2020
ANNUAL
REPORT
N YSE: MMP
Magellan owns the longest refined products pipeline system in
the country. We can tap into nearly 50% of the nation’s refining
capacity and store more than 100 million barrels of petroleum
products, such as gasoline, diesel fuel and crude oil.
FORWARD - LOOKING S TATEMENTS
Except for statements of historical fact, this report constitutes forward-looking statements
as defined by federal law. Forward-looking statements may sometimes be identified by
words such as: potential, growth, providing, remain, expect, ensure, continue, commitment,
maintain, likely, foreseeable, future, forecasts, can, could, to come, will and similar references
to future periods. Although management of Magellan Midstream Partners, L.P. believes
such statements are based on reasonable assumptions, such statements necessarily
involve known and unknown risks and uncertainties that may cause actual outcomes to
be materially different. You are urged to carefully review and consider the cautionary
statements and other disclosures made in our accompanying 2020 Annual Report on Form
10-K, especially under the headings “Risk Factors” and “Forward-Looking Statements.”
LE T TER FROM
MICHAEL N. MEARS
Chairman, President and Chief Executive Officer
FEBRUARY 2021
This month Magellan celebrates a significant milestone,
20 years as a publicly traded company. During that
time, we have grown our asset base by nearly
$8 billion and increased the annual cash payout to
investors each year, with our equity price now valued
eight times higher than our initial public offering.
but to successfully manage our company for the
long term. Even during a pandemic, our company
stood tall, 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.
These successes have been made possible
by our resilient business model, disciplined
approach and focus on financial strength and
long-term value. Further, these characteristics
have served us well, allowing us to grow our
company and weather the different cycles and
events that have occurred over the years.
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.
RESILIENT BUSINESS MODEL
LONG -TERM VALUE CRE ATION
Without a doubt, 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, Magellan generated solid
financial results while ensuring continuity
of critical fuel supply for our nation.
Companies like Magellan are extremely important
to keep the United States’ economy moving.
Our employees worked diligently to ensure our
business ran safely throughout the pandemic,
and we thank them for their professionalism
and dedication to providing essential services
to our country during this difficult time.
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, Magellan’s resilient business model and
financial strength positioned us well to respond
not only to the near-term industry challenges
We remain focused on delivering long-term value
for our investors through a disciplined combination
of cash distributions, equity repurchases and
capital investments. In 2020, we returned nearly
$1.2 billion of value to our investors through
payment of our quarterly cash distribution and
equity repurchases under our buyback program.
Construction projects have been a primary
source of growth for our company over the years,
including the recent expansion of our Texas refined
products pipeline system to meet industry needs.
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 Magellan’s future.
Our growth capital investments are expected to
be in the range of $100 million for 2021 as we
pursue smaller bolt-on projects, in part to address
changes in logistical patterns to satisfy demand
for petroleum products in our markets. We remain
disciplined in our decision-making to ensure we
are good stewards of capital while simultaneously
maintaining our healthy balance sheet.
continued
Our most important social obligation is to
safely and reliably provide the fuels that our
nation relies on each day, while protecting
the communities where we live and work.
FINANCIAL HIGHLIGHT S
Operating Profit
($ in millions)
Distributable Cash Flow
($ in millions)
Cash Distributions
(declared per unit)
2020
2019
2018
2020
2019
2018
2020
2019
2018
$1,200
$1,300
$4.15
OPER ATING S TATIS TICS
Refined Products
Pipeline Shipments
(million barrels)
Crude Oil
Pipeline Shipments
(million barrels)
Crude Oil Terminal
Average Utilization
(million barrels per month)
2020
2019
2018
2020
2019
2018
2020
2019
2018
525
325
25
MAGELL AN
ASSETS
2020
REFINED PRODUCTS ASSETS
Refined Products Pipeline
Refined Products Terminal
Refined Products Joint Venture Terminal
CRUDE OIL ASSETS
Crude Oil Pipeline
Crude Oil Joint Venture Pipeline
Crude Oil Terminal
Crude Oil Joint Venture Terminal
FOCUS ON OP TIMIZ ATION
SUS TAINABILIT Y COMMITMENT
Efficiency and discipline are key to Magellan’s
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.
In fact, we expect to realize $50 million of benefit
in 2021 from these cost savings and process
improvements. Magellan has always operated
in a safe and lean manner, but we are taking
the opportunity to improve where we can.
Optimization of our asset portfolio is an important
element of our company’s discipline as well.
During 2020, Magellan divested three marine
terminal facilities outside our strategic footprint to
maximize value and our strong financial position.
Moving What Moves America® is more than just our
motto, it 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 Magellan. We have focused
on long-term, sustainable operations and disciplined
management since the creation of our company
two decades ago. However, Magellan recognizes the
growing stakeholder interest in how we incorporate
these principles 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.
Magellan remains committed to providing transparency
around how we manage and measure our environmental,
social and governance performance.
continued
The same values and fundamentals we were
founded on — discipline, safety and long-term value
creation — remain critical attributes of Magellan today
and will continue to drive success in the future.
IMPORTANT FUTURE ROLE
SOLID FUNDAMENTAL S DRIVE SUCCESS
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 past 20 years have been marked with many
accomplishments and I am proud of the company we
have become. The same values and fundamentals we
were founded on — discipline, safety and long-term
value creation — remain critical attributes of Magellan
today and will continue to drive success in the future.
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.
Despite the challenges of 2020, Magellan’s
business fundamentals remain strong, and we
stand ready to serve the nation. We enter the
new year in a strong position with an investment-
grade balance sheet and resilient business model
to manage our company for the long term.
We appreciate your investment in Magellan.
(Mark One)
☒
☐
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-16335
Magellan Midstream Partners, L.P.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
73-1599053
(I.R.S. Employer
Identification No.)
One Williams Center, P.O. Box 22186, Tulsa, Oklahoma 74121-2186
(Address of principal executive offices and zip code)
(918) 574-7000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Common Units
Trading Symbol(s)
MMP
Name of Each Exchange on
Which Registered
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.
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.
DOCUMENTS INCORPORATED BY REFERENCE
TABLE OF CONTENTS
ITEM 1.
PART I
Business.......................................................................................................................................
ITEM 1A. Risk Factors.................................................................................................................................
ITEM 1B. Unresolved Staff Comments........................................................................................................
ITEM 2.
Properties.....................................................................................................................................
ITEM 3.
Legal Proceedings........................................................................................................................
ITEM 4.
Mine Safety Disclosures..............................................................................................................
ITEM 5.
PART II
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities.................................................................................................................
ITEM 6.
Selected Financial Data...............................................................................................................
ITEM 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations......
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk....................................................
ITEM 8.
Financial Statements and Supplementary Data...........................................................................
ITEM 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.....
ITEM 9A. Controls and Procedures..............................................................................................................
ITEM 9B. Other Information........................................................................................................................
PART III
ITEM 10. Directors, Executive Officers and Corporate Governance..........................................................
ITEM 11.
Executive Compensation.............................................................................................................
ITEM 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters.....................................................................................................................................
ITEM 13.
Certain Relationships and Related Transactions, and Director Independence............................
ITEM 14.
Principal Accountant Fees and Services......................................................................................
ITEM 15.
PART IV
Exhibits and Financial Statement Schedules...............................................................................
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Forward-Looking Statements
Except for statements of historical fact, all statements in this Annual Report on Form 10-K constitute forward-
looking statements within the meaning of the federal securities laws. Forward-looking statements may be identified
by words like “anticipates,” “believes,” “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:
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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;
1
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our ability to obtain adequate levels of insurance at a reasonable cost, and the potential for losses to exceed
the insurance coverage we do obtain;
the treatment of us as a corporation for federal or state income tax purposes or if we become subject to
significant forms of other taxation or more aggressive interpretation or increased assessments under
existing forms of taxation;
our ability to identify expansion projects 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.
2
MAGELLAN MIDSTREAM PARTNERS, L.P.
FORM 10-K
PART I
Item 1. Business
(a) General Development of Business
Unless indicated otherwise, the terms “our,” “we,” “us” and similar language refer to Magellan Midstream
Partners, L.P. together with its subsidiaries. Magellan Midstream Partners, L.P. is a Delaware limited partnership
formed in August 2000, and 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.
(b) [Reserved.]
(c) Narrative Description of Business
We are principally engaged in the transportation, storage and distribution of refined petroleum products and
crude oil. As of December 31, 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.
Industry Background
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:
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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;
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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
REFINED PRODUCTS
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:
Percent of consolidated revenue.............................................
Percent of consolidated operating margin..............................
Percent of consolidated total assets........................................
Year Ended December 31,
2018
78%
65%
61%
2019
76%
62%
64%
2020
75%
66%
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
4
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.
5
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
Cenovus Energy...........................................................................................
Refinery Location
Superior, WI
CHS.............................................................................................................. McPherson, KS
CVR Energy.................................................................................................
Coffeyville, KS
CVR Energy................................................................................................. Wynnewood, OK
Flint Hills Resources....................................................................................
Pine Bend, MN
HollyFrontier................................................................................................
El Dorado, KS
HollyFrontier................................................................................................
Tulsa, OK
Marathon......................................................................................................
St. Paul, MN
Marathon...................................................................................................... El Paso, TX
Marathon......................................................................................................
Galveston Bay, TX
Par Pacific ................................................................................................... Newcastle, WY
Phillips 66....................................................................................................
Ponca City, OK
Sinclair......................................................................................................... Evansville, WY
Suncor Energy.............................................................................................. Commerce City, CO
Valero........................................................................................................... Ardmore, OK
Valero........................................................................................................... Houston, TX
Valero...........................................................................................................
Texas City, TX
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Our system is also supplied by connections to multiple pipelines and terminals, including those shown in the
table below:
Major Origins—Pipelines and Terminals (Listed Alphabetically)
Pipeline/Terminal
Connection Location
Source of Product
BP...................................
Manhattan, IL...........................................................
Whiting, IN refinery
CHS................................
Fargo, ND.................................................................
Delek............................... El Paso and Odessa, TX........................................... Big Spring, TX refinery
Explorer..........................
Laurel, MT refinery
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
Magellan.........................
Galena Park, TX.......................................................
Various Gulf Coast refineries and imports
Mid-America
(Enterprise).................
NuStar Energy................
El Dorado, KS...........................................................
Denver, CO; El Dorado, KS; Minneapolis, MN.......
ONEOK..........................
Des Moines, IA; Wayne, IL; Plattsburg, MO...........
Phillips 66.......................
Denver, CO; Kansas City, KS; Pasadena, TX;
Casper, WY..............................................................
Conway, KS storage
Various OK & KS refineries, Mandan,
ND refinery, McKee, TX refinery
Bushton, KS storage and Chicago, IL area
refineries
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
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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.
CRUDE OIL
Our crude oil segment is comprised of approximately 2,200 miles of crude oil pipelines, a condensate splitter
and storage facilities with an aggregate storage capacity of approximately 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”).
8
Our crude oil segment accounted for the following percentages of our consolidated revenue, operating margin
and total assets:
Percent of consolidated revenue.....................................
Percent of consolidated operating margin......................
Percent of consolidated total assets................................
Year Ended December 31,
2018
22%
35%
36%
2019
24%
37%
34%
2020
25%
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.
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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.
10
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
11
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.
Regulation
Tariff Regulation. Our interstate common carrier pipeline operations are subject to rate regulation by the
FERC under the Interstate Commerce Act, the Energy Policy Act of 1992 and 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
12
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
13
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
14
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.
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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
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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.
Human Capital
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.
(d) [Reserved.]
(e) Available Information
Our internet address is www.magellanlp.com. We make available free of charge on or through our website our
annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those
reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the
“Exchange Act”), as soon as reasonably practicable after we electronically file such material with, or furnish it to,
the Securities and Exchange Commission.
Item 1A. Risk Factors
The nature of our business activities subjects us to a wide variety of hazards and risks. The following is a
summary and a description of the most significant risks relating to our business activities that we have identified. In
addition to the factors discussed elsewhere in this Annual Report on Form 10-K, you should carefully consider the
risks and uncertainties described below, which could have a material adverse effect on our business, 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.
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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.
Operational hazards
•
•
•
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.
Regulatory risks
•
•
•
Our operations are subject to extensive environmental, health, safety and other laws and regulations that
impose significant requirements and costs on us;
Our customers are subject to extensive environmental, health, safety and other laws and regulations, and
any new laws or regulations or changes in the interpretation of existing laws and regulations, 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;
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•
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in
increased operating costs and reduced demand for the products that we transport, store or distribute.
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.
Tax risks
•
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
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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.
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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
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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
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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
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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.
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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.
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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.
Operational hazards
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.
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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
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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.
Regulatory risks
Our operations are subject to extensive environmental, health, safety and other laws and regulations that
impose significant requirements, costs and liabilities on us. These requirements, costs and liabilities could increase
as a result of new laws or regulations or changes in the interpretation, implementation or enforcement of existing
laws and regulations. Our customers are also subject to extensive environmental, health, safety and other laws and
regulations, and any new laws or regulations or changes in the interpretation, implementation or enforcement of
existing laws and regulations, including laws and regulations related to hydraulic fracturing, could result in
decreased demand for our services.
Our operations are subject to extensive federal, state and local laws and regulations relating to the protection or
preservation of the environment, natural resources and human health and safety, including but not limited to the
CAA, RCRA, OPA, CWA, CERCLA, HLPSA, 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
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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
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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.
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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.
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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.
Tax risks
Our tax treatment or the tax treatment of our unitholders could be subject to potential legislative, judicial or
administrative changes and differing interpretations, possibly on a retroactive basis.
Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or
otherwise subject us to entity-level taxation. From time to time the U.S. government considers substantive changes
to the existing federal income tax laws that affect publicly traded partnerships. We are unable to predict whether any
such additional legislation or any other tax-related proposals will ultimately be enacted. Moreover, any modification
to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Any such
changes could 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.
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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
33
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.
34
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
None.
Item 2.
Properties
See Item 1(c) for a description of the locations and general character of our material properties.
Item 3.
Legal Proceedings
Butane Blending Patent Infringement Proceeding. On October 4, 2017, Sunoco Partners Marketing &
Terminals L.P. (“Sunoco”) brought an action for patent infringement in the U.S. District Court for the District of
Delaware alleging Magellan 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
Not applicable.
35
PART II
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities
Our common units are listed and traded on the New York Stock Exchange under the ticker symbol “MMP.” At
the close of business on February 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
January 1-31, 2020............
February 1-29, 2020..........
March 1-31, 2020..............
First Quarter 2020.......
April 1-30, 2020................
May 1-31, 2020.................
June 1-30, 2020.................
Second Quarter 2020...
July 1-31, 2020..................
August 1-31, 2020.............
September 1-30, 2020.......
Third Quarter 2020......
October 1-31, 2020...........
November 1-30, 2020.......
December 1-31, 2020........
Fourth Quarter 2020....
Total Number of
Common Units
Purchased
Average Price
Paid Per Unit
— $
1,514,719 $
2,117,065 $
3,631,784 $
—
59.19
53.06
55.62
—
—
—
—
—
—
1,355,344 $
1,355,344 $
—
266,703 $
314,429 $
581,132 $
36.87
36.87
41.24
44.50
43.00
49.74
36
Year Ended 2020..........
5,568,260 $
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)
— $
1,514,719 $
2,117,065 $
3,631,784
— $
— $
— $
—
— $
— $
1,355,344 $
1,355,344
— $
266,703 $
314,429 $
581,132
5,568,260
750.0
660.4
548.1
548.1
548.1
548.1
548.1
548.1
498.0
498.0
487.1
473.1
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.
12/31/2015
12/31/2016
12/31/2017
12/31/2018
12/31/2019
12/31/2020
MMP...............................................................
AMZI..............................................................
S&P 500.........................................................
S&P 500 Energy.............................................
$100
$100
$100
$100
$117
$119
$112
$127
$115
$108
$136
$126
$98
$95
$130
$103
$115
$102
$171
$115
$85
$70
$203
$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.
37
MMPAMZIS&P 500S&P 500 Energy12/31/1512/31/1612/31/1712/31/1812/31/1912/31/20$60$80$100$120$140$160$180$200$220
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.
38
Income Statement Data:
Transportation and terminals revenue.................
Product sales revenue..........................................
Affiliate management fee revenue.......................
Total revenue..................................................
Operating expenses..............................................
Cost of product sales............................................
Subtotal...........................................................
Other operating income (expense).......................
Earnings of non-controlled entities......................
Operating margin............................................
Depreciation, amortization and impairment
expense................................................................
G&A expense......................................................
Operating profit..............................................
Interest expense, net............................................
Gain on disposition of assets...............................
Other (income) expense.......................................
Income before provision for income taxes..........
Provision for income taxes..................................
Net income......................................................
Basic net income per common unit.....................
Diluted net income per common unit..................
Balance Sheets Data:
Working capital (deficit).....................................
Total assets..........................................................
Long-term debt, net.............................................
Partners’ capital...................................................
Year Ended December 31,
2016
2017
2018
2019
2020
(in thousands, except per unit amounts)
$ 1,591,119 $ 1,731,775 $ 1,878,988 $ 1,970,630 $ 1,794,854
611,719
21,229
2,427,802
601,359
513,715
1,312,728
101
153,327
1,466,156
758,206
17,680
2,507,661
577,978
635,617
1,294,066
—
120,994
1,415,060
736,092
21,190
2,727,912
634,081
619,279
1,474,552
2,975
168,961
1,646,488
927,220
20,365
2,826,573
649,436
704,313
1,472,824
—
181,117
1,653,941
599,602
14,689
2,205,410
528,672
493,338
1,183,400
—
78,696
1,262,096
178,142
147,165
936,789
165,410
196,630
165,717
1,052,713
193,718
265,077
194,283
1,194,581
200,514
246,134
196,650
1,203,704
198,554
258,676
173,478
1,034,002
221,826
(28,144)
(6,466)
805,989
3,218
802,771 $
(18,505)
4,139
873,361
3,830
(353,797)
13,868
1,333,996
71
869,531 $ 1,333,925 $ 1,020,849 $
(28,966)
11,830
1,022,286
1,437
(12,887)
5,164
819,899
2,934
816,965
3.52 $
3.81 $
5.84 $
4.46 $
3.62
3.52 $
3.81 $
5.84 $
4.46 $
3.62
$
$
$
(111,262) $
(239,899) $
$
(153,381)
$ 6,772,073 $ 7,394,375 $ 7,747,537 $ 8,437,729 $ 8,196,982
$ 4,087,192 $ 4,273,518 $ 4,211,380 $ 4,706,075 $ 4,978,691
$ 2,092,105 $ 2,129,653 $ 2,643,434 $ 2,715,028 $ 2,303,806
(207,468) $
(30,213) $
Distribution Data:
Distributions declared per unit(a)..........................
Distributions paid per unit(a)................................
$
$
3.32 $
3.25 $
3.59 $
3.52 $
3.87 $
3.79 $
4.07 $
4.04 $
4.11
4.11
39
Year Ended December 31,
2016
2017
2018
2019
2020
(in thousands, except operating statistics)
Other Data:
Operating margin:
Refined products...........................................
Crude oil........................................................
Allocated partnership depreciation costs(b)...
Operating margin..................................
$
840,181 $
416,960
4,955
965,813
493,734
6,609
$ 1,262,096 $ 1,415,060 $ 1,653,941 $ 1,646,488 $ 1,466,156
934,984 $ 1,074,705 $ 1,025,497 $
474,802
5,274
615,485
5,506
573,289
5,947
Adjusted EBITDA and distributable cash flow:
Net income....................................................
Interest expense, net......................................
$
802,771 $
165,410
869,531 $ 1,333,925 $ 1,020,849 $
193,718
200,514
198,554
816,965
221,826
Depreciation, amortization and
impairment(c).................................................
Equity-based incentive compensation(d)........
Gain on disposition of assets(e)......................
Commodity-related adjustments(f)................
Distributions from operations of non-
controlled entities in excess of (less than)
earnings for the period..................................
Other.............................................................
Adjusted EBITDA.......................................
189,332
210,000
272,522
240,874
254,586
4,982
(28,144)
64,257
6,766
(18,505)
12,463
22,768
(351,215)
(101,987)
14,247
(16,280)
88,223
(2,715)
(10,511)
14,211
9,293
5,341
1,213,242
25,216
3,749
1,302,938
15,584
3,644
1,395,755
34,641
—
1,581,108
54,273
—
1,348,635
Interest expense, net, excluding debt
issuance cost amortization(g).....................
Maintenance capital(h)...................................
Distributable cash flow....................
$
(162,251)
(197,274)
(205,446)
(98,718)
(88,736)
(103,507)
947,484 $ 1,021,372 $ 1,109,745 $ 1,297,464 $ 1,044,471
(186,942)
(96,702)
(190,403)
(91,163)
Operating Statistics:
Refined products:
Transportation revenue per barrel shipped...
Volume shipped (million barrels):
Gasoline...................................................
Distillates.................................................
Aviation fuel............................................
Liquefied petroleum gases.......................
Total volume shipped.........................
Crude oil:
Magellan 100%-owned assets:
Transportation revenue per barrel
shipped.................................................
Volume shipped (million barrels)(i)..........
Terminal average utilization (million
barrels per month)................................
Select joint venture pipelines:
BridgeTex - volume shipped (million
barrels)(j)...............................................
Saddlehorn - volume shipped (million
barrels)(k)..............................................
$
1.473 $
1.495 $
1.556 $
1.616 $
1.675
275.4
150.2
25.7
10.4
461.7
295.5
166.2
26.5
9.9
498.1
286.9
181.7
31.0
11.0
510.6
280.5
184.6
41.1
9.7
515.9
$
1.321 $
1.348 $
1.208 $
0.939 $
187.0
196.4
242.8
317.2
16.9
17.5
18.7
23.0
270.8
175.5
21.6
0.9
468.8
1.028
229.9
25.2
79.0
5.2
98.4
19.0
138.2
156.3
132.0
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.
40
(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
(g)
description of items included in our commodity-related adjustments.
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.
41
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Introduction
We are a publicly traded limited partnership principally engaged in the transportation, storage and distribution
of refined petroleum products and crude oil. As of December 31, 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.
Overview
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.
42
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.
Recent Developments
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
$1.0275 per unit for the period of October 1, 2020 through December 31, 2020. This quarterly distribution was paid
on February 12, 2021 to unitholders of record on February 5, 2021.
43
Results of Operations
We believe that investors benefit from having access to the same financial measures utilized by management.
Operating margin, which is presented in the following table, is an important measure used by management to
evaluate the economic performance of our core operations. Operating margin is not a generally accepted accounting
principles (“GAAP”) measure, but the components of operating margin are computed using amounts that are
determined in accordance with GAAP. A reconciliation of operating margin to operating profit, which is its nearest
comparable GAAP financial measure, is included in the following table. Operating profit includes expense items,
such as depreciation, amortization and impairment expense and general and administrative (“G&A”) expense, which
management does not focus on when evaluating the core profitability of our separate operating segments.
Additionally, product margin, which management primarily uses to evaluate the profitability of our commodity-
related activities, is provided in this table. Product margin is a non-GAAP measure but its components of product
sales revenue and cost of product sales are determined in accordance with GAAP. Our gas liquids blending,
fractionation and other commodity-related activities generate significant revenue. However, we believe the product
margin from these activities, which takes into account the related cost of product sales, better represents its
importance to our results of operations.
44
Year Ended December 31, 2019 Compared to Year Ended December 31, 2020
Financial Highlights ($ in millions, except operating statistics)
Transportation and terminals revenue:
Refined products...............................................................................
Crude oil............................................................................................
Intersegment eliminations.................................................................
Total transportation and terminals revenue...............................
Affiliate management fee revenue............................................................
Operating expenses:
Refined products...............................................................................
Crude oil............................................................................................
Intersegment eliminations.................................................................
Total operating expenses...........................................................
Product margin:
Product sales revenue........................................................................
Cost of product sales.........................................................................
Product margin..........................................................................
Other operating income (expense)............................................................
Earnings of non-controlled entities...........................................................
Operating margin......................................................................
Depreciation, amortization and impairment expense................................
G&A expense............................................................................................
Operating profit.........................................................................
Interest expense (net of interest income and interest capitalized)............
Gain on disposition of assets.....................................................................
Other (income) expense............................................................................
Income before provision for income taxes................................................
Provision for income taxes........................................................................
Net income................................................................................................
Operating Statistics
Refined products:
Transportation revenue per barrel shipped.......................................
Volume shipped (million barrels):
Gasoline.......................................................................................
Distillates.....................................................................................
Aviation fuel................................................................................
Liquefied petroleum gases...........................................................
Total volume shipped.............................................................
Crude oil:
Magellan 100%-owned assets:
Year Ended
December 31,
2019
2020
Variance
Favorable (Unfavorable)
$ Change % Change
$ 1,355.6 $ 1,241.8 $
620.4
(5.4)
1,970.6
21.2
559.6
(6.5)
1,794.9
21.2
471.7
173.3
(10.9)
634.1
736.1
619.3
116.8
3.0
169.0
1,646.5
246.1
196.7
1,203.7
198.6
(29.0)
11.8
1,022.3
1.5
$ 1,020.8 $
425.4
189.1
(13.2)
601.3
611.7
513.7
98.0
0.1
153.3
1,466.2
258.7
173.5
1,034.0
221.8
(12.9)
5.2
819.9
2.9
817.0 $
$
1.616 $
1.675
(113.8)
(60.8)
(1.1)
(175.7)
—
46.3
(15.8)
2.3
32.8
(124.4)
105.6
(18.8)
(2.9)
(15.7)
(180.3)
(12.6)
23.2
(169.7)
(23.2)
(16.1)
6.6
(202.4)
(1.4)
(203.8)
(8) %
(10) %
(20) %
(9) %
— %
10 %
(9) %
21 %
5 %
(17) %
17 %
(16) %
(97) %
(9) %
(11) %
(5) %
12 %
(14) %
(12) %
(56) %
56 %
(20) %
(93) %
(20) %
280.5
184.6
41.1
9.7
515.9
270.8
175.5
21.6
0.9
468.8
1.028
229.9
25.2
132.0
61.6
Transportation revenue per barrel shipped..................................
Volume shipped (million barrels)(a).............................................
Terminal average utilization (million barrels per month)............
$
0.939 $
317.2
23.0
Select joint venture pipelines:
BridgeTex - volume shipped (million barrels)(b)..........................
Saddlehorn - volume shipped (million barrels)(c).........................
156.3
56.1
(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.
45
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.
46
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.
47
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,
2019
2020
Net income.......................................................................................................
$
1,020.8 $
Interest expense, net.........................................................................................
Depreciation, amortization and impairment(1)..................................................
Equity-based incentive compensation(2)...........................................................
Gain on disposition of assets(3).........................................................................
Commodity-related adjustments:
Derivative (gains) losses recognized in the period associated with future
transactions(4)...........................................................................................
Derivative gains (losses) recognized in previous periods associated with
transactions completed in the period(4)....................................................
Inventory valuation adjustments(5)...............................................................
Total commodity-related adjustments......................................................
Distributions from operations of non-controlled entities in excess of (less
than) earnings...............................................................................................
Adjusted EBITDA..........................................................................................
Interest expense, net, excluding debt issuance cost amortization(6)..................
Maintenance capital(7).......................................................................................
DCF..................................................................................................................
198.6
240.9
14.2
(16.3)
29.7
71.2
(12.7)
88.2
34.7
1,581.1
(186.9)
(96.7)
817.0
221.8
254.6
(2.7)
(10.5)
29.3
(20.9)
5.8
14.2
54.3
1,348.7
(205.5)
(98.7)
$
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.
48
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 Requirements
Capital spending for our business consists primarily of:
• Maintenance capital expenditures. These expenditures include costs required to maintain equipment
reliability and safety and to address environmental and other regulatory requirements rather than to
generate incremental DCF; and
• Expansion capital expenditures. These expenditures are undertaken primarily to generate incremental DCF
and include costs to acquire 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
49
underway, we expect to spend approximately $75 million in 2021 to complete our current slate of expansion capital
projects.
Liquidity
Cash generated from operations is a key source of liquidity for funding debt service, maintenance capital
expenditures, quarterly distributions and 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
None.
50
Contractual Obligations
The following table summarizes our contractual obligations as of December 31, 2020 (in millions):
Long-term debt obligations(1)...........................
Interest obligations(1)........................................
Operating lease obligations..............................
Storage contract commitments(2)......................
Pipeline capacity commitments(3).....................
Right-of-way obligations(4)...............................
Pension and postretirement medical
obligations(5).................................................
Purchase commitments:
Product purchase commitments(6)................
Utility purchase commitments.....................
Derivative instruments(7)..............................
Equity-based incentive awards(8).................
Capital project purchase obligations............
Maintenance obligations..............................
Other............................................................
Total
< 1 year
1-3 years
4-5 years
> 5 years
$
5,000.0 $
— $
— $
250.0 $
4,750.0
4,459.2
186.7
11.9
49.8
11.4
221.4
33.2
8.4
9.6
1.8
165.2
29.5
79.9
15.9
—
33.1
29.2
79.4
11.8
69.8
8.2
—
15.2
29.1
79.0
7.7
442.8
434.5
3,360.5
61.3
2.5
19.3
3.4
87.3
10.1
4.5
—
17.9
0.1
0.4
3.9
49.5
0.6
19.3
2.2
37.0
—
3.1
—
—
—
—
0.2
42.7
0.4
1.6
4.0
11.4
—
0.1
—
—
—
—
—
Total..................................................
$ 10,133.5 $
512.9 $
653.5 $
796.4 $
8,170.7
(1) At December 31, 2020, we had no borrowings outstanding under our revolving credit facility or commercial paper program. For
purposes of this table, we have reflected no assumed borrowings under our revolving credit facility or commercial paper program for
any periods presented. We have included interest obligations based on the stated amounts of our fixed-rate obligations.
Includes product storage we have contracted from third parties. The cost of storage services is recognized in cost of product sales on
our consolidated statements of income.
Includes pipeline capacity we have contracted from third parties. The cost of these commitments is recognized in operating expense
on our consolidated statements of income.
(2)
(3)
(4) Represents right-of-way agreements with a contractual maturity date over one year. The cost of these obligations is recognized in
operating expense on our consolidated statements of income.
(5) Represents the projected benefit obligation of our pension and postretirement medical plans less the fair value of plan assets.
(6)
Includes product purchase commitments for which the price provisions are indexed based on the date of delivery. We have estimated
the value of these commitments using the related index price curve as of December 31, 2020. Also, we have excluded certain product
purchase agreements for which there is no specified or minimum quantity.
(7) As of December 31, 2020, we had entered into exchange-traded futures contracts representing 3.4 million barrels of petroleum
products that we expect to sell in the future and 0.1 million barrels of gas liquids we expect to purchase in the future. At
December 31, 2020, we had recorded a net liability of $21.3 million and made margin deposits of $34.2 million. We have excluded
from this table the future net cash outflows, if any, under these futures contracts and the amounts of future margin deposit
requirements because those amounts are uncertain.
(8) Settlements of our LTIP awards will differ from these reported amounts primarily due to differences between actual and current
estimates of payout percentages and completion of the remaining portion of the requisite service periods.
Other Items
Executive Officer Retirements. Jeff R. Selvidge, Senior Vice President of Commercial – Refined Products,
retired in November 2020 after 30 years of service with us and our predecessors.
Pipeline Tariff Changes. The Federal Energy Regulatory Commission (“FERC”) regulates the rates charged
on interstate common carrier pipelines. Based on preliminary estimates, we expect to decrease rates in the 40% of
our markets that are subject to the FERC’s index methodology by approximately 0.5% on July 1, 2021. While we
continue to evaluate the remaining 60% of our markets, we generally intend to increase rates in those markets by 3%
to 4% on July 1, 2021, similar to the 2020 rate increase for our competitive markets. Most of the tariffs on our long-
51
haul crude oil pipelines are established at negotiated rates that generally provide for annual adjustments in line with
changes in the FERC index, subject to certain modifications. We expect to change the rates of our long-haul crude
oil pipelines between 0% and 2% in July 2021.
Commodity Derivative Agreements. Certain of our business activities result in our owning various
commodities, which exposes us to commodity price risk. We use forward physical commodity contracts and
exchange-traded futures contracts to hedge against changes in prices of commodities that we expect to sell or
purchase in future periods. We are a party to a basis derivative agreement for which settlements are determined
based on the basis differential of crude oil prices at different market locations.
For further information regarding the quantities of refined products and crude oil hedged at December 31, 2020
and the fair value of open hedge and basis derivative contracts at that date, please see Item 7A. Quantitative and
Qualitative Disclosures about Market Risk.
Related Party Transactions. See Note 17 – Related Party Transactions in Item 8. Financial Statements and
Supplementary Data of this report for detail of our related party transactions.
Critical Accounting Estimates
Our management has discussed the development and selection of the following critical accounting estimates
with the audit committee of our general partner’s board of directors, which has reviewed and approved these
disclosures.
Pension Obligations
We sponsor a pension plan covering union employees and a pension plan for non-union employees. Various
estimates and assumptions directly affect net periodic benefit expense and obligations for these plans. These
estimates and assumptions include the expected long-term rates of return on plan assets, discount rates and the
expected rate of compensation increase. Management reviews these assumptions annually and makes adjustments as
necessary.
The following table presents the estimated increase (decrease) in net periodic benefit expense and obligations
that would result from a 1% change in the specified assumption (in thousands):
Pension benefits:
Discount rate..............................................................
Expected long-term rate of return on plan assets......
Rate of compensation increase..................................
$
$
$
(5,562)
(2,963)
5,210
$ 6,801
$ 2,963
$ (5,231)
$ (53,958)
$
—
$ 31,234
$ 67,603
$
—
$ (31,301)
Benefit Expense
Benefit Obligation
1% Increase
1% Decrease
1% Increase
1% Decrease
The following table sets forth the increase (decrease) in our pension funding based on our current funding
policy assuming a 1% change in the specified criterion (in thousands):
Rate of compensation increase.....
$
517 $
(506)
1% Increase
1% Decrease
The discount rate directly affects the measurement of the benefit obligations of our pension benefit plans. The
objective of the discount rate is to determine the amount, if invested at the December 31 measurement date in a
portfolio of high-quality fixed income securities, that would provide the necessary cash flows to make benefit
payments when due. Decreases in the discount rate increase the obligation and generally increase the related
expense, while increases in the discount rate have the opposite effect. Changes in general economic and market
52
conditions that affect interest rates on long-term high-quality fixed income securities as well as the duration of our
plans’ liabilities affect our estimate of the discount rate.
We estimate the long-term expected rate of return on plan assets using expectations of capital market results,
which includes an analysis of historical results as well as forward-looking projections. We base these capital market
expectations on a long-term period and on our investment strategy and asset allocation. We develop our estimates
using input from several external sources, including consultation with our third-party independent investment
consultant. We develop the forward-looking capital market projections using a consensus of expectations by
economists for inflation and dividend yield, along with expected changes in risk premiums. Because our determined
rate is an estimate of future results, it could be significantly different from actual results. The expected rates of return
on plan assets are long-term in nature; therefore, short-term market performance does not significantly affect our
estimated long-term expected rate of return.
The expected rate of compensation increase represents average long-term salary increases. An increase in this
rate causes the pension obligation and expense to increase.
Impairment of Long-Lived Assets, Goodwill and Investments
Impairment of Long-Lived Assets. Long-lived assets, including fixed assets and intangibles, are reviewed for
impairment whenever events or changes in circumstances indicate that the carrying value may not be recoverable.
Such indicators include, among others, the nature of the asset, the projected future economic benefit of the asset,
changes in regulatory and political environments and historical and future cash flow and profitability measurements.
If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, we recognize
an impairment charge for the excess of carrying value of the asset over its estimated fair value.
Goodwill. The goodwill relating to each of our reporting units is tested for impairment annually as well as
when an event or change in circumstances indicates an impairment may have occurred. Under GAAP, we have the
option to first assess qualitative factors to determine whether it is more likely than not that the fair value of one of
our reporting units is greater than its carrying amount. If, after assessing the totality of events or circumstances, we
determine it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, we are
not required to perform any further testing. However, if we conclude otherwise, we perform the first step of a two-
step impairment test by calculating the fair value of the reporting unit and comparing the fair value with the carrying
amount of the reporting unit. If the fair value of the reporting unit is less than its carrying value, an impairment loss
is recorded to the extent that the implied fair value of the goodwill of the reporting unit is less than its carrying
value. We have the option to bypass the qualitative assessment for any reporting unit in any period and proceed
directly to performing the first step of the two-step goodwill impairment test.
For purposes of performing the impairment test for goodwill, our reporting units are our reportable segments.
In 2018, we elected to complete the quantitative goodwill impairment test and began with step one of the test as
required by GAAP. Based on this assessment, we calculated that the fair value of each of our reporting units was
greater than its carrying amount. In 2019 and 2020, we elected to perform the qualitative assessment described
above for purposes of our annual goodwill impairment test. Based on these assessments, we concluded that it was
more likely than not that the fair value of each of our reporting units was greater than its carrying amount.
Accordingly, no further testing was required.
Determination as to whether and how much goodwill or long-lived assets are impaired involves management
estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology
improvements on operating expenses and the outlook for national or regional market supply and demand conditions.
We base the impairment reviews and calculations used in our impairment tests on assumptions that are consistent
with our business plans and long-term investment decisions. See Note 5 – Property, Plant and Equipment, Goodwill
and Other Intangibles in Item 8. Financial Statements and Supplementary Data for additional information regarding
impairments of goodwill and long-lived assets.
53
Investments. We evaluate investments in non-controlled entities for impairment whenever events or
circumstances indicate that there is an other-than-temporary loss in value of the investment. When evidence of loss
in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the
investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying
value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair
value is recognized in our consolidated financial statements as an impairment charge.
New Accounting Pronouncements
See Note 2 – Summary of Significant Accounting Policies in Item 8. Financial Statements and Supplementary
Data of this report for a summary of new accounting pronouncements.
54
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
We may be exposed to market risk through changes in commodity prices and interest rates and have
established policies to monitor and control these market risks. We use derivative agreements to help manage our
exposure to commodity price and interest rate risks.
Commodity Price Risk
Our commodity price risk primarily arises from our gas liquids blending and fractionation activities, and from
managing product overages and shortages associated with our refined products and crude oil pipelines and terminals.
We use derivatives such as forward physical contracts and exchange-traded futures contracts to help us manage
commodity price risk.
Forward physical contracts that qualify for and are elected as normal purchases and sales are accounted for
using traditional accrual accounting. As of December 31, 2020, we had commitments under forward purchase and
sale contracts as follows (in millions):
Forward purchase contracts – notional value...................... $
79.9 $
69.8 $
Total
< 1 Year
1 – 3 Years
10.1
Forward purchase contracts – barrels.................................
1.8
1.6
Forward sales contracts – notional value............................ $
23.5 $
23.5 $
Forward sales contracts – barrels........................................
0.5
0.5
0.2
—
—
We generally use exchange-traded futures contracts to hedge against changes in the price of petroleum
products we expect to sell or purchase. We did not elect hedge accounting treatment under Accounting Standards
Codification 815, Derivatives and Hedging for our open contracts and as a result we accounted for these contracts
as economic hedges, with changes in fair value recognized currently in earnings. The fair value of these open
futures contracts, representing 3.4 million barrels of petroleum products we expect to sell and 0.1 million barrels of
gas liquids we expect to purchase, was a net liability of $21.3 million. With respect to these contracts, a $10.00 per
barrel increase (decrease) in the prices of petroleum products we expect to sell would result in a $34.0 million
decrease (increase) in our operating profit, while a $10.00 per barrel increase (decrease) in the price of gas liquids
we expect to purchase would result in a $1.0 million increase (decrease) in our operating profit. These increases or
decreases in operating profit would be substantially offset by higher or lower product sales revenue or cost of
product sales when the physical sale or purchase of those products occurs, respectively. These contracts may be for
the purchase or sale of products in markets different from those in which we are attempting to hedge our exposure,
and the related hedges may not eliminate all price risks.
We are a party to a basis derivative agreement with a joint venture co-owner’s affiliate, and that affiliate is a
party to an intrastate transportation services agreement with the joint venture, which was entered into
contemporaneously with the basis derivative agreement. Settlements under the basis derivative agreement are
determined based on the basis differential of crude oil prices at different market locations and a notional volume of
30,000 barrels per day. As a result, we are exposed to the differential in the forward price curves for crude oil in
West Texas and the Houston Gulf Coast. With respect to this agreement, a $0.50 per barrel increase (decrease) in
the differential would result in an approximately $1 million increase (decrease) in our operating profit.
Interest Rate Risk
Our use of variable rate debt and any future issuances of fixed rate debt expose us to interest rate risk. As of
December 31, 2020, we did not have any variable rate debt outstanding.
55
Item 8.
Financial Statements and Supplementary Data
Management’s Annual Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting
as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934, as amended. Our internal control over financial
reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies
or procedures may deteriorate.
Management assessed the effectiveness of its internal control over financial reporting as of December 31,
2020. In making this assessment, it used the criteria set forth in 2013 by the Committee of Sponsoring Organizations
of the Treadway Commission in Internal Control—Integrated Framework. As a result of this assessment
management has concluded that, as of December 31, 2020, its internal control over financial reporting is effective
based on those criteria.
Ernst & Young LLP, the independent registered public accounting firm that audited our consolidated financial
statements included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of our
internal control over financial reporting as of December 31, 2020. The report, which expresses an unqualified
opinion on the effectiveness of our internal control over financial reporting as of December 31, 2020, is included
herein under the heading “Report of Independent Registered Public Accounting Firm” relative to internal control
over financial reporting.
By:
/S/ MICHAEL N. MEARS
Chairman of the Board, President, Chief Executive Officer
and Director of Magellan GP, LLC, General Partner of
Magellan Midstream Partners, L.P.
By:
/S/ JEFF HOLMAN
Senior Vice President, Chief Financial Officer and
Treasurer of Magellan GP, LLC, General Partner of
Magellan Midstream Partners, L.P.
56
Report of Independent Registered Public Accounting Firm
To the Common Unitholders of Magellan Midstream Partners, L.P. and the Board of Directors of Magellan GP,
LLC, General Partner of Magellan Midstream Partners, L.P.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Magellan Midstream Partners, L.P. (the
Partnership) as of December 31, 2020 and 2019, the related consolidated statements of income, comprehensive
income, partners’ capital and cash flows for each of the three years in the period ended December 31, 2020, and the
related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated
financial statements present fairly, in all material respects, the financial position of the Partnership at December 31,
2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended
December 31, 2020, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2020, based on
criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission (2013 framework) and our report dated -February 18, 2021 expressed an unqualified
opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an
opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered
with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S.
federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the
PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial statements are free of material
misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of
material misstatement of the financial statements, whether due to error or fraud, and performing procedures that
respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and
disclosures in the financial statements. Our audits also included evaluating the accounting principles used and
significant estimates made by management, as well as evaluating the overall presentation of the financial statements.
We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial
statements that was communicated or required to be communicated to the audit committee and that: (1) relates to
accounts or disclosures that are material to the financial statements and (2) involved our especially challenging,
subjective or complex judgments. The communication of the critical audit matter does not alter in any way our
opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical
audit matter below, providing a separate opinion on the critical audit matter or on the account or disclosures to
which it relates.
57
Defined Benefit Pension Obligation
Description of
the Matter
At December 31, 2020, the Partnership’s defined benefit pension obligation was $444 million
and exceeded the fair value of pension plan assets of $296 million, resulting in a net pension
obligation of $148 million. As discussed in Note 11 to the consolidated financial statements,
the Partnership reviews and updates the assumptions used to measure the defined benefit
pension obligation on an annual basis.
Auditing the pension obligation was complex due to the judgmental nature of certain actuarial
assumptions used in the measurement process, including the discount rate, mortality rates,
retirement rate and future compensation levels. The projected benefit obligation was sensitive
to these assumptions.
How We
Addressed the
Matter in Our
Audit
We obtained an understanding, evaluated the design and tested the operating effectiveness of
controls over the Partnership’s review of the defined benefit pension obligation calculations,
the significant actuarial assumptions and the data inputs provided to the third-party actuary.
To test the defined benefit pension obligation, our audit procedures included, among others,
evaluating the methodology used, the significant actuarial assumptions discussed above and
the underlying data used in the measurement process. We compared the actuarial assumptions
used by management to historical trends and evaluated the change in the defined benefit
pension obligation from the prior year resulting from the change in service cost, interest cost,
actuarial gains and losses, benefit payments, contributions and other activities. In addition, we
involved our actuarial specialists to assist with our procedures including, among others,
evaluating management’s methodology for determining the discount rate that reflects the
maturity and duration of the benefit payments and that is used to measure the defined benefit
pension obligation. As part of this assessment, we compared the projected cash flows used in
the current year measurement of the pension obligation to those in the prior year and
compared the current year benefits paid to the prior year projected payments. To evaluate the
future mortality rates, retirement rate and future compensation levels, we assessed whether the
information is consistent with publicly available information, and whether any market data
adjusted for entity-specific adjustments were applied. We also tested the completeness and
accuracy of the underlying data, including the participant data used in the actuarial
calculations.
/s/ Ernst & Young LLP
We have served as the Partnership’s auditor since 1999.
Tulsa, Oklahoma
February 18, 2021
58
Report of Independent Registered Public Accounting Firm
To the Common Unitholders of Magellan Midstream Partners, L.P. and the Board of Directors of Magellan GP,
LLC, General Partner of Magellan Midstream Partners, L.P.
Opinion on Internal Control Over Financial Reporting
We have audited Magellan Midstream Partners, L.P.’s internal control over financial reporting as of December 31,
2020, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Magellan
Midstream Partners, L.P. (the Partnership) maintained, in all material respects, effective internal control over
financial reporting as of December 31, 2020, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (PCAOB), the consolidated balance sheets of the Partnership as of December 31, 2020 and 2019, the related
consolidated statements of income, comprehensive income, partners’ capital and cash flows for each of the three
years in the period ended December 31, 2020, and the related notes and our report dated February 18, 2021
expressed an unqualified opinion thereon.
Basis for Opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and
for its assessment of the effectiveness of internal control over financial reporting included in the accompanying
Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an
opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting
firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance
with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange
Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting
was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a
material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on
the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We
believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
An entity’s internal control over financial reporting is a process designed to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. An entity’s internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the entity; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the entity are being made only in accordance with
authorizations of management and directors of the entity; and (3) provide reasonable assurance regarding prevention
or timely detection of unauthorized acquisition, use, or disposition of the entity’s assets that could have a material
effect on the financial statements.
59
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
deteriorate.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 18, 2021
60
MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per unit amounts)
Transportation and terminals revenue...........................................
Product sales revenue....................................................................
Affiliate management fee revenue.................................................
Total revenue...................................................................
Costs and expenses:
2018
Year Ended December 31,
2019
$ 1,878,988 $ 1,970,630 $ 1,794,854
611,719
21,229
2,427,802
736,092
21,190
2,727,912
927,220
20,365
2,826,573
2020
Operating................................................................................
Cost of product sales..............................................................
Depreciation, amortization and impairment...........................
General and administrative.....................................................
Total costs and expenses.................................................
Other operating income (expense).................................................
Earnings of non-controlled entities................................................
Operating profit.............................................................................
Interest expense.............................................................................
Interest capitalized.........................................................................
Interest income...............................................................................
Gain on disposition of assets.........................................................
Other (income) expense.................................................................
Income before provision for income taxes....................................
Provision for income taxes............................................................
Net income..................................................................................... $ 1,333,925 $ 1,020,849 $
649,436
704,313
265,077
194,283
1,813,109
—
181,117
1,194,581
220,979
(17,455)
(3,010)
(353,797)
13,868
1,333,996
71
634,081
619,279
246,134
196,650
1,696,144
2,975
168,961
1,203,704
221,123
(19,284)
(3,285)
(28,966)
11,830
1,022,286
1,437
601,359
513,715
258,676
173,478
1,547,228
101
153,327
1,034,002
234,133
(11,270)
(1,037)
(12,887)
5,164
819,899
2,934
816,965
Basic net income per common unit...............................................
$
5.84 $
4.46 $
3.62
Diluted net income per common unit............................................
$
5.84 $
4.46 $
3.62
Weighted average number of common units outstanding used
for basic net income per unit calculation...................................
228,377
228,658
225,503
Weighted average number of common units outstanding used
for diluted net income per unit calculation................................
228,573
228,842
225,531
See notes to consolidated financial statements.
61
MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
Year Ended December 31,
2018
2019
2020
Net income.......................................................................................... $ 1,333,925 $ 1,020,849 $ 816,965
Other comprehensive income (loss):
Derivative activity:
Net gain (loss) on cash flow hedges.......................................
Reclassification of net loss on cash flow hedges to income...
4,317
2,958
(25,216)
(9,484)
2,736
3,445
Changes in employee benefit plan assets and benefit
obligations recognized in other comprehensive income:
Net actuarial loss.....................................................................
(2,323)
(27,351)
(23,499)
Curtailment gain.....................................................................
—
—
Recognition of prior service credit amortization in income...
(181)
(181)
Recognition of actuarial loss amortization in income.............
Recognition of settlement cost in income...............................
Total other comprehensive income (loss)..........................
10,352
1,964
17,087
5,820
2,606
(41,586)
(21,113)
1,703
(181)
5,934
969
Comprehensive income...................................................................... $ 1,351,012 $ 979,263 $ 795,852
See notes to consolidated financial statements.
62
MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
December 31,
2019
2020
Current assets:
ASSETS
Cash and cash equivalents........................................................................................................
Trade accounts receivable.........................................................................................................
Other accounts receivable.........................................................................................................
Inventory...................................................................................................................................
Commodity derivatives deposits...............................................................................................
Other current assets...................................................................................................................
Total current assets...................................................................................................
Property, plant and equipment..........................................................................................................
Less: accumulated depreciation................................................................................................
Net property, plant and equipment............................................................................
Investments in non-controlled entities..............................................................................................
Right-of-use asset, operating leases..................................................................................................
Long-term receivables......................................................................................................................
Goodwill...........................................................................................................................................
Other intangibles (less accumulated amortization of $6,255 and $9,228 at December 31, 2019
and 2020, respectively).................................................................................................................
Restricted cash..................................................................................................................................
Other noncurrent assets.....................................................................................................................
Total assets................................................................................................................
Current liabilities:
LIABILITIES AND PARTNERS’ CAPITAL
Accounts payable......................................................................................................................
Accrued payroll and benefits....................................................................................................
Accrued interest payable...........................................................................................................
Accrued taxes other than income..............................................................................................
Deferred revenue.......................................................................................................................
Accrued product liabilities........................................................................................................
Commodity derivatives contracts, net.......................................................................................
Current portion of operating lease liability...............................................................................
Other current liabilities.............................................................................................................
Total current liabilities..............................................................................................
Long-term operating lease liability...................................................................................................
Long-term debt, net...........................................................................................................................
Long-term pension and benefits........................................................................................................
Other noncurrent liabilities...............................................................................................................
Commitments and contingencies
Partners’ capital:
$
58,030 $
125,440
23,887
184,399
27,415
40,237
459,408
8,431,227
2,027,193
6,404,034
1,240,551
171,868
20,782
53,260
13,036
109,136
37,075
167,389
34,165
44,392
405,193
8,352,825
2,091,134
6,261,691
1,213,856
166,078
22,755
52,830
47,898
26,569
13,359
44,925
9,411
20,243
$ 8,437,729 $ 8,196,982
$ 150,992 $ 100,022
52,490
58,998
68,313
98,897
79,166
22,372
27,533
50,783
558,574
137,483
4,978,691
163,776
54,652
75,511
64,276
66,007
109,654
90,788
10,222
26,221
73,205
666,876
144,023
4,706,075
145,992
59,735
Common unitholders (228,403 units and 223,120 units outstanding at December 31, 2019
and 2020, respectively).........................................................................................................
Accumulated other comprehensive loss....................................................................................
Total partners’ capital...............................................................................................
Total liabilities and partners’ capital.........................................................................
2,486,996
2,877,105
(183,190)
(162,077)
2,715,028
2,303,806
$ 8,437,729 $ 8,196,982
See notes to consolidated financial statements.
63
MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Year Ended December 31,
2018
2019
2020
Operating Activities:
Net income..............................................................................................................
Adjustments to reconcile net income to net cash provided by operating
$ 1,333,925 $ 1,020,849 $ 816,965
activities:
Depreciation, amortization and impairment expense......................................
Gain on sale and retirement of assets..............................................................
Earnings of non-controlled entities.................................................................
Distributions from operations of non-controlled entities................................
Equity-based incentive compensation expense...............................................
Settlement cost, amortization of prior service credit and actuarial loss..........
Debt extinguishment costs..............................................................................
Changes in components of operating assets and liabilities (Note 8)...............
Net cash provided by operating activities............................................
265,077
246,134
258,676
(328,055)
(181,117)
196,686
32,053
12,135
—
22,246
1,352,950
(28,966)
(168,961)
203,602
24,012
8,245
8,270
7,994
1,321,179
(12,887)
(153,327)
207,600
11,985
6,722
12,893
(41,249)
1,107,378
Investing Activities:
Additions to property, plant and equipment, net(1)..................................................
Proceeds from sale and disposition of assets..........................................................
Investments in non-controlled entities....................................................................
Distributions from returns of investments in non-controlled entities.....................
Deposits received from undivided joint interest third party....................................
Net cash used by investing activities....................................................
(552,257)
576,568
(216,424)
1,786
71,071
(119,256)
(943,990)
65,366
(212,380)
8,494
75,258
(1,007,252)
(439,574)
334,894
(95,068)
501
—
(199,247)
Financing Activities:
Distributions paid....................................................................................................
Repurchase of common units..................................................................................
Borrowings under long-term notes..........................................................................
Debt placement costs...............................................................................................
Payments on notes...................................................................................................
Debt extinguishment costs......................................................................................
Net receipt (payment) on financial derivatives.......................................................
Payments associated with settlement of equity-based incentive compensation......
Net cash used by financing activities...................................................
Change in cash, cash equivalents and restricted cash.....................................................
Cash, cash equivalents and restricted cash at beginning of period.................................
Cash, cash equivalents and restricted cash at end of period............................................
(865,431)
—
—
(404)
(250,000)
—
24,619
(9,285)
(1,100,501)
133,193
176,068
$ 309,261 $
(921,606)
—
996,405
(12,012)
(550,000)
(8,270)
(33,342)
(9,764)
(538,589)
(224,662)
309,261
84,599 $
(927,117)
(276,940)
828,434
(7,583)
(550,000)
(12,893)
(9,484)
(14,700)
(970,283)
(62,152)
84,599
22,447
Supplemental non-cash investing and financing activities:
(1) Additions to property, plant and equipment............................................................
Changes in accounts payable and other current liabilities related to capital
expenditures........................................................................................................
Additions to property, plant and equipment, net.....................................................
See notes to consolidated financial statements.
64
$ (562,296) $ (980,575) $ (358,765)
10,039
(80,809)
$ (552,257) $ (943,990) $ (439,574)
36,585
MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL
(In thousands)
Balance, January 1, 2018.............................................................
Comprehensive income:
Net income.................................................................................
Total other comprehensive income (loss)..................................
Total comprehensive income (loss)......................................
Distributions...................................................................................
Equity-based incentive compensation expense..............................
Issuance of common units in settlement of equity-based
incentive plan awards.................................................................
Payments associated with settlement of equity-based incentive
compensation..............................................................................
ASC 606 cumulative effect............................................................
Other...............................................................................................
Balance, December 31, 2018........................................................
Comprehensive income:
Net income.................................................................................
Total other comprehensive income (loss)..................................
Total comprehensive income (loss)......................................
Distributions...................................................................................
Equity-based incentive compensation expense..............................
Issuance of common units in settlement of equity-based
incentive plan awards.................................................................
Payments associated with settlement of equity-based incentive
compensation..............................................................................
Other...............................................................................................
Balance, December 31, 2019........................................................
Comprehensive income:
Net income.................................................................................
Total other comprehensive income (loss)..................................
Total comprehensive income (loss)......................................
Distributions...................................................................................
Equity-based incentive compensation expense..............................
Repurchase of common units.........................................................
Issuance of common units in settlement of equity-based
incentive plan awards.................................................................
Payments associated with settlement of equity-based incentive
compensation..............................................................................
Other...............................................................................................
Balance, December 31, 2020........................................................
Common
Unitholders
$ 2,267,231
1,333,925
—
1,333,925
(865,431)
32,053
Accumulated
Other
Comprehensive
Loss
$ (137,578)
Total
Partners’
Capital
$ 2,129,653
—
17,087
17,087
—
—
1,333,925
17,087
1,351,012
(865,431)
32,053
120
—
120
(9,285)
5,975
(663)
2,763,925
1,020,849
—
1,020,849
(921,606)
24,012
—
—
—
(120,491)
(9,285)
5,975
(663)
2,643,434
—
(41,586)
(41,586)
—
—
1,020,849
(41,586)
979,263
(921,606)
24,012
480
—
480
(9,764)
(791)
2,877,105
—
—
(162,077)
(9,764)
(791)
2,715,028
816,965
—
816,965
(927,117)
11,985
(276,940)
—
(21,113)
(21,113)
—
—
—
816,965
(21,113)
795,852
(927,117)
11,985
(276,940)
600
—
600
(14,700)
(902)
$ 2,486,996
—
—
$ (183,190)
(14,700)
(902)
$ 2,303,806
See notes to consolidated financial statements.
65
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Description of Business
Organization
Unless indicated otherwise, the terms “our,” “we,” “us” and similar language refer to Magellan Midstream
Partners, L.P. together with its subsidiaries. Magellan Midstream Partners, L.P. is a Delaware limited partnership,
and 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.
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 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.
Description of Products
The following terms are commonly used in our industry to describe products that we transport, store, distribute
or otherwise handle through our petroleum pipelines and terminals:
•
•
•
•
•
•
refined products are the output from crude oil refineries that are primarily used as fuels by consumers.
Refined products include gasoline, diesel fuel, aviation fuel, kerosene and heating oil. Diesel fuel, kerosene
and heating oil are also referred to as distillates;
transmix is a mixture that forms when different refined products are transported in pipelines. Transmix is
fractionated and blended into usable refined products;
liquefied petroleum gases, or LPGs, are liquids produced as by-products of the crude oil refining process
and in connection with natural gas production. LPGs include 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.
66
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
We use the term petroleum products to describe any, or a combination, of the above-noted products.
2.
Summary of Significant Accounting Policies
Significant Accounting Policies
Basis of Presentation. Our consolidated financial statements include our refined products and crude oil
operating segments. We consolidate all entities in which we have a controlling ownership interest. We apply the
equity method of accounting to investments in entities over which we exercise significant influence but do not
control. We eliminate all intercompany transactions.
Reclassifications. Certain prior year amounts have been reclassified to conform with the current period’s
presentation.
Use of Estimates. The preparation of our consolidated financial statements in conformity with U.S. generally
accepted accounting principles (“GAAP”) requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of
our consolidated financial statements, as well as their impact on the reported amounts of revenue and expense during
the reporting periods. Actual results could differ from those estimates.
Cash Equivalents. Cash and cash equivalents include demand and time deposits and funds that own highly
marketable securities with original maturities of three months or less when acquired. We periodically assess the
financial condition of the institutions where we hold these funds, and, at December 31, 2019 and 2020, we believed
our credit risk relative to these funds was minimal.
Restricted Cash. Restricted cash includes cash that we are contractually required to use for the construction of
fixed assets and is unavailable for general use. It is classified as noncurrent due to its designation to be used for the
construction of noncurrent assets.
Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable represent valid claims
against customers. We recognize accounts receivable when we sell products or render services and collection of the
receivable is probable. We extend credit terms to certain customers after a review of various credit indicators. We
establish an allowance for doubtful accounts using an expected credit loss approach and evaluate reserves no less
than quarterly to determine their adequacy. Judgments relative to at-risk accounts include the customers’ current
financial condition, the customers’ historical relationship with us and current and projected economic conditions.
We write off accounts receivable when we deem an account uncollectible.
Product Overages and Shortages. Each period end we measure the volume of each type of product in our
pipeline systems and terminals, which is compared to the volumes of our customers’ inventories (as adjusted for
tender deductions). To the extent the product volumes in our pipeline systems and terminals exceed the volumes of
our customers’ book inventories, we recognize a gain from the product overage and increase our product inventories.
To the extent the product in our pipeline systems and terminals is less than our customers’ book inventories, we
recognize a loss from the product shortage and we record a liability for product owed to our customers. The product
overages we recognize are recorded based on market prices, and the resulting inventory is carried at weighted
average cost. The product shortages we recognize are recorded based on our weighted average cost. Additionally,
when product shortages result in a net short inventory position, the related liability is recorded based on period-end
market prices. Product overages and shortages as well as adjustments to the value of net short inventory positions
are recorded in operating expenses on our consolidated statements of income.
67
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
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 taxable income. Net income for financial statement purposes may differ
significantly from taxable income of unitholders because of differences between the tax basis and financial reporting
basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The
aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily
determined because information regarding each unitholder’s tax attributes is not available to us.
The amounts recognized as provision for income taxes in our consolidated statements of income are primarily
comprised of partnership-level taxes levied by the state of Texas. This tax is based on revenues less direct costs of
sale for our assets apportioned to the state of Texas.
Net Income Per Unit. We calculate basic net income per common unit for each period by dividing net income
by the weighted-average number of common units outstanding. The difference between our actual common units
outstanding and our weighted-average number of common units outstanding used to calculate net income per
common unit is due to the impact of: (i) the phantom units issued to our independent directors, which are included in
the calculation of basic and diluted weighted average units outstanding, and (ii) the weighted-average effect of units
actually issued or repurchased during a period. The difference between the weighted-average number of common
units outstanding used for basic and diluted net income per unit calculations on our consolidated statements of
income is primarily the dilutive effect of phantom unit awards granted pursuant to our long-term incentive plan,
which have not yet vested in periods where contingent performance metrics have been met.
Index of Additional Significant Accounting Policies
Revenue from Contracts with Customers............ Note 4 – Revenue
Property, Plant and Equipment............................ Note 5 – Property, Plant and Equipment,
Goodwill and Other Intangibles
Goodwill and Other Intangible Assets................. Note 5 – Property, Plant and Equipment,
Goodwill and Other Intangibles
Investments in Non-Controlled Entities............... Note 6 – Investments in Non-Controlled Entities
Inventory.............................................................. Note 7 – Inventory
Leases................................................................... Note 10 – Leases
Pension and Postretirement Medical and Life
Benefit Obligations.............................................. Note 11 – Employee Benefit Plans
Equity-Based Incentive Compensation................ Note 12 – Long-Term Incentive Plan
Derivative Financial Instruments......................... Note 13 – Derivative Financial Instruments
Contingencies and Environmental....................... Note 15 – Commitments and Contingencies
68
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
New Accounting Pronouncements
In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”)
2016-13, Financial Instruments - Credit Losses (Topic 326). The new guidance is effective for reporting periods
beginning after December 15, 2019. The standard replaces the incurred loss impairment methodology under current
GAAP with a methodology that reflects expected credit losses and requires the use of a forward-looking
expected credit loss model for accounts receivables, loans and other financial instruments. The standard requires a
modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of
the first reporting period in which the guidance is effective. We adopted the new guidance as of January 1, 2020
using the modified retrospective approach related to our accounts receivables and contract assets, resulting in no
cumulative adjustment to retained earnings. The adoption of this guidance did not have a material impact on our
consolidated statements of income for the year ended December 31, 2020.
3.
Segment Disclosures
Our reportable segments are strategic business units that offer different products and services. Our segments
are managed separately because each segment requires different marketing strategies and business knowledge.
Management evaluates performance based on segment operating margin, which includes revenue from affiliates and
third-party customers, operating expenses, cost of product sales, other operating (income) expense and earnings of
non-controlled entities.
We believe that investors benefit from having access to the same financial measures used by management.
Operating margin, which is presented in the following tables, is an important measure used by management to
evaluate the economic performance of our core operations. Operating margin is not a GAAP measure, but the
components of operating margin are computed using amounts that are determined in accordance with GAAP. A
reconciliation of operating margin to operating profit, which is its nearest comparable GAAP financial measure, is
included in the tables below. Operating profit includes depreciation, amortization and impairment expense and
general and administrative (“G&A”) expense that management does not consider when evaluating the core
profitability of our separate operating segments.
69
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
Transportation and terminals revenue......................
Product sales revenue...............................................
Affiliate management fee revenue...........................
Total revenue...................................................
Operating expenses..................................................
Cost of product sales................................................
Earnings of non-controlled entities..........................
Operating margin.............................................
Depreciation, amortization and impairment
expense...............................................................
G&A expenses.........................................................
Operating profit........................................................
Additions to long-lived assets..................................
Segment assets.........................................................
Corporate assets.......................................................
Total assets...............................................................
Year Ended December 31, 2018
(in thousands)
Refined
Products
Crude Oil
Intersegment
Eliminations
Total
$ 1,316,616 $
880,453
5,533
2,202,602
486,596
660,185
566,063 $
46,767
14,832
627,662
172,478
44,128
(3,691) $ 1,878,988
927,220
20,365
2,826,573
649,436
704,313
—
—
(3,691)
(9,638)
—
(18,884)
1,074,705
(162,233)
573,289
—
5,947
(181,117)
1,653,941
202,047
140,333
732,325 $
57,083
53,950
462,256 $
265,077
5,947
—
194,283
— $ 1,194,581
357,359 $
148,995
$
506,354
$
$
$ 4,687,351 $ 2,803,895
As of December 31, 2018
$ 7,491,246
256,291
$ 7,747,537
$
53,260
$ 1,076,306
Goodwill..................................................................
Investments in non-controlled entities.....................
$
$
41,178 $
292,820 $
12,082
783,486
70
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
Transportation and terminals revenue......................
Product sales revenue...............................................
Affiliate management fee revenue...........................
Total revenue...................................................
Operating expenses..................................................
Cost of product sales................................................
Other operating (income) expense...........................
Earnings of non-controlled entities..........................
Operating margin.............................................
Depreciation, amortization and impairment
expense...............................................................
G&A expenses.........................................................
Operating profit........................................................
Additions to long-lived assets..................................
Segment assets.........................................................
Corporate assets.......................................................
Total assets...............................................................
Year Ended December 31, 2019
(in thousands)
Refined
Products
Crude Oil
Intersegment
Eliminations
Total
$ 1,355,682 $
707,812
6,719
2,070,213
471,743
591,228
(10,185)
(8,070)
1,025,497
620,365 $
28,280
14,471
663,116
173,261
28,051
7,210
(160,891)
615,485
(5,417) $ 1,970,630
736,092
21,190
2,727,912
634,081
619,279
(2,975)
(168,961)
1,646,488
—
—
(5,417)
(10,923)
—
—
—
5,506
174,096
140,735
710,666 $
66,532
55,915
493,038 $
246,134
5,506
—
196,650
— $ 1,203,704
805,902 $
74,235
$
880,137
$
$
$ 5,411,920 $ 2,894,733
As of December 31, 2019
$ 8,306,653
131,076
$ 8,437,729
$
53,260
$ 1,240,551
Goodwill..................................................................
Investments in non-controlled entities.....................
$
$
41,178 $
422,384 $
12,082
818,167
71
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
Year Ended December 31, 2020
(in thousands)
Refined
Products
Crude Oil
Intersegment
Eliminations
Total
$ 1,241,846 $
578,630
6,270
1,826,746
425,443
471,292
(3,247)
(32,555)
965,813
559,570 $
33,089
14,959
607,618
189,087
42,423
3,146
(120,772)
493,734
(6,562) $ 1,794,854
611,719
21,229
2,427,802
601,359
513,715
(101)
(153,327)
1,466,156
—
—
(6,562)
(13,171)
—
—
—
6,609
Transportation and terminals revenue......................
Product sales revenue...............................................
Affiliate management fee revenue...........................
Total revenue...................................................
Operating expenses..................................................
Cost of product sales................................................
Other operating (income) expense...........................
Earnings of non-controlled entities..........................
Operating margin.............................................
Depreciation, amortization and impairment
expense.................................................................
G&A expenses.........................................................
Operating profit........................................................
$
175,510
125,742
664,561 $
76,557
47,736
369,441 $
258,676
6,609
—
173,478
— $ 1,034,002
Additions to long-lived assets..................................
$
291,863 $
56,401
$
348,264
Segment assets.........................................................
Corporate assets.......................................................
Total assets...............................................................
As of December 31, 2020
$ 5,269,691 $ 2,836,888
Goodwill..................................................................
Investments in non-controlled entities.....................
$
$
40,748 $
429,193 $
12,082
784,663
$ 8,106,579
90,403
$ 8,196,982
$
52,830
$ 1,213,856
4. Revenue
Revenue recognition policies
Revenue is recognized upon the satisfaction of each performance obligation required by our customer
contracts. Transportation and terminals revenue is recognized over time as our customers receive the benefits of our
service as it is performed on their behalf using an output method based on actual deliveries. Revenue for our storage
services is recognized over time using an output method based on the capacity of storage under contract with our
customers. Product sales revenue is recognized at a point in time when our customers take control of the
commodities purchased. We record back-to-back purchases and sales of petroleum products on a net basis.
We recognize pipeline transportation revenue for crude oil shipments when our customers’ product arrives at
the customer-designated destination. For shipments of refined products under published tariffs that combine
transportation and terminalling services, we recognize revenue when our customers take delivery of their product
from our system. For shipments where terminalling services are not included in the tariff, we recognize revenue
when our customers’ product arrives at the customer-designated destination. We have certain contracts that require
counterparties to ship a minimum volume over an agreed-upon time period, which are contracted as minimum dollar
or volume commitments. Revenue pursuant to these take-or-pay contracts is recognized when the customers utilize
their committed volumes. Additionally, when we estimate that the customers will not utilize all or a portion of their
committed volumes, we recognize revenue in proportion to the pattern of exercised rights for the respective
commitment period.
72
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
Our interstate common carrier petroleum products pipeline operations are subject to rate regulation by the
Federal Energy Regulatory Commission (“FERC”) under the Interstate Commerce Act, the Energy Policy Act of
1992 and rules and orders promulgated pursuant thereto. FERC regulation requires that interstate pipeline rates be
filed with the FERC, be posted publicly and be nondiscriminatory and “just and reasonable.” The rates on
approximately 40% of the shipments on our refined products pipeline system are regulated by the FERC primarily
through an index methodology. As an alternative to cost-of-service or index-based rates, interstate pipeline
companies may establish rates by obtaining authority to charge market-based rates in competitive markets or by
negotiation with unaffiliated shippers. Approximately 60% of our refined products pipeline system’s markets are
either subject to regulations by the states in which we operate or are approved for market-based rates by the FERC,
and in both cases these rates can generally be adjusted at our discretion based on market factors. Most of the tariffs
on our crude oil pipelines are established by negotiated rates that generally provide for annual adjustments in line
with changes in the FERC index, subject to certain modifications.
For both our index-based rates and our market-based rates, our published tariffs serve as contracts, and
shippers nominate the volume to be shipped up to a month in advance. These tariffs include provisions which allow
us to deduct from our customer’s inventory a small percentage of the products our customers transport on our
pipeline systems. We refer to this non-monetary consideration as tender deduction revenue. We receive tender
deductions from our customers as consideration for product losses during the transportation of petroleum products
within our pipeline systems. Tender deduction revenue is generally recognized as transportation revenue when the
customer's transported commodities reach their destination and is recorded at the fair value of the product received
on the date received or the contract date, as applicable.
Product sales revenue pricing is contractually specified, and we have determined that each barrel sold
represents a separate performance obligation. Transaction prices for our other services including terminalling,
storage and ancillary services are typically contracted as a single performance obligation with our customers. In
circumstances where multiple performance obligations are contractually required, we allocate the transaction price
to the various performance obligations based on their relative standalone selling price.
73
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
The following tables provide details of our revenues disaggregated by key activities that comprise our
performance obligations by operating segment (in thousands):
Year Ended December 31, 2018
Refined
Products
Crude Oil
Intersegment
Eliminations
Total
Transportation......................................................
$
758,028 $
374,352 $
— $
1,132,380
Terminalling........................................................
Storage.................................................................
Ancillary services................................................
Lease revenue......................................................
182,648
212,112
136,122
27,706
Transportation and terminals revenue............
1,316,616
Product sales revenue..........................................
Affiliate management fee revenue.......................
880,453
5,533
Total revenue............................................
2,202,602
6,365
98,597
26,151
60,598
566,063
46,767
14,832
627,662
—
(3,691)
—
—
189,013
307,018
162,273
88,304
(3,691)
1,878,988
—
—
927,220
20,365
(3,691)
2,826,573
Revenue not under the guidance of ASC 606:
Lease revenue(1)..............................................
(Gains) losses from futures contracts
included in product sales revenue(2)............
Affiliate management fee revenue..................
Total revenue from contracts with
(27,706)
(60,598)
(85,643)
(5,533)
632
(14,832)
—
—
—
(88,304)
(85,011)
(20,365)
customers under ASC 606....................
$
2,083,720 $
552,864 $
(3,691) $
2,632,893
(1) Lease revenue is accounted for under ASC 840, Leases.
(2) The impact on product sales revenue from futures contracts falls under the guidance of ASC 815, Derivatives and Hedging.
74
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
Year Ended December 31, 2019
Refined
Products
Crude Oil
Intersegment
Eliminations
Total
Transportation..........................................................
$
787,688 $
381,654 $
— $
1,169,342
Terminalling.............................................................
Storage.....................................................................
Ancillary services.....................................................
Lease revenue...........................................................
185,008
215,042
140,055
27,889
Transportation and terminals revenue.................
1,355,682
Product sales revenue...............................................
Affiliate management fee revenue...........................
707,812
6,719
Total revenue................................................
2,070,213
17,822
119,330
28,376
73,183
620,365
28,280
14,471
663,116
—
(5,417)
—
—
202,830
328,955
168,431
101,072
(5,417)
1,970,630
—
—
736,092
21,190
(5,417)
2,727,912
Revenue not under the guidance of ASC 606:
Lease revenue(1)...................................................
(Gains) losses from futures contracts included
in product sales revenue(2)...............................
Affiliate management fee revenue......................
Total revenue from contracts with
(27,889)
(73,183)
69,538
(6,719)
3,024
(14,471)
—
—
—
(101,072)
72,562
(21,190)
customers under ASC 606........................
$
2,105,143 $
578,486 $
(5,417) $
2,678,212
(1) Lease revenue is accounted for under ASC 842, Leases.
(2) The impact on product sales revenue from futures contracts falls under the guidance of ASC 815, Derivatives and Hedging.
Year Ended December 31, 2020
Refined
Products
Crude Oil
Intersegment
Eliminations
Total
Transportation..........................................................
$
742,951 $
305,397 $
— $
1,048,348
Terminalling.............................................................
Storage.....................................................................
Ancillary services.....................................................
Lease revenue...........................................................
Transportation and terminals revenue.................
Product sales revenue...............................................
Affiliate management fee revenue...........................
149,859
200,091
125,268
23,677
1,241,846
578,630
6,270
Total revenue................................................
1,826,746
21,463
129,048
26,936
76,726
559,570
33,089
14,959
607,618
—
(6,562)
—
—
(6,562)
—
—
171,322
322,577
152,204
100,403
1,794,854
611,719
21,229
(6,562)
2,427,802
Revenue not under the guidance of ASC 606:
Lease revenue(1)...................................................
(Gains) losses from futures contracts included
in product sales revenue(2)...............................
Affiliate management fee revenue......................
Total revenue from contracts with
(23,677)
(76,726)
(62,317)
(6,270)
3,624
(14,959)
—
—
—
(100,403)
(58,693)
(21,229)
customers under ASC 606........................
$
1,734,482 $
519,557 $
(6,562) $
2,247,477
(1) Lease revenue is accounted for under ASC 842, Leases.
(2) The impact on product sales revenue from futures contracts falls under the guidance of ASC 815, Derivatives and Hedging.
75
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
Balance Sheet Disclosures
We invoice customers on our refined products pipelines for transportation services when their product enters
our system. At each period end, we record all invoiced amounts associated with products that have not yet been
delivered (in-transit products) as a contract liability. This liability is presented as deferred revenue on our
consolidated balance sheets. Deferred revenue is also recorded for pre-payments received in conjunction with take-
or-pay contracts, storage contracts and other service offerings in which the service to our customers remains
unfulfilled. Additionally, at each period end, we defer the direct costs we have incurred associated with our
customers’ in-transit products as contract assets. Contract assets are presented on our consolidated balance sheets as
other current assets. These direct costs are estimated based on our per-barrel direct delivery cost for the current
period multiplied by the total in-transit barrels in our system at the end of the period multiplied by 50% to reflect the
average transportation costs incurred for all products across all of our pipeline systems. We use 50% of the in-transit
barrels because that best represents the average delivery point of all barrels in our pipeline system. These contract
assets and contract liabilities are determined using judgments and assumptions that management considers
reasonable.
The following table summarizes our accounts receivable, contract assets and contract liabilities resulting from
contracts with customers (in thousands):
Accounts receivable from contracts with customers....
Contract assets..............................................................
Contract liabilities.........................................................
$
$
$
124,701 $
8,071 $
111,670 $
108,843
12,220
102,964
December 31, 2019
December 31, 2020
For the year ended December 31, 2020, we recognized $93.4 million of transportation and terminals revenue
that was recorded in deferred revenue as of December 31, 2019.
Unfulfilled Performance Obligations
We have certain contracts with customers that represent customer commitments to purchase a minimum
amount of our services over specified time periods. These contracts require us to provide services to our customers
in the future and result in our having unfulfilled performance obligations (“UPOs”) to our customers related to the
periods remaining under each contract. We have UPOs in many of our core business services, including
transportation, terminalling and storage services. The UPOs will be recognized as revenue in the future as our
customers utilize our services or when we estimate that our customers are not likely to use all or a portion of their
commitments.
The following table provides the aggregate amount of the transaction price allocated to our UPOs as of
December 31, 2020 by operating segment, including the range of years remaining on our contracts with customers
and an estimate of revenues expected to be recognized over the next 12 months (dollars in thousands):
Balances at December 31, 2020...............................
$
2,015,459 $
1,262,305 $
3,277,764
Refined Products
Crude Oil
Total
Remaining terms.......................................................
Estimated revenues from UPOs to be recognized in
the next 12 months................................................
1 - 18 years
1 - 11 years
$
383,897 $
273,782 $
657,679
76
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
In computing the value of these future revenues, we have used the current rates in effect as of December 31,
2020 and have not included any estimates for future rate changes due to changes in the FERC index or other
contractually negotiated rate escalations. Our UPO balances include the full amount of our customer commitments
as of December 31, 2020 through the expiration of the related contracts. The UPO balances disclosed exclude all
performance obligations for which the original expected term is one year or less, the consideration is variable or the
future use of our services is fully at the discretion of our customers.
5.
Property, Plant and Equipment, Goodwill and Other Intangibles
Property, Plant and Equipment
Property, plant and equipment consist primarily of pipeline, pipeline-related equipment, storage tanks and
processing equipment. We state property, plant and equipment at cost except for certain acquired assets recorded at
fair value on their respective acquisition dates and impaired assets. We record impaired assets at fair value on the
last impairment evaluation date for which an adjustment was required.
We assign asset lives based on reasonable estimates when we place an asset into service. Subsequent events
could cause us to change our estimates, which would affect the future calculation of depreciation expense.
When we sell or retire property, plant and equipment, we remove its carrying value and the related
accumulated depreciation from our accounts and record any associated gains or losses on our consolidated
statements of income in the period of sale or disposition.
We capitalize expenditures to replace existing assets and retire the replaced assets. We capitalize expenditures
when they extend the useful life, increase the productivity or capacity or improve the safety or efficiency of the
asset. We capitalize direct project costs such as labor and materials as incurred. Indirect project costs, such as
overhead, are capitalized based on a percentage of direct labor charged to the respective capital project. We charge
expenditures for maintenance, repairs and minor replacements to operating expense in the period incurred.
During construction, we capitalize interest on all construction projects requiring a completion period of three
months or longer and total project costs exceeding $0.5 million. The interest we capitalize is based on the weighted-
average interest rate of our debt. The weighted average rates used to capitalize interest on borrowed funds were
4.8%, 4.6% and 4.4% for the years ended December 31, 2018, 2019 and 2020, respectively.
Property, plant and equipment consisted of the following (in thousands):
December 31,
2019
2020
Estimated
Depreciable Lives
Construction work-in-progress............................
$
515,312 $
125,173
Land and rights-of-way.......................................
Buildings.............................................................
Storage tanks.......................................................
Pipeline and station equipment...........................
Processing equipment..........................................
Other....................................................................
336,982
125,772
2,206,839
2,917,059
2,044,589
284,674
385,190
126,619
2,085,601
3,327,078
2,006,835
296,329
Property, Plant and Equipment, Gross........
$
8,431,227 $
8,352,825
10 to 53 years
10 to 49 years
10 to 59 years
3 to 56 years
3 to 53 years
77
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
Other includes total interest capitalized on construction in progress as of December 31, 2019 and 2020 of $86.4
million and $98.4 million, respectively. Depreciation expense for the years ended December 31, 2018, 2019 and
2020 was $214.4 million, $242.9 million and $256.0 million, respectively.
Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the
carrying value may not be recoverable. In reviewing for impairment, the carrying value of such assets is compared to
the estimated undiscounted future cash flows expected from the use of the assets and their eventual disposition. If
such cash flows are not sufficient to support the asset’s recorded value, an impairment charge is recognized to
reduce the carrying value of the long-lived asset to its estimated fair value. The determination of future cash flows as
well as the estimated fair value of long-lived assets involves significant estimates on the part of management.
During 2018, we made the decision to discontinue commercial operations of our ammonia pipeline due to the
system’s low profitability and challenging economic outlook. We estimated the fair value of the ammonia pipeline
assets based on expected future cash flows and recognized a $49.1 million impairment charge in depreciation,
amortization and impairment expense on our consolidated statements of income in 2018.
Goodwill
We record the excess of purchase price over the fair value of the tangible and identifiable intangible assets
acquired and liabilities assumed in a business acquisition (or combination) as goodwill. The goodwill relating to
each of our reporting units is tested for impairment annually as well as when an event or change in circumstances
indicates an impairment may have occurred.
For purposes of performing the impairment test for goodwill, our reporting units are our refined products and
crude oil segments. In 2018, we elected to complete the quantitative goodwill impairment test and calculated that
the fair value of each of our reporting units was greater than its carrying amount. In 2019 and 2020, we elected to
perform the qualitative assessment for purposes of our annual goodwill impairment test and concluded that it was
more likely than not that the fair value of each of our reporting units was greater than its carrying amount. Based on
this assessment, we concluded goodwill was not impaired.
Other Intangibles
Other intangible assets with finite lives are amortized over their estimated useful lives of seven years up to 30
years. The weighted-average asset life of our other intangible assets at December 31, 2020 was approximately 18
years. We adjust the useful lives of our other intangible assets if events or circumstances indicate there has been a
change in the remaining useful lives. We eliminate from our balance sheets the gross carrying amount and the
related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. During the
years ended December 31, 2018, 2019 and 2020, amortization of other intangible assets was $1.6 million, $3.3
million and $2.7 million, respectively.
6.
Investments in Non-Controlled Entities
We account for interests in affiliates that we do not control using the equity method of accounting. Under this
method, an investment is recorded at our acquisition cost or capital contributions, as adjusted by contractual terms,
plus equity in earnings or losses since acquisition or formation, plus interest capitalized, less distributions received
and amortization of interest capitalized and excess net investment. Excess net investment is the amount by which our
investment in a non-controlled entity exceeded our proportionate share of the book value of the net assets of that
investment. We amortize excess net investment over the weighted-average depreciable asset lives of the equity
investee. Our unamortized excess net investment was $33.9 million and $33.0 million at December 31, 2019 and
2020, respectively. The amount of unamortized excess investment is primarily related to our investment in
78
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
BridgeTex. We evaluate equity method investments for impairment whenever events or circumstances indicate that
there is an other-than-temporary loss in value of the investment. In the event that we determine that the loss in value
of an investment is other-than-temporary, we would record a charge to earnings to adjust the carrying value to fair
value. We recognized no equity investment impairments during 2018, 2019 and 2020.
Our equity investments in non-controlled entities at December 31, 2020 were comprised of:
Entity
Ownership Interest
BridgeTex Pipeline Company, LLC (“BridgeTex”)...................................
Double Eagle Pipeline LLC (“Double Eagle”)...........................................
HoustonLink Pipeline Company, LLC (“HoustonLink”)...........................
MVP Terminalling, LLC (“MVP”).............................................................
Powder Springs Logistics, LLC (“Powder Springs”)..................................
Saddlehorn Pipeline Company, LLC (“Saddlehorn”).................................
Seabrook Logistics, LLC (“Seabrook”)......................................................
Texas Frontera, LLC (“Texas Frontera”)....................................................
30%
50%
50%
50%
50%
30%
50%
50%
In the first quarter of 2020, we sold a 10% interest in Saddlehorn to an affiliate of Black Diamond Gathering
LLC, which is majority-owned by Noble Midstream Partners LP, reducing our ongoing investment in Saddlehorn to
a 30% interest. We received $79.9 million in cash from the sale, and we recorded a gain of $12.9 million on our
consolidated statements of income for the year ended December 31, 2020.
We serve as operator of BridgeTex, HoustonLink, MVP, Powder Springs, Saddlehorn, Texas Frontera and the
pipeline activities of Seabrook. We receive fees for management services as well as reimbursement or payment to
us for certain direct operational payroll and other overhead costs. The management fees we receive are reported as
affiliate management fee revenue on our consolidated statements of income. Cost reimbursements we receive from
these entities in connection with our operating services are included as reductions to costs and expenses on our
consolidated statements of income and totaled $3.9 million, $5.3 million and $3.6 million, respectively, for the years
ended December 31, 2018, 2019 and 2020.
79
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
We recorded the following revenue and expense transactions from certain of these non-controlled entities in
our consolidated statements of income (in thousands):
Year Ended December 31,
2018
2019
2020
Transportation and terminals revenue:
BridgeTex, capacity lease....................................
Double Eagle, throughput revenue......................
Saddlehorn, storage revenue................................
$
$
$
39,596 $
41,806 $
42,286
5,250 $
6,213 $
2,180 $
2,234 $
4,917
2,483
Operating costs:
Seabrook, storage lease and ancillary services....
$
10,572 $
25,851 $
29,116
MVP, sale of air emission reduction credits
(reduction of operating costs)..............................
Product sales revenue:
Powder Springs, butane sales..............................
Seabrook, product sales.......................................
$
$
$
(2,161) $
— $
4,899 $
— $
— $
328 $
Cost of product sales:
Powder Springs, butane purchases......................
$
410 $
— $
Other operating income:
MVP, easement sale............................................
Seabrook, gain on sale of air emission credits.....
$
$
— $
— $
289 $
— $
1,410
—
—
—
—
—
Our consolidated balance sheets reflected the following balances related to our investments in non-controlled
entities (in thousands):
Trade
Accounts
Receivable
December 31, 2019
Other
Other
Accounts
Accounts
Payable
Receivable
Long-Term
Receivables
BridgeTex.......................
Double Eagle..................
HoustonLink...................
MVP...............................
Powder Springs..............
Saddlehorn......................
Seabrook.........................
$
$
$
$
$
$
$
392 $
445 $
60 $
— $
161 $
26 $
— $
— $
418 $
— $
— $
126 $
— $
— $
— $
— $
— $
— $
941 $
— $
1,349 $
—
—
—
—
6,006
—
—
80
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
Trade
Accounts
Receivable
December 31, 2020
Other
Other
Accounts
Accounts
Payable
Receivable
Long-Term
Receivables
BridgeTex.......................
Double Eagle..................
HoustonLink...................
MVP...............................
Powder Springs..............
Saddlehorn......................
Seabrook.........................
$
$
$
$
$
$
$
355 $
277 $
— $
— $
— $
— $
— $
27 $
— $
— $
970 $
— $
144 $
467 $
2,297 $
—
—
—
—
— $
121 $
— $
10,223
— $
— $
7,274 $
—
—
We entered into a long-term terminalling and storage contract with Seabrook for exclusive use of dedicated
tankage that provides our customers with crude oil storage capacity and dock access for crude oil imports and
exports on the Texas Gulf Coast (see Note 10 – Leases for more details regarding this lease).
The financial results from Powder Springs, MVP and Texas Frontera are included in our refined products
segment and the financial results from BridgeTex, Double Eagle, HoustonLink, Saddlehorn and Seabrook are
included in our crude oil segment, each as earnings of non-controlled entities.
A summary of our investments in non-controlled entities (representing only our proportionate interests)
follows (in thousands):
Investments at December 31, 2019.............................................................................
$
1,240,551
Additional investment.................................................................................................
Sale of ownership interest in Saddlehorn...................................................................
Earnings of non-controlled entities:
Proportionate share of earnings.............................................................................
Amortization of excess investment and capitalized interest..................................
Earnings of non-controlled entities..................................................................
95,068
(66,989)
155,140
(1,813)
153,327
Less:
Distributions from operations of non-controlled entities......................................
207,600
Distributions from returns of investments in non-controlled entities....................
501
Investments at December 31, 2020.............................................................................
$
1,213,856
81
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
Summarized financial information of our non-controlled entities (representing 100% of the interests in these
entities) follows (in thousands):
December 31,
2019
2020
Current assets....................................................................
$
260,033 $
243,828
Noncurrent assets..............................................................
2,768,696
2,846,747
Total assets...................................................................
$
3,028,729 $
3,090,575
Current liabilities..............................................................
$
160,566 $
143,638
Noncurrent liabilities........................................................
60,886
57,515
Total liabilities.............................................................
Equity................................................................................
$
$
221,452 $
201,153
2,807,277 $
2,889,422
Year Ended December 31,
2018
2019
2020
Revenue................................................
Net income............................................
$
$
631,420 $
782,013 $
752,685
416,128 $
507,464 $
471,438
7.
Inventory
Inventory is comprised primarily of refined products, liquefied petroleum gases, transmix, crude oil and
additives, which are stated and relieved at the lower of average cost or net realizable value.
Inventory at December 31, 2019 and 2020 was as follows (in thousands):
December 31,
2019
2020
Refined products...............................................................................
$
96,128 $
29,982
39,546
12,714
6,029
79,473
26,734
23,397
32,431
5,354
$
184,399 $
167,389
Liquefied petroleum gases................................................................
Transmix...........................................................................................
Crude oil............................................................................................
Additives...........................................................................................
Total inventory..........................................................................
82
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
8.
Consolidated Statements of Cash Flows
Changes in the components of operating assets and liabilities are as follows (in thousands):
Trade accounts receivable and other accounts receivable...........................
Inventory......................................................................................................
Accounts payable.........................................................................................
Accrued payroll and benefits.......................................................................
Accrued interest payable..............................................................................
Accrued taxes other than income.................................................................
Deferred revenue..........................................................................................
Accrued product liabilities...........................................................................
Other current and noncurrent assets and liabilities......................................
Year Ended December 31,
2018
2019
2020
$
24,169 $
(20,156) $
(1,172)
(3,390)
21,146
14,015
(7,399)
1,750
5,191
(20,677)
(12,559)
1,336
(1,237)
4,931
1,018
12,914
(11,431)
15,306
5,313
15,771
4,225
(23,269)
(5,278)
4,131
(10,757)
(11,622)
(13,278)
Total.....................................................................................................
$
22,246 $
7,994 $
(41,249)
Other current and noncurrent assets and liabilities above exclude certain non-cash items that were reflected in
the consolidated balance sheets but were not reflected in the statements of cash flows. At December 31, 2018, 2019
and 2020, the long-term pension and benefits liability was increased by $2.3 million, $27.0 million and $21.5
million, respectively, resulting in a corresponding increase in accumulated other comprehensive loss (“AOCL”).
83
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
9.
Debt
Long-term debt at December 31, 2019 and 2020 was as follows (in thousands):
December 31,
2019
2020
4.25% Notes due 2021........................................................................................
$
550,000 $
3.20% Notes due 2025........................................................................................
5.00% Notes due 2026........................................................................................
3.25% Notes due 2030........................................................................................
6.40% Notes due 2037........................................................................................
4.20% Notes due 2042........................................................................................
5.15% Notes due 2043........................................................................................
4.20% Notes due 2045........................................................................................
4.25% Notes due 2046........................................................................................
4.20% Notes due 2047........................................................................................
4.85%Notes due 2049.........................................................................................
3.95% Notes due 2050........................................................................................
250,000
650,000
—
250,000
250,000
550,000
250,000
500,000
500,000
500,000
500,000
—
250,000
650,000
500,000
250,000
250,000
550,000
250,000
500,000
500,000
500,000
800,000
Face value of long-term debt...................................................................
Unamortized debt issuance costs(1).....................................................................
Net unamortized debt premium (discount)(1)......................................................
4,750,000
5,000,000
(35,263)
(8,662)
(40,143)
18,834
Long-term debt, net.................................................................................
$
4,706,075 $
4,978,691
(1) Debt issuance costs, note discounts and premiums and realized gains and losses of historical fair value hedges are being amortized
or accreted to the applicable notes over the respective lives of those notes.
All of the instruments detailed in the table above are senior indebtedness.
At December 31, 2020, maturities of our debt were as follows: $0 in 2021 through 2024; $250 million in 2025;
and $4.75 billion thereafter.
2020 Debt Issuances
In December 2020, we issued $300.0 million of our 3.95% senior notes due 2050. The notes, which are
additional notes of the series originally issued in August 2019, were priced at 109.678% of par. Net proceeds from
this offering were approximately $329.2 million after underwriting discounts and offering expenses, and including
accrued interest. The net proceeds from this offering will be used for general partnership purposes, which may
include repayment of indebtedness, including borrowings under our revolving credit facility and commercial paper
program, capital expenditures and repurchases of our common units.
84
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
In May 2020, we issued $500.0 million of 3.25% senior notes due 2030 in an underwritten public
offering. The notes were issued at 99.88% of par. Net proceeds from this offering were approximately $495.2
million after underwriting discounts and offering expenses. The net proceeds from this offering, along with
commercial paper borrowings and cash on hand, were used to redeem our $550.0 million senior notes due in 2021.
We recognized $12.9 million of debt extinguishment costs that were recorded as interest expense in our consolidated
statements of income related to this early redemption, partially offset by the recognition of a $0.7 million
unamortized debt premium, for the year ended December 31, 2020.
Other Debt
Revolving Credit Facility. At December 31, 2020, the total borrowing capacity under our revolving credit
facility maturing in May 2024 was $1.0 billion. Any borrowings outstanding under this facility are classified as
long-term debt on our consolidated balance sheets. Borrowings under the facility are unsecured and bear interest at
LIBOR plus a spread ranging from 0.875% to 1.500% based on our credit ratings. Additionally, an unused
commitment fee is assessed at a rate from 0.075% to 0.200% depending on our credit ratings. The unused
commitment fee was 0.125% at December 31, 2020. Borrowings under this facility may be used for general
purposes, including capital expenditures. As of December 31, 2019 and 2020, there were no borrowings under this
facility and $3.5 million was obligated for letters of credit. Amounts obligated for letters of credit are not reflected
as debt on our consolidated balance sheets, but decrease our borrowing capacity under the facility.
Our revolving credit facility requires us to maintain a specified ratio of consolidated debt to EBITDA (as
defined in the credit agreement) of no greater than 5.0 to 1.0. In addition, the revolving credit facility and the
indentures under which our senior notes were issued contain covenants that limit our ability to, among other things,
incur indebtedness secured by certain liens or encumber our assets, engage in certain sale-leaseback transactions and
consolidate, merge or dispose of all or substantially all of our assets. We were in compliance with these covenants as
of and during the year ended December 31, 2020.
Commercial Paper Program. We have a commercial paper program under which we may issue commercial
paper notes in an amount up to the available capacity under our $1.0 billion revolving credit facility. The maturities
of the commercial paper notes vary, but may not exceed 397 days from the date of issuance. Because the
commercial paper we can issue is limited to amounts available under our revolving credit facility, amounts
outstanding under the program are classified as long-term debt. The commercial paper notes are sold under
customary terms in the commercial paper market and are issued at a discount from par, or alternatively, are sold at
par and bear varying interest rates on a fixed or floating basis. The weighted-average interest rate for commercial
paper borrowings based on the number of days outstanding was 2.6% and 0.4% for the year ended December 31,
2019 and 2020, respectively. There were no borrowings outstanding under this program at December 31, 2019 and
2020.
During the years ending December 31, 2018, 2019 and 2020, total cash payments for interest on all
indebtedness, excluding the impact of related interest rate swap agreements, were $227.8 million, $217.1 million and
$234.5 million, respectively.
10. Leases
We have both lessee and lessor arrangements. Our leases are evaluated at inception or at any subsequent
modification. Depending on the terms, leases are classified as either operating or finance leases if we are the lessee,
or as operating, sales-type or direct financing leases if we are the lessor, as appropriate under ASC 842, Leases. Our
lessee arrangements primarily include a terminalling and storage contract where we have exclusive use of dedicated
tankage, leased pipelines and office buildings. Our lessor arrangements include pipeline capacity and storage
contracts and our condensate splitter tolling agreement that qualify as operating leases under ASC 842. In addition,
85
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
we have a long-term throughput and deficiency agreement with a customer that is being accounted for as a sales-
type lease under ASC 842.
In accordance with ASC 842, we have made an accounting policy election to not apply the standard to lessee
arrangements with a term of one year or less and no purchase option that is reasonably certain of exercise. We will
continue to account for these short-term arrangements by recognizing payments and expenses as incurred, without
recording a lease liability and right-of-use asset.
We have also made an accounting policy election for both our lessee and lessor arrangements to combine lease
and non-lease components. This election is applied to all of our lease arrangements as our non-lease components do
not result in significant timing differences in the recognition of rental expenses or income.
Operating Leases – Lessee
We recognize a lease liability for each lease based on the present value of remaining minimum fixed rental
payments (which includes payments under any renewal option that we are reasonably certain to exercise), using a
discount rate that approximates the rate of interest we would have to pay to borrow on a collateralized basis over a
similar term. We also recognize a right-of-use asset for each lease, valued at the lease liability, adjusted for prepaid
or accrued rent balances existing at the time of initial recognition. The lease liability and right-of-use asset are
reduced over the term of the lease as payments are made and the assets are used.
Related Party Operating Lease. We entered into a long-term terminalling and storage contract with Seabrook
for exclusive use of dedicated tankage that provides our customers with crude oil storage capacity and dock access
for crude oil imports and exports on the Texas Gulf Coast.
Minimum fixed rental payments are recognized on a straight-line basis over the life of the lease as costs and
expenses on our consolidated statements of income. Variable and short-term rental payments are recognized as
costs and expenses as they are incurred. Variable payments consist of amounts that exceed the contractual minimum
rental payment (for example, payment increases tied to a change in a market index). Future minimum rental
payments under operating leases with initial terms greater than one year as of December 31, 2020 are as follows (in
thousands):
Third Party
Leases
Seabrook Lease
All Leases
2021........................................................................... $
20,463 $
12,701 $
2022...........................................................................
2023...........................................................................
2024...........................................................................
2025...........................................................................
Thereafter..................................................................
Total future minimum rental payments.............
Present value discount...............................................
Total operating lease liability............................ $
20,609
20,854
16,956
16,250
18,541
113,673
11,593 $
102,080 $
9,919
9,919
9,643
6,612
24,246
73,040
10,104 $
62,936 $
33,164
30,528
30,773
26,599
22,862
42,787
186,713
21,697
165,016
86
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
The following tables provide further information about our operating leases (dollars in thousands):
Year Ended 12/31/2019
Year Ended 12/31/2020
Third Party
Leases
Seabrook
Lease
All Leases
Third Party
Leases
Seabrook
Lease
All Leases
Fixed lease expense................
$
19,171 $
10,834 $
30,005 $
19,224 $
14,262 $
33,486
Short-term lease expense........
Variable lease expense............
1,603
3,058
—
15,017
1,603
18,075
1,334
4,105
—
14,854
1,334
18,959
Total lease expense............
$
23,832 $
25,851 $
49,683 $
24,663 $
29,116 $
53,779
As of and for the Year Ended
December 31, 2019
December 31, 2020
Third Party
Leases
Seabrook
Lease
All Leases
Third Party
Leases
Seabrook
Lease
All Leases
Current lease liability..............
Long-term lease liability.........
Right-of-use asset...................
$
$
$
15,136 $
11,085 $
26,221 $
17,099 $
10,434 $
27,533
81,508 $
98,268 $
84,982 $
62,515 $ 144,023 $
73,600 $ 171,868 $ 103,142 $
52,501 $ 137,483
62,936 $ 166,078
Operating cash flows for
operating leases.......................
Weighted average remaining
lease term (years)....................
Weighted-average discount
rate..........................................
$
23,253
25,870 $
49,123 $
24,098
29,116 $
53,214
6
8
7
6
7
7
3.9%
4.0%
4.0%
3.7%
4.0%
3.8%
Rent expense was $42.1 million for the year ended December 31, 2018 and was recognized in accordance with
ASC 840.
Operating Leases – Lessor
We recognize fixed rental income on a straight-line basis over the life of the lease as revenue on our
consolidated statements of income. Variable rental payments are recognized as revenue in the period in which the
circumstances on which the variable lease payments are based occur.
Future minimum payments receivable under operating leases with initial terms greater than one year as of
December 31, 2020 are estimated as follows (in thousands):
2021............................................. $
2022.............................................
2023.............................................
2024.............................................
2025.............................................
Thereafter.....................................
30,235
21,322
18,820
18,562
13,911
40,645
Total..................................... $
143,495
87
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
We recognized variable lease revenue of $51.8 million, $58.4 million and $61.4 million, respectively, for the
years ended December 31, 2018, 2019 and 2020, primarily related to our condensate splitter.
At December 31, 2020, property, plant and equipment utilized by our customers in operating lease
arrangements consisted of: $226.4 million of processing equipment; $58.3 million of storage tanks; $48.7 million of
pipeline and station equipment; and $30.5 million of other assets. The processing equipment primarily relates to our
condensate splitter.
Sales-Type Lease – Lessor
We entered into a long-term throughput and deficiency agreement with a customer on a pipeline and related
assets that we constructed in Texas and New Mexico, which contains minimum volume/payment commitments. Our
customer has the option to purchase this pipeline and related assets at the end of the lease term for a nominal
amount. This agreement is accounted for as a sales-type lease under ASC 842. The net investment under this
arrangement as of December 31, 2019 and 2020 was as follows (in thousands):
Total minimum lease payments receivable................................
$
15,721 $
Less: Unearned income.............................................................
2,814
Recorded net investment in sales-type lease.........................
$
12,907 $
13,974
2,257
11,717
December 31,
2019
December 31,
2020
The net investment in this sales-type lease was classified in the consolidated balance sheets as follows (in
millions):
Other accounts receivable........................................................
$
1,190 $
Long-term receivables.............................................................
11,717
Total....................................................................................
$
12,907 $
1,245
10,472
11,717
December 31,
2019
December 31,
2020
Future minimum payments receivable under this sales-type lease for the next five years are $1.7 million each
year with $5.3 million due thereafter.
11. Employee Benefit Plans
Our pension and postretirement benefit liabilities represent the funded status of the present value of benefit
obligations of our employee benefit plans. We develop pension, postretirement medical and life benefit costs from
third-party actuarial valuations. We establish actuarial assumptions to anticipate future events and use those
assumptions when calculating the expense and liabilities related to these plans. These factors include assumptions
management makes concerning expected investment return on plan assets, discount rates, health care costs trend
rates, turnover rates and rates of future compensation increases, among others. In addition, we use subjective factors
such as withdrawal and mortality rates to develop actuarial valuations. Management reviews and updates these
assumptions on an annual basis. The actuarial assumptions that we use may differ from actual results due to
changing market rates or other factors. These differences could affect the amount of pension and postretirement
medical and life benefit expense we will recognize in future periods.
Defined Contribution Plan. We sponsor a defined contribution plan in which we match our employees’
qualifying contributions, resulting in additional expense to us. Expenses related to the defined contribution plan
88
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
were $11.0 million, $11.4 million and $12.2 million in 2018, 2019 and 2020, respectively.
Defined Benefit Plans. We sponsor two pension plans, including one for all non-union employees and one
that covers union employees, and a postretirement benefit plan for certain employees. The annual measurement date
of these plans is December 31.
The following table presents the changes in benefit obligations and plan assets for pension benefits and other
postretirement benefits, as well as the end-of-period accumulated benefit obligation for the years ended
December 31, 2019 and 2020 (in thousands):
Pension Benefits
Other Postretirement Benefits
2019
2020
2019
2020
Change in benefit obligations:
Benefit obligations at beginning of year....................
Service cost................................................................
Interest cost................................................................
Plan participants’ contributions.................................
Actuarial loss............................................................
Benefits paid..............................................................
Curtailment gain.........................................................
Settlement payments..................................................
Benefit obligations at end of year..............................
Change in plan assets:
Fair value of plan assets at beginning of year............
Employer contributions..............................................
Plan participants’ contributions.................................
Actual return on plan assets.......................................
Benefits paid..............................................................
Settlement payments..................................................
Fair value of plan assets at end of year......................
Funded status at end of year...............................................
Accumulated benefit obligations.......................................
$
$
$
308,949 $
25,406
12,163
—
54,171
(11,409)
—
(8,040)
381,240
197,590
31,630
—
39,522
(11,409)
(8,040)
249,293
(131,947) $
381,240 $
27,736
10,989
—
53,165
(23,097)
(1,703)
(4,685)
443,645
249,293
29,338
—
43,560
(23,097)
(3,343)
295,751
(147,894) $
274,353 $
324,770
12,080 $
193
507
564
3,300
(1,437)
—
—
15,207
—
873
564
—
(1,437)
—
—
(15,207) $
15,207
258
479
567
2,540
(1,758)
—
—
17,293
—
1,191
567
—
(1,758)
—
—
(17,293)
At December 31, 2019 and 2020, the accumulated benefit obligations of each of our plans exceeded the fair
value of the related plans’ assets.
The pension plans actuarial loss in 2020 of $53.2 million is primarily due to the impact of decreases in the
discount rates used to calculate the benefit obligations, partially offset by demographic changes. The pension
benefit obligations experienced an actuarial loss of $54.2 million in 2019 primarily due to the impact of decreases in
the discount rates used to calculate the benefit obligations, partially offset by changes in salary assumptions and
higher asset returns.
89
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
The following table summarizes information for pension plans with obligations in excess of plan assets (in
thousands):
December 31,
2019
2020
Plans with a projected benefit obligation in excess of plan assets:
Projected benefit obligation..............................................................
$
Fair value of plan assets.................................................................... $
381,240 $
249,293 $
443,645
295,751
Plans with an accumulated benefit obligation in excess of plan assets:
Accumulated benefit obligation........................................................ $
Fair value of plan assets.................................................................... $
274,353 $
249,293 $
324,770
295,751
Amounts recognized in the consolidated balance sheets included in these financial statements were as follows
(in thousands):
Amounts recognized in consolidated balance sheets:
Current accrued benefit cost......................................
Long-term pension and benefits.................................
$
Accumulated other comprehensive loss:
Net actuarial loss................................................
Prior service credit.............................................
Net amount of liabilities and accumulated other
comprehensive loss recognized in consolidated
balance sheets.........................................................
Pension Benefits
Other Postretirement Benefits
2019
2020
2019
2020
— $
— $
131,947
131,947
147,894
147,894
1,162 $
14,045
15,207
(107,625)
2,886
(104,739)
(120,487)
2,705
(117,782)
(8,378)
—
(8,378)
1,411
15,882
17,293
(10,409)
—
(10,409)
$
27,208 $
30,112 $
6,829 $
6,884
Net periodic benefit expense for the years ended December 31, 2018, 2019 and 2020 was as follows (in
thousands):
Pension Benefits
Other Postretirement Benefits
2018
2019
2020
2018
2019
2020
Components of net periodic pension and
postretirement benefit expense:
Service cost...........................................
Interest cost...........................................
Expected return on plan assets..............
Amortization of prior service credit.....
Amortization of actuarial loss...............
Settlement cost......................................
Settlement gain on disposition of
assets.................................................
Net periodic expense............................
$ 38,167 $ 25,406 $ 27,736 $
12,163
(9,401)
10,989
(11,354)
14,907
(12,090)
243 $
416
—
193 $
507
—
(181)
9,763
1,964
(181)
5,489
2,606
(181)
5,425
969
—
—
(1,342)
—
589
—
—
$ 52,530 $ 36,082 $ 32,242 $ 1,248 $
90
258
479
—
—
509
—
—
331
—
—
1,031 $
—
1,246
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
The service component of our net periodic benefit expense (credit) is presented in operating expense and G&A
expense, and the non-service components are presented in other (income) expense in our consolidated statements of
income.
Net periodic benefit expense for the year ended December 31, 2018 includes corrections of $19.4 million
resulting from an error in our third-party actuary’s valuation of our pension liabilities and net periodic pension
expense. In addition, long-term pension and benefits increased $22.2 million and accumulated other comprehensive
loss increased $2.8 million in our 2018 consolidated balance sheets as a result of this valuation error.
Changes in plan assets and benefit obligations recognized in other comprehensive income (loss) during 2018,
2019 and 2020 were as follows (in thousands):
Beginning balance...............................
$
(97,226) $ (88,602) $ (104,739) $
(6,597) $
(5,409) $
(8,378)
Pension Benefits
2019
2018
2020
Other Postretirement Benefits
2019
2020
2018
Net actuarial gain (loss).......................
(2,922)
(24,051)
(20,959)
Amortization of prior service credit....
Amortization of actuarial loss.............
Curtailment gain..................................
Settlement cost....................................
Amount recognized in other
comprehensive loss.............................
(181)
9,763
—
1,964
(181)
5,489
—
2,606
(181)
5,425
1,703
969
599
—
589
—
—
(3,300)
(2,540)
—
331
—
—
—
509
—
—
8,624
(16,137)
(13,043)
1,188
(2,969)
(2,031)
Ending balance....................................
$
(88,602) $ (104,739) $ (117,782) $
(5,409) $
(8,378) $
(10,409)
Actuarial gains and losses are amortized over the average future service period of the current active plan
participants expected to receive benefits. The corridor approach is used to determine when actuarial gains and losses
are to be amortized and is equal to 10% of the greater of the projected benefit obligation or the market related value
of plan assets. The amount of gain or loss in excess of the calculated corridor is subject to amortization. The
estimated net actuarial loss and prior service credit for the defined benefit pension plans that will be amortized from
AOCL into net periodic benefit cost in 2021 are $6.2 million and $0.2 million, respectively. The estimated net
actuarial loss for the other defined benefit postretirement plan that will be amortized from AOCL into net periodic
benefit cost in 2021 is $0.6 million.
The weighted-average rate assumptions used to determine projected benefit obligations were as follows:
Discount rate...........................................
Rate of compensation increase................
Cash balance interest crediting rate.........
Pension Benefits
Other Postretirement Benefits
2019
3.01%
4.58%
2.16%
2020
2.23%
4.53%
1.70%
2019
3.06%
n/a
n/a
2020
2.30%
n/a
n/a
91
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
The weighted-average rate assumptions used to determine net pension and other postretirement benefit plans
expense were as follows:
Discount rate...........................................
Rate of compensation increase................
Expected rate of return on plan assets.....
Cash balance interest crediting rate.........
Pension Benefits
Other Postretirement Benefits
For the Year Ended December 31,
For the Year Ended December 31,
2018
3.63%
6.38%
6.00%
3.15%
2019
3.98%
6.48%
6.00%
2.78%
2020
3.01%
4.58%
4.50%
2.16%
2018
3.43%
n/a
n/a
n/a
2019
4.08%
n/a
n/a
n/a
2020
3.06%
n/a
n/a
n/a
The non-pension postretirement benefit plans provide for retiree contributions and contain other cost-sharing
features such as deductibles and coinsurance. The accounting for these plans anticipates future cost sharing that is
consistent with management’s expressed intent to increase the retiree contribution rate generally in line with health
care cost increases.
The annual assumed rate of increase in the health care cost trend rate for 2021 is 6.0% decreasing
systematically to 5.08% by 2028 for pre-65 year old participants.
The fair values of the pension plan assets at December 31, 2019 were as follows (in thousands):
Asset Category
Total
Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)
Significant
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Domestic Equity Securities:(1)
Small-cap fund..................................................
Mid-cap fund.....................................................
Large-cap fund..................................................
International equity fund...........................................
Fixed Income Securities:(1)
$
5,087 $
5,095
40,884
25,580
5,087 $
5,095
40,884
25,580
Short-term bond fund........................................
Intermediate-term bond fund............................
Long-term investment grade bond funds..........
3,590
29,485
132,096
3,590
29,485
132,096
Other:
Short-term investment fund..............................
Group annuity contract.....................................
Fair value of plan assets............................................
$
7,300
176
249,293 $
7,300
—
249,117 $
— $
—
—
—
—
—
—
—
—
— $
—
—
—
—
—
—
—
—
176
176
(1) We hold equity and fixed income securities through investments in mutual funds, which are dedicated to each category as indicated.
The fair values of the pension plan assets at December 31, 2020 were as follows (in thousands):
92
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
Asset Category
Total
Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)
Significant
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Domestic Equity Securities(1):
Small-cap fund...................................................
Mid-cap fund......................................................
Large-cap fund...................................................
International equity fund............................................
Fixed Income Securities(1):
$
5,798 $
5,853
47,598
29,876
5,798 $
5,853
47,598
29,876
Short-term bond fund.........................................
Intermediate-term bond fund.............................
Long-term investment grade bond funds...........
4,209
34,894
161,007
4,209
34,894
161,007
Other:
Short-term investment fund...............................
Group annuity contract......................................
Fair value of plan assets.............................................
$
6,354
162
295,751 $
6,354
—
295,589 $
— $
—
—
—
—
—
—
—
—
— $
—
—
—
—
—
—
—
—
162
162
(1) We hold equity and fixed income securities through investments in mutual funds, which are dedicated to each category as indicated.
As reflected in the tables above, Level 3 activity was not material.
The investment strategies for the various funds held as pension plan assets by asset category are as follows:
Asset Category
Domestic Equity Securities:
Fund’s Investment Strategy
Small-cap fund................................................. Seeks to track performance of the Center for Research in Security Prices
(“CRSP”) US Small Cap Index
Mid-cap fund...................................................
Seeks to track performance of the CRSP US Mid Cap Index
Large-cap fund................................................. Seeks to track performance of the Standard & Poor’s 500 Index
International equity fund......................................
Seeks long-term growth of capital by investing 65% or more of assets in
international equities
Fixed Income Securities:
Short-term bond fund....................................... Seeks current income with limited price volatility through investment in
primarily high quality bonds
Intermediate-term bond fund...........................
Seeks moderate and sustainable level of current income by investing
primarily in high quality fixed income securities with maturities from five
to ten years
Long-term investment grade bond funds......... Seek high and sustainable current income through investment primarily in
long-term high grade bonds
Other:
Short-term investment fund.............................
Invests in high quality short-term money market instruments issued by the
U.S. Treasury
Group annuity contract.................................... Earns interest quarterly equal to the effective yield of the 91-day U.S.
Treasury bill
The expected long-term rate of return on plan assets was determined by combining a review of projected
returns, historical returns of portfolios with assets similar to the current portfolios of the union and non-union
pension plans and target weightings of each asset classification. Our investment objective for the assets within the
93
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
pension plans is to earn a return that meets or exceeds the growth of obligations that result from interest and changes
in the discount rate, while avoiding excessive risk. Defined diversification goals are set in order to reduce the risk of
wide swings in the market value from year to year, or of incurring large losses that may result from concentrated
positions. As a result, our plan assets have no significant concentrations of credit risk. Additionally, liquidity risks
are minimized because all of the funds that the plans have invested in are publicly traded. We evaluate risks based
on the potential impact to the predictability of contribution requirements, probability of under-funding, expected
risk-adjusted returns and investment return volatility. Funds are invested with multiple investment managers. Our
liabilities are calculated using rates defined by the Pension Protection Act of 2006. Approximately 70% of the
plans’ investments are allocated to fixed-income securities and invested to match the durations of the plans’ short,
intermediate and long-term pension liabilities, with the amount invested in each duration reflecting that duration’s
proportion of the plans’ liabilities. The remaining approximately 30% of the plans’ investments are allocated to
equity securities.
The target allocation and actual weighted-average asset allocation percentages at December 31, 2019 and 2020
were as follows:
Equity securities.................................................................
Fixed income securities......................................................
Other..................................................................................
2019
2020
Actual
30%
67%
3%
Target
30%
67%
3%
Actual
30%
68%
2%
Target
30%
67%
3%
As of December 31, 2020, the benefit amounts expected to be paid from plan assets through December 31,
2030 were as follows (in thousands):
Pension
Benefits
Other
Postretirement
Benefits
2021..................................................................................................................
2022..................................................................................................................
2023..................................................................................................................
2024..................................................................................................................
2025..................................................................................................................
2026 through 2030............................................................................................
21,404 $
$
17,855 $
$
21,413 $
$
22,878 $
$
$
23,629 $
$ 145,885 $
1,410
1,275
1,168
1,016
975
3,929
Contributions estimated to be paid by us into the plans in 2021 are $29.7 million and $1.4 million for the
pension and other postretirement benefit plans, respectively.
94
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
12. Long-Term Incentive Plan
The compensation committee of our general partner’s board of directors administers our long-term incentive
plan (“LTIP”) covering certain of our employees and the independent directors of our general partner. The LTIP
primarily consists of phantom units and permits the grant of awards covering an aggregate of 11.9 million of our
common units. The estimated units remaining available under the LTIP at December 31, 2020 totaled
approximately 1.1 million. The awards include: (i) performance-based awards issued to certain officers and other
key employees (“performance-based awards”), (ii) time-based awards issued to certain officers and other key
employees (“time-based awards,” and together with performance-based awards, “employee awards”), and (iii)
awards issued to independent members of our general partner’s board of directors (“director awards”) that may be
deferred and if deferred may be paid in cash. All of the awards include distribution equivalent rights, except non-
deferred director awards.
The LTIP requires employee awards to be settled in our common units, except the settlement of distribution
equivalents, which we pay in cash. As a result, we classify employee awards as equity. Fair value for these awards
is determined on the grant date, and we recognize this value as compensation expense ratably over the requisite
service period, which is the vesting period of each award. The vesting period for employee awards is generally three
years; however, certain awards have been issued with shorter vesting periods while others have vesting periods of up
to four years. Because employee awards contain distribution equivalent rights, the fair value of our employee
awards is based on the closing price of our units on the grant date.
Payouts for performance-based awards are subject to the attainment of a financial metric. Additionally, the
2018 and 2019 performance-based awards are subject to an adjustment for our total unitholder return (the “TUR
adjustment”), and the fair value of these awards is adjusted for the fair value of the TUR adjustment. The financial
metric for the performance-based awards is our distributable cash flow per unit excluding commodity-related
activities for the last year of the three-year vesting period as compared to established threshold, target and stretch
levels. The payouts for the performance-related component of the awards can range from 0% for results below
threshold, up to 200% for actual results at stretch or above. The TUR adjustment is based on our total unitholder
return at the end of the three-year vesting period of the awards in relation to the total unitholder returns of certain
peer entities and can increase or decrease the payout of the award by as much as 50%. Payouts related to time-based
awards are based solely on the completion of the requisite service period by the employee and contain no provisions
that provide for a payout other than the original number of units awarded and the associated distribution equivalents.
Performance-based awards are subject to forfeiture if a participant’s employment is terminated for any reason
other than for termination within two years of a change-in-control that occurs on an involuntary basis without cause
or on a voluntary basis for good cause, or due to retirement, disability or death prior to the vesting date. These
awards can vest early under certain circumstances following a change in control. Time-based awards are subject to
forfeiture if a participant’s employment is terminated for any reason other than retirement, death or disability prior to
the vesting date, or as the result of certain other employment restrictions. If an employee award recipient retires,
dies or becomes disabled prior to the end of the vesting period, the award is prorated based upon months of
employment completed during the vesting period, and the award is settled shortly after the end of the vesting period.
Compensation expense for our equity awards is calculated as the number of unit awards less forfeitures,
multiplied by the grant date fair value of those awards, multiplied by the percentage of the requisite service period
completed at each period end, multiplied by the expected payout percentage, less previously-recognized
compensation expense.
Non-deferred director awards are paid in units valued on the grant date, with compensation expense calculated
as the number of units awarded multiplied by the fair value of those units at that date. We classify deferred director
awards as liability awards because they may be settled in cash. Because deferred director awards have distribution
95
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
equivalent rights, the fair value of these awards equals the closing price of our units at the measurement date.
Compensation expense for deferred director awards is calculated as the number of units awarded, multiplied by the
fair value of those awards on the measurement date, less previously-recognized compensation expense. Director
awards deferred prior to 2015 are paid in January of the year following the director’s resignation from the board of
directors of our general partner or death. Director awards deferred after January 1, 2015 are paid 60 days following
the director’s death or resignation from the board of directors of our general partner.
Non-Vested Unit Awards
The following table includes the changes during the current fiscal year in the number of non-vested units that
have been granted by the compensation committee. The amounts below do not include adjustments for above-target
or below-target performance.
Performance-Based
Awards
Time-Based Awards
Total Awards
Number of
Unit
Awards
Weighted-
Average
Fair Value
Number of
Unit
Awards
Weighted-
Average
Fair Value
Number of
Unit
Awards
Weighted-
Average
Fair Value
Non-vested units - 1/1/2020........
379,904 $
Units granted during 2020...........
189,632 $
Units vested during 2020............
(196,142) $
Units forfeited during 2020.........
(33,230) $
Non-vested units - 12/31/20........
340,164 $
69.14
61.16
73.79
65.70
62.35
260,316 $
198,450 $
(75,089) $
(30,133) $
353,544 $
63.92
61.18
70.50
62.90
61.07
640,220 $
388,082 $
(271,231) $
(63,363) $
693,708 $
67.02
61.17
72.88
64.37
61.70
The table below summarizes the total non-vested unit awards outstanding, including estimated targeted
financial performance adjustments, to determine our total equity-based liability accrual.
Grant Date
Performance-Based Awards:
2019 Awards............................
2020 Awards............................
Time-Based Awards:...................
2021 Vesting Date...................
2022 Vesting Date...................
Total...................................
Non-Vested
Unit Awards
Performance
Adjustment to
Unit Awards
Total Unit
Award
Accrual
Vesting
Date
Unrecognized
Compensation
Expense (in
millions)(a)
164,706
175,458
170,837
182,707
693,708
(82,353)
82,353
12/31/2021
$
—
—
—
(82,353)
175,458
12/31/2022
170,837
182,707
611,355
12/31/2021
12/31/2022
$
1.7
7.0
3.4
7.6
19.7
(a) Unrecognized compensation expense will be recognized over the remaining vesting period of the awards.
96
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
Weighted-Average Fair Value
The weighted-average fair value of awards granted during 2018, 2019 and 2020 was as follows:
Performance-Based Awards
Time-Based Awards
Number of
Unit
Awards
Weighted-
Average Fair
Value
Number of
Unit
Awards
Weighted-
Average Fair
Value
Units granted during 2018...................
218,923 $
Units granted during 2019...................
182,834 $
Units granted during 2020...................
189,632 $
73.80
63.65
61.16
83,564 $
195,031 $
198,450 $
71.03
62.91
61.18
Vested Unit Awards
The table below sets forth the numbers and values of units that vested in each of the three years ended
December 31, 2020. The vested common units include adjustments for above-target financial and market
performance.
Vesting Date
12/31/2018................
12/31/2019................
12/31/2020................
Vested
Common Units
317,037
436,629
235,127
Cash Flow Effects of LTIP Settlements
Fair Value of
Unit Awards on
Vesting Date
(in millions)
Intrinsic Value of
Unit Awards on
Vesting Date (in
millions)
$22.1
$31.0
$15.2
$18.1
$27.5
$10.0
The difference between the common units issued to the participants and the total number of unit awards vested
primarily represents the tax withholdings associated with the award settlement, which we pay in cash.
Employer
Taxes
Total Cash
Payments (in
millions)
(in millions)
$1.1
$0.9
$1.3
$10.4
$10.7
$16.0
Settlement Date
January 2018..............
January 2019..............
January 2020..............
Number of Common
Units Issued, Net of
Tax Withholdings
168,913
199,792
275,093
Tax
Withholdings
and Other
Cash
Payments
(in millions)
$9.3
$9.8
$14.7
97
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
Compensation Expense Summary
Equity-based incentive compensation expense for 2018, 2019 and 2020, primarily recorded as G&A expense
on our consolidated statements of income, was as follows (in thousands):
Year Ended December 31,
2018
2019
2020
Performance awards.......................................
$
28,728 $
17,920 $
Time-based awards.........................................
3,325
6,092
3,087
8,898
Total...................................................
$
32,053 $
24,012 $
11,985
During 2020, LTIP expense related to performance awards vesting in 2020 and 2021 decreased, reflecting the
impacts of COVID-19-related reductions in economic activity.
13. Derivative Financial Instruments
We use derivative instruments to manage market price risks associated with inventories, interest rates and
certain forecasted transactions. For those instruments that qualify for hedge accounting, the accounting treatment
depends on their intended use and their designation. We classify derivative financial instruments qualifying for
hedge accounting treatment into two categories: (1) cash flow hedges and (2) fair value hedges. We execute cash
flow hedges to hedge against the variability in cash flows related to a forecasted transaction and execute fair value
hedges to hedge against the changes in the value of a recognized asset or liability. At the inception of a hedged
transaction, we document the relationship between the hedging instrument and the hedged item, the risk
management objectives and the methods used for assessing and testing hedge effectiveness. We also assess, both at
the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging
transactions are highly effective in offsetting changes in cash flows or fair value of the hedged item. If we determine
that a derivative originally designated as a cash flow or fair value hedge is no longer highly effective, we discontinue
hedge accounting prospectively and record the change in the fair value of the derivative in current earnings. The
changes in fair value of derivative financial instruments that are not designated as hedges for accounting purposes,
which we refer to as economic hedges, are included in current earnings.
As part of our risk management process, we assess the creditworthiness of the financial and other institutions
with which we execute financial derivatives. Such financial instruments involve the risk of non-performance by the
counterparty, which could result in material losses to us.
Interest Rate Derivatives
We periodically enter into interest rate derivatives to hedge the fair value of debt or hedge against variability in
interest rates. For interest rate cash flow hedges, we record the unrealized gains or losses as an adjustment to other
comprehensive income. The realized gains and losses from our cash flow hedges are recognized into earnings as an
adjustment to our periodic interest expense over the life of the related debt issuance. For fair value hedges on long-
term debt, we record the unrealized gains or losses as an adjustment to long-term debt, and realized amounts as an
adjustment to our periodic interest expense. Adjustments resulting from discontinued hedges continue to be
recognized in accordance with their historic hedging relationships.
98
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
In December 2020, upon issuance of an additional $300.0 million of 3.95% notes due 2050, we terminated and
settled treasury lock agreements that we had previously entered into to protect against the variability of interest
payments on this anticipated debt issuance for a gain of $1.0 million, which was included in our statements of cash
flows as a net receipt on financial derivatives. These agreements were accounted for as cash flow hedges. The gain
was recorded to other comprehensive income (loss) and will be recognized into earnings as an adjustment to our
periodic interest expense over the term of the life of the associated notes.
In May 2020, upon issuance of $500.0 million of 3.25% notes due 2030, we terminated and settled treasury
lock agreements that we had previously entered into to protect against the variability of interest payments on this
anticipated debt issuance for a loss of $10.4 million, which was included in our statements of cash flows as a net
payment on financial derivatives. These agreements were accounted for as cash flow hedges. The loss was recorded
to other comprehensive income (loss) and will be recognized into earnings as an adjustment to our periodic interest
expense over the term of the life of the associated notes.
In August 2019, upon issuance of our $500.0 million of 3.95% notes due 2050, we terminated and settled
treasury lock agreements we had previously entered into to protect against the variability of interest payments on
this anticipated debt issuance for a loss of $25.3 million, which was included in our statements of cash flows as a net
payment on financial derivatives. These agreements were accounted for as cash flow hedges. The loss was recorded
to other comprehensive income (loss) and will be recognized into earnings as an adjustment to our periodic interest
expense over the life of the associated notes.
In 2019, upon issuance of $500.0 million of 4.85% notes due 2049, we terminated and settled treasury lock
agreements that we had previously entered into to protect against the variability of interest payments on this
anticipated debt issuance for a loss of $8.0 million, which was included in our statements of cash flows as a net
payment on financial derivatives. These agreements were accounted for as cash flow hedges. The loss was recorded
to other comprehensive income (loss) and will be recognized into earnings as an adjustment to our periodic interest
expense over the life of the associated notes.
During 2018, we terminated and settled $200.0 million of interest rate derivative agreements with cumulative
gains of $24.6 million. These agreements were previously entered into to protect against the risk of variability of
interest payments on debt we issued in 2019. These agreements were accounted for as cash flow hedges. The gains
were recorded to other comprehensive income (loss) and will be recognized into earnings as an adjustment to our
periodic interest expense over the life of the associated notes. These gains were also reported as a net receipt on
financial derivatives in the financing activities of our consolidated statements of cash flows in 2018.
Commodity Derivatives
Our gas liquids blending activities produce gasoline, and we can reasonably estimate the timing and quantities
of sales of these products. We use a combination of exchange-based commodities futures contracts and forward
purchase and sale contracts to help manage commodity price changes and mitigate the risk of decline in the product
margin realized from our gas liquids blending activities. Further, certain of our other commercial operations
generate petroleum products, and we also use futures contracts to hedge against price changes for some of these
commodities.
Forward physical purchase and sale contracts that qualify for and are elected as normal purchases and sales are
accounted for using traditional accrual accounting, whereby changes in the mark-to-market values of such contracts
are not recognized in income, rather the revenues and costs associated with such transactions are recognized during
the period when commodities are physically delivered or received. Physical forward commodity contracts subject to
this exception are evaluated for the probability of future delivery and are periodically tested once the forecasted
period has passed to determine whether similar forward contracts are probable of physical delivery in the future.
99
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
We record the effective portion of the gains or losses for commodity-based contracts designated as fair value
hedges as adjustments to the assets being hedged and the ineffective portions as well as amounts excluded from the
assessment of hedge effectiveness as adjustments to other income or expense. We recognize the change in fair value
of economic hedges that hedge against changes in the price of petroleum products that we expect to sell or purchase
in the future currently in earnings as adjustments to product sales revenue, cost of product sales, or operating
expenses, as applicable.
Our open futures contracts at December 31, 2020 were as follows:
Type of Contract/Accounting
Methodology
Futures - Economic Hedges....................
Product Represented by the Contract
and Associated Barrels
3.4 million barrels of refined products
and crude oil...........................................
Maturity Dates
Between January 2021 and November
2022
Futures - Economic Hedges....................
0.1 million barrels of gas liquids............
Between January and April 2021
Commodity Derivatives Contracts and Deposits Offsets
At December 31, 2019 and 2020, we had made margin deposits of $27.4 million and $34.2 million,
respectively, for our futures contracts with our counterparties, which were recorded as current assets under
commodity derivatives deposits on our consolidated balance sheets. We have the right to offset the combined fair
values of our open futures contracts against our margin deposits under a master netting arrangement for each
counterparty; however, we have elected to present the combined fair values of our open futures contracts separately
from the related margin deposits on our consolidated balance sheets. Additionally, we have the right to offset the fair
values of our futures contracts together for each counterparty, which we have elected to do, and we report the
combined net balances on our consolidated balance sheets. A schedule of the derivative amounts we have offset and
the deposit amounts we could offset under a master netting arrangement are provided below as of December 31,
2019 and 2020 (in thousands):
Gross
Amounts of
Recognized
Liabilities
Gross Amounts
of Assets Offset
in the
Consolidated
Balance Sheets
Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheets
Margin Deposit
Amounts Not
Offset in the
Consolidated
Balance Sheets
Net Asset
Amount(1)
As of December 31, 2019.............
As of December 31, 2020.............
$
$
(11,033) $
(22,988) $
811 $
1,690 $
(10,222) $
(21,298) $
27,415 $
34,165 $
17,193
12,867
(1) Amount represents the maximum loss we would incur if all of our counterparties failed to perform on their derivative contracts.
Basis Derivative Agreement
During 2019, we entered into a basis derivative agreement with a joint venture co-owner’s affiliate, and,
contemporaneously, that affiliate entered into an intrastate transportation services agreement with the joint venture.
Settlements under the basis derivative agreement are determined based on the basis differential of crude oil prices at
different market locations and a notional volume of 30,000 barrels per day. As a result, we account for this
agreement as a derivative. The agreement will expire in early 2022. We recognize the changes in fair value of this
agreement based on forward price curves for crude oil in West Texas and the Houston Gulf Coast in other operating
income (expense) in our consolidated statements of income. The liability for this agreement at December 31, 2019
and 2020, respectively, was $17.3 million and $10.2 million.
100
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
Impact of Derivatives on Our Financial Statements
Comprehensive Income
The changes in derivative activity included in AOCL for the years ended December 31, 2018, 2019 and 2020
were as follows (in thousands):
Derivative Gains (Losses) Included in AOCL
2018
2019
2020
Beginning balance.....................................................................
$
(33,755) $
(26,480) $
(48,960)
Net gain (loss) on interest rate contract cash flow hedges........
Reclassification of net loss on cash flow hedges to income.....
4,317
2,958
(25,216)
2,736
(9,484)
3,445
Ending balance..........................................................................
$
(26,480) $
(48,960) $
(54,999)
Year Ended December 31,
The following is a summary of the effect on our consolidated statements of income for the years ended
December 31, 2018, 2019 and 2020 of derivatives that were designated as cash flow hedges (in thousands):
Amount of Gain
(Loss) Recognized
in AOCL on
Derivatives
Interest Rate Contracts
Location of Loss
Reclassified from
AOCL into Income
Year Ended December 31, 2018.............
Year Ended December 31, 2019.............
Year Ended December 31, 2020.............
$
$
$
4,317
Interest expense................
(25,216)
Interest expense................
(9,484)
Interest expense................
Amount of Loss
Reclassified
from AOCL into
Income
$
$
$
(2,958)
(2,736)
(3,445)
As of December 31, 2020, the net loss estimated to be classified to interest expense over the next twelve
months from AOCL is approximately $3.3 million. This amount relates to the amortization of losses on interest rate
contracts over the life of the related debt instruments.
The following table provides a summary of the effect on our consolidated statements of income for the years
ended December 31, 2018, 2019 and 2020 of derivatives that were not designated as hedging instruments (in
thousands):
Amount of Gain (Loss)
Recognized on Derivative
Year Ended December 31,
Derivative Instrument
Location of Gain (Loss)
Recognized on Derivatives
2018
2019
2020
Futures contracts......................................
Product sales revenue...................
$
85,012 $
(72,562) $
58,693
Futures contracts...................................... Cost of product sales....................
Basis derivative agreement...................... Other operating income
(15,947)
(1,931)
2,183
(expense).................................
—
(10,252)
(4,253)
Total..........................................
$
69,065 $
(84,745) $
56,623
The impact of the derivatives in the above table was reflected as cash from operations on our consolidated
statements of cash flows.
101
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
Balance Sheets
The following tables provide a summary of the fair value of derivatives, which are presented on a net basis in
our consolidated balance sheets, that were not designated as hedging instruments as of December 31, 2019 and 2020
(in thousands):
Derivative Instrument
Futures contracts............................................
Basis derivative agreement
Basis derivative agreement
December 31, 2019
Asset Derivatives
Liability Derivatives
Balance Sheet Location
Fair Value
Balance Sheet Location
Fair Value
Commodity derivatives
contracts, net......................
$
Other current assets................
Other noncurrent assets..........
Commodity derivatives
contracts, net......................
Other current liabilities.......
Other noncurrent liabilities.
811
—
—
$ 11,033
8,457
8,847
Total....................................
$
811
Total....................................
$ 28,337
December 31, 2020
Asset Derivatives
Liability Derivatives
Derivative Instrument
Futures contracts............................................
Balance Sheet Location
Fair Value
Balance Sheet Location
Fair Value
Commodity derivatives
contracts, net......................
$
616
Commodity derivatives
contracts, net......................
$ 22,988
Futures contracts............................................ Other noncurrent assets..........
Basis derivative agreement............................. Other current assets................
Basis derivative agreement............................. Other noncurrent assets..........
1,074 Other noncurrent liabilities.....
— Other current liabilities...........
— Other noncurrent liabilities.....
—
8,774
1,468
Total....................................
$
1,690
Total....................................
$ 33,230
14. Fair Value Disclosures
Fair Value Methods and Assumptions - Financial Assets and Liabilities
The following methods and assumptions were used in estimating fair value for our financial assets and
liabilities:
•
•
•
Commodity derivatives contracts. These include exchange-traded futures contracts related to
petroleum products. These contracts are carried at fair value on our consolidated balance sheets
and are valued based on quoted prices in active markets. See Note 13 – Derivative Financial
Instruments for further disclosures regarding these contracts.
Basis Derivative Agreement. During 2019, we entered into a basis derivative agreement with a
joint venture co-owner’s affiliate, and, contemporaneously, that affiliate entered into an intrastate
transportation services agreement with the joint venture. Settlements under the basis derivative
agreement are determined based on the basis differential of crude oil prices at different market
locations and a notional volume of 30,000 barrels per day (see Note 13 - Derivative Financial
Instruments for further disclosures regarding this agreement). The fair value of this derivative was
calculated based on observable market data inputs, including published commodity pricing data
and market interest rates. The key inputs in the fair value calculation include the forward price
curves for crude oil, the implied forward correlation in crude oil prices between West Texas and
the Houston Gulf Coast, and the implied forward volatility for crude oil futures contracts.
Long-term receivables. These primarily include payments receivable under a sales-type leasing
arrangement and cost reimbursement payments receivable. These receivables were recorded at
102
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
•
•
fair value on our consolidated balance sheets, using then-current market rates to estimate the
present value of future cash flows.
Guarantees and contractual obligations. At December 31, 2020, these primarily included a long-
term contractual obligation we entered into in connection with the sale of our three marine
terminals to a subsidiary of Buckeye Partners, L.P. (“Buckeye”). This obligation requires us to
perform certain environmental remediation work on Buckeye’s behalf at the New Haven,
Connecticut terminal. The contractual obligation was recorded at fair value on our consolidated
balance sheets upon initial recognition and was calculated using our best estimate of potential
outcome scenarios to determine our liability for the remediation costs required in this agreement.
Debt. The fair value of our publicly traded notes was based on the prices of those notes at
December 31, 2019 and 2020; however, where recent observable market trades were not available,
prices were determined using adjustments to the last traded value for that debt issuance or by
adjustments to the prices of similar debt instruments of peer entities that are actively traded. The
carrying amount of borrowings, if any, under our revolving credit facility and our commercial
paper program approximates fair value due to the frequent repricing of these obligations.
Fair Value Measurements - Financial Assets and Liabilities
The following tables summarize the carrying amounts, fair values and fair value measurements recorded or
disclosed as of December 31, 2019 and 2020, based on the three levels established by ASC 820; Fair Value
Measurements and Disclosures (in thousands):
Assets (Liabilities)
Carrying Amount
Fair Value
Fair Value Measurements as of
December 31, 2019 using:
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
Significant Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Commodity derivatives
contracts........................
Basis derivative
agreement.....................
Long-term receivables.......
Guarantees and
contractual obligations..
Debt...................................
$
$
$
$
$
(10,222) $
(10,222) $
(10,222) $
— $
(17,304) $
(17,304) $
20,782 $
20,782 $
(408) $
(408) $
(4,706,075) $
(5,192,685) $
— $
— $
— $
— $
(17,304) $
— $
— $
(5,192,685) $
—
—
20,782
(408)
—
Assets (Liabilities)
Carrying Amount
Fair Value
Fair Value Measurements as of
December 31, 2020 using:
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
Significant Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
(21,298) $
(21,298) $
(21,298) $
— $
Commodity derivatives
contracts........................
$
Basis derivative
agreement.....................
Long-term receivables.......
Guarantees and
contractual obligations..
Debt...................................
$
$
$
$
(10,242) $
(10,242) $
22,755 $
22,755 $
(11,207) $
(11,207) $
(4,978,691) $
(5,880,850) $
— $
— $
— $
— $
103
—
—
(10,242) $
— $
22,755
— $
(11,207)
(5,880,850) $
—
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
15. Commitments and Contingencies
Certain conditions may exist as of the date our consolidated financial statements are issued that could result in
a loss to us, but which will only be resolved when one or more future events occur or fail to occur. Our management
assesses such contingent liabilities, which inherently involves significant judgment. In assessing loss contingencies
related to legal proceedings that are pending against us or for unasserted claims that may result in proceedings, our
management, with input from legal counsel, evaluates the perceived merits of any legal proceedings or unasserted
claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.
Environmental expenditures are charged to operating expense or capitalized based on the nature of the
expenditures. Environmental expenditures that meet the capitalization criteria for property, plant and equipment, as
well as costs that mitigate or prevent environmental contamination that has yet to occur, are capitalized. We
expense expenditures that relate to an existing condition caused by past operations. We initially record
environmental liabilities assumed in a business combination at fair value; otherwise, we record environmental
liabilities on an undiscounted basis. We recognize liabilities for other commitments and contingencies when, after
analyzing the available information, we determine it is probable that an asset has been impaired, or that a liability
has been incurred and the amount of impairment or loss can be reasonably estimated. When we can estimate a range
of probable loss, we accrue the most likely amount within that range, or if no amount is more likely than another, we
accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as
incurred.
We record environmental liabilities independently of any potential claim for recovery. Accruals related to
environmental matters are generally determined based on site-specific plans for remediation, taking into account
currently available facts, existing technologies and presently enacted laws and regulations. Accruals for
environmental matters reflect our prior remediation experience and include an estimate for costs such as fees paid to
contractors, outside engineering and consulting firms. Accruals for estimated losses from environmental
remediation obligations generally are recognized no later than completion of the remediation feasibility study. Such
accruals are adjusted as further information develops or circumstances change.
We maintain specific insurance coverage, which may cover all or portions of certain environmental
expenditures less a deductible. We recognize receivables in cases where we consider the realization of
reimbursements of remediation costs as probable. We would sustain losses to the extent of amounts we have
recognized as environmental receivables if the counterparties to those transactions were unable to perform their
obligations to us.
The determination of the accrual amounts recorded for environmental liabilities includes significant judgments
and assumptions made by management. The use of alternate judgments and assumptions could result in the
recognition of different levels of environmental remediation costs.
Butane Blending Patent Infringement Proceeding
On October 4, 2017, Sunoco Partners Marketing & Terminals L.P. (“Sunoco”) brought an action for patent
infringement in the U.S. District Court for the District of Delaware alleging Magellan Midstream Partners, L.P.
(“Magellan”) and Powder Springs Logistics, LLC (“Powder Springs”) have infringed patents relating to butane
blending at the Powder Springs facility located in Powder Springs, Georgia. Sunoco 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 ultimate outcome, we
104
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
believe the ultimate resolution of this matter will not have a material adverse impact on our results of operations,
financial position or cash flows.
Environmental Liabilities
Liabilities recognized for estimated environmental costs were $14.9 million and $14.3 million at December 31,
2019 and December 31, 2020, respectively. We have classified environmental liabilities as other current or
noncurrent based on management’s estimates regarding the timing of actual payments. Environmental expenses
recognized as a result of changes in our environmental liabilities are included in operating expenses on our
consolidated statements of income. Environmental expenses were $15.0 million, $4.4 million and $3.8 million for
the years ended December 31, 2018, 2019 and 2020, respectively.
Other
In 2020, we entered into a long-term contractual obligation in connection with the sale of three marine
terminals to Buckeye. This obligation requires us to perform certain environmental remediation work on Buckeye’s
behalf at the New Haven terminal. As of December 31, 2020, our consolidated balance sheets reflected a current
liability of $0.6 million and a noncurrent liability of $10.2 million to reflect the fair value of this obligation.
We have entered into an agreement to guarantee our 50% pro rata share, up to $25.0 million, of obligations
under Powder Springs’ credit facility. As of December 31, 2020, our consolidated balance sheets reflected a $0.4
million other current liability and a corresponding increase in our investment in non-controlled entities on our
consolidated balance sheets to reflect the fair value of this guarantee.
We and the non-controlled entities in which we own an interest are a party to various other claims, legal
actions and complaints. While the results cannot be predicted with certainty, management believes the ultimate
resolution of these claims, legal actions and complaints after consideration of amounts accrued, insurance coverage
or other indemnification arrangements will not have a material adverse effect on our results of operations, financial
position or cash flows.
16. Concentration of Risks
We transport, store and distribute petroleum products for refiners, producers, marketers, traders and end users
of those products. Our revenue producing activities are concentrated in the central U.S. Concentrations of customers
may affect our overall credit risk as our customers may be similarly affected by changes in economic, regulatory or
other factors. We generally secure transportation and storage revenue with warehouseman’s liens. We periodically
evaluate the financial condition and creditworthiness of our customers and require additional security as we deem
necessary.
As of December 31, 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.
105
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
17. Related Party Transactions
Stacy Methvin is an independent member of our general partner’s board of directors and is also a director of
one of our customers. We received tariff, terminalling and other ancillary revenue from this customer of $21.7
million, $29.6 million and $37.4 million for the periods ending December 31, 2018, 2019 and 2020, respectively.
We recorded a receivable of $3.8 million and $3.9 million from this customer at December 31, 2019 and 2020,
respectively. We also made a one-time payment of $0.2 million in 2019 to a subsidiary of this customer for an
easement related to one of our expansion projects. Additionally, we received storage and other miscellaneous
revenue of $0.5 million for the period ending December 31, 2020 from a subsidiary of a separate company for which
Stacy Methvin serves as a director.
See Note 6 – Investments in Non-Controlled Entities for a discussion of transactions with our joint venture
affiliates.
18. Partners’ Capital and Distributions
Partners’ Capital
Our general partner’s board of directors authorized the repurchase of up to $750 million of our common units
through 2022. The timing, price and actual number of common units repurchased will depend on a number of
factors including our expected expansion capital spending needs, excess cash available, balance sheet metrics, legal
and regulatory requirements, market conditions and the trading price of our common units. The repurchase program
does not obligate us to acquire any particular amount of common units, and the repurchase program may be
suspended or discontinued at any time.
The following table details the changes in the number of our common units outstanding from January 1, 2018
through December 31, 2020:
Common units outstanding on January 1, 2018..........................................................................................
228,024,556
January 2018—Settlement of employee LTIP awards.............................................................................
During 2018—Other(a)..............................................................................................................................
Common units outstanding on December 31, 2018.....................................................................................
168,913
1,691
228,195,160
February 2019—Settlement of employee LTIP awards...........................................................................
During 2019—Other(a)..............................................................................................................................
Common units outstanding on December 31, 2019.....................................................................................
199,792
8,476
228,403,428
Units repurchased during 2020.................................................................................................................
(5,568,260)
February 2020—Settlement of employee LTIP awards...........................................................................
During 2020—Other(a)..............................................................................................................................
Common units outstanding on December 31, 2020.....................................................................................
275,093
9,550
223,119,811
(a) Common units issued to settle the equity-based retainer paid to independent directors of our general partner.
Our partnership agreement allows us to issue additional partnership securities for any partnership purpose at
any time and from time to time for consideration and on terms and conditions as our general partner determines, all
without approval by our unitholders.
Common unitholders have the following rights, among others:
•
right to receive distributions of our available cash within 45 days after the end of each quarter;
106
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
•
•
•
•
•
•
•
right to elect the board members of our general partner;
right to remove Magellan GP, LLC as our general partner upon a 100% vote of outstanding unitholders;
right to transfer common unit ownership to substitute common unitholders;
right to receive an annual report, containing audited financial statements and a report on those financial
statements by our independent public accountants, within 120 days after the close of the fiscal year end;
right to receive information reasonably required for tax reporting purposes within 90 days after the close
of the calendar year;
right to vote according to the unitholder’s percentage interest in us at any meeting that may be called by
our general partner; and
right to inspect our books and records at the unitholder’s own expense.
In the event of liquidation, we would distribute all property and cash in excess of that required to discharge all
liabilities to the unitholders in proportion to the positive balances in their respective capital accounts. The common
unitholders’ liability is generally limited to their investment.
Distributions
Distributions we paid during 2018, 2019 and 2020 were as follows (in thousands, except per unit amount):
Payment Date
2/14/2018
5/15/2018
8/14/2018
11/14/2018
Total
2/14/2019
5/15/2019
8/14/2019
11/14/2019
Total
2/14/2020
5/15/2020
8/14/2020
11/13/2020
Total
Per Unit Distribution
Amount
Total Distribution
$
$
$
$
$
$
0.9200 $
0.9375
0.9575
0.9775
3.7925 $
0.9975 $
1.0050
1.0125
1.0200
4.0350 $
1.0275 $
1.0275
1.0275
1.0275
4.1100 $
209,940
213,933
218,497
223,061
865,431
227,832
229,545
231,258
232,971
921,606
234,774
231,245
231,245
229,853
927,117
19. Subsequent Events
Recognizable events
No recognizable events have occurred subsequent to December 31, 2020.
107
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued
Non-recognizable events
On February 12, 2021, we paid distributions of $1.0275 per unit on our outstanding common units to
unitholders of record at the close of business on February 5, 2021.
108
Quarterly Financial Data (unaudited)
Summarized quarterly financial data is as follows (in thousands, except per unit amounts):
2019
Revenue.....................................................
Total costs and expenses...........................
Operating margin.......................................
Net income................................................
Basic net income per common unit...........
Diluted net income per common unit........
2020
Revenue.....................................................
Total costs and expenses...........................
Operating margin.......................................
Net income................................................
Basic net income per common unit...........
Diluted net income per common unit........
$
$
$
$
$
$
$
$
$
$
$
$
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
628,935 $
701,699 $
656,596 $
740,682
422,985 $
436,718 $
385,927 $
450,514
352,012 $
415,655 $
428,262 $
450,559
207,663 $
253,703 $
273,038 $
286,445
0.91 $
0.91 $
1.11 $
1.11 $
1.19 $
1.19 $
1.25
1.25
782,806 $
460,408 $
598,264 $
586,324
499,186 $
297,324 $
367,939 $
382,779
427,211 $
301,394 $
376,435 $
361,116
287,564 $
133,843 $
211,638 $
183,920
1.26 $
1.26 $
0.59 $
0.59 $
0.94 $
0.94 $
0.82
0.82
109
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We performed an evaluation of the effectiveness of the design and operation of our “disclosure controls and
procedures” (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended
(the “Exchange Act”)) as of the end of the period covered by this report. We performed this evaluation under the
supervision and with the participation of our management, including our general partner’s Chief Executive Officer
(“CEO”) and Chief Financial Officer (“CFO”). Based upon that evaluation, our general partner’s CEO and CFO
concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were
effective to provide reasonable assurance that information required to be disclosed in the reports that we file or
submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in
the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include
controls and procedures designed so that information required to be disclosed in reports filed or submitted under the
Exchange Act is accumulated and communicated to management, including the CEO and the CFO, as appropriate,
to allow timely decisions regarding required disclosure. There has been no change in our internal control over
financial reporting that occurred during the quarter ended December 31, 2020 that has materially affected, or is
reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
See “Management’s Annual Report on Internal Control Over Financial Reporting” set forth in Item 8.
Financial Statements and Supplementary Data.
Item 9B.
Other Information
None.
110
Item 10.
Directors, Executive Officers and Corporate Governance
PART III
The information regarding the directors and executive officers of our general partner and our governance
required by Items 401, 405, 406 and 407(c)(3), (d)(4) and (d)(5) of Regulation S-K will be presented in our
definitive proxy statement to be filed pursuant to Regulation 14A (our “Proxy Statement”) under the following
captions, which information is to be incorporated by reference herein:
•
•
•
•
•
•
Director Election Proposal;
Executive Officers of our General Partner;
Section 16(a) Beneficial Ownership Reporting Compliance;
Code of Ethics;
Governance – Director Nominations; and
Governance – Board Committees.
Item 11.
Executive Compensation
The information regarding executive compensation required by Items 402 and 407(e)(4) and (e)(5) of
Regulation S-K will be presented in our Proxy Statement under the following captions, which information is to be
incorporated by reference herein:
•
•
•
Compensation of Directors and Executive Officers;
Governance – Compensation Committee – Interlocks and Insider Participation; and
Compensation of Directors and Executive Officers – Compensation Committee Report.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
The information regarding securities authorized for issuance under equity compensation plans and security
ownership required by Items 201(d) and 403 of Regulation S-K will be presented in our Proxy Statement under the
following captions, which information is to be incorporated by reference herein:
•
•
Securities Authorized for Issuance Under Equity Compensation Plans; and
Security Ownership of Certain Beneficial Owners and Management.
Item 13.
Certain Relationships and Related Transactions, and Director Independence
The information regarding certain relationships and related transactions and director independence required by
Items 404 and 407(a) of Regulation S-K will be presented in our Proxy Statement under the following captions,
which information is to be incorporated by reference herein:
•
•
Transactions with Related Persons, Promoters and Certain Control Persons; and
Governance – Director Independence.
Item 14.
Principal Accountant Fees and Services
The information regarding principal accountant fees and services required by Item 9(e) of Schedule 14A of the
Exchange Act will be presented in our Proxy Statement under the caption “Independent Auditor Proposal,” which
information is to be incorporated by reference herein.
111
PART IV
Item 15.
Exhibits and Financial Statement Schedules
(a)1 and (a)2.
Covered by reports of independent auditors:
Consolidated statements of income for the three years ended December 31, 2020.......................
Consolidated statements of comprehensive income for the three years ended December 31,
2020............................................................................................................................................
Consolidated balance sheets at December 31, 2019 and 2020.......................................................
Consolidated statements of cash flows for the three years ended December 31, 2020..................
Consolidated statement of partners’ capital for the three years ended December 31, 2020..........
Notes 1 through 19 to consolidated financial statements...............................................................
Page
61
62
63
64
65
66
Not covered by reports of independent auditors:
Quarterly financial data (unaudited)...............................................................................................
109
We have omitted all other required schedules since the required information is not present or is not present in
amounts sufficient to require submission of the schedule, or because the information required is included in the
financial statements and notes thereto.
(a)3, (b) and (c). The exhibits listed below on the Index to Exhibits are filed or incorporated by reference as
part of this annual report.
112
Index to Exhibits
Description
Certificate of Limited Partnership of Magellan Midstream Partners, L.P. dated August 30, 2000, as amended on November 15,
2002 and August 12, 2003 (filed as Exhibit 3.1 to Form 10-Q filed November 10, 2003).
Fifth Amended and Restated Agreement of Limited Partnership of Magellan Midstream Partners, L.P. dated September 28,
2009 (filed as Exhibit 3.1 to Form 8-K filed September 30, 2009).
Amendment No. 1 dated October 27, 2011 to Fifth Amended and Restated Agreement of Limited Partnership of Magellan
Midstream Partners, L.P. dated September 28, 2009 (filed as Exhibit 3.1 to Form 8-K filed October 28, 2011).
Amendment No. 2 dated January 16, 2017 to Fifth Amended and Restated Agreement of Limited Partnership of Magellan
Midstream Partners, L.P. dated September 28, 2009 (filed as Exhibit 3.2 to Form 8-K filed January 17, 2017).
Amendment No. 3 dated October 25, 2018 to Fifth Amended and Restated Agreement of Limited Partnership of Magellan
Midstream Partners, L.P. dated September 28, 2009 (filed as Exhibit 3.1 to Form 8-K filed October 26, 2018).
Amendment No. 4 dated September 25, 2020 to Fifth Amended and Restated Agreement of Limited Partnership of Magellan
Midstream Partners, L.P. dated September 28, 2009 (filed as Exhibit 3.1 to Form 8-K filed September 25, 2020).
Amended and Restated Certificate of Formation of Magellan GP, LLC dated November 15, 2002, as amended on August 12,
2003 (filed as Exhibit 3(f) to Form 10-K filed March 10, 2004).
Third Amended and Restated Limited Liability Company Agreement of Magellan GP, LLC dated September 28, 2009 (filed as
Exhibit 3.2 to Form 8-K filed September 30, 2009).
Amendment No. 1 dated January 16, 2017 to Third Amended and Restated Limited Liability Company Agreement of Magellan
GP, LLC dated September 28, 2009 (filed as Exhibit 3.1 to Form 8-K filed January 17, 2017).
Exhibit No.
Exhibit 3
*(a)
*(b)
*(c)
*(d)
*(e)
*(f)
*(g)
*(h)
*(i)
Exhibit 4
*(a)
*(b)
*(c)
*(d)
*(e)
*(f)
*(g)
*(h)
*(i)
*(j)
*(k)
*(l)
Indenture dated as of April 19, 2007 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as
trustee (filed as Exhibit 4.1 to Form 8-K filed April 20, 2007).
First Supplemental Indenture dated as of April 19, 2007 between Magellan Midstream Partners, L.P. and U.S. Bank National
Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed April 20, 2007).
Indenture dated as of August 11, 2010 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as
trustee (filed as Exhibit 4.1 to Form 8-K filed August 16, 2010).
Second Supplemental Indenture dated as of November 9, 2012 between Magellan Midstream Partners, L.P. and U.S. Bank
National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed November 9, 2012).
Third Supplemental Indenture dated as of October 10, 2013 between Magellan Midstream Partners, L.P. and U.S. Bank
National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed October 10, 2013).
Fourth Supplemental Indenture dated as of March 4, 2015 between Magellan Midstream Partners, L.P. and U.S. Bank National
Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed March 4, 2015).
Fifth Supplemental Indenture dated as of March 4, 2015 between Magellan Midstream Partners, L.P. and U.S. Bank National
Association, as trustee (filed as Exhibit 4.3 to Form 8-K filed March 4, 2015).
Sixth Supplemental Indenture dated as of February 29, 2016 between Magellan Midstream Partners, L.P. and U.S. Bank
National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed February 29, 2016).
Seventh Supplemental Indenture dated as of September 13, 2016 between Magellan Midstream Partners, L.P. and U.S. Bank
National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed September 13, 2016).
Eighth Supplemental Indenture dated as of October 3, 2017 between Magellan Midstream Partners, L.P. and U.S. Bank
National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed October 3, 2017).
Ninth Supplemental Indenture dated as of January 18, 2019 between Magellan Midstream Partners, L.P. and U.S. Bank
National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed January 18, 2019).
Tenth Supplemental Indenture dated as of August 19, 2019 between Magellan Midstream Partners, L.P. and U.S. Bank
National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed August 19, 2019).
*(m)
Eleventh Supplemental Indenture dated as of May 20, 2020 between Magellan Midstream Partners, L.P. and U.S. Bank
National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed May 20, 2020).
*(n)
Description of Securities (filed as Exhibit 4(o) to Form 10-K filed February 18, 2020).
113
Exhibit No.
Exhibit 10
Description
(a)
(b)
(c)
*(d)
*(e)
*(f)
*(g)
(h)
(i)
*(j)
*(k)
Amended and Restated Magellan Midstream Partners Long-Term Incentive Plan dated January 26, 2021.
Description of Magellan 2021 Annual Incentive Program.
Magellan GP, LLC Non-Management Director Compensation Program effective January 1, 2021.
Amended and Restated Director Deferred Compensation Plan effective January 28, 2014 (filed as Exhibit 10(d) to Form 10-K
filed February 24, 2014).
$1,000,000,000 Second Amended and Restated Credit Agreement dated as of October 26, 2017 among Magellan Midstream
Partners, L.P., the Lenders party thereto, Wells Fargo Bank, National Association, as Administrative Agent and an Issuing
Bank, JPMorgan Chase Bank, N.A., as Co-Syndication Agent and an Issuing Bank, and SunTrust Bank, as Co-Syndication
Agent and an Issuing Bank (filed as Exhibit 10.1 to Form 8-K filed October 27, 2017).
First Amendment to Second Amended and Restated Credit Agreement dated as of May 17, 2019 among Magellan Midstream
Partners, L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto
(filed as Exhibit 10.2 to Form 8-K filed May 22, 2019).
Executive Severance Pay Plan dated July 21, 2011 (filed as Exhibit 10.2 to Form 10-Q filed August 4, 2011).
Form of 2021 Performance Based Phantom Unit Agreement for awards granted pursuant to the Magellan Midstream Partners
Long-Term Incentive Plan.
Form of 2021 Retention Phantom Unit Agreement for awards granted pursuant to the Magellan Midstream Partners Long-Term
Incentive Plan.
Form of Commercial Paper Dealer Agreement between Magellan Midstream Partners, L.P., as Issuer, and the Dealer party
thereto (filed as Exhibit 10.1 to Form 8-K filed April 22, 2014).
Form of Indemnification Agreement by and among Magellan Midstream Partners, L.P., Magellan GP, LLC and the directors
and officers of Magellan GP, LLC (filed as Exhibit 10.1 to Form 10-Q filed November 3, 2015).
Exhibit 14
*(a)
*(b)
Code of Ethics dated February 1, 2011 by Michael N. Mears, principal executive officer (filed as Exhibit 14(a) to Form 10-K
filed February 25, 2011).
Code of Ethics dated May 1, 2019 by Jeff L. Holman, principal financial and accounting officer (filed as Exhibit 14(b) to Form
10-K filed February 18, 2020).
Exhibit 21
Subsidiaries of Magellan Midstream Partners, L.P.
Exhibit 23
Consent of Independent Registered Public Accounting Firm.
Exhibit 31
(a)
(b)
Exhibit 32
Certification of Michael N. Mears, principal executive officer.
Certification of Jeff Holman, principal financial officer.
(a)
(b)
Exhibit
101.INS
Exhibit
101.SCH
Exhibit
101.CAL
Exhibit
101.DEF
Exhibit
101.LAB
Exhibit
101.PRE
*
Section 1350 Certification of Michael N. Mears, Chief Executive Officer.
Section 1350 Certification of Jeff Holman, Chief Financial Officer.
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Each such exhibit has heretofore been filed with the Securities and Exchange Commission as part of the filing indicated and is
incorporated herein by reference.
114
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
MAGELLAN MIDSTREAM PARTNERS, L.P.
(Registrant)
By:
By:
MAGELLAN GP, LLC, its general partner
/s/ JEFF HOLMAN
Jeff Holman
Senior Vice President, Chief Financial Officer and Treasurer
Date: February 18, 2021
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the registrant and in the capacity and on the dates indicated.
115
Signature
Title
Date
/s/ MICHAEL N. MEARS
Michael N. Mears
/s/ JEFF HOLMAN
Jeff Holman
Chairman of the Board and Principal Executive
Officer of Magellan GP, LLC, General Partner of
Magellan Midstream Partners, L.P.
February 18, 2021
Principal Financial and Accounting Officer of
Magellan GP, LLC, General Partner of Magellan
Midstream Partners, L.P.
February 18, 2021
/s/ WALTER R. ARNHEIM
Director of Magellan GP, LLC, General Partner of
Magellan Midstream Partners, L.P.
February 18, 2021
Walter R. Arnheim
/s/ ROBERT G. CROYLE
Robert G. Croyle
/s/ LORI A. GOBILLOT
Lori A. Gobillot
/s/ EDWARD J. GUAY
Edward J. Guay
/s/ CHANSOO JOUNG
Chansoo Joung
/s/ STACY P. METHVIN
Stacy P. Methvin
/s/ JAMES R. MONTAGUE
James R. Montague
/s/ BARRY R. PEARL
Barry R. Pearl
Director of Magellan GP, LLC, General Partner of
Magellan Midstream Partners, L.P.
February 18, 2021
Director of Magellan GP, LLC, General Partner of
Magellan Midstream Partners, L.P.
February 18, 2021
Director of Magellan GP, LLC, General Partner of
Magellan Midstream Partners, L.P.
February 18, 2021
Director of Magellan GP, LLC, General Partner of
Magellan Midstream Partners, L.P.
February 18, 2021
Director of Magellan GP, LLC, General Partner of
Magellan Midstream Partners, L.P.
February 18, 2021
Director of Magellan GP, LLC, General Partner of
Magellan Midstream Partners, L.P.
February 18, 2021
Director of Magellan GP, LLC, General Partner of
Magellan Midstream Partners, L.P.
February 18, 2021
116
E XECUTIVE OFFICER S
BOARD OF DIREC TOR S
HE ADQUARTER S
Michael J. Aaronson
Senior Vice President,
Business Development
Robert L. Barnes
Senior Vice President,
Commercial, Crude Oil
Jeff L. Holman
Senior Vice President,
Chief Financial Officer and Treasurer
Lisa J. Korner
Senior Vice President, Human
Resources and Administration
Walter R. Arnheim
Chairman, Audit Committee
Robert G. Croyle
Chairman, Nominating and
Governance Committee
Lori A. Gobillot
Edward J. Guay
Chansoo Joung
Michael N. Mears
Chairman, Board of Directors
Melanie A. Little
Senior Vice President, Operations
Stacy P. Methvin
Douglas J. May
Senior Vice President,
General Counsel, Compliance
and Ethics Officer
Michael N. Mears
President and Chief Executive Officer
Aaron L. Milford
Chief Operating Officer
Michael C. Pearson
Senior Vice President,
Technical Services
James R. Montague
Chairman, Compensation
Committee
Barry R. Pearl
Lead Director
INVES TOR REL ATIONS
Paula Farrell
Associate Vice President,
Investor Relations
(918) 574-7650 • (877) 934-6571
paula.farrell@magellanlp.com
Magellan Midstream Partners, L.P.
P.O. Box 22186
Tulsa, OK 74121-2186
One Williams Center
Tulsa, OK 74172
(918) 574-7000 • (800) 574-6671
TR ANSFER AGENT
Computershare
(800) 884-4225
web.queries@computershare.com
K-1 TA X SUPPORT
(800) 230-1032
www.taxpackagesupport.com/mmp
SECURITIES
Magellan Midstream Partners, L.P.
common units are listed on
the New York Stock Exchange
under the ticker symbol MMP.
WEBSITE
www.magellanlp.com
www.magellanlp.com • NYSE: MMP