UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
|ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)|
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020
|☐||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)
|(State or other jurisdiction of|
incorporation or organization)
| ||(I.R.S. Employer|
One Williams Center, P.O. Box 22186, Tulsa, Oklahoma 74121-2186
(Address of principal executive offices and zip code)
(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|
|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, 2020 was $9,686,843,947.
As of February 17, 2021, there were 223,282,818 common units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s Proxy Statement prepared for the solicitation of proxies in connection with the 2021 Annual Meeting of Limited Partners are to be incorporated by reference in Part III of this Form 10-K.
TABLE OF CONTENTS
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,” “continue,” “could,” “estimates,” “expects,” “forecasts,” “goal,” “guidance,” “intends,” “may,” “might,” “plans,” “potential,” “projected,” “scheduled,” “should,” “will” and other similar 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, estimated or budgeted amounts, events or circumstances we have discussed in this report:
•overall demand for refined products, crude oil and liquefied petroleum gases;
•price fluctuations for refined products, crude oil and liquefied petroleum gases and expectations about future prices for these products;
•changes in the production of crude oil in the basins served by our pipelines;
•changes in general economic conditions, interest rates and price levels;
•changes in the financial condition of our customers, vendors, derivatives counterparties, lenders or joint venture co-owners;
•our ability to secure financing in the credit and capital markets in amounts and on terms that will allow us to execute our business strategy, refinance our existing obligations when due and maintain adequate liquidity;
•development and increasing use of alternative energy sources, including but not limited to natural gas, solar power, wind power, electric and battery-powered engines and geothermal energy, increased use of renewable fuels such as ethanol, biodiesel and renewable diesel, increased conservation or fuel efficiency, increased use of electric vehicles, as well as regulatory developments or other trends that could affect demand for our services;
•changes in 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 or storage in our refined products or crude oil segments;
•changes in supply and demand patterns for our facilities due to geopolitical events, the activities of the Organization of the Petroleum Exporting Countries (“OPEC”) and other non-OPEC oil producing countries with large production capacity, changes in U.S. trade policies or in laws governing the importing and exporting of petroleum products, technological developments or other factors;
•our ability to manage interest rate and commodity price exposures;
•changes in our tariff rates or other terms of service required by the Federal Energy Regulatory Commission or state regulatory agencies;
•shut-downs or cutbacks at refineries, oil fields, petrochemical plants or other customers or businesses that use or supply our services;
•the effect of weather patterns and other natural phenomena, including climate change, on our operations and demand for our services;
•an increase in the competition our operations encounter, including the effects of capacity over-build in the areas where we operate;
•the occurrence of natural disasters, epidemics, terrorism, sabotage, protests or activism, operational hazards, equipment failures, system failures or unforeseen interruptions;
•changes in general economic conditions, including market and macro-economic disruptions resulting from the COVID-19 pandemic and related governmental responses;
•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 with acceptable expected returns or to complete identified expansion projects on time and at projected costs;
•our ability to make and integrate accretive acquisitions and joint ventures and successfully execute our business strategies;
•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 interpretations of such laws that govern our gas liquids blending activities or changes regarding product quality specifications or renewable fuel obligations that impact our ability to produce gasoline volumes through our gas liquids blending activities or that require significant capital outlays for compliance;
•changes in laws and regulations to which we or our customers are or could become subject, including tax withholding requirements, safety, security, employment, hydraulic fracturing, derivatives transactions, trade and environmental, including laws and regulations designed to address climate change;
•the cost and effects of legal and administrative claims and proceedings against us, our subsidiaries or our joint ventures;
•the amount of our indebtedness, which could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, place us at competitive disadvantages compared to our competitors that have less debt or have other adverse consequences;
•the potential that our internal controls may not be adequate, weaknesses may be discovered or remediation of any identified weaknesses may not be successful;
•the ability and intent of our customers, vendors, lenders, joint venture co-owners or other third parties to perform their contractual obligations to us;
•petroleum product supply disruptions;
•global and domestic repercussions from terrorist activities, including cyberattacks, and the government’s response thereto; 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.
MAGELLAN MIDSTREAM PARTNERS, L.P.
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 its common units are traded on the New York Stock Exchange under the ticker symbol “MMP.” Magellan GP, LLC, a wholly-owned Delaware limited liability company, serves as its general partner.
(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, 2020, our asset portfolio consisted of:
•our refined products segment, comprised of our approximately 9,800-mile refined petroleum products pipeline system with 54 connected terminals, as well as 25 independent terminals not connected to our pipeline system 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 37 million barrels of aggregate storage capacity, of which approximately 27 million barrels are used for contract storage. Approximately 1,000 miles of these pipelines, the condensate splitter and 30 million barrels of this storage capacity (including 24 million barrels used for contract storage) are wholly-owned, with the remainder owned through joint ventures.
The United States (“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 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;
•transmix is a mixture that forms when different refined products are transported in pipelines. Transmix is fractionated and blended into usable refined products;
•liquefied petroleum gases or LPGs are liquids produced as by-products of the crude oil refining process and in connection with natural gas production. LPGs include butane and propane;
•blendstocks are products blended with refined products to change or enhance their characteristics such as increasing a gasoline’s octane or oxygen content. Blendstocks include alkylates, oxygenates and natural gasoline;
•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; and
•renewable fuels, such as ethanol, biodiesel and renewable diesel, are fuels derived from living materials and typically blended with other refined products as required by government mandates.
We use the term petroleum products to describe any, or a combination, of the above-noted products.
Description of Our Businesses
Our refined products segment consists of our refined products pipeline system, our independent terminals and two marine terminals. Our refined products pipeline system is the longest common carrier pipeline system for refined products and LPGs in the U.S., extending approximately 9,800 miles from the Texas Gulf Coast and covering a 15-state area across the central U.S. The system includes approximately 47 million barrels of aggregate usable storage capacity at 54 connected terminals. Our network of independent terminals includes 25 refined products terminals with 6 million barrels of storage located primarily in the southeastern U.S. and connected to third-party common carrier interstate pipelines, including the Colonial and Plantation pipelines. 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,|
|Percent of consolidated revenue||78%||76%||75%|
|Percent of consolidated operating margin||65%||62%||66%|
|Percent of consolidated total assets||61%||64%||64%|
See Note 3 – 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 2020, approximately 65% of the refined products segment’s revenue (excluding product sales revenue) was generated from transportation tariffs on volumes shipped on our refined products pipeline system. These transportation tariffs vary depending upon where the product originates, where ultimate delivery occurs and any applicable discounts. All transportation rates and discounts are in published tariffs filed with the Federal Energy Regulatory Commission (“FERC”) or appropriate state agency. Included as part of these tariffs are charges for terminalling and storage of products at 31 of our pipeline system’s 54 connected terminals. Revenue from terminalling and storage at the other 23 terminals on our refined products pipeline system is derived from privately negotiated rates. Under our tariffs, we are allowed to deduct prescribed quantities of the products our shippers transport on our pipelines, which are commonly referred to as “tender deductions,” to compensate us for lost product during shipment due to metering inaccuracies, intermingling of products between batches (transmix), evaporation or other events that result in volume shortages during the shipment process. In return for these tender deductions, our customers receive a guaranteed delivery of
the gross volume of products they ship with us, less the amount of our tender deductions, irrespective of the actual amount of product shortages we incur during the shipment process.
In 2020, the products transported on our refined products pipeline system were comprised of 58% gasoline, 37% distillates and 5% 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 independent terminals generate revenue primarily by charging fees based on the amount of product delivered through our facilities and from ancillary services such as additive injections and ethanol blending. Our marine terminals generate revenue primarily by providing storage and related services, including dock capabilities.
Commodity-Related Activities. Substantially all of the transportation, throughput and storage services we provide are for third parties, and we do not take title to their products. We do take title to products related to tender deductions, product overages, gas liquids blending and fractionation activities. The sales of these products generate product sales revenue.
Our gas liquids blending activity primarily involves purchasing butane and blending it into gasoline, which creates additional gasoline available for us to sell. This activity is limited by seasonal changes in gasoline vapor pressure specification requirements and by the varying quality of the gasoline products 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 hedge the economic margin from this blending activity by entering into forward physical or exchange-traded gasoline futures contracts at the time we purchase the related gas liquids. These blending activities accounted for approximately 92% of the total product margin for the refined products segment during 2020.
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 $220.3 million, $116.6 million and $107.3 million for the years ended December 31, 2018, 2019 and 2020, respectively. The amount of margin we earn from these activities and related hedges fluctuates with changes in petroleum prices (see Note 13–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 3—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 afffiliate of Petroleos Mexicanos (PEMEX), which owns approximately one million barrels of storage at our Galena Park terminal. We serve as operator of the Texas Frontera assets.
We own a 50% interest in MVP Terminalling, LLC (“MVP”), a joint venture with an affiliate of Valero Energy Corporation, which owns a refined products marine storage terminal along the Houston Ship Channel in Pasadena, Texas. The terminal includes five million barrels of storage, two ship docks and truck loading facilities. We serve as operator of the MVP assets.
Markets and Competition. Shipments originate on our refined products pipeline system from direct connections to refineries or through interconnections with other pipelines or terminals for transportation and ultimate distribution to retail gasoline stations, truck stops, railroads, airports and other end users. Through direct refinery connections and interconnections with other interstate pipelines, our refined products system can access approximately 45% of U.S. refining capacity, and in particular is well-connected to Texas Gulf Coast and Mid-Continent refineries. As a result of its extensive connections to multiple refining regions, our pipeline system is well positioned to accommodate demand or supply shifts that may occur.
Our system is dependent on the ability of refiners and marketers to meet the demand for refined products in the markets they serve through shipments on our pipeline system. Demand for refined products is influenced by many factors, including driving patterns and consumer preferences, economic conditions, population changes, government regulations, changes in vehicle fuel efficiency and development of alternative energy sources. 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. Projections published by the Energy Information Administration in February 2021 suggest that overall demand for refined products in the market areas served by our pipeline system, primarily the West North Central and West South Central census districts, will decline by approximately 0.6% annually over the next ten years, when compared to the more historical demand levels of 2019.
In 2020, approximately 62% of the products transported on our refined products pipeline system originated from direct refinery connections and 38% 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|
|CVR Energy|| ||Coffeyville, KS|
|CVR Energy||Wynnewood, OK|
|Flint Hills Resources|| ||Pine Bend, MN|
|HollyFrontier|| ||El Dorado, KS|
|HollyFrontier|| ||Tulsa, OK|
|Marathon|| ||St. Paul, MN|
|Marathon||El Paso, TX|
|Marathon|| ||Galveston Bay, TX|
|Par Pacific ||Newcastle, WY|
|Phillips 66|| ||Ponca City, OK|
|Suncor Energy||Commerce City, CO|
|Valero|| ||Texas City, TX|
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|
|Explorer|| ||Mt. Vernon, MO; Glenpool, OK; Dallas, TX; East Houston, TX; Pasadena, TX|| ||Various Gulf Coast refineries|
|Holly Energy Partners||Duncan, OK; El Paso, TX|
Big Spring, TX refinery, Artesia, NM refinery
|Kinder Morgan|| ||Galena Park and Pasadena, TX|| ||Various Gulf Coast refineries and imports|
| ||Galena Park, TX|| ||Various Gulf Coast refineries and imports|
| ||El Dorado, KS|| ||Conway, KS storage|
|NuStar Energy|| |
Denver, CO; El Dorado, KS; Minneapolis, MN
Various OK & KS refineries, Mandan, ND refinery, McKee, TX refinery
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 area 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 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 the use of renewable fuels, including ethanol and biodiesel. Due to technical and operational concerns, pipelines have historically not shipped ethanol or biodiesel in significant quantities, but rather are transported by railroad, truck or barge to terminal facilities where they are then blended into the fuel stream. The increased use of ethanol and biodiesel has and will continue to compete with shipments on our pipeline system. Our terminals have the necessary infrastructure to blend ethanol and biodiesel with refined products, and we earn revenue for these services and continue to evaluate the potential to move ethanol and biodiesel blends, along with other renewable fuels, on our pipeline system.
Our independent terminals receive product primarily from the interstate pipelines to which they are connected and serve the retail, industrial and commercial sales markets along those pipelines. Demand for our services is driven primarily by end user demand for refined products in those markets. Our terminals compete with other
independent terminal operators as well as integrated oil companies on the basis of terminal location and versatility, services provided and price.
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 2020, approximately 45% of the shipments on our pipeline system were subject to these supplemental agreements. The average remaining life of these agreements was approximately four years as of December 31, 2020. 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, 2020, 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, 2020 represented 37% of total revenue for our refined products segment and 52% of revenue excluding product sales.
Customers of our independent terminals include refiners, retailers, wholesalers and traders. Contracts vary in term and commitment and typically renew automatically, unless the customer elects to terminate, at the end of each contract period.
Customers of our marine terminals include refiners, marketers and traders. As of December 31, 2020, approximately 78% of our usable marine storage capacity, including the storage capacity of our joint ventures, was under contract with an average remaining life of approximately two years. 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.
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 37 million barrels, of which 27 million barrels are used for contract storage. Approximately 1,000 miles of these pipelines, the condensate splitter and 30 million barrels of this storage capacity (including 24 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,|
|Percent of consolidated revenue||22%||24%||25%|
|Percent of consolidated operating margin||35%||37%||34%|
|Percent of consolidated total assets||36%||34%||35%|
See Note 3 – 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, providing pipeline capacity and tolling fees from our condensate splitter. In addition, we earn revenue for ancillary services including terminal throughput fees. We generally do not take title to the products we ship or store for our crude oil customers. Our tariffs provide for tender deductions to compensate us for lost product during shipment due to metering inaccuracies, evaporation or other events that result in volume losses during the shipment process, and we take title to these products. We also take title to volumes shipped 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 the delivery point for the Permian WTI Crude Oil futures contract traded on the Intercontinental Exchange. We expect the nature and availability of crude oil futures contracts and market price assessments to continue evolving in the Houston market. We will continue to pursue opportunities as this market develops.
Our Houston distribution system consists of more than 100 miles of pipeline that connect our East Houston terminal through several interchanges to various points, including multiple refineries throughout the Houston area and crude oil import and export facilities, including through the facility owned by Seabrook discussed below. In addition, it is directly connected to other third-party crude oil pipelines providing us access to crude oil from the Permian and Eagle Ford basins, the strategic crude oil trading hub in Cushing, Oklahoma and crude oil imports.
Our Cushing terminal consists of approximately 13 million barrels of crude oil storage, all of which is used for contract storage. The facility primarily receives and distributes crude oil via the multiple common carrier pipelines that terminate in and originate from the Cushing crude oil trading hub, including the pipeline owned by our Saddlehorn joint venture discussed below, as well as short-haul pipeline connections with neighboring crude oil terminals.
We own approximately 400 miles of pipeline in Kansas and Oklahoma used for crude oil service. A portion of these pipelines is leased to third parties, and we earn revenue from these pipeline segments for capacity leased even if not used by the customers.
Our Corpus Christi terminal includes approximately four million barrels of storage, with a portion used for contract storage and a portion used in conjunction with our Double Eagle joint venture discussed below. This terminal receives product primarily from barges and pipelines that connect to our terminal for further distribution to end users by trucks, pipeline or waterborne vessels. Our 50,000 bpd condensate splitter with approximately two million barrels of related storage is also located at our terminal in Corpus Christi.
Crude Oil Marketing Activities. Our crude oil marketing activities primarily involve purchasing and selling crude oil to be shipped on our Texas crude oil pipelines to facilitate intrastate shipments and maximize profitability on our crude oil pipeline assets. Earnings from these activities are primarily based on the differential in market prices for crude oil between our origin and destination points.
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 currently capable of transporting up to 440,000 bpd of Permian Basin crude oil to our East Houston terminal. We serve as operator of the BridgeTex pipeline. 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 the Double Eagle pipeline. We have entered into a terminal throughput agreement which provides Double Eagle access to our Corpus Christi terminal.
We own a 50% interest in HoustonLink, a joint venture with an affiliate of TC Energy Corporation (“TC Energy”). HoustonLink owns a crude oil pipeline connecting TC Energy’s Houston terminal, which is a termination point for TC Energy’s Marketlink pipeline, to our nearby East Houston terminal. We serve as operator of the HoustonLink pipeline.
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 Noble Midstream Partners LP). Saddlehorn owns an undivided joint interest in an approximately 600-mile pipeline, which delivers various grades of crude oil from the DJ Basin as well as other Rocky Mountain production regions to storage facilities in Cushing, including our Cushing terminal. Saddlehorn currently has the capacity to deliver up to 290,000 bpd of crude oil, following the completion of a 100,000 bpd expansion in late 2020. We serve as operator of Saddlehorn and have also entered into contracts 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 three million barrels of crude oil storage (two million barrels of which is used for contract storage) located in Seabrook, Texas, a pipeline connecting Seabrook’s storage facilities to an existing third-party pipeline that connects to a Houston-area refinery and another pipeline connecting its facility to our Houston distribution system. LBC serves as operator of the Seabrook terminal and the general and administrative operator of the entity, while we serve as operator of the Seabrook pipelines. In addition, we have a long-term lease agreement with Seabrook that we utilize to provide our customers with crude oil storage capacity and dock access for crude oil imports and exports on the Texas Gulf Coast.
Markets and Competition. Market conditions experienced by our crude oil pipelines vary significantly by location. The Longhorn and BridgeTex pipelines deliver Permian Basin production to trading and demand centers in the Houston area, and consequently depend on the level of production in the Permian Basin for supply. Demand for shipments to the Houston area is driven primarily by the utilization of West Texas crude oil by Gulf Coast refineries and the price for crude oil on the Gulf Coast relative to its price in alternative markets, including export markets. Permian Basin production varies based on numerous factors including overall crude oil prices and changes in costs of production, while Gulf Coast demand for Permian Basin production also fluctuates based on relative prices for competing crude oil or changes by refineries to their crude oil processing slates, as well as by overall domestic and international demand for petroleum products. The Longhorn and BridgeTex pipelines compete with alternative outlets for Permian Basin production, including pipelines that transport crude oil to the Cushing crude oil trading hub as well as other pipelines that transport Permian Basin crude to Houston, Corpus Christi or Nederland. These pipelines also compete with truck and rail alternatives for Permian Basin barrels. Further, these pipelines indirectly compete with other alternatives for delivering similar quality crude oil to the Gulf Coast, including pipelines from other producing regions such as the Mid-Continent, Bakken, Eagle Ford or Gulf of Mexico, as well as waterborne imports. Competition is based primarily on tariff rates, proximity to supply sources and demand centers, connectivity, service offerings, crude quality and customer relationships.
Volumes transported on our Houston distribution system are driven by supply of crude oil delivered into our system from the basins connected by our pipeline 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 and customer relationships.
Our crude oil storage in Cushing serves customers who value Cushing’s location as an interchange point for numerous interstate pipelines, including Saddlehorn, and its status as a crude oil trading hub. Demand for crude oil storage in Cushing could be affected by changes in crude oil pipeline flows that change the volume of crude oil that flows through or is stored in Cushing, as well as by developments of alternative trading hubs that reduce Cushing’s relative importance. In addition, demand for our storage services in Cushing could be affected by crude oil price volatility or price structures or by regulatory or financial conditions that affect the ability of our customers to store or trade crude oil. We compete in Cushing with numerous other storage providers, with competition based on a combination of connectivity, storage rates and other terms, customer service and customer relationships.
The Double Eagle pipeline depends on condensate production from the Eagle Ford basin for its supply and competes primarily with other pipelines and supply alternatives that are capable of transporting condensate from the Eagle Ford production area. Competition is based primarily on tariff rates, connectivity, customer service and customer relationships. Eagle Ford production may vary based on numerous factors including overall crude oil prices and changes in costs of production. Demand for our storage at Corpus Christi is subject to similar market conditions and competitive forces.
Our condensate splitter at our Corpus Christi terminal depends on condensate production and overall demand for products derived from condensate, including naphthas and distillates. Our splitter competes with other facilities in the Gulf Coast region including other splitters and refineries, as well as export alternatives.
The Saddlehorn pipeline depends on crude oil production primarily from the DJ Basin and broader Rocky Mountain region for its supply and competes primarily with other pipelines and supply alternatives that are capable of transporting crude oil from the DJ Basin and Rocky Mountain production area. Competition is based primarily on tariff rates, connectivity, customer service and customer relationships. The demand for Saddlehorn’s services could be affected by changes in DJ Basin crude oil production and additional investment in competing transportation alternatives out of the basin, as well as the status of Cushing as a crude oil trading hub. DJ Basin production may vary based on numerous factors including overall crude oil prices and changes in costs of production.
Customers and Contracts. We ship crude oil as a common carrier for several different types of customers, including crude oil producers and end users, such as refiners and marketing and trading companies, including our marketing affiliate. Published transportation tariffs filed with the FERC or the appropriate state agency serve as
contracts to ship on our crude oil pipelines, and shippers nominate volumes to be transported up to a month in advance, with rates varying by origin, destination and product grade. We typically reserve at least 10% of the shipping capacity of our pipelines for spot shippers. Spot barrel movements on our pipelines generally ship at higher rates than those charged to committed shippers. Generally, we seek to secure long-term commitments to support our long-haul crude oil pipeline assets. The majority of the capacity on our Longhorn pipeline is supported by take-or-pay commitments. At December 31, 2020, approximately 70% of the capacity of our Longhorn pipeline was subject to long-term commitments with an average remaining life of approximately six years. Our Houston distribution system is generally not subject to long-term agreements. As of December 31, 2020, approximately 90% of our crude oil storage available for contract was under agreements with terms in excess of one year or that renew on an annual basis at our customers’ option. The average remaining life of our storage contracts was approximately three years as of December 31, 2020. 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 long-term take-or-pay customer commitments. At December 31, 2020, approximately 80% of the capacity of the BridgeTex pipeline was subject to long-term commitments with an average remaining life of four years. At December 31, 2020, approximately 75% of the capacity of the Saddlehorn pipeline was subject to long-term commitments with an average remaining life of six years. Additionally, we have a tolling agreement with one customer for the exclusive use of our condensate splitter in Corpus Christi with a remaining life of approximately two years.
GENERAL BUSINESS INFORMATION
Commodity Positions and Hedges
Our policy is generally to purchase only those products necessary to conduct our normal business activities. We generally do not acquire physical inventory, futures contracts or other derivative instruments for the purpose of speculating on commodity price changes. Our gas liquids blending, fractionation and crude oil 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.
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 rules and orders promulgated pursuant thereto. FERC regulation requires that interstate liquids pipeline rates be filed with the FERC, be posted publicly, be nondiscriminatory, and be “just and reasonable.” Rate changes and the overall level of our rates may be subject to challenge by the FERC or shippers. If 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 40% 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”) plus 0.78%. 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 60% of our refined products pipeline system’s markets are either subject to regulations by the states in which we operate or are approved for market-based rates by the FERC, and in both cases these rates can generally be adjusted at our discretion based on market factors. Most of the tariffs on our long-haul crude oil pipelines are established by negotiated rates that provide for annual adjustments in line with changes in the FERC index, subject to certain modifications.
Some shipments on our pipeline systems that move within a single state are considered to be in intrastate commerce. The rates, terms and conditions of service offered by our intrastate pipelines are subject to certain
regulations with respect to such intrastate transportation by state regulatory authorities in the states of Colorado, Illinois, 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 products 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 met our RVO requirements for 2020 and expect to satisfy the requirements for 2021 through the purchase of credits, known as Renewable Identification Numbers (“RINs”). As the RFS program is currently structured, the RVO of all obligated parties will increase over time unless adjusted by the EPA. The ability to incorporate increasing volumes 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.
Income Taxes. We are a partnership for income tax purposes and, therefore, are not subject to federal or state income taxes for most of the states in which we operate. The tax on our net income is borne by our unitholders through allocation to them of their share of our taxable income. Net income for financial statement purposes may differ significantly from taxable income allocated to unitholders because of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each unitholder’s tax attributes is not available to us.
As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations and Internal Revenue Service pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, we could be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2018, 2019 and 2020, 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 and workplace safety. 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. 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 $14.9 million and $14.3 million at December 31, 2019 and 2020, 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 liabilities arising from sudden and accidental releases of products applicable to all of our assets.
Hazardous Substances and Wastes. Our operations are subject to various laws and regulations that relate to the release of hazardous substances and solid wastes into water or soils. For instance, the Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment.
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. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on, under or from the properties owned or leased by us or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties were previously operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed of or released by prior owners or operators, to remediate contaminated property, including groundwater contaminated by prior owners or operators, or to make capital improvements to prevent future contamination.
Water Discharges. Our operations can result in the discharge of pollutants, including crude oil and refined products, and are subject to the Oil Pollution Act (“OPA”) and Clean Water Act (“CWA”). The OPA and CWA subject owners of facilities to strict, joint and potentially significant liability for removal costs and certain other consequences of a product spill such as natural resource damages, where the product spills into regulated waters, along federal shorelines or in the exclusive economic zone of the U.S. In the event of a product spill from one of our facilities into regulated waters, substantial liabilities could be imposed. States in which we operate have also enacted similar laws. The CWA imposes restrictions and strict controls regarding the discharge of pollutants into regulated waters. This law and comparable state laws require that permits be obtained to discharge pollutants into regulated waters and impose substantial potential liability for non-compliance. Compliance with these laws is not expected to have a material adverse effect on our business, financial position, results of operations or cash flows.
Air Emissions. Our operations are subject to the federal Clean Air Act (“CAA”) and comparable state and local laws and regulations, which regulate emissions of air pollutants from various industrial sources, including certain of our facilities, and impose various operating, monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or increase air emissions, obtain and strictly comply with air permits and regulations
containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe that our operations will not be materially adversely affected by such requirements.
Greenhouse Gas Emissions. The EPA has adopted regulations under existing provisions of the CAA that require certain large stationary sources to obtain pre-construction permits and operating permits for greenhouse gas emissions. In addition, the EPA requires the monitoring and reporting of greenhouse gas emissions from certain large greenhouse gas emissions sources, including petroleum facilities.
Federal and state legislative and regulatory initiatives may attempt to further address climate change or control or limit greenhouse gas emissions. Although it is not possible at this time to predict how they would impact our business, any such future laws or regulations could adversely affect demand for the products that we transport, store and distribute. Depending on the particular programs adopted, they could also increase our costs to operate and 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 assets and operations.
Pipeline Safety and Maintenance. Our pipeline systems are subject to regulation by the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”) under the Hazardous Liquid Pipeline Safety Act of 1979, as amended (“HLPSA”). The HLPSA prescribes and enforces minimum federal safety standards for the transportation of hazardous liquids by pipeline, including the design, construction, testing, operation and maintenance, spill response planning, and overall reporting and management related to our pipeline facilities. In addition to the amended HLPSA covered in Title 49 of the Code of Federal Regulations, subsequent statutes provide the framework for the pipeline hazardous liquid safety program and include provisions related to PHMSA’s authorities, administration, and regulatory activities. Most recently, the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020 would require PHMSA to, among other things, issue regulations addressing idled pipelines, the safety of gas gathering pipelines, minimum performance standards for methane leak detection and repair, and gas distribution pipelines’ emergency response plans, responses to over-pressurization events, and maintenance of maps and records of critical pressure control infrastructure. In addition, the act includes the adoption of due process improvements related to PHMSA enforcement, establishes an idle pipe operating status, requires routine reporting to Congress regarding outstanding pipeline rulemaking, and an independent study regarding the cost-benefit of automated shut-off valves. We believe the revised legislation will not have a material impact on our business.
PHMSA is advancing additional rulemakings regarding rupture detection, the installation of remotely controlled valves on newly constructed or entirely replaced hazardous liquid pipelines, and revisions to the required repair criteria for integrity assessments. We believe that compliance with such regulatory changes will not have a material adverse effect on our results of operations.
In addition to regulations applicable to all of our pipelines, we have undertaken additional obligations to mitigate potential risks to health, safety and the environment on our Longhorn pipeline. Our compliance with these incremental obligations is subject to the oversight of the U.S. Department of Transportation through PHMSA.
States are largely preempted by federal law from regulating pipeline safety for interstate lines, but most states are certified by the U.S. Department of Transportation to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include requirements for facility design and management in addition to requirements for pipelines.
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. Our assets are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes, which, among other things, require us to organize and disclose information about the hazardous materials used in our operations. Certain parts of this information must be reported to employees, contractors, state and local governmental authorities and local citizens upon request. We are subject to OSHA process safety management regulations and EPA risk management plan rules that are designed to identify and establish procedures to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. Compliance with these laws is not expected to have a material adverse effect on our business, financial position, results of operations or cash flows.
Security. Our assets can be subject to both physical and cyber security regulations depending on the nature of the facility. Some of our assets are regulated by the U.S. Department of Transportation, the EPA, the U.S. Coast Guard and the Department of Homeland Security (“DHS”). Compliance with these regulations is achieved by creating physical security plans, minimal physical security standards, marine terminal security drills and annual security audits of both marine and DHS-regulated facilities. Compliance with these laws is not expected to have a material adverse effect on our business, financial position, results of operations or cash flows.
Title to Properties
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 have not been subordinated to the rights-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 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, property for pipeline purposes was purchased in fee. In some states and under some circumstances, we have the right of eminent domain to acquire rights-of-way and land necessary for our pipelines. In some circumstances, a pipeline may be categorized as abandoned under certain governmental regulations, which may give rise to claims that the underlying easement or permit has been abandoned as well.
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 to all of our assets. Although title to our properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, liens that can be imposed in some jurisdictions for government-initiated action to clean up environmental contamination, liens for current taxes and other burdens, and easements, restrictions and other encumbrances to which the underlying properties were subject at the time of acquisition, we believe that none of
these burdens should materially detract from the value of our properties or from our interest in them or should materially interfere with their use in the operation of our business.
As of December 31, 2020, we had 1,720 employees, primarily concentrated in the central and Gulf Coast regions of the U.S. There were 934 employees assigned to our refined products segment, 253 employees assigned to our crude oil segment and 533 employees assigned to provide G&A services. Approximately 13% of our employees are represented by the United Steel Workers and covered by a collective bargaining agreement that expires in January 2022.
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, 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 the company’s long-term financial performance.
Investing in employee training and development is crucial to retaining top talent and developing our employees into subject matter experts and leaders who solve challenges, fuel innovation and move our business strategy forward. Employees receive training focused on safety, leadership, respect, regulatory compliance and company policies, including our code of 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 operate our assets.
(e) Available Information
Our internet address is www.magellanlp.com. We make available free of charge on or through our website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission.
Item 1A. Risk Factors
The nature of our business activities subjects us to a wide variety of hazards and risks. The following is a summary and a description of the most significant risks relating to our business activities that we have identified. In addition to the factors discussed elsewhere in this Annual Report on Form 10-K, you should carefully consider the risks and uncertainties described below, which could have a material adverse effect on our business, financial condition or results of operations, including our ability to generate cash and make 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, financial condition or results of operation, including our ability to generate cash and make distributions 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;
•Decreased activities of producers, gathering systems, refineries and petroleum pipelines owned and operated by others on which we depend to supply our assets could impact 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.
Capital investment and financial risks
•The market value of our units may be affected by our ability to pay distributions or repurchase our units;
•We do not have the same flexibility as other types of organizations to accumulate cash and retained earnings, and we rely on access to capital to fund growth projects and to refinance existing debt obligations;
•Our business is subject to the risk of a capacity overbuild in the markets in which we operate;
•We are exposed to counterparty risk, and nonpayment or nonperformance by our customers, vendors, joint venture co-owners, lenders or derivative counterparties.
Commodity price volatility
•Reduced volatility in energy prices or new government regulations could discourage our storage customers from holding positions in petroleum products;
•The volume of crude oil we transport and the tariff rates we collect for transportation services partially depend upon unpredictable market differentials between our origin points and our destination points;
•Fluctuations in prices of petroleum products that we purchase and sell could materially adversely affect our results of operations.
•Our business involves many hazards and operational risks, the occurrence of which could materially
adversely affect our financial results;
•Failure to monitor and maintain our physical assets could compromise integrity and result in increased risk of product releases and future maintenance costs;
•Failure of critical information technology systems may impact our ability to operate our assets or manage our businesses.
Cyber-attacks, terrorism and other external threats
•Cyber-attacks and terrorist attacks could result in increased costs or other damage to our business;
•The COVID-19 pandemic has adversely affected, and could continue to adversely affect, our business.
•Our operations are subject to extensive environmental, health, safety and other laws and regulations that
impose significant requirements and costs on us;
•Our customers are subject to extensive environmental, health, safety and other laws and regulations, and any new laws or regulations or changes in the interpretation of existing laws and regulations, including laws and regulations related to hydraulic fracturing, could result in decreased demand for our services;
•Rate regulation, challenges by shippers of the rates we charge on our refined products and crude oil pipelines or changes in the jurisdictional characterization of our assets or activities by federal, state or local regulatory agencies may reduce the amount of cash we generate;
•Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the products that we transport, store or distribute.
MLP structural risks
•Our status as a publicly traded partnership prevents our equity from being included in many prominent equity indices, which reduces the demand for our units from passive investment funds. In addition, some individual investors or investment funds may be unable or unwilling to invest in us for reasons related to our status as a partnership for federal income tax purposes;
•Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
•Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as it not being subject to a material amount of entity-level taxation by individual states or local entities. The IRS could treat us as a corporation or we could otherwise become subject to a material amount of entity-level taxation for state or local tax purposes.
General risk factors
•Our business could be affected adversely by union disputes and strikes or work stoppages by our unionized employees.
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, financial condition or results of operations, including our ability to generate cash and pay distributions.
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 material adverse impacts to our business, financial condition or results of operations.
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 fuel sources, such as ethanol, biodiesel, renewable diesel, renewable gasoline, natural gas, fuel cells, solar power, wind power, electric and battery-powered engines and geothermal energy. Several governments and some automobile manufacturers have announced plans to significantly reduce or eliminate the use of traditional petroleum fuel powered vehicles, and significant increases in the production of electric vehicles are widely expected. In addition, current U.S. laws and
regulations require an increase in the quantity of ethanol, biodiesel and other qualifying renewable fuels used in transportation fuels. Increases in the use of such alternative fuels could have a material adverse impact on the volume of petroleum-based fuels transported, stored or distributed on our pipelines or terminals;
•an increase in transportation fuel economy, whether as a result of a shift by consumers to more fuel-efficient vehicles, technological advances by manufacturers or federal, state or international regulations. Government regulations require increasing improvements in fuel economy standards. These standards are intended to reduce demand for petroleum products and could reduce demand for our services;
•changes in population or changes in consumer preferences, rates of automobile ownership or driving patterns in the markets we serve;
•an increase or decrease in the market prices of petroleum products, which may reduce supply or demand. Petroleum product prices have been volatile in recent years, and that volatility may continue in ways that we are unable to predict;
•higher fuel taxes 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 changes, changing preferences for the type of petroleum products we export or preferences for alternative energy sources.
A decrease in crude oil production in the basins served by our crude oil pipelines could reduce our revenues, which could adversely impact our results of operations and the amount of cash we generate.
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 quality differences, higher costs of crude oil production, exhaustion of reserves, weather or other natural causes, epidemics, adverse regulatory or legal developments, disruptions in financial or credit markets that inhibit production, or lower overall demand for crude oil and the products derived from crude oil. Crude oil prices have historically exhibited significant volatility and are influenced by, among other factors, worldwide and domestic supplies of and demand for crude oil, political and economic developments in often-volatile producing regions, actions taken by OPEC and other non-OPEC countries with large production capacity, technological developments, government regulations, taxes, policies regarding the importing and exporting of crude oil and conditions in global financial markets.
We are unable to predict future prices of crude oil or what impact the crude price environment will have on future production overall or specifically on production in the basins we serve. Lower production in the regions served by our pipelines could result in lower shipments of uncommitted volume or could cause us to be unable to renew our contracts at existing volumes or rates. Any sustained decrease in the production of crude oil in the regions served by our crude oil pipelines could result in 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, thereby reducing our cash flow and our ability to pay distributions.
We depend on producers, gathering systems, refineries and petroleum pipelines owned and operated by others to supply our assets, and any closures, interruptions or reduced activity levels at these facilities may reduce the volumes we transport and store and the amount of cash we generate.
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 materially adversely affect our cash flows and ability to pay distributions.
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 located directly or indirectly connected to our refined products and crude oil pipelines. The closure of a refinery that delivers product to or receives crude from our pipelines could reduce the volumes we transport and the amount of cash we generate. Further, the closure of these or other refineries could result in our 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 results of operations and the amount of cash we generate and our ability to make distributions.
A significant portion of the revenue we earn from transportation, storage and processing services is received pursuant to multi-year contracts negotiated with our customers. Many of those contracts require our customers to pay for our services regardless of market conditions during the contract period. Changing market conditions, including changes in petroleum product supply or demand patterns, competitive factors, forward-price structure, financial market conditions, regulations, accounting rules or other factors could cause our customers to be unwilling to renew their contracts with us when those contracts terminate, or make them willing to renew only at lower rates or for shorter contract periods. Failure by our customers to renew any of their contracts with us on terms and at rates substantially similar to our existing contracts could result in lower utilization of our assets or cause our revenues to decline or be more volatile, any of which could adversely affect our results of operations, financial position and our ability to make distributions.
Capital investment and financial risks
The market value of our units may be affected by our ability to pay distributions or repurchase 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, as well as cash reserves established by our general partner. Our distributable cash flow does not depend solely on profitability, which is affected by non-cash items. As a result, we could pay distributions during periods when we record net losses and could be unable to pay distributions during periods when we record net income. In addition, 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 general partner’s board of directors authorized the repurchase of up to $750 million of our common units through 2022. 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 some of the factors used to determine our ability to pay distributions. 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 the value of our unit price.
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 reduce our cash flows and ability to pay distributions or repurchase our units.
Our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash, after taking into account reserves established by the board of directors of our general partner for commitments and contingencies, including capital investments, operating costs and debt service requirements. In addition, our general partner’s board of directors authorized the repurchase of up to $750 million of our common units through 2022. We do not accumulate equity in the form of retained earnings in a manner typical of many other forms of organization, including most traditional public corporations, and so are more likely than those organizations to require issuances of additional capital 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 can be effected quickly, 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 such 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 partnership, and decreases in the availability of credit 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, result in the dilution of the interests of our existing unitholders, and materially reduce our liquidity, our financial flexibility, our cash flows and our ability to pay distributions.
Our business is subject to the risk of a capacity overbuild 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. For example, we have invested significantly in pipelines to deliver crude oil from the Permian Basin in west Texas to markets along the U.S. Gulf Coast and from the DJ Basin in Colorado to Cushing, Oklahoma. The success of these and similar projects largely relies on the realization of anticipated market demand, and these projects typically require significant development periods, during which time demand for such infrastructure may change, or additional investments by competitors may be made. For example, the development of new pipeline capacity from the Permian Basin has resulted in takeaway capacity that significantly exceeds current production. This 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, resulting in lowering the rates we are able to charge for our transportation services. 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 materially adversely affect our results of operations, financial position or cash flows, as well as our ability to pay distributions.
We are exposed to counterparty risk. Nonpayment, commitment termination or 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 results of operations, financial position or cash flows and our ability to pay distributions.
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 or termination of those commitments resulting from our inability to timely meet our obligations could result in substantial losses to us. Nonperformance by customers who back our capital projects could significantly impact our expected return from those projects.
We have undertaken numerous projects that require cooperation with and performance by joint venture co-owners. Nonperformance by our joint venture co-owners could result in increased costs or delays that could decrease our returns on our joint venture projects.
We utilize third-party vendors to provide various functions, including, for example, certain construction activities, engineering services, facility inspections and operation of certain software systems. Using third parties to provide these functions has the effect of reducing our direct control over the services rendered. The failure of one or more of our third-party providers to deliver the expected services on a timely basis at the prices we expect and as required by contract could result in significant disruptions, costs to our operation or instances of a contractor’s non-compliance with applicable laws and regulations, which could materially adversely affect our business, financial condition, operating results or cash flows.
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 take-or-pay commitment terminations or substantial increase in the nonpayment or nonperformance by our customers, vendors, lenders or derivative counterparties could have a material adverse effect on our results of operations, financial position or cash flows and our ability to pay distributions.
Changes in price levels could negatively impact our revenue, our expenses, or both, which could materially adversely affect our results from operations, our liquidity and our ability to pay distributions.
The operation of our assets and the execution of expansion projects require significant expenditures for labor, materials, property, equipment and services. Increases in the cost of these items could materially increase our expenses or capital costs and we may not be able to pass these increased costs on to our customers in the form of higher fees for our services. Because we use the FERC’s PPI-based price indexing methodology to establish tariff rates in certain markets served by our pipelines, our revenues may be impacted by changes in price levels. In periods of general price deflation, the ceiling level provided for by the FERC’s index methodology could decrease requiring us to reduce our index-based rates, even if the actual costs we incur to operate our assets increase. Changes in price levels that lead to decreases in our revenue or increases in the prices we pay to operate and maintain our assets could materially adversely affect our results of operations, financial position or cash flows, as well as our ability to pay distributions.
Our expansion projects may not immediately produce operating cash flows and may exceed our cost estimates or experience delays.
We may pursue large expansion projects that require us to make significant capital investments. We may finance those projects primarily with new borrowings, and we may incur financing costs during the planning and construction phases of these projects; however, the operating cash flows we expect these projects to generate may
not materialize until sometime after the projects are completed, if at all. As a result, our indebtedness relative to our earnings could increase during the period prior to the generation of those operating cash flows. In addition, the amount of time and investment necessary to complete these projects could materially exceed the estimates we used when determining whether to undertake them.
Similarly, we typically must secure and retain required permits and rights-of-way in order to complete and operate these projects, 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 encounter opposition from political activists, who may attempt to delay energy infrastructure construction through protests, lawsuits and other means. Further, in many instances, the operations of our expansion projects are subject to the completion by third parties of connections or other related projects that are beyond our control. Delays or unanticipated costs associated with these third parties in the completion of these related projects could result in delays or cost overruns in the start-up of our own projects. In addition, we run the risk of failing to meet commitments to our customers as a result of project delays, which in some cases could allow our customers to terminate their commitments to us or otherwise negatively impact customer relationships and future financial results. Any cost overruns or unanticipated delays in the completion or commercial development of our expansion projects could reduce the anticipated returns on these projects, which in turn could materially increase our leverage and reduce our liquidity and our ability to pay distributions.
The amount and timing of distributions to us from our joint ventures is not within our control, and we may be unable to cause our joint ventures to take or refrain from taking certain actions that may be in our best interest. In addition, as operator of most of our joint ventures, we are exposed to additional risk and liability in connection with our responsibilities in that capacity.
As of December 31, 2020, 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 of operations, cash flows and our ability to pay distributions.
In the case of Double Eagle and Seabrook, an affiliate of our joint venture co-owner serves as operator, and consequently we rely on affiliates of our joint venture co-owner for many of the management functions of those joint ventures. Without the cooperation of the other owners of those joint ventures, we may not be able to cause our joint ventures to take or not take certain actions, even though those actions or inactions may be in the best interest of us or the particular joint venture. With respect to our other joint ventures, we are the operator, which exposes us to additional risk and liability in connection with our responsibilities in that capacity.
If we are unable to agree with our joint venture co-owners on a significant matter, it could result in delays, litigation or operational impasses that could result in a material adverse effect on that joint venture’s financial condition, results of operations or cash flows. If the matter is significant to us, it could result in a material adverse effect on our results of operations, financial position or cash flows. If we fail to make a required capital contribution, we could be deemed to be in default under the applicable joint venture agreement. Our joint venture co-owners may be permitted to pursue a variety of remedies, including funding any deficiency resulting from our failure to make such capital contribution, which would result in a dilution of our ownership interest, or, in some cases, our joint venture co-owners may have the option to purchase all of our existing interest in the subject joint venture.
Moreover, subject to certain limitations in the respective joint venture agreements, any joint venture owner may sell or transfer its ownership interest in a joint venture, whether in a transaction involving third parties or the other joint venture owners. Any such transaction could result in our being co-owners with different or additional parties with whom we have not had a previous relationship or who may not provide the same strengths and benefits as prior co-owners.
Commodity price volatility
Reduced volatility in energy prices or new government regulations could discourage our storage customers from holding positions in petroleum products, which could adversely affect the demand for our storage services.
The demand for our storage services has resulted in part from our customers’ desire to have the ability to take advantage of profit opportunities created by the volatility in prices of petroleum products. Periods of prolonged stability in petroleum product prices or extended declining trends of 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 materially reduce the amount of cash we generate.
The volume of crude oil we transport and the tariff rates we collect for transportation services partially depend upon unpredictable market differentials between our origin points and our destination points.
Our tariff rates are established in accordance with federal and state regulations which, in general, permit us to negotiate rates with shippers so long as such negotiated rates are not unduly discriminatory among similarly situated shippers. Applicable regulations and our obligations to certain classes of committed shippers may limit our ability to change our tariff rates. When the difference in market prices for crude oil between our origin points and our destination points is lower than our tariff rates, the volume of product we transport could decline or the revenue we collect could decrease. For example, when the posted tariff rate for transportation on the Longhorn pipeline is higher than the market differential, as experienced in 2020, it is uneconomical for shippers to use Longhorn to move volumes from the Permian Basin to Houston. As a result, we experience lower revenues during such periods, which adversely impacts our results of operations and the amount of cash we generate.
Fluctuations in prices of petroleum products that we purchase and sell could materially adversely affect our results of operations.
We generate product sales revenue from our gas liquids blending and fractionation activities, as well as from the sale of product generated by the operations of our pipelines and terminals. We also maintain product inventory related to these activities. Significant fluctuations in market prices of petroleum products could result in material unrealized gains or losses on transactions we enter to hedge our exposure to commodity price changes. To the extent these transactions have not been designated as hedges for accounting purposes, the associated unrealized gains and losses directly impact our reported results of operations. In addition, significant fluctuations in market prices of petroleum products could result in material losses or lower profits from these activities, thereby reducing the amount of cash we generate and our ability to pay distributions.
We hedge prices of petroleum products by utilizing physical purchase and sale agreements and exchange-traded futures contracts. These hedging arrangements do not eliminate all price risks, could result in fluctuations in quarterly or annual financial results and could result in material cash obligations that could negatively impact our financial position or our ability to pay distributions to our unitholders. Further, non-compliance with our risk management policies and procedures could result in material losses.
We hedge our exposure to price fluctuations for our petroleum products purchase and sale activities by utilizing physical purchase and sale agreements and exchange-traded futures contracts. To the extent these hedges do not qualify for hedge accounting treatment or are not designated as hedges, or if they result in material amounts of ineffectiveness, we could experience material fluctuations in our quarterly or annual reported results of operations. We may be required to post margin in connection with these hedges, which could result in material and unpredictable demands on our liquidity. These contracts may be for the purchase or sale of product in markets for a time frame different from those in which we are attempting to hedge our exposure, resulting in hedges that do not eliminate all price risks. In addition, our product 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. If we incur a material loss related to commodity price risks, including as a result of non-compliance with our risk management policies and procedures, our results of operations or cash flows could be materially negatively impacted. Further, our requirement to post material amounts of margin in connection with our hedges could materially negatively impact our liquidity and our ability to pay distributions to our unitholders.
Our business involves many hazards and operational risks, the occurrence of which could materially adversely affect our results of operations, financial position or cash flows and our ability to pay distributions. Non-compliance with our policies and procedures could result in material losses.
Our operations are subject to many hazards inherent in the transportation and distribution of petroleum products, including releases and fires. In addition, our operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and earthquakes. The risk of natural disasters and other operational risks could result in material losses due to personal injury or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage, and may result in curtailment or suspension of our related operations. Some of our assets are located in or near high consequence areas such as residential and commercial centers or sensitive environments, and the potential damages are even greater in these areas. If a significant accident or event occurs or if any of our employees or agents violate or fail to observe the various policies and procedures we have adopted, including operational policies, safety policies and our code of business conduct, it could materially adversely affect our results of operations, financial position or cash flows and our ability to pay distributions.
Failure to monitor and maintain our physical assets could compromise integrity and result in increased risk of product releases and future maintenance costs.
We utilize risk management systems and technologies to manage the physical asset risks associated with our pipeline systems and storage tanks. Our pipeline and storage assets are generally long-lived assets, some of which have been in service for decades. Failure of those management systems and technologies 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 increase in these expenditures, costs or liabilities could materially adversely affect our results of operations, financial position or cash flows, as well as our ability to pay distributions.
Our insurance coverage may not be adequate to cover losses sustained, and we may experience increased costs and decreased availability of insurance options.
We are not fully insured against all hazards or operational risks related to our businesses, and the insurance we carry requires that we meet certain deductibles before we can collect for any covered losses we sustain. If a significant accident or event occurs that is not fully insured, it could materially adversely affect our results of operations, financial position or cash flows and our ability to pay distributions.
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 materially affect our results of operations, financial position or cash flows and our ability to pay distributions.
Failure of critical information technology systems may materially impact our ability to operate our assets or manage our businesses.
We utilize information technology systems to operate our assets and manage our businesses. Some of these systems are proprietary systems that require specialized programming capabilities, while others are based upon or rely on technology that has been in service for many years. Failures of these systems could result in a failure of critical operational or financial controls and lead to a disruption of our operations, commercial activities or financial processes. Such failures could materially adversely affect our results of operations, financial position or cash flow, as well as our ability to pay distributions.
Cyber-attacks, terrorism and other external threats
Cyber-attacks, 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 materially increased costs or other damage to our business.
We rely on our information technology infrastructure to process, transmit and store electronic information, including information we use to operate our assets. In addition, we rely on third-party systems, including for example the electric grid and cloud-based software services, which could also be subject to security breaches or cyber-attacks, 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, which could include threats to our control systems and safety systems that operate our pipelines and other assets. We could face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, including state-sponsored groups, “hacktivists” or private individuals. The age, operating systems or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could adversely affect our ability to resist cybersecurity threats. We could also face attempts to obtain unauthorized access by targeting acts of deception against individuals with legitimate access to physical locations or information.
Breaches in our information technology infrastructure or physical facilities, or other disruptions including those arising from theft, vandalism, fraud or unethical conduct, could result in damage to our assets, unnecessary waste, safety incidents, damage to people, property and the environment, reputational damage, potential liability or the loss of contracts, and could materially adversely affect our results of operations, financial position or cash flows, as well as our ability to pay distributions.
Terrorist attacks aimed at our facilities or that impact our customers or the markets we serve could materially 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. The threat of terrorist attacks subjects our
operations to increased risks. Any terrorist attack on our facilities, those of our customers or, in some cases, on energy infrastructure owned by others, could have a material adverse effect on our business. Similarly, any terrorist attack that severely disrupts the markets we serve could materially adversely affect our results of operations, financial position or cash flows, as well as our ability to pay distributions.
The COVID-19 pandemic has adversely affected and could continue to materially and adversely affect our business.
The COVID-19 pandemic has negatively impacted the global economy. In response to the pandemic, governments around the world have implemented stringent measures to help reduce the spread of the virus, including stay-at-home orders, travel restrictions and other measures. Due to reductions in economic activity, the world is experiencing reduced demand for petroleum products and depressed petroleum products commodity prices, which has adversely affected our business. Continuing uncertainty regarding the global impact of COVID-19 is likely to result in continued weakness in demand for the services we provide. The reduction in refined products demand and lower crude oil prices have combined to put significant downward pressure on domestic crude oil production, and a sustained reduction in crude oil production could cause delays in the timing of our recognition of revenue from take-or-pay pipeline transportation commitments. These events have and will continue to materially and adversely affect our business.
Our operations are subject to extensive environmental, health, safety and other laws and regulations that impose significant requirements, costs and liabilities on us. These requirements, costs and liabilities could increase as a result of new laws or regulations or changes in the interpretation, implementation or enforcement of existing laws and regulations. Our customers are also subject to extensive environmental, health, safety and other laws and regulations, and any new laws or regulations or changes in the interpretation, implementation or enforcement of existing laws and regulations, including laws and regulations related to hydraulic fracturing, could result in decreased demand for our services.
Our operations are subject to extensive federal, state and local laws and regulations relating to the protection or preservation of the environment, natural resources and human health and safety, including but not limited to the CAA, RCRA, OPA, CWA, CERCLA, HLPSA, ESA, MBTA, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 and OSHA. Such laws and regulations affect almost all aspects of our operations and generally require us to obtain and comply with various environmental registrations, licenses, permits, credits, inspections and other approvals. We incur substantial costs to comply with these laws and regulations, and any failure to comply may expose us to civil, criminal and administrative fees, fines and penalties, and interruptions in our operations that could have a material adverse impact on our results of operations, financial position and prospects. For example, if an accidental release or spill of petroleum products, chemicals or other hazardous substances occurs at or from our pipelines, storage or other facilities, we may experience significant operational disruptions, and we may have to pay a significant amount to remediate the release or spill, pay government penalties, address natural resource damages, compensate for human exposure and property damage, install costly pollution control equipment or undertake a combination of these and other measures. The resulting costs and liabilities could materially adversely affect our results of operations, financial position or cash flows. 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. We cannot ensure that these laws and regulations will not be further revised or that new laws or regulations will not be adopted or become applicable to us. For instance, in October 2019, PHMSA modified its
existing hazardous liquid pipeline regulations, requiring integrity assessments at least once every 10 years for pipeline segments located outside of high consequence areas (“HCAs”) and requires all pipelines in HCAs to be capable of accommodating in-line inspection tools within 20 years unless basic construction cannot accommodate in-line inspection tools effective July 1, 2020. In addition, changes in permitting processes, such as the Nationwide Permit Program under the CWA, could impact our ability to develop new projects or maintain our existing assets. Compliance with such legislative and regulatory changes could increase our compliance costs, make it more difficult to construct or maintain our assets and have a material adverse effect on our results of operations.
Our customers are also subject to extensive laws and regulations that affect their businesses, and new laws or regulations could materially adversely affect their businesses. For example, several of our most significant customers are refineries whose businesses 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 who largely depend on production techniques, such as hydraulic fracturing, that are currently being scrutinized by some governmental authorities and have encountered political opposition that could result in increased regulatory costs or delays. We are unable to predict the ultimate outcome of any such future legislative or regulatory activity. 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, or that result in delays or cancellations of their projects, could reduce demand for our services and materially adversely affect our results of operations, financial position or cash flows and our ability to pay cash distributions.
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.
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 petroleum products pipelines may change over time, which may change 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 with or without such a protest or complaint. Further, other than for rates set under market-based rate authority, the FERC may order refunds of amounts collected under interstate rates that are determined to be in excess of a just and reasonable level. State regulatory authorities could take similar measures for intrastate tariffs. In addition, shippers may challenge by complaint the lawfulness of tariff rates that have become final and effective. If existing rates are determined to be in excess of a just and reasonable level, we could be required to pay refunds to shippers, reduce rates and make other concessions.
The FERC’s ratemaking methodologies may limit our ability to set rates based on our actual costs or may delay the use of rates that reflect increased costs. The FERC’s primary ratemaking methodology applicable to us is price indexing. We use this methodology to establish our rates in approximately 40% of the markets for our refined products pipelines. The FERC’s indexing methodology is subject to review every five years and currently allows a pipeline to change its rates each year to a new ceiling level, which is calculated as the previous year’s ceiling level multiplied by a percentage. 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 PPI-FG plus 0.78%. When the ceiling level is negative, as it is anticipated to be in 2021, we are required to reduce our rates that are subject to the FERC’s price indexing methodology.
The FERC and 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 60% of the markets for our refined products pipelines. The tariffs on most of our crude oil pipelines are at negotiated rates, but are still subject to regulation by the FERC or state agencies and subject to protest by shippers. If we were to lose our market-based rate authority, or if our negotiated rates were determined to not be just and reasonable, we could be required to establish rates on some other basis, such as our cost-of-service. We could also consider a cost-of-service filing if the indexing methodology did not provide a reasonable return on
our assets due to cost increases in excess of the index or significantly declining transportation volumes. However, a cost-of-service filing could be limited in scope, unsuccessful, or even result in a tariff reduction, which could materially adversely reduce our revenues.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the products that we transport, store or distribute.
Federal and state legislative and regulatory initiatives in the U.S., as well as those in other countries, have attempted to and will continue to address climate change and control or limit greenhouse gas emissions. Although it is not possible to predict how they will impact our business, any such laws or regulations could adversely affect demand for the products that we transport, store and distribute. Depending on the particular programs adopted, they could also increase our costs to operate and maintain our facilities by requiring that we measure and report our emissions, install new emission controls on our facilities, acquire allowances to authorize our emissions, pay taxes related to our emissions and administer and manage an emissions program, among other things. We may be unable to include some or all of such increased costs in the rates charged to our customers and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before the FERC or state regulatory agencies and the provisions of any final legislation or implementing regulations.
Finally, certain scientific studies conclude that increasing concentrations of greenhouse gases in the Earth’s atmosphere effect 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 material adverse effects on our assets and operations.
Our gas liquids blending activities subject us to federal regulations that govern renewable fuel requirements in the United States.
The Energy Independence and Security Act of 2007 expanded the required use of renewable fuels in the United States. Each year, the EPA establishes an RVO requirement for refiners and fuel manufacturers based on overall quotas established by the federal government. By virtue of our gas liquids blending activity and resulting gasoline production, we are an obligated party and receive an annual RVO from the EPA. We typically purchase renewable energy credits, called RINs, to meet this obligation. RINs are generated when a gallon of renewable fuels such as ethanol or biodiesel is produced. RINs may be separated when the renewable fuel is blended into gasoline or diesel, at which point the RIN is available for use in compliance or is available for sale on the open market. Increases in the cost or decreases in the availability of RINs could have a material adverse impact on our results of operations, cash flows and distributions.
Our business is subject to federal, state, local and international laws and regulations that govern the quality specifications of the petroleum products that we store, transport or sell.
Petroleum products that we store and transport are sold by our customers for consumption into the public market. Various federal, state and local agencies, as well as international regulatory bodies, have the authority to prescribe specific product quality specifications for commodities sold into the public market. Changes in product quality specifications or blending requirements could reduce demand, reduce our throughput volume, require us to incur additional handling costs or require capital expenditures. For instance, different product specifications for different markets impact the fungibility of the products in our system and could require the construction of additional storage. If we are unable to recover these costs through increased revenue, our cash flows and ability to pay distributions could be materially adversely affected.
In addition, changes in the quality of the products we receive on our refined products pipeline, or changes in the product specifications in the markets we serve, could reduce or eliminate our ability to blend products, which would result in a reduction of our revenue and operating profit from blending activities. Any such reduction of our revenue or operating profit could have a material adverse effect on our results of operations, financial position, cash flows and ability to pay distributions.
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. In those instances, we obtain the rights to construct and operate our pipelines on land owned by third parties or governmental agencies and sometimes those rights are only for a specific period of time. In addition, some of our facilities cross Native American lands pursuant to rights-of-way of limited terms. We may not be able to utilize the right of eminent 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 expansion 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 a material adverse effect on our business, financial condition, results of operations, cash flows and our ability to make distributions to unitholders.
MLP structural risks
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 enjoy 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 “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.
Our tax treatment or the tax treatment of our unitholders could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. From time to time the U.S. government considers substantive changes to the existing federal income tax laws that affect publicly traded partnerships. We are unable to predict whether any such additional legislation or any other tax-related proposals will ultimately be enacted. Moreover, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Any such changes could materially 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 materially reduce the cash available for distribution to our unitholders.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.
The IRS has made no determination as to our status as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders as the costs will reduce our cash available for distribution.
The IRS may challenge aspects of our proration method, and, if successful, we would be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The U.S. Department of Treasury and the IRS issued Treasury 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 may be required to pay taxes on their share of our income 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 even if they receive no distributions from us. Our unitholders may not receive distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
Tax gain or loss on disposition of our common units could be more or less than expected.
If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to our unitholders in excess of the total net taxable income they were allocated for a common unit, which decreased their tax basis in that common unit, will, in effect, become taxable income to our unitholders if the common unit is sold at a price greater than their tax basis in that common unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of
nonrecourse liabilities, if our unitholders sell their common units, they may incur a tax liability in excess of the amount of cash received from the sale.
Tax-exempt entities and foreign persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans, individual retirement accounts (known as IRAs) and foreign persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to foreign persons will be reduced by withholding taxes at the highest applicable effective tax rate, and foreign persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. Upon the sale, exchange or other disposition of a common unit by a foreign person, the transferee is generally required to withhold 10% of the amount realized on such sale, exchange or other disposition if any portion of the gain on such sale, exchange or other disposition would be treated as effectively connected with a U.S. trade or business. The U.S. Department of the Treasury and the IRS have recently issued final regulations providing guidance on the application of these rules for transfers of certain publicly traded partnership interests, including transfers of our common units. Under these regulations, the “amount realized” on a transfer of our common units will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and such broker will generally be responsible for the relevant withholding obligations. Distributions to foreign persons may also be subject to additional withholding under these rules to the extent a portion of a distribution is attributable to an amount in excess of our cumulative net income that has not previously been distributed. The U.S. Department of the Treasury and the IRS have provided that these rules will generally not apply to transfers of, or distributions on, our common units occurring before January 1, 2022.
Our unitholders may be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.
In addition to federal income taxes, our unitholders may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders may be required to file tax returns and pay taxes in some or all of these various jurisdictions or be subject to penalties for failure to comply with those requirements. We currently own assets and conduct business in 22 states, most of which impose a personal income tax.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
For tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Generally, we expect to elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, but there can be no assurance that such election will be made, or applicable, in all circumstances. If we are unable to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, our current unitholders may bear some or all of the economic burden resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced.
General risk factors
Our business could be affected adversely by union disputes and strikes or work stoppages by our unionized employees.
As of December 31, 2020, approximately 13% of our workforce was covered by a collective bargaining agreement expiring January 2022. We could experience a work stoppage in the future as a result of disagreements with these labor unions. A prolonged work stoppage could have a material adverse effect on our business activities, results of operations and cash flows.
Item 1B.Unresolved Staff Comments
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 Midstream Partners, L.P. (“Magellan”) and Powder Springs Logistics, LLC (“Powder Springs”) are infringing patents related to butane blending at the Powder Springs facility located in Powder Springs, Georgia. Sunoco subsequently submitted pleadings alleging that Magellan is also infringing various patents related to butane blending at nine Magellan facilities, in addition to Powder Springs. Sunoco is seeking monetary damages, attorneys’ fees and a permanent injunction enjoining Magellan and Powder Springs from infringing the subject patents. We deny and are vigorously defending against all claims asserted by Sunoco. Although it is not possible to predict the outcome, we believe the ultimate resolution of this matter will not have a material adverse impact on our results of operations, financial position or cash flows.
Hurricane Harvey Enforcement Proceeding. In July 2018, we received a Notice of Enforcement letter from the Texas Commission on Environmental Quality alleging two air emission violations at our Galena Park, Texas terminal that occurred during Hurricane Harvey in third quarter 2017. The penalties associated with these alleged violations could exceed $300,000. While the results cannot be predicted with certainty, we believe the ultimate resolution of this matter will not have a material impact on our results of operations, financial position or cash flows.
We and the non-controlled entities in which we own an interest are a party to various other claims, legal actions and complaints. While the results cannot be predicted with certainty, management believes the ultimate resolution of these claims, legal actions and complaints, after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect on our future results of operations, financial position or cash flows.
Item 4.Mine Safety Disclosures
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 17, 2021, we had 223,282,818 common units outstanding that were owned by approximately 150,000 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 $1.0275 per common unit. In general, we intend to maintain our distribution at the current level; however, we cannot guarantee that future distributions will continue at current levels.
Issuer Purchases of Common Units
In first quarter 2020, we announced that our general partner’s board of directors authorized the repurchase of up to $750 million of our common units through 2022. We intend to purchase our common units from time-to-time through a variety of methods, including open market purchases and negotiated transactions, all in compliance with the rules of the Securities and Exchange Commission and other applicable legal requirements. The timing, price and actual number of common units repurchased will depend on a number of factors including our expected expansion capital spending, excess cash available, balance sheet metrics, legal and regulatory requirements, market conditions and the trading price of our common units. The repurchase program does not obligate us to acquire any particular amount of common units and may be suspended or discontinued at any time.
Unit repurchase activity during 2020 is detailed in the following table:
|Period||Total Number of Common Units Purchased||Average Price Paid Per Unit||Total Number of Units Purchased as Part of Publicly Announced Program||Approximate Dollar Value of Units That May Yet Be Purchased under the Program (in millions)|
|January 1-31, 2020||— ||$||— ||— ||$||750.0 |
|February 1-29, 2020||1,514,719 ||$||59.19 ||1,514,719 ||$||660.4 |
|March 1-31, 2020||2,117,065 ||$||53.06 ||2,117,065 ||$||548.1 |
|First Quarter 2020||3,631,784 ||$||55.62 ||3,631,784 |
|April 1-30, 2020||— ||— ||$||548.1 |
|May 1-31, 2020||— ||— ||$||548.1 |
|June 1-30, 2020||— ||— ||$||548.1 |
|Second Quarter 2020||— ||— |
|July 1-31, 2020||— ||— ||$||548.1 |
|August 1-31, 2020||— ||— ||$||548.1 |
|September 1-30, 2020||1,355,344 ||$||36.87 ||1,355,344 ||$||498.0 |
|Third Quarter 2020||1,355,344 ||$||36.87 ||1,355,344 |
|October 1-31, 2020||— ||— ||$||498.0 |
|November 1-30, 2020||266,703 ||$||41.24 ||266,703 ||$||487.1 |
|December 1-31, 2020||314,429 ||$||44.50 ||314,429 ||$||473.1 |
|Fourth Quarter 2020||581,132 ||$||43.00 ||581,132 |
|Year Ended 2020||5,568,260 ||$||49.74 ||5,568,260 |
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, 2015 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.
|S&P 500 Energy||$100||$127||$126||$103||$115||$77|
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.
Item 6.Selected Financial Data
We have derived the summary selected historical financial data from our current and historical accounting records. Information concerning significant trends in our financial condition and results of operations is contained in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Our operating results incorporate a number of significant estimates and uncertainties. Such matters could cause the data included herein not to be indicative of our future financial condition or results of operations. A discussion of our critical accounting estimates and how these estimates could impact our future financial condition or results of operations is included in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Item 7 of this report. In addition, a discussion of the risk factors that could affect our business and future financial condition or results of operations is included under Item 1A. Risk Factors of this report. Further, the notes to our financial statements under Item 8. Financial Statements and Supplementary Data of this report include descriptions of areas where estimates and judgments could result in different amounts being recognized in our accompanying consolidated financial statements.
We believe that investors benefit from having access to the same financial measures utilized by management. In the following tables, we present the financial measure of distributable cash flow (“DCF”), which is not a generally accepted accounting principles (“GAAP”) measure. Our partnership agreement requires that all of our available cash, less amounts reserved by our general partner’s board of directors, be distributed to our unitholders. Management uses DCF to determine the amount of cash that our operations generated that is available for distribution to our unitholders and as a basis for recommending to our general partner’s board of directors the amount of distributions to be paid each period. We also use DCF as the basis for calculating our equity-based long-term incentive compensation. A reconciliation of DCF to net income, the nearest comparable GAAP measure, is included in the following tables.
In addition to DCF, the non-GAAP measures of operating margin (in the aggregate and by segment) and Adjusted EBITDA are presented in the following tables. A reconciliation of operating margin to operating profit and net income to Adjusted EBITDA, which are the nearest comparable GAAP financial measures, are included in the following tables. See Note 3 – Segment Disclosures under Item 8. Financial Statements and Supplementary Data of this report for a reconciliation of segment operating margin to segment operating profit. Operating margin is computed using amounts that are determined in accordance with GAAP and is an important measure of the economic performance of our core operations. Operating profit, alternatively, includes depreciation, amortization and impairment expense and general and administrative (“G&A”) expense that management does not focus on when evaluating the core profitability of our separate operating segments. Adjusted EBITDA is an important measure utilized by management and the investment community to assess the financial results of a company.
Since the non-GAAP measures presented here include adjustments specific to us, they may not be comparable to similarly-titled measures of other companies.
| ||Year Ended December 31,|
| ||(in thousands, except per unit amounts)|
|Income Statement Data:|
|Transportation and terminals revenue||$||1,591,119 ||$||1,731,775 ||$||1,878,988 ||$||1,970,630 ||$||1,794,854 |
|Product sales revenue||599,602 ||758,206 ||927,220 ||736,092 ||611,719 |
|Affiliate management fee revenue||14,689 ||17,680 ||20,365 ||21,190 ||21,229 |
|Total revenue||2,205,410 ||2,507,661 ||2,826,573 ||2,727,912 ||2,427,802 |
|Operating expenses||528,672 ||577,978 ||649,436 ||634,081 ||601,359 |
|Cost of product sales||493,338 ||635,617 ||704,313 ||619,279 ||513,715 |
|Subtotal||1,183,400 ||1,294,066 ||1,472,824 ||1,474,552 ||1,312,728 |
|Other operating income (expense)||— ||— ||— ||2,975 ||101 |
|Earnings of non-controlled entities||78,696 ||120,994 ||181,117 ||168,961 ||153,327 |
|Operating margin||1,262,096 ||1,415,060 ||1,653,941 ||1,646,488 ||1,466,156 |
|Depreciation, amortization and impairment expense||178,142 ||196,630 ||265,077 ||246,134 ||258,676 |
|G&A expense||147,165 ||165,717 ||194,283 ||196,650 ||173,478 |
|Operating profit||936,789 ||1,052,713 ||1,194,581 ||1,203,704 ||1,034,002 |
|Interest expense, net||165,410 ||193,718 ||200,514 ||198,554 ||221,826 |
|Gain on disposition of assets||(28,144)||(18,505)||(353,797)||(28,966)||(12,887)|
|Other (income) expense||(6,466)||4,139 ||13,868 ||11,830 ||5,164 |
|Income before provision for income taxes||805,989 ||873,361 ||1,333,996 ||1,022,286 ||819,899 |
Provision for income taxes
|3,218 ||3,830 ||71 ||1,437 ||2,934 |
|Net income||$||802,771 ||$||869,531 ||$||1,333,925 ||$||1,020,849 ||$||816,965 |
Basic net income per common unit
|$||3.52 ||$||3.81 ||$||5.84 ||$||4.46 ||$||3.62 |
Diluted net income per common unit
|$||3.52 ||$||3.81 ||$||5.84 ||$||4.46 ||$||3.62 |
|Balance Sheets Data:|
Working capital (deficit)
|Total assets||$||6,772,073 ||$||7,394,375 ||$||7,747,537 ||$||8,437,729 ||$||8,196,982 |
Long-term debt, net
|$||4,087,192 ||$||4,273,518 ||$||4,211,380 ||$||4,706,075 ||$||4,978,691 |
|Partners’ capital||$||2,092,105 ||$||2,129,653 ||$||2,643,434 ||$||2,715,028 ||$||2,303,806 |
Distributions declared per unit(a)
|$||3.32 ||$||3.59 ||$||3.87 ||$||4.07 ||$||4.11 |
Distributions paid per unit(a)
|$||3.25 ||$||3.52 ||$||3.79 ||$||4.04 ||$||4.11 |
| ||Year Ended December 31,|
| ||(in thousands, except operating statistics)|
|Refined products||$||840,181 ||$||934,984 ||$||1,074,705 ||$||1,025,497 ||$||965,813 |
|Crude oil||416,960 ||474,802 ||573,289 ||615,485 ||493,734 |
Allocated partnership depreciation costs(b)
|4,955 ||5,274 ||5,947 ||5,506 ||6,609 |
|Operating margin||$||1,262,096 ||$||1,415,060 ||$||1,653,941 ||$||1,646,488 ||$||1,466,156 |
|Adjusted EBITDA and distributable cash flow:|
|Net income||$||802,771 ||$||869,531 ||$||1,333,925 ||$||1,020,849 ||$||816,965 |
Interest expense, net
|165,410 ||193,718 ||200,514 ||198,554 ||221,826 |
Depreciation, amortization and impairment(c)
|189,332 ||210,000 ||272,522 ||240,874 ||254,586 |
Equity-based incentive compensation(d)
|4,982 ||6,766 ||22,768 ||14,247 ||(2,715)|
Gain on disposition of assets(e)
|64,257 ||12,463 ||(101,987)||88,223 ||14,211 |
|Distributions from operations of non-controlled entities in excess of (less than) earnings for the period||9,293 ||25,216 ||15,584 ||34,641 ||54,273 |
|Other||5,341 ||3,749 ||3,644 ||— ||— |
|Adjusted EBITDA||1,213,242 ||1,302,938 ||1,395,755 ||1,581,108 ||1,348,635 |
Interest expense, net, excluding debt issuance cost amortization(g)
|Distributable cash flow||$||947,484 ||$||1,021,372 ||$||1,109,745 ||$||1,297,464 ||$||1,044,471 |
|Transportation revenue per barrel shipped||$||1.473 ||$||1.495 ||$||1.556 ||$||1.616 ||$||1.675 |
Volume shipped (million barrels):
|Gasoline||275.4 ||295.5 ||286.9 ||280.5 ||270.8 |
|Distillates||150.2 ||166.2 ||181.7 ||184.6 ||175.5 |
|Aviation fuel||25.7 ||26.5 ||31.0 ||41.1 ||21.6 |
|Liquefied petroleum gases||10.4 ||9.9 ||11.0 ||9.7 ||0.9 |
|Total volume shipped||461.7 ||498.1 ||510.6 ||515.9 ||468.8 |
|Magellan 100%-owned assets:|
|Transportation revenue per barrel shipped||$||1.321 ||$||1.348 ||$||1.208 ||$||0.939 ||$||1.028 |
Volume shipped (million barrels)(i)
|187.0 ||196.4 ||242.8 ||317.2 ||229.9 |
|Terminal average utilization (million barrels per month)||16.9 ||17.5 ||18.7 ||23.0 ||25.2 |
|Select joint venture pipelines:|
BridgeTex - volume shipped (million barrels)(j)
|79.0 ||98.4 ||138.2 ||156.3 ||132.0 |
Saddlehorn - volume shipped (million barrels)(k)
|5.2 ||19.0 ||27.4 ||56.1 ||61.6 |
(a)Distributions related to each quarter are declared and paid within 45 days following the close of that quarter. Distributions paid represent actual cash payments for distributions during each of the periods presented.
(b)Certain depreciation expense was allocated to our various business segments, which in turn recognized these allocated costs as operating expense, reducing segment operating margin by these amounts.
(c)Depreciation, amortization and impairment expense is excluded from DCF to the extent it represents a non-cash expense.
(d)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.
(e)Gains on disposition of assets are excluded from DCF to the extent they are not related to our ongoing operations..
(f)See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Distributable Cash Flow for a description of items included in our commodity-related adjustments.
(g)Interest expense includes $8.3 million of debt extinguishment costs in 2019 and $12.9 million in 2020 that are excluded from DCF as they are financing activities and not related to our ongoing operations.
(h)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.
(i)Volume shipped includes shipments related to our crude oil marketing activities. Volume shipped in 2020 reflects a change in the way our customers contract for our services pursuant to which customers are able to utilize crude oil storage capacity at East Houston and dock access at Seabrook. Subsequent to this change, the services we provide no longer include a transportation element. Therefore, revenues related to these services are reflected entirely as terminalling revenues and the related volumes are no longer reflected in our calculation of transportation volumes.
(j)These volumes reflect the total shipments for the BridgeTex pipeline, which was owned 50% by us through September 28, 2018 and 30% thereafter.
(k)These volumes reflect the total shipments for the Saddlehorn pipeline which began operations in September 2016 and was owned 40% by us through January 31, 2020 and 30% thereafter.
Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations
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, 2020, our asset portfolio consisted of:
•our refined products segment, comprised of our approximately 9,800-mile refined petroleum products pipeline system with 54 connected terminals as well as 25 independent terminals not connected to our pipeline system 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 37 million barrels of aggregate storage capacity, of which approximately 27 million barrels are used for contract storage. Approximately 1,000 miles of these pipelines, the condensate splitter and 30 million barrels of this storage capacity (including 24 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, 2020.
See Item 1. Business for a detailed description of our business.
Resilient Business Model. The year 2020 presented the most challenging industry and economic conditions experienced in our 20-year history as a public company. Despite the backdrop of a difficult year, we generated solid financial results while ensuring continuity of critical fuel supply for our nation. Companies like ours are extremely important to keep the United States’ economy moving and our employees worked diligently to ensure our business ran safely throughout the pandemic.
Our nation experienced unprecedented travel and economic restrictions related to COVID-19 and reduced drilling activity from the lower commodity price environment. As a result, our company was negatively impacted by significantly reduced demand for petroleum products, such as gasoline, diesel fuel and crude oil.
However, our resilient business model and financial strength positioned us well to respond not only to the near-term industry challenges but to successfully manage our company for the long term. Even during a pandemic, our company proved to be resilient, and we were able to pay consistent cash distributions to our investors, generate solid distribution coverage and maintain industry-leading leverage well within our long-standing limit.
Our conservative, disciplined approach provides us the confidence to manage our business through this business cycle. We remain optimistic that demand for our services will continue to increase as vaccines become more readily available, travel and economic activity recover and drilling returns due to an improved demand and commodity price environment.
Long-Term Value Creation. We remain focused on delivering long-term value for our investors through a disciplined combination of cash distributions, equity repurchases and capital investments. Construction projects have been a primary source of growth for our company over the years. Although the current environment for large-scale capital investments is challenging and likely to remain so for the foreseeable future, we continue to look for opportunities to invest in attractive, low-risk projects to benefit our future.
Focus on Optimization. Efficiency and discipline are key to our business strategy, and we kicked off an optimization initiative over a year ago to identify opportunities throughout the organization. Our employees have been actively engaged in the process to identify better ways to run our business, with significant progress to date on this effort.
Optimization of our asset portfolio is an important element of our company’s discipline as well. During 2020, we divested three marine terminal facilities outside our strategic footprint to maximize value and our strong financial position.
Sustainability Commitment. Moving What Moves America® represents who we are and our commitment to safely and reliably deliver petroleum products that are essential and beneficial to everyday life.
Sustainability is not new to us. We have focused on long-term, sustainable operations and disciplined management since our creation two decades ago. However, we recognize the growing stakeholder interest in how these principles are incorporated into our daily operations, and we published our inaugural sustainability report last fall.
Our most important social obligation is to safely and reliably provide the fuels that our nation relies on each day, while protecting the communities where we live and work. In addition, we continue to be an industry leader in governance, with an independent board elected by our investors and all-employee annual compensation aligned with key environmental and safety metrics. We remain committed to providing transparency around how we manage and measure our environmental, social and governance performance.
Important Future Role. Looking ahead, investors are understandably curious how potential changes in energy policy could impact the long-term viability of our business. Based on industry and government forecasts, the demand for petroleum products is expected to remain strong for many years to come.
The vast majority of cars, trucks, tractors, locomotives and airplanes today depend on petroleum products to operate, especially in the markets served by our assets. Realistically, energy transition will take decades to accomplish, with petroleum products and Magellan continuing to play important roles in our nation’s energy future.
COVID-19 and Decline in Commodity Prices. The COVID-19 pandemic has negatively impacted the global economy. In response to the pandemic, governments around the world have implemented stringent measures to help reduce the spread of the virus, including stay-at-home orders, travel restrictions and other measures. Due to reductions in economic activity, the world is experiencing reduced demand for petroleum products and depressed commodity prices for petroleum products, which has adversely affected our business. Continuing uncertainty regarding the global impact of COVID-19 is likely to result in continued weakness in demand for the services we provide while the pandemic continues. The reduction in refined products demand and lower crude oil prices have combined to put significant downward pressure on domestic crude oil production, and a sustained reduction in crude oil production could cause delays in the timing of our recognition of revenue from take-or-pay pipeline transportation commitments. These events have and will continue to adversely affect our business. However, we do not believe these events will impact our ability to meet any of our financial obligations or result in any significant impairments to our assets.
Distribution. In January 2021, the board of directors of our general partner declared a quarterly distribution of $1.0275 per unit for the period of October 1, 2020 through December 31, 2020. This quarterly distribution was paid on February 12, 2021 to unitholders of record on February 5, 2021.
Results of Operations
We believe that investors benefit from having access to the same financial measures utilized by management. Operating margin, which is presented in the following table, is an important measure used by management to evaluate the economic performance of our core operations. Operating margin is not a generally accepted accounting principles (“GAAP”) measure, but the components of operating margin are computed using amounts that are determined in accordance with GAAP. A reconciliation of operating margin to operating profit, which is its nearest comparable GAAP financial measure, is included in the following table. Operating profit includes expense items, such as depreciation, amortization and impairment expense and general and administrative (“G&A”) expense, which management does not focus on when evaluating the core profitability of our separate operating segments. Additionally, product margin, which management primarily uses to evaluate the profitability of our commodity-related activities, is provided in this table. Product margin is a non-GAAP measure but its components of product sales revenue and cost of product sales are determined in accordance with GAAP. Our gas liquids blending, fractionation and other commodity-related activities generate significant revenue. However, we believe the product margin from these activities, which takes into account the related cost of product sales, better represents its importance to our results of operations.
Year Ended December 31, 2019 Compared to Year Ended December 31, 2020
|Financial Highlights ($ in millions, except operating statistics)||Year Ended December 31,||Variance|
| ||2019||2020||$ Change||% Change|
|Transportation and terminals revenue:|
|Refined products||$||1,355.6 ||$||1,241.8 ||$||(113.8)||(8)||%|
|Crude oil||620.4 ||559.6 ||(60.8)||(10)||%|
|Total transportation and terminals revenue||1,970.6 ||1,794.9 ||(175.7)||(9)||%|
|Affiliate management fee revenue||21.2 ||21.2 ||— ||— ||%|
|Refined products||471.7 ||425.4 ||46.3 ||10 ||%|
|Crude oil||173.3 ||189.1 ||(15.8)||(9)||%|
|Intersegment eliminations||(10.9)||(13.2)||2.3 ||21 ||%|
|Total operating expenses||634.1 ||601.3 ||32.8 ||5 ||%|
|Product sales revenue||736.1 ||611.7 ||(124.4)||(17)||%|
|Cost of product sales||619.3 ||513.7 ||105.6 ||17 ||%|
|Product margin||116.8 ||98.0 ||(18.8)||(16)||%|
|Other operating income (expense)||3.0 ||0.1 ||(2.9)||(97)||%|
|Earnings of non-controlled entities||169.0 ||153.3 ||(15.7)||(9)||%|
|Operating margin||1,646.5 ||1,466.2 ||(180.3)||(11)||%|
|Depreciation, amortization and impairment expense||246.1 ||258.7 ||(12.6)||(5)||%|
|G&A expense||196.7 ||173.5 ||23.2 ||12 ||%|
|Operating profit||1,203.7 ||1,034.0 ||(169.7)||(14)||%|
Interest expense (net of interest income and interest capitalized)
|198.6 ||221.8 ||(23.2)||(12)||%|
|Gain on disposition of assets||(29.0)||(12.9)||(16.1)||(56)||%|
|Other (income) expense||11.8 ||5.2 ||6.6 ||56 ||%|
|Income before provision for income taxes||1,022.3 ||819.9 ||(202.4)||(20)||%|
|Provision for income taxes||1.5 ||2.9 ||(1.4)||(93)||%|
|Net income||$||1,020.8 ||$||817.0 ||$||(203.8)||(20)||%|
|Transportation revenue per barrel shipped||$||1.616 ||$||1.675 |
Volume shipped (million barrels):
|Gasoline||280.5 ||270.8 |
|Distillates||184.6 ||175.5 |
|Aviation fuel||41.1 ||21.6 |
|Liquefied petroleum gases||9.7 ||0.9 |
|Total volume shipped||515.9 ||468.8 |
|Magellan 100%-owned assets:|
|Transportation revenue per barrel shipped||$||0.939 ||$||1.028 |
Volume shipped (million barrels)(a)
|317.2 ||229.9 |
|Terminal average utilization (million barrels per month)||23.0 ||25.2 |
|Select joint venture pipelines:|
BridgeTex - volume shipped (million barrels)(b)
|156.3 ||132.0 |
Saddlehorn - volume shipped (million barrels)(c)
|56.1 ||61.6 |
(a) Volume shipped includes shipments related to our crude oil marketing activities. Volume shipped in 2020 reflects a change in the way our customers contract for our services pursuant to which customers are able to utilize crude oil storage capacity at East Houston and dock access at Seabrook. Subsequent to this change, the services we provide no longer include a transportation element. Therefore, revenues related to these services are reflected entirely as terminalling revenues and the related volumes are no longer reflected in our calculation of transportation volumes.
(b) These volumes reflect total shipments for the BridgeTex pipeline, which is owned 30% by us.
(c) These volumes reflect the total shipments for the Saddlehorn pipeline, which was owned 40% by us through January 31, 2020 and 30% thereafter.
Transportation and terminals revenue decreased by $175.7 million, resulting from:
•a decrease in refined products revenue of $113.8 million. Transportation volumes decreased primarily due to lower demand during 2020 associated with the ongoing impact from COVID-19 and related restrictions as well as reduced drilling activity in response to the lower commodity price environment. Revenues also decreased due to the sale of three marine terminals in first quarter 2020 and discontinuation of the ammonia pipeline operations in late 2019. These declines were partially offset by contributions from the recently-constructed East Houston-to-Hearne pipeline segment that became operational in late 2019 and the West Texas pipeline expansion that began operations in the third quarter of 2020, as well as an increase in the average tariff rate in the current period as a result of the 2019 and 2020 mid-year adjustments; and
•a decrease in crude oil revenue of $60.8 million. Revenues from our Longhorn pipeline declined due to lower third-party spot shipments resulting from less favorable differentials between the Permian Basin and Houston and the 2020 expiration of several higher-priced contracts, partially offset by the activities of our marketing affiliate. Average tariff rates increased as a result of fewer shipments on our Houston distribution system, which move at a lower rate than longer-haul shipments. Lower transportation volume on our Houston distribution system resulted primarily from a change in the way customers now contract for services at our Seabrook export facility and was offset by incremental revenue from the related terminal transfer fee. Tender deduction revenues also decreased due to lower crude oil prices. These declines were partially offset by increased storage revenues as more contract storage was utilized at higher rates.
Operating expenses decreased $32.8 million, resulting from:
•a decrease in refined products expenses of $46.3 million primarily due to lower throughput activity, less integrity spending due to timing of work, reduced compensation expense and the absence of costs in the current period associated with the sold or discontinued assets, partially offset by less favorable product overages (which reduce operating expenses); and
•an increase in crude oil expenses of $15.8 million primarily due to higher integrity spending, less favorable product overages and additional fees we pay to Seabrook for contract storage and ancillary services that we utilize to provide services to our shippers, partially offset by lower power costs from reduced shipments and our recent optimization efforts.
Product margin decreased $18.8 million primarily due to reduced profitability and lower sales volumes from our gas liquids blending activities, partially offset by lower losses recognized in the current year on futures contracts. See Note 13 – Derivative Financial Instruments in Item 8. Financial Statements and Supplementary Data, as well as Other Items – Commodity Derivative Agreements below, for more information about our futures contracts.
Other operating income decreased $2.9 million in 2020 primarily due to insurance settlements received in 2019 mainly related to Hurricane Harvey, partially offset by lower losses recognized on a basis derivative agreement during the current period.
Earnings of non-controlled entities decreased $15.7 million primarily due to lower earnings from BridgeTex related to decreased uncommitted shipments based on unfavorable market conditions as well as lower earnings from Saddlehorn following the sale of a 10% interest in early 2020. These decreases were partially offset by additional earnings from MVP from the 2020 start-up of newly-constructed storage and dock assets.
Depreciation, amortization and impairment expense increased $12.6 million primarily due to the impairment of certain terminalling assets in 2020.
G&A expense decreased $23.2 million primarily due to lower incentive compensation accruals to reflect the impacts of COVID-19 related reductions in economic activity and the significant decline in commodity prices.
Interest expense, net of interest income and interest capitalized, increased $23.2 million in 2020 primarily due to higher outstanding debt and higher costs associated with early debt retirement, as well as lower capitalized interest (due to lower ongoing construction project spending in 2020). Our average outstanding debt increased from $4.6 billion in 2019 to $4.9 billion in 2020. Our weighted-average interest rate decreased from 4.6% in 2019 to 4.4% in 2020.
Gain on disposition of assets was $16.1 million unfavorable. In 2020, we recognized a gain on the sale of a portion of our interest in Saddlehorn of $12.9 million. In 2019, we recognized a deferred gain of $11.0 million related to the 2018 sale of a portion of our investment in BridgeTex, a gain of $12.7 million related to our discontinued Delaware Basin crude oil pipeline construction project that was sold to a third party and a gain of $5.3 million resulting from the sale of an inactive terminal along our refined products pipeline system.
Other expense was $6.6 million favorable primarily due to lower pension costs.
For a comparative discussion of the years ended December 31, 2018 and 2019, see Part II, Item 7 – “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations” in Exhibit 99.1 to our Form 8-K filed with the Securities and Exchange Commission on May 4, 2020, which reflects changes in our reporting segments since the filing of our Annual Report on Form 10-K for the year ended December 31, 2019.
Distributable Cash Flow
Distributable cash flow (“DCF”) and Adjusted EBITDA are non-GAAP measures. See Item 6. Selected Financial Data for a discussion of how management uses these non-GAAP measures. A reconciliation of DCF and Adjusted EBITDA for the years ended December 31, 2019 and 2020 to net income, which is the nearest comparable GAAP financial measure, is as follows (in millions):
|Year Ended December 31,|
|Net income||$||1,020.8 ||$||817.0 |
|Interest expense, net||198.6 ||221.8 |
Depreciation, amortization and impairment(1)
|240.9 ||254.6 |
Equity-based incentive compensation(2)
Gain on disposition of assets(3)
Derivative (gains) losses recognized in the period associated with future transactions(4)
|29.7 ||29.3 |
Derivative gains (losses) recognized in previous periods associated with transactions completed in the period(4)
Inventory valuation adjustments(5)
|Total commodity-related adjustments||88.2 ||14.2 |
|Distributions from operations of non-controlled entities in excess of (less than) earnings||34.7 ||54.3 |
|Adjusted EBITDA||1,581.1 ||1,348.7 |
Interest expense, net, excluding debt issuance cost amortization(6)
|DCF||$||1,297.5 ||$||1,044.5 |
(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.
(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. In the period in which these transactions are settled and any related products are sold, the net impact of the derivatives is included in DCF.
(5) We adjust DCF for lower of average cost or net realizable value adjustments related to inventory and firm purchase commitments as well as market valuations of short positions recognized each period as these are non-cash items. In subsequent periods when we physically sell or purchase the related products, we adjust DCF for the valuation adjustments previously recognized.
(6) Interest expense includes $8.3 million of debt extinguishment costs in 2019 and $12.9 million in 2020 that are excluded from DCF as they are financing activities and are not related to our ongoing operations.
(7) Maintenance capital expenditures maintain our existing assets and do not generate incremental DCF (i.e. incremental returns to our unitholders). For this reason, we deduct maintenance capital expenditures to determine DCF.
Liquidity and Capital Resources
Cash Flows and Capital Expenditures
Operating Activities. Net cash provided by operating activities was $1,321.2 million and $1,107.4 million for the years ended December 31, 2019 and 2020, respectively. The $213.8 million decrease from 2019 to 2020 was due to lower net income as previously described and changes in our working capital, partially offset by adjustments for non-cash items and distributions in excess of earnings of our non-controlled entities.
Investing Activities. Net cash used by investing activities for the years ended December 31, 2019 and 2020 was $1,007.3 million and $199.2 million, respectively. During 2020, we used $439.6 million for capital expenditures, which included $0.2 million for undivided joint interest projects for which cash was received from a third party. Also, during 2020, we sold three marine terminals for cash proceeds of $251.8 million and sold a portion of our interest in Saddlehorn for cash proceeds of $79.9 million. Additionally, we made net capital contributions of $94.6 million to our joint ventures, which we account for as investments in non-controlled entities. During 2019, we used $944.0 million for capital expenditures, which included $92.1 million for undivided joint interest projects for which cash was received from a third party. Additionally, we made net capital contributions of $203.9 million to our joint ventures, of which $198.9 million related to capital projects.
Financing Activities. Net cash used by financing activities for the years ended December 31, 2019 and 2020 was $538.6 million and $970.3 million, respectively. During 2020, we paid distributions of $927.1 million to our unitholders and made common unit repurchases of $276.9 million. Additionally, we received net proceeds of $828.4 million from the issuance of long-term senior notes, which were used to repay our $550.0 million of 4.25% notes due 2021 and outstanding commercial paper borrowings at that time. Also, in January 2020, our equity-based incentive compensation awards that vested December 31, 2019 were settled by issuing 284,643 common units and distributing those units to the long-term incentive plan (“LTIP”) participants, resulting in payments primarily associated with tax withholdings of $14.7 million. During 2019, we paid distributions of $921.6 million to our unitholders. Additionally, we received net proceeds of $996.4 million from borrowings under long-term notes, which were used to repay our $550.0 million of 6.55% notes due 2019 and outstanding commercial paper borrowings at that time. Also, in January 2019, our equity-based long-term incentive compensation awards that vested December 31, 2018 were settled by issuing 208,268 common units and distributing those units to the LTIP participants, resulting in payments primarily associated with tax withholdings of $9.8 million.
The quarterly distribution amount related to fourth quarter 2020 earnings was $1.0275 per unit, which was paid in February 2021. If we were to continue paying distributions at this level on the number of common units currently outstanding, total distributions of approximately $918 million would be paid to our unitholders related to 2021 earnings. Management believes we will have sufficient DCF to fund these distributions.
For a discussion of cash flows for the year ended December 31, 2018, see Part I, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” in Exhibit 99.1 to our Form 8-K filed with the Securities and Exchange Commission on May 4, 2020, which reflects changes in our reporting segments since the filing of our Annual Report on Form 10-K for the year ended December 31, 2019.
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 or construct 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 2020, our maintenance capital spending was $98.7 million. For 2021, we expect to spend approximately $85 million on maintenance capital projects.
During 2020, we spent $259.8 million for our expansion capital projects and contributed $94.6 million for expansion capital projects in conjunction with our joint ventures. Based on the progress of projects already
underway, we expect to spend approximately $75 million in 2021 to complete our current slate of expansion capital projects.
Cash generated from operations is a key source of liquidity for funding debt service, maintenance capital expenditures, quarterly distributions and unit repurchases. Additional liquidity for purposes other than quarterly distributions, such as expansion capital expenditures and debt repayments, is available through borrowings under our commercial paper program and revolving credit facility, as well as from other borrowings or issuances of debt or common units (see Note 9 – Debt and Note 18 – Partners’ Capital and Distributions in Item 8. Financial Statements and Supplementary Data of this report for detail of our borrowings and changes in partners’ capital).
Off-Balance Sheet Arrangements
The following table summarizes our contractual obligations as of December 31, 2020 (in millions):
| ||Total||< 1 year||1-3 years||4-5 years||> 5 years|
Long-term debt obligations(1)
|$||5,000.0 ||$||— ||$||— ||$||250.0 ||$||4,750.0 |
|4,459.2 ||221.4 ||442.8 ||434.5 ||3,360.5 |
|Operating lease obligations||186.7 ||33.2 ||61.3 ||49.5 ||42.7 |
Storage contract commitments(2)
|11.9 ||8.4 ||2.5 ||0.6 ||0.4 |
Pipeline capacity commitments(3)
|49.8 ||9.6 ||19.3 ||19.3 ||1.6 |
|11.4 ||1.8 ||3.4 ||2.2 ||4.0 |
Pension and postretirement medical obligations(5)
|165.2 ||29.5 ||87.3 ||37.0 ||11.4 |
Product purchase commitments(6)
|79.9 ||69.8 ||10.1 ||— ||— |
|Utility purchase commitments||15.9 ||8.2 ||4.5 ||3.1 ||0.1 |
|— ||— ||— ||— ||— |
Equity-based incentive awards(8)
|33.1 ||15.2 ||17.9 ||— ||— |
|Capital project purchase obligations|