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, 2022
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, 2022 was $9,911,874,513.
As of February 20, 2023, there were 203,293,822 common units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s Proxy Statement prepared for the solicitation of proxies in connection with the 2023 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. | |||||||||||
| ITEM 1A. | |||||||||||
| ITEM 1B. | |||||||||||
| ITEM 2. | |||||||||||
| ITEM 3. | |||||||||||
| ITEM 4. | |||||||||||
| PART II | |||||||||||
| ITEM 5. | |||||||||||
| ITEM 7. | |||||||||||
| ITEM 7A. | |||||||||||
| ITEM 8. | |||||||||||
| ITEM 9. | |||||||||||
| ITEM 9A. | |||||||||||
| ITEM 9B. | |||||||||||
| PART III | |||||||||||
| ITEM 10. | |||||||||||
| ITEM 11. | |||||||||||
| ITEM 12. | |||||||||||
| ITEM 13. | |||||||||||
| ITEM 14. | |||||||||||
| PART IV | |||||||||||
| ITEM 15. | |||||||||||
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,” “changes,” “continue,” “could,” “decline,” “decrease,” “depend,” “develop,” “estimates,” “expects,” “exposed” “forecasts,” “future,” “goal,” “guidance,” “have,” “impact,” “implement,” “increase,” “intends,” “lead,” “maintain,” “may,” “might,” “plans,” “potential,” “possible,” “projected,” “reduce,” “remain,” “result,” “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 discussed in this report:
•changes in demand for refined products, crude oil or liquefied petroleum gases (“LPGs”);
•price fluctuations for refined products, crude oil or LPGs and expectations about future prices for these products;
•changes in the production of crude oil in the basins served by our pipelines or terminals;
•changes in general economic conditions, including inflation or recession;
•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, including but not limited to electric and battery-powered motors, natural gas, hydrogen and renewable fuels such as ethanol, biodiesel and other products not typically transported via pipeline, as well as increased conservation or fuel efficiency and regulatory or technological developments that 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 services due to geopolitical events, conflicts, or the activities of the Organization of the Petroleum Exporting Countries (“OPEC”) and other non-OPEC oil producing countries with large production capacity;
•changes in United States (“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 (“FERC”) or state regulatory agencies;
•shut-downs or cutbacks at refineries, oil fields, petrochemical plants or other customers or businesses that use or supply our assets or 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 we encounter, including the effects of capacity over-build in the areas where we operate;
•the occurrence of wars, conflicts, 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 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 blending activities or changes regarding product quality specifications or renewable fuel obligations that impact our ability to produce petroleum products through our 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 subject, including those related to tax withholding requirements, reporting, 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; 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 2022, we completed the sale of our independent terminals network comprised of 26 refined petroleum products terminals in the southeastern U.S. to Buckeye Partners, L.P. (“Buckeye”) for $446.2 million, including final working capital adjustments. The related results of operations, financial position and cash flows were classified as discontinued operations for all periods presented (See Note 3 – Discontinued Operations for additional details). 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, 2022, our asset portfolio 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;
•LPGs are liquids produced as by-products of the crude oil refining process and in connection with crude oil and natural gas production. LPGs include gas liquids such as butane, natural gasoline and propane;
•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, biodiesel and renewable diesel.
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 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, | ||||||||||||||||||||
| 2020 | 2021 | 2022 | ||||||||||||||||||
| Percent of consolidated revenue | 74% | 77% | 81% | |||||||||||||||||
| Percent of consolidated operating margin | 65% | 72% | 71% | |||||||||||||||||
| Percent of consolidated total assets | 61% | 61% | 63% | |||||||||||||||||
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 2022, 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 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 delivery of the gross 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.
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In 2022, the products transported on our refined products pipeline system were comprised of 57% gasoline, 37% 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, and in connection with commodity activities including gas liquids blending and fractionation. 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 98% of the total product margin for the refined products segment during 2022.
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 $98.6 million, $133.8 million and $152.9 million for the years ended December 31, 2020, 2021 and 2022, 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, also known as 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.
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 fueling stations, convenience stores, travel centers, railroads, airports and other end users.
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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, consumer preferences, economic conditions, population changes, government regulations, changes in vehicle fuel efficiency and development of alternative energy sources. The 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. Industry and government forecasts project petroleum products to remain essential for decades to come.
In 2022, 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 | Rosemount, MN | |||||||
| HF Sinclair | El Dorado, KS | |||||||
| HF Sinclair | Tulsa, OK | |||||||
| HF Sinclair | Evansville, WY | |||||||
| Marathon | St. Paul, MN | |||||||
| Marathon | El Paso, TX | |||||||
| Marathon | Galveston Bay, TX | |||||||
| Par Pacific | Newcastle, WY | |||||||
| Phillips 66 | Ponca City, OK | |||||||
| 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 | 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 | ||||||||||||
| Koch | Waco, TX | Corpus Christi, TX refinery | ||||||||||||
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 those products are typically transported by railroad, truck or barge to terminal facilities and 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 capability to move certain 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 2022, 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, 2022. 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, 2022, 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, 2022 represented 34% of total revenue for our refined products segment and 61% of revenue excluding product sales.
Customers of our marine terminals include refiners, marketers and traders. As of December 31, 2022, approximately 60% 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 annual renewal options. The weighted average remaining life of our marine storage contracts was approximately two years as of December 31, 2022. 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, | ||||||||||||||||||||
| 2020 | 2021 | 2022 | ||||||||||||||||||
| Percent of consolidated revenue | 26% | 23% | 19% | |||||||||||||||||
| Percent of consolidated operating margin | 35% | 28% | 28% | |||||||||||||||||
| Percent of consolidated total assets | 35% | 35% | 36% | |||||||||||||||||
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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 terminalling and ancillary services. We typically 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 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 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 are 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, which is primarily used for contract storage. 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 petroleum products to optimize utilization and profitability of our crude oil assets, including our pipelines and storage facilities. Earnings from these activities are generally derived from differentials in market prices based on factors including time, location and product quality specifications.
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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. For details regarding the impairment of our Double Eagle joint venture investment see Note 15 – Fair Value.
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.
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 distribution systems in the Houston area based primarily on rates, connectivity to supply sources and demand centers, customer service, crude quality and customer relationships.
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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 our customers’ interest in storing or trading 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. Spot barrel movements on our pipelines generally ship at higher rates than those charged to committed shippers. Generally, we seek to secure 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, 2022, approximately 80% 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, 2022, approximately 75% of our crude oil storage available for contract was under agreements with terms in excess of one year or subject to annual renewal options. The weighted average remaining life of our storage contracts was approximately three years as of December 31, 2022. 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, 2022, approximately 65% of the capacity of the BridgeTex pipeline was subject to commitments with a weighted average remaining life of three years. At December 31, 2022, approximately 80% of the capacity of the Saddlehorn pipeline was subject to commitments with a weighted average remaining life of four years. Additionally, we have a tolling agreement with one customer for the exclusive use of our condensate splitter in Corpus Christi, the term of which expires at the end of 2024.
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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 blending, fractionation and 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 provides for annual changes in rates by a percentage equal to the change in the producer price index for finished goods (“PPI-FG”) minus 0.21%. 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 generally 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”). RINs are generated when a gallon of renewable fuel is produced and may be separated when the renewable fuel is blended into gasoline or diesel fuel, at which point the RIN is available for use in compliance or available for sale on the open market. 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
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of renewable fuel 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.
Fuel Compliance. We are subject to the EPA’s fuels compliance regulations. These regulations include standards for fuel parameters and require rigorous product sampling and testing, recordkeeping and reporting. Our ongoing compliance with these regulations is not expected to have a material adverse effect on our business.
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) be at least 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, 2020, 2021 and 2022, 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, cybersecurity and physical security. 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 effect on our results of operations, financial position or cash flow.
Liabilities recognized for estimated environmental costs were $9.8 million and $10.2 million at December 31, 2021 and 2022, 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.
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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.
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 crude oil, refined products or renewable fuels, 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. These regulations continue to expand and are also amenable to non-governmental organizations (i.e., environmental groups, private citizens, property owners, tribal entities and other groups) using them to oppose our operations, renewal of existing air permits, as well as obtaining new or modified air permits. We anticipate incurring capital expenditures in the future for air pollution control and monitoring equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. At this time, we believe that our business will not be materially adversely affected by such requirements.
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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 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 (“DOT”) 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. During 2022, PHMSA published expanded regulations for the installation of rupture mitigation valves and the establishment of a minimum rupture detection standard. 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 DOT through PHMSA.
States are largely preempted by federal law from regulating pipeline safety for interstate lines, but most states are certified by the DOT 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
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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 cybersecurity and physical security regulations. Some of our assets are regulated by the DOT, the EPA, the U.S. Coast Guard and the Department of Homeland Security (“DHS”). Compliance with these regulations is achieved by creating cybersecurity and physical security plans, 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 easements or permits 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, covenants related to environmental contamination, liens for current taxes and other burdens, easements, restrictions and other encumbrances to which the underlying properties were subject 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, 2022, we had 1,655 employees, primarily concentrated in the central U.S. There were 855 employees assigned to our refined products segment, 248 employees assigned to our crude oil segment and 552 employees assigned to provide general & administrative (“G&A”) services. Approximately 13% of our employees are represented by the United Steelworkers and covered by a collective bargaining agreement that expires in January 2026.
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.
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Investing in employee training and development is crucial to retaining skilled talent and developing our employees into subject matter experts and leaders who solve challenges, fuel innovation and move our business strategy 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 (“SEC”). The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, at www.sec.gov.
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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, each of which could have a material adverse effect on our business. As used throughout this report, “effect on our business” includes, among other things, effects on our financial condition, results of operations and 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 petroleum products 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.
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;
•Non-traditional 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 close.
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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 business.
Cyberattacks, terrorism and other external threats
•Cyberattacks and terrorist attacks could result in increased costs or other damage to our business;
•The occurrence of epidemics and government responses thereto may adversely affect our business.
Regulatory risks
•We and 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 increased costs and 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 regarding emissions of greenhouse gases could result in increased operating costs and reduced demand for our services and 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 requires the recruitment and retention of a skilled workforce, and difficulties attracting and retaining talent could result in a failure to efficiently operate our business and execute our strategies;
•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 for 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 an adverse impact on the volume of petroleum-based fuels transported, stored or distributed by 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 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 or fees, 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 oil 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 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 and storage capacity that significantly exceeds market demands. 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 oil 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 and storage 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 blending, fractionation and petroleum products marketing activities, as well as product generated by the operations of our pipelines and terminals. We also maintain product inventories related to these activities. The hedging arrangements we enter into to hedge our exposure to commodity price changes may be for the purchase or sale of product in markets or on time frames different from those in which we are attempting to hedge, resulting in hedges that do not eliminate all price risks. Significant fluctuations in market prices of petroleum products could result in material unrealized gains or losses on our hedge transactions. 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 adverse fluctuations in our results of operations. In addition, significant fluctuation in market prices of petroleum products could require us to post material amounts of margin and result in adverse 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 losses or lower profits.
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 or declines in petroleum product 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.
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The volume of petroleum products 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 petroleum between our origin points and our 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, it may be 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. 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.
Non-traditional 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.
Recently, investor advocacy groups, certain institutional investors and many investment funds have increased their focus on non-traditional investment criteria, such as environmental, social and governance (“ESG”) goals. 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 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 could 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. 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,
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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 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 fossil 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 satisfy our 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 returns from those projects.
We have numerous joint ventures that we do not control and that requires cooperation with and performance by co-owners. Noncooperation by our joint venture co-owners could result in increased costs, delays or business decisions that are not in our best interests, which 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 safely and efficiently deliver the expected services on a timely basis at the prices we expect and as required by contract could result in significant disruptions, costs or instances of 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 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 and maintenance 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 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. Our revenues are impacted by changes in price levels, and we use the FERC’s PPI-based price indexing methodology to establish tariff rates in certain markets served by our pipelines. In periods of price deflation, the ceiling level provided by the FERC’s index methodology could decrease, requiring us to
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reduce our index-based rates, even if the actual costs we incur to operate our assets increase. In periods of inflation, our revenues may not keep pace with costs necessary to operate and maintain our assets, and we may be prevented from increasing our rates consistent with changes to the PPI-FG and our competitors. Changes in price levels that lead to decreases in our revenues or increases in the prices we pay to operate and maintain our assets could adversely affect our business.
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 close.
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 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, 2022, 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 impasses that could result in an adverse effect on that joint venture’s business, and, therefore, 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 could adversely affect our business.
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Our operations are subject to many hazards inherent in the transportation, storage and distribution of petroleum products, including releases and fires. In addition, our operations are exposed to potential heightened risks from natural disasters, including hurricanes, tornadoes, storms, floods and earthquakes. The risk of natural disasters and other operational risks could result in personal injury or loss of life, damage to and destruction of property and equipment, 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 (“HCAs”) such as residential and 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 business, and the insurance we carry requires that we meet certain deductibles before we can receive reimbursement 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 adversely impact our ability to operate our assets or manage our business.
We utilize information technology systems to operate our assets and manage our business. 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 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 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.
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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 otherwise adversely affect our business.
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 an adverse effect on our business. Similarly, any terrorist attack that severely disrupts the markets we serve could adversely affect our business.
The occurrence of epidemics and government responses thereto may adversely affect our business.
The occurrence of epidemics and the related government responses, as experienced with COVID-19, could result in significant declines in economic activity around the world and reduced demand for petroleum products. It is difficult to predict the occurrence or impact of new outbreaks and the government responses thereto on economic activity or our operations, any of which could adversely affect our business.
Regulatory risks
We 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 could result in increased costs and 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 DOT 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, material handling procedures and other requirements. 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 releases, 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. 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
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become applicable to us. For instance, in 2022 the Transportation Security Administration released additional pipeline 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 2022, PHMSA published expanded hazardous liquid pipeline regulations for the installation of rupture mitigation valves and establishment of a minimum rupture detection standard. Compliance with 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 largely dependent on production techniques, such as hydraulic fracturing, that have been scrutinized by governmental authorities and have encountered political opposition which 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 increase rates by amounts sufficient to reflect our actual cost or may delay the use of rates that reflect increased costs. We use the FERC’s indexing 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. When the change in the ceiling level is negative, we are required to reduce our rates that are subject to the FERC’s 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 long-haul 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 and could result in tariff reductions, which would adversely affect our business.
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Climate change legislation or regulations regarding emissions of greenhouse gases could result in increased operating costs and reduced demand for our services and 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 likely 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, such as the Securities and Exchange Commission’s proposed rules to Enhance and Standardize Climate-Related Disclosures for Investors, they could also increase our costs to operate and maintain our facilities by, for example, requiring that we measure and report our emissions, install new emission controls at 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, many 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 a renewable volume obligation (“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. 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 transport, store, distribute or sell.
Petroleum products that we transport and store 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 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 would 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 duration. We may not be able to utilize the right of
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eminent 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. Further, certain benefits to our unitholders provided by current law could expire or otherwise change. For example, the 20% federal pass-through deduction enacted as part of the Tax Cuts and Jobs Act, which is generally available for ordinary income allocated to investors of publicly traded partnerships or recognized upon the sale of publicly traded partnership units, will expire at the end of 2025, barring further legislative action. 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 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.
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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 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.
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Cash distributions paid to foreign persons will be reduced by withholding taxes at the highest applicable effective U.S. 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 allocated to them. Upon the sale, exchange or other disposition of a common unit of a publicly traded partnership 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. Beginning in 2023, the IRS has clarified the broker is generally responsible for withholding 10% of the gross proceeds upon sale of an investment in a publicly traded partnership by a foreign investor. Distributions to foreign persons may also be subject to additional withholding of 10% 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.
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 16 states, most of which impose a personal income tax.
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, in which case our cash available for distribution to our unitholders might be substantially reduced.
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 requires the recruitment and retention of a skilled workforce, and difficulties attracting and retaining talent could result in a failure to efficiently operate our business and execute our strategies.
Our operations and management require the recruitment and retention of a skilled workforce, including engineers, technical personnel and other professionals. We compete with other companies both within and outside the energy industry for this skilled workforce. Successfully competing for talented employees necessary to operate our business may result in increased costs, which could adversely affect our business.
As our employees, including much of our management team, reach retirement age and elect to retire, we may lose valuable skills and institutional knowledge that have been developed over many years of service. If we are unable to transfer knowledge successfully to new employees or are otherwise unable to recruit and retain talented personnel, we could experience increased costs or we could encounter other difficulties in running our business efficiently.
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Our business could be affected adversely by union disputes and strikes or work stoppages by our unionized employees.
As of December 31, 2022, approximately 13% of our workforce was represented by the United Steelworkers and covered by a collective bargaining agreement expiring January 2026. 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.
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 and Powder Springs Logistics, LLC (“Powder Springs”) were infringing patents relating to butane blending. A trial concluded on December 6, 2021, at which the jury found Magellan and Powder Springs willfully infringed those patents. Based on the jury’s award and post-trial proceedings, the total amount awarded to Sunoco is approximately $22.9 million, plus post-judgment interest that continues to accrue. Sunoco and defendants, Magellan and Powder Springs, have appealed the final judgment of the trial court. The amounts we have accrued in relation to the claims represent our best estimate of probable damages, and although it is not possible to predict the ultimate outcome, we do not expect the final resolution of this matter to have a material adverse effect on our business.
Corpus Christi Terminal Personal Injury Proceeding. Ismael Garcia, Andrew Ramirez, and Jesus Juarez Quintero, et al. brought personal injury cases against Magellan and co-defendants Triton Industrial Services, LLC, Tidal Tank, Inc. and Cleveland Integrity Services, Inc. in Nueces County Court in Texas. The claims were originally brought in three different actions but were consolidated into a single case on March 2, 2021. Claims were asserted by or on behalf of seven individuals, and certain beneficiaries, who were employed by a contractor of Magellan and were injured, one fatally, as a result of a fire that occurred on December 5, 2020 while they were cleaning a tank at our Corpus Christi terminal. The plaintiffs are seeking damages of an undetermined amount. While the outcome cannot be predicted, we do not expect the final resolution of this matter to 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 20, 2023, we had 203,293,822 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 $1.0475 per common unit and are targeting annual distribution growth of 1% for 2023.
Our board has authorized the repurchase of up to $1.5 billion of our common units through 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 may be suspended or discontinued at any time.
The table below reflects our common units repurchased through December 31, 2022 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 | ||||||||||||||||||||
| Year Ended 2021 | 10,894,828 | $ | 48.01 | 10,894,828 | $ | 700.0 | ||||||||||||||||||||
| January 1-31, 2022 | — | — | — | $ | 700.0 | |||||||||||||||||||||
| February 1-28, 2022 | 430,670 | $ | 47.87 | 430,670 | $ | 679.4 | ||||||||||||||||||||
| March 1-31, 2022 | 611,365 | $ | 48.06 | 611,365 | $ | 650.0 | ||||||||||||||||||||
| First Quarter 2022 | 1,042,035 | $ | 47.98 | 1,042,035 | ||||||||||||||||||||||
| April 1-30, 2022 | — | $ | — | — | $ | 650.0 | ||||||||||||||||||||
| May 1-31, 2022 | 1,038,564 | $ | 48.15 | 1,038,564 | $ | 600.0 | ||||||||||||||||||||
| June 1-30, 2022 | 2,847,492 | $ | 49.03 | 2,847,492 | $ | 460.4 | ||||||||||||||||||||
| Second Quarter 2022 | 3,886,056 | $ | 48.79 | 3,886,056 | ||||||||||||||||||||||
| July 1-31, 2022 | — | $ | — | — | $ | 460.4 | ||||||||||||||||||||
| August 1-31, 2022 | 1,794,372 | $ | 50.96 | 1,794,372 | $ | 368.9 | ||||||||||||||||||||
| September 1-30, 2022 | 953,799 | $ | 48.38 | 953,799 | $ | 322.8 | ||||||||||||||||||||
| Third Quarter 2022 | 2,748,171 | $ | 50.06 | 2,748,171 | ||||||||||||||||||||||
| October 1-31, 2022 | — | — | — | $ | 322.8 | |||||||||||||||||||||
| November 1-30, 2022 | 76,057 | $ | 52.61 | 76,057 | $ | 318.8 | ||||||||||||||||||||
| December 1-31, 2022 | 1,826,183 | $ | 49.88 | 1,826,183 | $ | 227.7 | ||||||||||||||||||||
| Fourth Quarter 2022 | 1,902,240 | $ | 49.99 | 1,902,240 | ||||||||||||||||||||||
| Year Ended 2022 | 9,578,502 | $ | 49.31 | 9,578,502 | ||||||||||||||||||||||
| Total Inception-to-Date | 26,041,590 | $ | 48.86 | 26,041,590 | ||||||||||||||||||||||
(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 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, 2017 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.
| 12/31/2017 | 12/31/2018 | 12/31/2019 | 12/31/2020 | 12/31/2021 | 12/31/2022 | |||||||||||||||||||||||||||||||||
| MMP | $100 | $85 | $100 | $74 | $89 | $104 | ||||||||||||||||||||||||||||||||
| AMZI | $100 | $88 | $94 | $64 | $91 | $119 | ||||||||||||||||||||||||||||||||
| S&P 500 | $100 | $96 | $126 | $149 | $192 | $157 | ||||||||||||||||||||||||||||||||
| S&P 500 Energy | $100 | $82 | $92 | $61 | $94 | $155 | ||||||||||||||||||||||||||||||||
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, 2022, our asset portfolio 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, 2022.
See Item 1. Business for a detailed description of our business.
Overview
Fueling Prosperity and Security. World events over the past year have reinforced the criticality of the energy industry to our country and the world. We are well positioned to continue to responsibly provide the essential fuels such as gasoline, diesel fuel and jet fuel that our communities and economy rely on daily.
Dynamic energy markets provide both challenges and opportunities. We own the longest refined products pipeline in the country and can access nearly 50% of the nation’s refining capacity. During 2022, we shipped record refined products volumes as customers took advantage of our network’s extensive connectivity to overcome various supply disruptions in the markets we serve.
Creating and Returning Value to Investors. Our resilient business model continues to provide strong cash flow to consistently pay distributions. We recognize that investors value steady increases to the cash distribution and currently target annual distribution growth of 1% for 2023. We expect to continue to generate free cash flow after paying distributions to allocate in a manner that creates value for our investors.
We continue to pursue investment opportunities that meet our disciplined financial requirements. For example, we have completed a number of small, bolt-on projects over the past year, including recent pipeline expansions to New Mexico and Colorado. Additionally, during 2022, we launched an expansion of our refined products pipeline to El Paso, Texas, which will connect more supply to growing markets in Texas, Arizona and Mexico and is supported by commitments from high-quality counterparties.
While we expect to continue finding opportunities to invest in new projects, attractive opportunities have been more limited over the last few years. This more limited capital investment environment, along with the fact that we believe the value of our equity has not reflected the economic potential of our company, has allowed us to simply invest in ourselves by repurchasing equity.
Through our equity repurchase program, we have reduced the number of our outstanding units by 11% over the last three years, providing meaningful growth in earnings and distributable cash flow on a per unit basis.
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We believe the combination of investing in good projects as they are available, opportunistically repurchasing units and providing an attractive current cash distribution is a strategy that will allow us to continue creating meaningful value for our investors.
In total, we delivered over $1.3 billion to our investors in 2022 via opportunistic equity repurchases and our attractive cash distribution.
Our Role in Energy Transition. We will remain an important part of a successful energy transition. The services we provide are vital to ensuring our communities and economies function while the U.S. and the world pursue a transition from fossil fuels. Supported by industry and government forecasts, we believe demand for the fuels we deliver will remain steady for the foreseeable future and essential for many more decades, and likely beyond.
Continuing to operate our business in a safe and responsible manner is a fundamental priority. We also believe that we must continue to optimize our business and adapt to future realities. However, we expect energy transition is likely to take longer and be more dynamic than many may currently predict.
For any transition to be truly successful, all of the costs and benefits must be weighed to seek a balance among policy objectives, technological capability and market acceptance in order to make sustainable progress.
Recent Developments
Sale of Independent Terminals Network. On June 8, 2022, we completed the sale of our independent terminals network comprised of 26 refined petroleum products terminals in the southeastern U.S. to Buckeye Partners, L.P. for $446.2 million, including final working capital adjustments.
Impairment of Double Eagle Investment. In December 2022, as a result of the non-renewal on existing terms of customer commitments that expire in 2023 and reduced demand for transportation of condensate from the Eagle Ford basin, we recognized an impairment in our Double Eagle joint venture investment of $58.4 million.
Distribution. In January 2023, our board declared a quarterly distribution of $1.0475 per unit for the period of October 1, 2022 through December 31, 2022. This quarterly distribution was paid on February 14, 2023 to unitholders of record on February 7, 2023.
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 U.S. 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 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 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, 2021 Compared to Year Ended December 31, 2022
| Year Ended December 31, | Variance Favorable (Unfavorable) | |||||||||||||||||||||||||
| 2021 | 2022 | $ Change | % Change | |||||||||||||||||||||||
| Financial Highlights ($ in millions, except operating statistics) | ||||||||||||||||||||||||||
| Transportation and terminals revenue: | ||||||||||||||||||||||||||
| Refined products | $ | 1,338.5 | $ | 1,408.2 | $ | 69.7 | 5 | |||||||||||||||||||
| Crude oil | 466.2 | 473.7 | 7.5 | 2 | ||||||||||||||||||||||
| Intersegment eliminations | (5.8) | (6.1) | (0.3) | (5) | ||||||||||||||||||||||
| Total transportation and terminals revenue | 1,798.9 | 1,875.8 | 76.9 | 4 | ||||||||||||||||||||||
| Affiliate management fee revenue | 21.2 | 22.2 | 1.0 | 5 | ||||||||||||||||||||||
| Operating expenses: | ||||||||||||||||||||||||||
| Refined products | 416.7 | 431.5 | (14.8) | (4) | ||||||||||||||||||||||
| Crude oil | 165.4 | 173.6 | (8.2) | (5) | ||||||||||||||||||||||
| Intersegment eliminations | (12.4) | (13.0) | 0.6 | 5 | ||||||||||||||||||||||
| Total operating expenses | 569.7 | 592.1 | (22.4) | (4) | ||||||||||||||||||||||
| Product margin: | ||||||||||||||||||||||||||
| Product sales revenue | 913.0 | 1,302.4 | 389.4 | 43 | ||||||||||||||||||||||
| Cost of product sales | 780.0 | 1,119.4 | (339.4) | (44) | ||||||||||||||||||||||
| Product margin | 133.0 | 183.0 | 50.0 | 38 | ||||||||||||||||||||||
| Other operating income (expense) | 2.8 | 5.3 | 2.5 | 89 | ||||||||||||||||||||||
| Earnings of non-controlled entities | 154.4 | 147.4 | (7.0) | (5) | ||||||||||||||||||||||
| Operating margin | 1,540.6 | 1,641.6 | 101.0 | 7 | ||||||||||||||||||||||
| Depreciation, amortization and impairment expense | 227.9 | 292.8 | (64.9) | (28) | ||||||||||||||||||||||
| G&A expense | 206.3 | 240.7 | (34.4) | (17) | ||||||||||||||||||||||
| Operating profit | 1,106.4 | 1,108.1 | 1.7 | — | ||||||||||||||||||||||
Interest expense (net of interest income and interest capitalized) | 225.9 | 226.8 | (0.9) | — | ||||||||||||||||||||||
| Gain on disposition of assets | (75.0) | (0.9) | (74.1) | (99) | ||||||||||||||||||||||
| Other (income) expense | 20.9 | 20.3 | 0.6 | 3 | ||||||||||||||||||||||
| Income from continuing operations before provision for income taxes | 934.6 | 861.9 | (72.7) | (8) | ||||||||||||||||||||||
| Provision for income taxes | 2.3 | 2.7 | (0.4) | (17) | ||||||||||||||||||||||
| Income from continuing operations | 932.3 | 859.2 | (73.1) | (8) | ||||||||||||||||||||||
| Income from discontinued operations (including gain on disposition of assets of $164.0 million in 2022) | 49.7 | 177.2 | 127.5 | 257 | ||||||||||||||||||||||
| Net income | $ | 982.0 | $ | 1,036.4 | $ | 54.4 | 6 | |||||||||||||||||||
| Operating Statistics | ||||||||||||||||||||||||||
| Refined products: | ||||||||||||||||||||||||||
| Transportation revenue per barrel shipped | $ | 1.715 | $ | 1.781 | ||||||||||||||||||||||
Volume shipped (million barrels): | ||||||||||||||||||||||||||
| Gasoline | 303.8 | 319.9 | ||||||||||||||||||||||||
| Distillates | 205.6 | 206.1 | ||||||||||||||||||||||||
| Aviation fuel | 30.5 | 33.3 | ||||||||||||||||||||||||
| Liquefied petroleum gases | 0.9 | 0.6 | ||||||||||||||||||||||||
| Total volume shipped | 540.8 | 559.9 | ||||||||||||||||||||||||
| Crude oil: | ||||||||||||||||||||||||||
| Magellan 100%-owned assets: | ||||||||||||||||||||||||||
Transportation revenue per barrel shipped(1) | $ | 0.815 | $ | 0.643 | ||||||||||||||||||||||
Volume shipped (million barrels)(1) | 189.6 | 229.8 | ||||||||||||||||||||||||
| Terminal average utilization (million barrels per month) | 24.9 | 24.2 | ||||||||||||||||||||||||
| Select joint venture pipelines: | ||||||||||||||||||||||||||
BridgeTex - volume shipped (million barrels)(2) | 112.1 | 92.7 | ||||||||||||||||||||||||
Saddlehorn - volume shipped (million barrels)(2) | 77.6 | 80.9 | ||||||||||||||||||||||||
(1) Includes shipments related to our crude oil marketing activities.
(2) These volumes reflect total shipments for these joint ventures, which are owned 30% by us.
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Transportation and terminals revenue increased by $76.9 million, resulting from:
•an increase in refined products revenue of $69.7 million primarily due to higher average transportation rates and higher volumes. The higher average rate per barrel in the current year was favorably impacted by the 2021 and 2022 mid-year tariff adjustments as well as a higher proportion of long-haul shipments, which move at higher rates. Volume increased between periods as a result of additional contributions from our Texas pipeline expansion projects, higher shipments on our South Texas pipeline segment as well as continued demand recovery from pandemic levels. Higher tender deduction revenue that benefited from increased commodity prices mainly offset less storage revenue due to lower utilization and rates following recent contract expirations; and
•an increase in crude oil revenue of $7.5 million primarily due to higher terminal throughput fees as a result of more customers utilizing a simplified structure for service in the Houston area and higher tender deduction revenue due to higher commodity prices. These favorable items were partially offset by less storage revenue from lower rates and utilization in the current backwardated market and decreased transportation revenues as overall lower tariff rates offset higher shipments on our Houston distribution system, in part due to a recent pipeline connection.
Operating expenses increased $22.4 million, resulting from:
•an increase in refined products expenses of $14.8 million primarily due to higher power costs resulting from the benefit of gains on our power hedges in the prior year driven by the 2021 winter storms and more long-haul shipments in 2022, as well as higher asset integrity spending related to the timing of maintenance work. These higher costs were partially offset by more favorable product overages in the current period (which reduce operating expense); and
•an increase in crude oil expenses of $8.2 million primarily due to less favorable product overages in 2022.
Product margin increased $50.0 million primarily due to improved margins and higher volumes on our gas liquids blending activities as well as additional crude oil marketing opportunities in the current year.
Other operating income was favorable $2.5 million primarily due to settlement of our claims for expense reimbursement related to historical product contaminations.
Earnings of non-controlled entities decreased $7.0 million primarily due to lower average rates on the Saddlehorn pipeline and lower MVP earnings as a result of the sale of a portion of our interest in April 2021, partially offset by additional deficiency revenue recognized for the BridgeTex and Double Eagle pipelines.
Depreciation, amortization and impairment expense increased $64.9 million primarily due to an impairment of $58.4 million related to our Double Eagle joint venture investment and the timing of asset retirements.
G&A expense increased $34.4 million primarily due to expenses related to the retirement agreement for our former chief executive officer, higher incentive compensation costs resulting from overall improved financial results, as well as increased technology fees.
Interest expense, net of interest income and interest capitalized, increased $0.9 million. Our average outstanding debt increased from $5.1 billion in 2021 to $5.2 billion in 2022. Our weighted average interest rate was 4.3% in 2022 compared to 4.4% in 2021.
Gain on disposition of assets was $74.1 million lower primarily due to the sale of a portion of our interest in MVP in 2021.
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Other expense was favorable by $0.6 million as lower amounts recognized for certain legal matters were primarily offset by higher pension settlement expenses recognized in 2022.
Income from discontinued operations increased by $127.5 million primarily due to the $164.0 million gain recognized on the sale of the independent terminals network, partially offset by lower contributions from these assets once the sale closed in June 2022.
For a comparative discussion of the years ended December 31, 2020 and 2021, see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations” in our 2021 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. Reconciliations of FCF to net income and to net cash provided by operating activities, which are the nearest comparable GAAP measures, are 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, 2021 and 2022 is as follows (in millions):
| Year Ended December 31, | ||||||||||||||
| 2021 | 2022 | |||||||||||||
| Net income | $ | 982.0 | $ | 1,036.4 | ||||||||||
| Interest expense, net | 225.9 | 226.8 | ||||||||||||
Depreciation, amortization and impairment(1) | 233.9 | 292.8 | ||||||||||||
Equity-based incentive compensation(2) | 15.6 | 29.6 | ||||||||||||
Gain on disposition of assets(3) | (70.6) | (158.6) | ||||||||||||
| Commodity-related adjustments: | ||||||||||||||
Derivative (gains) losses recognized in the period associated with future transactions(4) | 27.7 | 18.6 | ||||||||||||
Derivative gains (losses) recognized in previous periods associated with transactions completed in the period(4) | (36.8) | (30.2) | ||||||||||||
Inventory valuation adjustments(5) | 2.1 | (9.0) | ||||||||||||
| Total commodity-related adjustments | (7.0) | (20.6) | ||||||||||||
| Distributions from operations of non-controlled entities in excess of earnings | 38.9 | 27.3 | ||||||||||||
| Adjusted EBITDA | 1,418.7 | 1,433.7 | ||||||||||||
| Interest expense, net, excluding debt issuance cost amortization | (222.8) | (223.6) | ||||||||||||
Maintenance capital(6) | (77.6) | (81.9) | ||||||||||||
| Distributable cash flow | $ | 1,118.3 | $ | 1,128.2 | ||||||||||
Expansion capital(7) | (73.0) | (83.0) | ||||||||||||
Proceeds from disposition of assets(3) | 270.7 | 440.3 | ||||||||||||
| Free cash flow | $ | 1,316.0 | $ | 1,485.5 | ||||||||||
| Distributions paid | (906.4) | (870.0) | ||||||||||||
| Free cash flow after distributions | $ | 409.6 | $ | 615.5 | ||||||||||
(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 valuation of short positions recognized each period as these are non-cash items. In subsequent periods when we sell or purchase the related products, we recognize these valuation adjustments in DCF.
(6) Maintenance capital expenditures maintain our existing assets and do not generate incremental DCF (i.e. incremental returns to our unitholders). For this reason, we deduct maintenance capital expenditures to determine DCF.
(7) 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, 2021 and 2022, is as follows (in millions):
| Year Ended December 31, | ||||||||||||||
| 2021 | 2022 | |||||||||||||
| Net cash provided by operating activities | $ | 1,196.2 | $ | 1,141.3 | ||||||||||
| Changes in operating assets and liabilities | 9.7 | 113.0 | ||||||||||||
| Net cash provided by investing activities | 118.1 | 274.4 | ||||||||||||
| Payments associated with settlement of equity-based incentive compensation | (6.2) | (8.9) | ||||||||||||
| Settlement cost, amortization of prior service credit and actuarial loss | (8.4) | (13.9) | ||||||||||||
| Changes in accrued capital items | 7.8 | 7.3 | ||||||||||||
Commodity-related adjustments(1) | (7.0) | (20.6) | ||||||||||||
| Other | 5.8 | (7.1) | ||||||||||||
| Free cash flow | $ | 1,316.0 | $ | 1,485.5 | ||||||||||
| Distributions paid | (906.4) | (870.0) | ||||||||||||
| Free cash flow after distributions | $ | 409.6 | $ | 615.5 | ||||||||||
(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 $1,196.2 million and $1,141.3 million for the years ended December 31, 2021 and 2022, respectively. The $54.9 million decrease from 2021 to 2022 was due to changes in our working capital, decreases in income from continuing operations, partially offset by adjustments for non-cash items and distributions in excess of earnings of our non-controlled entities.
Investing Activities. Net cash provided by investing activities for the year ended December 31, 2021 and 2022 was $118.1 million and $274.4 million, respectively, including $148.6 million and $175.3 million used for capital expenditures for those same periods in 2021 and 2022, respectively. Also, during 2022, we sold our independent terminals network for $446.2 million inclusive of final working capital adjustments. During 2021, we sold a portion of our interest in MVP for cash proceeds of $272.1 million.
Financing Activities. Net cash used in financing activities for the years ended December 31, 2021 and 2022 was $1,327.7 million and $1,417.8 million, respectively. During 2022, we paid distributions of $870.0 million to our unitholders and made common unit repurchases of $462.9 million. Additionally, we had net commercial paper payments of $76.0 million. 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.
The quarterly distribution amount related to fourth-quarter 2022 earnings was $1.0475 per unit, which was paid in February 2023. Based on the number of common units currently outstanding and our current quarterly distribution, total distributions paid to our unitholders related to 2023 earnings would be approximately $852 million. Management believes we will have sufficient DCF to fund these distributions.
For a discussion of cash flows for the year ended December 31, 2020, see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” in our 2021 Annual Report on Form 10-K.
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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 2022, our maintenance capital spending was $81.9 million. For 2023, we expect to spend approximately $90.0 million on maintenance capital projects.
During 2022, we spent $83.0 million for our expansion capital projects and in conjunction with our joint ventures. Based on the progress of expansion projects already committed, we expect to spend approximately $110.0 million in 2023 and $40.0 million in 2024 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
Leadership Changes. In April 2022, Michael N. Mears retired from his positions of President and Chief Executive Officer, and our board elected Aaron L. Milford as Chief Executive Officer and President. Mr. Milford served as Chief Operating Officer 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.
In August 2022, Robert L. Barnes, Senior Vice President of Commercial - Crude Oil, retired from his position after 34 years of service. Our board elected Kyle T. Krshka as Senior Vice President of Commercial - Crude Oil in November 2022. Mr. Krshka served as Vice President of Commercial - Marine, Independent Terminals & Commodities since 2020 and various positions of increasing responsibility since joining us in 2016.
In December 2022, Melanie A. Little, Executive Vice President, Chief Operating Officer, announced her resignation effective January 1, 2023 to pursue another opportunity.
Executive Officer Promotions. Two members of our senior management team were promoted effective June 1, 2022. Jeff L. Holman became Executive Vice President in addition to his titles of Chief Financial Officer and Treasurer. Michael J. Aaronson, who previously held the position of Senior Vice President of Business Development, became Executive Vice President, Chief Commercial Officer.
Board of Director Changes. Michael N. Mears retired from his position of Chair of the Board of Directors in April 2022 and our board elected Barry R. Pearl, our previous independent Lead Director, as Chair of the Board and also elected Aaron L. Milford as a member of our board. In April 2022, Robert G. Croyle retired from our board after 13 years of service. Following Mr. Croyle’s retirement, Sivasankaran Somasundaram was elected as an independent board member beginning in May 2022.
Pipeline Tariff Changes. The 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. Based on the preliminary PPI-FG estimate for 2022, the ceiling level for our index-based rates will increase by 13.4%. However, we continue to evaluate increases to our index and market-based rates and currently expect to increase all of our refined products rates by an average of approximately 8% on July 1, 2023. 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 2023.
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, 2022 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.
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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 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 | $ | (1.9) | $ | 3.1 | $ | (26.5) | $ | 32.3 | ||||||||||||||||||||||||||||||||||||||||||
| Expected long-term rate of return on plan assets | $ | (2.0) | $ | 2.0 | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||||||
| Rate of compensation increase | $ | 3.4 | $ | (2.9) | $ | 18.0 | $ | (17.0) | ||||||||||||||||||||||||||||||||||||||||||
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 | $0.4 | $(0.4) | ||||||||||||
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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. For purposes of performing the impairment test for goodwill, our reporting units are our refined products and crude oil segments. 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. Based on our qualitative assessments performed, we determined goodwill was not impaired.
When indicators of impairment are identified, 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.
In December 2022, we determined the fair value of our investment in Double Eagle was less than the carrying value and recognized an impairment charge of $58.4 million.
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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, fractionation 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, 2022, 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 | $ | 387.2 | $ | 140.5 | $ | 145.4 | $ | 101.3 | |||||||||||||||
| Forward purchase contracts – barrels | 9.0 | 2.7 | 3.6 | 2.7 | |||||||||||||||||||
| Forward sales contracts – notional value | $ | 49.6 | $ | 49.6 | $ | — | $ | — | |||||||||||||||
| Forward sales contracts – barrels | 0.6 | 0.6 | — | — | |||||||||||||||||||
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 5.1 million barrels of petroleum products we expect to sell and 1.0 million barrels of gas liquids we expect to purchase, was a net liability of $8.9 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 $51.0 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 $10.0 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, 2022, we had $32.0 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, 2022. 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, 2022, 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, 2022. The report, which expresses an unqualified opinion on the effectiveness of our internal control over financial reporting as of December 31, 2022, is included herein under the heading “Report of Independent Registered Public Accounting Firm” relative to internal control over financial reporting.
| By: | /S/ AARON L. MILFORD | ||||
| President, Chief Executive Officer and Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P. | |||||
| By: | /S/ JEFF L. HOLMAN | ||||
| Executive 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, 2022 and 2021, 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, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, 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, 2022, 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 21, 2023 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.
52
| Defined Benefit Pension Obligation | ||||||||
| Description of the Matter | At December 31, 2022, the Partnership’s defined benefit pension obligation was $277 million and exceeded the fair value of pension plan assets of $199 million, resulting in a net pension obligation of $78 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 rates and 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, gaining an understanding of the methodology used, evaluating 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 determination of the discount rate, which reflects the maturity and duration of the benefit payments and 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 mortality rates, retirement rates, and compensation levels, we assessed whether the information is consistent with publicly available information and/or entity-specific support, and we evaluated any market data adjusted for entity-specific data. 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 21, 2023
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, 2022, 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, 2022, 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, 2022 and 2021, 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, 2022, and the related notes and our report dated February 21, 2023 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 21, 2023
55
MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per unit amounts)
| Year Ended December 31, | ||||||||||||||||||||
| 2020 | 2021 | 2022 | ||||||||||||||||||
| Transportation and terminals revenue | $ | 1,743.3 | $ | 1,798.9 | $ | 1,875.8 | ||||||||||||||
| Product sales revenue | 557.5 | 913.0 | 1,302.4 | |||||||||||||||||
| Affiliate management fee revenue | 21.2 | 21.2 | 22.2 | |||||||||||||||||
| Total revenue | 2,322.0 | 2,733.1 | 3,200.4 | |||||||||||||||||
| Costs and expenses: | ||||||||||||||||||||
| Operating | 587.8 | 569.7 | 592.1 | |||||||||||||||||
| Cost of product sales | 468.2 | 780.0 | 1,119.4 | |||||||||||||||||
| Depreciation, amortization and impairment | 243.1 | 227.9 | 292.8 | |||||||||||||||||
| General and administrative | 171.2 | 206.3 | 240.7 | |||||||||||||||||
| Total costs and expenses | 1,470.3 | 1,783.9 | 2,245.0 | |||||||||||||||||
| Other operating income (expense) | 0.1 | 2.8 | 5.3 | |||||||||||||||||
| Earnings of non-controlled entities | 153.3 | 154.4 | 147.4 | |||||||||||||||||
| Operating profit | 1,005.1 | 1,106.4 | 1,108.1 | |||||||||||||||||
| Interest expense | 234.1 | 228.1 | 229.8 | |||||||||||||||||
| Interest capitalized | (11.3) | (1.7) | (1.8) | |||||||||||||||||
| Interest income | (1.0) | (0.5) | (1.2) | |||||||||||||||||
| Gain on disposition of assets | (12.9) | (75.0) | (0.9) | |||||||||||||||||
| Other (income) expense | 5.2 | 20.9 | 20.3 | |||||||||||||||||
| Income from continuing operations before provision for income taxes | 791.0 | 934.6 | 861.9 | |||||||||||||||||
| Provision for income taxes | 2.9 | 2.3 | 2.7 | |||||||||||||||||
| Income from continuing operations | 788.1 | 932.3 | 859.2 | |||||||||||||||||
Income from discontinued operations (including gain on disposition of assets of $164.0 million in 2022) | 28.9 | 49.7 | 177.2 | |||||||||||||||||
| Net income | $ | 817.0 | $ | 982.0 | $ | 1,036.4 | ||||||||||||||
| Earnings per common unit | ||||||||||||||||||||
| Basic: | ||||||||||||||||||||
| Continuing operations | $ | 3.49 | $ | 4.24 | $ | 4.10 | ||||||||||||||
| Discontinued operations | 0.13 | 0.23 | 0.85 | |||||||||||||||||
| Net income per common unit | $ | 3.62 | $ | 4.47 | $ | 4.95 | ||||||||||||||
| Weighted average number of common units outstanding | 225.5 | 219.6 | 209.4 | |||||||||||||||||
| Diluted: | ||||||||||||||||||||
| Continuing operations | $ | 3.49 | $ | 4.24 | $ | 4.10 | ||||||||||||||
| Discontinued operations | 0.13 | 0.23 | 0.85 | |||||||||||||||||
| Net income per common unit | $ | 3.62 | $ | 4.47 | $ | 4.95 | ||||||||||||||
| Weighted average number of common units outstanding | 225.5 | 219.8 | 209.6 | |||||||||||||||||
See notes to consolidated financial statements.
56
MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2021 | 2022 | |||||||||||||||
| Net income | $ | 817.0 | $ | 982.0 | $ | 1,036.4 | |||||||||||
| Other comprehensive income (loss): | |||||||||||||||||
| Derivative activity: | |||||||||||||||||
| Net loss on cash flow hedges | (9.5) | — | — | ||||||||||||||
Reclassification of net loss on cash flow hedges to income | 3.5 | 3.5 | 3.5 | ||||||||||||||
Changes in employee benefit plan assets and benefit obligations recognized in other comprehensive income: | |||||||||||||||||
| Net actuarial gain (loss) | (23.5) | 16.3 | 43.7 | ||||||||||||||
| 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 | 5.9 | 6.0 | 4.6 | ||||||||||||||
| Recognition of settlement cost in income | 1.0 | 2.6 | 9.5 | ||||||||||||||
| Total other comprehensive income (loss) | (21.1) | 28.2 | 61.1 | ||||||||||||||
| Comprehensive income | $ | 795.9 | $ | 1,010.2 | $ | 1,097.5 | |||||||||||
See notes to consolidated financial statements.
57
MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In millions)
See notes to consolidated financial statements.
58
MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
| Year Ended December 31, | ||||||||||||||||||||
| 2020 | 2021 | 2022 | ||||||||||||||||||
| Operating Activities: | ||||||||||||||||||||
| Net income | $ | 817.0 | $ | 982.0 | $ | 1,036.4 | ||||||||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||||||||
| Income from discontinued operations | (28.9) | (49.7) | (177.2) | |||||||||||||||||
| Depreciation, amortization and impairment expense | 243.1 | 227.9 | 292.8 | |||||||||||||||||
| Gain on disposition of assets | (12.9) | (75.0) | (0.9) | |||||||||||||||||
| Earnings of non-controlled entities | (153.3) | (154.4) | (147.4) | |||||||||||||||||
| Distributions from operations of non-controlled entities | 207.6 | 193.3 | 174.7 | |||||||||||||||||
| Equity-based incentive compensation expense | 12.0 | 21.8 | 38.5 | |||||||||||||||||
| Settlement cost, amortization of prior service credit and actuarial loss | 6.7 | 8.4 | 13.9 | |||||||||||||||||
| Debt extinguishment costs | 12.9 | — | — | |||||||||||||||||
| Changes in operating assets and liabilities (Note 9) | (37.1) | (9.7) | (113.0) | |||||||||||||||||
| Net cash provided by operating activities of continuing operations | 1,067.1 | 1,144.6 | 1,117.8 | |||||||||||||||||
| Net cash provided by operating activities of discontinued operations | 40.4 | 51.6 | 23.5 | |||||||||||||||||
| Net cash provided by operating activities | 1,107.5 | 1,196.2 | 1,141.3 | |||||||||||||||||
| Investing Activities: | ||||||||||||||||||||
Additions to property, plant and equipment, net(1) | (424.1) | (148.6) | (175.3) | |||||||||||||||||
| Proceeds from disposition of assets | 334.8 | 275.1 | 0.4 | |||||||||||||||||
| Investments in non-controlled entities | (95.1) | (5.6) | (0.9) | |||||||||||||||||
| Distributions from returns of investments in non-controlled entities | 0.5 | — | 2.5 | |||||||||||||||||
| Net cash provided (used) by investing activities of continuing operations | (183.9) | 120.9 | (173.3) | |||||||||||||||||
| Net cash provided (used) by investing activities of discontinued operations | (15.5) | (2.8) | 447.7 | |||||||||||||||||
| Net cash provided (used) by investing activities | (199.4) | 118.1 | 274.4 | |||||||||||||||||
| Financing Activities: | ||||||||||||||||||||
| Distributions paid | (927.1) | (906.4) | (870.0) | |||||||||||||||||
Repurchases of common units, net(2) | (276.9) | (523.1) | (462.9) | |||||||||||||||||
| Net commercial paper borrowings (repayments) | — | 108.0 | (76.0) | |||||||||||||||||
| Borrowings under long-term notes | 828.4 | — | — | |||||||||||||||||
| Payments on notes | (550.0) | — | — | |||||||||||||||||
| Debt placement costs | (7.6) | — | — | |||||||||||||||||
| Debt extinguishment costs | (12.9) | — | — | |||||||||||||||||
| Net payment on financial derivatives | (9.5) | — | — | |||||||||||||||||
| Payments associated with settlement of equity-based incentive compensation | (14.7) | (6.2) | (8.9) | |||||||||||||||||
| Net cash used by financing activities | (970.3) | (1,327.7) | (1,417.8) | |||||||||||||||||
| Change in cash, cash equivalents and restricted cash | (62.2) | (13.4) | (2.1) | |||||||||||||||||
| Cash, cash equivalents and restricted cash at beginning of period | 84.6 | 22.4 | 9.0 | |||||||||||||||||
| Cash, cash equivalents and restricted cash at end of period | $ | 22.4 | $ | 9.0 | $ | 6.9 | ||||||||||||||
| Supplemental non-cash investing and financing activities: | ||||||||||||||||||||
(1) Additions to property, plant and equipment | $ | (344.4) | $ | (140.8) | $ | (168.0) | ||||||||||||||
| Changes in current liabilities related to capital expenditures | (79.7) | (7.8) | (7.3) | |||||||||||||||||
| Additions to property, plant and equipment, net | $ | (424.1) | $ | (148.6) | $ | (175.3) | ||||||||||||||
(2) Repurchases of common units | $ | (276.9) | $ | (523.1) | $ | (472.3) | ||||||||||||||
| Changes in accounts payable related to repurchases of common units | — | — | 9.4 | |||||||||||||||||
| Repurchases of common units, net | $ | (276.9) | $ | (523.1) | $ | (462.9) | ||||||||||||||
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, 2020 | $ | 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 loss | — | 28.2 | 28.2 | |||||||||||||||||||||||
| Total comprehensive income | 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 | |||||||||||||||||||||||
| Comprehensive income: | ||||||||||||||||||||||||||
| Net income | 1,036.4 | — | 1,036.4 | |||||||||||||||||||||||
| Total other comprehensive income | — | 61.1 | 61.1 | |||||||||||||||||||||||
| Total comprehensive income | 1,036.4 | 61.1 | 1,097.5 | |||||||||||||||||||||||
| Distributions | (870.0) | — | (870.0) | |||||||||||||||||||||||
| Repurchase of common units | (472.3) | — | (472.3) | |||||||||||||||||||||||
| Equity-based incentive compensation expense | 38.5 | — | 38.5 | |||||||||||||||||||||||
| Issuance of common units in settlement of equity-based incentive plan awards | 1.1 | — | 1.1 | |||||||||||||||||||||||
| Payments associated with settlement of equity-based incentive compensation | (8.9) | — | (8.9) | |||||||||||||||||||||||
| Other | (0.8) | — | (0.8) | |||||||||||||||||||||||
| Balance, December 31, 2022 | $ | 1,778.8 | $ | (93.9) | $ | 1,684.9 | ||||||||||||||||||||
See notes to consolidated financial statements.
60
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, 2022, our asset portfolio 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;
•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;
•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.
61
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
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.
On June 8, 2022, we completed the sale of the independent terminals network comprised of 26 refined petroleum products terminals in the southeastern U.S. to Buckeye Partners, L.P. (“Buckeye”) for $446.2 million, including final working capital adjustments. 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 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.
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 and 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, 2021 and 2022, 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,
62
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
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 as operating expenses in 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, (ii) unit awards granted to retirees or employees of retirement age and (iii) 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 in 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
| Revenue from Contracts with Customers | ||||||||
| Property, Plant and Equipment | ||||||||
| Goodwill and Other Intangible Assets | ||||||||
| Investments in Non-Controlled Entities | ||||||||
| Inventories | ||||||||
| Leases | ||||||||
| Pension and Postretirement Medical and Life Benefit Obligations | ||||||||
| Equity-Based Incentive Compensation | ||||||||
| Derivative Financial Instruments | ||||||||
| Contingencies and Environmental | ||||||||
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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
3. Discontinued Operations
Summarized Results of Discontinued Operations
The following table provides the summarized results that have been presented as discontinued operations in the consolidated statements of income for the years ended December 31, 2020, 2021 and 2022 (in millions):
| Year Ended December 31, | ||||||||||||||||||||
| 2020 | 2021 | 2022 | ||||||||||||||||||
| Transportation and terminals revenue | $ | 51.4 | $ | 53.3 | $ | 21.1 | ||||||||||||||
| Product sales revenue | 54.2 | 83.7 | 30.0 | |||||||||||||||||
| Total revenue | 105.6 | 137.0 | 51.1 | |||||||||||||||||
| Costs and expenses: | ||||||||||||||||||||
| Operating | 13.4 | 11.2 | 8.0 | |||||||||||||||||
| Cost of product sales | 45.5 | 66.5 | 28.8 | |||||||||||||||||
| Depreciation, amortization and impairment | 15.6 | 7.1 | — | |||||||||||||||||
| General and administrative | 2.2 | 2.5 | 1.1 | |||||||||||||||||
| Total costs and expenses | 76.7 | 87.3 | 37.9 | |||||||||||||||||
| Gain on disposition of assets | — | — | (164.0) | |||||||||||||||||
| Income from discontinued operations | $ | 28.9 | $ | 49.7 | $ | 177.2 | ||||||||||||||
Summarized Assets and Liabilities of Discontinued Operations
The following table provides the summarized assets and liabilities classified as held for sale in the consolidated balance sheets as of December 31, 2021 (in millions). Subsequent to the sale of the independent terminals network on June 8, 2022, no assets or liabilities were classified as held for sale in relation to discontinued operations.
| December 31, 2021 | ||||||||
| Assets: | ||||||||
| Trade accounts receivable | $ | 6.3 | ||||||
| Inventories | 17.0 | |||||||
| Net property, plant and equipment | 272.0 | |||||||
| Goodwill | 2.7 | |||||||
| Other assets | 1.5 | |||||||
| Total assets classified as held for sale | $ | 299.5 | ||||||
| Liabilities: | ||||||||
| Accounts payable | $ | 3.7 | ||||||
| Accrued product liabilities | 8.4 | |||||||
| Other liabilities | 3.7 | |||||||
| Total liabilities classified as held for sale | $ | 15.8 | ||||||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
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, intersegment transactions, operating expense, 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 G&A expense that management does not consider when evaluating the core profitability of our separate operating segments.
| 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
| 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
| Year Ended December 31, 2022 | ||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||
| Refined Products | Crude Oil | Intersegment Eliminations | Total | |||||||||||||||||||||||
| Transportation and terminals revenue | $ | 1,408.2 | $ | 473.7 | $ | (6.1) | $ | 1,875.8 | ||||||||||||||||||
| Product sales revenue | 1,173.1 | 129.3 | — | 1,302.4 | ||||||||||||||||||||||
| Affiliate management fee revenue | 6.6 | 15.6 | — | 22.2 | ||||||||||||||||||||||
| Total revenue | 2,587.9 | 618.6 | (6.1) | 3,200.4 | ||||||||||||||||||||||
| Operating expense | 431.5 | 173.6 | (13.0) | 592.1 | ||||||||||||||||||||||
| Cost of product sales | 1,020.2 | 99.2 | — | 1,119.4 | ||||||||||||||||||||||
| Other operating (income) expense | (7.9) | 2.6 | — | (5.3) | ||||||||||||||||||||||
| Earnings of non-controlled entities | (23.7) | (123.7) | — | (147.4) | ||||||||||||||||||||||
| Operating margin | 1,167.8 | 466.9 | 6.9 | 1,641.6 | ||||||||||||||||||||||
Depreciation, amortization and impairment expense | 159.2 | 126.7 | 6.9 | 292.8 | ||||||||||||||||||||||
| G&A expense | 172.6 | 68.1 | — | 240.7 | ||||||||||||||||||||||
| Operating profit | $ | 836.0 | $ | 272.1 | $ | — | $ | 1,108.1 | ||||||||||||||||||
| Additions to long-lived assets | $ | 115.8 | $ | 32.0 | $ | 147.8 | ||||||||||||||||||||
| As of December 31, 2022 | ||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||
| Segment assets | $ | 4,880.3 | $ | 2,745.7 | $ | 7,626.0 | ||||||||||||||||||||
| Corporate assets | 81.7 | |||||||||||||||||||||||||
| Total assets | $ | 7,707.7 | ||||||||||||||||||||||||
| Goodwill | $ | 38.3 | $ | 12.1 | $ | 50.4 | ||||||||||||||||||||
| Investments in non-controlled entities | $ | 225.1 | $ | 668.9 | $ | 894.0 | ||||||||||||||||||||
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 their committed volumes. Additionally, when we estimate that the customers will not utilize all or a portion of their
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
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 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 most 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 customers’ transported products 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
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, 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 | ||||||||||||||||||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
| 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 | ||||||||||||||||||
| Year Ended December 31, 2022 | ||||||||||||||||||||||||||
| Refined Products | Crude Oil | Intersegment Eliminations | Total | |||||||||||||||||||||||
| Transportation | $ | 1,000.2 | $ | 226.8 | $ | — | $ | 1,227.0 | ||||||||||||||||||
| Terminalling | 111.2 | 49.6 | — | 160.8 | ||||||||||||||||||||||
| Storage | 151.1 | 101.8 | (6.1) | 246.8 | ||||||||||||||||||||||
| Ancillary services | 115.6 | 18.3 | — | 133.9 | ||||||||||||||||||||||
| Lease revenue | 30.1 | 77.2 | — | 107.3 | ||||||||||||||||||||||
Transportation and terminals revenue | 1,408.2 | 473.7 | (6.1) | 1,875.8 | ||||||||||||||||||||||
| Product sales revenue | 1,173.1 | 129.3 | — | 1,302.4 | ||||||||||||||||||||||
Affiliate management fee revenue | 6.6 | 15.6 | — | 22.2 | ||||||||||||||||||||||
Total revenue | 2,587.9 | 618.6 | (6.1) | 3,200.4 | ||||||||||||||||||||||
Revenue not under the guidance of ASC 606, Revenue from Contracts with Customers: | ||||||||||||||||||||||||||
| Lease revenue | (30.1) | (77.2) | — | (107.3) | ||||||||||||||||||||||
| (Gains) losses from futures contracts included in product sales revenue | (148.4) | (6.8) | — | (155.2) | ||||||||||||||||||||||
Affiliate management fee revenue | (6.6) | (15.6) | — | (22.2) | ||||||||||||||||||||||
Total revenue from contracts with customers under ASC 606 | $ | 2,402.8 | $ | 519.0 | $ | (6.1) | $ | 2,915.7 | ||||||||||||||||||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
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 in 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 per-barrel direct delivery costs and the average delivery point for all barrels in our system. These contract assets are presented in 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, 2021 | December 31, 2022 | |||||||||||||
| Accounts receivable from contracts with customers | $ | 134.8 | $ | 217.0 | ||||||||||
| Contract assets | $ | 12.5 | $ | 10.1 | ||||||||||
| Contract liabilities | $ | 100.1 | $ | 112.7 | ||||||||||
For the year ended December 31, 2022, we recognized $72.9 million of transportation and terminals revenue that was recorded in deferred revenue as of December 31, 2021.
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, 2022 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, 2022 | $ | 2,089.5 | $ | 915.3 | $ | 3,004.8 | ||||||||||||||
| Remaining terms | 1 - 16 years | 1 - 9 years | ||||||||||||||||||
Estimated revenues from UPOs to be recognized in the next 12 months | $ | 356.3 | $ | 237.7 | $ | 594.0 | ||||||||||||||
In computing the value of these future revenues, we have used the current rates in effect as of December 31, 2022 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
as of December 31, 2022 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 in 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 routine 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 4.4%, 4.4% and 4.3% for the years ended December 31, 2020, 2021 and 2022, respectively.
Property, plant and equipment consisted of the following (in millions):
Other includes total interest capitalized on assets placed in service as of December 31, 2021 and 2022 of $98.7 million and $100.1 million, respectively. Depreciation expense for the years ended December 31, 2020, 2021 and 2022 was $240.5 million, $225.2 million and $218.7 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 Property, Plant and Equipment, we ceased recording depreciation and amortization for all assets upon their designation as assets held for sale.
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 2021, we elected to bypass the qualitative assessment of our annual goodwill impairment test and perform the quantitative assessment. Based on this assessment, we concluded goodwill was not impaired as calculated fair value of each of our reporting units was greater than the carrying amount. In 2020 and 2022, 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.
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, 2022 was approximately 15 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, 2020, 2021 and 2022, amortization of other intangible assets was $2.7 million, $2.7 million and $2.8 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, investments are recorded at our acquisition cost or capital contributions, as adjusted by contractual terms or the impacts of impairments, plus capitalized interest, plus equity in earnings or losses since acquisition or formation, less distributions received, less amortization of interest capitalized, and adjustments for the accretion and amortization of basis differences. 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 record a charge to earnings to adjust the carrying value to fair value. We recognized no impairments of our non-controlled entities during 2020 and 2021. In 2022, we recognized an impairment of $58.4 million related to our Double Eagle investment, which was reported as depreciation, amortization and impairment in our consolidated statements of income.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
Our investments in non-controlled entities at December 31, 2022 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 in our consolidated statements of income.
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 in 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 in our consolidated statements of income and totaled $3.6 million, $2.5 million and $8.3 million, respectively, for the years ended December 31, 2020, 2021 and 2022.
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, | ||||||||||||||||||||
| 2020 | 2021 | 2022 | ||||||||||||||||||
| Transportation and terminals revenue: | ||||||||||||||||||||
| BridgeTex, pipeline capacity and storage | $ | 42.3 | $ | 43.7 | $ | 48.5 | ||||||||||||||
| Double Eagle, throughput revenue | $ | 4.9 | $ | 3.0 | $ | 2.5 | ||||||||||||||
| Saddlehorn, storage revenue | $ | 2.5 | $ | 2.3 | $ | 2.4 | ||||||||||||||
| Operating expense: | ||||||||||||||||||||
| Seabrook, storage lease and ancillary services | $ | 29.1 | $ | 19.7 | $ | 17.5 | ||||||||||||||
| Other operating income: | ||||||||||||||||||||
| 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 transactions with non-controlled entities (in millions):
| December 31, 2021 | |||||||||||||||||||||||
| Trade Accounts Receivable | Other Accounts Receivable | Other Accounts Payable | |||||||||||||||||||||
| BridgeTex | $ | 1.2 | $ | — | $ | 0.3 | |||||||||||||||||
| Double Eagle | $ | 0.2 | $ | — | $ | — | |||||||||||||||||
| HoustonLink | $ | — | $ | — | $ | 0.2 | |||||||||||||||||
| MVP | $ | — | $ | 0.6 | $ | 2.2 | |||||||||||||||||
| Saddlehorn | $ | — | $ | 0.2 | $ | — | |||||||||||||||||
| Seabrook | $ | — | $ | 0.1 | $ | 3.2 | |||||||||||||||||
| December 31, 2022 | |||||||||||||||||||||||
| Trade Accounts Receivable | Other Accounts Receivable | Other Accounts Payable | |||||||||||||||||||||
| BridgeTex | $ | 4.8 | $ | — | $ | 3.1 | |||||||||||||||||
| Double Eagle | $ | 0.2 | $ | — | $ | — | |||||||||||||||||
| HoustonLink | $ | — | $ | — | $ | 0.3 | |||||||||||||||||
| MVP | $ | — | $ | 0.6 | $ | — | |||||||||||||||||
| Saddlehorn | $ | — | $ | 0.2 | $ | — | |||||||||||||||||
| Seabrook | $ | 0.3 | $ | — | $ | 0.9 | |||||||||||||||||
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 totaling $7.6 million and $6.5 million in 2021 and 2022, respectively.
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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
A summary of our investments in non-controlled entities (representing only our proportionate interests) follows (in millions):
| Investments at December 31, 2021 | $ | 980.8 | ||||||
| Additional investment | 0.9 | |||||||
| Impairment losses | (58.4) | |||||||
| Other adjustments | 0.5 | |||||||
| Earnings of non-controlled entities: | ||||||||
| Proportionate share of earnings | 149.1 | |||||||
| Amortization of basis differences and capitalized interest | (1.7) | |||||||
| Earnings of non-controlled entities | 147.4 | |||||||
| Less: | ||||||||
Distributions from operations of non-controlled entities | 174.7 | |||||||
Distributions from returns of investments in non-controlled entities | 2.5 | |||||||
| Investments at December 31, 2022 | $ | 894.0 | ||||||
Summarized financial information of our non-controlled entities (representing 100% of the interests in these entities) follows (in millions):
| December 31, | ||||||||||||||
| 2021 | 2022 | |||||||||||||
| Current assets | $ | 227.0 | $ | 206.4 | ||||||||||
| Noncurrent assets | 2,795.7 | 2,727.0 | ||||||||||||
| Total assets | $ | 3,022.7 | $ | 2,933.4 | ||||||||||
| Current liabilities | $ | 178.6 | $ | 187.7 | ||||||||||
| Noncurrent liabilities | 59.5 | 47.9 | ||||||||||||
| Total liabilities | $ | 238.1 | $ | 235.6 | ||||||||||
| Equity | $ | 2,784.6 | $ | 2,697.8 | ||||||||||
| Year Ended December 31, | ||||||||||||||||||||
| 2020 | 2021 | 2022 | ||||||||||||||||||
| Revenue | $ | 752.7 | $ | 733.1 | $ | 760.7 | ||||||||||||||
| Net income | $ | 471.4 | $ | 463.4 | $ | 463.6 | ||||||||||||||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
8. Inventories
Inventories, which are stated at the lower of average cost or net realizable value, consist of the following (in millions):
| December 31, | ||||||||||||||
| 2021 | 2022 | |||||||||||||
| Refined products | $ | 138.0 | $ | 150.2 | ||||||||||
| Transmix | 72.4 | 91.1 | ||||||||||||
| Liquefied petroleum gases | 42.0 | 66.7 | ||||||||||||
| Crude oil | 25.4 | 42.5 | ||||||||||||
| Additives | 3.3 | 5.7 | ||||||||||||
| Total inventories | $ | 281.1 | $ | 356.2 | ||||||||||
9. Consolidated Statements of Cash Flows
Changes in the components of operating assets and liabilities are as follows (in millions):
| Year Ended December 31, | ||||||||||||||||||||
| 2020 | 2021 | 2022 | ||||||||||||||||||
| Trade accounts receivable and other accounts receivable | $ | (0.9) | $ | (29.1) | $ | (94.5) | ||||||||||||||
| Inventories | 14.0 | (122.9) | (75.1) | |||||||||||||||||
| Accounts payable | 4.5 | 16.0 | (6.5) | |||||||||||||||||
| Accrued payroll and benefits | (22.3) | 22.8 | 1.9 | |||||||||||||||||
| Accrued product liabilities | (8.5) | 78.3 | 55.8 | |||||||||||||||||
| Other | (23.9) | 25.2 | 5.4 | |||||||||||||||||
| Total | $ | (37.1) | $ | (9.7) | $ | (113.0) | ||||||||||||||
Other excludes 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, 2020, the long-term pension and benefits liability increased by $21.5 million resulting in a corresponding increase in accumulated other comprehensive loss (“AOCL”). At December 31, 2021 and 2022, the long-term pension and benefits liability decreased by $16.3 million and $43.7 million, respectively, resulting in a corresponding decrease in AOCL.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
10. Debt
Long-term debt at December 31, 2021 and 2022 was as follows (in millions):
| December 31, | ||||||||||||||
| 2021 | 2022 | |||||||||||||
| Commercial paper | $ | 108.0 | $ | 32.0 | ||||||||||
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 | 5,108.0 | 5,032.0 | ||||||||||||
Unamortized debt issuance costs(1) | (37.8) | (35.3) | ||||||||||||
Net unamortized debt premium(1) | 18.6 | 18.3 | ||||||||||||
| Long-term debt, net | $ | 5,088.8 | $ | 5,015.0 | ||||||||||
(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, 2022, maturities of our senior notes were as follows: $0 in 2023 and 2024; $250 million in 2025; $650 million in 2026; $0 in 2027; and $4.1 billion thereafter.
Other Debt
Revolving Credit Facility. At December 31, 2022, the total borrowing capacity under our revolving credit facility was $1.0 billion, of which $88.1 million matures in May 2024 and the remaining $911.9 million matures in November 2027. Any borrowings outstanding under this facility are classified as long-term debt in our consolidated balance sheets. Borrowings under the facility are unsecured and bear interest at Term SOFR and a credit spread adjustment of 0.10% 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, 2022. Borrowings under this facility may be used for general purposes, including capital expenditures. As of December 31, 2021 and 2022, 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 in 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,
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
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, 2022.
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 0.2% and 1.2% for the years ended December 31, 2021 and 2022, respectively. There was $32.0 million outstanding under this program at December 31, 2022.
During the years ending December 31, 2020, 2021 and 2022, total cash payments for interest on all indebtedness, excluding the impact of related interest rate swap agreements, were $234.5 million, $221.6 million and $223.7 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
Minimum fixed rental payments are recognized on a straight-line basis over the life of the lease as costs and expenses in 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, 2022 are as follows (in millions):
| Third Party Leases | Seabrook Lease | All Leases | |||||||||||||||
| 2023 | $ | 21.6 | $ | 9.9 | $ | 31.5 | |||||||||||
| 2024 | 21.9 | 9.7 | 31.6 | ||||||||||||||
| 2025 | 22.0 | 6.6 | 28.6 | ||||||||||||||
| 2026 | 12.6 | 6.6 | 19.2 | ||||||||||||||
| 2027 | 9.4 | 6.6 | 16.0 | ||||||||||||||
| Thereafter | 24.7 | 11.0 | 35.7 | ||||||||||||||
| Total future minimum rental payments | 112.2 | 50.4 | 162.6 | ||||||||||||||
| Present value discount | 8.8 | 5.9 | 14.7 | ||||||||||||||
| Total operating lease liability | $ | 103.4 | $ | 44.5 | $ | 147.9 | |||||||||||
The following tables provide a summary of the effect on our consolidated statements of income for the years ended December 31, 2020, 2021 and 2022 (in millions):
| 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 | ||||||||||||||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
| Year Ended December 31, 2022 | ||||||||||||||||||||
| Third Party Leases | Seabrook Lease | All Leases | ||||||||||||||||||
| Fixed lease expense | $ | 20.9 | $ | 9.9 | $ | 30.8 | ||||||||||||||
| Short-term lease expense | 2.0 | — | 2.0 | |||||||||||||||||
| Variable lease expense | 1.9 | 7.6 | 9.5 | |||||||||||||||||
| Total lease expense | $ | 24.8 | $ | 17.5 | $ | 42.3 | ||||||||||||||
The following table provides a summary of the effect on our consolidated balance sheets as of December 31, 2021 and 2022 (dollars in millions):
Operating Leases – Lessor
We recognize fixed rental income on a straight-line basis over the life of the lease as revenue in 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, 2022 are estimated as follows (in millions):
| 2023 | $ | 35.3 | |||
| 2024 | 35.3 | ||||
| 2025 | 23.9 | ||||
| 2026 | 23.9 | ||||
| 2027 | 23.0 | ||||
| Thereafter | 54.4 | ||||
| Total | $ | 195.8 | |||
We recognized variable lease revenue of $61.4 million, $61.0 million and $66.2 million, respectively, for the years ended December 31, 2020, 2021 and 2022, primarily related to our condensate splitter.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
At December 31, 2022, property, plant and equipment utilized by our customers in operating lease arrangements consisted of: $211.4 million of processing equipment; $64.6 million of storage tanks; $46.6 million of pipeline and station equipment; and $27.6 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 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, 2021 and 2022 was as follows (in millions):
| December 31, 2021 | December 31, 2022 | |||||||||||||
| Total minimum lease payments receivable | $ | 12.2 | $ | 10.5 | ||||||||||
| Less: Unearned income | 1.8 | 1.3 | ||||||||||||
| Recorded net investment in sales-type lease | $ | 10.4 | $ | 9.2 | ||||||||||
The net investment in this sales-type lease was classified in the consolidated balance sheets as follows (in millions):
| December 31, 2021 | December 31, 2022 | |||||||||||||
| Other accounts receivable | $ | 1.3 | $ | 1.4 | ||||||||||
| Long-term receivables | 9.1 | 7.8 | ||||||||||||
| Total | $ | 10.4 | $ | 9.2 | ||||||||||
Future minimum payments receivable under this sales-type lease for the next five years are $1.7 million each year with $1.7 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 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 $12.2 million, $10.6 million and $11.6 million in 2020, 2021 and 2022, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
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, 2021 and 2022 (in millions):
| Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||
| 2021 | 2022 | 2021 | 2022 | |||||||||||||||||||||||
| Change in benefit obligations: | ||||||||||||||||||||||||||
| Benefit obligations at beginning of year | $ | 443.6 | $ | 423.4 | $ | 17.3 | $ | 17.8 | ||||||||||||||||||
| Service cost | 28.2 | 27.2 | 0.3 | 0.3 | ||||||||||||||||||||||
| Interest cost | 9.5 | 10.7 | 0.4 | 0.4 | ||||||||||||||||||||||
| Plan participants’ contributions | — | — | 0.8 | 0.8 | ||||||||||||||||||||||
| Actuarial (gain) loss | (19.4) | (124.6) | 0.9 | (6.6) | ||||||||||||||||||||||
| Benefits paid | (29.2) | (2.5) | (1.9) | (2.0) | ||||||||||||||||||||||
| Settlement payments | (9.3) | (57.3) | — | — | ||||||||||||||||||||||
| Benefit obligations at end of year | 423.4 | 276.9 | 17.8 | 10.7 | ||||||||||||||||||||||
| Change in plan assets: | ||||||||||||||||||||||||||
| Fair value of plan assets at beginning of year | 295.7 | 294.5 | — | — | ||||||||||||||||||||||
| Employer contributions | 27.6 | 39.0 | 1.1 | 1.2 | ||||||||||||||||||||||
| Plan participants’ contributions | — | — | 0.8 | 0.8 | ||||||||||||||||||||||
| Actual return on plan assets | 9.7 | (74.7) | — | — | ||||||||||||||||||||||
| Benefits paid | (29.2) | (2.5) | (1.9) | (2.0) | ||||||||||||||||||||||
| Settlement payments | (9.3) | (57.3) | — | — | ||||||||||||||||||||||
| Fair value of plan assets at end of year | 294.5 | 199.0 | — | — | ||||||||||||||||||||||
| Funded status at end of year | $ | (128.9) | $ | (77.9) | $ | (17.8) | $ | (10.7) | ||||||||||||||||||
| Accumulated benefit obligations | $ | 305.0 | $ | 211.5 | ||||||||||||||||||||||
At December 31, 2021, the accumulated benefit obligations of each of our plans exceeded the fair value of the related plans’ assets. At December 31, 2022, the accumulated benefit obligations of the non-union employee pension plan exceeded the fair value of the plan’s assets.
The pension plans’ actuarial gain in 2021 and 2022 of $19.4 million and $124.6 million, respectively, is primarily due to the impact of increases in the discount rates used to calculate the benefit obligations, partially offset by demographic changes.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
The following table summarizes information for pension plans with obligations in excess of plan assets (in millions):
| December 31, | ||||||||||||||
| 2021 | 2022 | |||||||||||||
| Plans with a projected benefit obligation in excess of plan assets: | ||||||||||||||
| Projected benefit obligation | $ | 423.4 | $ | 276.9 | ||||||||||
| Fair value of plan assets | $ | 294.5 | $ | 199.0 | ||||||||||
| Plans with an accumulated benefit obligation in excess of plan assets: | ||||||||||||||
| Accumulated benefit obligation | $ | 305.0 | $ | 171.9 | ||||||||||
| Fair value of plan assets | $ | 294.5 | $ | 159.2 | ||||||||||
Amounts recognized in the consolidated balance sheets included in these financial statements were as follows (in millions):
| Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||
| 2021 | 2022 | 2021 | 2022 | |||||||||||||||||||||||
| Amounts recognized in consolidated balance sheets: | ||||||||||||||||||||||||||
| Current accrued benefit cost | $ | — | $ | — | $ | 1.7 | $ | 1.2 | ||||||||||||||||||
| Long-term pension and benefits | 128.9 | 77.9 | 16.1 | 9.5 | ||||||||||||||||||||||
| 128.9 | 77.9 | 17.8 | 10.7 | |||||||||||||||||||||||
| Accumulated other comprehensive loss: | ||||||||||||||||||||||||||
| Net actuarial loss | (95.3) | (44.6) | (10.7) | (3.7) | ||||||||||||||||||||||
| Prior service credit | 2.5 | 2.3 | — | — | ||||||||||||||||||||||
| (92.8) | (42.3) | (10.7) | (3.7) | |||||||||||||||||||||||
| Net amount of liabilities and accumulated other comprehensive loss recognized in consolidated balance sheets | $ | 36.1 | $ | 35.6 | $ | 7.1 | $ | 7.0 | ||||||||||||||||||
Net periodic benefit expense for the years ended December 31, 2020, 2021 and 2022 was as follows (in millions):
| Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||||||||||||
| 2020 | 2021 | 2022 | 2020 | 2021 | 2022 | |||||||||||||||||||||||||||||||||
| Components of net periodic benefit costs: | ||||||||||||||||||||||||||||||||||||||
| Service cost | $ | 27.7 | $ | 28.2 | $ | 27.2 | $ | 0.3 | $ | 0.3 | $ | 0.3 | ||||||||||||||||||||||||||
| Interest cost | 11.0 | 9.5 | 10.7 | 0.5 | 0.4 | 0.4 | ||||||||||||||||||||||||||||||||
| Expected return on plan assets | (11.4) | (11.9) | (12.8) | — | — | — | ||||||||||||||||||||||||||||||||
| Amortization of prior service credit | (0.2) | (0.2) | (0.2) | — | — | — | ||||||||||||||||||||||||||||||||
| Amortization of actuarial loss | 5.4 | 5.4 | 4.2 | 0.4 | 0.6 | 0.4 | ||||||||||||||||||||||||||||||||
| Settlement cost | 1.0 | 2.6 | 9.5 | — | — | — | ||||||||||||||||||||||||||||||||
| Settlement gain on disposition of assets | (1.3) | — | — | — | — | — | ||||||||||||||||||||||||||||||||
| Net periodic benefit cost | $ | 32.2 | $ | 33.6 | $ | 38.6 | $ | 1.2 | $ | 1.3 | $ | 1.1 | ||||||||||||||||||||||||||
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.
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Changes in plan assets and benefit obligations recognized in other comprehensive income (loss) during 2020, 2021 and 2022 were as follows (in millions):
| Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||||||||||||
| 2020 | 2021 | 2022 | 2020 | 2021 | 2022 | |||||||||||||||||||||||||||||||||
| Beginning balance | $ | (104.7) | $ | (117.8) | $ | (92.8) | $ | (8.4) | $ | (10.4) | $ | (10.7) | ||||||||||||||||||||||||||
| Net actuarial gain (loss) | (21.0) | 17.2 | 37.1 | (2.5) | (0.9) | 6.6 | ||||||||||||||||||||||||||||||||
| Recognition of prior service credit amortization in income | (0.2) | (0.2) | (0.2) | — | — | — | ||||||||||||||||||||||||||||||||
| Recognition of actuarial loss amortization in income | 5.4 | 5.4 | 4.2 | 0.5 | 0.6 | 0.4 | ||||||||||||||||||||||||||||||||
| Curtailment gain | 1.7 | — | — | — | — | — | ||||||||||||||||||||||||||||||||
| Settlement cost | 1.0 | 2.6 | 9.5 | — | — | — | ||||||||||||||||||||||||||||||||
| Amount recognized in other comprehensive loss | (13.1) | 25.0 | 50.6 | (2.0) | (0.3) | 7.0 | ||||||||||||||||||||||||||||||||
| Ending balance | $ | (117.8) | $ | (92.8) | $ | (42.2) | $ | (10.4) | $ | (10.7) | $ | (3.7) | ||||||||||||||||||||||||||
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 | |||||||||||||||||||||||||
| 2021 | 2022 | 2021 | 2022 | |||||||||||||||||||||||
| Discount rate | 2.61% | 4.79% | 2.64% | 4.98% | ||||||||||||||||||||||
| Rate of compensation increase | 6.51% | 4.42% | n/a | n/a | ||||||||||||||||||||||
| Cash balance interest crediting rate | 1.94% | 3.55% | 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, | |||||||||||||||||||||||||||||||||||||
| 2020 | 2021 | 2022 | 2020 | 2021 | 2022 | |||||||||||||||||||||||||||||||||
| Discount rate | 3.01% | 2.23% | 2.61% | 3.06% | 2.30% | 2.64% | ||||||||||||||||||||||||||||||||
| Rate of compensation increase | 4.58% | 4.53% | 6.51% | n/a | n/a | n/a | ||||||||||||||||||||||||||||||||
| Expected rate of return on plan assets | 4.50% | 4.10% | 4.40% | n/a | n/a | n/a | ||||||||||||||||||||||||||||||||
| Cash balance interest crediting rate | 2.16% | 1.70% | 1.94% | 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 7.2% decreasing systematically to 5.08% by 2029 for pre-65 year old participants.
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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 fair values of the pension plan assets at December 31, 2022 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 | $ | 3.9 | $ | 3.9 | $ | — | $ | — | ||||||||||||||||||
| Mid-cap fund | 3.9 | 3.9 | — | — | ||||||||||||||||||||||
| Large-cap fund | 31.3 | 31.3 | — | — | ||||||||||||||||||||||
| International equity fund | 20.2 | 20.2 | — | — | ||||||||||||||||||||||
Fixed income securities(1): | ||||||||||||||||||||||||||
| Long-term investment grade bond funds | 128.3 | 128.3 | — | — | ||||||||||||||||||||||
| Other: | ||||||||||||||||||||||||||
| Short-term investment fund | 11.2 | 11.2 | — | — | ||||||||||||||||||||||
| Group annuity contract | 0.2 | — | — | 0.2 | ||||||||||||||||||||||
| Fair value of plan assets | $ | 199.0 | $ | 198.8 | $ | — | $ | 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 | Seeks maximum current income by investing exclusively in Short Term U.S. Government Securities and repurchase agreements secured by U.S. government securities | |||||||
| 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.
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The target allocation and actual weighted average asset allocation percentages at December 31, 2021 and 2022 were as follows:
| 2021 | 2022 | |||||||||||||||||||||||||
| Actual | Target | Actual | Target | |||||||||||||||||||||||
| Equity securities | 30% | 30% | 30% | 30% | ||||||||||||||||||||||
| Fixed income securities | 67% | 70% | 64% | 70% | ||||||||||||||||||||||
| Other | 3% | —% | 6% | —% | ||||||||||||||||||||||
As of December 31, 2022, the benefit amounts expected to be paid from plan assets through December 31, 2032 were as follows (in millions):
| Pension Benefits | Other Postretirement Benefits | |||||||||||||
| 2023 | $ | 10.7 | $ | 1.1 | ||||||||||
| 2024 | $ | 11.1 | $ | 1.0 | ||||||||||
| 2025 | $ | 14.5 | $ | 0.9 | ||||||||||
| 2026 | $ | 16.7 | $ | 0.8 | ||||||||||
| 2027 | $ | 18.1 | $ | 0.7 | ||||||||||
| 2028 through 2032 | $ | 110.8 | $ | 2.9 | ||||||||||
Contributions estimated to be paid by us into the plans in 2023 are $19.3 million and $1.1 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 board. The LTIP primarily consists of phantom units and permits the grant of awards covering an aggregate of 13.7 million of our common units. The estimated units remaining available under the LTIP at December 31, 2022 totaled approximately 1.8 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. 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. 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
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 - 1/1/2022 | 445,925 | $ | 48.66 | 470,514 | $ | 48.67 | 916,439 | $ | 48.67 | |||||||||||||||||||||||||||||
Units granted during 2022 | 296,236 | $ | 48.76 | 320,844 | $ | 48.75 | 617,080 | $ | 48.75 | |||||||||||||||||||||||||||||
Units vested during 2022 | (168,939) | $ | 61.16 | (176,846) | $ | 61.15 | (345,785) | $ | 61.16 | |||||||||||||||||||||||||||||
Units forfeited during 2022 | (28,619) | $ | 46.92 | (30,024) | $ | 47.11 | (58,643) | $ | 47.02 | |||||||||||||||||||||||||||||
Non-vested units - 12/31/2022 | 544,603 | $ | 44.93 | 584,488 | $ | 45.02 | 1,129,091 | $ | 44.97 | |||||||||||||||||||||||||||||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
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.
| Awards Description | Non-Vested Unit Awards | Performance Adjustment to Unit Awards | Total Unit Award Accrual | Vesting Date | Unrecognized Compensation Expense (in millions)(a) | |||||||||||||||||||||||||||
| Performance-based awards: | ||||||||||||||||||||||||||||||||
2021 awards | 264,352 | 198,264 | 462,616 | 12/31/2023 | $ | 4.5 | ||||||||||||||||||||||||||
2022 awards | 280,251 | 70,063 | 350,314 | 12/31/2024 | 8.8 | |||||||||||||||||||||||||||
| Time-based awards: | ||||||||||||||||||||||||||||||||
| 2023 vesting date | 283,002 | — | 283,002 | 12/31/2023 | 2.9 | |||||||||||||||||||||||||||
| 2024 vesting date | 301,486 | — | 301,486 | 12/31/2024 | 8.0 | |||||||||||||||||||||||||||
| Total | 1,129,091 | 268,327 | 1,397,418 | $ | 24.2 | |||||||||||||||||||||||||||
(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 2020, 2021 and 2022 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 2020 | 189,632 | $ | 61.16 | 198,450 | $ | 61.18 | ||||||||||||||||||||
Units granted during 2021 | 281,823 | $ | 40.85 | 301,873 | $ | 40.99 | ||||||||||||||||||||
Units granted during 2022 | 296,236 | $ | 48.76 | 320,844 | $ | 48.75 | ||||||||||||||||||||
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, 2022. The vested common units include adjustments for above or below 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) | |||||||||||||||||
12/31/2020 | 235,127 | $15.2 | $10.0 | |||||||||||||||||
12/31/2021 | 316,336 | $19.3 | $14.7 | |||||||||||||||||
12/31/2022 | 334,656 | $20.2 | $16.8 | |||||||||||||||||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
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 2020 | 275,093 | $14.7 | $1.3 | $16.0 | ||||||||||||||||||||||
January 2021 | 150,435 | $6.2 | $0.7 | $6.9 | ||||||||||||||||||||||
January 2022 | 200,949 | $8.9 | $0.8 | $9.7 | ||||||||||||||||||||||
Compensation Expense Summary
Equity-based incentive compensation expense for 2020, 2021 and 2022, primarily recorded as G&A expense in our consolidated statements of income, was as follows (in millions):
| Year Ended December 31, | ||||||||||||||||||||
| 2020 | 2021 | 2022 | ||||||||||||||||||
| Performance awards | $ | 3.1 | $ | 11.2 | $ | 23.0 | ||||||||||||||
| Time-based awards | $ | 8.9 | $ | 10.6 | $ | 15.5 | ||||||||||||||
| Total | $ | 12.0 | $ | 21.8 | $ | 38.5 | ||||||||||||||
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.
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.
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Our open futures contracts at December 31, 2022 were as follows:
| Type of Contract/ Accounting Methodology | Product Represented by the Contract and Associated Barrels | Maturity Dates | ||||||||||||
| Commodity derivatives contract - Economic hedges | 5.1 million barrels of refined products and crude oil | Between January and December 2023 | ||||||||||||
| Commodity derivatives contract - Economic hedges | 1.0 million barrels of gas liquids | Between January and December 2023 | ||||||||||||
Commodity Derivatives Contracts and Deposits Offsets
At December 31, 2021 and 2022, we had made margin deposits of $46.3 million and $14.8 million, respectively, for our commodity derivatives contracts with our counterparties, which were recorded as current assets under commodity derivatives deposits in 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 in 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 in 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, 2021 and 2022 (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, 2021 | $ | (22.3) | $ | 5.1 | $ | (17.2) | $ | 46.3 | $ | 29.1 | ||||||||||||||||||||||
| As of December 31, 2022 | $ | (18.2) | $ | 9.3 | $ | (8.9) | $ | 14.8 | $ | 5.9 | ||||||||||||||||||||||
(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 were 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 accounted for this agreement as a derivative. The agreement expired in early 2022. We recognized 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, 2021 was $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, 2020, 2021 and 2022 were as follows (in millions):
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| Year Ended December 31, | ||||||||||||||||||||
| Derivative Losses Included in AOCL | 2020 | 2021 | 2022 | |||||||||||||||||
| Beginning balance | $ | (49.0) | $ | (55.0) | $ | (51.5) | ||||||||||||||
| Net loss on cash flow hedges | (9.5) | — | — | |||||||||||||||||
| Reclassification of net loss on cash flow hedges to income | 3.5 | 3.5 | 3.5 | |||||||||||||||||
| Ending balance | $ | (55.0) | $ | (51.5) | $ | (48.0) | ||||||||||||||
The following is a summary of the effect on our consolidated statements of income for the years ended December 31, 2020, 2021 and 2022 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, 2020 | $ | (9.5) | Interest expense | $ | (3.5) | |||||||||||||||||||||||||||
| Year Ended December 31, 2021 | $ | — | Interest expense | $ | (3.5) | |||||||||||||||||||||||||||
| Year Ended December 31, 2022 | $ | — | Interest expense | $ | (3.5) | |||||||||||||||||||||||||||
As of December 31, 2022, 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, 2020, 2021 and 2022 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 | 2020 | 2021 | 2022 | ||||||||||||||||||||||
| Commodity derivatives contracts | Product sales revenue | $ | 53.2 | $ | (143.2) | $ | (155.2) | |||||||||||||||||||
| Commodity derivatives contracts | Cost of product sales | 0.3 | 21.1 | (16.6) | ||||||||||||||||||||||
| Basis derivative agreement | Other operating income (expense) | (4.3) | (5.6) | (2.1) | ||||||||||||||||||||||
| Total | $ | 49.2 | $ | (127.7) | $ | (173.9) | ||||||||||||||||||||
The impact of the derivatives in the above table was reflected as cash from operations in our consolidated statements of cash flows.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
Balance Sheets
The following tables provide a summary of the fair value of derivatives, which are presented on a net basis in our consolidated balance sheets, that were not designated as hedging instruments as of December 31, 2021 and 2022 (in millions):
| 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 | |||||||||||||||||||||
| December 31, 2022 | ||||||||||||||||||||||||||
| Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||||
| Derivative Instrument | Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | ||||||||||||||||||||||
| Commodity derivatives contracts | Commodity derivatives contracts, net | $ | 9.3 | Commodity derivatives contracts, net | $ | 18.2 | ||||||||||||||||||||
15. Fair Value Disclosures
Fair Value Methods and Assumptions
We used the following methods and assumptions in estimating the fair value of our 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 in 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.
•Long-term receivables. These include payments receivable under a sales-type leasing arrangement and cost reimbursement agreements. These receivables were recorded at fair value in our consolidated balance sheets, using then-current market rates to estimate the present value of future cash flows.
•Contractual obligations. These primarily include a long-term contractual obligation we entered into in connection with the 2020 sale of three marine terminals to 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 in 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.
•Investment in Double Eagle. In December 2022, as a result of the non-renewal on existing terms of customer commitments that expire in 2023 and reduced demand for transportation of condensate from the Eagle Ford basin, we evaluated our investment in Double Eagle for an other-
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
than-temporary impairment. The fair value was measured using an income approach and discounted cash flow analysis, which resulted in us recording a $58.4 million charge to earnings to adjust the carrying value of our investment to fair value.
•Debt. The fair value of our publicly traded notes was based on the prices of those notes at December 31, 2021 and 2022; 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
The following tables summarize the carrying amounts, fair values and fair value measurements recorded or disclosed as of December 31, 2021 and 2022, based on the three levels established by ASC 820; Fair Value Measurements and Disclosures (in millions):
| 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 | $ | — | ||||||||||||||||||||||
| Long-term receivables | $ | 10.1 | $ | 10.1 | $ | — | $ | — | $ | 10.1 | ||||||||||||||||||||||
| Contractual obligations | $ | (11.3) | $ | (11.3) | $ | — | $ | (1.5) | $ | (9.8) | ||||||||||||||||||||||
| Debt | $ | (5,088.8) | $ | (5,711.5) | $ | — | $ | (5,711.5) | $ | — | ||||||||||||||||||||||
| Fair Value Measurements as of December 31, 2022 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 | $ | (8.9) | $ | (8.9) | $ | 1.4 | $ | (10.3) | $ | — | ||||||||||||||||||||||
| Long-term receivables | $ | 8.3 | $ | 8.3 | $ | — | $ | — | $ | 8.3 | ||||||||||||||||||||||
| Contractual obligations | $ | (9.6) | $ | (9.6) | $ | — | $ | — | $ | (9.6) | ||||||||||||||||||||||
| Investment in Double Eagle | $ | 11.8 | $ | 11.8 | $ | — | $ | — | $ | 11.8 | ||||||||||||||||||||||
| Debt | $ | (5,015.0) | $ | (4,232.5) | $ | — | $ | (4,232.5) | $ | — | ||||||||||||||||||||||
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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
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 and Powder Springs Logistics, LLC (“Powder Springs”) were infringing patents relating to butane blending. A trial concluded on December 6, 2021, at which the jury found Magellan and Powder Springs willfully infringed those patents. Based on the jury’s award and post-trial proceedings, the total amount awarded to Sunoco is approximately $22.9 million, plus post-judgment interest that continues to accrue. Sunoco and defendants, Magellan and Powder Springs, have appealed the final judgment of the trial court. The amounts we have accrued in relation to the claims represent our best estimate of probable damages, and although it is not possible to predict the ultimate outcome, we do not expect the final resolution of this matter to have a material adverse effect on our business.
Corpus Christi Terminal Personal Injury Proceeding.
Ismael Garcia, Andrew Ramirez, and Jesus Juarez Quintero, et al. brought personal injury cases against Magellan and co-defendants Triton Industrial Services, LLC, Tidal Tank, Inc. and Cleveland Integrity Services, Inc. in Nueces County Court in Texas. The claims were originally brought in three different actions but were consolidated into a single case on March 2, 2021. Claims were asserted by or on behalf of seven individuals, and certain beneficiaries, who were employed by a contractor of Magellan and were injured, one fatally, as a result of a fire that occurred on December 5, 2020 while they were cleaning a tank at our Corpus Christi terminal. The plaintiffs are seeking damages of an undetermined amount. While the outcome cannot be predicted, we do not expect the final resolution of this matter to have a material adverse effect on our business.
Environmental Liabilities
Liabilities recognized for estimated environmental costs were $9.8 million and $10.2 million at December 31, 2021 and December 31, 2022, respectively. We have classified environmental liabilities as based on management’s estimates regarding the timing of actual payments. Environmental expenses recognized as a
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
result of changes in our environmental liabilities are included as in our consolidated statements of income. Environmental expenses were $3.4 million, $3.2 million and $4.1 million for the years ended December 31, 2020, 2021 and 2022, 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, 2021 our consolidated balance sheets included a current liability of $0.5 million and a noncurrent liability of $8.9 million, and as of December 31, 2022, our consolidated balance sheets included a current liability of $0.6 million and a noncurrent liability of $8.2 million, reflecting the fair values of these obligations.
We have entered into an agreement to guarantee our 50% pro rata share, up to $50.0 million, of contractual obligations under Powder Springs’ credit facility. At December 31, 2021 and 2022, our consolidated balance sheets reflected $0.4 million and $0.8 million, respectively, other current liability and a corresponding increase in our investment in non-controlled entities in 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, 2022, we had 1,655 employees, primarily concentrated in the central U.S. There were 855 employees assigned to our refined products segment, 248 employees assigned to our crude oil segment and 552 employees assigned to provide G&A services. Approximately 13% of our employees are represented by the United Steelworkers and covered by a collective bargaining agreement that expires in January 2026.
18. Related Party Transactions
Stacy P. Methvin is an independent member of our board and also serves as a director of one of our customers. We received tariff, terminalling and other ancillary revenue from this customer of $37.4 million, $65.2 million and $67.5 million for the periods ending December 31, 2020, 2021 and 2022, respectively. We recorded a receivable of $5.4 million and $6.8 million from this customer at December 31, 2021 and 2022, 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 Ms. Methvin served as a director until August 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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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, 2020 through December 31, 2022:
| Common units outstanding on January 1, 2020 | 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 | ||||
| Units repurchased during 2022 | (9,578,502) | ||||
| January 2022—Settlement of employee LTIP awards | 200,949 | ||||
During 2022—Other(1) | 23,400 | ||||
| Common units outstanding on December 31, 2022 | 203,033,837 | ||||
(1)Common units issued to settle the equity-based retainer paid to our independent directors of our board.
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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
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 2020, 2021 and 2022 were as follows (in millions, except per unit amounts):
| Payment Date | Per Unit Distribution Amount | Total Distribution | ||||||||||||
| 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 | ||||||||||
| 2/14/2022 | $ | 1.0375 | $ | 220.6 | ||||||||||
| 5/13/2022 | 1.0375 | 219.5 | ||||||||||||
| 8/12/2022 | 1.0375 | 215.2 | ||||||||||||
| 11/14/2022 | 1.0475 | 214.7 | ||||||||||||
| Total | $ | 4.1600 | $ | 870.0 | ||||||||||
20. Subsequent Events
Recognizable events
No recognizable events have occurred subsequent to December 31, 2022.
Non-recognizable events
On February 14, 2023, we paid distributions of $1.0475 per unit on our outstanding common units to unitholders of record at the close of business on February 7, 2023.
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Quarterly Financial Data (unaudited)
Summarized quarterly financial data is as follows (in millions, except per unit amounts):
2021 | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||||||||||||
| 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 | ||||||||||||||||||
2022 | ||||||||||||||||||||||||||
| Revenue | $ | 674.7 | $ | 788.6 | $ | 876.1 | $ | 861.0 | ||||||||||||||||||
| Total costs and expenses | $ | 488.1 | $ | 578.1 | $ | 522.7 | $ | 656.1 | ||||||||||||||||||
| Operating margin | $ | 340.5 | $ | 355.7 | $ | 512.3 | $ | 433.1 | ||||||||||||||||||
| Income from continuing operations | $ | 162.0 | $ | 181.8 | $ | 328.4 | $ | 187.0 | ||||||||||||||||||
| Income from discontinued operations | $ | 3.5 | $ | 172.1 | $ | 1.6 | $ | — | ||||||||||||||||||
| Net income | $ | 165.5 | $ | 353.9 | $ | 330.0 | $ | 187.0 | ||||||||||||||||||
| Basic net income per common unit | $ | 0.78 | $ | 1.67 | $ | 1.59 | $ | 0.91 | ||||||||||||||||||
| Diluted net income per common unit | $ | 0.78 | $ | 1.67 | $ | 1.59 | $ | 0.91 | ||||||||||||||||||
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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 Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”). Based upon that evaluation, our 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 to ensure 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, 2022 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.
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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.
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PART IV
Item 15. Exhibits and Financial Statement Schedules
(a)1 and (a)2.
| Page | ||||||||
| Financial Statements | ||||||||
| Not covered by reports of independent auditors: | ||||||||
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.
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Index to Exhibits
| Exhibit No. | Description | |||||||
| Exhibit 3 | ||||||||
| *(a) | ||||||||
| *(b) | ||||||||
| *(c) | ||||||||
| *(d) | ||||||||
| *(e) | ||||||||
| *(f) | ||||||||
| *(g) | ||||||||
| *(h) | ||||||||
| *(i) | ||||||||
| *(j) | ||||||||
| Exhibit 4 | ||||||||
| *(a) | ||||||||
| *(b) | ||||||||
| *(c) | ||||||||
| *(d) | ||||||||
| *(e) | ||||||||
| *(f) | ||||||||
| *(g) | ||||||||
| *(h) | ||||||||
| *(i) | ||||||||
| *(j) | ||||||||
| *(k) | ||||||||
| *(l) | ||||||||
| *(m) | ||||||||
| *(n) | ||||||||
| Exhibit 10 | ||||||||
| #*(a) | ||||||||
| #*(b) | ||||||||
105
| Exhibit No. | Description | |||||||
| #(c) | ||||||||
| #(d) | ||||||||
| #*(e) | ||||||||
| *(f) | ||||||||
| *(g) | ||||||||
| *(h) | ||||||||
| #*(i) | ||||||||
| #(j) | ||||||||
| #(k) | ||||||||
| *(l) | ||||||||
| *(m) | ||||||||
| #*(n) | ||||||||
| #*(o) | ||||||||
| #(p) | ||||||||
| Exhibit 14 | ||||||||
| (a) | ||||||||
| *(b) | ||||||||
| Exhibit 21 | ||||||||
| Exhibit 23 | ||||||||
| Exhibit 31 | ||||||||
| (a) | ||||||||
| (b) | ||||||||
| **Exhibit 32 | ||||||||
| (a) | ||||||||
| (b) | ||||||||
| 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.
** Furnished herewith
# Management contract or compensatory plan or arrangement
106
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 L. HOLMAN | |||||||
| Jeff L. Holman Executive Vice President, Chief Financial Officer and Treasurer | ||||||||
Date: February 21, 2023
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.
107
| Signature | Title | Date | ||||||||||||
/s/ AARON L. MILFORD | Principal Executive Officer and Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P. | February 21, 2023 | ||||||||||||
| Aaron L. Milford | ||||||||||||||
/s/ JEFF L. HOLMAN | Principal Financial and Accounting Officer of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P. | February 21, 2023 | ||||||||||||
| Jeff L. Holman | ||||||||||||||
/s/ WALTER R. ARNHEIM | Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P. | February 21, 2023 | ||||||||||||
| Walter R. Arnheim | ||||||||||||||
/s/ LORI A. GOBILLOT | Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P. | February 21, 2023 | ||||||||||||
| Lori A. Gobillot | ||||||||||||||
/s/ EDWARD J. GUAY | Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P. | February 21, 2023 | ||||||||||||
| Edward J. Guay | ||||||||||||||
/s/ CHANSOO JOUNG | Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P. | February 21, 2023 | ||||||||||||
| Chansoo Joung | ||||||||||||||
/s/ STACY P. METHVIN | Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P. | February 21, 2023 | ||||||||||||
| Stacy P. Methvin | ||||||||||||||
/s/ JAMES R. MONTAGUE | Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P. | February 21, 2023 | ||||||||||||
| James R. Montague | ||||||||||||||
/s/ BARRY R. PEARL | Chair of the Board and Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P. | February 21, 2023 | ||||||||||||
| Barry R. Pearl | ||||||||||||||
/s/ SIVASANKARAN SOMASUNDARAM | Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P. | February 21, 2023 | ||||||||||||
Sivasankaran Somasundaram | ||||||||||||||
108
