tax purposes and therefore are not subject to federal or state income taxes for most of the states in which we operate. The tax on our net income is borne by our unitholders through allocation to them of their share of our taxable income. Net income for financial statement purposes may differ significantly from taxable income allocated to unitholders because of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each unitholder’s tax attributes is not available to us.

The amounts recognized as provision for income taxes in our consolidated statements of income are primarily

comprised of partnership-level taxes levied by the state of Texas. This tax is based on revenues less direct costs of sale for our assets apportioned to the state of Texas.

Net Income Per Unit

Net Income Per Unit. We calculate basic net income per common unit for each period by dividing net income by the weighted average number of common units outstanding. The difference between our actual common units outstanding and our weighted average number of common units outstanding used to calculate net income per common unit is due to the impact of: (i) the phantom units issued to our independent directors, which are included in the calculation of basic and diluted weighted average units outstanding and (ii) the weighted average effect of units actually issued or repurchased during a period.  The difference between the weighted average number of common units outstanding used for basic and diluted net income per unit calculations on our consolidated statements of income is primarily the dilutive effect of phantom unit awards granted pursuant to our long-term incentive plan, which have not yet vested in periods where contingent performance metrics have been met.

New Accounting Pronouncements

New Accounting Pronouncements

We evaluate new Accounting Standards Codifications (“ASC”) and updates issued by the Financial Accounting Standards Board on an ongoing basis. There are no new accounting pronouncements that we anticipate will have a material impact on our financial statements.

Revenue

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 on a net basis.

We recognize pipeline transportation revenue for crude oil 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 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 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 related rules and orders. FERC regulation requires that interstate pipeline rates be filed with the FERC, be posted publicly, be “just and reasonable” and not be unduly discriminatory. The rates on approximately 30% 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 liquid pipeline companies may establish rates by obtaining authority to charge market-based rates in competitive markets or by negotiation with unaffiliated shippers. Approximately 70% 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.

Statements of Income Disclosures

Property, Plant and Equipment

Property, plant and equipment consists primarily of pipeline, pipeline-related equipment, storage tanks and processing equipment. We state property, plant and equipment at cost except for certain acquired assets recorded at fair value on their respective acquisition dates and impaired assets. We record impaired assets at fair value on the last impairment evaluation date for which an adjustment was required.

We assign asset lives based on reasonable estimates when we place an asset into service. Subsequent events could cause us to change our estimates, which would affect the future calculation of depreciation expense.

When we sell or retire property, plant and equipment, we remove its carrying value and the related accumulated depreciation from our accounts and record any associated gains or losses on our consolidated statements of income in the period of sale or disposition.

We capitalize expenditures to replace existing assets and retire the replaced assets. We capitalize expenditures when they extend the useful life, increase the productivity or capacity, or improve the safety or efficiency of the asset. We capitalize direct project costs such as labor and materials as incurred. Indirect project costs, such as overhead, are capitalized based on a percentage of direct labor charged to the respective capital project. We charge expenditures for maintenance, repairs and minor replacements to operating expense in the period incurred.

During construction, we capitalize interest on construction projects undergoing preparation for use and when total budgeted project costs exceed $0.5 million. The interest we capitalize is based on the weighted average interest rate of our debt.

Impairment of Long-Lived Assets

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying value may not be recoverable. In reviewing for impairment, the carrying value of such assets is compared to the estimated undiscounted future cash flows expected from the use of the assets and their eventual disposition. If such cash flows are not sufficient to support the asset’s recorded value, an impairment charge is recognized to reduce the carrying value of the long-lived asset to its estimated fair value. The determination of future cash flows as well as the estimated fair value of long-lived assets involves significant estimates on the part of management.

Goodwill

We record the excess of purchase price over the fair value of the tangible and identifiable intangible assets acquired and liabilities assumed in a business acquisition (or combination) as goodwill. The goodwill relating to each of our reporting units is tested for impairment annually as well as when an event or change in circumstances indicates an impairment may have occurred.For purposes of performing the impairment test for goodwill, our reporting units are our refined products and crude oil segments.

Other Intangibles

Other intangible assets with finite lives are amortized over their estimated useful lives of 7 years up to 30 years. The weighted average asset life of our other intangible assets at December 31, 2021 was approximately 16 years. We adjust the useful lives of our other intangible assets if events or circumstances indicate there has been a change in the remaining useful lives. We eliminate from our balance sheets the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized.

Investments in Non-Controlled Entities

We account for interests in affiliates that we do not control using the equity method of accounting. Under this method, an investment is recorded at our acquisition cost or capital contributions, as adjusted by contractual terms, plus equity in earnings or losses since acquisition or formation, plus interest capitalized, less distributions received and amortization of interest capitalized and excess net investment. Excess net investment is the amount by which our investment in a non-controlled entity exceeded our proportionate share of the book value of the net assets of that investment. We amortize excess net investment over the weighted average depreciable asset lives of the equity investee. Our unamortized excess net investment was $33.0 million and $32.0 million at December 31, 2020 and 2021, respectively. The amount of unamortized excess investment is primarily related to our investment in BridgeTex. We evaluate equity method investments for impairment whenever events or circumstances indicate that there is an other-than-temporary loss in value of the investment. In the event that we determine that the loss in value of an investment is other-than-temporary, we would record a charge to earnings to adjust the carrying value to fair value. We recognized no equity investment impairments during 2019, 2020 and 2021.

Inventory

stated and relieved at the lower of average cost or net realizable value.Inventory

Lessee and Lessor Arrangements

We have both lessee and lessor arrangements. Our leases are evaluated at inception or at any subsequent modification. Depending on the terms, leases are classified as either operating or finance leases if we are the lessee, or as operating, sales-type or direct financing leases if we are the lessor, as appropriate under ASC 842, Leases.  Our lessee arrangements primarily include a terminalling and storage contract where we have exclusive use of dedicated tankage, leased pipelines and office buildings. Our lessor arrangements include pipeline capacity and storage contracts and our condensate splitter tolling agreement that qualify as operating leases under ASC 842. In addition, we have a long-term throughput and deficiency agreement with a customer that is being accounted for as a sales-type lease under ASC 842.

In accordance with ASC 842, we have made an accounting policy election to not apply the standard to lessee arrangements with a term of one year or less and no purchase option that is reasonably certain of exercise. We will continue to account for these short-term arrangements by recognizing payments and expenses as incurred, without recording a lease liability and right-of-use asset.

We have also made an accounting policy election for both our lessee and lessor arrangements to combine lease and non-lease components. This election is applied to all of our lease arrangements as our non-lease components do not result in significant timing differences in the recognition of rental expenses or income.

Operating Leases – Lessee

We recognize a lease liability for each lease based on the present value of remaining minimum fixed rental payments (which includes payments under any renewal option that we are reasonably certain to exercise), using a discount rate that approximates the rate of interest we would have to pay to borrow on a collateralized basis over a similar term. We also recognize a right-of-use asset for each lease, valued at the lease liability, adjusted for prepaid or accrued rent balances existing at the time of initial recognition. The lease liability and right-of-use asset are reduced over the term of the lease as payments are made and the assets are used.

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

Minimum fixed rental payments are recognized on a straight-line basis over the life of the lease as costs and expenses on our consolidated statements of income. Variable and short-term rental payments are recognized as costs and expenses as they are incurred. Variable payments consist of amounts that exceed the contractual minimum rental payment (for example, payment increases tied to a change in a market index).

Employee Benefit Plans

Our pension and postretirement benefit liabilities represent the funded status of the present value of benefit obligations of our employee benefit plans. We develop pension, postretirement medical and life benefit costs from third-party actuarial valuations. We establish actuarial assumptions to anticipate future events and use those assumptions when calculating the expense and liabilities related to these plans. These factors include assumptions management makes concerning expected investment return on plan assets, discount rates, health care costs trend rates, turnover rates and rates of future compensation increases, among others. In addition, we use subjective factors such as withdrawal and mortality rates to develop actuarial valuations. Management reviews and updates these assumptions on an annual basis. The actuarial assumptions that we use may differ from actual results due to changing market rates or other factors. These differences could affect the amount of pension and postretirement medical and life benefit expense we will recognize in future periods.

Long-Term Incentive Plan

The compensation committee of our board administers our long-term incentive plan (“LTIP”) covering certain of our employees and the independent directors of our general partner. In April 2021, our compensation committee and our limited partners approved an amendment to the LTIP increasing the number of common units available for issuance from 11.9 million to 13.7 million. The LTIP primarily consists of phantom units. The estimated units remaining available under the LTIP at December 31, 2021 totaled approximately 2.4 million. The awards include: (i) performance-based awards issued to certain officers and other key employees (“performance-based awards”), (ii) time-based awards issued to certain officers and other key employees (“time-based awards,” and together with performance-based awards, “employee awards”) and (iii) awards issued to independent members of our board (“director awards”) that may be deferred and if deferred may be paid in cash. All of the awards include distribution equivalent rights, except non-deferred director awards.

The LTIP requires employee awards to be settled in our common units, except the settlement of distribution equivalents, which we pay in cash. As a result, we classify employee awards as equity. Fair value for these awards is determined on the grant date, and we recognize this value as compensation expense ratably over the requisite service period, which is the vesting period of each award. The vesting period for employee awards is generally three years; however, certain awards have been issued with shorter vesting periods while others have vesting periods of up to four years. Because employee awards contain distribution equivalent rights, the fair value of our employee awards is based on the closing price of our units on the grant date.

Payouts for performance-based awards are subject to the attainment of a financial metric. Additionally, the 2019 performance-based awards, which vested on December 31, 2021, were subject to an adjustment for our total unitholder return (the “TUR adjustment”), and the fair value of these awards was adjusted for the fair value of the TUR adjustment. The TUR adjustment is based on our total unitholder return at the end of the three-year vesting period of the awards in relation to the total unitholder returns of certain peer entities. The financial metric for the performance-based awards is our distributable cash flow per unit excluding commodity-related activities for the last year of the three-year vesting period as compared to established threshold, target and stretch levels. The payouts for the performance-related component of the awards can range from 0%, for results below threshold, up to 200%, for actual results at stretch or above. Payouts related to time-based awards are based solely on the completion of the requisite service period by the employee and contain no provisions that provide for a payout other than the original number of units awarded and the associated distribution equivalents.

Performance-based awards are subject to forfeiture if a participant’s employment is terminated for any reason other than for termination within two years of a change-in-control that occurs on an involuntary basis without cause or on a voluntary basis for good cause, or due to retirement, disability or death prior to the vesting date.  These awards can vest early under certain circumstances following a change in control. Time-based awards are subject to forfeiture if a participant’s employment is terminated for any reason other than retirement, death or disability prior to the vesting date, or as the result of certain other employment restrictions. If an employee award recipient retires, dies or becomes disabled prior to the end of the vesting period, the award is prorated based upon months of employment completed during the vesting period, and the award is settled shortly after the end of the vesting period.

Compensation expense for our equity awards is calculated as the number of unit awards less forfeitures, multiplied by the grant date fair value of those awards, multiplied by the percentage of the requisite service period completed at each period end, multiplied by the expected payout percentage, less previously-recognized compensation expense.

Non-deferred director awards are paid in units valued on the grant date, with compensation expense calculated as the number of units awarded multiplied by the fair value of those units at that date. We classify deferred director awards as liability awards because they may be settled in cash. Because deferred director awards have distribution equivalent rights, the fair value of these awards equals the closing price of our units at the measurement date. Compensation expense for deferred director awards is calculated as the number of units awarded, multiplied by the fair value of those awards on the measurement date, less previously-recognized compensation expense.

Derivative Financial Instruments

We use derivative instruments to manage market price risks associated with inventories, interest rates and certain forecasted transactions. For those instruments that qualify for hedge accounting, the accounting treatment depends on their intended use and their designation. We classify derivative financial instruments qualifying for hedge accounting treatment into two categories: (1) cash flow hedges and (2) fair value hedges. We execute cash flow hedges to hedge against the variability in cash flows related to a forecasted transaction and execute fair value hedges to hedge against the changes in the value of a recognized asset or liability. At the inception of a hedged transaction, we document the relationship between the hedging instrument and the hedged item, the risk management objectives and the methods used for assessing and testing hedge effectiveness. We also assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows or fair value of the hedged item. If we determine that a derivative originally designated as a cash flow or fair value hedge is no longer highly effective, we discontinue hedge accounting prospectively and record the change in the fair value of the derivative in current earnings. The changes in fair value of derivative financial instruments that are not designated as hedges for accounting purposes, which we refer to as economic hedges, are included in current earnings.

As part of our risk management process, we assess the creditworthiness of the financial and other institutions with which we execute financial derivatives. Such financial instruments involve the risk of non-performance by the counterparty, which could result in material losses to us.

Commitments and Contingencies

Certain conditions may exist as of the date our consolidated financial statements are issued that could result in a loss to us, but which will only be resolved when one or more future events occur or fail to occur. Our management assesses such contingent liabilities, which inherently involves significant judgment. In assessing loss contingencies related to legal proceedings that are pending against us or for unasserted claims that may result in proceedings, our management, with input from legal counsel, evaluates the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.

Environmental expenditures are charged to operating expense or capitalized based on the nature of the expenditures. We record environmental liabilities independently of any potential claim for recovery. Accruals related to environmental matters are generally determined based on site-specific plans for remediation, taking into account currently available facts, existing technologies and presently enacted laws and regulations. Accruals for environmental matters reflect our prior remediation experience and include an estimate for costs such as fees paid to contractors, outside engineering and consulting firms. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remediation feasibility study. Such accruals are adjusted as further information develops or circumstances change. The determination of the accrual amounts recorded for environmental liabilities includes significant judgments and assumptions made by

management. The use of alternate judgments and assumptions could result in the recognition of different levels of environmental remediation costs.

We maintain specific insurance coverage, which may cover all or portions of certain environmental expenditures less a deductible. We recognize receivables in cases where we consider the realization of reimbursements of remediation costs as probable.

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Discontinued Operations and Assets Held for Sale (Tables)

12 Months Ended

Dec. 31, 2021

Discontinued Operations and Disposal Groups [Abstract]

Disposal Groups, Including Discontinued Operations

The following table provides the summarized results that have been reclassified from continuing operations to discontinued operations on the consolidated statements of income for the years ended December 31, 2019, 2020 and 2021 (in millions):

	Year Ended December 31,
	2019		2020		2021
Transportation and terminals revenue	$	56.8	$	51.4	$	53.3
Product sales revenue	70.3		54.2		83.7
Total revenue	127.1		105.6		137.0
Costs and expenses:
Operating	17.9		13.4		11.2
Cost of product sales	58.5		45.5		66.5
Depreciation, amortization and impairment	15.4		15.6		7.1
General and administrative	2.5		2.2		2.5
Total costs and expenses	94.3		76.7		87.3
Income from discontinued operations	$	32.8	$	28.9	$	49.7

The following table provides the summarized assets and liabilities classified as held for sale on the consolidated balance sheets as of December 31, 2020 and 2021 (in millions):

	Year Ended December 31,
	2020		2021
Assets:
Trade accounts receivable	$	5.6	$	6.3
Inventory	9.2		17.0
Net property, plant and equipment	274.9		272.0
Goodwill	2.7		2.7
Other assets	0.3		1.5
Total assets classified as held for sale	$	292.7	$	299.5
Liabilities:
Accounts payable	$	2.0	$	3.7
Accrued product liabilities	4.0		8.4
Other liabilities	3.9		3.7
Total liabilities classified as held for sale	$	9.9	$	15.8

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Segment Disclosures (Tables)

12 Months Ended

Dec. 31, 2021

Segment Reporting [Abstract]

Segment Reporting Information by Segment

	Year Ended December 31, 2019
	(in millions)
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation and terminals revenue	$	1,299.0	$	620.3	$	(5.4)	$	1,913.9
Product sales revenue	637.5		28.3		—		665.8
Affiliate management fee revenue	6.7		14.5		—		21.2
Total revenue	1,943.2		663.1		(5.4)		2,600.9
Operating expense	454.0		173.3		(10.9)		616.4
Cost of product sales	532.8		28.1		—		560.9
Other operating (income) expense	(10.2)		7.2		—		(3.0)
Earnings of non-controlled entities	(8.1)		(160.9)		—		(169.0)
Operating margin	974.7		615.4		5.5		1,595.6
Depreciation, amortization and impairment expense	158.7		66.5		5.5		230.7
G&A expense	138.3		55.9		—		194.2
Operating profit	$	677.7	$	493.0	$	—	$	1,170.7
Additions to long-lived assets	$	785.1	$	74.2			$	859.3
	As of December 31, 2019
	(in millions)
Segment assets	$	5,116.4	$	2,894.7			$	8,011.1
Assets held for sale							295.5
Corporate assets							131.1
Total assets							$	8,437.7
Goodwill	$	38.5	$	12.1			$	50.6
Investments in non-controlled entities	$	422.4	$	818.2			$	1,240.6

	Year Ended December 31, 2020
	(in millions)
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation and terminals revenue	$	1,190.4	$	559.5	$	(6.6)	$	1,743.3
Product sales revenue	524.4		33.1		—		557.5
Affiliate management fee revenue	6.3		14.9		—		21.2
Total revenue	1,721.1		607.5		(6.6)		2,322.0
Operating expense	411.8		189.2		(13.2)		587.8
Cost of product sales	425.8		42.4		—		468.2
Other operating (income) expense	(3.2)		3.1		—		(0.1)
Earnings of non-controlled entities	(32.5)		(120.8)		—		(153.3)
Operating margin	919.2		493.6		6.6		1,419.4
Depreciation, amortization and impairment expense	159.9		76.6		6.6		243.1
G&A expense	123.5		47.7		—		171.2
Operating profit	$	635.8	$	369.3	$	—	$	1,005.1
Additions to long-lived assets	$	277.5	$	56.4			$	333.9
	As of December 31, 2020
	(in millions)
Segment assets	$	4,977.0	$	2,836.9			$	7,813.9
Assets held for sale							292.7
Corporate assets							90.4
Total assets							$	8,197.0
Goodwill	$	38.0	$	12.1			$	50.1
Investments in non-controlled entities	$	429.2	$	784.7			$	1,213.9

	Year Ended December 31, 2021
	(in millions)
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation and terminals revenue	$	1,338.5	$	466.2	$	(5.8)	$	1,798.9
Product sales revenue	763.9		149.1		—		913.0
Affiliate management fee revenue	6.4		14.8		—		21.2
Total revenue	2,108.8		630.1		(5.8)		2,733.1
Operating expense	416.7		165.4		(12.4)		569.7
Cost of product sales	630.1		149.9		—		780.0
Other operating (income) expense	(6.9)		4.1		—		(2.8)
Earnings of non-controlled entities	(34.4)		(120.0)		—		(154.4)
Operating margin	1,103.3		430.7		6.6		1,540.6
Depreciation, amortization and impairment expense	153.9		67.4		6.6		227.9
G&A expense	147.8		58.5		—		206.3
Operating profit	$	801.6	$	304.8	$	—	$	1,106.4
Additions to long-lived assets	$	88.9	$	41.1			$	130.0
	As of December 31, 2021
	(in millions)
Segment assets	$	4,880.0	$	2,780.7			$	7,660.7
Assets held for sale							299.5
Corporate assets							69.8
Total assets							$	8,030.0
Goodwill	$	38.0	$	12.1			$	50.1
Investments in non-controlled entities	$	232.8	$	748.0			$	980.8

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Revenue (Tables)

12 Months Ended

Dec. 31, 2021

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

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

	Year Ended December 31, 2019
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation	$	787.7	$	381.6	$	—	$	1,169.3
Terminalling	139.9		17.8		—		157.7
Storage	214.9		119.3		(5.4)		328.8
Ancillary services	128.6		28.4		—		157.0
Lease revenue	27.9		73.2		—		101.1
Transportation and terminals revenue	1,299.0		620.3		(5.4)		1,913.9
Product sales revenue	637.5		28.3		—		665.8
Affiliate management fee revenue	6.7		14.5		—		21.2
Total revenue	1,943.2		663.1		(5.4)		2,600.9
Revenue not under the guidance of ASC 606, Revenue from Contracts with Customers:
Lease revenue	(27.9)		(73.2)		—		(101.1)
(Gains) losses from futures contracts included in product sales revenue	63.5		3.0		—		66.5
Affiliate management fee revenue	(6.7)		(14.5)		—		(21.2)
Total revenue from contracts with customers under ASC 606	$	1,972.1	$	578.4	$	(5.4)	$	2,545.1

	Year Ended December 31, 2020
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation	$	742.9	$	305.4	$	—	$	1,048.3
Terminalling	109.6		21.5		—		131.1
Storage	199.3		129.0		(6.6)		321.7
Ancillary services	114.9		26.9		—		141.8
Lease revenue	23.7		76.7		—		100.4
Transportation and terminals revenue	1,190.4		559.5		(6.6)		1,743.3
Product sales revenue	524.4		33.1		—		557.5
Affiliate management fee revenue	6.3		14.9		—		21.2
Total revenue	1,721.1		607.5		(6.6)		2,322.0
Revenue not under the guidance of ASC 606, Revenue from Contracts with Customers:
Lease revenue	(23.7)		(76.7)		—		(100.4)
(Gains) losses from futures contracts included in product sales revenue	(56.8)		3.6		—		(53.2)
Affiliate management fee revenue	(6.3)		(14.9)		—		(21.2)
Total revenue from contracts with customers under ASC 606	$	1,634.3	$	519.5	$	(6.6)	$	2,147.2

	Year Ended December 31, 2021
	Refined Products		Crude Oil		Intersegment Eliminations		Total
Transportation	$	915.7	$	228.8	$	—	$	1,144.5
Terminalling	100.1		17.0		—		117.1
Storage	177.1		114.8		(5.8)		286.1
Ancillary services	125.2		29.9		—		155.1
Lease revenue	20.4		75.7		—		96.1
Transportation and terminals revenue	1,338.5		466.2		(5.8)		1,798.9
Product sales revenue	763.9		149.1		—		913.0
Affiliate management fee revenue	6.4		14.8		—		21.2
Total revenue	2,108.8		630.1		(5.8)		2,733.1
Revenue not under the guidance of ASC 606, Revenue from Contracts with Customers:
Lease revenue	(20.4)		(75.7)		—		(96.1)
(Gains) losses from futures contracts included in product sales revenue	(127.2)		(16.0)		—		(143.2)
Affiliate management fee revenue	(6.4)		(14.8)		—		(21.2)
Total revenue from contracts with customers under ASC 606	$	1,954.8	$	523.6	$	(5.8)	$	2,472.6

Contract Assets and Liabilities

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

	December 31, 2020		December 31, 2021
Accounts receivable from contracts with customers	$	103.3	$	134.8
Contract assets	$	12.2	$	12.5
Contract liabilities	$	102.7	$	100.1

Remaining Performance Obligation

The following table provides the aggregate amount of the transaction price allocated to our UPOs as of December 31, 2021 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 millions):

	Refined Products		Crude Oil		Total
Amounts as of December 31, 2021	$	1,874.5	$	1,069.8	$	2,944.3
Remaining terms	1 - 17 years		1 - 10 years
Estimated revenues from UPOs to be recognized in the next 12 months	$	368.9	$	257.4	$	626.3

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Property, Plant and Equipment and Other Intangibles (Tables)

12 Months Ended

Dec. 31, 2021

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, plant and equipment consisted of the following (in millions):

					Estimated  Depreciable Lives
	December 31,
	2020		2021
Construction work-in-progress	$	122.0	$	89.5
Land and rights-of-way	373.9		374.3
Buildings	119.7		121.8		10 to 53 years
Storage tanks	1,952.7		1,986.7		10 to 49 years
Pipeline and station equipment	3,325.9		3,386.0		10 to 59 years
Processing equipment	1,769.4		1,826.4		3 to 56 years
Other	280.2		261.2		3 to 53 years
Property, plant and equipment, gross	$	7,943.8	$	8,045.9

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Investments in Non-Controlled Entities (Tables)

12 Months Ended

Dec. 31, 2021

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments

Our equity investments in non-controlled entities at December 31, 2021 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”)	25%
Powder Springs Logistics, LLC (“Powder Springs”)	50%
Saddlehorn Pipeline Company, LLC (“Saddlehorn”)	30%
Seabrook Logistics, LLC (“Seabrook”)	50%
Texas Frontera, LLC (“Texas Frontera”)	50%

In April 2021, we sold nearly half of our membership interest in MVP. As a result of the sale, we received proceeds of $272.1 million and recorded a gain of $70.4 million on our consolidated statements of income. Following the sale, we own approximately 25% of MVP and remain the operator of the facility.

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 receive are reported as affiliate management fee revenue on our consolidated statements of income. Cost reimbursements we receive from these entities in connection with our operating services are included as reductions to costs and expenses on our consolidated statements of income and totaled $5.3 million, $3.6 million and $2.5 million, respectively, for the years ended December 31, 2019, 2020 and 2021.

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

	Year Ended December 31,
	2019		2020		2021
Transportation and terminals revenue:
BridgeTex, pipeline capacity and storage	$	41.8	$	42.3	$	43.7
Double Eagle, throughput revenue	$	6.2	$	4.9	$	3.0
Saddlehorn, storage revenue	$	2.2	$	2.5	$	2.3
Operating expense:
Seabrook, storage lease and ancillary services	$	25.9	$	29.1	$	19.7
Product sales revenue:
Seabrook, product sales	$	0.3	$	—	$	—
Other operating income:
MVP, easement sale	$	0.3	$	—	$	—
Seabrook, gain on sale of air emission credits	$	—	$	1.4	$	0.4

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

	December 31, 2020
	Trade Accounts Receivable		Other Accounts Receivable		Other Accounts Payable		Long-Term Receivables
BridgeTex	$	0.4	$	—	$	1.0	$	—
Double Eagle	$	0.3	$	—	$	—	$	—
HoustonLink	$	—	$	—	$	0.1	$	—
MVP	$	—	$	0.5	$	2.3	$	—
Powder Springs	$	—	$	—	$	—	$	10.2
Saddlehorn	$	—	$	0.1	$	—	$	—
Seabrook	$	—	$	—	$	7.3	$	—

	December 31, 2021
	Trade Accounts Receivable		Other Accounts Receivable		Other Accounts Payable		Long-Term Receivables
BridgeTex	$	1.2	$	—	$	0.3	$	—
Double Eagle	$	0.2	$	—	$	—	$	—
HoustonLink	$	—	$	—	$	0.2	$	—
MVP	$	—	$	0.6	$	2.2	$	—
Powder Springs	$	—	$	—	$	—	$	—
Saddlehorn	$	—	$	0.2	$	—	$	—
Seabrook	$	—	$	0.1	$	3.2	$	—

We entered into a long-term terminalling and storage contract with Seabrook for exclusive use of dedicated tankage that provides our customers with crude oil storage capacity and dock access for crude oil imports and exports on the Texas Gulf Coast (see Note 11 – Leases for more details regarding this lease).

We also made purchases of transmix from MVP throughout the year totaling $7.6 million.

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

A summary of our investments in non-controlled entities (representing only our proportionate interests) follows (in millions):

Investments at December 31, 2020	$	1,213.9
Additional investment	5.6
Sale of ownership interests	(199.8)
Earnings of non-controlled entities:
Proportionate share of earnings	156.2
Amortization of excess investment and capitalized interest	(1.8)
Earnings of non-controlled entities	154.4
Less:
Distributions from operations of non-controlled entities	193.3
Investments at December 31, 2021	$	980.8

Summarized financial information of our non-controlled entities (representing 100% of the interests in these entities) follows (in millions):

	December 31,
	2020		2021
Current assets	$	243.8	$	227.0
Noncurrent assets	2,846.7		2,795.7
Total assets	$	3,090.5	$	3,022.7
Current liabilities	$	143.6	$	178.6
Noncurrent liabilities	57.5		59.5
Total liabilities	$	201.1	$	238.1
Equity	$	2,889.4	$	2,784.6

	Year Ended December 31,
	2019		2020		2021
Revenue	$	782.0	$	752.7	$	733.1
Net income	$	507.5	$	471.4	$	463.4

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Inventory (Tables)

12 Months Ended

Dec. 31, 2021

Inventory Disclosure [Abstract]

Inventory

stated and relieved at the lower of average cost or net realizable value.

Inventory at December 31, 2020 and 2021 was as follows (in millions):

	December 31,
	2020		2021
Refined products	$	72.0	$	138.0
Crude oil	32.4		25.4
Liquefied petroleum gases	25.0		42.0
Transmix	23.4		72.4
Additives	5.4		3.3
Total inventory	$	158.2	$	281.1

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Supplemental Cash Flows Information (Tables)

12 Months Ended

Dec. 31, 2021

Supplemental Cash Flow Information [Abstract]

Changes in Components of Operating Assets and Liabilities

Changes in the components of operating assets and liabilities are as follows (in millions):

	Year Ended December 31,
	2019		2020		2021
Trade accounts receivable and other accounts receivable	$	(20.3)	$	(0.9)	$	(29.1)
Inventory	2.7		14.0		(122.9)
Accounts payable	(1.9)		4.5		16.0
Accrued payroll and benefits	4.8		(22.3)		22.8
Accrued interest payable	1.0		(5.3)		—
Accrued taxes other than income	12.6		4.4		8.8
Deferred revenue	(11.4)		(10.7)		(6.1)
Accrued product liabilities	15.9		(8.5)		78.3
Other current and noncurrent assets and liabilities	(1.3)		(12.3)		22.5
Total	$	2.1	$	(37.1)	$	(9.7)

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Debt (Tables)

12 Months Ended

Dec. 31, 2021

Debt Disclosure [Abstract]

Consolidated Debt

Debt

Long-term debt at December 31, 2020 and 2021 was as follows (in millions): 

	December 31,
	2020		2021
Commercial paper	$	—	$	108.0
3.20% Notes due 2025	250.0		250.0
5.00% Notes due 2026	650.0		650.0
3.25% Notes due 2030	500.0		500.0
6.40% Notes due 2037	250.0		250.0
4.20% Notes due 2042	250.0		250.0
5.15% Notes due 2043	550.0		550.0
4.20% Notes due 2045	250.0		250.0
4.25% Notes due 2046	500.0		500.0
4.20% Notes due 2047	500.0		500.0
4.85% Notes due 2049	500.0		500.0
3.95% Notes due 2050	800.0		800.0
Face value of long-term debt	5,000.0		5,108.0
Unamortized debt issuance costs(1)	(40.1)		(37.8)
Net unamortized debt premium(1)	18.8		18.6
Long-term debt, net	$	4,978.7	$	5,088.8

(1)    Debt issuance costs and note discounts and premiums are being amortized or accreted to the applicable notes over the respective lives of those notes.

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Leases (Tables)

12 Months Ended

Dec. 31, 2021

Leases [Abstract]

Lessee, Operating Lease, Liability, Maturity

Future minimum rental payments under operating leases with initial terms greater than one year as of December 31, 2021 are as follows (in millions):

	Third Party Leases		Seabrook Lease		All Leases
2022	$	21.2	$	9.9	$	31.1
2023	21.4		9.9		31.3
2024	21.7		9.7		31.4
2025	21.8		6.6		28.4
2026	12.5		6.6		19.1
Thereafter	34.1		17.6		51.7
Total future minimum rental payments	132.7		60.3		193.0
Present value discount	12.1		7.8		19.9
Total operating lease liability	$	120.6	$	52.5	$	173.1

Lessee, Operating Lease, Disclosure

The following tables provide a summary of the effect on our consolidated statements of income for the years ended December 31, 2019, 2020 and 2021 (in millions):

	Year Ended December 31, 2019
	Third Party Leases		Seabrook Lease		All Leases
Fixed lease expense	$	19.2	$	10.8	$	30.0
Short-term lease expense	1.6		—		1.6
Variable lease expense	3.0		15.0		18.1
Total lease expense	$	23.8	$	25.8	$	49.7

	Year Ended December 31, 2020
	Third Party Leases		Seabrook Lease		All Leases
Fixed lease expense	$	19.2	$	14.3	$	33.5
Short-term lease expense	1.3		—		1.3
Variable lease expense	4.1		14.8		18.9
Total lease expense	$	24.6	$	29.1	$	53.7

	Year Ended December 31, 2021
	Third Party Leases		Seabrook Lease		All Leases
Fixed lease expense	$	21.0	$	12.7	$	33.7
Short-term lease expense	1.7		—		1.7
Variable lease expense	3.4		6.8		10.2
Total lease expense	$	26.1	$	19.5	$	45.6

The following table provides a summary of the effect on our consolidated balance sheets as of December 31, 2020 and 2021 (dollars in millions):

	As of and for the Year Ended
	December 31, 2020									December 31, 2021
	Third Party Leases			Seabrook Lease			All Leases			Third Party Leases			Seabrook Lease			All Leases
Current lease liability	$	17.1		$	10.4		$	27.5		$	17.8		$	8.0		$	25.8
Long-term lease liability	$	85.0		$	52.5		$	137.5		$	102.8		$	44.5		$	147.3
Right-of-use asset	$	103.2		$	62.9		$	166.1		$	121.7		$	52.5		$	174.2
Operating cash flows for operating leases	$	24.1		$	29.1		$	53.2		$	26.2		$	19.5		$	45.7
Weighted average remaining lease term (years)	6			7			7			7			7			7
Weighted average discount  rate	3.7		%	4.0		%	3.8		%	3.0		%	4.1		%	3.4		%

Lessor, Future Minimum Payments Receivable

Future minimum payments receivable under operating leases with initial terms greater than one year as of December 31, 2021 are estimated as follows (in millions):

2022	$	24.9
2023	25.2
2024	21.9
2025	13.8
2026	13.1
Thereafter	32.9
Total	$	131.8

Leases, Investment in Direct Financing Lease

The net investment under this arrangement as of December 31, 2020 and 2021 was as follows (in millions):

	December 31, 2020		December 31, 2021
Total minimum lease payments receivable	$	14.0	$	12.2
Less: Unearned income	2.3		1.8
Recorded net investment in sales-type lease	$	11.7	$	10.4

The net investment in this sales-type lease was classified in the consolidated balance sheets as follows (in millions):

	December 31, 2020		December 31, 2021
Other accounts receivable	$	1.2	$	1.3
Long-term receivables	10.5		9.1
Total	$	11.7	$	10.4

Future minimum payments receivable under this sales-type lease for the next five years are $1.7 million each year with $3.5 million due thereafter.

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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2021

Retirement Benefits [Abstract]

Changes in Benefit Obligations and Plan Assets

The following table presents the changes in benefit obligations and plan assets for pension benefits and other postretirement benefits, as well as the end-of-period accumulated benefit obligation, including amounts related to discontinued operations, for the years ended December 31, 2020 and 2021 (in millions):

	Pension Benefits				Other Postretirement Benefits
	2020		2021		2020		2021
Change in benefit obligations:
Benefit obligations at beginning of year	$	381.2	$	443.6	$	15.2	$	17.3
Service cost	27.7		28.2		0.3		0.3
Interest cost	11.0		9.5		0.5		0.4
Plan participants’ contributions	—		—		0.6		0.8
Actuarial (gain) loss	53.2		(19.4)		2.5		0.9
Benefits paid	(23.1)		(29.2)		(1.8)		(1.9)
Curtailment gain	(1.7)		—		—		—
Settlement payments	(4.7)		(9.3)		—		—
Benefit obligations at end of year	443.6		423.4		17.3		17.8
Change in plan assets:
Fair value of plan assets at beginning of year	249.2		295.7		—		—
Employer contributions	29.3		27.6		1.2		1.1
Plan participants’ contributions	—		—		0.6		0.8
Actual return on plan assets	43.6		9.7		—		—
Benefits paid	(23.1)		(29.2)		(1.8)		(1.9)
Settlement payments	(3.3)		(9.3)		—		—
Fair value of plan assets at end of year	295.7		294.5		—		—
Funded status at end of year	$	(147.9)	$	(128.9)	$	(17.3)	$	(17.8)
Accumulated benefit obligations	$	324.8	$	305.0

Pension Plans with Obligations in Excess of Assets

The following table summarizes information for pension plans with obligations in excess of plan assets (in millions):

	December 31,
	2020		2021
Plans with a projected benefit obligation in excess of plan assets:
Projected benefit obligation	$	443.6	$	423.4
Fair value of plan assets	$	295.7	$	294.5
Plans with an accumulated benefit obligation in excess of plan assets:
Accumulated benefit obligation	$	324.8	$	305.0
Fair value of plan assets	$	295.7	$	294.5

Amounts Recognized in Consolidated Balance Sheets

Amounts recognized in the consolidated balance sheets included in these financial statements were as follows (in millions):

	Pension Benefits				Other Postretirement Benefits
	2020		2021		2020		2021
Amounts recognized in consolidated balance sheets:
Current accrued benefit cost	$	—	$	—	$	1.4	$	1.7
Long-term pension and benefits	147.9		128.9		15.9		16.1
	147.9		128.9		17.3		17.8
Accumulated other comprehensive loss:
Net actuarial loss	(120.5)		(95.3)		(10.4)		(10.7)
Prior service credit	2.7		2.5		—		—
	(117.8)		(92.8)		(10.4)		(10.7)
Net amount of liabilities and accumulated other comprehensive loss recognized in consolidated balance sheets	$	30.1	$	36.1	$	6.9	$	7.1

Consolidated Net Periodic Benefit Costs

Net periodic benefit expense for the years ended December 31, 2019, 2020 and 2021 was as follows (in millions): 

	Pension Benefits						Other Postretirement Benefits
	2019		2020		2021		2019		2020		2021
Components of net periodic benefit costs:
Service cost	$	25.4	$	27.7	$	28.2	$	0.2	$	0.3	$	0.3
Interest cost	12.2		11.0		9.5		0.5		0.5		0.4
Expected return on plan assets	(9.4)		(11.4)		(11.9)		—		—		—
Amortization of prior service credit	(0.2)		(0.2)		(0.2)		—		—		—
Amortization of actuarial loss	5.5		5.4		5.4		0.3		0.4		0.6
Settlement cost	2.6		1.0		2.6		—		—		—
Settlement gain on disposition of assets	—		(1.3)		—		—		—		—
Net periodic benefit cost	$	36.1	$	32.2	$	33.6	$	1.0	$	1.2	$	1.3

Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income (Loss)

Changes in plan assets and benefit obligations recognized in other comprehensive income (loss) during 2019, 2020 and 2021 were as follows (in millions):

	Pension Benefits						Other Postretirement Benefits
	2019		2020		2021		2019		2020		2021
Beginning balance	$	(88.6)	$	(104.7)	$	(117.8)	$	(5.4)	$	(8.4)	$	(10.4)
Net actuarial gain (loss)	(24.0)		(21.0)		17.2		(3.3)		(2.5)		(0.9)
Amortization of prior service credit	(0.2)		(0.2)		(0.2)		—		—		—
Amortization of actuarial loss	5.5		5.4		5.4		0.3		0.5		0.6
Curtailment gain	—		1.7		—		—		—		—
Settlement cost	2.6		1.0		2.6		—		—		—
Amount recognized in other comprehensive loss	(16.1)		(13.1)		25.0		(3.0)		(2.0)		(0.3)
Ending balance	$	(104.7)	$	(117.8)	$	(92.8)	$	(8.4)	$	(10.4)	$	(10.7)

Weighted-Average Rate Assumptions Used and Investment Strategies

The weighted average rate assumptions used to determine projected benefit obligations were as follows:

	Pension Benefits		Other Postretirement Benefits
	2020	2021	2020	2021
Discount rate	2.23%	2.61%	2.30%	2.64%
Rate of compensation increase	4.53%	6.51%	n/a	n/a
Cash balance interest crediting rate	1.70%	1.94%	n/a	n/a

The weighted average rate assumptions used to determine net pension and other postretirement benefit plans expense were as follows:

 

	Pension Benefits			Other Postretirement Benefits
	For the Year Ended December 31,			For the Year Ended December 31,
	2019	2020	2021	2019	2020	2021
Discount rate	3.98%	3.01%	2.23%	4.08%	3.06%	2.30%
Rate of compensation increase	6.48%	4.58%	4.53%	n/a	n/a	n/a
Expected rate of return on plan assets	6.00%	4.50%	4.10%	n/a	n/a	n/a
Cash balance interest crediting rate	2.78%	2.16%	1.70%	n/a	n/a	n/a

The investment strategies for the various funds held as pension plan assets by asset category are as follows: 

Asset Category	Fund’s Investment Strategy
Domestic equity securities:
Small-cap fund	Seeks to track performance of the Center for Research in Security Prices (“CRSP”) US Small Cap Index
Mid-cap fund	Seeks to track performance of the CRSP US Mid Cap Index
Large-cap fund	Seeks to track performance of the Standard & Poor’s 500 Index
International equity fund	Seeks to track performance of the FTSE Global All Cap ex US Index
Fixed income securities:
Short-term bond fund	Seeks current income with limited price volatility through investment in primarily high quality bonds with short-term maturities
Intermediate-term bond fund	Seeks moderate and sustainable level of current income by investing primarily in high quality fixed income securities with maturities from five to ten years
Long-term investment grade bond funds	Seek high and sustainable current income through investment primarily in long-term investment grade debt securities
Other:
Short-term investment funds	Invest in high quality short-term money market instruments issued by the U.S. Treasury
Group annuity contract	Earns interest quarterly equal to the effective yield of the 91-day U.S. Treasury bill

Fair Value and Allocation of Pension Plan Assets

The fair values of the pension plan assets at December 31, 2020 were as follows (in millions):

Asset Category	Total		Quoted Prices in Active  Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Domestic equity securities:(1)
Small-cap fund	$	5.8	$	5.8	$	—	$	—
Mid-cap fund	5.8		5.8		—		—
Large-cap fund	47.6		47.6		—		—
International equity fund	29.9		29.9		—		—
Fixed income securities:(1)
Short-term bond fund	4.2		4.2		—		—
Intermediate-term bond fund	34.9		34.9		—		—
Long-term investment grade bond funds	161.0		161.0		—		—
Other:
Short-term investment fund	6.3		6.3		—		—
Group annuity contract	0.2		—		—		0.2
Fair value of plan assets	$	295.7	$	295.5	$	—	$	0.2

(1) We hold equity and fixed income securities through investments in mutual funds, which are dedicated to each category as indicated.

The fair values of the pension plan assets at December 31, 2021 were as follows (in millions):

Asset Category	Total		Quoted Prices in Active  Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Domestic equity securities(1):
Small-cap fund	$	6.1	$	6.1	$	—	$	—
Mid-cap fund	6.0		6.0		—		—
Large-cap fund	48.0		48.0		—		—
International equity fund	30.1		30.1		—		—
Fixed income securities(1):
Long-term investment grade bond funds	197.1		197.1		—		—
Other:
Short-term investment fund	7.0		7.0		—		—
Group annuity contract	0.2		—		—		0.2
Fair value of plan assets	$	294.5	$	294.3	$	—	$	0.2

(1) We hold equity and fixed income securities through investments in mutual funds, which are dedicated to each category as indicated.

The target allocation and actual weighted average asset allocation percentages at December 31, 2020 and 2021 were as follows:

	2020		2021
	Actual	Target	Actual	Target
Equity securities	30%	30%	30%	30%
Fixed income securities	68%	67%	67%	70%
Other	2%	3%	3%	—%

Expected Benefit Payments

As of December 31, 2021, the benefit amounts expected to be paid from plan assets through December 31, 2031 were as follows (in millions): 

	Pension Benefits		Other Postretirement Benefits
2022	$	16.2	$	1.7
2023	$	18.1	$	1.5
2024	$	21.6	$	1.3
2025	$	22.4	$	1.3
2026	$	27.4	$	1.2
2027 through 2031	$	147.9	$	4.0

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Long-Term Incentive Plan (Tables)

12 Months Ended

Dec. 31, 2021

Share-based Payment Arrangement [Abstract]

Changes in Non-Vested Unit Awards

The amounts below do not include adjustments for above-target or below-target performance.

	Performance-Based Awards			Time-Based Awards			Total Awards
	Number of Unit Awards	Weighted Average Fair Value		Number of Unit Awards	Weighted Average Fair Value		Number of Unit Awards	Weighted Average Fair Value
Non-vested units - 1/1/2021	340,164	$	62.35	353,544	$	61.07	693,708	$	61.70
Units granted during 2021	281,823	$	40.85	301,873	$	40.99	583,696	$	40.92
Units vested during 2021	(161,484)	$	63.62	(168,204)	$	60.76	(329,688)	$	62.16
Units forfeited during 2021	(14,578)	$	51.23	(16,699)	$	50.92	(31,277)	$	51.06
Non-vested units - 12/31/21	445,925	$	48.66	470,514	$	48.67	916,439	$	48.67

Total Non-Vested Unit Awards

The table below summarizes the total non-vested unit awards outstanding, including estimated targeted financial performance adjustments, to determine our total equity-based liability accrual.

Grant Date	Non-Vested Unit Awards	Performance Adjustment to Unit Awards	Total Unit Award Accrual	Vesting Date	Unrecognized Compensation Expense (in millions)(a)
Performance-based awards:
2020 awards	171,400	(51,420)	119,980	12/31/2022	$	2.4
2021 awards	274,525	68,631	343,156	12/31/2023	9.3
Time-based awards:
2022 vesting date	178,911	—	178,911	12/31/2022	3.7
2023 vesting date	291,603	—	291,603	12/31/2023	8.3
Total	916,439	17,211	933,650		$	23.7

(a) Unrecognized compensation expense will be recognized over the remaining vesting period of the awards.

Weighted-Average Grant Date Fair Values

The weighted average fair value of awards granted during 2019, 2020 and 2021 was as follows:

	Performance-Based Awards			Time-Based Awards
	Number of Unit Awards	Weighted Average Fair Value		Number of Unit Awards	Weighted Average Fair Value
Units granted during 2019	182,834	$	63.65	195,031	$	62.91
Units granted during 2020	189,632	$	61.16	198,450	$	61.18
Units granted during 2021	281,823	$	40.85	301,873	$	40.99

Vested Unit Awards

The table below sets forth the numbers and values of units that vested in each of the three years ended December 31, 2021. The vested common units include adjustments for above-target financial and market performance.

Vesting Date	Vested Common Units	Fair Value of Unit Awards on Vesting Date (in millions)	Intrinsic Value of Unit Awards on Vesting Date (in millions)
12/31/2019	436,629	$31.0	$27.5
12/31/2020	235,127	$15.2	$10.0
12/31/2021	316,336	$19.3	$14.7

Cash Flow Effects of LTIP Settlements

The difference between the common units issued to the participants and the total number of unit awards vested primarily represents the tax withholdings associated with the award settlement, which we pay in cash.

Settlement Date	Number of Common Units Issued, Net of Tax Withholdings	Tax Withholdings and Other Cash Payments (in millions)	Employer Taxes (in millions)	Total Cash Payments (in millions)
January 2019	199,792	$9.8	$0.9	$10.7
January 2020	275,093	$14.7	$1.3	$16.0
January 2021	150,435	$6.2	$0.7	$6.9

Equity-Based Incentive Compensation Expense

Equity-based incentive compensation expense for 2019, 2020 and 2021, primarily recorded as G&A expense on our consolidated statements of income, was as follows (in millions):

	Year Ended December 31,
	2019		2020		2021
Performance awards	$	17.9	$	3.1	$	11.2
Time-based awards	$	6.1	$	8.9	$	10.6
Total	$	24.0	$	12.0	$	21.8

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Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Open Future Contracts

Our open futures contracts at December 31, 2021 were as follows:

Type of Contract/ Accounting Methodology	Product Represented by the Contract and Associated Barrels	Maturity Dates
Commodity derivatives contract - Economic hedges	3.3 million barrels of refined products and crude oil	Between January and November 2022
Commodity derivatives contract - Economic hedges	0.6 million barrels of gas liquids	Between January and April 2022

Schedule of Derivatives Offset Amounts

A schedule of the derivative amounts we have offset and the deposit amounts we could offset under master netting arrangements are provided below as of December 31, 2020 and 2021 (in millions):

Description	Gross Amounts of Recognized Liabilities		Gross Amounts of Assets Offset in the Consolidated Balance Sheets		Net Amounts of Liabilities Presented in the Consolidated Balance Sheets		Margin Deposit Amounts Not Offset in the Consolidated Balance Sheets		Net Asset Amount(1)
As of December 31, 2020	$	(21.7)	$	1.2	$	(20.5)	$	34.2	$	13.7
As of December 31, 2021	$	(22.3)	$	5.1	$	(17.2)	$	46.3	$	29.1

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

Schedule of Derivative Instruments, Effect on Other Comprehensive Income (Loss)

The changes in derivative activity included in AOCL for the years ended December 31, 2019, 2020 and 2021 were as follows (in millions):

	Year Ended December 31,
Derivative Losses Included in AOCL	2019		2020		2021
Beginning balance	$	(26.5)	$	(49.0)	$	(55.0)
Net loss on cash flow hedges	(25.2)		(9.5)		—
Reclassification of net loss on cash flow hedges to income	2.7		3.5		3.5
Ending balance	$	(49.0)	$	(55.0)	$	(51.5)

The following is a summary of the effect on our consolidated statements of income for the years ended December 31, 2019, 2020 and 2021 of derivatives that were designated as cash flow hedges (in millions):

	Interest Rate Contracts
	Amount of Loss Recognized in AOCL on  Derivatives			Location of Loss Reclassified from AOCL into Income	Amount of Loss Reclassified from AOCL into Income
Year Ended December 31, 2019		$	(25.2)	Interest expense		$	(2.7)
Year Ended December 31, 2020		$	(9.5)	Interest expense		$	(3.5)
Year Ended December 31, 2021		$	—	Interest expense		$	(3.5)

Schedule of Derivatives and Hedging-Overall-Subsequent Measurement

The following table provides a summary of the effect on our consolidated statements of income for the years ended December 31, 2019, 2020 and 2021 of derivatives that were not designated as hedging instruments (in millions):

		Amount of Gain (Loss) Recognized on Derivatives
		Year Ended December 31,
Derivative Instrument	Location of Gain (Loss) Recognized on Derivatives	2019		2020		2021
Commodity derivatives contracts	Product sales revenue	$	(66.5)	$	53.2	$	(143.2)
Commodity derivatives contracts	Cost of product sales	(0.2)		0.3		21.1
Basis derivative agreement	Other operating income (expense)	(10.2)		(4.3)		(5.6)
	Total	$	(76.9)	$	49.2	$	(127.7)

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

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, 2020 and 2021 (in millions):

	December 31, 2020
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity derivatives contracts	Commodity derivatives contracts, net	$	0.1	Commodity derivatives contracts, net	$	21.7
Commodity derivatives contracts	Other noncurrent assets	1.1		Other noncurrent liabilities	—
Basis derivative agreement	Other current assets	—		Other current liabilities	8.8
Basis derivative agreement	Other noncurrent assets	—		Other noncurrent liabilities	1.4
	Total	$	1.2	Total	$	31.9
	December 31, 2021
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity derivatives contracts	Commodity derivatives contracts, net	$	5.1	Commodity derivatives contracts, net	$	22.3
Basis derivative agreement	Other current assets	—		Other current liabilities	1.5
	Total	$	5.1	Total	$	23.8

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Fair Value Disclosures (Tables)

12 Months Ended

Dec. 31, 2021

Fair Value Disclosures [Abstract]

Fair Value Measurements, Recurring and Nonrecurring

The following tables summarize the carrying amounts, fair values and fair value measurements recorded or disclosed as of December 31, 2020 and 2021, based on the three levels established by ASC 820; Fair Value Measurements and Disclosures (in millions):

					Fair Value Measurements as of December 31, 2020 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)
Commodity derivatives contracts	$	(20.5)	$	(20.5)	$	(20.5)	$	—	$	—
Basis derivative agreement	$	(10.2)	$	(10.2)	$	—	$	(10.2)	$	—
Long-term receivables	$	22.8	$	22.8	$	—	$	—	$	22.8
Contractual obligations	$	(11.2)	$	(11.2)	$	—	$	—	$	(11.2)
Debt	$	(4,978.7)	$	(5,880.9)	$	—	$	(5,880.9)	$	—

					Fair Value Measurements as of December 31, 2021 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)
Commodity derivatives contracts	$	(17.2)	$	(17.2)	$	(18.6)	$	1.4	$	—
Basis derivative agreement	$	(1.5)	$	(1.5)	$	—	$	(1.5)	$	—
Long-term receivables	$	10.1	$	10.1	$	—	$	—	$	10.1
Contractual obligations	$	(9.8)	$	(9.8)	$	—	$	—	$	(9.8)
Debt	$	(5,088.8)	$	(5,711.5)	$	—	$	(5,711.5)	$	—

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Partners' Capital and Distributions (Tables)

12 Months Ended

Dec. 31, 2021

Partners' Capital Notes [Abstract]

Changes in Outstanding Limited Partner Units

The following table details the changes in the number of our common units outstanding from January 1, 2019 through December 31, 2021:

Common units outstanding on January 1, 2019	228,195,160
February 2019—Settlement of employee LTIP awards	199,792
During 2019—Other(1)	8,476
Common units outstanding on December 31, 2019	228,403,428
Units repurchased during 2020	(5,568,260)
February 2020—Settlement of employee LTIP awards	275,093
During 2020—Other(1)	9,550
Common units outstanding on December 31, 2020	223,119,811
Units repurchased during 2021	(10,894,828)
January 2021—Settlement of employee LTIP awards	150,435
During 2021—Other(1)	12,572
Common units outstanding on December 31, 2021	212,387,990

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

Distributions Made to Limited Partner

Distributions we paid during 2019, 2020 and 2021 were as follows (in millions, except per unit amounts):

Payment Date	Per Unit  Distribution Amount		Total Distribution
2/14/2019	$	0.9975	$	227.8
5/15/2019	1.0050		229.5
8/14/2019	1.0125		231.3
11/14/2019	1.0200		233.0
Total	$	4.0350	$	921.6
2/14/2020	$	1.0275	$	234.8
5/15/2020	1.0275		231.2
8/14/2020	1.0275		231.2
11/13/2020	1.0275		229.9
Total	$	4.1100	$	927.1
2/12/2021	$	1.0275	$	229.4
5/14/2021	1.0275		229.0
8/13/2021	1.0275		226.6
11/12/2021	1.0375		221.4
Total	$	4.1200	$	906.4

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Organization and Description of Business (Narrative) (Details) bbl in Millions	12 Months Ended
	Dec. 31, 2021 bbl terminal mi
Refined Products
Segment Reporting Information [Line Items]
Pipeline length | mi	9,800
Number of pipeline terminals | terminal	54
number of marine terminals | terminal	2
Number of marine terminals owned through joint venture | terminal	1
Crude Oil
Segment Reporting Information [Line Items]
Pipeline length | mi	2,200
Storage capacity	39
Contracted storage	29
Pipeline length - wholly owned | mi	1,000
Storage capacity - wholly owned	31
Contracted storage - wholly owned	25

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Summary of Significant Accounting Policies (Details) - Discontinued Operations, Held-for-sale - Independent Terminals Network bbl in Millions	Jun. 30, 2021 bbl terminal	Jun. 10, 2021 terminal bbl
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of independent terminals | terminal	26	26
Contracted storage | bbl	6	6

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Discontinued Operations and Assets Held for Sale (Narrative) (Details) bbl in Millions, $ in Millions		12 Months Ended
	Jun. 10, 2021 USD ($) terminal bbl	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Jun. 30, 2021 bbl terminal
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from disposition of assets		$ 275.1	$ 334.8	$ 65.4
Independent Terminals Network | Discontinued Operations, Held-for-sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of independent terminals | terminal	26				26
Contracted storage | bbl	6				6
Proceeds from disposition of assets	$ 435.0

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Discontinued Operations and Assets Held for Sale (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenue	$ 137.0	$ 105.6	$ 127.1
Costs and expenses:
Operating	11.2	13.4	17.9
Cost of product sales	66.5	45.5	58.5
Depreciation, amortization and impairment	7.1	15.6	15.4
General and administrative	2.5	2.2	2.5
Total costs and expenses	87.3	76.7	94.3
Income from discontinued operations	49.7	28.9	32.8
Assets:
Trade accounts receivable	6.3	5.6
Inventory	17.0	9.2
Net property, plant and equipment	272.0	274.9
Goodwill	2.7	2.7
Other assets	1.5	0.3
Total assets classified as held for sale	299.5	292.7
Liabilities:
Accounts payable	3.7	2.0
Accrued product liabilities	8.4	4.0
Other liabilities	3.7	3.9
Total liabilities classified as held for sale	15.8	9.9
Transportation and terminals revenue
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenue	53.3	51.4	56.8
Product sales revenue
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenue	$ 83.7	$ 54.2	$ 70.3

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Segment Disclosures (Segment Reporting Information by Segment) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Total revenue	$ 2,733.1	$ 2,322.0	$ 2,600.9
Operating expense	569.7	587.8	616.4
Cost of product sales	780.0	468.2	560.9
Other operating (income) expense	(2.8)	(0.1)	(3.0)
Earnings of non-controlled entities	(154.4)	(153.3)	(169.0)
Operating margin	1,540.6	1,419.4	1,595.6
Depreciation, amortization and impairment expense	227.9	243.1	230.7
G&A expense	206.3	171.2	194.2
Operating profit	1,106.4	1,005.1	1,170.7
Additions to long-lived assets	140.8	344.4	959.8
Total assets	8,030.0	8,197.0	8,437.7
Goodwill	50.1	50.1	50.6
Investments in non-controlled entities	980.8	1,213.9	1,240.6
Operating Segments
Segment Reporting Information [Line Items]
Additions to long-lived assets	130.0	333.9	859.3
Total assets	7,660.7	7,813.9	8,011.1
Operating Segments | Refined Products
Segment Reporting Information [Line Items]
Total revenue	2,108.8	1,721.1	1,943.2
Operating expense	416.7	411.8	454.0
Cost of product sales	630.1	425.8	532.8
Other operating (income) expense	(6.9)	(3.2)	(10.2)
Earnings of non-controlled entities	(34.4)	(32.5)	(8.1)
Operating margin	1,103.3	919.2	974.7
Depreciation, amortization and impairment expense	153.9	159.9	158.7
G&A expense	147.8	123.5	138.3
Operating profit	801.6	635.8	677.7
Additions to long-lived assets	88.9	277.5	785.1
Total assets	4,880.0	4,977.0	5,116.4
Goodwill	38.0	38.0	38.5
Investments in non-controlled entities	232.8	429.2	422.4
Operating Segments | Crude Oil
Segment Reporting Information [Line Items]
Total revenue	630.1	607.5	663.1
Operating expense	165.4	189.2	173.3
Cost of product sales	149.9	42.4	28.1
Other operating (income) expense	4.1	3.1	7.2
Earnings of non-controlled entities	(120.0)	(120.8)	(160.9)
Operating margin	430.7	493.6	615.4
Depreciation, amortization and impairment expense	67.4	76.6	66.5
G&A expense	58.5	47.7	55.9
Operating profit	304.8	369.3	493.0
Additions to long-lived assets	41.1	56.4	74.2
Total assets	2,780.7	2,836.9	2,894.7
Goodwill	12.1	12.1	12.1
Investments in non-controlled entities	748.0	784.7	818.2
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Total assets	69.8	90.4	131.1
Intersegment Eliminations
Segment Reporting Information [Line Items]
Total revenue	(5.8)	(6.6)	(5.4)
Operating expense	(12.4)	(13.2)	(10.9)
Cost of product sales	0.0	0.0	0.0
Other operating (income) expense	0.0	0.0	0.0
Earnings of non-controlled entities	0.0	0.0	0.0
Operating margin	6.6	6.6	5.5
Depreciation, amortization and impairment expense	6.6	6.6	5.5
G&A expense	0.0	0.0	0.0
Operating profit	0.0	0.0	0.0
Assets held for sale
Segment Reporting Information [Line Items]
Total assets	299.5	292.7	295.5
Transportation and terminals revenue
Segment Reporting Information [Line Items]
Total revenue	1,798.9	1,743.3	1,913.9
Transportation and terminals revenue | Operating Segments | Refined Products
Segment Reporting Information [Line Items]
Total revenue	1,338.5	1,190.4	1,299.0
Transportation and terminals revenue | Operating Segments | Crude Oil
Segment Reporting Information [Line Items]
Total revenue	466.2	559.5	620.3
Transportation and terminals revenue | Intersegment Eliminations
Segment Reporting Information [Line Items]
Total revenue	(5.8)	(6.6)	(5.4)
Product sales revenue
Segment Reporting Information [Line Items]
Total revenue	913.0	557.5	665.8
Product sales revenue | Operating Segments | Refined Products
Segment Reporting Information [Line Items]
Total revenue	763.9	524.4	637.5
Product sales revenue | Operating Segments | Crude Oil
Segment Reporting Information [Line Items]
Total revenue	149.1	33.1	28.3
Product sales revenue | Intersegment Eliminations
Segment Reporting Information [Line Items]
Total revenue	0.0	0.0	0.0
Affiliate management fee revenue
Segment Reporting Information [Line Items]
Total revenue	21.2	21.2	21.2
Affiliate management fee revenue | Operating Segments | Refined Products
Segment Reporting Information [Line Items]
Total revenue	6.4	6.3	6.7
Affiliate management fee revenue | Operating Segments | Crude Oil
Segment Reporting Information [Line Items]
Total revenue	14.8	14.9	14.5
Affiliate management fee revenue | Intersegment Eliminations
Segment Reporting Information [Line Items]
Total revenue	$ 0.0	$ 0.0	$ 0.0

XML

Revenue (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($)
Disaggregation of Revenue [Line Items]
Contract with customer, liability, change in timeframe, performance obligation satisfied, revenue recognized	$ 80.9
Refined Products
Disaggregation of Revenue [Line Items]
Revenue, shipments regulated by FERC, percentage	30.00%
Revenue, markets regulated by FERC, percentage	70.00%

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Revenue (Disaggregated Revenue) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Revenues	$ 2,733.1	$ 2,322.0	$ 2,600.9
Lease revenue	(96.1)	(100.4)	(101.1)
(Gains) losses from futures contracts included in product sales revenue	(143.2)	(53.2)	66.5
Affiliate management fee revenue	(21.2)	(21.2)	(21.2)
Total revenue from contracts with customers under ASC 606	2,472.6	2,147.2	2,545.1
Transportation and terminals revenue
Disaggregation of Revenue [Line Items]
Revenues	1,798.9	1,743.3	1,913.9
Product sales revenue
Disaggregation of Revenue [Line Items]
Revenues	913.0	557.5	665.8
Affiliate management fee revenue
Disaggregation of Revenue [Line Items]
Revenues	21.2	21.2	21.2
Transferred over Time | Transportation
Disaggregation of Revenue [Line Items]
Revenues	1,144.5	1,048.3	1,169.3
Transferred over Time | Terminalling
Disaggregation of Revenue [Line Items]
Revenues	117.1	131.1	157.7
Transferred over Time | Storage
Disaggregation of Revenue [Line Items]
Revenues	286.1	321.7	328.8
Transferred over Time | Ancillary services
Disaggregation of Revenue [Line Items]
Revenues	155.1	141.8	157.0
Transferred over Time | Lease revenue
Disaggregation of Revenue [Line Items]
Revenues	96.1	100.4	101.1
Transferred over Time | Transportation and terminals revenue
Disaggregation of Revenue [Line Items]
Revenues	1,798.9	1,743.3	1,913.9
Transferred at Point in Time | Product sales revenue
Disaggregation of Revenue [Line Items]
Revenues	913.0	557.5	665.8
Operating Segments | Refined Products
Disaggregation of Revenue [Line Items]
Revenues	2,108.8	1,721.1	1,943.2
Lease revenue	(20.4)	(23.7)	(27.9)
(Gains) losses from futures contracts included in product sales revenue	(127.2)	(56.8)	63.5
Affiliate management fee revenue	(6.4)	(6.3)	(6.7)
Total revenue from contracts with customers under ASC 606	1,954.8	1,634.3	1,972.1
Operating Segments | Refined Products | Transportation and terminals revenue
Disaggregation of Revenue [Line Items]
Revenues	1,338.5	1,190.4	1,299.0
Operating Segments | Refined Products | Product sales revenue
Disaggregation of Revenue [Line Items]
Revenues	763.9	524.4	637.5
Operating Segments | Refined Products | Affiliate management fee revenue
Disaggregation of Revenue [Line Items]
Revenues	6.4	6.3	6.7
Operating Segments | Refined Products | Transferred over Time | Transportation
Disaggregation of Revenue [Line Items]
Revenues	915.7	742.9	787.7
Operating Segments | Refined Products | Transferred over Time | Terminalling
Disaggregation of Revenue [Line Items]
Revenues	100.1	109.6	139.9
Operating Segments | Refined Products | Transferred over Time | Storage
Disaggregation of Revenue [Line Items]
Revenues	177.1	199.3	214.9
Operating Segments | Refined Products | Transferred over Time | Ancillary services
Disaggregation of Revenue [Line Items]
Revenues	125.2	114.9	128.6
Operating Segments | Refined Products | Transferred over Time | Lease revenue
Disaggregation of Revenue [Line Items]
Revenues	20.4	23.7	27.9
Operating Segments | Refined Products | Transferred over Time | Transportation and terminals revenue
Disaggregation of Revenue [Line Items]
Revenues	1,338.5	1,190.4	1,299.0
Operating Segments | Refined Products | Transferred at Point in Time | Product sales revenue
Disaggregation of Revenue [Line Items]
Revenues	763.9	524.4	637.5
Operating Segments | Crude Oil
Disaggregation of Revenue [Line Items]
Revenues	630.1	607.5	663.1
Lease revenue	(75.7)	(76.7)	(73.2)
(Gains) losses from futures contracts included in product sales revenue	(16.0)	3.6	3.0
Affiliate management fee revenue	(14.8)	(14.9)	(14.5)
Total revenue from contracts with customers under ASC 606	523.6	519.5	578.4
Operating Segments | Crude Oil | Transportation and terminals revenue
Disaggregation of Revenue [Line Items]
Revenues	466.2	559.5	620.3
Operating Segments | Crude Oil | Product sales revenue
Disaggregation of Revenue [Line Items]
Revenues	149.1	33.1	28.3
Operating Segments | Crude Oil | Affiliate management fee revenue
Disaggregation of Revenue [Line Items]
Revenues	14.8	14.9	14.5
Operating Segments | Crude Oil | Transferred over Time | Transportation
Disaggregation of Revenue [Line Items]
Revenues	228.8	305.4	381.6
Operating Segments | Crude Oil | Transferred over Time | Terminalling
Disaggregation of Revenue [Line Items]
Revenues	17.0	21.5	17.8
Operating Segments | Crude Oil | Transferred over Time | Storage
Disaggregation of Revenue [Line Items]
Revenues	114.8	129.0	119.3
Operating Segments | Crude Oil | Transferred over Time | Ancillary services
Disaggregation of Revenue [Line Items]
Revenues	29.9	26.9	28.4
Operating Segments | Crude Oil | Transferred over Time | Lease revenue
Disaggregation of Revenue [Line Items]
Revenues	75.7	76.7	73.2
Operating Segments | Crude Oil | Transferred over Time | Transportation and terminals revenue
Disaggregation of Revenue [Line Items]
Revenues	466.2	559.5	620.3
Operating Segments | Crude Oil | Transferred at Point in Time | Product sales revenue
Disaggregation of Revenue [Line Items]
Revenues	149.1	33.1	28.3
Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenues	(5.8)	(6.6)	(5.4)
Lease revenue	0.0	0.0	0.0
(Gains) losses from futures contracts included in product sales revenue	0.0	0.0	0.0
Affiliate management fee revenue	0.0	0.0	0.0
Total revenue from contracts with customers under ASC 606	(5.8)	(6.6)	(5.4)
Intersegment Eliminations | Transportation and terminals revenue
Disaggregation of Revenue [Line Items]
Revenues	(5.8)	(6.6)	(5.4)
Intersegment Eliminations | Product sales revenue
Disaggregation of Revenue [Line Items]
Revenues	0.0	0.0	0.0
Intersegment Eliminations | Affiliate management fee revenue
Disaggregation of Revenue [Line Items]
Revenues	0.0	0.0	0.0
Intersegment Eliminations | Transferred over Time | Transportation
Disaggregation of Revenue [Line Items]
Revenues	0.0	0.0	0.0
Intersegment Eliminations | Transferred over Time | Terminalling
Disaggregation of Revenue [Line Items]
Revenues	0.0	0.0	0.0
Intersegment Eliminations | Transferred over Time | Storage
Disaggregation of Revenue [Line Items]
Revenues	(5.8)	(6.6)	(5.4)
Intersegment Eliminations | Transferred over Time | Ancillary services
Disaggregation of Revenue [Line Items]
Revenues	0.0	0.0	0.0
Intersegment Eliminations | Transferred over Time | Lease revenue
Disaggregation of Revenue [Line Items]
Revenues	0.0	0.0	0.0
Intersegment Eliminations | Transferred over Time | Transportation and terminals revenue
Disaggregation of Revenue [Line Items]
Revenues	(5.8)	(6.6)	(5.4)
Intersegment Eliminations | Transferred at Point in Time | Product sales revenue
Disaggregation of Revenue [Line Items]
Revenues	$ 0.0	$ 0.0	$ 0.0

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Revenue (Contract Assets and Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Accounts receivable from contracts with customers	$ 134.8	$ 103.3
Contract assets	12.5	12.2
Contract liabilities	$ 100.1	$ 102.7

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Revenue (Remaining Performance Obligation) (Details) $ in Millions	Dec. 31, 2021 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, amount	$ 2,944.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining terms	12 months
Revenue, remaining performance obligation, amount	$ 626.3
Refined Products
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, amount	1,874.5
Refined Products | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, amount	368.9
Crude Oil
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, amount	1,069.8
Crude Oil | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, amount	$ 257.4
Minimum | Refined Products | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining terms	1 year
Minimum | Crude Oil | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining terms	1 year
Maximum | Refined Products | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining terms	17 years
Maximum | Crude Oil | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining terms	10 years

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Property, Plant and Equipment and Other Intangibles (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Interest costs threshold for capitalization construction in process	$ 0.5
Long-term debt, weighted average interest rate, over time	4.40%	4.40%	4.60%
Property, plant and equipment	$ 8,045.9	$ 7,943.8
Depreciation expense	$ 225.2	240.5	$ 227.5
Finite-lived intangible asset, useful life	16 years
Amortization of intangible assets	$ 2.7	2.7	$ 3.3
Other
Property, Plant and Equipment [Line Items]
Property, plant and equipment	261.2	280.2
Capitalized Interest | Other
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 98.7	$ 96.2
Minimum
Property, Plant and Equipment [Line Items]
Finite-lived intangible asset, useful life	7 years
Maximum
Property, Plant and Equipment [Line Items]
Finite-lived intangible asset, useful life	30 years

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Property, Plant and Equipment and Other Intangibles (Property, Plant and Equipment) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 8,045.9	$ 7,943.8
Construction work-in-progress
Property, Plant and Equipment [Line Items]
Property, plant and equipment	89.5	122.0
Land and rights-of-way
Property, Plant and Equipment [Line Items]
Property, plant and equipment	374.3	373.9
Buildings
Property, Plant and Equipment [Line Items]
Property, plant and equipment	121.8	119.7
Storage tanks
Property, Plant and Equipment [Line Items]
Property, plant and equipment	1,986.7	1,952.7
Pipeline and station equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment	3,386.0	3,325.9
Processing equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment	1,826.4	1,769.4
Other
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 261.2	$ 280.2
Minimum | Buildings
Property, Plant and Equipment [Line Items]
Estimated depreciable life, years	10 years
Minimum | Storage tanks
Property, Plant and Equipment [Line Items]
Estimated depreciable life, years	10 years
Minimum | Pipeline and station equipment
Property, Plant and Equipment [Line Items]
Estimated depreciable life, years	10 years
Minimum | Processing equipment
Property, Plant and Equipment [Line Items]
Estimated depreciable life, years	3 years
Minimum | Other
Property, Plant and Equipment [Line Items]
Estimated depreciable life, years	3 years
Maximum | Buildings
Property, Plant and Equipment [Line Items]
Estimated depreciable life, years	53 years
Maximum | Storage tanks
Property, Plant and Equipment [Line Items]
Estimated depreciable life, years	49 years
Maximum | Pipeline and station equipment
Property, Plant and Equipment [Line Items]
Estimated depreciable life, years	59 years
Maximum | Processing equipment
Property, Plant and Equipment [Line Items]
Estimated depreciable life, years	56 years
Maximum | Other
Property, Plant and Equipment [Line Items]
Estimated depreciable life, years	53 years

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Investments in Non-Controlled Entities (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Apr. 30, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	May 01, 2021
Schedule of Equity Method Investments [Line Items]
Equity method investments unamortized excess investment net		$ 32.0	$ 33.0
Proceeds from disposition of assets		275.1	334.8	$ 65.4
Gain on disposition of assets		75.0	12.9	29.0
Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Other revenues from transactions with related party		$ 2.5	$ 3.6	$ 5.3
MVP Terminalling, LLC (“MVP”)
Schedule of Equity Method Investments [Line Items]
Proceeds from disposition of assets	$ 272.1
Gain on disposition of assets	$ 70.4
Ownership interest		25.00%			25.00%
MVP Terminalling, LLC (“MVP”) | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Purchases from related party		$ 7.6

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Investments in Non-Controlled Entities (Equity Method Investments) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	May 01, 2021	Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]
Total revenue	$ 2,733.1	$ 2,322.0	$ 2,600.9
Operating expense	569.7	587.8	616.4
Other operating income (expense)	2.8	0.1	3.0
Trade Accounts Receivable	135.2	103.6
Other Accounts Receivable	34.6	37.1
Change in Equity Method Investments [Roll Forward]
Beginning balance	1,213.9	1,240.6
Additional investment	5.6
Sale of ownership interests	(199.8)
Proportionate share of earnings	156.2
Amortization of excess investment and capitalized interest	(1.8)
Earnings of non-controlled entities	154.4	153.3	169.0
Distributions from operations of non-controlled entities	193.3	207.6	203.6
Ending balance	980.8	1,213.9	1,240.6
Balance Sheet Information:
Current assets	843.2	405.1
Total assets	8,030.0	8,197.0	8,437.7
Current liabilities	679.6	558.6
Equity	1,899.8	2,303.8	2,715.0		$ 2,643.4
Income Statement Information:
Revenue	2,733.1	2,322.0	2,600.9
Equity Method Investments
Schedule of Equity Method Investments [Line Items]
Total revenue	733.1	752.7	782.0
Balance Sheet Information:
Current assets	227.0	243.8
Noncurrent assets	2,795.7	2,846.7
Total assets	3,022.7	3,090.5
Current liabilities	178.6	143.6
Noncurrent liabilities	59.5	57.5
Total liabilities	238.1	201.1
Equity	2,784.6	2,889.4
Income Statement Information:
Revenue	733.1	752.7	782.0
Net income	$ 463.4	471.4	507.5
BridgeTex Pipeline Company, LLC (“BridgeTex”)
Schedule of Equity Method Investments [Line Items]
Ownership Interest	30.00%
BridgeTex Pipeline Company, LLC (“BridgeTex”) | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Trade Accounts Receivable	$ 1.2	0.4
Other Accounts Receivable	0.0	0.0
Other Accounts Payable	0.3	1.0
Long-Term Receivables	$ 0.0	0.0
Double Eagle Pipeline LLC (“Double Eagle”)
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50.00%
Double Eagle Pipeline LLC (“Double Eagle”) | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Trade Accounts Receivable	$ 0.2	0.3
Other Accounts Receivable	0.0	0.0
Other Accounts Payable	0.0	0.0
Long-Term Receivables	$ 0.0	0.0
HoustonLink Pipeline Company, LLC (“HoustonLink”)
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50.00%
HoustonLink Pipeline Company, LLC (“HoustonLink”) | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Trade Accounts Receivable	$ 0.0	0.0
Other Accounts Receivable	0.0	0.0
Other Accounts Payable	0.2	0.1
Long-Term Receivables	$ 0.0	0.0
MVP Terminalling, LLC (“MVP”)
Schedule of Equity Method Investments [Line Items]
Ownership Interest	25.00%			25.00%
MVP Terminalling, LLC (“MVP”) | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Other operating income (expense)	$ 0.0	0.0	0.3
Trade Accounts Receivable	0.0	0.0
Other Accounts Receivable	0.6	0.5
Other Accounts Payable	2.2	2.3
Long-Term Receivables	$ 0.0	0.0
Powder Springs Logistics, LLC (“Powder Springs”)
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50.00%
Powder Springs Logistics, LLC (“Powder Springs”) | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Trade Accounts Receivable	$ 0.0	0.0
Other Accounts Receivable	0.0	0.0
Other Accounts Payable	0.0	0.0
Long-Term Receivables	$ 0.0	10.2
Saddlehorn Pipeline Company, LLC (“Saddlehorn”)
Schedule of Equity Method Investments [Line Items]
Ownership Interest	30.00%
Saddlehorn Pipeline Company, LLC (“Saddlehorn”) | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Trade Accounts Receivable	$ 0.0	0.0
Other Accounts Receivable	0.2	0.1
Other Accounts Payable	0.0	0.0
Long-Term Receivables	$ 0.0	0.0
Seabrook Logistics, LLC (“Seabrook”)
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50.00%
Seabrook Logistics, LLC (“Seabrook”) | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Operating expense	$ 19.7	29.1	25.9
Other operating income (expense)	0.4	1.4	0.0
Trade Accounts Receivable	0.0	0.0
Other Accounts Receivable	0.1	0.0
Other Accounts Payable	3.2	7.3
Long-Term Receivables	$ 0.0	0.0
Texas Frontera, LLC (“Texas Frontera”)
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50.00%
Transportation and terminals revenue
Schedule of Equity Method Investments [Line Items]
Total revenue	$ 1,798.9	1,743.3	1,913.9
Income Statement Information:
Revenue	1,798.9	1,743.3	1,913.9
Transportation and terminals revenue | BridgeTex Pipeline Company, LLC (“BridgeTex”) | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Total revenue	43.7	42.3	41.8
Income Statement Information:
Revenue	43.7	42.3	41.8
Transportation and terminals revenue | Double Eagle Pipeline LLC (“Double Eagle”) | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Total revenue	3.0	4.9	6.2
Income Statement Information:
Revenue	3.0	4.9	6.2
Transportation and terminals revenue | Saddlehorn Pipeline Company, LLC (“Saddlehorn”) | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Total revenue	2.3	2.5	2.2
Income Statement Information:
Revenue	2.3	2.5	2.2
Product sales revenue
Schedule of Equity Method Investments [Line Items]
Total revenue	913.0	557.5	665.8
Income Statement Information:
Revenue	913.0	557.5	665.8
Product sales revenue | Seabrook Logistics, LLC (“Seabrook”) | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Total revenue	0.0	0.0	0.3
Income Statement Information:
Revenue	$ 0.0	$ 0.0	$ 0.3

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Inventory (Inventory) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Inventory Disclosure [Abstract]
Refined products	$ 138.0	$ 72.0
Crude oil	25.4	32.4
Liquefied petroleum gases	42.0	25.0
Transmix	72.4	23.4
Additives	3.3	5.4
Total inventory	$ 281.1	$ 158.2

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Supplemental Cash Flows Information (Changes in Components of Operating Assets and Liabilities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Supplemental Cash Flow Information [Abstract]
Trade accounts receivable and other accounts receivable	$ (29.1)	$ (0.9)	$ (20.3)
Inventory	(122.9)	14.0	2.7
Accounts payable	16.0	4.5	(1.9)
Accrued payroll and benefits	22.8	(22.3)	4.8
Accrued interest payable	0.0	(5.3)	1.0
Accrued taxes other than income	8.8	4.4	12.6
Deferred revenue	(6.1)	(10.7)	(11.4)
Accrued product liabilities	78.3	(8.5)	15.9
Other current and noncurrent assets and liabilities	22.5	(12.3)	(1.3)
Changes in components of operating assets and liabilities	$ (9.7)	$ (37.1)	$ 2.1

XML

Supplemental Cash Flows Information (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Supplemental Cash Flow Information [Abstract]
Increase (decrease) in long-term pension and benefits liability	$ (16.3)	$ 21.5	$ 27.0

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Debt (Consolidated Debt) (Details) - USD ($)		Dec. 31, 2021	Dec. 31, 2020	May 31, 2020	Dec. 31, 2019	Aug. 31, 2019
Debt Instrument [Line Items]
Face value of long-term debt		$ 5,108,000,000	$ 5,000,000,000
Unamortized debt issuance costs	[1]	(37,800,000)	(40,100,000)
Net unamortized debt premium	[1]	18,600,000	18,800,000
Long-term debt, net		5,088,800,000	4,978,700,000
Commercial paper
Debt Instrument [Line Items]
Face value of long-term debt		$ 108,000,000.0	0
3.20% Notes due 2025
Debt Instrument [Line Items]
Interest rate		3.20%
Face value of long-term debt		$ 250,000,000.0	250,000,000.0
5.00% Notes due 2026
Debt Instrument [Line Items]
Interest rate		5.00%
Face value of long-term debt		$ 650,000,000.0	650,000,000.0
3.25% Notes due 2030
Debt Instrument [Line Items]
Interest rate		3.25%		3.25%
Face value of long-term debt		$ 500,000,000.0	500,000,000.0	$ 500,000,000
6.40% Notes due 2037
Debt Instrument [Line Items]
Interest rate		6.40%
Face value of long-term debt		$ 250,000,000.0	250,000,000.0
4.20% Notes due 2042
Debt Instrument [Line Items]
Interest rate		4.20%
Face value of long-term debt		$ 250,000,000.0	250,000,000.0
5.15% Notes due 2043
Debt Instrument [Line Items]
Interest rate		5.15%
Face value of long-term debt		$ 550,000,000.0	550,000,000.0
4.20% Notes due 2045
Debt Instrument [Line Items]
Interest rate		4.20%
Face value of long-term debt		$ 250,000,000.0	250,000,000.0
4.25% Notes due 2046
Debt Instrument [Line Items]
Interest rate		4.25%
Face value of long-term debt		$ 500,000,000.0	500,000,000.0
4.20% Notes due 2047
Debt Instrument [Line Items]
Interest rate		4.20%
Face value of long-term debt		$ 500,000,000.0	500,000,000.0
4.85% Notes due 2049
Debt Instrument [Line Items]
Interest rate		4.85%			4.85%
Face value of long-term debt		$ 500,000,000.0	500,000,000.0		$ 500,000,000
3.95% Notes due 2050
Debt Instrument [Line Items]
Interest rate		3.95%				3.95%
Face value of long-term debt		$ 800,000,000.0	$ 800,000,000.0			$ 500,000,000

[1] Debt issuance costs and note discounts and premiums are being amortized or accreted to the applicable notes over the respective lives of those notes.

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Debt (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Long-term Debt, Fiscal Year Maturity [Abstract]
2022	$ 0
2023	0
2024	0
2025	250,000,000
Thereafter	$ 4,750,000,000
Long-term debt, weighted average interest rate, over time	4.40%	4.40%	4.60%
Cash payments for interest	$ 221,600,000	$ 234,500,000	$ 217,100,000
Revolving Credit Facility
Long-term Debt, Fiscal Year Maturity [Abstract]
Maximum borrowing capacity	$ 1,000,000,000
Commitment fee percentage	0.125%
Borrowings outstanding	$ 0	0
Letter of credit obligations	$ 3,500,000	$ 3,500,000
Consolidated debt to EBITDA ratio	5.0
Revolving Credit Facility | Minimum
Long-term Debt, Fiscal Year Maturity [Abstract]
Basis spread on variable rate	0.875%
Commitment fee percentage	0.075%
Revolving Credit Facility | Maximum
Long-term Debt, Fiscal Year Maturity [Abstract]
Basis spread on variable rate	1.50%
Commitment fee percentage	0.20%
Commercial Paper
Long-term Debt, Fiscal Year Maturity [Abstract]
Maximum borrowing capacity	$ 1,000,000,000
Borrowings outstanding	$ 108,000,000
Long-term debt, weighted average interest rate, over time	0.20%	0.40%
Commercial Paper | Maximum
Long-term Debt, Fiscal Year Maturity [Abstract]
Term of contract	397 days

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Leases (Lessee, Operating Lease Liability, Maturity) (Details) $ in Millions	Dec. 31, 2021 USD ($)
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
2022	$ 31.1
2023	31.3
2024	31.4
2025	28.4
2026	19.1
Thereafter	51.7
Total future minimum rental payments	193.0
Present value discount	19.9
Total operating lease liability	173.1
Third Party Leases
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
2022	21.2
2023	21.4
2024	21.7
2025	21.8
2026	12.5
Thereafter	34.1
Total future minimum rental payments	132.7
Present value discount	12.1
Total operating lease liability	120.6
Seabrook Lease | Equity Method Investee | Seabrook Logistics, LLC (“Seabrook”)
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
2022	9.9
2023	9.9
2024	9.7
2025	6.6
2026	6.6
Thereafter	17.6
Total future minimum rental payments	60.3
Present value discount	7.8
Total operating lease liability	$ 52.5

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Leases (Lessee, Operating Lease, Disclosure) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Lessee, Lease, Description [Line Items]
Fixed lease expense	$ 33.7	$ 33.5	$ 30.0
Short-term lease expense	1.7	1.3	1.6
Variable lease expense	10.2	18.9	18.1
Total lease expense	45.6	53.7	49.7
Current lease liability	25.8	27.5
Long-term lease liability	147.3	137.5
Right-of-use asset	174.2	166.1
Operating cash flows for operating leases	$ 45.7	$ 53.2
Weighted average remaining lease term (years)	7 years	7 years
Weighted average discount rate	3.40%	3.80%
Third Party Leases
Lessee, Lease, Description [Line Items]
Fixed lease expense	$ 21.0	$ 19.2	19.2
Short-term lease expense	1.7	1.3	1.6
Variable lease expense	3.4	4.1	3.0
Total lease expense	26.1	24.6	23.8
Current lease liability	17.8	17.1
Long-term lease liability	102.8	85.0
Right-of-use asset	121.7	103.2
Operating cash flows for operating leases	$ 26.2	$ 24.1
Weighted average remaining lease term (years)	7 years	6 years
Weighted average discount rate	3.00%	3.70%
Seabrook Logistics, LLC (“Seabrook”) | Equity Method Investee | Seabrook Lease
Lessee, Lease, Description [Line Items]
Fixed lease expense	$ 12.7	$ 14.3	10.8
Short-term lease expense	0.0	0.0	0.0
Variable lease expense	6.8	14.8	15.0
Total lease expense	19.5	29.1	$ 25.8
Current lease liability	8.0	10.4
Long-term lease liability	44.5	52.5
Right-of-use asset	52.5	62.9
Operating cash flows for operating leases	$ 19.5	$ 29.1
Weighted average remaining lease term (years)	7 years	7 years
Weighted average discount rate	4.10%	4.00%

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Leases (Lessor, Future Minimum Payments Receivable) (Details) $ in Millions	Dec. 31, 2021 USD ($)
Lessor, Operating Lease, Payments, Fiscal Year Maturity [Abstract]
2022	$ 24.9
2023	25.2
2024	21.9
2025	13.8
2026	13.1
Thereafter	32.9
Total	$ 131.8

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Leases (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Variable lease revenue	$ 61.0	$ 61.4	$ 58.4
Processing equipment
Lessor, Lease, Description [Line Items]
Property, plant, and equipment, lessor asset under operating lease, after accumulated depreciation	216.9
Storage tanks
Lessor, Lease, Description [Line Items]
Property, plant, and equipment, lessor asset under operating lease, after accumulated depreciation	56.4
Pipeline and station equipment
Lessor, Lease, Description [Line Items]
Property, plant, and equipment, lessor asset under operating lease, after accumulated depreciation	47.5
Other
Lessor, Lease, Description [Line Items]
Property, plant, and equipment, lessor asset under operating lease, after accumulated depreciation	$ 29.0

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Leases (Investment in Direct Financing Lease) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Sales-type and Direct Financing Leases, Lease Receivables, Gross Difference, Amount [Abstract]
Total minimum lease payments receivable	$ 12.2	$ 14.0
Less: Unearned income	1.8	2.3
Recorded net investment in sales-type lease	10.4	11.7
Other accounts receivable	1.3	1.2
Long-term receivables	9.1	10.5
Total	10.4	$ 11.7
Sales-type and Direct Financing Leases, Lease Receivable, Fiscal Year Maturity [Abstract]
2022	1.7
2023	1.7
2024	1.7
2025	1.7
2026	1.7
Thereafter	$ 3.5

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Employee Benefit Plans (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($) plan	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Defined contribution plan, expenses	$ 10.6	$ 12.2	$ 11.4
Number of sponsored pension plans | plan	2
Number of sponsored pension plans, non-union employees | plan	1
Number of sponsored pension plans, union employees | plan	1
Health care cost trend rate assumed, next fiscal year	6.00%
Ultimate health care cost trend rate	5.08%
Fixed income securities
Defined Benefit Plan Disclosure [Line Items]
Target	70.00%	67.00%
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Target	30.00%	30.00%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Actuarial (gain) loss	$ 19.4	$ (53.2)
Contributions estimated to be paid	37.2
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Actuarial (gain) loss	(0.9)	$ (2.5)
Contributions estimated to be paid	$ 1.7

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Employee Benefit Plans (Changes in Benefit Obligations and Plan Assets) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Change in benefit obligations:
Benefit obligations at beginning of year	$ 443,600	$ 381,200
Service cost	28,200	27,700	$ 25,400
Interest cost	9,500	11,000	12,200
Plan participants’ contributions	0	0
Actuarial (gain) loss	(19,400)	53,200
Benefits paid	(29,200)	(23,100)
Curtailment gain	0	(1,700)
Settlement payments	(9,300)	(4,700)
Benefit obligations at end of year	423,400	443,600	381,200
Change in plan assets:
Fair value of plan assets at beginning of year	295,700	249,200
Employer contributions	27,600	29,300
Plan participants’ contributions	0	0
Actual return on plan assets	9,700	43,600
Benefits paid	(29,200)	(23,100)
Settlement payments	(9,300)	(3,300)
Fair value of plan assets at end of year	294,500	295,700	249,200
Funded status at end of year	(128,900)	(147,900)
Accumulated benefit obligations	305,000	324,800
Other Postretirement Benefits
Change in benefit obligations:
Benefit obligations at beginning of year	17,300	15,200
Service cost	300	300	200
Interest cost	400	500	500
Plan participants’ contributions	800	600
Actuarial (gain) loss	900	2,500
Benefits paid	(1,900)	(1,800)
Curtailment gain	0	0
Settlement payments	0	0
Benefit obligations at end of year	17,800	17,300	15,200
Change in plan assets:
Fair value of plan assets at beginning of year	0	0
Employer contributions	1,100	1,200
Plan participants’ contributions	800	600
Actual return on plan assets	0	0
Benefits paid	(1,900)	(1,800)
Settlement payments	0	0
Fair value of plan assets at end of year	0	0	$ 0
Funded status at end of year	$ (17,800)	$ (17,300)

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Employee Benefit Plans (Pension Plans with Obligations in Excess of Assets) (Details) - Pension Benefits - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$ 423,400	$ 443,600	$ 381,200
Fair value of plan assets	294,500	295,700	$ 249,200
Accumulated benefit obligation	$ 305,000	$ 324,800

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Employee Benefit Plans (Amounts Recognized in Consolidated Balance Sheets) (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Amounts recognized in consolidated balance sheets:
Long-term pension and benefits	$ 145,000	$ 163,800
Accumulated other comprehensive loss:
Accumulated other comprehensive loss	(155,000)	(183,200)
Pension Benefits
Amounts recognized in consolidated balance sheets:
Current accrued benefit cost	0	0
Long-term pension and benefits	128,900	147,900
Amounts recognized in consolidated balance sheets	128,900	147,900
Accumulated other comprehensive loss:
Net actuarial loss	(95,300)	(120,500)
Prior service credit	2,500	2,700
Accumulated other comprehensive loss	(92,800)	(117,800)
Net amount of liabilities and accumulated other comprehensive loss recognized in consolidated balance sheets	36,100	30,100
Other Postretirement Benefits
Amounts recognized in consolidated balance sheets:
Current accrued benefit cost	1,700	1,400
Long-term pension and benefits	16,100	15,900
Amounts recognized in consolidated balance sheets	17,800	17,300
Accumulated other comprehensive loss:
Net actuarial loss	(10,700)	(10,400)
Prior service credit	0	0
Accumulated other comprehensive loss	(10,700)	(10,400)
Net amount of liabilities and accumulated other comprehensive loss recognized in consolidated balance sheets	$ 7,100	$ 6,900

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Employee Benefit Plans (Consolidated Net Periodic Benefit Costs) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Components of net periodic pension and postretirement benefit expense:
Service cost	$ 28,200	$ 27,700	$ 25,400
Interest cost	9,500	11,000	12,200
Expected return on plan assets	(11,900)	(11,400)	(9,400)
Amortization of prior service credit	(200)	(200)	(200)
Amortization of actuarial loss	5,400	5,400	5,500
Settlement cost	2,600	1,000	2,600
Settlement gain on disposition of assets	0	(1,300)	0
Net periodic benefit cost	33,600	32,200	36,100
Other Postretirement Benefits
Components of net periodic pension and postretirement benefit expense:
Service cost	300	300	200
Interest cost	400	500	500
Expected return on plan assets	0	0	0
Amortization of prior service credit	0	0	0
Amortization of actuarial loss	600	400	300
Settlement cost	0	0	0
Settlement gain on disposition of assets	0	0	0
Net periodic benefit cost	$ 1,300	$ 1,200	$ 1,000

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Employee Benefit Plans (Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Changes in AOCL [Roll Forward]
Beginning balance	$ 2,303,800	$ 2,715,000	$ 2,643,400
Net actuarial gain (loss)	16,300	(23,500)	(27,300)
Recognition of prior service credit amortization in income	(200)	(200)	(200)
Recognition of actuarial loss amortization in income	6,000	5,900	5,800
Curtailment gain	0	1,700	0
Settlement cost	2,600	1,000	2,600
Total other comprehensive income (loss)	28,200	(21,100)	(41,600)
Ending balance	1,899,800	2,303,800	2,715,000
Pension Benefits
Changes in AOCL [Roll Forward]
Beginning balance	(117,800)	(104,700)	(88,600)
Net actuarial gain (loss)	17,200	(21,000)	(24,000)
Recognition of prior service credit amortization in income	(200)	(200)	(200)
Recognition of actuarial loss amortization in income	5,400	5,400	5,500
Curtailment gain	0	1,700	0
Settlement cost	2,600	1,000	2,600
Total other comprehensive income (loss)	25,000	(13,100)	(16,100)
Ending balance	(92,800)	(117,800)	(104,700)
Other Postretirement Benefits
Changes in AOCL [Roll Forward]
Beginning balance	(10,400)	(8,400)	(5,400)
Net actuarial gain (loss)	(900)	(2,500)	(3,300)
Recognition of prior service credit amortization in income	0	0	0
Recognition of actuarial loss amortization in income	600	500	300
Curtailment gain	0	0	0
Settlement cost	0	0	0
Total other comprehensive income (loss)	(300)	(2,000)	(3,000)
Ending balance	$ (10,700)	$ (10,400)	$ (8,400)

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Employee Benefit Plans (Weighted-Average Rate Assumptions Used) (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	2.61%	2.23%
Rate of compensation increase	6.51%	4.53%
Cash balance interest crediting rate	1.94%	1.70%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate	2.23%	3.01%	3.98%
Rate of compensation increase	4.53%	4.58%	6.48%
Expected rate of return on plan assets	4.10%	4.50%	6.00%
Cash balance interest crediting rate	1.70%	2.16%	2.78%
Other Postretirement Benefits
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	2.64%	2.30%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate	2.30%	3.06%	4.08%

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Employee Benefit Plans (Fair Value of Pension Plan Assets) (Details) - Pension Benefits - USD ($) $ in Thousands		Dec. 31, 2021		Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		$ 294,500		$ 295,700	$ 249,200
Quoted Prices in Active  Markets for Identical Assets (Level 1)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		294,300		295,500
Significant Observable Inputs (Level 2)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0		0
Significant Unobservable Inputs (Level 3)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		200		200
Small-cap fund
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]	6,100		5,800
Small-cap fund | Quoted Prices in Active  Markets for Identical Assets (Level 1)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]	6,100		5,800
Small-cap fund | Significant Observable Inputs (Level 2)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0		0
Small-cap fund | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0		0
Mid-cap fund
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]	6,000		5,800
Mid-cap fund | Quoted Prices in Active  Markets for Identical Assets (Level 1)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]	6,000		5,800
Mid-cap fund | Significant Observable Inputs (Level 2)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0		0
Mid-cap fund | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0		0
Large-cap fund
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]	48,000		47,600
Large-cap fund | Quoted Prices in Active  Markets for Identical Assets (Level 1)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]	48,000		47,600
Large-cap fund | Significant Observable Inputs (Level 2)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0		0
Large-cap fund | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0		0
International equity fund
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		30,100	[1]	29,900
International equity fund | Quoted Prices in Active  Markets for Identical Assets (Level 1)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		30,100	[1]	29,900
International equity fund | Significant Observable Inputs (Level 2)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0		0
International equity fund | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0		0
Short-term bond fund
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]			4,200
Short-term bond fund | Quoted Prices in Active  Markets for Identical Assets (Level 1)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]			4,200
Short-term bond fund | Significant Observable Inputs (Level 2)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets				0
Short-term bond fund | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets				0
Intermediate-term bond fund
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]			34,900
Intermediate-term bond fund | Quoted Prices in Active  Markets for Identical Assets (Level 1)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]			34,900
Intermediate-term bond fund | Significant Observable Inputs (Level 2)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets				0
Intermediate-term bond fund | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets				0
Long-term investment grade bond funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]	197,100		161,000
Long-term investment grade bond funds | Quoted Prices in Active  Markets for Identical Assets (Level 1)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]	197,100		161,000
Long-term investment grade bond funds | Significant Observable Inputs (Level 2)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0		0
Long-term investment grade bond funds | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0		0
Short-term investment fund
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		7,000		6,300
Short-term investment fund | Quoted Prices in Active  Markets for Identical Assets (Level 1)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		7,000		6,300
Short-term investment fund | Significant Observable Inputs (Level 2)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0		0
Short-term investment fund | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0		0
Group annuity contract
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		200		200
Group annuity contract | Quoted Prices in Active  Markets for Identical Assets (Level 1)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0		0
Group annuity contract | Significant Observable Inputs (Level 2)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0		0
Group annuity contract | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		$ 200		$ 200

[1] We hold equity and fixed income securities through investments in mutual funds, which are dedicated to each category as indicated.

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Employee Benefit Plans (Target Allocation and Actual Weighted-Average Asset Allocation of Plan Assets) (Details)	Dec. 31, 2021	Dec. 31, 2020
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Actual	30.00%	30.00%
Target	30.00%	30.00%
Fixed income securities
Defined Benefit Plan Disclosure [Line Items]
Actual	67.00%	68.00%
Target	70.00%	67.00%
Other
Defined Benefit Plan Disclosure [Line Items]
Actual	3.00%	2.00%
Target	0.00%	3.00%

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Employee Benefit Plans (Expected Benefit Payments) (Details) $ in Thousands	Dec. 31, 2021 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2022	$ 16,200
2023	18,100
2024	21,600
2025	22,400
2026	27,400
2027 through 2031	147,900
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2022	1,700
2023	1,500
2024	1,300
2025	1,300
2026	1,200
2027 through 2031	$ 4,000

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Long-Term Incentive Plan (Narrative) (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2021	Apr. 30, 2021	Mar. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Limited partners' capital account, units issued (in units)		13.7	11.9
Limited partner unitholders, units remaining available (in shares)	2.4
Performance-Based Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award payout percentage, minimum	0.00%
Award payout percentage, maximum	200.00%
Award forfeiture period	2 years
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period	3 years
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period	4 years

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Long-Term Incentive Plan (Changes in Non-Vested Unit Awards) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Number of Unit Awards
Beginning balance (in shares)	693,708
Units granted during 2021 (in shares)	583,696
Units vested during 2021 (in shares)	(329,688)
Units forfeited during 2021 (in shares)	(31,277)
Ending balance (in shares)	916,439	693,708
Weighted Average Fair Value
Beginning balance (in dollars per share)	$ 61.70
Units granted during 2021 (in dollars per share)	40.92
Units vested during 2021 (in dollars per share)	62.16
Units forfeited during 2021 (in dollars per share)	51.06
Ending balance (in dollars per share)	$ 48.67	$ 61.70
Performance-Based Awards
Number of Unit Awards
Beginning balance (in shares)	340,164
Units granted during 2021 (in shares)	281,823	189,632	182,834
Units vested during 2021 (in shares)	(161,484)
Units forfeited during 2021 (in shares)	(14,578)
Ending balance (in shares)	445,925	340,164
Weighted Average Fair Value
Beginning balance (in dollars per share)	$ 62.35
Units granted during 2021 (in dollars per share)	40.85	$ 61.16	$ 63.65
Units vested during 2021 (in dollars per share)	63.62
Units forfeited during 2021 (in dollars per share)	51.23
Ending balance (in dollars per share)	$ 48.66	$ 62.35
Time-Based Awards
Number of Unit Awards
Beginning balance (in shares)	353,544
Units granted during 2021 (in shares)	301,873	198,450	195,031
Units vested during 2021 (in shares)	(168,204)
Units forfeited during 2021 (in shares)	(16,699)
Ending balance (in shares)	470,514	353,544
Weighted Average Fair Value
Beginning balance (in dollars per share)	$ 61.07
Units granted during 2021 (in dollars per share)	40.99	$ 61.18	$ 62.91
Units vested during 2021 (in dollars per share)	60.76
Units forfeited during 2021 (in dollars per share)	50.92
Ending balance (in dollars per share)	$ 48.67	$ 61.07

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Long-Term Incentive Plan (Total Non-Vested Unit Awards) (Details) - USD ($) $ in Millions		Dec. 31, 2021	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-Vested Unit Awards (in shares)		916,439	693,708
Performance Adjustment to Unit Awards (in shares)		17,211
Total Unit Award Accrual (in shares)		933,650
Unrecognized Compensation Expense	[1]	$ 23.7
Performance-Based Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-Vested Unit Awards (in shares)		445,925	340,164
Time-Based Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-Vested Unit Awards (in shares)		470,514	353,544
Time-Based Awards | 2022 vesting date
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-Vested Unit Awards (in shares)		178,911
Performance Adjustment to Unit Awards (in shares)		0
Total Unit Award Accrual (in shares)		178,911
Unrecognized Compensation Expense	[1]	$ 3.7
Time-Based Awards | 2023 vesting date
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-Vested Unit Awards (in shares)		291,603
Performance Adjustment to Unit Awards (in shares)		0
Total Unit Award Accrual (in shares)		291,603
Unrecognized Compensation Expense	[1]	$ 8.3
2020 awards | Performance-Based Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-Vested Unit Awards (in shares)		171,400
Performance Adjustment to Unit Awards (in shares)		(51,420)
Total Unit Award Accrual (in shares)		119,980
Unrecognized Compensation Expense	[1]	$ 2.4
2021 awards | Performance-Based Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-Vested Unit Awards (in shares)		274,525
Performance Adjustment to Unit Awards (in shares)		68,631
Total Unit Award Accrual (in shares)		343,156
Unrecognized Compensation Expense	[1]	$ 9.3

[1] Unrecognized compensation expense will be recognized over the remaining vesting period of the awards.

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Long-Term Incentive Plan (Weighted-Average Grant Date Fair Values) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Units Awarded (in shares)	583,696
Weighted-Average Fair Value (in dollars per share)	$ 40.92
Performance-Based Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Units Awarded (in shares)	281,823	189,632	182,834
Weighted-Average Fair Value (in dollars per share)	$ 40.85	$ 61.16	$ 63.65
Time-Based Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Units Awarded (in shares)	301,873	198,450	195,031
Weighted-Average Fair Value (in dollars per share)	$ 40.99	$ 61.18	$ 62.91

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Long-Term Incentive Plan (Vested Unit Awards) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Vested Common Units (in shares)	316,336	235,127	436,629
Fair Value of Unit Awards on Vesting Date	$ 19.3	$ 15.2	$ 31.0
Intrinsic Value of Unit Awards on Vesting Date	$ 14.7	$ 10.0	$ 27.5

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Long-Term Incentive Plan (Cash Flow Effects of LTIP Settlements) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Number of Common Units Issued, Net of Tax Withholdings (in shares)	150,435	275,093	199,792
Tax Withholdings and Other Cash Payments	$ 6.2	$ 14.7	$ 9.8
Employer Taxes	0.7	1.3	0.9
Total Cash Payments	$ 6.9	$ 16.0	$ 10.7

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Long-Term Incentive Plan (Equity-Based Incentive Compensation Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based incentive compensation expense	$ 21.8	$ 12.0	$ 24.0
Performance-Based Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based incentive compensation expense	11.2	3.1	17.9
Time-Based Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based incentive compensation expense	$ 10.6	$ 8.9	$ 6.1

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Derivative Financial Instruments (Narrative) (Details)	1 Months Ended			12 Months Ended
	Dec. 31, 2020 USD ($)	May 31, 2020 USD ($)	Aug. 31, 2019 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($) bbl
Derivative [Line Items]
Face value of long-term debt	$ 5,000,000,000			$ 5,108,000,000	$ 5,000,000,000
Net payment on financial derivatives				0	9,500,000	$ 33,300,000
Commodity derivatives deposits	34,200,000			46,300,000	34,200,000
Derivative liability	20,500,000			17,200,000	20,500,000
Loss to be reclassified within twelve months				3,500,000
3.95% Notes due 2050
Derivative [Line Items]
Face value of long-term debt	$ 300,000,000				$ 300,000,000
Interest rate	3.95%				3.95%
Net payment on financial derivatives	$ (1,000,000)
3.25% Notes due 2030
Derivative [Line Items]
Face value of long-term debt	500,000,000.0	$ 500,000,000		$ 500,000,000.0	$ 500,000,000.0
Interest rate		3.25%		3.25%
Net payment on financial derivatives		$ 10,400,000
3.95% Notes due 2050
Derivative [Line Items]
Face value of long-term debt	800,000,000.0		$ 500,000,000	$ 800,000,000.0	800,000,000.0
Interest rate			3.95%	3.95%
Net payment on financial derivatives			$ 25,300,000
4.85% Notes due 2049
Derivative [Line Items]
Face value of long-term debt	500,000,000.0			$ 500,000,000.0	500,000,000.0	$ 500,000,000
Interest rate				4.85%		4.85%
Net payment on financial derivatives						$ 8,000,000
Basis derivative agreement
Derivative [Line Items]
Nonmonetary notional amount | bbl						30,000
Derivative liability	$ 10,200,000			$ 1,500,000	$ 10,200,000

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Derivative Financial Instruments (Schedule of Open Future Contracts) (Details) - Economic Hedges bbl in Millions	Dec. 31, 2021 bbl
Future Contract One
Derivative [Line Items]
Nonmonetary notional amount	3.3
Future Contract Two
Derivative [Line Items]
Nonmonetary notional amount	0.6

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Derivative Financial Instruments (Schedule of Derivative Offset Amounts) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Gross Amounts of Recognized Liabilities	$ (22.3)	$ (21.7)
Gross Amounts of Assets Offset in the Consolidated Balance Sheets	5.1	1.2
Derivative Liability, Total	17.2	20.5
Margin Deposit Amounts Not Offset in the Consolidated Balance Sheets	46.3	34.2
Net Amount Offset	$ 29.1	$ 13.7

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Derivative Financial Instruments (Amounts Included in AOCL) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Losses Included in AOCL
Beginning balance	$ 2,303.8	$ 2,715.0	$ 2,643.4
Net loss on cash flow hedges	0.0	(9.5)	(25.2)
Reclassification of net loss on cash flow hedges to income	3.5	3.5	2.7
Ending balance	1,899.8	2,303.8	2,715.0
Derivative Losses Included in AOCL
Derivative Losses Included in AOCL
Beginning balance	(55.0)	(49.0)	(26.5)
Ending balance	$ (51.5)	$ (55.0)	$ (49.0)

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Derivative Financial Instruments (Derivatives and Hedging-Cash Flow Hedges) (Details) - Interest Rate Contract - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Loss Recognized in AOCL on  Derivatives	$ 0.0	$ (9.5)	$ (25.2)
Interest expense
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Loss Reclassified from AOCL into Income	$ (3.5)	$ (3.5)	$ (2.7)

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Derivative Financial Instruments (Derivatives and Hedging-Overall-Subsequent Measurement) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized on Derivatives	$ (127.7)	$ 49.2	$ (76.9)
Product sales revenue | Commodity derivatives contracts
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized on Derivatives	(143.2)	53.2	(66.5)
Cost of product sales | Commodity derivatives contracts
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized on Derivatives	21.1	0.3	(0.2)
Other operating income (expense) | Basis derivative agreement
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized on Derivatives	$ (5.6)	$ (4.3)	$ (10.2)

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Derivative Financial Instruments (Derivatives and Hedging-Designated) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Derivatives, Fair Value [Line Items]
Asset Derivatives, Fair Value	$ 5.1	$ 1.2
Liability Derivatives, Fair Value	22.3	21.7
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Asset Derivatives, Fair Value	5.1	1.2
Liability Derivatives, Fair Value	23.8	31.9
Not Designated as Hedging Instrument | Commodity derivatives contracts | Other noncurrent assets
Derivatives, Fair Value [Line Items]
Asset Derivatives, Fair Value		1.1
Not Designated as Hedging Instrument | Commodity derivatives contracts | Other noncurrent liabilities
Derivatives, Fair Value [Line Items]
Liability Derivatives, Fair Value		0.0
Not Designated as Hedging Instrument | Commodity derivatives contracts | Energy Marketing Contracts Assets, Current
Derivatives, Fair Value [Line Items]
Asset Derivatives, Fair Value	5.1	0.1
Liability Derivatives, Fair Value	22.3	21.7
Not Designated as Hedging Instrument | Basis derivative agreement | Other noncurrent assets
Derivatives, Fair Value [Line Items]
Asset Derivatives, Fair Value		0.0
Not Designated as Hedging Instrument | Basis derivative agreement | Other current assets
Derivatives, Fair Value [Line Items]
Asset Derivatives, Fair Value	0.0	0.0
Not Designated as Hedging Instrument | Basis derivative agreement | Other noncurrent liabilities
Derivatives, Fair Value [Line Items]
Liability Derivatives, Fair Value		1.4
Not Designated as Hedging Instrument | Basis derivative agreement | Other current liabilities
Derivatives, Fair Value [Line Items]
Liability Derivatives, Fair Value	$ 1.5	$ 8.8

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Fair Value Disclosures (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($) terminal	Dec. 31, 2021 USD ($)	Dec. 31, 2019 bbl
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Number of marine terminals sold | terminal	3
Derivative liability	$ (20.5)	$ (17.2)
Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term receivables	0.0	0.0
Contractual obligations	0.0	0.0
Debt	0.0	0.0
Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term receivables	0.0	0.0
Contractual obligations	0.0	0.0
Debt	(5,880.9)	(5,711.5)
Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term receivables	22.8	10.1
Contractual obligations	(11.2)	(9.8)
Debt	0.0	0.0
Commodity derivatives contracts | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liability	(20.5)	(18.6)
Commodity derivatives contracts | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liability	0.0	1.4
Commodity derivatives contracts | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liability	0.0	0.0
Basis derivative agreement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nonmonetary notional amount | bbl			30,000
Derivative liability	(10.2)	(1.5)
Basis derivative agreement | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liability	0.0	0.0
Basis derivative agreement | Significant Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liability	(10.2)	(1.5)
Basis derivative agreement | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liability	0.0	0.0
Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term receivables	22.8	10.1
Contractual obligations	(11.2)	(9.8)
Debt	(4,978.7)	(5,088.8)
Carrying Amount | Commodity derivatives contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liability	(20.5)	(17.2)
Carrying Amount | Basis derivative agreement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liability	(10.2)	(1.5)
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term receivables	22.8	10.1
Contractual obligations	(11.2)	(9.8)
Debt	(5,880.9)	(5,711.5)
Fair Value | Commodity derivatives contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liability	(20.5)	(17.2)
Fair Value | Basis derivative agreement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liability	$ (10.2)	$ (1.5)

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Commitments and Contingencies (Details) $ in Millions		12 Months Ended
	Dec. 06, 2021 USD ($) patent facility	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($) terminal	Dec. 31, 2019 USD ($)	Oct. 04, 2017 facility
Loss Contingencies [Line Items]
Accrual for environmental loss contingencies		$ 9.8	$ 13.5
Environmental remediation expense		$ 3.2	$ 3.4	$ 3.8
Number of marine terminals sold | terminal			3
Powder Springs Logistics, LLC (“Powder Springs”)
Loss Contingencies [Line Items]
Ownership interest		50.00%
Guarantee of Indebtedness of Others | Equity Method Investee | Powder Springs Logistics, LLC (“Powder Springs”)
Loss Contingencies [Line Items]
Contractual obligations		$ 0.4	$ 0.4
Ownership interest		50.00%
Guarantor obligations, maximum exposure, undiscounted		$ 25.0
Other current liabilities | Performance Guarantee
Loss Contingencies [Line Items]
Contractual obligations		0.5	0.6
Other noncurrent liabilities | Performance Guarantee
Loss Contingencies [Line Items]
Contractual obligations		$ 8.9	$ 10.2
Unfavorable Regulatory Action | Settled Litigation | Sunoco v.s. Magellan
Loss Contingencies [Line Items]
Alleged patent infringement, number of facilities | facility					8
Patents found infringed, number | patent	3
Damages awarded, value	$ 9.4
Patents found infringed, number of facilities | facility	8
Unfavorable Regulatory Action | Settled Litigation | Powder Springs Logistics, LLC (“Powder Springs”) | Sunoco v.s. Magellan
Loss Contingencies [Line Items]
Patents found infringed, number | patent	1
Damages awarded, value	$ 2.8

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Concentration of Risks (Details) - employee	Jan. 31, 2022	Dec. 31, 2021
Concentration Risk [Line Items]
Number of employees		1,715
Number of Employees, Total | Unionized Employees Concentration Risk | Subsequent Event
Concentration Risk [Line Items]
Concentration risk, percentage	13.00%
Corporate, Non-Segment
Concentration Risk [Line Items]
Number of employees		526
Refined Products | Operating Segments
Concentration Risk [Line Items]
Number of employees		854
Number of employees subject to sales agreement		82
Crude Oil | Operating Segments
Concentration Risk [Line Items]
Number of employees		253

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Related Party Transactions (Narrative) (Details) - Director - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Methvin Company
Related Party Transaction [Line Items]
Other revenues from transactions with related party	$ 65.2	$ 37.4	$ 29.6
Accounts receivable, related parties, current	5.4	3.9
Methvin Company 2
Related Party Transaction [Line Items]
Other revenues from transactions with related party	$ 0.3	$ 0.5

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Partners' Capital and Distributions (Changes in Limited Partner Units Outstanding) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021		Dec. 31, 2020		Dec. 31, 2019
Capital Unit [Line Items]
Stock repurchase program, authorized amount (up to)	$ 1,500,000,000
Limited Partners' Capital Account [Roll Forward]
Common units outstanding, beginning balance (in shares)	223,119,811		228,403,428		228,195,160
Units repurchased (in shares)	(10,894,828)		(5,568,260)
Units issued (in shares)	150,435		275,093		199,792
Common units outstanding, ending balance (in shares)	212,387,990		223,119,811		228,403,428
Right to receive distribution in cash, period	45 days
Removal of general partner, percentage vote required	100.00%
Annual report available, period	120 days
Tax reporting information, period	90 days
Management
Limited Partners' Capital Account [Roll Forward]
Units issued (in shares)	150,435		275,093	[1]	199,792
Director
Limited Partners' Capital Account [Roll Forward]
Units issued (in shares)	12,572	[1]	9,550		8,476	[1]

[1] issued to settle the equity-based retainer paid to independent directors of our general partner.

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Partners' Capital and Distributions (Distributions Made to Limited Partner) (Details) - USD ($) $ / shares in Units, $ in Millions													12 Months Ended
	Nov. 12, 2021	Aug. 13, 2021	May 14, 2021	Feb. 12, 2021	Nov. 13, 2020	Aug. 14, 2020	May 15, 2020	Feb. 14, 2020	Nov. 14, 2019	Aug. 14, 2019	May 15, 2019	Feb. 14, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Partners' Capital Notes [Abstract]
Per Unit Distribution Amount (in dollars per share)	$ 1.0375	$ 1.0275	$ 1.0275	$ 1.0275	$ 1.0275	$ 1.0275	$ 1.0275	$ 1.0275	$ 1.0200	$ 1.0125	$ 1.0050	$ 0.9975	$ 4.1200	$ 4.1100	$ 4.0350
Total Distribution	$ 221.4	$ 226.6	$ 229.0	$ 229.4	$ 229.9	$ 231.2	$ 231.2	$ 234.8	$ 233.0	$ 231.3	$ 229.5	$ 227.8	$ 906.4	$ 927.1	$ 921.6

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Subsequent Events (Details)	Jan. 31, 2022 h	Feb. 13, 2022 $ / shares	Dec. 31, 2021 $ / shares	Nov. 12, 2021 $ / shares	Aug. 13, 2021 $ / shares	May 14, 2021 $ / shares	Feb. 12, 2021 $ / shares	Dec. 31, 2020 $ / shares	Nov. 13, 2020 $ / shares	Aug. 14, 2020 $ / shares	May 15, 2020 $ / shares	Feb. 14, 2020 $ / shares	Dec. 31, 2019 $ / shares	Nov. 14, 2019 $ / shares	Aug. 14, 2019 $ / shares	May 15, 2019 $ / shares	Feb. 14, 2019 $ / shares
Subsequent Event [Line Items]
Per unit distribution amount (in dollars per share)			$ 4.1200	$ 1.0375	$ 1.0275	$ 1.0275	$ 1.0275	$ 4.1100	$ 1.0275	$ 1.0275	$ 1.0275	$ 1.0275	$ 4.0350	$ 1.0200	$ 1.0125	$ 1.0050	$ 0.9975
Subsequent Event
Subsequent Event [Line Items]
Collective bargaining agreement, rolling extension term | h	24
Per unit distribution amount (in dollars per share)		$ 1.0375
Subsequent Event | Number of Employees, Total | Unionized Employees Concentration Risk
Subsequent Event [Line Items]
Concentration risk, percentage	13.00%