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
12/31
OR

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

For the transition period from ___  to  ___.

Commission file number:  1-14323

ENTERPRISE PRODUCTS PARTNERS L.P.
(Exact name of Registrant as Specified in Its Charter)

Delaware
 
76-0568219
(State or Other Jurisdiction of Incorporation or Organization)
 
(I.R.S. Employer Identification No.)
 
1100 Louisiana Street, 10th Floor, Houston, Texas 77002
    (Address of Principal Executive Offices, including Zip Code)
(713) 381-6500
(Registrant’s Telephone Number, including Area Code)

Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:

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

Securities to be 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

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

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).   Yes    No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company.  See 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     Non-accelerated filer       Smaller reporting company      Emerging growth company  

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

Indicate by check mark whether the registrant 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 Exchange Act).   Yes     No

The aggregate market value of our common units held by non-affiliates at June 30, 2020 (the last business day of the registrant’s most recently completed second fiscal quarter) was $26.96 billion based on a closing price on that date of $18.17 per common unit on the New York Stock Exchange Composite ticker tape.  There were 2,181,599,142 common units outstanding at January 31, 2021.





ENTERPRISE PRODUCTS PARTNERS L.P.
TABLE OF CONTENTS

   
Page
   
Number
3
     
     
     
     
 







CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This annual report on Form 10-K for the year ended December 31, 2020 (our “annual report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us.  When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “scheduled,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements.  Although we and our general partner believe that our expectations reflected in such forward-looking statements (including any forward-looking statements/expectations of third parties referenced in this annual report) are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct.  

Forward-looking statements are subject to a variety of risks, uncertainties and assumptions as described in more detail under Part I, Item 1A of this annual report.  If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected.  You should not put undue reliance on any forward-looking statements.  The forward-looking statements in this annual report speak only as of the date hereof.  Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.














KEY REFERENCES USED IN THIS REPORT

Unless the context requires otherwise, references to “we,” “us” or “our” within this annual report are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.  

References to the “Partnership” mean Enterprise Products Partners L.P. on a standalone basis.

References to “EPO” mean Enterprise Products Operating LLC, which is an indirect wholly owned subsidiary of the Partnership, and its consolidated subsidiaries, through which the Partnership conducts its business.  We are managed by our general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company.

The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Directors (the “Board”) of Enterprise GP;  (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board of Enterprise GP; and (iii) W. Randall Fowler, who is also a director and the Co-Chief Executive Officer and Chief Financial Officer of Enterprise GP.  Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as managers of Dan Duncan LLC.

References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates.  The outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are:  (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO; and (iii) Mr. Fowler, who serves as an Executive Vice President and the Chief Financial Officer of EPCO.  Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as directors of EPCO.

We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees.  EPCO, together with its privately held affiliates, owned approximately 32.2% of the Partnership’s common units outstanding and 30.2% of its Series A Cumulative Convertible Preferred Units (“preferred units”) outstanding at December 31, 2020.

As generally used in the energy industry and in this annual report, the acronyms below have the following meanings:

/d
=
per day
MMBbls
=
million barrels
BBtus
=
billion British thermal units
MMBPD
=
million barrels per day
Bcf
=
billion cubic feet
MMBtus
=
million British thermal units
BPD
=
barrels per day
MMcf
=
million cubic feet
MBPD
=
thousand barrels per day
TBtus
=
trillion British thermal units















PART I

ITEMS 1 AND 2.  BUSINESS AND PROPERTIES

General

We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.”  Our preferred units are not publicly traded.  We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products.  We are owned by our limited partners (preferred and common unitholders) from an economic perspective. Enterprise GP, which owns a non-economic general partner interest in us, manages our Partnership.  We conduct substantially all of our business operations through EPO and its consolidated subsidiaries.

Our fully integrated, midstream energy asset network (or “value chain”) links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States (“U.S.”), Canada and the Gulf of Mexico with domestic consumers and international markets.  Our midstream energy operations include:

natural gas gathering, treating, processing, transportation and storage;

NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases, or “LPG,” and ethane);

crude oil gathering, transportation, storage, and marine terminals;

propylene production facilities (including propane dehydrogenation (“PDH”) facilities), butane isomerization, octane enhancement, isobutane dehydrogenation (“iBDH”) and high purity isobutylene (“HPIB”) production facilities;

petrochemical and refined products transportation, storage, and marine terminals (including those used to export ethylene and polymer grade propylene (“PGP”); and

a marine transportation business that operates on key U.S. inland and intracoastal waterway systems. 

Our business strategy seeks to leverage these operations to:

capitalize on expected trends and opportunities in energy evolution and demand growth, including exports, for natural gas, NGLs, crude oil and petrochemical and refined products;

maintain a diversified portfolio of midstream energy assets and expand this asset base through growth capital projects and accretive acquisitions of complementary midstream energy assets;

enhance the stability of our cash flows by investing in pipelines and other fee-based businesses; and

share capital costs and risks through business ventures or alliances with strategic partners, including those that provide processing, throughput or feedstock volumes for growth capital projects or the purchase of such projects’ end products.

Our financial position, results of operations and cash flows are contingent on the supply of, and demand for the energy commodities we handle across our integrated midstream energy asset network.  See “Current Outlook” included under Part II, Item 7 of this annual report for management’s views on key midstream energy supply and demand fundamentals in 2021.




Business Segments

The following sections provide an overview of our business segments, including information regarding principal products produced and/or services rendered and properties owned.  Our operations are reported under four business segments:  NGL Pipelines & Services, Crude Oil Pipelines & Services, Natural Gas Pipelines & Services and  Petrochemical & Refined Products Services.

Each of our business segments benefits from the supporting role of our marketing activities.  The main purpose of our marketing activities is to support the utilization and expansion of assets across our midstream energy asset network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment.  In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of gross operating margin for us.  The financial results of our marketing efforts fluctuate due to changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for the products bought and sold.

Our financial position, results of operations and cash flows are subject to certain risks. For information regarding such risks, see “Risk Factors” included under Part I, Item 1A of this annual report.  In addition, our business activities are subject to various federal, state and local laws and regulations governing a wide variety of topics, including commercial, operational, environmental, safety and other matters.  For a discussion of the principal effects of such laws and regulations on our business activities, see “Regulatory Matters” within this Part I, Items 1 and 2 discussion.

For management’s discussion and analysis of our results of operations, liquidity and capital resources and capital investment program, see Part II, Item 7 of this annual report.

For detailed financial information regarding our business segments, including major customer information, see Note 10 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

NGL Pipelines & Services

This business segment includes our natural gas processing and related NGL marketing activities, NGL pipelines, NGL fractionation facilities, NGL and related product storage facilities, and NGL marine terminals.

Natural gas processing and related NGL marketing activities
At the core of our natural gas processing business are 21 processing facilities located in Colorado, Louisiana, Mississippi, New Mexico, Texas and Wyoming.

In its raw form, natural gas produced at the wellhead (especially in association with crude oil production) contains varying amounts of NGLs such as ethane and propane.  Natural gas streams containing NGLs and other impurities are usually not acceptable for transportation in downstream natural gas transmission pipelines or for commercial use as fuel; therefore, the unprocessed natural gas stream must be transported to a natural gas processing facility to remove the NGLs and other impurities. Once the natural gas is processed and the NGLs and impurities are removed, the residue natural gas meets downstream natural gas pipeline and commercial quality specifications.

In general, on an energy-equivalent basis, NGLs have greater economic value as feedstock for petrochemical and motor gasoline production than as components of a natural gas stream. Typical uses of NGLs include the following:

Ethane is primarily used in the petrochemical industry as a feedstock in the production of ethylene, one of the basic building blocks for a wide range of plastics and other chemical products.

Propane is used for heating, as an engine and industrial fuel, and as a petrochemical feedstock in the production of ethylene and propylene.

Normal butane is used as a petrochemical feedstock in the production of ethylene and butadiene (a key ingredient of synthetic rubber), as a blendstock for motor gasoline, and to produce isobutane through isomerization.

Isobutane is fractionated from mixed butane (a mixed stream of normal butane and isobutane) or produced from normal butane through the process of isomerization, and is used in refinery alkylation to enhance the octane content of motor gasoline, in the production of isooctane and other octane additives, and in the production of propylene oxide.

Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is primarily used as a blendstock for motor gasoline, diluent in crude oil to aid in transportation, and as a petrochemical feedstock.

The results of operations from natural gas processing are primarily dependent on the difference between the revenues we earn from extracting NGLs (in terms of cash processing fees and/or the value of any retained NGLs) and the cost of natural gas and other operating costs incurred in connection with such extraction activities.

Natural gas processing utilizes service contracts that are either fee-based, commodity-based or a combination of the two. Our commodity-based contracts include keepwhole, margin-band, percent-of-liquids, percent-of-proceeds and contracts featuring a combination of commodity and fee-based terms.  To the extent we retain all or a portion of the extracted NGLs as consideration for our processing services, we refer to such volumes as our “equity NGL production.”

If the operating costs of a natural gas processing facility are higher than the incremental value of the NGLs that would be extracted, then recovery levels of certain NGLs, primarily ethane, may be purposefully reduced. This scenario is typically referred to as “ethane rejection” and results in a reduction in NGL volumes available to us for subsequent transportation, fractionation, storage and marketing.

Our NGL marketing activities entail spot and term sales of NGLs that we take title to through our natural gas processing activities (i.e., our equity NGL production) and open market and contract purchases. The results of operations for NGL marketing are primarily dependent on the difference between NGL sales prices and the associated purchase and other costs, including those costs attributable to the use of our other assets by the marketing group.  Market prices for NGLs are subject to fluctuations in response to changes in supply and demand and a variety of additional factors that are beyond our control.  We attempt to mitigate these price risks through the use of commodity derivative instruments.  For a discussion of our commodity hedging program, see Part II, Item 7A of this annual report.
















The following table presents selected information regarding our natural gas processing facilities at February 1, 2021:

       
Total Gas
       
Net Gas
Processing
   
Production
 
Processing
Capacity
   
Region
Ownership
Capacity
of Plant
Facility Name
Location
Served
Interest
(MMcf/d) (1)
(MMcf/d)
Meeker
Colorado
Piceance
100.0%
 1,800
 1,800
Pioneer
Wyoming
Green River
100.0%
 1,100
 1,100
Yoakum
Texas
Eagle Ford
100.0%
 1,050
 1,050
Pascagoula
Mississippi
Gulf of Mexico
  75.0%   (2)
750
 1,000
Orla
Texas
Delaware
100.0%
900
900
Chaco
New Mexico
San Juan
100.0%
 600
 600
Neptune
Louisiana
Gulf of Mexico
  66.0%   (3)
 430
 650
Sea Robin
Louisiana
Gulf of Mexico
  54.1%   (3)
 352
 650
Thompsonville
Texas
Eagle Ford
100.0%
 330
 330
Carthage (4)
Texas
Cotton Valley
100.0%
320
320
Mentone
Texas
Delaware
100.0%
300
300
Shoup
Texas
Eagle Ford
100.0%
 280
 280
Armstrong
Texas
Eagle Ford
100.0%
250
250
Gilmore
Texas
Frio-Vicksburg
100.0%
250
250
San Martin
Texas
Eagle Ford
100.0%
 200
 200
South Eddy
New Mexico
Delaware
100.0%
 200
 200
Waha
Texas
Delaware
100.0%
150
 150
Sonora
Texas
Strawn
100.0%
 120
 120
Venice
Louisiana
Gulf of Mexico
  13.1%   (5)
 98
 750
Indian Springs
Texas
Wilcox-Woodbine
  75.0%   (3)
 90
 120
Chaparral
New Mexico
Delaware
100.0%
 45
 45
    Total
     
9,615
11,065

(1)
The approximate net gas processing capacity does not necessarily correspond to our ownership interest in each facility.  The capacity is based on a variety of factors such as the level of volumes an owner processes at the facility and contractual arrangements with joint owners.
(2)
We own a 75% consolidated interest in the Pascagoula facility through our majority owned subsidiary, Pascagoula Gas Processing LLC.
(3)
We proportionately consolidate our undivided interests in these operating assets.
(4)
The Carthage processing complex consists of two natural gas processing plants: Panola and Bulldog.
(5)
Our 13.1% ownership in the Venice plant is held indirectly through our equity method investment in Venice Energy Services Company, L.L.C.

We operate all of our natural gas processing facilities except for the Venice plant.  On a weighted-average basis, utilization rates for our natural gas processing facilities were approximately 57.6%, 57.4% and 52.7% during the years ended December 31, 2020, 2019 and 2018, respectively.

Our NGL marketing activities utilize a fleet of approximately 880 railcars, the majority of which are leased from third parties.  These railcars are used to deliver feedstocks to our facilities and to distribute NGLs throughout the U.S. and parts of Canada.  We have rail loading and unloading capabilities at certain of our terminal facilities in Arizona, Kansas, Louisiana, Minnesota, Mississippi, New York, North Carolina and Texas. These facilities service both our rail shipments and those of our customers. Our NGL marketing activities also utilize a fleet of approximately 135 tractor-trailer tank trucks that are used to transport LPG for us and on behalf of third parties.  We own and operate the majority of these trucks and trailers.

NGL pipelines
Our NGL pipelines transport mixed NGLs from natural gas processing facilities, refineries and marine terminals to downstream fractionation plants and storage facilities; gather and distribute purity NGL products to and from fractionation plants, storage and terminal facilities, petrochemical plants, refineries and export facilities; and deliver propane and ethane to destinations along our pipeline systems.


The results of operations from our NGL pipelines are primarily dependent upon the volume of NGLs transported (or capacity reserved) and the associated fees we charge for such transportation services. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the Federal Energy Regulatory Commission (“FERC”), or contractual arrangements.  See “Regulatory Matters” within this Part I, Items 1 and 2 for information regarding governmental oversight of our liquids pipelines.

The following table presents selected information regarding our NGL pipelines at February 1, 2021:

   
Pipeline
   
Ownership
Length
Description of Asset
Location(s)
Interest
(Miles)
Mid-America Pipeline System (1)
Midwest and Western U.S.
 100.0%
7,977
South Texas NGL Pipeline System
Texas
 100.0%
2,019
Dixie Pipeline (1)
South and Southeastern U.S.
 100.0%
1,307
ATEX (1)
Texas to Midwest and Northeast U.S.
 100.0%
1,192
Chaparral NGL System (1)
Texas, New Mexico
 100.0%
1,085
Louisiana Pipeline System (1)
Louisiana
 100.0%
877
Seminole NGL Pipeline (1)
Texas
 100.0%
869
Shin Oak NGL Pipeline
Texas
   67.0% (3)
664
Texas Express Pipeline (1)
Texas
   35.0% (4)
594
Skelly-Belvieu Pipeline (1)
Texas, Oklahoma
   50.0% (5)
572
Front Range Pipeline (1)
Colorado, Oklahoma, Texas
   33.3% (6)
 451
Houston Ship Channel Pipeline System
Texas
 100.0%
304
Aegis Ethane Pipeline (1)
Texas, Louisiana
 100.0%
299
Panola Pipeline (1)
Texas
   55.0%  (7)
253
Rio Grande Pipeline (1)
Texas
 100.0%
249
Lou-Tex NGL Pipeline (1)
Texas, Louisiana
 100.0%
206
Promix NGL Gathering System
Louisiana
   50.0%  (8)
194
Texas Express Gathering System
Texas
   45.0%  (9)
170
Tri-States NGL Pipeline (1)
Alabama, Mississippi, Louisiana
   83.3% (10)
168
Others (eight systems) (2)
Various
 Various (11)
459
   Total
   
19,909

(1)
Interstate transportation services provided by these liquids pipelines, in whole or part, are regulated by federal governmental agencies.
(2)
Includes our Belle Rose and Wilprise pipelines located in the coastal regions of Louisiana; two pipelines located near Port Arthur in southeast Texas; our San Jacinto pipeline located in East Texas; our Permian NGL lateral pipelines located in West Texas; Leveret pipeline in West Texas and New Mexico; and a pipeline in Colorado associated with our Meeker facility.  Transportation services provided by the Wilprise, Permian NGL and Leveret pipelines are regulated by federal governmental agencies.
(3)
We own a 67% consolidated interest in the Shin Oak NGL Pipeline through our majority owned subsidiary, Breviloba, LLC.
(4)
Our 35% ownership interest in the Texas Express Pipeline is held indirectly through our equity method investment in Texas Express Pipeline LLC.
(5)
Our 50% ownership interest in the Skelly-Belvieu Pipeline is held indirectly through our equity method investment in Skelly-Belvieu Pipeline Company, L.L.C.
(6)
Our 33.3% ownership interest in the Front Range Pipeline is held indirectly through our equity method investment in Front Range Pipeline LLC.
(7)
We own a 55% consolidated interest in the Panola Pipeline through our majority owned subsidiary, Panola Pipeline Company, LLC.
(8)
Our 50% ownership interest in the Promix NGL Gathering System is held indirectly through our equity method investment in K/D/S Promix, L.L.C.
(9)
Our 45% ownership interest in the Texas Express Gathering System is held indirectly through our equity method investment in Texas Express Gathering LLC.
(10)
We own an 83.3% consolidated interest in the Tri-States NGL Pipeline through our majority owned subsidiary, Tri-States NGL Pipeline, L.L.C.
(11)
We own a 74.7% consolidated interest in the 30-mile Wilprise pipeline through our majority owned subsidiary, Wilprise Pipeline Company, L.L.C.  We proportionately consolidate our 50% undivided interest in a 45-mile segment of the Port Arthur pipelines.  The remainder of these NGL pipelines are wholly owned.


The maximum number of barrels per day that our NGL pipelines can transport depends on the operating rates achieved at a given point in time between various segments of each system (e.g., demand levels at each injection and delivery point and the mix of products being transported).  As a result, we measure the utilization rates of our NGL pipelines in terms of net throughput, which is based on our ownership interest.  In the aggregate, net throughput volumes for these pipelines were 3,589 MBPD, 3,615 MBPD and 3,461 MBPD during the years ended December 31, 2020, 2019 and 2018, respectively.

We operate our NGL pipelines with the exception of the Texas Express Gathering System. The following information describes our principal NGL pipelines:

The Mid-America Pipeline System is an NGL pipeline system consisting of the 3,119-mile Rocky Mountain pipeline, the 2,138-mile Conway North pipeline, the 632-mile Ethane-Propane (“EP”) Mix pipeline, and the 2,088-mile Conway South pipeline. The Rocky Mountain pipeline transports mixed NGLs from production fields located in the Rocky Mountain Overthrust and San Juan Basin to the Hobbs NGL hub located on the Texas-New Mexico border. The Conway North segment links the NGL hub at Conway, Kansas to refineries, petrochemical plants and propane markets in the upper Midwest. NGL hubs, such as those at Mont Belvieu, Hobbs and Conway, provide buyers and sellers with a centralized location for the storage and pricing of products, while also providing connections to intrastate and/or interstate pipelines. The EP Mix segment transports EP mix from the Conway hub to petrochemical plants in Iowa and Illinois. The Conway South pipeline connects the Conway hub with Kansas refineries and provides bi-directional transportation of NGLs between the Conway and Hobbs hubs.  At the Hobbs NGL hub, the Mid-America Pipeline System interconnects with our Seminole NGL Pipeline and Hobbs NGL fractionation and storage facility. The Mid-America Pipeline System is also connected to 18 non-regulated NGL terminals that we own and operate.

The South Texas NGL Pipeline System is a network of NGL gathering and transportation pipelines located in South Texas that gather and transport mixed NGLs from natural gas processing facilities (owned by either us or third parties) to our NGL fractionators located in South Texas and at the Mont Belvieu hub in Chambers County, Texas. In addition, this system transports purity NGL products from our South Texas NGL fractionators to refineries and petrochemical plants located between Corpus Christi, Texas and Houston, Texas and within the Texas City-Houston area, as well as to interconnects with other NGL pipelines and to our Mont Belvieu storage complex.  The South Texas NGL Pipeline System extends our ethane header system from the Mont Belvieu hub to Corpus Christi, Texas.

The Dixie Pipeline transports propane and other NGLs from locations in southeast Texas, south Louisiana and Mississippi to markets in the southeastern U.S.  The Dixie Pipeline operates in seven states:  Alabama, Georgia, Louisiana, Mississippi, North Carolina, South Carolina and Texas, and is connected to eight non-regulated propane terminals that we own and operate.

The Appalachia-to-Texas Express, or ATEX, pipeline transports ethane in southbound service from third-party owned NGL fractionation plants located in Ohio, Pennsylvania and West Virginia to our Mont Belvieu storage complex.  Ethane originating at these fractionation facilities is sourced from the Marcellus and Utica Shale production areas. ATEX operates in nine states: Arkansas, Illinois, Indiana, Louisiana, Missouri, Ohio, Pennsylvania, Texas and West Virginia.

The Chaparral NGL System transports mixed NGLs from natural gas processing facilities located in West Texas and New Mexico to the Mont Belvieu hub.  This system consists of the 906-mile Chaparral pipeline and the 179-mile Quanah pipeline. Interstate and intrastate transportation services provided by the Chaparral pipeline are regulated; however, transportation services provided by the Quanah pipeline are not.

The Louisiana Pipeline System is a network of NGL pipelines that transport NGLs originating in Louisiana and Texas to refineries and petrochemical plants located along the Mississippi River corridor in southern Louisiana.  This system also provides transportation services for our natural gas processing facilities, NGL fractionators and other assets located in Louisiana.

The Seminole NGL Pipeline transports NGLs from the Hobbs hub and the Permian Basin to markets in southeast Texas, including our NGL fractionation complex located in and near Mont Belvieu.  NGLs originating on the Mid-America Pipeline System are a significant source of throughput for the Seminole NGL Pipeline.

The Shin Oak NGL Pipeline transports NGL production from Orla, Texas in the Permian Basin to our NGL fractionation and storage complex located at the Mont Belvieu hub.

The Texas Express Pipeline extends from Skellytown, Texas to our NGL fractionation and storage complex located in and near Mont Belvieu.  Mixed NGLs from production fields located in the Rocky Mountains, Permian Basin and Mid-Continent regions are delivered to the Texas Express Pipeline via an interconnect with our Mid-America Pipeline System near Skellytown.  In addition, the Texas Express Pipeline transports mixed NGLs gathered by the Texas Express Gathering System.  Also, mixed NGLs originating from the Denver-Julesburg (“DJ”) Basin in Colorado are transported to the Texas Express Pipeline using the Front Range Pipeline.

The Skelly-Belvieu Pipeline transports mixed NGLs from Skellytown, Texas to Mont Belvieu.  The Skelly-Belvieu Pipeline receives a significant quantity of NGLs through an interconnect with our Mid-America Pipeline System at Skellytown.

The Front Range Pipeline transports mixed NGLs from natural gas processing facilities located in the DJ Basin in Colorado to an interconnect with our Texas Express Pipeline, Mid-America Pipeline System and other third-party facilities located at Skellytown, Texas.

The Houston Ship Channel Pipeline System connects our Mont Belvieu area assets to our marine terminals on the Houston Ship Channel and to area petrochemical plants, refineries and other pipelines.

The Aegis Ethane Pipeline (“Aegis”) delivers purity ethane to petrochemical facilities located along the southeast Texas and Louisiana Gulf Coast.  Aegis, when combined with a portion of our South Texas NGL Pipeline System, forms an ethane header system stretching from Corpus Christi, Texas to the Mississippi River in Louisiana.

The Panola Pipeline transports mixed NGLs from injection points near Carthage, Texas to the Mont Belvieu hub and supports the Haynesville and Cotton Valley crude oil and natural gas production areas.

The Rio Grande Pipeline transports mixed NGLs from near Odessa, Texas to a pipeline interconnect at the Mexican border south of El Paso, Texas.

The Lou-Tex NGL Pipeline transports mixed NGLs, purity NGL products and refinery grade propylene (“RGP”) between the Louisiana and Texas markets.

NGL fractionation and related facilities
Our NGL fractionators separate mixed NGLs into purity NGL products for third-party customers and our NGL marketing activities.  Mixed NGLs extracted by domestic natural gas processing facilities represent the largest source of volumes processed at our NGL fractionators.  Based upon industry data, we believe that sufficient volumes of mixed NGLs, especially those originating from natural gas processing facilities located in West Texas, will be available for fractionation for the foreseeable future.

The results of operations from our NGL fractionation business are generally dependent upon the volume of mixed NGLs fractionated and either (i) the level of fractionation fees charged (under fee-based contracts) or (ii) the value of NGLs received (under percent-of-liquids arrangements).  Under fee-based fractionation contracts, customers retain title to the NGLs that we process for them.  Under percent-of-liquids fractionation contracts, we retain a portion of the purity NGLs we separate for customers and are exposed to commodity price risk through fluctuations in NGL prices.  We attempt to mitigate these risks through the use of commodity derivative instruments.



The following table presents selected information regarding our NGL fractionation facilities at February 1, 2021:

   
Net Plant
Total Plant
   
Ownership
Capacity
Capacity
Description of Asset
Location
Interest
(MBPD) (1)
(MBPD)
NGL fractionation facilities:
       
Mont Belvieu-area:
       
   Fracs I, II and III
Texas
  75.0% (2)
189
245
   Fracs IV, V, VI ,IX, X and XI
Texas
100.0%
645
645
   Fracs VII and VIII
Texas
  75.0% (3)
128
170
   Total Mont Belvieu-area
   
962
1,060
Shoup and Armstrong
Texas
100.0%
93
93
Hobbs
Texas
100.0%
75
75
Norco
Louisiana
100.0%
75
75
Promix
Louisiana
  50.0%  (4)
73
145
Tebone
Louisiana
100.0%
30
30
Baton Rouge
Louisiana
  32.2%  (5)
19
60
   Total
   
1,327
1,538

(1)
The approximate net plant capacity does not necessarily correspond to our ownership interest in each facility.  The capacity is based on a variety of factors such as the level of volumes an owner processes at the facility and contractual arrangements with joint owners.
(2)
We proportionately consolidate a 75% undivided interest in these fractionators.
(3)
We own a 75% consolidated equity interest in NGL fractionators VII and VIII through our majority owned subsidiary, Enterprise EF78 LLC.
(4)
Our 50% ownership interest in the Promix NGL fractionator is held indirectly through our equity method investment in K/D/S Promix, L.L.C.
(5)
Our 32.2% ownership interest in the Baton Rouge fractionator is held indirectly through our equity method investment in Baton Rouge Fractionators LLC.

On a weighted-average basis, the overall utilization rates for our NGL fractionators (based on nameplate capacities) were 101.6%, 97.8% and 94.0% during the years ended December 31, 2020, 2019 and 2018, respectively.

The following information describes our principal NGL fractionators, all of which we operate:

We own and operate NGL fractionators located in Mont Belvieu, Texas and surrounding areas of Chambers County, Texas.  These fractionators process mixed NGLs from several major NGL supply basins in North America, including the Permian Basin, Rocky Mountains, Eagle Ford Shale, Mid-Continent and San Juan Basin.  Our Mont Belvieu-area NGL fractionators are connected to our network of NGL supply and distribution pipelines, approximately 130 MMBbls of underground salt dome storage capacity, along with access to international markets through our marine terminals located on the Houston Ship Channel.

In 2020, we completed and placed into service two new NGL fractionators located in Chambers County, Texas that are adjacent to our other Mont Belvieu-area NGL fractionators:  Frac X (March 2020) and Frac XI (September 2020). Completion of these two fractionators increased our total NGL fractionation capacity in the Mont Belvieu-area to approximately 1.1 MMBPD.

The Shoup and Armstrong NGL fractionators in South Texas process mixed NGLs supplied by regional natural gas processing facilities.  Purity NGL products from these fractionators are transported to local markets in the Corpus Christi area and also to the Mont Belvieu hub using our South Texas NGL Pipeline System.

The Hobbs NGL fractionator serves NGL producers in West Texas, New Mexico and Colorado. This fractionator receives mixed NGLs from several major supply basins, including the Mid-Continent, Permian Basin, San Juan Basin and Rocky Mountains.  The facility is located at the interconnect of our Mid-America Pipeline System and Seminole NGL Pipeline, thus providing customers access to both the Mont Belvieu and Conway hubs.


The Norco NGL fractionator receives mixed NGLs from refineries and natural gas processing facilities located in southern Louisiana and along the Mississippi and Alabama Gulf Coast, including our Pascagoula and Venice facilities.

We are currently constructing a 60 MBPD natural gasoline hydrotreater facility at our Mont Belvieu-area complex along with related storage and pipeline infrastructure.  The new facility, which is designed to lower the sulfur content of natural gasoline, is scheduled to be completed and placed into service during the fourth quarter of 2021.

NGL and related product storage facilities
We utilize underground salt dome storage caverns and above-ground storage tanks to store mixed and purity NGLs, petrochemicals and related products that are owned by us and our customers.  The results of operations from our storage facilities are dependent upon the level of storage capacity reserved by customers, the volume of product delivered into and withdrawn from storage, and the fees associated with each activity.

The following table presents selected information regarding our NGL and related product storage assets at February 1, 2021:

   
Net Usable
     
Storage
   
Ownership
Capacity
Description of Asset
Location
Interest
(MMBbls) (1)
Mont Belvieu storage complex
Texas
100.0%
129.8
Breaux Bridge, Anse La Butte and Sorrento (2)
Louisiana
100.0%
12.7
Almeda and Markham (3)
Texas
Leased
12.4
Petal (4)
Mississippi
100.0%
5.4
Hutchinson (5)
Kansas
100.0%
4.0
Others (6)
Various
Various
14.3
   Total
   
178.6

(1)
Net usable storage capacity is based on our ownership interest or contractual right-of-use.
(2)
These storage facilities are used in connection with our Louisiana Pipeline System.
(3)
These storage facilities are used in connection with our South Texas NGL Pipeline System.
(4)
This storage facility is used in connection with our Dixie Pipeline.
(5)
This storage facility is used in connection with our Mid-America Pipeline System.
(6)
Primarily consists of operational storage capacity for our major pipeline systems, including the Mid-America Pipeline System, Dixie Pipeline and TE Products Pipeline.  We own substantially all of this storage capacity.

We operate substantially all of our NGL and related product storage facilities.

Our largest underground storage facility is located at the Mont Belvieu hub in Chambers County, Texas. This facility consists of 38 underground salt dome caverns used to store and redeliver mixed and purity NGLs, petrochemicals and related products.  This facility has an aggregate usable storage capacity of 129.8 MMBbls, a brine system with approximately 31 MMBbls of above-ground brine storage capacity and five wells used in brine production.

NGL marine terminals and related operations
We own and operate marine terminals (export and import) that handle NGLs. The results of operations from our NGL marine terminals, all of which are located on the Houston Ship Channel, are primarily dependent upon the level of volumes handled (loading and unloading) and the associated fees we charge for such services.


The following information describes our Houston Ship Channel terminals:

The Enterprise Hydrocarbons Terminal (“EHT”) provides terminaling services to exporters, marketers, distributors, chemical companies and major integrated oil companies.  EHT has extensive waterfront access consisting of seven deep-water ship docks, a barge dock and a lay berth dock.  The terminal can accommodate vessels with up to a 45 foot draft, including Suezmax tankers, which are the largest tankers that can navigate the Houston Ship Channel.  We believe that our location on the Houston Ship Channel enables us to handle larger vessels than our competitors because our waterfront has fewer draft and beam (width) restrictions.  The size and structure of our waterfront allows us to receive and unload products for our customers and provide terminaling services.

EHT can load refrigerated cargoes of low-ethane propane and/or butane (collectively referred to as LPG) onto multiple tanker vessels simultaneously.  Our LPG export services continue to benefit from increased NGL supplies produced from domestic shale plays, international demand for propane as a feedstock in ethylene production, and for power generation and heating purposes.  The current estimated maximum loading capacity for LPG at EHT is approximately 835 MBPD.  EHT has the capability to load up to six Very Large Gas Carrier (“VLGC”) vessels simultaneously, while maintaining the option to switch between loading propane and butane.  EHT can load a single VLGC in less than 24 hours, creating greater efficiencies and cost savings for our customers.  LPG loading volumes at EHT averaged 588 MBPD, 483 MBPD and 445 MBPD during the years ended December 31, 2020, 2019 and 2018, respectively.

The primary customer of EHT is our NGL marketing group, which uses the terminal to meet the needs of export customers.  NGL marketing transacts with these customers using long-term sales contracts with take-or-pay provisions and/or exchange agreements.  In recent years, the U.S. has become the largest exporter of LPG in the world, with shipments originating from EHT playing a key role.

EHT also includes an NGL import terminal.  This import terminal can offload NGLs from tanker vessels at rates up to 8,000 barrels per hour depending on the product.  Our NGL import volumes for the last three years were minimal.

EHT also provides terminaling services involving crude oil, propylene and refined products.  EHT’s assets and activities associated with crude oil terminaling and storage are a component of our Crude Oil Pipelines & Services business segment.  EHT’s activities involving propylene and refined products are a component of our Petrochemical & Refined Products Services business segment.

The Morgan’s Point Ethane Export Terminal, located on the Houston Ship Channel, has a nameplate loading capacity of approximately 10,000 barrels per hour of fully refrigerated ethane and is the largest of its kind in the world. The terminal supports domestic production of U.S. ethane from shale plays by providing the global petrochemical industry with access to a low-cost feedstock option and opportunities for supply diversification.  Ethane volumes handled by the terminal are sourced from our Mont Belvieu-area NGL fractionators and storage complex.  Ethane loading volumes at the terminal averaged 134 MBPD, 143 MBPD and 146 MBPD during the years ended December 31, 2020, 2019 and 2018, respectively.

Crude Oil Pipelines & Services

This business segment includes our crude oil pipelines, crude oil storage and marine terminals, and related crude oil marketing activities.

Crude oil pipelines
We have crude oil gathering and transportation pipelines located in Oklahoma, New Mexico and Texas. The results of operations from our crude oil pipelines are primarily dependent upon the volume of crude oil transported (or capacity reserved) and the associated fees we charge for such transportation services.  Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the FERC, or contractual arrangements.  See “Regulatory Matters” within this Part I, Items 1 and 2 for information regarding governmental oversight of our liquids pipelines.

The following table presents selected information regarding our crude oil pipelines and related operations at February 1, 2021:

   
Operational
 
   
Our
Storage
Pipeline
   
Ownership
Capacity
Length
Description of Asset
Location(s)
Interest
(MMBbls) (2)
(Miles)
Midland-to-ECHO System:
       
   Midland-to-ECHO 1 pipeline
Texas
    80.0% (3)
4.0
418
   Midland-to-ECHO 2 pipeline
Texas
  100.0%
444
   Midland-to-ECHO 3 pipeline
Texas
    29.0% (4)
521
   Total Midland-to-ECHO System:
   
4.0
1,383
Seaway Pipeline (1)
Texas, Oklahoma
    50.0% (5)
9.8
1,273
West Texas System (1)
Texas, New Mexico
  100.0%
1.3
1,078
South Texas Crude Oil Pipeline System
Texas
  100.0%
5.1
633
Basin Pipeline (1)
Texas, New Mexico, Oklahoma
    13.0% (6)
6.0
618
EFS Midstream System
Texas
  100.0%
0.3
525
Eagle Ford Crude Oil Pipeline System
Texas
    50.0% (7)
4.5
390
   Total
   
31.0
5,900

(1)
Transportation services provided by these liquids pipelines are regulated, in whole or part, by federal governmental agencies.
(2)
Operational storage capacity amounts presented on a gross basis.
(3)
The Midland-to-Sealy section of the Midland-to-ECHO 1 pipeline is owned by Whitethorn Pipeline Company LLC, in which we own an 80% consolidated interest.
(4)
We proportionately consolidate our 29% undivided interest in the Midland-to-Webster pipeline, which we refer to as the Midland-to-ECHO 3 pipeline.
(5)
Our 50% ownership interest in the Seaway Pipeline is held indirectly through our equity method investment in Seaway Crude Holdings LLC (“Seaway”).
(6)
We proportionately consolidate our 13% undivided interest in the Basin Pipeline.
(7)
Our 50% ownership interest in the Eagle Ford Crude Oil Pipeline System is held indirectly through our equity method investment in Eagle Ford Pipeline LLC.

The maximum number of barrels per day that our crude oil pipelines can transport depends on the operating rates achieved at a given point in time between various segments of each system (e.g., demand levels at each delivery point and the grades of crude oil being transported).  As a result, we measure the utilization rates of our crude oil pipelines in terms of net throughput, which is based on our ownership interest.  In the aggregate, net throughput volumes for these pipelines were 2,166 MBPD, 2,304 MBPD and 2,000 MBPD during the years ended December 31, 2020, 2019 and 2018, respectively.

We operate our crude oil pipelines with the exception of the Basin Pipeline, Eagle Ford Crude Oil Pipeline System and Midland-to-ECHO 3. The following information describes our principal crude oil pipelines:

The Midland-to-ECHO System supports Permian Basin crude oil production by providing producers and other shippers with transportation solutions that are both cost-efficient and operationally flexible.  After aggregating crude at our Midland terminal, the system has the capability to transport multiple grades of crude oil, including West Texas Intermediate (“WTI”), WTI light sweet crude oil (“West Texas Light”), West Texas Sour, and condensate, to our Enterprise Crude Houston (“ECHO”) storage terminal (using batched shipments to safeguard crude quality) for further delivery to markets along the Gulf Coast.  Using the ECHO terminal, shippers on the Midland-to-ECHO System have access to every refinery in Houston, Texas City, Beaumont and Port Arthur, Texas, as well as our crude oil export terminal facilities.

The Midland-to-ECHO 1 pipeline originates at our Midland terminal and extends 418 miles to our Sealy storage terminal.  Volumes arriving at Sealy are then transported to our ECHO terminal using the Rancho II pipeline, which is a component of our South Texas Crude Oil Pipeline System. The Midland-to-ECHO 1 pipeline has an approximate maximum transportation capacity of up to 620 MBPD, depending on certain operational variables.


The Midland-to-ECHO 2 pipeline originates at our Midland terminal and extends 444 miles to our Sealy terminal, with crude oil volumes arriving at Sealy transported to our ECHO terminal using the Rancho II pipeline.  The Midland-to-ECHO 2 pipeline was created by converting the Midland-to-Sealy segment of one of our two Seminole NGL pipelines from NGL service to crude oil service.  We retain the flexibility to convert this pipeline back to NGL service should future market conditions support the need for additional NGL transportation capacity out of the Permian Basin. The Midland-to-ECHO 2 pipeline has an approximate maximum transportation capacity of up to 225 MBPD, depending on certain operational variables.

In July 2019, we announced a third expansion of our Midland-to-ECHO System (“Midland-to-ECHO 3”) comprised of a 36-inch pipeline extending from Midland, Texas to our ECHO terminal, and further from ECHO to a third-party terminal in Webster, Texas  (collectively, the “Midland-to-Webster pipeline”). In October 2020, we announced that the Midland-to-ECHO segment of the Midland-to-Webster pipeline was placed into service.  The ECHO-to-Webster segment was mechanically complete in December 2020.  Once all facilities are placed into full commercial service, our maximum transportation capacity on the Midland-to-Webster pipeline is expected to approximate 450 MBPD.

In October 2019, we announced plans to construct a fourth pipeline (the “Midland-to-ECHO 4” pipeline) that would have connected our Midland terminal with our ECHO terminal by utilizing existing segments of our South Texas Crude Oil Pipeline System along with new construction. In September 2020, we cancelled this project in connection with the amendment of certain crude oil transportation agreements.

The Seaway Pipeline connects the Cushing, Oklahoma crude oil hub with markets in southeast Texas. The Seaway Pipeline is comprised of the Longhaul System, the Freeport System and the Texas City System. The Cushing hub is an industry trading hub and price settlement point for WTI crude oil on the New York Mercantile Exchange (“NYMEX”).

The Longhaul System consists of two approximately 500-mile, 30-inch diameter pipelines (Seaway I and the Seaway Loop) that provide north-to-south transportation of crude oil from the Cushing hub to Seaway’s Jones Creek terminal located near Freeport, Texas. The aggregate transportation capacity of the Longhaul System is approximately 950 MBPD, depending on the type and mix of crude oil being transported and other variables. The Jones Creek terminal is connected by pipeline to our ECHO terminal, which enables Seaway to serve a variety of customers along the upper Texas Gulf Coast including the Beaumont/Port Arthur area.

The Freeport System consists of a marine terminal that facilitates both crude oil imports and exports, along with pipelines that transport crude oil to and from Freeport, Texas and the Jones Creek terminal.

The Texas City System consists of a marine terminal and storage tanks, various pipelines and related infrastructure used to transport crude oil to refineries in the Texas City, Texas area and to and from terminals in the Galena Park, Texas area, our ECHO terminal and locations along the Houston Ship Channel.  The Texas City System also receives production from certain offshore Gulf of Mexico developments. The intrastate pipeline transportation capacity of the Freeport System and Texas City System is approximately 480 MBPD and 800 MBPD, respectively.

Seaway’s Texas City marine terminal features two docks, a 45-foot draft, an overall length of 1,125 feet, a 200-foot beam (width) and the capacity to load crude oil at a rate of 35,000 barrels per hour.  We have used Seaway’s Texas City terminal to partially load Very Large Crude Carrier (“VLCC”) tankers, with the remaining volumes subsequently loaded on such vessels using lightering operations in the Gulf of Mexico.

The West Texas System connects crude oil gathering systems in West Texas and southeast New Mexico to our terminal facility located in Midland, Texas.  The West Texas System, including the Loving County pipeline, is a key part of our strategic crude oil aggregation program designed to support Permian Basin producers. At Midland, shippers have access to storage and terminal services, as well as connectivity to multiple transportation alternatives such as trucking and pipeline infrastructure that offer access to various downstream markets, including the Gulf Coast.

The South Texas Crude Oil Pipeline System transports crude oil and condensate originating in South Texas to customers in the Houston area.  This system includes storage terminal assets located at Sealy, Texas.  The South Texas Crude Oil Pipeline System also includes our Rancho II pipeline, which extends 89-miles from the Sealy terminal to our ECHO terminal.  From ECHO, we have connectivity to refinery customers and our marine terminals along the Texas Gulf Coast.

The Basin Pipeline transports crude oil from the Permian Basin in West Texas and southern New Mexico to the Cushing hub.

The EFS Midstream System serves producers in the Eagle Ford Shale, by providing condensate gathering and processing services as well as gathering, treating and compression services for associated natural gas.  The EFS Midstream System includes 525 miles of gathering pipelines, 11 central gathering plants having a combined condensate storage capacity of 0.3 MMBbls, 201 MBPD of condensate stabilization capacity and 1.0 Bcf/d of associated natural gas treating capacity.

The Eagle Ford Crude Oil Pipeline System transports crude oil and condensate for producers in South Texas.  The system, which is effectively looped and has a capacity to transport over 600 MBPD of light and medium grades of crude oil, consists of 390 miles of crude oil and condensate pipelines originating in Gardendale, Texas and extending to Corpus Christi, Texas.  The system interconnects with our South Texas Crude Oil Pipeline System in Wilson County, Texas and our Corpus Christi marine terminal.

Crude oil terminals
In addition to the operational storage capacity associated with our crude oil pipelines, we also own and operate crude oil terminals located in Houston, Midland and Beaumont, Texas and Cushing, Oklahoma that are used to store crude oil for us and our customers.  In conjunction with other aspects of our midstream network, our crude oil terminals provide Gulf Coast refiners with an integrated system featuring supply diversification, significant storage capabilities and a high capacity pipeline distribution system. Our system has access to an aggregate refining capacity of approximately 8 MMBPD.

The results of operations from crude oil terminals are primarily dependent upon the level of volumes stored and the length of time such storage occurs, including the level of firm storage capacity reserved, pumpover volumes and the fees associated with each activity.  If the terminal offers marine services, the results of operations from these activities are primarily dependent upon the level of volumes handled (loading and unloading) and the associated fees we charge for such services.

The following table presents selected information regarding our crude oil terminals at February 1, 2021:

   
Number of
Net Storage
   
Ownership
Above-Ground
Capacity
Description of Asset
Location(s)
Interest
Tanks in Service
(MMBbls)
EHT (crude oil)
Texas
100.0%
81
23.4
ECHO (1)
Texas
100.0%
14
5.9
Beaumont Marine West
Texas
100.0%
12
4.2
Cushing
Oklahoma
100.0%
19
3.3
Midland (2)
Texas
100.0%
9
2.7
Corpus Christi
Texas
       50.0% (3)
4
0.7
   Total
   
139
40.2

(1)
Number of tanks and storage capacity excludes three tanks that are used in the operation of our Midland-to-ECHO 1 pipeline and three tanks owned by Seaway.
(2)
Number of tanks and storage capacity excludes three tanks that are used in the operation of our Midland-to-ECHO 1 pipeline.
(3)
Our 50% ownership interest in the terminal is held indirectly through our equity method investment in Eagle Ford Terminals Corpus Christi LLC.




The following information describes our principal crude oil terminals, all of which we operate with the exception of the Corpus Christi terminal.

Our EHT marine terminal located on the Houston Ship Channel includes export assets capable of loading up to 2.0 MMBPD, or 62 MMBbls per month, of crude oil.  The crude oil terminal at EHT represents one of the largest such facilities on the Gulf Coast.  As noted previously, EHT can accommodate vessels with up to a 45-foot draft, including Suezmax tankers, which are the largest tankers that can navigate the Houston Ship Channel.

The ECHO terminal is located in Houston, Texas and provides storage customers with access to major refineries located in the Houston, Texas City and Beaumont/Port Arthur areas.  ECHO also has connections to marine terminals, including EHT, that provide access to any refinery on the U.S. Gulf Coast and international markets.

The Beaumont Marine West terminal is located on the Neches River near Beaumont, Texas.  This terminal includes three deep-water docks and one barge dock that facilitate the exporting and importing of crude oil and related products.

The Cushing terminal is located at the Cushing hub in Oklahoma and provides crude oil storage, pumpover and trade documentation services.  This terminal is one of the origination points for our Seaway Pipeline.

The Midland terminal provides crude oil storage, pumpover and trade documentation services.  The Midland terminal is the origination point for our Midland-to-ECHO pipelines.

The Corpus Christi terminal, located in Corpus Christi, Texas, is capable of loading ocean-going vessels with either crude oil or condensate.  The terminal includes one deep-water ship dock and serves Eagle Ford Shale and Permian Basin producers through a connection with our Eagle Ford Crude Oil Pipeline System.

Sea Port Oil Terminal.  In July 2019, we announced the execution of long-term customer agreements supporting the development of our Sea Port Oil Terminal (“SPOT”) in the Gulf of Mexico.  As a result of these agreements, we announced our final investment decision with respect to SPOT, subject to obtaining the required approvals and licenses from the federal Maritime Administration, which is currently reviewing our SPOT application. We currently anticipate receiving approval for SPOT as early as the third quarter of 2021; however, we can give no assurance as to whether the project will ultimately be approved or the timing of such decision.

SPOT consists of proposed onshore and offshore facilities, including a fixed platform located approximately 30 nautical miles off the Brazoria County, Texas coast in approximately 115 feet of water.  SPOT is designed to load a VLCC at rates of approximately 85,000 barrels per hour. We believe that SPOT’s design meets or exceeds federal requirements for such facilities and, unlike existing and other proposed offshore terminals, is designed with a vapor control system to minimize emissions.  SPOT would provide customers with an integrated export solution that leverages our extensive supply, storage and distribution network along the Gulf Coast, with access to approximately 6 MMBbls of crude oil supply and more than 300 MMBbls of storage based on our estimates.

In December 2019, we announced the execution of a letter of intent (“LOI”) with an affiliate of Enbridge Inc. (“Enbridge”) to jointly develop SPOT in the Gulf of Mexico.  Under terms of the LOI, we agreed to negotiate an equity participation right agreement with Enbridge whereby, subject to SPOT receiving a deepwater port license, an affiliate of Enbridge could acquire a noncontrolling member interest in SPOT Terminal Services LLC, which owns SPOT.

Crude oil marketing activities
Our crude oil marketing activities generate revenues from the sale and delivery of crude oil and condensate purchased either directly from producers or from others on the open market.  The results of operations from our crude oil marketing activities are primarily dependent upon the difference, or spread, between crude oil and condensate sales prices and the associated purchase and other costs, including those costs attributable to the use of our assets.  In general, sales prices referenced in the underlying contracts are market-based and include pricing differentials for factors such as delivery location or crude oil quality.  We use derivative instruments to mitigate our exposure to commodity price risks associated with our crude oil marketing activities.  For a discussion of our commodity hedging program, see Part II, Item 7A of this annual report.

Our Crude Oil Pipelines & Services segment also includes a fleet of approximately 310 tractor-trailer tank trucks, the majority of which we lease and operate, that are used to transport crude oil.

Natural Gas Pipelines & Services

This business segment includes our natural gas pipeline systems that provide for the gathering, treating and transportation of natural gas.  This segment also includes our natural gas marketing activities.

Natural gas pipelines and related storage assets
Our natural gas gathering pipelines gather, treat and transport natural gas from production developments to regional natural gas plants for further processing.  Our natural gas transmission pipelines transport natural gas from regional processing facilities to downstream electric generation plants, local gas distribution companies, industrial and municipal customers, storage facilities or other connecting pipelines.

The results of operations from our natural gas pipelines and related storage assets are primarily dependent upon the volume of natural gas gathered, treated, transported or stored, the level of firm capacity reservations made by shippers, and the fees associated with each activity.  Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the FERC, or contractual arrangements.  See “Regulatory Matters” within this Part I, Items 1 and 2 for information regarding governmental oversight of our natural gas pipelines.

The following table presents selected information regarding our natural gas pipelines and related infrastructure at February 1, 2021:

     
Net Capacity (1)
     
Pipeline
Pipeline
Natural Gas
Usable
   
Ownership
Length
Capacity
Treating
Storage
Description of Asset
Location(s)
Interest
(Miles)
(MMcf/d)
(MMcf/d)
(Bcf)
Texas Intrastate System  (2)
Texas
 Various (5)
6,893
7,345
12.9
Acadian Gas System (2)
Louisiana
 100.0% (6)
1,307
3,100
1.3
Jonah Gathering System
Wyoming
 100.0%
776
2,360
Piceance Basin Gathering System
Colorado
 100.0%
191
1,800
San Juan Gathering System
New Mexico, Colorado
 100.0%
6,117
1,750
420
Permian Basin Gathering System
Texas, New Mexico
 100.0%
1,722
1,575
150
White River Hub (3)
Colorado
   50.0%  (7)
10
1,500
Haynesville Gathering System
Louisiana, Texas
 100.0%
360
1,300
810
BTA Gathering System (4)
Texas
 100.0%  (8)
788
925
840
Indian Springs Gathering System (4)
Texas
   80.0%  (9)
145
160
Delmita Gathering System
Texas
 100.0%
203
145
South Texas Gathering System
Texas
 100.0%
517
143
220
Old Ocean Pipeline
Texas
   50.0% (10)
240
80
Big Thicket Gathering System
Texas
 100.0%
250
60
Central Treating Facility
Colorado
 100.0%
200
   Total
   
19,519
22,243
2,640
14.2

(1)
Net capacity amounts are based on our ownership interest or contractual right-of-use.
(2)
Transportation services provided by these pipeline systems, in whole or part, are regulated by both federal and state governmental agencies.
(3)
Services provided by the White River Hub are regulated by federal governmental agencies.
(4)
Transportation services provided by these systems are regulated in part by state governmental agencies.
(5)
We proportionately consolidate our undivided interests, which range from 22% to 80%, in 1,471 miles of the Texas Intrastate System.  The Texas Intrastate System also includes our Wilson natural gas storage facility, which consists of a network of leased and owned underground salt dome storage caverns located in Wharton County, Texas with an aggregate 12.9 Bcf of usable storage capacity.  Four of these caverns, comprising 6.9 Bcf of usable capacity, are held under an operating lease.  The remainder of our Texas Intrastate System is wholly owned.
(6)
The Acadian Gas System includes a leased 1.3 Bcf underground salt dome natural gas storage cavern located at Napoleonville, Louisiana.
(7)
Our 50% ownership interest in White River Hub is held indirectly through our equity method investment in White River Hub, LLC.
(8)
This system includes approximately 52 miles of pipeline held under an operating lease.
(9)
We proportionately consolidate our 80% undivided interest in the Indian Springs Gathering System.
(10)
Our 50% ownership interest in the Old Ocean Pipeline is held indirectly through our equity method investment in Old Ocean Pipeline, LLC.



On a weighted-average basis, overall utilization rates for our natural gas pipelines were approximately 57.2%, 60.0% and 58.3% during the years ended December 31, 2020, 2019 and 2018, respectively.  These utilization rates represent actual natural gas volumes delivered as a percentage of our nominal delivery capacity and do not reflect firm capacity reservation agreements where capacity fees are earned whether or not the shipper actually utilizes such capacity.

We operate our natural gas pipelines and storage facilities with the exception of the White River Hub, Old Ocean Pipeline and certain segments of the Texas Intrastate System.  The following information describes our principal natural gas pipelines:

The Texas Intrastate System is comprised of the 6,276-mile Enterprise Texas pipeline system and the 617-mile Channel pipeline system. The Texas Intrastate System gathers, transports and stores natural gas from supply basins in Texas including the Permian Basin and Eagle Ford and Barnett Shales for delivery to local gas distribution companies, electric utility plants and industrial and municipal consumers. The system is also connected to regional natural gas processing facilities and other intrastate and interstate pipelines.  The Texas Intrastate System serves a number of commercial markets in Texas, including Corpus Christi, San Antonio/Austin, Beaumont/Orange and Houston, including the Houston Ship Channel industrial market.

The Acadian Gas System transports, stores and markets natural gas in Louisiana.  The Acadian Gas System is comprised of the 582-mile Cypress pipeline, 424-mile Acadian pipeline, 275-mile Haynesville Extension pipeline and 26-mile Enterprise Pelican pipeline.  The Acadian Gas System links natural gas supplies from Louisiana (e.g., from the Haynesville Shale supply basin) and offshore Gulf of Mexico developments with local gas distribution companies, electric utility plants and industrial customers located primarily in the Baton Rouge/New Orleans/Mississippi River corridor.

In September 2019, we announced plans to expand and extend our Acadian Gas System in order to deliver natural gas production from the Haynesville Shale to the liquefied natural gas (“LNG”) market in South Louisiana. The expansion project will include construction of an approximately 80-mile natural gas pipeline (the “Gillis Lateral”) extending from near Cheneyville, Louisiana to third-party pipeline interconnects near Gillis, Louisiana, including multiple pipelines serving regional LNG export facilities.  According to the FERC, the LNG market in South Louisiana and Southeast Texas includes facilities, including those under construction, featuring an aggregate 18 Bcf/d of export capacity. The Gillis Lateral is expected to have a transportation capacity of approximately 1 Bcf/d.  In addition to construction of the Gillis Lateral, we plan to increase the transportation capacity of the Haynesville Extension from 1.8 Bcf/d to 2.1 Bcf/d by adding horsepower at our compressor station in Mansfield, Louisiana (the “Mansfield Project”).

The Mansfield Project and construction of the Gillis Lateral are supported by long-term customer contracts and are expected to begin service in the fourth quarter of 2021. Once the expansion project is completed, we expect that our Acadian Gas System will be able to deliver up to 2.1 Bcf/d of Haynesville Shale production into the LNG market, South Louisiana industrial complex and other pipeline interconnects that serve attractive southeastern U.S. markets.

The Jonah Gathering System is located in the Greater Green River Basin of southwest Wyoming.  This system gathers natural gas from the Jonah and Pinedale supply fields for delivery to regional natural gas processing facilities, including our Pioneer facility.

The Piceance Basin Gathering System gathers natural gas produced from the Piceance Basin in northwestern Colorado to our Meeker natural gas processing facility.

The San Juan Gathering System gathers and treats natural gas produced from the San Juan Basin in northern New Mexico and southern Colorado and delivers the natural gas either directly into interstate pipelines or to regional natural gas plants, including our Chaco facility, for further processing prior to being transported on interstate pipelines.




The Permian Basin Gathering System is comprised of the 1,051-mile Carlsbad pipeline system, the 614-mile Waha pipeline system, the 34-mile Orla pipeline system and the 23-mile Mentone pipeline system. The Permian Basin Gathering System gathers natural gas from the Permian Basin for delivery to regional natural gas processing facilities, including our Chaparral, South Eddy, Waha, Mentone and Orla plants, and delivers residue and treated natural gas into our Texas Intrastate System and third-party pipelines.

The White River Hub is a natural gas hub facility serving producers in the Piceance Basin.  The facility enables producers to access six interstate natural gas pipelines and has a gross throughput capacity of 3 Bcf/d of natural gas.

The Haynesville Gathering System consists of the 217-mile State Line gathering system, the 73-mile Southeast Mansfield gathering system, and the 70-mile Southeast Stanley gathering system.  The Haynesville Gathering System gathers and treats natural gas produced from the Haynesville and Bossier Shale supply basins and the Cotton Valley and Taylor Sand formations in Louisiana and eastern Texas for delivery to regional markets, including (through an interconnect with the Haynesville Extension pipeline) markets served by our Acadian Gas System.

The BTA Gathering System, which is located in East Texas, gathers and treats natural gas from the Haynesville Shale and Bossier, Cotton Valley and Travis Peak formations.  This system includes our Fairplay Gathering System.

The Indian Springs Gathering System, along with the Big Thicket Gathering System, gather natural gas from the Woodbine, Wilcox and Yegua production areas in East Texas.

The Delmita Gathering System gathers natural gas from the Frio-Vicksburg formation in South Texas for delivery to our South Texas natural gas processing facilities.

The South Texas Gathering System gathers natural gas from the Olmos and Wilcox formations for delivery to our South Texas natural gas processing facilities.

The Old Ocean Pipeline transports natural gas from an injection point on our Texas Intrastate System near Maypearl, Texas for delivery to a pipeline interconnect at Sweeny, Texas.  A third party serves as operator of the pipeline, which has a gross natural gas transportation capacity of 160 MMcf/d and entered full service in January 2019.

The Central Treating Facility is located in Rio Blanco County, Colorado and serves producers in the Piceance Basin.  Natural gas delivered to the treating facility is treated to remove impurities and transported to our Meeker gas plant for further processing.

Natural gas marketing activities
Our natural gas marketing activities generate revenues from the sale and delivery of natural gas purchased from producers, regional natural gas processing facilities and on the open market.  Our natural gas marketing customers include local gas distribution companies and electric utility plants. The results of operations from our natural gas marketing activities are primarily dependent upon the difference, or spread, between natural gas sales prices and the associated purchase and other costs, including those costs attributable to the use of our assets.  In general, sales prices referenced in the underlying contracts are market-based and may include pricing differentials for factors such as delivery location.








We are exposed to commodity price risk to the extent that we take title to natural gas volumes in connection with our natural gas marketing activities and certain intrastate natural gas transportation contracts.  In addition, we purchase and resell natural gas for certain producers that use our San Juan, Piceance, Permian Basin and Jonah Gathering Systems and certain segments of our Acadian Gas and Texas Intrastate Systems.  Also, several of our natural gas gathering systems, while not providing marketing services, have some exposure to risks related to fluctuations in commodity prices through transportation arrangements with shippers.  For example, nearly all of the transportation revenues generated by our San Juan Gathering System are based on a percentage of a regional natural gas price index.  This index may fluctuate based on a variety of factors, including changes in natural gas supply and consumer demand.  We attempt to mitigate these price risks through the use of commodity derivative instruments.  For a discussion of our commodity hedging program, see Part II, Item 7A of this annual report.

Goodwill Impairment
In December 2020, we recognized a goodwill impairment charge of $296.3 million attributable to the Natural Gas Pipelines & Services business segment.  For information regarding this charge, see Note 6 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Petrochemical & Refined Products Services

This business segment includes our:

propylene production facilities, which include propylene fractionation units and a PDH facility, and related pipelines and marketing activities;

butane isomerization complex and related deisobutanizer (“DIB”) operations;

octane enhancement, iBDH and HPIB production facilities;

refined products pipelines, terminals and related marketing activities;

an ethylene export terminal and related operations; and

marine transportation business.

Propylene production facilities and related operations
Our propylene production facilities and related operations include propylene fractionation (or splitter) units, a PDH facility, propylene pipelines, propylene export assets and related petrochemical marketing activities.

Propylene production and related marketing activities.  Propylene is a key feedstock used by the petrochemical industry.  There are three grades of propylene: polymer grade propylene (“PGP”), with a minimum purity of 99.5%; chemical grade propylene (“CGP”), with a minimum purity of approximately 93-94%; and refinery grade propylene (“RGP”), with a purity of approximately 70%. Propylene fractionation units separate RGP, which is a mixture of propane and propylene, into either PGP or CGP.  Our PDH facility produces PGP using propane feedstocks.  The demand for PGP primarily relates to the manufacture of polypropylene, which has a variety of end uses including packaging film, fiber for carpets and upholstery, molded plastic parts for appliances, and automotive, houseware and medical products.  CGP is a basic petrochemical used in the manufacturing of plastics, synthetic fibers and foams.

To the extent we fractionate RGP for customers, we enter into toll processing arrangements.  In our petrochemical marketing activities, we purchase RGP on the open market for fractionation at our splitter units and sell the resulting PGP to customers at market-based prices.  The results of this marketing activity are primarily dependent upon the difference, or spread, between the sales prices of the PGP and the associated purchase and other costs, including the costs attributable to use of our propylene production assets and related infrastructure. To limit the exposure of these marketing activities to price risk, we attempt to match the timing and price of our feedstock purchases with those of the sales of end products.

Our petrochemical marketing activities also include the purchase of propane for our PDH facility to process into PGP, which is then sold to customers under long-term sales contracts (take-or-pay arrangements) that feature minimum volume commitments and contractual pricing that minimizes our commodity price risk.

The following table presents selected information regarding our propylene production facilities at February 1, 2021:

 
Our
Net Plant
Total Plant
   
Ownership
Capacity
Capacity
Description of Asset
Location
Interest
(MBPD)
(MBPD)
Propylene fractionation facilities:
       
Mont Belvieu (six units)
Texas
    Various   (1)
80
93
BRPC (one unit)
Louisiana
       30.0%  (2)
7
23
   Total
   
87
116
         
PDH facility:
       
PDH 1
Texas
     100.0%
25
25

(1)
We proportionately consolidate a 66.7% undivided interest in three of the propylene splitters, which have an aggregate 38 MBPD of total plant capacity.  The remaining three propylene fractionation units are wholly owned.
(2)
Our 30% ownership interest in the BRPC facility is held indirectly through our equity method investment in Baton Rouge Propylene Concentrator LLC (“BRPC”).

We produce PGP at our Mont Belvieu facilities and CGP at our BRPC facility.  On a weighted-average basis, the overall utilization rate of our propylene production facilities was approximately 79.4%, 86.7% and 86.7% during the years ended December 31, 2020, 2019 and 2018, respectively.

Global demand for propylene is increasing; however, the use of lighter crude oil feedstocks by U.S. refiners and increased use of ethane by steam crackers has reduced propylene production from these traditional sources.  This has led to the development of more “on purpose” propylene production facilities such as our PDH 1 facility.  This facility, which is located in Chambers County, Texas at our Mont Belvieu complex, has the capacity to produce up to 1.65 billion pounds per year, or approximately 25 MBPD, of PGP.  At this nameplate production rate, the facility upgrades approximately 35 MBPD of propane as feedstock. The PDH 1 facility is integrated with our legacy Mont Belvieu propylene fractionation units, which provides us with operational reliability and flexibility for both the PDH facility and the fractionation units. The construction of PDH 1 was underwritten by long-term, fee-based contracts that feature minimum volume commitments.

We have initiated legal proceedings involving the former general contractor for PDH 1.  For a summary of this litigation, see Note 17 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

PDH 2.  In September 2019, we announced the execution of long-term, fee-based contracts with affiliates of LyondellBasell Industries N.V. that support construction of our second PDH facility (referred to as “PDH 2”).  In June 2020, we executed additional long-term PGP sales agreements with Marubeni Corporation in support of PDH 2.  Like PDH 1, PDH 2 is expected to have the capacity to upgrade up to 35 MBPD of propane and produce up to 1.65 billion pounds per year of PGP.  PDH 2 will be located in Chambers County, Texas at our Mont Belvieu complex and is scheduled to begin service in the second quarter of 2023.  Once PDH 2 is placed into service and integrated with PDH 1 and our other propylene production facilities, we will have the capability to produce 11 billion pounds of propylene per year.








Propylene pipelines.  The results of operations from our petrochemical pipelines are primarily dependent upon the volume of products transported and the associated fees we charge for such transportation services.  The following table presents selected information regarding our propylene pipelines at February 1, 2021:

 
Ownership
Length
Description of Asset
Location(s)
Interest
(Miles)
Lou-Tex Propylene Pipeline
Texas, Louisiana
  100.0%
267
North Dean Pipeline System
Texas
  100.0%
189
Texas City RGP Gathering System
Texas
  100.0%
157
Propylene Splitter PGP Distribution System
Texas
  100.0%
92
Louisiana RGP Gathering System
Louisiana
  100.0%
63
Lake Charles PGP Pipeline
Texas, Louisiana
    50.0%  (1)
27
La Porte PGP Pipeline
Texas
    80.0%  (2)
20
Sabine Pipeline
Texas, Louisiana
  100.0%
15
Total
   
830

(1)
We proportionately consolidate our 50% undivided interest in the Lake Charles PGP Pipeline.
(2)
We own an 80% consolidated interest in the La Porte PGP Pipeline through our majority owned subsidiaries, La Porte Pipeline Company, L.P. and La Porte Pipeline GP, L.L.C.

The maximum number of barrels per day that our petrochemical pipelines can transport depends on the operating rates achieved at a given point in time between various segments of each system (e.g., demand levels at each delivery point and the mix of products being transported).  As a result, we measure the utilization rates of our petrochemical pipelines in terms of net throughput, which is based on our ownership interest.  Total net throughput volumes were 140 MBPD, 124 MBPD and 125 MBPD during the years ended December 31, 2020, 2019 and 2018, respectively.

With the exception of the Lake Charles PGP Pipeline in Louisiana, we operate all of our propylene production assets and related pipelines.

Propylene export assets.  Our EHT marine terminal located on the Houston Ship Channel includes export assets capable of loading up to 3,000 barrels per hour, or 72 MBPD, of semi-refrigerated propylene.

Isomerization and related operations
We own and operate three isomerization units at our Mont Belvieu complex having an aggregate processing capacity of 116 MBPD that comprise the largest commercial isomerization facility in the U.S.  We also own and operate a 70-mile pipeline system used to transport high-purity isobutane from the Mont Belvieu hub to Port Neches, Texas.

The demand for commercial isomerization services depends upon the energy industry’s requirements for isobutane and high-purity isobutane in excess of the isobutane produced through the process of NGL fractionation and refinery operations.  Isomerization units convert normal butane feedstock into mixed butane, which is a stream of isobutane and normal butane.  DIB units, of which we own and operate ten located at our Mont Belvieu complex, then separate the isobutane from the normal butane.  Any remaining unconverted (or residual) normal butane generated by the DIB process is then recirculated through the isomerization process until it has been converted into varying grades of isobutane, including high-purity isobutane.  The primary uses of isobutane are for the production of propylene oxide, isooctane, isobutylene and alkylate for motor gasoline. We also use certain of our DIB units to fractionate mixed butanes originating from NGL fractionation activities, imports and other sources into isobutane and normal butane.  The operating flexibility provided by our multiple standalone DIBs enables us to capture market opportunities resulting from fluctuations in demand and prices for different types of butanes.

The results of operations from our isomerization business are generally dependent on the volume of normal and mixed butanes processed and the level of toll processing fees charged to customers.

Our isomerization assets provide processing services to meet the needs of third-party customers and our other businesses, including our NGL marketing activities and octane enhancement production facility. On a weighted-average basis, the utilization rates of our isomerization facility were approximately 82.8%, 94.0% and 92.2% during the years ended December 31, 2020, 2019 and 2018, respectively.

Octane enhancement and related operations
We own and operate an octane enhancement production facility located at our Mont Belvieu complex that is designed to produce isobutylene and either isooctane or methyl tertiary butyl ether (“MTBE”).  The products produced by this facility are used by refiners to increase octane values in reformulated motor gasoline blends.  The high-purity isobutane feedstocks consumed in the production of these products are supplied by our isomerization units.

We sell our octane enhancement products at market-based prices.  We attempt to mitigate the price risk associated with these products by entering into commodity derivative instruments.  To the extent that we produce MTBE, it is sold exclusively into the export market.  We measure the utilization of our octane enhancement facility in terms of its combined isooctane, isobutylene and MTBE production volumes, which averaged 15 MBPD, 24 MBPD and 25 MBPD during the years ended December 31, 2020, 2019 and 2018, respectively.

We also own and operate a facility located on the Houston Ship Channel that produces up to 4 MBPD of HPIB and includes an associated storage facility with 0.6 MMBbls of related product storage capacity.  The primary feedstock for this plant, an isobutane/isobutylene mix, is produced by our octane enhancement and iBDH facilities.  HPIB is used in the production of polyisobutylene, which is used in the manufacture of lubricants and rubber.  In general, we sell HPIB at market-based prices with a cost-based floor.  On a weighted-average basis, utilization rates for this facility were 97.6%, 77.6% and 88.9% for the years ended December 31, 2020, 2019 and 2018, respectively.

The results of operations from our octane enhancement and HPIB facilities are generally dependent on the level of production volumes and the difference, or spread, between the sales prices of the products and the associated feedstock purchase costs and other operating expenses.

Isobutane Dehydrogenation Unit. In December 2019, we completed construction and placed our iBDH unit into service.  The facility, which is located at our Mont Belvieu complex and supported by long-term, fee-based contracts, is capable of processing approximately 25 MBPD of butane into nearly 1 billion pounds per year of isobutylene.  Production from the iBDH plant enables us to optimize our MTBE and high purity isobutylene assets and meet growing market demand for isobutylene.

Steam crackers and refineries have historically been the major source of propane and butane olefins for downstream use; however, with the increased use of light-end feedstocks such as ethane, the need for “on purpose” olefins production has increased.  Like our PDH facility, the iBDH plant will help meet market demand where traditional supplies have been reduced.  The iBDH plant will increase our production of high purity and low purity isobutylene, both of which are used as feedstocks to manufacture lubricants, rubber products and fuel additives.

Refined products services
Our refined products services business includes refined products pipelines, terminals and associated marketing activities.

Refined products pipelines.  We own and operate the TE Products Pipeline, which is a 3,247-mile pipeline system comprised of 2,922 miles of regulated interstate pipelines and 325 miles of unregulated intrastate Texas pipelines.  The system primarily transports refined products from the upper Texas Gulf Coast to Seymour, Indiana. From Seymour, segments of the TE Products Pipeline extend to Chicago, Illinois; Lima, Ohio; Selkirk, New York; and a location near Philadelphia, Pennsylvania.  East of Seymour, Indiana, the TE Products Pipeline is primarily dedicated to NGL transportation service. The refined products transported by the TE Products Pipeline are produced by refineries and include motor gasoline and distillates.  

The results of operations for this pipeline system are dependent upon the volume of products transported and the level of fees charged to shippers.  The tariffs charged for such services are either contractual or regulated by governmental agencies, including the FERC. See “Regulatory Matters” within this Part I, Items 1 and 2 discussion for information regarding governmental oversight of our liquids pipelines, including tariffs charged for transportation services.




The maximum number of barrels per day that our TE Products Pipeline can transport depends on the operating balance achieved at a given point in time between various segments of the system (e.g., demand levels at each delivery point and the mix of products being transported).  As a result, we measure the utilization rate of this pipeline in terms of throughput.  Aggregate throughput volumes by product type for the TE Products Pipeline were as follows for the years indicated:

 
For the Year Ended December 31,
 
   
2020
   
2019
   
2018
 
Refined products transportation (MBPD)
   
419
     
407
     
456
 
Petrochemical transportation (MBPD)
   
156
     
126
     
148
 
NGL transportation (MBPD)
   
55
     
63
     
71
 

The TE Products Pipeline system includes five non-regulated refined products truck terminals and 19.6 MMBbls of aggregate storage capacity.

Refined products marine terminals.  We own and operate marine terminals located on the Neches River near Beaumont, Texas that handle refined products along with crude oil.  Our Beaumont facilities include five deep-water ship docks, three barge docks and access to approximately 11.1 MMBbls of aggregate refined products storage capacity.

We also handle refined products at EHT on the Houston Ship Channel.  In addition to providing vessel loading and unloading services for refined products, EHT’s refined products operations include 2.3 MMBbls of aggregate storage capacity through the use of 19 above-ground storage tanks.

The results of operations from these marine terminals are primarily dependent upon the volume handled and the associated storage and other fees we charge.

Refined products marketing activities.  Our refined products marketing activities generate revenues from the sale and delivery of refined products obtained on the open market.  The results of operations from our refined products marketing activities are primarily dependent upon the difference, or spread, between product sales prices and the associated purchase and other costs, including those costs attributable to the use of our other assets.  In general, we sell our refined products at market-based prices, which may include pricing differentials for factors such as grade and delivery location.  We use derivative instruments to mitigate our exposure to commodity price risks associated with our refined products marketing activities.  For a discussion of our commodity hedging program, see Part II, Item 7A of this annual report.

Ethylene export terminal and related operations
In December 2020, our ethylene export terminal located at our Morgan’s Point facility on the Houston Ship Channel entered full service with the commissioning of a refrigerated storage tank capable of handling 66 million pounds of ethylene.  The ethylene export terminal, which had been in limited service since December 2019, features two docks and a nameplate capacity to load 1 million tons of ethylene per year. Ethylene is the primary feedstock for a wide variety of consumer products, including cell phones and computer parts, food packaging, apparel, textiles and personal protective equipment.  We own a 50% member interest in Enterprise Navigator Ethylene Terminal LLC, which owns the export facility.

Our ethylene system serves as an open market storage and trading hub for the ethylene industry by incorporating storage capacity, connections to multiple ethylene pipelines, and high-volume export capabilities.  In support of our ethylene business, our Mont Belvieu storage operations include a high-capacity underground ethylene storage well having a storage capacity of 600 million pounds of ethylene.  The storage well is connected to our Morgan’s Point ethylene export terminal and further to Bayport, Texas by a 27-mile pipeline.





In May 2019, we announced plans to further expand our ethylene pipeline and logistics system by constructing the Baymark ethylene pipeline in South Texas, which is a leading growth area for new ethylene crackers and related facilities.  The Baymark pipeline will originate in Bayport and extend approximately 90 miles to Markham, Texas.  The Baymark pipeline is supported by long-term customer commitments and is expected to begin service in mid-2021.  We own a 70% consolidated interest in the Baymark pipeline through our majority owned subsidiary, Baymark Pipeline LLC.  Customers using the Baymark pipeline will have pipeline access to our high-capacity ethylene storage well in Mont Belvieu and our export terminal at Morgan’s Point.

Marine transportation
Our marine transportation business consists of 65 tow boats and 160 tank barges used to transport refined products, crude oil, asphalt, condensate, heavy fuel oil, LPG and other petroleum products on key U.S. inland and intracoastal waterway systems.  The marine transportation industry uses tow boats as power sources and tank barges for freight capacity. Our marine transportation assets serve refinery and storage terminal customers along the Mississippi River, the intracoastal waterway between Texas and Florida, and the Tennessee-Tombigbee waterway system.  We own and operate shipyard and repair facilities located in Houma and Morgan City, Louisiana and marine fleeting facilities located in Bourg, Louisiana and Channelview, Texas.

The results of operations from our marine transportation business are generally dependent upon the level of fees charged to transport petroleum products.

Our fleet of marine vessels operated at an average utilization rate of 86.1%, 94.0% and 93.5% during the years ended December 31, 2020, 2019 and 2018, respectively.

Our marine transportation business is subject to regulation, including by the U.S. Department of Transportation (“DOT”), Department of Homeland Security, U.S. Department of Commerce and the U.S. Coast Guard (“USCG”).  For information regarding these regulations, see “Regulatory Matters – Federal Regulation of Marine Operations,” within this Part I, Items 1 and 2 discussion.

In December 2020, we recognized an impairment charge of $256.7 million attributable to our marine transportation business. For information regarding this charge, see Note 4 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Regulatory Matters

The following information describes the principal effects of regulation on our operations, including those regulations involving safety and environmental matters and the rates we charge customers for transportation services.

Environmental, Safety and Conservation

The safe operation of our pipelines and other assets is a top priority.  We are committed to protecting the environment and the health and safety of the public and those working on our behalf by conducting our business activities in a safe and environmentally responsible manner.

Occupational Safety and Health
Certain of our facilities are subject to general industry requirements of the Federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes.  We believe we are in material compliance with OSHA and similar state requirements, including general industry standards, record keeping requirements and monitoring of occupational exposures of employees.


Certain of our facilities are also subject to OSHA Process Safety Management (“PSM”) regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals.  These regulations apply to any process involving certain chemicals, flammable gases or liquids at or above a specified threshold (as defined in the regulations).  In addition, we are subject to Risk Management Plan regulations of the U.S. Environmental Protection Agency (“EPA”) at certain facilities.  These regulations are intended to complement the OSHA PSM regulations.  These EPA regulations require us to develop and implement a risk management program that includes a five-year accident history report, an offsite consequence analysis process, a prevention program and an emergency response program.  We believe we are operating in material compliance with the OSHA PSM regulations and the EPA’s Risk Management Plan requirements.

The OSHA hazard communication standard, the community right-to-know regulations under Title III of the federal Superfund Amendments and Reauthorization Act, and comparable state statutes require us to organize and disclose information about the hazardous materials used in our operations.  Certain parts of this information must be reported to federal, state and local governmental authorities and local citizens upon request.  These laws and provisions of the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) require us to report spills and releases of hazardous chemicals in certain situations.

Pipeline Safety
We are subject to extensive regulation by the DOT as authorized under various provisions of Title 49 of the United States Code and comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of our pipeline facilities.  These statutes require companies that own or operate pipelines to (i) comply with such regulations, (ii) permit access to and copying of pertinent records, (iii) file certain reports and (iv) provide information as required by the U.S. Secretary of Transportation.  The DOT regulates natural gas and hazardous liquids pipelines through its Pipeline and Hazardous Materials Safety Administration (“PHMSA”).  We believe we are in material compliance with DOT regulations.

We are also subject to DOT pipeline integrity management regulations that specify how companies should assess, evaluate, validate and maintain the integrity of pipeline segments that, in the event of a release, could impact High Consequence Areas (“HCAs”).  HCAs include populated areas, unusually sensitive areas and commercially navigable waterways.  These regulations require the development and implementation of an integrity management program that utilizes internal pipeline inspection techniques, pressure testing or other equally effective means to assess the integrity of pipeline segments in HCAs.  These regulations also require periodic review of pipeline segments in HCAs to ensure that adequate preventive and mitigative measures exist and that companies take prompt action to address integrity issues raised in the assessment and analysis process.  We have identified our pipeline segments in HCAs and developed an appropriate integrity management program for such assets.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the “Pipeline Safety Act”) provides for regulatory oversight of the nation’s pipelines, penalties for violations of pipeline safety rules, and other DOT matters.  The Pipeline Safety Act currently provides for penalties involving non-compliance with DOT regulations of $0.2 million for a single violation and a maximum fine for the most serious pipeline safety violations (e.g., those violations resulting in deaths, injuries or major environmental harm) of approximately $2.2 million per incident.   In addition, the Pipeline Safety Act includes additional safety requirements for newly constructed pipelines.

In June 2016, the “Securing America’s Future Energy:  Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016” (the “SAFE PIPES Act”) was signed into law. The SAFE PIPES Act establishes or continues the development of requirements affecting pipeline safety including, but not limited to, the following: (i) providing the PHMSA with additional authority to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities, without prior notice or an opportunity for a hearing; (ii) obligating the PHMSA to develop safety standards for natural gas storage facilities; and (iii) requiring the PHMSA to complete certain of the outstanding mandates under existing legislation and to report to Congress on the status of overdue rulemakings. The SAFE PIPES Act also empowered PHMSA to address unsafe conditions or practices constituting imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. PHMSA published an interim rule in October 2016 and a final rule on October 1, 2019 to implement the agency’s expanded authority to address imminent hazards to life, property, or the environment.

In response to the SAFE PIPES Act, PHMSA also issued an interim final rule in December 2016 and a final rule in January 2020 adopting federal safety regulations and reporting requirements for underground natural gas storage facilities.  The final rule incorporates by reference American Petroleum Institute Recommended Practices 1170 and 1171, which outline safety standards for underground natural gas storage facilities and provide a minimum federal standard for inspection, enforcement and training.

In December 2020, the “Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020” (“PIPES Act”) was signed into law.  The PIPES Act extends the PHMSA’s statutory mandate through 2023.  It continues the legislative mandates that were established in the SAFE PIPES Act and creates new regulatory authorities for PHMSA or state agencies enforcing the federal pipeline safety regulations that include, among other things: (i) requiring regulations prescribing the applicability of pipeline safety requirements to idled natural gas transmission and hazardous liquids pipelines; (ii) updating existing large-scale LNG regulations; (iii) the creation of new leak detection and repair programs that impact certain gathering lines, new and existing transmission pipeline facilities, and new and existing gas distribution pipelines that have the dual purpose of meeting the need for gas pipeline safety and protecting the environment; (iv) necessitating updates to gas pipeline and hazardous liquid pipeline facility written inspection and maintenance plans; and (v) extensive new regulations governing gas distribution systems.

DOT regulations have also incorporated by reference American Petroleum Institute Standard 653 (“API 653”) as the industry standard for the inspection, repair, alteration and reconstruction of above-ground storage tanks. API 653 requires that above-ground storage tanks undergo regularly scheduled maintenance, which may result in significant and unanticipated expenditures for repairs or upgrades that are deemed necessary to ensure the continued safe and reliable operation of such tanks.

In October 2015, PHMSA issued proposed new or revised regulations under the Pipeline Safety Act and the SAFE PIPES Act that may impact our hazardous liquids pipelines.   Several elements of the proposed rules were incorporated into a final rule issued by PHMSA in October 2019, significantly extending and expanding the reach of certain PHMSA integrity management requirements (for example, periodic assessments and expanded use of leak detection systems), regardless of the pipeline’s proximity to an HCA. The final rule also requires all hazardous liquid pipelines in or affecting an HCA to be capable of accommodating in-line inspection tools within the next 20 years. In addition, the final rule extends annual, accident and safety-related conditional reporting requirements to gravity lines and certain gathering lines and also imposes inspection requirements on pipelines in areas affected by extreme weather events and natural disasters, such as hurricanes, landslides, floods, earthquakes or other similar events that are likely to damage infrastructure.  This final rule became effective July 1, 2020.

In March 2016, PHMSA issued proposed new safety regulations for natural gas transmission pipelines that broaden the scope of safety coverage in several ways, including but not limited to: (i) modifying the regulation of gathering lines by eliminating the exemption from reporting requirements for gas gathering line operators and revising the definition for gathering lines; (ii) adding new assessment and revising repair criteria for pipeline segments in HCAs and establishing repair criteria for pipelines that are outside of HCAs; (iii) expanding the scope of the regulations to include pipelines located in areas of Moderate Consequence Areas (“MCAs”); (iv) adding a requirement to test pipelines built before 1970, which are currently exempt from certain pipeline safety requirements; (v) modifying the way that pipeline operators secure and inspect transmission pipeline infrastructure following extreme weather events; (vi) clarifying requirements for conducting risk assessment associated with integrity management activities; (vii) expanding mandatory data collection and integration requirements associated with integrity management activities, including data validation; (viii) requiring new safety features for pipeline “pig” launchers and receivers; and (ix) requiring a systematic approach to verify a pipeline’s maximum allowable operating pressure (“MAOP”) and requiring operators to report MAOP exceedances.  PHMSA has since decided to split its 2016 proposed rule, which has become known as the “gas mega rule,” into three separate rulemakings to facilitate completion. The first of these three rulemakings, relating to onshore gas transmission pipelines, was published as a final rule on October 1, 2019 and became effective on July 1, 2020.  However, due to the COVID-19 pandemic, PHMSA announced a stay of enforcement of initial compliance deadlines to provide operators with additional time to incorporate the new procedures. The rule imposes numerous requirements on such pipelines, including MAOP reconfirmation, the periodic assessment of these pipelines in populated areas not designated as HCAs, the reporting of exceedances of MAOP, and the consideration of seismicity as a risk factor in integrity management.  The PIPES Act requires PHMSA to issue the remaining rulemakings comprising the gas mega rule by the end of March 2021.

PHMSA has also issued a final rule, which became effective in January 2019, that amends pipeline safety regulations covering the types, design, and installation of plastic materials that can be used to transport natural gas. The new rule permits the use of PVC pipe, adopts a variety of applicable industry standards, and revises regulations related to storage and handling, component design, valve design, standard fittings, and pipe testing associated with the use of plastic pipe.

The development and/or implementation of more stringent requirements pursuant to regulations implementing all of the requirements of the Pipeline Safety Act, the SAFE PIPES Act, or the PIPES Act, as well as any implementation of the PHMSA rules thereunder or reinterpretation of guidance by PHMSA or any state agencies with respect thereto, may result in us incurring significant and unanticipated expenditures to comply with such standards.  Until any proposed regulations are finalized, the impact on our operations, if any, is not known.

Environmental Matters
Our operations are subject to various environmental and safety requirements and potential liabilities under extensive federal, state and local laws and regulations. These include, without limitation: CERCLA; the Resource Conservation and Recovery Act (“RCRA”); the Federal Clean Air Act (“CAA”); the Clean Water Act (“CWA”); the Oil Pollution Act of 1990 (“OPA”); the OSHA; the Emergency Planning and Community Right-to-Know Act; the National Historic Preservation Act; and comparable or analogous state and local laws and regulations.  Such laws and regulations affect many aspects of our present and future operations, and generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals with respect to air emissions, water quality, wastewater discharges and solid and hazardous waste management.  Failure to comply with these requirements may expose us to fines, penalties and/or interruptions in our operations that could have a material adverse effect on our financial position, results of operations and cash flows.

If a leak, spill or release of hazardous substances occurs at any facilities that we own, operate or otherwise use, or where we send materials for treatment or disposal, we could be held liable for all resulting liabilities, including investigation, remedial and clean-up costs.  Likewise, we could be required to remove previously disposed waste products or remediate contaminated property, including situations where groundwater has been impacted.  Any or all of these developments could have a material adverse effect on our financial position, results of operations and cash flows.

We believe our operations are in material compliance with existing environmental and safety laws and regulations and that our compliance with such regulations will not have a material adverse effect on our financial position, results of operations and cash flows.  However, environmental and safety laws and regulations are subject to change.  The trend in environmental regulation has been to place more restrictions and limitations on activities that may be perceived to impact the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation.  New or revised regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our financial position, results of operations and cash flows.

On occasion, we are assessed monetary sanctions by governmental authorities related to administrative or judicial proceedings involving environmental matters.

Air Quality
Our operations are associated with regulated, permitted emissions of air pollutants.  As a result, we are subject to the CAA and comparable state laws and regulations including state air quality implementation plans.  These laws and regulations regulate emissions of air pollutants from various industrial sources, including certain of our facilities, and also impose various monitoring and reporting requirements.  These laws and regulations may also require that we (i) obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase in existing levels of air emissions, (ii) obtain and strictly comply with the requirements of air permits containing various emission and operational limitations, or (iii) utilize specific emission control technologies to limit emissions.


Increasingly, environmental groups are challenging requests to modify or renew permits and seeking to apply more stringent provisions on applicants.  Our failure to comply with applicable requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, including enforcement actions, and our inability to renew or secure a needed modification to an existing permit could adversely affect our operations.  We may also be required to incur certain capital expenditures for air pollution control equipment in connection with obtaining and maintaining permits and approvals for air emissions.

Water Quality
The CWA and comparable state laws impose strict controls on the discharge of petroleum and its derivatives into regulated waters.  The CWA provides penalties for any discharge of petroleum products in reportable quantities and imposes substantial potential liability for the costs of removing petroleum or other hazardous substances.  State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of a release of petroleum or its derivatives into navigable waters or groundwater. Federal spill prevention control and countermeasure mandates require appropriate containment berms and similar structures to help prevent a petroleum tank release from impacting regulated waters.  The EPA has also adopted regulations that require us to have permits in order to discharge certain storm water run-off.  Storm water discharge permits may also be required by certain states in which we operate and may impose monitoring and other requirements.  The CWA prohibits discharges of dredged and fill material in wetlands and other waters of the U.S. unless authorized by an appropriately issued permit.  We believe that our costs of compliance with these CWA requirements will not have a material adverse effect on our financial position, results of operations and cash flows.

The primary federal law for crude oil spill liability is the OPA, which addresses three principal areas of crude oil pollution: prevention, containment and clean-up, and liability.  The OPA applies to vessels, deepwater ports, offshore production platforms and onshore facilities, including terminals, pipelines and transfer facilities.  In order to handle, store or transport crude oil above certain thresholds, onshore facilities are required to file oil spill response plans with the USCG, the DOT’s Office of Pipeline Safety (“OPS”) or the EPA, as appropriate.  Numerous states have enacted laws similar to the OPA.  Under the OPA and similar state laws, responsible parties for a regulated facility from which crude oil is discharged may be liable for remediation costs, including damage to surrounding natural resources.  Any unpermitted release of petroleum or other pollutants from our pipelines or facilities could result in fines or penalties as well as significant remediation costs.

Contamination resulting from spills or releases of petroleum products is an inherent risk within the pipeline industry.  To the extent that groundwater contamination requiring remediation exists along our pipeline systems or other facilities as a result of historical operations, we believe any such contamination could be controlled or remedied; however, such costs are site specific and there is no assurance that the impact will not be material in the aggregate.

Environmental groups have instituted lawsuits regarding certain nationwide permits issued by the U.S. Army Corps of Engineers. These permits allow for streamlined permitting of pipeline projects.  If these lawsuits are successful, timelines for future pipeline construction projects could be adversely impacted.

Disposal of Hazardous and Non-Hazardous Wastes
In our normal operations, we generate hazardous and non-hazardous solid wastes that are subject to requirements of the federal RCRA and comparable state statutes, which impose detailed requirements for the handling, storage, treatment and disposal of solid waste.  We also utilize waste minimization and recycling processes to reduce the volumes of our solid wastes.


CERCLA, also known as “Superfund,” imposes liability, often without regard to fault or the legality of the original act, on certain classes of persons who contributed to the release of a “hazardous substance” into the environment.  These persons include the owner or operator of a facility where a release occurred and companies that disposed or arranged for the disposal of hazardous substances found at a facility.  Under CERCLA, responsible parties may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies.  CERCLA and RCRA also authorize the EPA and, in some instances, third parties to take actions in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible parties.  It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.  In the course of our ordinary operations, our pipeline systems and other facilities generate wastes that may fall within CERCLA’s definition of a “hazardous substance” or be subject to CERCLA and RCRA remediation requirements.  It is possible that we could incur liability for remediation, or reimbursement of remediation costs, under CERCLA or RCRA for remediation at sites we currently own or operate, whether as a result of our or our predecessors’ operations, at sites that we previously owned or operated, or at disposal facilities previously used by us, even if such disposal was legal at the time it was undertaken.

Endangered Species
The federal Endangered Species Act, as amended, and comparable state laws, may restrict commercial or other activities that affect endangered and threatened species or their habitats.  Some of our current or future planned facilities may be located in areas that are designated as a habitat for endangered or threatened species and, if so, may limit or impose increased costs on facility construction or operation.  In addition, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

FERC Regulation – Liquids Pipelines

Certain of our NGL, refined products and crude oil pipeline systems have interstate common carrier movements subject to regulation by the FERC under the Interstate Commerce Act (“ICA”).  Pipelines providing such movements (referred to as “interstate liquids pipelines”) include, but are not limited to, the following: ATEX, Aegis, Dixie Pipeline, TE Products Pipeline, Front Range Pipeline, Mid-America Pipeline System, Seaway Pipeline, Seminole NGL Pipeline and Texas Express Pipeline.  These pipelines are owned by legal entities whose movements are subject to FERC regulation, including periodic reporting requirements.  For example, ATEX, Aegis and the TE Products Pipeline are owned by Enterprise TE Products Pipeline Company LLC (“Enterprise TE”), which provides FERC-regulated movements.

The ICA prescribes that the rates we charge for transportation on these interstate liquids pipelines must be just and reasonable, and that the rules applied to our services not unduly discriminate against or confer any undue preference upon any shipper. The FERC regulations implementing the ICA further require that interstate liquids pipeline transportation rates and rules be filed with the FERC.  The ICA permits interested persons to challenge proposed new or changed rates or rules, and authorizes the FERC to investigate such changes and to suspend their effectiveness for a period of up to seven months.  Upon completion of such an investigation, the FERC may require refunds of amounts collected above what it finds to be a just and reasonable level, together with interest.  The FERC may also investigate, upon complaint or on its own motion, rates and related rules that are already in effect, and may order a carrier to change them prospectively.  Upon an appropriate showing, a shipper may obtain reparations (including interest) for damages sustained for a period of up to two years prior to the filing of its complaint.


The rates charged for our interstate liquids pipeline services are generally based on a FERC-approved indexing methodology, which allows a pipeline to charge rates up to a prescribed ceiling that changes annually based on the year-to-year change in the U.S. Producer Price Index for Finished Goods (“PPI”).  A rate increase within the indexed rate ceiling is presumed to be just and reasonable unless a protesting party can demonstrate that the rate increase is substantially in excess of the pipeline’s operating costs.  For the five-year period ending June 30, 2021, we are permitted to adjust the indexed rate ceiling annually by PPI plus 1.23%.  On December 17, 2020, the FERC issued a final rule setting the index for the five-year period beginning July 1, 2021 at PPI plus 0.78%.  In any year in which the index is negative due to a decline in the PPI, a pipeline must file to lower its rates if they otherwise would be above the indexed rate ceiling.  Otherwise, a pipeline is permitted to increase its rates to the new ceiling.  As an alternative to this indexing methodology, we may also choose to support changes in our rates based on a cost-of-service methodology, by obtaining advance approval to charge “market-based rates,” or by charging “settlement rates” agreed to by all affected shippers.

In December 2014, Seaway submitted an application requesting market-based rate setting authority. Certain parties filed protests to the application.  In September 2015, the FERC issued an order setting the matter for hearing. In December 2016, an administrative law judge issued an initial decision in the market-based rate proceeding (“2016 Initial Decision”) finding that the FERC should grant Seaway’s application for market-based rates.  In May 2018, the FERC issued an order affirming the initial decision’s finding that Seaway lacks market power in the applicable markets, thereby granting Seaway market-based rate authority.

In March 2018, the FERC issued a Revised Policy Statement on the Treatment of Income Taxes (the “Revised Policy”). The Revised Policy reversed a 13-year old policy that permitted a pipeline owned by a master limited partnership (“MLP”) to recover an income tax allowance (“ITA”) in its cost-of-service rates, if it could demonstrate that the ultimate owners of the pipeline (i.e., the unitholders of the MLP) have an actual or potential income tax liability. In July 2018, the FERC, in an Order on Rehearing, decided to provide pipeline MLPs the opportunity to argue for inclusion of an ITA in cost-of-service rates on a case-by-case basis, as opposed to having no opportunity to recover an ITA. The D.C. Circuit upheld the Revised Policy and Order on Rehearing to a MLP pipeline on July 31, 2020 following court challenges initiated in September 2018.

The Revised Policy and Order on Rehearing do not impact oil and liquids pipelines with market-based rate authority, or those that charge “settlement rates,” and have no immediate effect on crude oil and liquid pipelines with rates set using the indexing methodology, given that the current index will remain in effect through June 30, 2021.  Following issuance of the Revised Policy, the FERC now requires crude oil and liquids pipelines owned by MLPs to remove the ITA from their cost-of-service reporting in FERC Form No. 6.  In its final rule issued December 17, 2020, the FERC removed any effect of the change in ITA treatment in determining the index for rates that will take effect on July 1, 2021.

Changes in the FERC’s methodologies for approving rates could adversely affect us.  In addition, challenges to our regulated rates could be filed with the FERC and future decisions by the FERC regarding our regulated rates could adversely affect our cash flows.  We believe the transportation rates currently charged by our interstate liquids pipelines are in accordance with the ICA and applicable FERC regulations.  However, we cannot predict the rates we will be allowed to charge in the future for transportation services by such pipelines.

FERC Regulation – Natural Gas Pipelines and Related Matters

Certain of our intrastate natural gas pipelines, including the Texas Intrastate System and Acadian Gas System, are subject to regulation by the FERC under the Natural Gas Policy Act of 1978 (“NGPA”), in connection with the transportation and storage services they provide pursuant to Section 311 of the NGPA.  Under Section 311, along with the FERC’s implementing regulations, an intrastate pipeline may transport gas “on behalf of” an interstate pipeline company or any local distribution company served by an interstate pipeline, without becoming subject to the FERC’s broader regulatory authority under the Natural Gas Act of 1938 (“NGA”).  These services must be provided on an open and nondiscriminatory basis, and the rates charged for these services may not exceed a “fair and equitable” level as determined by the FERC in periodic rate proceedings.


In July 2018, the FERC issued a final rule to address the impact of the Tax Cuts and Jobs Act on cost-of-service rates for jurisdictional natural gas pipelines.  The final rule primarily impacts interstate pipelines regulated under the NGA.  With respect to intrastate pipelines regulated by the FERC under the NGPA, the rule requires an intrastate pipeline with rates on file with a state regulatory agency to file with the FERC a new rate election for its interstate rates if the state rates are reduced to reflect the reduced income tax rates adopted in the Tax Cuts and Jobs Act.  As of the filing date of this annual report, we have not been required to refile the rates for our intrastate systems as a result of this rule.

We believe that the transportation rates currently charged and the services performed by our natural gas pipelines are all in accordance with the applicable requirements of the NGPA and FERC regulations.  However, we cannot predict the rates we will be allowed to charge in the future for transportation services by our pipelines.

The resale of natural gas in interstate commerce is subject to FERC oversight.  In order to increase transparency in natural gas markets, the FERC has established rules requiring the annual reporting of data regarding natural gas sales.  The FERC has also established regulations that prohibit manipulation of energy markets.  A violation of the FERC’s regulations may subject us to civil penalties, suspension or loss of authorization to perform services or make sales of natural gas, disgorgement of unjust profits or other appropriate non-monetary remedies imposed by the FERC.  Pursuant to the Energy Policy Act of 2005, the potential civil and criminal penalties for any violation of the NGPA, or any rules, regulations or orders of the FERC, were approximately $1.3 million per day per violation as of January 2021.  The Federal Trade Commission and the Commodity Futures Trading Commission (“CFTC”) have also issued rules and regulations prohibiting energy market manipulation.  We believe that our natural gas sales activities are in compliance with all applicable regulatory requirements.

State Regulation of Pipeline Transportation Services

Transportation services rendered by our intrastate liquids and natural gas pipelines are subject to regulation in many states, including Alabama, Colorado, Illinois, Kansas, Louisiana, Minnesota, Mississippi, New Mexico, Oklahoma, Texas and Wyoming.  Although the applicable state statutes and regulations vary widely, they generally require that intrastate pipelines publish tariffs setting forth all rates, rules and regulations applying to intrastate service, and generally require that pipeline rates and practices be reasonable and nondiscriminatory.

Federal Regulation of Marine Operations

The operation of tow boats, barges and marine equipment create obligations involving property, personnel and cargo under General Maritime Law.  These obligations create a variety of risks including, among other things, the risk of collision and allision, which may precipitate claims for personal injury, cargo, contract, pollution, third-party claims and property damages to vessels and facilities.

We are subject to the Jones Act and other federal laws that restrict maritime transportation between U.S. departure and destination points to vessels built and registered in the U.S. and owned and manned by U.S. citizens.  As a result of this ownership requirement, we are responsible for monitoring the foreign ownership of our common units and other partnership interests.  If we do not comply with such requirements, we would be prohibited from operating our vessels in U.S. coastwise trade, and under certain circumstances we would be deemed to have undertaken an unapproved foreign transfer, resulting in severe penalties, including permanent loss of U.S. coastwise trading rights for our vessels, fines or forfeiture of the vessels.  In addition, the USCG and American Bureau of Shipping maintain the most stringent regime of vessel inspection in the world, which tends to result in higher regulatory compliance costs for U.S.-flagged operators than for owners of vessels registered under foreign flags of convenience.  Our marine operations are also subject to the Merchant Marine Act of 1936, which under certain conditions would allow the U.S. government to requisition our marine assets in the event of a national emergency.


Climate Change Discussion

There is considerable discussion over climate change and the environmental effects of greenhouse gas emissions and their associated consequences on global climate, oceans and ecosystems. Climate change could have a long-term impact on our operations.  For example, our facilities that are located in low lying areas such as the coastal regions of Louisiana and Texas may be at increased risk due to flooding, rising sea levels, or disruption of operations from more frequent and severe weather events.  Facilities in areas with limited water availability may be impacted if droughts become more frequent or severe.  Changes in climate or weather may hinder exploration and production activities or increase the cost of production of oil and gas resources and consequently affect the volume of hydrocarbon products entering our system.  Changes in climate or weather may also affect consumer demand for energy or alter the overall energy mix.

In response to governmental, scientific and public concerns that emissions of certain gases, commonly referred to as greenhouse gases, including gases associated with oil and natural gas production such as carbon dioxide, methane and nitrous oxide among others, contribute to a warming of the earth’s atmosphere and other adverse environmental effects, various governmental authorities have considered or taken actions to reduce emissions of greenhouse gases.  For example, the EPA has taken action under the CAA to regulate greenhouse gas emissions.  In addition, certain states (individually or in regional cooperation), including states in which some of our facilities or operations are located, have taken or proposed measures to reduce emissions of greenhouse gases. Also, the U.S. Congress from time to time has proposed legislative measures for imposing restrictions or requiring fees or carbon taxes for the emission of greenhouse gases.

Actions have also taken place at the international level, with the U.S. being involved.  Various policies and approaches, including establishing a cap on emissions, requiring efficiency measures, or providing incentives for emissions reduction, use of renewable energy, or use of replacement fuels with lower carbon content are under discussion and have and may continue to result in additional actions involving greenhouse gases.

These federal, regional and state measures generally apply to industrial sources (including facilities in the oil and gas sector) and suppliers and distributors of fuel, and could increase the operating and compliance costs of our pipelines, natural gas processing facilities, fractionation plants and other facilities, and the costs of certain sale and distribution activities.  These regulations could also adversely affect market demand and pricing for products handled by our midstream network, by affecting the price of, or reducing the demand for, fossil fuels or providing competitive advantages to competing fuels and energy sources.  The potential increase in the costs of our operations could include costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions, or administer and manage a greenhouse gas emissions program.  While we may be able to include some or all of such increased costs in the rates charged by our pipelines or other facilities, such recovery of costs is uncertain and may depend on events beyond our control, including the outcome of future rate proceedings before the FERC and the provisions of any final regulations.  In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to greenhouse gases, or restrictions on their use, may reduce volumes available to us for processing, transportation, marketing and storage.

Competition

NGL Pipelines & Services

Within their respective market areas, our natural gas processing facilities and related NGL marketing activities encounter competition primarily from independent processors, major integrated oil companies, and financial institutions with commodity trading platforms.  Each of our marketing competitors has varying levels of financial and personnel resources, and competition generally revolves around price, quality of customer service and proximity to customers and other market hubs.  In the markets served by our NGL pipelines, we compete with a number of intrastate and interstate pipeline companies (including those affiliated with major oil, petrochemical and natural gas companies) and barge, rail and truck fleet operations.  In general, our NGL pipelines compete with these entities in terms of transportation fees, reliability and quality of customer service.

Our primary competitors in the NGL and related product storage business are major integrated oil companies, chemical companies and other storage and pipeline companies.  We compete with other storage service providers primarily in terms of the fees charged, number of pipeline connections provided and operational dependability.  Our export terminal operations compete with those operated by major oil and gas and chemical companies and other midstream service providers primarily in terms of loading and offloading throughput capacity and access to related pipeline and storage infrastructure.

We compete with a number of NGL fractionators in Kansas, Louisiana, New Mexico and Texas.  Competition for such services is primarily based on the fractionation fee charged.  However, the ability of an NGL fractionator to receive a customer’s mixed NGLs and store and distribute the resulting purity NGL products is also an important competitive factor and is a function of having the necessary pipeline and storage infrastructure.

Crude Oil Pipelines & Services

Within their respective market areas, our crude oil pipelines, storage and marine terminals and related marketing activities compete with other crude oil pipeline companies, rail carriers, major integrated oil companies and their marketing affiliates, financial institutions with commodity trading platforms and independent crude oil gathering and marketing companies.  The crude oil business can be characterized by intense competition for supplies of crude oil at the wellhead.  Competition is based primarily on quality of customer service, competitive pricing and proximity to customers and market hubs.

Natural Gas Pipelines & Services

In our natural gas gathering business, we encounter competition in obtaining contracts to gather natural gas supplies, particularly new supplies.  Competition in natural gas gathering is based in large part on reputation, efficiency, system reliability, gathering system capacity and pricing arrangements.  Our key competitors in the natural gas gathering business include independent gas gatherers and major integrated energy companies.  Our natural gas marketing activities compete primarily with other natural gas pipeline companies and their marketing affiliates as well as standalone natural gas marketing and trading firms.  Competition in the natural gas marketing business is based primarily on competitive pricing, proximity to customers and market hubs, and quality of customer service.

Petrochemical & Refined Products Services

We compete with numerous producers of PGP, which include many of the major refiners and petrochemical companies located along the Gulf Coast, in terms of the level of toll processing fees charged and access to pipeline and storage infrastructure.  Our petrochemical marketing activities encounter competition from major integrated oil companies and various petrochemical companies that have varying levels of financial and personnel resources and competition generally revolves around product price, quality of customer service, logistics and location.

With respect to our isomerization operations, we compete primarily with facilities located in Kansas, Louisiana and New Mexico.  Competitive factors affecting this business include the level of toll processing fees charged, the quality of isobutane that can be produced and access to supporting pipeline and storage infrastructure.  We compete with other octane additive manufacturing companies primarily on the basis of price.

With respect to our TE Products Pipeline, the pipeline’s most significant competitors are third-party pipelines in the areas where it delivers products.  Competition among common carrier pipelines is based primarily on transportation fees, quality of customer service and proximity to end users. Trucks, barges and railroads competitively deliver products into some of the markets served by our TE Products Pipeline and river terminals.  The TE Products Pipeline also faces competition from rail and pipeline movements of NGLs from Canada and waterborne imports into terminals located along the upper East Coast.

Our marine transportation business competes with other inland marine transportation companies as well as providers of other modes of transportation, such as rail tank cars, tractor-trailer tank trucks and, to a limited extent, pipelines.  Competition within the marine transportation business is largely based on performance and price. Also, substantial new construction of inland marine vessels could create an oversupply and intensify competition for our marine transportation business. 

For a discussion of the general risks involving competition, see “We face competition from third parties in our midstream energy businesses” under Part I, Item 1A of this annual report.

Seasonality

Although the majority of our businesses are not materially affected by seasonality, certain aspects of our operations are impacted by seasonal changes such as tropical weather events, energy demand in connection with heating and cooling requirements and for the summer driving season.  Examples include:

Our operations along the Gulf Coast, including those at our Mont Belvieu complex, may be affected by weather events such as hurricanes and tropical storms, which generally arise during the summer and fall months.

Residential demand for natural gas typically peaks during the winter months in connection with heating needs and during the summer months for power generation for air conditioning. These seasonal trends affect throughput volumes on our natural gas pipelines and associated natural gas storage levels and marketing results.

Residential demand for propane typically peaks during the winter months in connection with heating needs in rural areas. These seasonal trends can affect throughput volumes on our TE Products Pipeline, Dixie Pipeline and Mid-America Pipeline System and associated terminals.

Due to increased demand for fuel additives used in the production of motor gasoline, our isomerization and octane enhancement businesses experience higher levels of demand during the summer driving season, which typically occurs in the spring and summer months.  Likewise, shipments of refined products and normal butane experience similar changes in demand due to their use in motor fuels.

Extreme temperatures and ice during the winter months can negatively impact our gas processing plants as they may experience freeze offs.  In addition, these conditions can negatively affect our trucking and inland marine operations on the upper Mississippi and Illinois rivers.

Workforce and Related Matters

Like many publicly-traded partnerships, we have no direct employees.  All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers.  The culture of our workforce is one of ownership, integrity, and opportunity. We recognize the hard work and contributions of individuals in our workforce who strive to further our goals.  We promote an environment where our employees feel that working for us is more than just a job, it is a tight-knit community that looks out for one another.  We respect employees’ differences and believe everyone should be treated with fairness and respect. We value diverse ideas and perspectives, and are committed to promoting a safe and inclusive workforce.

As of February 1, 2021, there were approximately 7,130 EPCO personnel who spend all or a substantial portion of their time engaged in our business.  From a diversity perspective, approximately 15% of these personnel were female and approximately 29% of these personnel were minorities.  We believe that the diversity of our workforce compares favorably to the energy and chemical industries as a whole.

The health and safety of those working on our behalf is a top priority. We promote a culture in which all personnel share the same commitment to health and safety, and recognize the importance of mitigating risks.  Acting upon our commitment to safety, we engage all levels of employees and management, our Board, our contractors, and various external entities and organizations.  We strive to achieve a goal of zero incidents and injuries.  We track our safety performance by monitoring our Total Recordable Incident Rate (“TRIR”), which is an OSHA measure that generally reflects the number of recordable incidents per 100 full-time workers during a one-year period.  Our TRIR for 2020 was 0.48, which compares favorably to the average TRIR for the midstream industry over the last six years.  We strive for year-to-year improvement in our safety performance.


Title to Properties

Our real property holdings fall into two basic categories: (i) parcels that we and our unconsolidated affiliates own in fee (e.g., we own the land upon which our Mont Belvieu complex is constructed) and (ii) parcels in which our interests and those of our unconsolidated affiliates are derived from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations.  The fee sites upon which our significant facilities are located have been owned by us or our predecessors in title for many years without any material challenge known to us relating to title to the land upon which the assets are located, and we believe that we have satisfactory title to such fee sites.  We and our affiliates have no knowledge of any material challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our rights pursuant to any material lease, easement, right-of-way, permit or license, and we believe that we have satisfactory rights pursuant to all of our material leases, easements, rights-of-way, permits and licenses.

Available Information

As a publicly traded partnership, we electronically file certain documents with the U.S. Securities and Exchange Commission (“SEC”).  We file annual reports on Form 10-K; quarterly reports on Form 10-Q; and current reports on Form 8-K (as appropriate); along with any related amendments and supplements thereto.  Occasionally, we may also file registration statements and related documents in connection with equity or debt offerings.  The SEC maintains a website at www.sec.gov that contains reports and other information regarding registrants that file electronically with the SEC.

We provide free electronic access to our periodic and current reports on our website, www.enterpriseproducts.com.  These reports are available as soon as reasonably practicable after we electronically file such materials with, or furnish such materials to, the SEC.  You may also contact our Investor Relations department at (866) 230-0745 for paper copies of these reports free of charge.  The information found on our website is not incorporated into this annual report.


ITEM 1A.  RISK FACTORS.

Summary of Key Risk Factors

An investment in our common units or debt securities involves certain risks.  If any of the following key risks were to occur, it could have a material adverse effect on our financial position, results of operations and cash flows, as well as our ability to maintain or increase distribution levels.  In any such circumstance and others described below, the trading price of our securities could decline and you could lose part or all of your investment.

Risks Relating to Our Business

The impacts from the COVID-19 pandemic and certain developments in the global oil markets have had, and may continue to have, material adverse consequences for general economic, financial and business conditions, and could materially and adversely affect our business, financial condition, results of operations and liquidity and those of our customers, suppliers and other counterparties.

Changes in demand for and prices and production of hydrocarbon products could have a material adverse effect on our financial position, results of operations and cash flows.

Our debt level may limit our future financial and operating flexibility.

We may not be able to fully execute our growth strategy if we encounter illiquid capital markets or increased competition for investment opportunities.

Our construction of new assets is subject to operational, regulatory, environmental, political, legal and economic risks, which may result in delays, increased costs or decreased cash flows.

Several of our assets have been in service for many years and require significant expenditures to maintain them. As a result, our maintenance or repair costs may increase in the future.

The inability to continue to access lands owned by third parties and governmental bodies could adversely affect our operations and have a material adverse effect on our financial position, results of operations and cash flows.

Our growth strategy may adversely affect our results of operations if we do not successfully integrate and manage the businesses that we acquire or if we substantially increase our indebtedness and contingent liabilities to make acquisitions.

A natural disaster, catastrophe, terrorist attack or other event could result in severe personal injury, property damage and environmental damage, which could curtail our operations and have a material adverse effect on our financial position, results of operations and cash flows.

A cyber-attack on our information technology (“IT”) systems could affect our business and assets, and have a material adverse effect on our financial position, results of operations and cash flows.

Our business requires extensive credit risk management that may not be adequate to protect against customer nonpayment.

The use of derivative financial instruments could result in material financial losses by us.

Our risk management policies cannot eliminate all commodity price risks.  In addition, any noncompliance with our risk management policies could result in significant financial losses.

Federal, state or local regulatory measures (including those related to climate, environmental, health, safety and pipeline integrity matters) could have a material adverse effect on our financial position, results of operations and cash flows.

The rates of our regulated assets are subject to review and possible adjustment by federal and state regulators, which could adversely affect our revenues.

Our standalone operating cash flow is derived primarily from cash distributions we receive from EPO.

Risks Relating to Our Partnership Structure

We may not have sufficient operating cash flows to pay cash distributions at the current level following establishment of cash reserves and payments of fees and expenses.

Our general partner and its affiliates have limited fiduciary responsibilities to, and conflicts of interest with respect to, our partnership, which may permit it to favor its own interests to your detriment.

Unitholders have limited voting rights and are not entitled to elect our general partner or its directors.  In addition, even if unitholders are dissatisfied, they cannot easily remove our general partner.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Our general partner has a limited call right that may require common unitholders to sell their common units at an undesirable time or price.

Our common unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.

Unitholders may have a liability to repay distributions.

Our general partner’s interest in us and the control of our general partner may be transferred to a third party without unitholder consent.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, which could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

A successful IRS contest of the federal income tax positions we take and certain valuation methodologies we adopt in determining a unitholder’s allocation of income, gain, loss and deductions, may adversely impact the market for our common units and the cost of any IRS contest will reduce our cash available for distribution to unitholders.

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

Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Tax gains or losses on the disposition of our common units could be more or less than expected.

We treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased.  The IRS may challenge this treatment, which could adversely affect the value of our common units.

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

Discussion of Key Risk Factors

The following discussion provides additional information regarding each of our key risk factors by category:  Risks Relating to Our Business, Risks Relating to Our Partnership Structure and Tax Risks to Common Unitholders.

Risks Relating to Our Business

The impacts from the COVID-19 pandemic and certain developments in the global oil markets have had, and may continue to have, material adverse consequences for general economic, financial and business conditions, and could materially and adversely affect our business, financial condition, results of operations and liquidity and those of our customers, suppliers and other counterparties.

Changes in the supply of and demand for hydrocarbon products impacts both the volume of products that we sell and the level of services that we provide to customers, which in turn has a direct impact on our financial position, results of operations and cash flows. The continued global effects of the COVID-19 pandemic, which began in the first quarter of 2020 and include the consequences of international COVID-19 containment measures (e.g., quarantines, travel restrictions, temporary business closures and similar protective actions), reduced near-term demand for hydrocarbon products by record amounts and created a significant oversupply situation.  Also, in the early stages of the pandemic, disputes between members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (collectively, the “OPEC+” group)  over crude oil production levels led to unprecedented volatility in global energy markets and a historic collapse in crude oil prices in April 2020. Although the OPEC+ group and other producers subsequently reached agreements to gradually reduce the oversupply of crude oil through production cuts, the downturn in the energy industry caused by lower demand and prices negatively impacted us, the producers we work with and our other customers to varying degrees.

Across the globe, many countries have eased their COVID-19 containment measures and central banks and governments have instituted fiscal measures in an effort to stimulate economic activity.  As a result, hydrocarbon demand has started to recover; however, a continuation of this trend remains dependent on successful containment of the disease, the efficacy and distribution of approved vaccines on COVID-19 and its emerging variants, and proven therapeutics. Any prolonged period of economic slowdown or recession, or a protracted period of depressed demand or prices for crude oil or other products that we handle, could have significant adverse consequences on our financial condition and the financial condition of our customers, suppliers and other counterparties, and could diminish our liquidity and negatively affect the volumes of products handled by our pipelines and other facilities.

The ultimate impact of the pandemic on our financial condition, results of operations and cash flows depends largely on developments outside our control, including the duration of the outbreak, the related impact on overall economic activity, potential long-term impacts on demand for crude oil and other products and the willingness of the OPEC+ group to continue to reduce the oversupply of crude, all of which cannot be predicted with certainty.

Changes in demand for and prices and production of hydrocarbon products could have a material adverse effect on our financial position, results of operations and cash flows.

We operate predominantly in the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs, crude oil, petrochemical and refined products.  As such, changes in the prices of hydrocarbon products and in the relative price levels among hydrocarbon products could have a material adverse effect on our financial position, results of operations and cash flows.  Changes in prices may impact demand for hydrocarbon products, which in turn may impact production, demand and the volumes of products for which we provide services.  In addition, decreases in demand may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, adverse weather conditions, public health emergencies, and government regulations affecting prices and production levels.  We may also incur credit and price risk to the extent customers do not fulfill their obligations to us in connection with our marketing of natural gas, NGLs, propylene, refined products and/or crude oil and long-term take-or-pay agreements.

Crude oil and natural gas prices have been volatile in recent years.  For example, crude oil prices (based on WTI as measured by the NYMEX) ranged from a high of $76.41 per barrel to a low of a negative $37.63 per barrel in the three year period ended December 31, 2020.  For the period January 1, 2021 through January 29, 2021, WTI prices ranged from a high of $53.57 per barrel to a low of $47.62 per barrel.  Natural gas prices (based on Henry Hub as measured by the NYMEX) ranged from a high of $4.84 per MMBtu to a low of $1.48 per MMBtu over the three-year period ended December 31, 2020.   Henry Hub natural gas prices ranged from a high of $2.76 per MMBtu to a low of $2.45 per MMBtu from January 1, 2021 through January 29, 2021.

Generally, prices of hydrocarbon products are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of other uncontrollable factors, such as: (i) the level of domestic production and consumer product demand; (ii) the availability of imported crude oil and natural gas and actions taken by foreign crude oil and natural gas producing nations; (iii) the availability of transportation systems with adequate capacity; (iv) the availability of competitive fuels; (v) fluctuating and seasonal demand for crude oil, natural gas, NGLs and other hydrocarbon products, including demand for NGL products by the petrochemical, refining and heating industries; (vi) the impact of conservation efforts; (vii) governmental regulation and taxation of production; (viii) reduced demand for hydrocarbons attributable to public health emergencies and (ix) prevailing economic conditions.

We are exposed to natural gas and NGL commodity price risks under certain of our natural gas processing and gathering and NGL fractionation contracts that provide for fees to be calculated based on a regional natural gas or NGL price index, or to be paid in-kind by taking title to natural gas or NGLs.  A decrease in natural gas and NGL prices can result in lower margins from these contracts, which could have a material adverse effect on our financial position, results of operations and cash flows.  Volatility in the prices of natural gas and NGLs can lead to ethane rejection, which results in a reduction in volumes available for transportation, fractionation, storage and marketing.  Volatility in these commodity prices may also have an impact on many of our customers, which in turn could have a negative impact on their ability to fulfill their obligations to us.

The crude oil, natural gas and NGLs currently transported, gathered or processed at our facilities originate primarily from existing domestic resource basins, which naturally deplete over time.  To offset this natural decline, our facilities need access to production from newly discovered properties.  Many economic and business factors beyond our control can adversely affect the decision by producers to explore for and develop new reserves.  These factors could include relatively low crude oil and natural gas prices, cost and availability of equipment and labor, regulatory changes, capital budget limitations, the lack of available capital or the probability of success in finding hydrocarbons.  A decrease in exploration and development activities in the regions where our facilities and other energy logistic assets are located could result in a decrease in volumes handled by our assets, which could have a material adverse effect on our financial position, results of operations and cash flows.  

For a discussion regarding our current outlook on industry fundamentals for 2021, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Current Outlook” included under Part II, Item 7 of this annual report.

We face competition from third parties in our midstream energy businesses.

Even if crude oil and natural gas reserves exist in the areas served by our assets, we may not be chosen by producers in these areas to gather, transport, process, fractionate, store or otherwise handle the hydrocarbons extracted.  We compete with other companies, including producers of crude oil and natural gas, for any such production on the basis of many factors, including but not limited to geographic proximity to the production, costs of connection, available capacity, rates and access to markets.

Our NGL, refined products and marine transportation businesses may compete with other pipelines and marine transportation companies in the areas they serve.  We also compete with railroads and third party trucking operations in certain of the areas we serve.  Competitive pressures may adversely affect our tariff rates or volumes shipped.  Also, substantial new construction of inland marine vessels could create an oversupply and intensify competition for our marine transportation business.  

The crude oil gathering and marketing business can be characterized by intense competition for supplies of crude oil at the wellhead.  A decline in domestic crude oil production could intensify this competition among gatherers and marketers.  Our crude oil transportation business competes with common carriers and proprietary pipelines owned and operated by major oil companies, large independent pipeline companies, financial institutions with commodity trading platforms and other companies in the areas where such pipeline systems deliver crude oil.

In our natural gas gathering business, we encounter competition in obtaining contracts to gather natural gas supplies, particularly new supplies.  Competition in natural gas gathering is based in large part on reputation, efficiency, system reliability, gathering system capacity and pricing arrangements.  Our key competitors in the natural gas gathering business include independent gas gatherers and major integrated energy companies.  Alternate gathering facilities are available to producers we serve, and those producers may also elect to construct proprietary gas gathering systems.  

Both we and our competitors make significant investments in new energy infrastructure to meet anticipated market demand.  The success of our projects depends on utilization of our assets.  Demand for our new projects may change during construction, and our competitors may make additional investments or redeploy assets that compete with our projects and existing assets.  If either our investments or construction by competitors in the markets we serve result in excess capacity, our facilities and assets could be underutilized, which could cause us to reduce rates for our services.  A reduction in rates may result in lower returns on our investments and, as a result, lower the value of our assets.

A significant increase in competition in the midstream energy industry, including construction of new assets or redeployment of existing assets by our competitors, could have a material adverse effect on our financial position, results of operations and cash flows.


Our debt level may limit our future financial and operating flexibility.

As of December 31, 2020, we had $27.5 billion in principal amount of consolidated senior long-term debt outstanding and $2.65 billion in principal amount of junior subordinated debt outstanding.  The amount of our future debt could have significant effects on our operations, including, among other things:

a substantial portion of our cash flow could be dedicated to the payment of principal and interest on our future debt and may not be available for other purposes, including the payment of distributions on our common units and for capital investments;

credit rating agencies may take a negative view of the energy sector or our consolidated debt level;

covenants contained in our existing and future credit and debt agreements will require us to continue to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

our ability to obtain additional financing, if necessary, for working capital, capital investments, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

we may be at a competitive disadvantage relative to similar companies that have less debt; and

we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level.

Our public debt indentures currently do not limit the amount of future indebtedness that we can incur, assume or guarantee.  Although our credit agreements restrict our ability to incur additional debt above certain levels, any debt we may incur in compliance with these restrictions may still be substantial.  For information regarding our long-term debt, see Note 7 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Our credit agreements and each of the indentures related to our public debt instruments include traditional financial covenants and other restrictions.  For example, we are prohibited from making distributions to our partners if such distributions would cause an event of default or otherwise violate a covenant under our credit agreements.  A breach of any of these restrictions by us could permit our lenders or noteholders, as applicable, to declare all amounts outstanding under these debt agreements to be immediately due and payable and, in the case of our credit agreements, terminate all commitments to extend further credit.

Our ability to access capital markets to raise capital on favorable terms could be affected by our debt level, when such debt matures, and by prevailing market conditions.  Moreover, if the rating agencies were to downgrade the energy sector or our credit ratings, we could experience an increase in our borrowing costs, difficulty assessing capital markets and/or a reduction in the market price of our securities.  Such a development could adversely affect our ability to obtain financing for working capital, capital investments or acquisitions, or to refinance existing indebtedness.  If we are unable to access the capital markets on favorable terms in the future, we might be forced to seek extensions for some of our short-term debt obligations or to refinance some of our debt obligations through bank credit, as opposed to long-term public debt securities or equity securities.  The price and terms upon which we might receive such extensions or additional bank credit, if at all, could be more onerous than those contained in existing debt agreements.  Any such arrangements could, in turn, increase the risk that our leverage may adversely affect our future financial and operating flexibility and thereby impact our ability to pay cash distributions at expected levels.


We may not be able to fully execute our growth strategy if we encounter illiquid capital markets or increased competition for investment opportunities.

Our growth strategy contemplates the development and acquisition of a wide range of midstream and other energy infrastructure assets while maintaining a strong balance sheet.  This strategy includes constructing and acquiring additional assets and businesses that enhance our ability to compete effectively and to diversify our asset portfolio, thereby providing us with more stable cash flows.  We consider and pursue potential joint ventures, standalone projects and other transactions that we believe may present opportunities to expand our business, increase our market position and realize operational synergies.

We will require substantial new capital to finance the future development and acquisition of assets and businesses.  For example, our capital investments for 2020 reflected $3.32 billion of cash payments for capital projects and other investments.  Based on information currently available, we expect our total capital investments for 2021, net of contributions from joint venture partners, to approximate $2.1 billion, which includes growth capital projects of $1.6 billion and sustaining capital expenditures of $440 million. Any limitations on our access to capital may impair our ability to execute this growth strategy.  If our cost of debt or equity capital becomes too expensive, our ability to develop or acquire accretive assets will be limited.  We also may not be able to raise the necessary funds on satisfactory terms, if at all.  

Any sustained tightening of the credit markets may have a material adverse effect on us by, among other things, decreasing our ability to finance growth capital projects or business acquisitions on favorable terms and by the imposition of increasingly restrictive borrowing covenants.  In addition, the distribution yields of any new equity we may issue may be higher than historical levels, making additional equity issuances more expensive. Accordingly, increased costs of equity and debt will make returns on capital expenditures with proceeds from such capital less accretive on a per unit basis.

We also may compete with third parties in the acquisition of energy infrastructure assets that complement our existing asset base.  Increased competition for a limited pool of assets could result in our losing to other bidders more often than in the past or acquiring assets at less attractive prices.  Either occurrence could limit our ability to fully execute our growth strategy.  Our inability to execute our growth strategy may materially adversely affect our ability to maintain or pay higher cash distributions in the future.

Our actual construction, development and acquisition costs could materially exceed forecasted amounts.

We have announced and are engaged in multiple significant construction projects involving existing and new assets for which we have expended or will expend significant capital.  These projects entail significant logistical, technological and staffing challenges.  We may not be able to complete our projects at the costs we estimated at the time of each project’s initiation or that we currently estimate.  Similarly, force majeure events such as hurricanes along the U.S. Gulf Coast may cause delays, shortages of skilled labor and additional expenses for these construction and development projects. 

If capital investments materially exceed expected amounts, then our future cash flows could be reduced, which, in turn, could reduce the amount of cash we expect to have available for distribution.  In addition, a material increase in project costs could result in decreased overall profitability of the newly constructed asset once it is placed into service.

Our construction of new assets is subject to operational, regulatory, environmental, political, legal and economic risks, which may result in delays, increased costs or decreased cash flows.

One of the ways we intend to grow our business is through the construction of new midstream energy infrastructure assets.  The construction of new assets involves numerous operational, regulatory, environmental, political, legal and economic risks beyond our control and may require the expenditure of significant amounts of capital.  These potential risks include, among other things, the following:
 
we may be unable to complete construction projects on schedule or at the budgeted cost due to the unavailability of required construction personnel or materials, accidents, weather conditions or an inability to obtain necessary permits;

we will not receive any material increase in operating cash flows until the project is completed, even though we may have expended considerable funds during the construction phase, which may be prolonged;

we may construct facilities to capture anticipated future production growth in a region in which such growth does not materialize;

since we are not engaged in the exploration for and development of crude oil or natural gas reserves, we may not have access to third party estimates of reserves in an area prior to our constructing facilities in the area.  As a result, we may construct facilities in an area where the reserves are materially lower than we anticipate;

in those situations where we do rely on third party reserve estimates in making a decision to construct assets, these estimates may prove inaccurate;

the completion or success of our construction project may depend on the completion of a third party construction project (e.g., a downstream crude oil refinery expansion or construction of a new petrochemical facility) that we do not control and that may be subject to numerous of its own potential risks, delays and complexities; and

we may be unable to obtain rights-of-way to construct additional pipelines or the cost to do so may be uneconomical.

A materialization of any of these risks could adversely affect our ability to achieve growth in the level of our cash flows or realize benefits from expansion opportunities or construction projects, which could impact the level of cash distributions we pay to partners.

Several of our assets have been in service for many years and require significant expenditures to maintain them. As a result, our maintenance or repair costs may increase in the future.

Our pipelines, terminals and storage assets are generally long-lived assets, and many of them have been in service for many years. The age and condition of our assets could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our results of operations, financial position or cash flows, as well as our ability to make cash distributions to our unitholders.

The inability to continue to access lands owned by third parties could adversely affect our operations and have a material adverse effect on our financial position, results of operations and cash flows.

Our ability to operate our pipeline systems on certain lands owned by third parties will depend on our maintaining existing rights-of-way and obtaining new rights-of-way on those lands. We are parties to rights-of-way agreements, permits and licenses authorizing land use with numerous parties, including private land owners, governmental entities, Native American tribes, rail carriers, public utilities and others. Our ability to secure extensions of existing agreements, permits and licenses is essential to our continuing business operations, and securing additional rights-of-way will be critical to our ability to pursue expansion projects. We cannot provide any assurance that we will be able to maintain access to all existing rights-of-way upon the expiration of the current grants, that all of the rights-of-way will be obtained in a timely fashion or that we will acquire new rights-of-way as needed.

In particular, various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, Bureau of Land Management, and the Office of Natural Resources Revenue, along with each Native American tribe, promulgate and enforce regulations pertaining to natural gas and oil operations on Native American tribal lands. These regulations and approval requirements relate to such matters as drilling and production requirements and environmental standards. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to operators and contractors conducting operations on Native American tribal lands. One or more of these factors may increase our cost of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct our operations on such lands.

Furthermore, whether we have the power of eminent domain for our pipelines varies from state to state, depending upon the type of pipeline, the laws of the particular state and the ownership of the land to which we seek access. When we exercise eminent domain rights or negotiate private agreements, we must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. The inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipelines are located.

We may face opposition to the operation of our pipelines and facilities from various groups.

We may face opposition to the operation of our pipelines and facilities from environmental groups, landowners, tribal groups, local groups and other advocates. Such opposition could take many forms, including organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt or delay the operation of our assets and business. For example, repairing our pipelines often involves securing consent from individual landowners to access their property; one or more landowners may resist our efforts to make needed repairs, which could lead to an interruption in the operation of the affected pipeline or facility for a period of time that is significantly longer than would have otherwise been the case. In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property or the environment or lead to extended interruptions of our operations. Any such event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions to our partners and, accordingly, adversely affect our financial condition and the market price of our securities.

Our growth strategy may adversely affect our results of operations if we do not successfully integrate and manage the businesses that we acquire or if we substantially increase our indebtedness and contingent liabilities to make acquisitions.

Our growth strategy includes making accretive acquisitions.  From time to time, we evaluate and acquire additional assets and businesses that we believe complement our existing operations.  We may be unable to successfully integrate and manage the businesses we acquire in the future.  We may incur substantial expenses or encounter delays or other problems in connection with our growth strategy that could have a material adverse effect on our financial position, results of operations and cash flows.  Moreover, acquisitions and business expansions involve numerous risks, such as:

difficulties in the assimilation of the operations, technologies, services and products of the acquired assets or businesses;

establishing the internal controls and procedures we are required to maintain under the Sarbanes-Oxley Act of 2002;

managing relationships with new joint venture partners with whom we have not previously partnered;

experiencing unforeseen operational interruptions or the loss of key employees, customers or suppliers;

inefficiencies and complexities that can arise because of unfamiliarity with new assets and the businesses associated with them, including with their markets; and

diversion of the attention of management and other personnel from day-to-day business to the development or acquisition of new businesses and other business opportunities.

If consummated, any acquisition or investment would also likely result in the incurrence of indebtedness and contingent liabilities and an increase in interest expense and depreciation, amortization and accretion expenses.  As a result, our capitalization and results of operations may change significantly following a material acquisition.  A substantial increase in our indebtedness and contingent liabilities could have a material adverse effect on our financial position, results of operations and cash flows.  In addition, any anticipated benefits of a material acquisition, such as expected cost savings or other synergies, may not be fully realized, if at all.

Acquisitions that appear to increase our operating cash flows may nevertheless reduce our operating cash flows on a per unit basis.

Even if we make acquisitions that we believe will increase our operating cash flows, these acquisitions may ultimately result in a reduction of operating cash flow on a per unit basis, such as if our assumptions regarding a newly acquired asset or business did not materialize or unforeseen risks occurred.  As a result, an acquisition initially deemed accretive based on information available at the time could turn out not to be.  Examples of risks that could cause an acquisition to ultimately not be accretive include our inability to achieve anticipated operating and financial projections or to integrate an acquired business successfully, the assumption of unknown liabilities for which we become liable, and the loss of key employees or key customers.  If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will in making such decisions.  As a result of the risks noted above, we may not realize the full benefits we expect from a material acquisition, which could have a material adverse effect on our financial position, results of operations and cash flows.

A natural disaster, catastrophe, terrorist attack or other event could result in severe personal injury, property damage and environmental damage, which could curtail our operations and have a material adverse effect on our financial position, results of operations and cash flows.

Some of our operations involve risks of personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow.  For example, natural gas facilities operate at high pressures, sometimes in excess of 1,100 pounds per square inch.  In addition, our marine transportation business is subject to additional risks, including the possibility of marine accidents and spill events.  From time to time, our octane enhancement facility may produce MTBE for export, which could expose us to additional risks from spill events.  Virtually all of our operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes.  The location of our assets and our customers’ assets in the U.S. Gulf Coast region makes them particularly vulnerable to hurricane or tropical storm risk.  In addition, terrorists may target our physical facilities and computer hackers may attack our electronic systems.

If one or more facilities or electronic systems that we own or that deliver products to us or that supply our facilities are damaged by severe weather or any other disaster, accident, catastrophe, terrorist attack or other event, our operations could be significantly interrupted.  These interruptions could involve significant damage to people, property or the environment, and repairs could take from a week or less for a minor incident to six months or more for a major interruption.  Additionally, some of the storage contracts that we are a party to obligate us to indemnify our customers for any damage or injury occurring during the period in which the customers’ product is in our possession.  Any event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions and, accordingly, adversely affect the market price of our common units.

We believe that EPCO maintains adequate insurance coverage on our behalf; however, insurance will not cover all types of interruptions that might occur, will not cover amounts up to applicable deductibles and will not cover all risks associated with the nature and extent of our operations.  As a result of market conditions, premiums and deductibles for certain types of insurance (e.g., general liability policies) can increase substantially, and in some instances, such insurance may become unavailable or available only for reduced amounts of coverage.

In the future, circumstances may arise whereby EPCO may not be able to renew existing insurance policies on our behalf or procure other desirable insurance on commercially reasonable terms, if at all.  If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations and cash flows.  In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.


A cyber-attack on our information technology (“IT”) systems could affect our business and assets, and have a material adverse effect on our financial position, results of operations and cash flows.

We rely on our IT systems to conduct our business, as well as systems of third-party vendors.  These systems include information used to operate our assets, as well as cloud-based services.  These systems are subject to possible security breaches and cyber-attacks.

Cyber-attacks are becoming more sophisticated, and U.S. government warnings have indicated that infrastructure assets, including pipelines, may be specifically targeted by certain groups.  These attacks include, without limitation, malicious software, ransomware, attempts to gain unauthorized access to data, and other electronic security breaches.  These attacks may be perpetrated by state-sponsored groups, “hacktivists”, criminal organizations or private individuals (including employee malfeasance).  These cybersecurity risks include cyber-attacks on both us and third parties who provide material services to us.  In addition to disrupting operations, cyber security breaches could also affect our ability to operate or control our facilities, render data or systems unusable, or result in the theft of sensitive, confidential or customer information.  These events could also damage our reputation, and result in losses from remedial actions, loss of business or potential liability to third parties.

We do not carry insurance specifically for cybersecurity events; however, certain of our insurance policies may allow for coverage of associated damages resulting from such events.  If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations and cash flows.  In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

Failure of our critical IT systems could have an adverse impact on our business, financial condition, results of operations and cash flows, as well as our ability to pay cash distributions.

We rely on IT systems to operate our assets and manage our businesses.  We depend on these systems to process, transmit and store electronic information, including financial records and personally identifiable information such as employee, customer, investor and payroll data, and to manage or support a variety of business processes, including our supply chain, pipeline and storage operations, gathering and processing operations, financial transactions, banking and numerous other processes and transactions.  Some of these IT systems are proprietary and custom designed for our business, while others are based upon or reside on commercially available technologies.

IT policies and procedures protect our critical systems. Our cybersecurity approach is strategically layered with people, technology and processes such as disaster recovery, incident response and business continuity. However, the risk of critical systems failing due to an unforeseen major disruption is not eliminated.

Failures of these IT systems, whether due to power failures, a cybersecurity event or other reason, could result in a breach of critical operational or financial controls and lead to a disruption of our operations, commercial activities or financial processes. Such failures could adversely affect our results of operations, financial position or cash flow, as well as our ability to pay cash distributions in a timely manner.  State and federal cybersecurity legislation could also impose new requirements on us, which could increase our cost of doing business.

Our business requires extensive credit risk management that may not be adequate to protect against customer nonpayment.

We may incur credit risk to the extent customers do not fulfill their obligations to us in connection with our marketing of natural gas, NGLs, crude oil, petrochemicals and refined products and long-term contracts with minimum volume commitments or fixed demand charges.  Risks of nonpayment and nonperformance by customers are a major consideration in our businesses, and our credit procedures and policies may not be adequate to sufficiently eliminate customer credit risk.  Further, adverse economic conditions in our industry may increase the risk of nonpayment and nonperformance by customers, particularly customers that have sub-investment grade credit ratings or small-scale companies.  We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments, net out agreements and guarantees.  However, these procedures and policies do not fully eliminate customer credit risk.

The primary markets for our services are the Gulf Coast, Southwest, Rocky Mountains, Northeast and Midwest regions of the U.S.  We have a concentration of trade receivable balances due from domestic and international major integrated oil and gas companies, independent oil and gas companies and other pipelines and wholesalers operating in these markets.  These concentrations of market areas may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors.

See Note 2 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for information regarding our allowance for doubtful accounts.

The use of derivative financial instruments could result in material financial losses by us.

Historically, we have sought to limit a portion of the adverse effects resulting from changes in energy commodity prices and interest rates by using derivative instruments.  Derivative instruments typically include futures, forward contracts, swaps, options and other instruments with similar characteristics.  Substantially all of our derivatives are used for non-trading activities.

To the extent that we hedge our commodity price and interest rate exposures, we will forego the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor.  In addition, hedging activities can result in losses that might be material to our financial condition, results of operations and cash flows.  Such losses could occur under various circumstances, including those situations where a counterparty does not perform its obligations under a hedge arrangement, the hedge is not effective in mitigating the underlying risk, or our risk management policies and procedures are not followed.  Adverse economic conditions (e.g., a significant decline in energy commodity prices that negatively impact the cash flows of oil and gas producers) increase the risk of nonpayment or performance by our hedging counterparties.  

See Part II, Item 7A of this annual report and Note 14 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for a discussion of our derivative instruments and related hedging activities.

Our risk management policies cannot eliminate all commodity price risks.  In addition, any noncompliance with our risk management policies could result in significant financial losses.

When engaged in marketing activities, it is our policy to maintain physical commodity positions that are substantially balanced with respect to price risks between purchases, on the one hand, and sales or future delivery obligations, on the other hand.  Through these transactions, we seek to earn a margin for the commodity purchased by selling the commodity for physical delivery to third party users, such as producers, wholesalers, local distributors, independent refiners, marketing companies or major integrated oil and gas companies.  These policies and practices cannot, however, eliminate all price risks.  For example, any event that disrupts our anticipated physical supply could expose us to risk of loss resulting from price changes if we are required to obtain alternative supplies to cover our sales transactions.  We are also exposed to basis risks when a commodity is purchased against one pricing index and sold against a different index.  Moreover, we are exposed to some risks that are not hedged, including price risks on product we own, such as pipeline linefill, which must be maintained in order to facilitate transportation of the commodity in our pipelines.  In addition, our marketing operations involve the risk of non-compliance with our risk management policies.  We cannot assure you 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 were to incur a material loss related to commodity price risks, including non-compliance with our risk management policies, it could have a material adverse effect on our financial position, results of operations and cash flows.


Our variable-rate debt, including those fixed-rate debt obligations that may be converted to variable-rate through the use of interest rate swaps, make us vulnerable to increases in interest rates, which could have a material adverse effect on our financial position, results of operation and cash flows.

At December 31, 2020, we had $29.9 billion in principal amount of consolidated fixed-rate debt outstanding, including current maturities thereof.  Due to the short term nature of commercial paper notes, we view the interest rates charged in connection with these instruments as variable.

The Board of Governors of the Federal Reserve System raised benchmark interest rates four times during 2018, and again in early 2019 before lowering rates three times by the end of 2019, and lowered rates twice during 2020.  Should interest rates increase significantly, the amount of cash required to service our debt (including any future refinancing of our fixed-rate debt instruments) would increase.  Additionally, from time to time, we may enter into interest rate swap arrangements, which could increase our exposure to variable interest rates.  As a result, significant increases in interest rates could have a material adverse effect on our financial position, results of operations and cash flows.

An increase in interest rates may also cause a corresponding decline in demand for equity securities in general, and in particular, for yield-based equity securities such as our common units.  A reduction in demand for our common units may cause their trading price to decline.

Amounts borrowed under our 364-Day and Multi-Year Revolving Credit Agreements may bear interest, at our election, based ona London Interbank Offered Rate (“LIBOR”).  In addition, our junior subordinated notes and interest rate swap agreements may also reflect LIBOR-based terms. In July 2017, the Financial Conduct Authority in the United Kingdom, or U.K., announced a desire to phase out LIBOR as a benchmark by the end of June 2023. Financial industry working groups are developing replacement rates and methodologies to transition existing agreements that depend on LIBOR as a reference rate.  We currently do not expect the transition from LIBOR to have a material impact on us. 

Our pipeline integrity program as well as compliance with pipeline safety laws and regulations may impose significant costs and liabilities on us.

If we were to incur material costs in connection with our pipeline integrity program or pipeline safety laws and regulations, those costs could have a material adverse effect on our financial condition, results of operations and cash flows.

The DOT requires pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in HCAs.  The majority of the costs to comply with this integrity management rule are associated with pipeline integrity testing and any repairs found to be necessary as a result of such testing.  Changes such as advances in pipeline inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipe determined to be located in HCAs can have a significant impact on the costs to perform integrity testing and repairs.  We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines.  The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

In total, our pipeline integrity costs for the years ended December 31, 2020, 2019 and 2018 were $82.7 million, $110.6 million and $122.0 million, respectively.  Of these annual totals, we charged $52.9 million, $56.4 million and $71.8 million to operating costs and expenses during the years ended December 31, 2020, 2019 and 2018, respectively.  The remaining annual pipeline integrity costs were capitalized and treated as sustaining capital projects.  We expect the cost of our pipeline integrity program, regardless of whether such costs are capitalized or expensed, to approximate $119 million for 2021.

For additional information regarding the pipeline safety regulations, the Pipeline Safety Act and the SAFE PIPES Act, see “Regulatory Matters – Environmental, Safety and Conservation – Pipeline Safety” included under Part I, Items 1 and 2 of this annual report.

Environmental, health and safety costs and liabilities, and changing environmental, health and safety regulation, could have a material adverse effect on our financial position, results of operations and cash flows.

Our operations are subject to various environmental, health and safety requirements and potential liabilities under extensive federal, state and local laws and regulations.  Further, we cannot ensure that existing environmental, health and safety regulations will not be revised or that new regulations will not be adopted or become applicable to us.  Governmental authorities have the power to enforce compliance with applicable regulations and permits and to subject violators to civil and criminal penalties, including substantial fines, injunctions or both.  Certain environmental laws, including CERCLA and analogous state laws and regulations, may impose strict, joint and several liability for costs required to clean-up and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released.  Moreover, third parties, including neighboring landowners, may also have the right to pursue legal actions to enforce compliance or to recover for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.  Failure to comply with these requirements may expose us to fines, penalties and/or interruptions in our operations that could have a material adverse effect on our financial position, results of operations and cash flows.

In addition, future environmental, health and safety law developments, such as stricter laws, regulations, permits or enforcement policies, could significantly increase some costs of our operations. Areas of potential future environmental, health and safety law developments include the following items.

Climate Change.  Responding to reports regarding climate change matters, the U.S. Congress from time to time has considered legislation to reduce emissions of greenhouse gases or implement carbon taxes.  In addition, certain states, including states in which our facilities or operations are located, have, individually or in regional cooperation, taken or proposed measures to reduce emissions of greenhouse gases.  Various policies and approaches, including establishing a cap on emissions, requiring efficiency measures, or providing incentives for pollution reduction, use of renewable energy sources, or use of replacement fuels with lower carbon content are under discussion and have and may continue to result in additional actions involving greenhouse gases.

The adoption and implementation of any federal, state or local regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur significant costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the crude oil, natural gas or other hydrocarbon products that we transport, store or otherwise handle in connection with our midstream services.  The potential increase in our operating costs could include costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize greenhouse gas emissions (whether emitted by our operations or associated with fuel that we supply into the markets), pay taxes related to greenhouse gas emissions, and administer and manage a greenhouse gas emissions program.  We may not be able to recover such increased costs through customer prices or rates, which may limit our access to, or otherwise cause us to reduce our participation in, certain market activities.  In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to greenhouse gases, or restrictions on their use, may reduce volumes available to us for processing, transportation, marketing and storage.  These developments could have a material adverse effect on our financial position, results of operations and cash flows.

In addition, numerous countries around the world have adopted or are considering adopting laws or regulations to reduce greenhouse gas emissions.  It is not possible to know how quickly renewable energy technologies may advance, but if significant additional legislation and regulation were enacted, the increased use of renewable energy could ultimately reduce future demand for hydrocarbons.  These developments could have a material adverse effect on our financial position, results of operations and cash flows.



Hydraulic Fracturing.  Substantially all of our producer customers employ hydraulic fracturing techniques (commonly referred to as “fracking”) to stimulate natural gas and crude oil production from unconventional geological formations (including shale formations), which entails the injection of pressurized fracturing fluids (consisting of water, sand and certain chemicals) into a well bore.  The U.S. federal government, and some states and localities, have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, or that would impose higher taxes, fees or royalties on such activities.  Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to crude oil and natural gas drilling activities using hydraulic fracturing techniques, including increased litigation.  Additional legislation or regulation could also lead to operational delays and/or increased operating costs in the production of crude oil and natural gas (including natural gas produced from shale plays like the Permian, Eagle Ford, Haynesville, Barnett, Marcellus and Utica Shales) incurred by our customers or could make it more difficult to perform hydraulic fracturing.  If these legislative and regulatory initiatives cause a material decrease in the drilling of new wells and related servicing activities, it may affect the volume of hydrocarbon products available to our midstream businesses and have a material adverse effect on our financial position, results of operations and cash flows.

See “Regulatory Matters” under Part I, Items 1 and 2 of this annual report for more information and specific disclosures relating to environmental, health and safety laws and regulations, and costs and liabilities.

Federal, state or local regulatory measures could have a material adverse effect on our financial position, results of operations and cash flows.

The FERC regulates our interstate liquids pipelines under the ICA.  State regulatory agencies regulate our intrastate natural gas and NGL pipelines, intrastate storage facilities and gathering lines.

Our intrastate NGL and natural gas pipelines are subject to regulation in many states, including Colorado, Kansas, Louisiana, New Mexico, Texas and Wyoming.  To the extent our intrastate natural gas pipelines engage in interstate transportation, they are also subject to regulation by the FERC pursuant to Section 311 of the NGPA.  We also have natural gas underground storage facilities in Louisiana and Texas.  Although state regulation is typically less comprehensive in scope than regulation by the FERC, our services are typically required to be provided on a nondiscriminatory basis and are also subject to challenge by protest and complaint.

Although our natural gas gathering systems are generally exempt from FERC regulation under the NGA, our natural gas gathering operations could be adversely affected should they become subject to federal regulation of rates and services, or, if the states in which we operate adopt policies imposing more onerous regulation on gas gathering operations.  Additional rules and legislation pertaining to these matters are considered and adopted from time to time at both state and federal levels.  We cannot predict what effect, if any, such regulatory changes and legislation might have on our operations, but we could be required to incur additional capital expenditures.

For a general overview of federal, state and local regulation applicable to our assets, see “Regulatory Matters” included within Part I, Items 1 and 2 of this annual report.  This regulatory oversight can affect certain aspects of our business and the market for our products and could have a material adverse effect on our financial position, results of operations and cash flows.



The rates of our regulated assets are subject to review and possible adjustment by federal and state regulators, which could adversely affect our revenues.

The FERC, pursuant to the ICA (as amended), the Energy Policy Act and rules and orders promulgated thereunder, regulates the tariff rates and terms and conditions of service for our interstate common carrier liquids pipeline operations.  To be lawful under the ICA, interstate tariff rates, terms and conditions of service must be just and reasonable and not unduly discriminatory, and must be on file with the FERC.  In addition, pipelines may not confer any undue preference upon any shipper.  Shippers may protest (and the FERC may investigate) the lawfulness of new or changed tariff rates.  The FERC can suspend those tariff rates for up to seven months.  It can also require refunds of amounts collected pursuant to rates that are ultimately found to be unlawful and prescribe new rates prospectively.  The FERC and interested parties can also challenge tariff rates that have become final and effective.  The FERC can also order new rates to take effect prospectively and order reparations for past rates that exceed the just and reasonable level up to two years prior to the date of a complaint.  Due to the complexity of rate making, the lawfulness of any rate is never assured.  A successful challenge of our rates could adversely affect our revenues.

The FERC uses prescribed rate methodologies for approving regulated tariff rate changes for interstate liquids pipelines.  The FERC’s indexing methodology currently allows a pipeline to increase its rates by a percentage linked to the Bureau of Labor’s PPI for finished goods.   For the five-year period ending June 30, 2021, the index is measured by the year-over-year change in the PPI, plus 1.23%.  On December 17, 2020, the FERC issued a final rule setting the index for the five-year period beginning July 1, 2021 at PPI plus 0.78%.  In any year in which the index is negative, a pipeline must file to lower its rates if its rates would be above the indexed rate ceiling.  As an alternative to this indexing methodology, we may also choose to support our rates based on a cost-of-service methodology, or by obtaining advance approval to charge “market-based rates,” or by charging “settlement rates” agreed to by all affected shippers.  These methodologies may limit our ability to set rates based on our actual costs or may delay the use of rates reflecting increased costs.   Adverse decisions by the FERC in approving our regulated rates could adversely affect our financial position, results of operations and cash flows.

The intrastate liquids pipeline transportation services we provide are subject to various state laws and regulations that apply to the rates we charge and the terms and conditions of the services we offer.  Although state regulation typically is less onerous than FERC regulation, the rates we charge and the provision of our services may be subject to challenge.

The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

The Dodd-Frank Wall Street Reform and Consumer Protection Act enacted in 2010 (the “Dodd-Frank Act”) provides for statutory and regulatory requirements for swaps and other derivative transactions, including financial and certain physical oil and gas hedging transactions.  Under the Dodd-Frank Act, the CFTC has adopted regulations requiring registration of swap dealers and major swap participants, mandatory clearing of swaps, election of the end-user exception for any uncleared swaps by certain qualified companies, recordkeeping and reporting requirements, business conduct standards and position limits among other requirements.  Several of these requirements, including position limits rules, allow the CFTC to impose controls that could have an adverse impact on our ability to hedge risks associated with our business and could increase our working capital requirements to conduct these activities.

Based on an assessment of final rules promulgated by the CFTC, we have determined that we are not a swap dealer, major swap participant or a financial entity, and therefore have determined that we currently qualify as an end-user.  In addition, the vast majority of our derivative transactions are currently transacted through a Derivatives Clearing Organization, and we believe our use of the end-user exception will likely not be necessary on a routine basis.  We will also seek to retain our status as an end-user by taking reasonable measures necessary to avoid becoming a swap dealer, major swap participant or financial entity, and other measures to preserve our ability to elect the end-user exception should it become necessary.  However, derivative transactions that are not clearable, and transactions that are clearable but for which we choose to elect the end-user exception, are subject to recordkeeping and reporting requirements and potentially additional credit support arrangements including cash margin or collateral.  Posting of additional cash margin or collateral could affect our liquidity and reduce our ability to use cash for capital investments or other company purposes.

In September 2012, the U.S. District Court for the District of Columbia vacated and remanded the position limits rules adopted by the CFTC based on a necessity finding.  In December 2013, the CFTC responded by proposing amended rules in an effort to better conform to the Dodd-Frank Act and in December 2016, the CFTC further refined and re-proposed rules on position limits.  At its open meeting on October 15, 2020, the CFTC approved three final rules, including one regarding position limits for derivatives, completing the CFTC’s major rulemakings related to implementation of the Dodd-Frank Act.  The Final Rule on position limits for derivatives was approved by a 3-2 vote, amending regulations of speculative position limits to conform with certain Dodd-Frank amendments to the Commodity Exchange Act. Among other things, the CFTC adopted new and amended federal spot month position limits for derivatives contracts associated with 25 physical commodities and their economically equivalent futures, options and swaps, and amended single-month and all-months-combined federal limits for most of the agricultural contracts currently subject to federal position limits. Under the Final Rule, federal non-spot month position limits were not extended to the sixteen new physical commodities.

Additionally, the CFTC adopted new and amended definitions for use throughout the position limits regulations, including a revised definition of “bona fide hedging transaction or position” that includes an expanded list of enumerated bona fide hedges and a new definition of “economically equivalent swaps.” The CFTC also amended rules governing exchange-set position limit levels and related exchange exemptions; established a new streamlined process for non-enumerated bona fide hedging recognitions for purposes of federal position limits; and amended certain regulatory provisions that would eliminate Form 204 (and the corresponding parts of Form 304), while also enabling the CFTC to leverage and receive cash-market reporting submitted directly to the exchanges by market participants. The Final Rule was published in the Federal Register January 14, 2021 and will become effective March 15, 2021.

While we believe that the majority of our hedging transactions would meet one or more of the enumerated categories for bona fide hedges under the Dodd-Frank Act, the rules could have an adverse impact on our ability to hedge certain risks associated with our business and could potentially affect our profitability.

Over time, the Executive Branch, the U.S. Congress and the CFTC itself may express interest in amending some of the statutory and regulatory provisions impacting financial markets and institutions and in reevaluating some of the existing regulations and regulatory proposals.  In addition, the make-up of the CFTC, and its Chairman, changes periodically, often year-to-year, since the term for one CFTC seat expires each year.  Those personnel changes can also impact the regulatory agenda.  It is not clear what, if any, changes in the law may gain sufficient support to be enacted or what, if any, changes in the existing regulations might move forward and be adopted, or how any such changes would impact our hedging activity.

Our standalone operating cash flow is derived primarily from cash distributions we receive from EPO.

On a standalone basis, the Partnership is a holding company with no business operations and conducts all of its business through its wholly owned subsidiary, EPO.  As a result, we depend upon the earnings and cash flows of EPO and its subsidiaries and unconsolidated affiliates, and the distribution of their cash flows to us in order to meet our obligations and to allow us to make cash distributions to our limited partners.

The amount of cash EPO and its subsidiaries and unconsolidated affiliates can distribute to us depends primarily on cash flows generated from their operations.  These operating cash flows fluctuate based on, among other things, the: (i) volume of hydrocarbon products transported on their gathering and transmission pipelines; (ii) throughput volumes in their processing and treating operations; (iii) fees charged and the margins realized for their various storage, terminaling, processing and transportation services; (iv) price of natural gas, crude oil, NGLs and other products; (v) relationships among natural gas, crude oil, NGL and other product prices, including differentials between regional markets; (vi) fluctuations in their working capital needs; (vii) level of their operating costs; (viii) prevailing economic conditions; and (ix) level of competition encountered by their businesses.  In addition, the actual amount of cash EPO and its subsidiaries and unconsolidated affiliates will have available for distribution will depend on factors such as: (i) the level of sustaining capital expenditures incurred; (ii) their cash outlays for expansion (or growth) capital projects and acquisitions; and (iii) their debt service requirements and restrictions included in the provisions of existing and future indebtedness, organizational documents, applicable state business organization laws and other applicable laws and regulations.  Due to these factors, we may not have sufficient available cash each quarter to continue paying distributions at our current levels.

Risks Relating to Our Partnership Structure

We may issue additional securities without the approval of our common unitholders.

At any time, we may issue an unlimited number of limited partner interests of any type (to parties other than our affiliates) without the approval of our unitholders.  Our partnership agreement does not give our common unitholders the right to approve the issuance of equity securities, including equity securities ranking senior to our common units.  The issuance of additional common units or other equity securities of equal or senior rank will have the following effects: (i) the ownership interest of a unitholder immediately prior to the issuance will decrease; (ii) the amount of cash available for distribution on each common unit may decrease; (iii) the ratio of taxable income to distributions may increase; (iv) the relative voting strength of each previously outstanding common unit may be diminished; and (v) the market price of our common units may decline.

We may not have sufficient operating cash flows to pay cash distributions at the current level following establishment of cash reserves and payments of fees and expenses.

Because cash distributions on our common units are dependent on the amount of cash we generate, distributions may fluctuate based on our performance and capital needs.  We cannot guarantee that we will continue to pay distributions at the current level each quarter.  The actual amount of cash that is available to be distributed each quarter will depend upon numerous factors, some of which are beyond our control and the control of our general partner.  These factors include, but are not limited to: (i) the volume of the products that we handle and the prices we receive for our services; (ii) the level of our operating costs; (iii) the level of competition in our business; (iv) prevailing economic conditions, including the price of and demand for crude oil, natural gas, NGLs and other products we transport, store and market; (v) the level of capital investments we make; (vi) the amount and cost of capital we can raise compared to the amount of our capital investments and debt service requirements; (vii)  restrictions contained in our debt agreements; (viii) fluctuations in our working capital needs; (ix) weather volatility; (x) cash outlays for acquisitions, if any; and (xi) the amount, if any, of cash reserves required by our general partner in its sole discretion.

Furthermore, the amount of cash that we have available for distribution is not solely a function of profitability, which will be affected by non-cash items such as depreciation, amortization and provisions for asset impairments.  Our cash flows are also impacted by borrowings under credit agreements and similar arrangements.  As a result, we may be able to make cash distributions during periods when we record losses and may not be able to make cash distributions during periods when we record net income.  An inability on our part to pay cash distributions to partners could have a material adverse effect on our financial position, results of operations and cash flows.

Our general partner and its affiliates have limited fiduciary responsibilities to, and conflicts of interest with respect to, our partnership, which may permit it to favor its own interests to your detriment.

The directors and officers of our general partner and its affiliates have duties to manage our general partner in a manner that is beneficial to its members.  At the same time, our general partner has duties to manage our partnership in a manner that is beneficial to us.  Therefore, our general partner’s duties to us may conflict with the duties of its officers and directors to its members.  Such conflicts may include, among others, the following:

neither our partnership agreement nor any other agreement requires our general partner or EPCO to pursue a business strategy that favors us;

decisions of our general partner regarding the amount and timing of asset purchases and sales, cash expenditures, borrowings, issuances of additional units, and the establishment of additional reserves in any quarter may affect the level of cash available to pay quarterly distributions to our unitholders;

under our partnership agreement, our general partner determines which costs incurred by it and its affiliates are reimbursable by us;


our general partner is allowed to resolve any conflicts of interest involving us and our general partner and its affiliates, and may take into account the interests of parties other than us, such as EPCO, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;

any resolution of a conflict of interest by our general partner not made in bad faith and that is fair and reasonable to us is binding on the partners and is not a breach of our partnership agreement;

affiliates of our general partner may compete with us in certain circumstances;

our general partner has limited its liability and reduced its fiduciary duties and has also restricted the remedies available to our unitholders for actions that might, without the limitations, constitute breaches of fiduciary duty.  As a result of purchasing our units, you are deemed to consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;

we do not have any employees and we rely solely on employees of EPCO and its affiliates;

in some instances, our general partner may cause us to borrow funds in order to permit the payment of distributions;

our general partner may cause us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, may be entitled to be indemnified by us;

our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and

our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

We have significant business relationships with entities controlled by EPCO and Dan Duncan LLC.  For information regarding these relationships and related party transactions with EPCO and its affiliates, see Note 15 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.  Additional information regarding our relationship with EPCO and its affiliates can also be found under Part III, Item 13 of this annual report.

The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.

We currently list our common units on the NYSE under the symbol “EPD.” Because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s Board or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to a corporation. Accordingly, unitholders do not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. See Part III, Item 10 of this annual report for additional information.



Unitholders have limited voting rights and are not entitled to elect our general partner or its directors.  In addition, even if unitholders are dissatisfied, they cannot easily remove our general partner.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business.  Unitholders did not elect our general partner or its directors and will have no right to elect our general partner or its directors on an annual or other continuing basis.  The owners of our general partner choose the directors of our general partner.

Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have no practical ability to remove our general partner or its officers or directors.  Our general partner may not be removed except upon the vote of the holders of at least 60% of our outstanding units voting together as a single class.  Since affiliates of our general partner currently own approximately 32% of our outstanding common units, the removal of Enterprise GP as our general partner is highly unlikely without the consent of both our general partner and its affiliates.  As a result of this provision, the trading price of our common units may be lower than other forms of equity ownership because of the absence of a takeover premium in the trading price.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further 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 because of the absence of a takeover premium in the trading price.

Our general partner has a limited call right that may require common unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own 85% or more of the common units then outstanding, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price not less than the then current market price.  As a result, common unitholders may be required to sell their common units at an undesirable time or price and may therefore not receive any return on their investment.  Unitholders may also incur a tax liability upon the sale of their common units.

Our common unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.

Under Delaware law, common unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right of limited partners to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business.  Under Delaware law, our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those of our contractual obligations that are expressly made without recourse to our general partner.

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 states in which we do business. You could have unlimited liability for our obligations if a court or government agency determined that (i) we were conducting business in a state, but had not complied with that particular state’s partnership statute; or (ii) your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constituted “control” of our business.



Unitholders may have a liability to repay distributions.

Under certain circumstances, our unitholders may have to repay amounts wrongfully distributed to them.  Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.  Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the Partnership are not counted for purposes of determining whether a distribution is permitted.  Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount.  A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the Partnership that are known to such purchaser of common units at the time it became a limited partner, and for unknown obligations if the liabilities could be determined from our partnership agreement.

Our general partner’s interest in us and the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner, in accordance with our partnership agreement, may transfer its general partner interest without the consent of unitholders.  In addition, our general partner may transfer its general partner interest to a third party in a merger or consolidation or in a sale of all or substantially all of its assets without the consent of our unitholders.  Furthermore, there is no restriction in our partnership agreement on the ability of the sole member of our general partner, currently Dan Duncan LLC, to transfer its equity interests in our general partner to a third party.  The new equity owner of our general partner would then be in a position to replace the Board and officers of our general partner with their own choices and to influence the decisions taken by the Board and officers of our general partner.

We do not have the same flexibility as other types of organizations to accumulate cash and issue equity to protect against illiquidity in the future.

Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash, after taking into account reserves for commitments and contingencies, including capital and operating costs and debt service requirements.  The value of our common units and other limited partner interests may decrease in correlation with any reduction in our cash distributions per unit.  Accordingly, if we experience a liquidity problem in the future, we may not be able to issue more equity to recapitalize.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states.  If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes or if we were otherwise subject to a material amount of entity-level taxation, then cash available for distribution to our unitholders would be reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.  Despite the fact that we are organized as a limited partnership under Delaware law, we will be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based on our current operations, we believe we satisfy the qualifying income requirement.  Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.  We have not requested, and do not plan to request, a ruling from the Internal Revenue Service (“IRS”) with respect to our classification as a partnership for federal income tax purposes.



If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate and we would also likely pay additional state and local income taxes at varying rates.  Distributions to our unitholders would generally be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to our unitholders.  Because a tax would be imposed upon us as a corporation, the cash available for distribution to our unitholders would be reduced.  Thus, treatment of us as a corporation could result in a reduction in the anticipated cash-flow and after-tax return to our unitholders, which would cause a reduction in the value of our common units.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, capital, and other forms of business taxes, as well as subjecting nonresident partners to taxation through the imposition of withholding obligations and composite, combined, group, block, or similar filing obligations on nonresident partners receiving a distributive share of state “sourced” income. We currently own property or do business in a substantial number of states. Imposition on us of any of these taxes in jurisdictions in which we own assets or conduct business or an increase in the existing tax rates could result in a reduction in the anticipated cash-flow and after-tax return to our unitholders, which would cause a reduction in the value of our common units.
 
From 2013 through 2017, several publicly traded partnerships merged into their corporate general partner sponsors.  In 2018 and continuing into 2020, the combination of a number of additional factors, including the passage of the Tax Cuts and Jobs Act (the “Tax Act”) of 2017 (which lowered the federal corporate tax rate from 35% to 21% and generally provides for the expensing of certain capital investments and acquisitions), the FERC issuing its Revised Policy Statement on the Treatment of Income Taxes in March 2018, and, generally, continued lower demand and related liquidity for midstream energy companies (including those structured as publicly traded partnerships), led to additional publicly traded partnerships to either (i) merge into their corporate general partner sponsors, (ii) merge into their general partner structured as a partnership and then elect for the combined entity to be taxed as a corporation, or (iii) voluntarily elect to be taxed as a corporation.  These conversions have materially reduced the number of publicly traded partnerships and the total market capitalization and the depth of capital available for the publicly traded partnership sector.
 
While we currently believe that our classification as a partnership for federal income tax purposes continues to provide  a net benefit for our unitholders, should we continue to see (i) additional publicly traded partnerships elect to be taxed as corporations, which could result in a further decrease in the total market capitalization of the publicly traded partnership sector, (ii) lower demand for equity capital in the publicly traded partnership sector, (iii) the absence of a historic premium in the market valuation of publicly traded partnerships compared to midstream energy companies taxed as corporations  (or if we see any discount in the valuation of our partnership compared to such companies), or (iv) a combination thereof that results in a material difference in our cost of capital or limits our access to capital, the board of directors of our general partner may determine it is in our unitholders’ best interest to change our classification as a partnership for federal income tax purposes. Should the general partner recommend that we change our tax classification, such change would be subject to the approval of our common unitholders.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial interpretation.  From time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships or an investment in our common units, including elimination of partnership tax treatment for certain publicly traded partnerships.

Any changes to federal income tax laws and interpretations thereof (including administrative guidance relating to the Tax Act) may or may not be applied retroactively and could make it more difficult or impossible for us to be treated as a partnership for federal income tax purposes or otherwise adversely affect our business, financial condition or results of operations.  Any such changes or interpretations thereof could adversely impact the value of an investment in our common units.

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 day of each month, instead of on the basis of the date a particular common unit is transferred.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of the units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method.  If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units and the cost of any IRS contest will reduce our cash available for distribution to unitholders.

The IRS has made no determination as to our status as a partnership for U.S. federal income tax purposes.  The IRS may adopt positions that differ from the positions we take, even positions taken with advice of counsel.  It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained.  A court may not agree with some or all of the positions we take.  As a result, any such contest with the IRS may materially and adversely impact the market for our common units and the price at which our common units trade.  In addition, our costs of any contest with the IRS, principally legal, accounting and related fees, will be indirectly borne by our unitholders because the costs will reduce our cash available for distribution.

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

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Our general partner would cause us to pay the taxes (including any applicable penalties and interest) directly to the IRS. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own common 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.

Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount from the cash that we distribute, our unitholders may be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive any cash distributions from us.  Our common unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability resulting from their share of our taxable income.


Tax gains or losses on the 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.  Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in the unitholder’s common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if the unitholder sells such common units at a price greater than the unitholder’s tax basis in those common units, even if the price received is less than the unitholder’s 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 such as depreciation.  In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of the cash received from the sale.

Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

Our ability to deduct interest paid or accrued on indebtedness properly allocable to a trade or business (“business interest”) may be limited in certain circumstances. Should our ability to deduct business interest be limited, the amount of taxable income allocated to our unitholders in the taxable year in which the limitation is in effect may increase. However, in certain circumstances, a unitholder may be able to utilize a portion of a business interest deduction subject to this limitation in future taxable years. Prospective unitholders should consult their tax advisors regarding the impact of this business interest deduction limitation on an investment in our common units.

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

Investments in our common units by tax-exempt entities, such as individual retirement accounts (“IRAs”) or other retirement plans, and non-U.S. persons raise issues unique to them.  For example, virtually all of our income allocated to unitholders who are organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. With respect to taxable years beginning after December 31, 2017, subject to the proposed aggregation rules for certain similarly situated businesses or activities issued by the Treasury Department, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor regarding the impact of these rules on an investment in our common units. 

Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our common units.

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our common units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a common unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that common unit.


Moreover, upon the sale, exchange or other disposition of a common unit by a non-U.S. unitholder, 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 non-U.S. unitholders 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 our common units occurring before January 1, 2022. Non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.

We treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased.  The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of common units, we adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations.  A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a common unitholder.  It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholder’s tax returns.

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

In addition to federal income taxes, our common unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes imposed by the various jurisdictions in which we do business or own property now or in the future, even if the unitholder does not live in any of those jurisdictions.  Our common unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions.  Further, our unitholders may be subject to penalties for failure to comply with those requirements.  We currently own property or conduct business in a substantial number of states, many of which impose an income tax on individuals, corporations and other entities.  As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal or corporate income tax.  It is the responsibility of each unitholder to file its own federal, state and local tax returns, as applicable.

A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those common units.  If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned units.  In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and the unitholder may recognize gain or loss from such disposition.  Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income.  Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from lending their common units.


We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction.  The IRS may challenge these methods 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, we must routinely determine the fair market value of our respective assets.  Although we may from time to time consult with professional appraisers regarding valuation matters, we make 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 respective 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 common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.


ITEM 1B.  UNRESOLVED SEC STAFF COMMENTS.

None.


ITEM 3.  LEGAL PROCEEDINGS.


We may be named as defendants in legal proceedings in connection with our normal business activities.  Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully indemnify us against losses arising from legal proceedings.  We will vigorously defend our partnership in litigation matters.

For additional information regarding litigation matters, see Note 17 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

On occasion, we are assessed monetary penalties by governmental authorities related to administrative or judicial proceedings involving environmental matters.  In June 2019, we received a Notice of Violation from the U.S. Environmental Protection Agency in connection with regulatory requirements applicable to facilities that we operate in Baton Rouge, Louisiana. The eventual resolution of this matter may result in monetary sanctions in excess of $0.3 million; however, we do not expect such expenditures to be material to our consolidated financial statements.


ITEM 4.  MINE SAFETY DISCLOSURES.

Not applicable.




PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES


Our common units are listed on the NYSE under the ticker symbol EPD. As of January 31, 2021, there were approximately 2,130 unitholders of record of our common units.  For information regarding our quarterly cash distributions to partners, see Note 8 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Recent Issuances of Unregistered Securities

On September 30, 2020, we issued and sold an aggregate of 50,000 Series A Cumulative Convertible Preferred Units in a private placement transaction.  The stated value of each preferred unit is $1,000 per unit.  The total offering price for the preferred units was $50.0 million, of which $32.5 million was received in cash with the remaining $17.5 million funded through the exchange of 1,120,588 of our common units owned by the purchasers.  Cash proceeds from the preferred unit offering include $15.0 million received from a privately held affiliate of EPCO for the purchase of 15,000 preferred units.

Concurrently, we exchanged all of the 54,807,352 Partnership common units owned directly by OTA for 855,915 of the new preferred units having an equivalent value.  The preferred units held by OTA, like the common units OTA held prior to the exchange, are accounted for as treasury units by the Partnership in consolidation.

Holders of the preferred units are entitled to receive cumulative quarterly distributions at a rate of 7.25% per annum. We may satisfy our obligation to pay distributions to the preferred unitholders through the issuance, in whole or in part, of additional preferred units (referred to as paid-in kind or “PIK” distributions), with the remainder in cash, subject to certain rights of a holder to elect all cash and other conditions as described in our partnership agreement.

In November 2020, the Partnership made its first quarterly distribution to preferred unitholders, including PIK distributions of an aggregate of 8,067 restricted preferred units consisting of 7,929 preferred units to OTA (which are accounted for as treasury units in consolidation) and 138 preferred units to the privately held EPCO affiliate referenced above.

For additional information regarding the preferred units, see Note 8 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

The issuances of the preferred units as PIK distributions during the three months ended December 31, 2020 were undertaken in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof.

Other than as described above, there were no sales of unregistered equity securities during the three months ended December 31, 2020.


Common Units Authorized for Issuance Under Equity Compensation Plan

See “Securities Authorized for Issuance Under Equity Compensation Plans” included under Part III, Item 12 of this annual report, which is incorporated by reference into this Item 5.

Issuer Purchases of Equity Securities

The following table summarizes our equity repurchase activity during the fourth quarter of 2020:

Period
 
Total Number
of Units
Purchased
   
Average
Price Paid
per Unit
   
Total
Number
Of Units
Purchased
as Part of
2019 Buyback
Program
   
Remaining
Dollar Amount
of Units
That May
Be Purchased
Under the 2019 Buyback
Program
($ thousands)
 
2019 Buyback Program: (1)
                       
   October 2020
   
   
$
     
   
$
1,745,312
 
   November 2020
   
   
$
     
   
$
1,745,312
 
   December 2020
   
636,071
   
$
19.66
     
636,071
   
$
1,732,808
 
Vesting of phantom unit awards:
                               
   November 2020 (2)
   
20,759
   
$
16.63
     
n/a
     
n/a
 

(1)
In January 2019, we announced the 2019 Buyback Program, which authorized the repurchase of up to $2 billion of our common units.  Common units repurchased under this program during 2020 were cancelled immediately upon acquisition.
(2)
Of the 83,609 phantom unit awards that vested in November 2020 and converted to common units, 20,759 units were sold back to us by employees to cover related withholding tax requirements.  These repurchases are not part of any announced program.  We cancelled these units immediately upon acquisition.


ITEM 6.  SELECTED FINANCIAL DATA.

We voluntarily adopted the amended disclosure requirements under final SEC rules in Release No. 34-90459 applicable to Item 301 of Regulation S-K and Item 6 of Form 10-K on December 31, 2020.  As a result, the five-year summary financial information formerly disclosed under Item 6 of Form 10-K is no longer applicable.

ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

For the Years Ended December 31, 2020, 2019 and 2018

The following discussion and analysis of our financial condition, results of operations and related information for the years ended December 31, 2020 and 2019, including applicable year-to-year comparisons, should be read in conjunction with our Consolidated Financial Statements and accompanying notes included under Part II, Item 8 of this annual report.  Our financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the United States (“U.S.”).

Discussion and analysis of matters pertaining to the year ended December 31, 2018 and year-to-year comparisons between the years ended December 31, 2019 and 2018 are not included in this Form 10-K, but can be found under Part II, Item 7 of our annual report on Form 10-K for the year ended December 31, 2019 that was filed on February 28, 2020. 

Key References Used in this Management’s Discussion and Analysis

Unless the context requires otherwise, references to “we,” “us” or “our” within this annual report are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.  

References to the “Partnership” mean Enterprise Products Partners L.P. on a standalone basis.

References to “EPO” mean Enterprise Products Operating LLC, which is an indirect wholly owned subsidiary of the Partnership, and its consolidated subsidiaries, through which the Partnership conducts its business.  We are managed by our general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company.

The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Directors (the “Board”) of Enterprise GP;  (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board of Enterprise GP; and (iii) W. Randall Fowler, who is also a director and the Co-Chief Executive Officer and Chief Financial Officer of Enterprise GP.  Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as managers of Dan Duncan LLC.

References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates.  The outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are:  (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO; and (iii) Mr. Fowler, who serves as an Executive Vice President and the Chief Financial Officer of EPCO.  Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as directors of EPCO.

We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees.  EPCO, together with its privately held affiliates, owned approximately 32.2% of the Partnership’s common units outstanding and 30.2% of its Series A Cumulative Convertible Preferred Units (“preferred units”) outstanding at December 31, 2020.

As generally used in the energy industry and in this annual report, the acronyms below have the following meanings:

/d
=
per day
MMBbls
=
million barrels
BBtus
=
billion British thermal units
MMBPD
=
million barrels per day
Bcf
=
billion cubic feet
MMBtus
=
million British thermal units
BPD
=
barrels per day
MMcf
=
million cubic feet
MBPD
=
thousand barrels per day
TBtus
=
trillion British thermal units


CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This annual report on Form 10-K for the year ended December 31, 2020 (our “annual report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us.  When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “scheduled,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements.  Although we and our general partner believe that our expectations reflected in such forward-looking statements (including any forward-looking statements/expectations of third parties referenced in this annual report) are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct.  

Forward-looking statements are subject to a variety of risks, uncertainties and assumptions as described in more detail under Part I, Item 1A of this annual report.  If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected.  You should not put undue reliance on any forward-looking statements.  The forward-looking statements in this annual report speak only as of the date hereof.  Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.

Overview of Business

We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.”  Our preferred units are not publicly traded.  We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products.  We are owned by our limited partners (preferred and common unitholders) from an economic perspective.   Enterprise GP, which owns a non-economic general partner interest in us, manages our Partnership.  We conduct substantially all of our business operations through EPO and its consolidated subsidiaries.

Our fully integrated, midstream energy asset network (or “value chain”) links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States (“U.S.”), Canada and the Gulf of Mexico with domestic consumers and international markets.  Our midstream energy operations include:

natural gas gathering, treating, processing, transportation and storage;

NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases, or “LPG,” and ethane);

crude oil gathering, transportation, storage, and marine terminals;

propylene production facilities (including propane dehydrogenation (“PDH”) facilities), butane isomerization, octane enhancement, isobutane dehydrogenation (“iBDH”) and high purity isobutylene (“HPIB”) production facilities;

petrochemical and refined products transportation, storage, and marine terminals (including those used to export ethylene and polymer grade propylene (“PGP”); and

a marine transportation business that operates on key U.S. inland and intracoastal waterway systems. 

The safe operation of our assets is a top priority.  We are committed to protecting the environment and the health and safety of the public and those working on our behalf by conducting our business activities in a safe and environmentally responsible manner.  For additional information, see “Environmental, Safety and Conservation” within the Regulatory Matters section of Part I, Items 1 and 2 of this annual report.


Like many publicly traded partnerships, we have no employees.  All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers.

Each of our business segments benefits from the supporting role of our marketing activities.  The main purpose of our marketing activities is to support the utilization and expansion of assets across our midstream energy asset network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment.  In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of gross operating margin, a non-generally accepted accounting principle (“non-GAAP”) financial measure, for us.  The financial results of our marketing efforts fluctuate due to changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for the products bought and sold.

Our financial position, results of operations and cash flows are subject to certain risks. For information regarding such risks, see “Risk Factors” included under Part I, Item 1A of this annual report.

Current Outlook

As noted previously, this annual report on Form 10-K, including this update to our outlook on business conditions, contains forward-looking statements that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us, which includes forecast information published by third parties. See “Cautionary Statement Regarding Forward-Looking Information” within this Part II, Item 7 and “Risk Factors” in Part I, Item 1A, for additional information.  The following information presents our current views on key midstream energy supply and demand fundamentals. The third-party supply and demand forecasts cited in the following discussion, including our internal forecasts based on such information, remain subject to significant uncertainty because mitigation and reopening efforts related to COVID-19, emerging variants of COVID-19 and the introduction of approved vaccines and proven therapeutics continue to evolve.

All references to U.S. Energy Information Administration (“EIA”) forecasts and expectations are derived from its February 2021 Short-Term Energy Outlook (“February 2021 STEO”), which was published on February 9, 2021.

Changes in the supply of and demand for hydrocarbon products impacts both the volume of products that we sell and the level of services that we provide to customers, which in turn has a direct impact on our financial position, results of operations and cash flows.  The continued global effects of the COVID-19 pandemic, which began in the first quarter of 2020 and include the consequences of international COVID-19 containment measures (e.g., quarantines, travel restrictions, temporary business closures and similar protective actions), reduced near-term demand for hydrocarbon products by record amounts and created a significant oversupply situation.  Also, in the early stages of the pandemic, disputes between members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (collectively, the “OPEC+” group) over crude oil production levels led to unprecedented volatility in global energy markets and a historic collapse in crude oil prices in April 2020.  Although the OPEC+ group and other producers subsequently reached agreements to gradually reduce the oversupply of crude oil through production cuts, the downturn in the energy industry caused by lower demand and prices negatively impacted us, the producers we work with and our other customers to varying degrees.













Supply Side Observations

Ongoing production cuts within the OPEC+ group, along with market-driven cuts in U.S., Brazilian and Canadian supplies, continue to provide much-needed support for international energy markets in coping with the ongoing weakness in hydrocarbon demand attributable to the pandemic.  In April 2020, the OPEC+ group resolved their production dispute by agreeing to reduce their combined crude oil production by 9.7 MMBPD in May and June 2020, 9.6 MMBPD in July 2020, 7.7 MMBPD from August through December 2020, and 5.8 MMBPD from January 2021 to April 2022.  In December 2020, the OPEC+ group revised their post-2020 production curtailments in light of current market dynamics and agreed to reduce their combined crude oil production by 7.2 MMBPD beginning in January 2021. The group will also hold monthly meetings to sign off on production adjustments for the following month, which would be no more than a 0.5 MMBPD increase. In addition, Saudi Arabia, the world’s biggest oil exporter, said it would voluntarily reduce its production by 1.0 MMBPD in February and March in recognition of demand uncertainty related to the pandemic. The duration of market-driven production cuts by non-OPEC countries such as the U.S., Brazil and Canada will depend on supply and demand fundamentals. According to the February 2021 STEO, the EIA estimates that global production of petroleum and related liquids averaged 94.2 MMBPD in 2020, which represents a decline of 6.4 MMBPD when compared to 2019, and expects an average of 97.3 MMBPD in 2021 and 100.8 MMBPD in 2022.

As a result of the current business environment, most crude oil producers in North America have significantly reduced their drilling and completion of new wells compared to prior years.  Baker Hughes reported that the total number of drilling rigs working in the continental U.S. (combined crude oil and natural gas rigs) declined from 805 at December 27, 2019 to 265 at June 26, 2020.  The U.S. drilling rig count stood at 266 on October 2, 2020, but increased to 392 by February 5, 2021 due to strengthening energy fundamentals.  In its February 2021 STEO, the EIA estimates that U.S. crude oil production averaged 11.3 MMBPD in 2020, which is down from an average of 12.3 MMBPD in 2019.  According to the February 2021 STEO, the EIA expects U.S. crude oil production to decline to an average of 10.9 MMBPD in the second quarter of 2021 since near-term drilling and completion activity will not generate enough production to offset declines from existing wells. The EIA expects drilling activity to rise later in 2021, contributing to U.S. crude oil production returning to an average of 11.2 MMBPD in the fourth quarter of 2021 and 11.0 MBPD for 2021. The EIA forecasts U.S. crude oil production to average 11.5 MMBPD in 2022.

In its February 2021 STEO, the EIA estimates that U.S. natural gas production averaged 91.3 Bcf/d in 2020, which is down from an average of 93.1 Bcf/d in 2019.  The EIA forecasts natural gas production to average 90.5 Bcf/d in 2021 and 91.0 Bcf/d in 2022. With the expected increase in U.S. crude oil production in late-2021, the EIA expects associated natural gas production from crude oil-directed wells to increase, especially in the Permian Basin region, and to average 90.5 Bcf/d in the fourth quarter of 2021.

Demand Side Observations

Across the globe, downstream demand for petroleum products such as gasoline and jet fuel has recovered from the lows of the second quarter of 2020, but remains depressed due to the effects of the pandemic and refiners have reduced their utilization rates in response.  Many countries have eased their COVID-19 containment measures and central banks and governments have instituted fiscal measures in an effort to stimulate economic activity. As a result, hydrocarbon demand has started to recover; however, a continuation of this trend remains dependent on successful containment of the disease, the efficacy and distribution of approved vaccines on COVID-19 and its emerging variants, and proven therapeutics. In its February 2021 STEO, the EIA estimates that global demand for petroleum and related liquids averaged 92.3 MMBPD in 2020, and expects an average of 97.7 MMBPD in 2021 and 101.2 MMBPD in 2022.  By contrast, the EIA estimates that global demand for petroleum and related liquids averaged 101.2 MMBPD in 2019 (pre-pandemic).



The decrease in hydrocarbon demand attributable to COVID-19 and the resulting oversupply situation caused a significant decrease in crude oil prices.  Prior to the pandemic, crude oil prices for West Texas Intermediate (“WTI”) at Cushing, Oklahoma (as reported by the NYMEX) closed at $61.06 per barrel on December 31, 2019. By March 31, 2020, WTI prices closed at $20.48 per barrel and, notwithstanding the announced OPEC+ production cuts, closed at a record low of a negative $37.63 per barrel on April 20, 2020.  As demand began to recover starting in the second quarter of 2020, WTI prices rebounded from the April lows and closed at $39.27 per barrel on June 30, 2020.  At September 30, 2020, WTI prices closed at $40.22 per barrel.  At December 31, 2020, WTI prices closed at $48.52 per barrel as supply and demand fundamentals strengthened.  Prices continue to increase as we begin 2021, averaging $52.10 per barrel in January 2021.

In its February 2021 STEO, the EIA estimates that U.S. consumption of natural gas averaged 83.3 Bcf/d in 2020, which reflects a 2.2% decrease from the 2019 average of 85.2 Bcf/d.  The EIA expects U.S. consumption of natural gas to decrease to an average of 81.7 Bcf/d in 2021 and 81.0 Bcf/d in 2022 due to rising natural gas prices, which are expected to negatively impact demand from the electric power sector.  Natural gas prices, as measured by the NYMEX at Henry Hub and reported in the February 2021 STEO, averaged $2.03 per MMBtu in 2020 compared to an average of $2.57 per MMBtu in 2019. The EIA forecasts Henry Hub spot prices to increase to an average $2.95 per MMBtu in 2021 due to rising space heating demand and liquefied natural gas exports amid the overall decrease in U.S. natural gas production expected for 2021.  The EIA expects Henry Hub spot prices to average $3.27 per MMBtu in 2022.

Enterprise Outlook

We believe that crude oil prices will continue to increase.  Our view considers the record retrenchment in drilling and completion activities worldwide, including by U.S. producers in 2020, along with steep decline curves in shale basins that result in lower near-term production through mid-2021, and the expected continuing recovery of global hydrocarbon demand following the pandemic.  However, in the interim, we believe the midstream industry will be challenged in its supply-side businesses and that challenges and opportunities will be different for each producing basin.

Although the current industry and business outlooks remain challenging, we believe that our integrated, diversified and fee-based business model, will enable us to successfully traverse this difficult period. The Partnership and its consolidated operations remain in a strong position, with our financial strength and operational flexibility demonstrated by the following:

At December 31, 2020, we had $6.06 billion of consolidated liquidity, which was comprised of $5.0 billion of available borrowing capacity under EPO’s revolving credit facilities and $1.06 billion of unrestricted cash on hand.  Our liquidity is supported by investment grade credit ratings on EPO’s long-term senior unsecured debt of BBB+, Baa1 and BBB+ from Standard and Poors, Moody’s and Fitch, respectively.

EPO successfully issued $4.25 billion in principal amount of senior notes in 2020.  Based on current conditions, we believe that we will have sufficient liquidity and/or access to debt capital markets to fund the remaining principal amount of senior notes maturing through 2021.

In light of the current downturn in the domestic energy industry, we reevaluated our planned capital investments.  Based on information currently available, we expect our total capital investments for 2021, net of contributions from joint venture partners, to approximate $2.1 billion, which reflects growth capital investments of $1.6 billion and sustaining capital expenditures of $440 million.  In addition, we currently expect our growth capital investments in 2022 and 2023 for sanctioned projects to approximate $800 million and $400 million, respectively. These amounts do not include capital investments associated with our proposed deepwater offshore crude oil terminal (the Sea Port Oil Terminal or “SPOT”), which remains subject to governmental approvals.  We currently anticipate receiving approval for SPOT as early as the third quarter of 2021; however, we can give no assurance as to whether the project will ultimately be approved or the timing of such decision.


We continue to optimize our assets to provide incremental services to customers and to respond to market opportunities. As prices for certain NGLs, crude oil and refined products fell in 2020 due to collapsing demand for refined products as a result of the pandemic, our storage services provided valuable flexibility for our customers. In addition, our earnings from marketing activities in 2020 benefited from using uncontracted storage capacity to capture contango opportunities in NGLs, crude oil and refined products.

Across all of our assets, we have contracted with a large number of quality customers in order to achieve customer diversification. In 2020, our top 200 largest customers represented 95.3% of consolidated revenues.  Based on their respective year-end 2020 debt ratings, 81.4% of our top 200 customers were either investment grade rated or backed by letters of credit.  Additionally, only 8.1% of our top 200 customer revenues were attributable to sub-investment grade or non-rated upstream producers.

In light of current events, we are closely monitoring the recoverability of our long-lived assets for potential impairment. We recognized a combined $890.6 million of non-cash asset impairment charges during the year ended December 31, 2020.  If the adverse economic impacts of the pandemic persist for longer periods than currently expected, these developments could result in our recognition of additional non-cash impairment charges in the future.

Significant Recent Developments

Enterprise and Magellan to Develop Joint Houston Crude Oil Futures Contract

In January 2021, we and Magellan Midstream Partners, L.P (“Magellan”) announced that our affiliates had entered into an agreement to jointly develop a futures contract for the physical delivery of crude oil in the Houston, Texas area in response to market interest for a Houston-based index with greater scale, flow assurance and price transparency. The quality specifications will be consistent with WTI crude oil originating from the Permian Basin with delivery capabilities at either our ECHO terminal in Houston or Magellan’s East Houston terminal.

Ethylene Export Terminal Enters Full Service

In December 2020, our ethylene export terminal located at our Morgan’s Point facility on the Houston Ship Channel entered full service with the commissioning of a refrigerated storage tank capable of handling 66 million pounds of ethylene.  The ethylene export terminal, which had been in limited service since December 2019, features two docks and a nameplate capacity to load 1 million tons of ethylene per year. Ethylene is the primary feedstock for a wide variety of consumer products, including cell phones and computer parts, food packaging, apparel, textiles and personal protective equipment.  We own a 50% member interest in Enterprise Navigator Ethylene Terminal LLC, which owns the export facility.

Our ethylene system serves as an open market storage and trading hub for the ethylene industry by incorporating storage capacity, connections to multiple ethylene pipelines, and high-volume export capabilities.  In support of our ethylene business, our Mont Belvieu storage operations include a high-capacity underground ethylene storage well having a storage capacity of 600 million pounds of ethylene.  The storage well is connected to our Morgan’s Point ethylene export terminal and further to Bayport, Texas by a 27-mile pipeline.

Enterprise Joins The Alliance To End Plastic Waste

In December 2020, we became the first midstream company member of The Alliance to End Plastic Waste (the “Alliance”), which represents an international community of chief executive officers from across the plastic industry that are committed to addressing the global plastic waste challenge. Formed in 2019, the Alliance partners with a diverse and growing network of organizations, technical leaders, engineers and scientists, all dedicated to the goal of ending plastic waste.  To achieve this goal, the Alliance focuses on four strategic areas – infrastructure, innovation, education and clean up – to unlock innovative solutions that will bring the world closer to the Alliance’s ambition of diverting millions of tons of plastic waste in more than 100 at-risk cities across the globe by 2025.


Expansion of Midland-to-ECHO System Enters Service

In July 2019, we announced a third expansion of our Midland-to-ECHO System comprised of a 36-inch pipeline extending from Midland, Texas to our Enterprise Crude Houston (“ECHO”) terminal, and further from ECHO to a third-party terminal in Webster, Texas (collectively, the “Midland-to-Webster pipeline”).  We proportionately consolidate a 29% undivided interest in the Midland-to-Webster pipeline, which we refer to as the “Midland-to-ECHO 3” pipeline.  In October 2020, we announced that the Midland-to-ECHO segment was placed into service.   The ECHO-to-Webster segment was mechanically complete in December 2020.  Once all facilities are placed into full commercial service, our maximum transportation capacity on the pipeline is expected to approximate 450 MBPD.

Amendments to Crude Oil Transportation Agreements; Cancellation of Midland-to-ECHO 4 Pipeline

In September 2020, we announced the amendment of certain crude oil transportation agreements and the related cancellation of the Midland-to-ECHO 4 pipeline. In general, the amendments provide for the reduction of near-term pipeline volume commitments in exchange for extending the term of the related transportation agreements and using existing pipeline infrastructure. Cancellation of the Midland-to-ECHO 4 pipeline reduced our growth capital investments by an aggregate $800 million over the years 2020 through 2022.  As a result of the cancellation, we recorded an impairment charge of $42.2 million.

Execution of Long-Term PGP Sales Agreement in Support of PDH 2 Facility

In June 2020, we announced the execution of a long-term sales agreement with Marubeni Corporation to supply PGP from our second propane dehydrogenation plant (“PDH 2”), which is currently under construction at our Mont Belvieu complex. Marubeni Corporation is a major Japanese integrated trading and investment business conglomerate and the world’s largest olefins trader. PGP is a primary petrochemical that has global demand growth as a feedstock to manufacture consumer, medical and industrial products that improve the daily lives and protect the health of people around the world.

PDH 2 is expected to have the capacity to upgrade 35 MBPD of propane into 1.65 billion pounds per year (equivalent to 25 MBPD) of PGP and begin service in the second quarter of 2023.  Once PDH 2 is placed into service and integrated with PDH 1 and our other propylene production facilities, we will have the capability to produce 11 billion pounds of propylene per year.


Selected Energy Commodity Price Data

The following table presents selected average index prices for natural gas and selected NGL and petrochemical products for the periods indicated:

           
Polymer
Refinery
Indicative Gas
 
Natural
   
Normal
 
Natural
Grade
Grade
Processing
 
Gas,
Ethane,
Propane,
Butane,
Isobutane,
Gasoline,
Propylene,
Propylene,
Gross Spread
 
$/MMBtu
$/gallon
$/gallon
$/gallon
$/gallon
$/gallon
$/pound
$/pound
$/gallon
 
(1)
(2)
(2)
(2)
(2)
(2)
(3)
(3)
(4)
2019 by quarter:
                 
1st Quarter
$3.15
$0.30
$0.67
$0.82
$0.85
$1.16
$0.38
$0.24
$0.31
2nd Quarter
$2.64
$0.21
$0.55
$0.63
$0.65
$1.21
$0.37
$0.24
$0.25
3rd Quarter
$2.23
$0.17
$0.44
$0.51
$0.66
$1.06
$0.38
$0.23
$0.21
4th Quarter
$2.50
$0.19
$0.50
$0.68
$0.82
$1.20
$0.35
$0.21
$0.25
2019 Averages
$2.63
$0.22
$0.54
$0.66
$0.75
$1.16
$0.37
$0.23
$0.26
                   
2020 by quarter:
                 
1st Quarter
$1.95
$0.14
$0.37
$0.57
$0.63
$0.93
$0.31
$0.18
$0.19
2nd Quarter
$1.71
$0.19
$0.41
$0.43
$0.44
$0.41
$0.26
$0.11
$0.17
3rd Quarter
$1.98
$0.22
$0.50
$0.58
$0.60
$0.80
$0.35
$0.17
$0.25
4th Quarter
$2.67
$0.21
$0.57
$0.76
$0.68
$0.92
$0.41
$0.24
$0.22
2020 Averages
$2.08
$0.19
$0.46
$0.59
$0.59
$0.77
$0.33
$0.18
$0.21

(1)
Natural gas prices are based on Henry-Hub Inside FERC commercial index prices as reported by Platts, which is a division of McGraw Hill Financial, Inc.
(2)
NGL prices for ethane, propane, normal butane, isobutane and natural gasoline are based on Mont Belvieu Non-TET commercial index prices as reported by Oil Price Information Service.
(3)
Polymer grade propylene prices represent average contract pricing for such product as reported by IHS Chemical, a division of IHS Inc. (“IHS Chemical”).  Refinery grade propylene (“RGP”) prices represent weighted-average spot prices for such product as reported by IHS Chemical.
(4)
The “Indicative Gas Processing Gross Spread” represents our generic estimate of the gross economic benefit from extracting NGLs from natural gas production based on certain pricing assumptions.  Specifically, it is the amount by which the assumed economic value of a composite gallon of NGLs at Mont Belvieu, Texas exceeds the value of the equivalent amount of energy in natural gas at Henry Hub, Louisiana. Our estimate of the indicative spread does not consider the operating costs incurred by a natural gas processing facility to extract the NGLs nor the transportation and fractionation costs to deliver the NGLs to market.   In addition, the actual gas processing spread earned at each plant is determined by regional pricing and extraction dynamics.

The weighted-average indicative market price for NGLs was $0.38 per gallon in 2020 versus $0.47 per gallon for 2019.


The following table presents selected average index prices for crude oil for the periods indicated:

WTI
Midland
Houston
LLS
 
Crude Oil,
Crude Oil,
Crude Oil
Crude Oil,
 
$/barrel
$/barrel
$/barrel
$/barrel
 
(1)
(2)
(2)
(3)
2019 by quarter:
       
1st Quarter
$54.90
$53.70
$61.19
$62.35
2nd Quarter
$59.81
$57.62
$66.47
$67.07
3rd Quarter
$56.45
$56.12
$59.75
$60.64
4th Quarter
$56.96
$57.80
$60.04
 $60.76
2019 Averages
$57.03
$56.31
$61.86
$62.71
         
2020 by quarter:
       
1st Quarter
$46.17
$45.51
$47.81
$48.15
2nd Quarter
$27.85
$28.22
$29.68
$30.12
3rd Quarter
$40.93
$41.05
$41.77
 $42.47
4th Quarter
$42.66
$43.07
$43.63
 $44.08
2020 Averages
$39.40
$39.46
$40.72
$41.21

(1)
WTI prices are based on commercial index prices at Cushing, Oklahoma as measured by the NYMEX.
(2)
Midland and Houston crude oil prices are based on commercial index prices as reported by Argus.
(3)
Light Louisiana Sweet (“LLS”) prices are based on commercial index prices as reported by Platts.

Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices. Energy commodity prices in 2020 fluctuated significantly due to the adverse economic effects of the COVID-19 pandemic and, with respect to crude oil prices in early 2020, the production dispute between Saudi Arabia and Russia.  See “Current Outlook” within this Part II, Item 7 for information regarding these recent events.

A decrease in our consolidated marketing revenues due to lower energy commodity sales prices may not result in a decrease in gross operating margin or cash available for distribution, since our consolidated cost of sales amounts would also decrease due to comparable decreases in the purchase prices of the underlying energy commodities.  The same type of correlation would be true in the case of higher energy commodity sales prices and purchase costs.

We attempt to mitigate commodity price exposure through our hedging activities and the use of fee-based arrangements.  See Note 14 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for information regarding our commodity hedging activities.



Income Statement Highlights

The following table summarizes the key components of our consolidated results of operations for the years indicated (dollars in millions):

 
 
For the Year Ended
December 31,
 
 
 
2020
   
2019
 
Revenues
 
$
27,199.7
   
$
32,789.2
 
Costs and expenses:
               
Operating costs and expenses:
               
Cost of sales
   
16,723.2
     
22,065.8
 
Other operating costs and expenses
   
2,800.2
     
3,020.7
 
Depreciation, amortization and accretion expenses
   
1,961.5
     
1,848.3
 
Net gains attributable to asset sales
   
(4.4
)
   
(5.7
)
Asset impairment and related charges
   
890.6
     
132.7
 
Total operating costs and expenses
   
22,371.1
     
27,061.8
 
General and administrative costs
   
219.6
     
211.7
 
Total costs and expenses
   
22,590.7
     
27,273.5
 
Equity in income of unconsolidated affiliates
   
426.1
     
563.0
 
Operating income
   
5,035.1
     
6,078.7
 
Interest expense
   
(1,287.4
)
   
(1,243.0
)
Change in fair value of Liquidity Option
   
(2.3
)
   
(119.6
)
Other, net
   
16.0
     
16.6
 
Benefit from (provision for) income taxes
   
124.3
     
(45.6
)
Net income
   
3,885.7
     
4,687.1
 
Net income attributable to noncontrolling interests
   
(110.1
)
   
(95.8
)
Net income attributable to preferred units
   
(0.9
)
   
 
Net income attributable to common unitholders
 
$
3,774.7
   
$
4,591.3
 

Revenues

The following table presents each business segment’s contribution to consolidated revenues for the years indicated (dollars in millions):

   
For the Year Ended
December 31,
 
 
 
2020
   
2019
 
NGL Pipelines & Services:
           
Sales of NGLs and related products
 
$
8,970.7
   
$
10,934.3
 
Midstream services
   
2,206.5
     
2,536.4
 
Total
   
11,177.2
     
13,470.7
 
Crude Oil Pipelines & Services:
               
    Sales of crude oil
   
5,410.8
     
9,007.8
 
    Midstream services
   
1,278.2
     
1,279.5
 
        Total
   
6,689.0
     
10,287.3
 
Natural Gas Pipelines & Services:
               
    Sales of natural gas
   
1,530.5
     
2,075.4
 
    Midstream services
   
1,022.6
     
1,094.0
 
       Total
   
2,553.1
     
3,169.4
 
Petrochemical & Refined Products Services:
               
    Sales of petrochemicals and refined products
   
5,942.6
     
4,985.2
 
    Midstream services
   
837.8
     
876.6
 
       Total
   
6,780.4
     
5,861.8
 
Total consolidated revenues
 
$
27,199.7
   
$
32,789.2
 



Total revenues for 2020 decreased $5.59 billion when compared to 2019 primarily due to a net $5.15 billion decrease in marketing revenues.  Revenues from the marketing of crude oil and natural gas decreased $4.14 billion year-to-year primarily due to lower average sales prices, which accounted for a $3.27 billion decrease, and lower sales volumes, which accounted for an additional $867.8 million decrease.  Revenues from the marketing of NGLs decreased a net $1.96 billion year-to-year primarily due to lower average sales prices, which accounted for a $3.16 billion decrease, partially offset by the effects of higher sales volumes, which resulted in a $1.2 billion increase.  Revenues from the marketing of petrochemicals and refined products increased a net $957.4 million year-to-year primarily due to higher sales volumes, which accounted for a $2.05 billion increase, partially offset by lower average sales prices, which resulted in a $1.1 billion decrease.

Revenues from midstream services for 2020 decreased $441.4 million when compared to 2019.  Revenues from our natural gas processing facilities decreased $229.9 million year-to-year primarily due to lower market values for the equity NGLs we receive as non-cash consideration for processing services.  Revenues from our Midland-to-ECHO 2 pipeline, which commenced limited service in February 2019 and full service in April 2019 and Midland-to-ECHO 3 pipeline, which commenced service in October 2020, increased a combined $49.6 million year-to-year.  Revenues from our other pipeline assets decreased $179.8 million year-to-year primarily due to lower demand for crude oil, natural gas and refined products transportation services.  Lastly, revenues from our Mont Belvieu-area NGL fractionators decreased $82.0 million year-to-year primarily due to lower fractionation fees.

For additional information regarding our revenues, see Note 9 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Operating costs and expenses

Total operating costs and expenses for 2020 decreased $4.69 billion when compared to 2019 primarily due to lower cost of sales.  The cost of sales associated with our marketing of crude oil and natural gas decreased a combined $3.83 billion year-to-year primarily due to lower average purchase prices, which accounted for a $3.19 billion decrease, and lower sales volumes, which accounted for an additional $634.4 million decrease.  The cost of sales associated with our marketing of NGLs decreased a net $2.25 billion year-to-year primarily due to lower average purchase prices, which accounted for a $3.22 billion decrease, partially offset by higher sales volumes, which accounted for a $970.7 million increase. The cost of sales associated with our marketing of petrochemicals and refined products increased a net $736.9 million year-to-year primarily due to higher sales volumes, which accounted for a $1.81 billion increase, partially offset by lower average purchase prices, which accounted for a $1.07 billion decrease.

Other operating costs and expenses for 2020 decreased $220.5 million year-to-year primarily due to lower maintenance, chemicals and power-related expenses, which accounted for a $282.2 million decrease, partially offset by higher ad valorem taxes and employee compensation costs, which accounted for a $50.2 million increase.  Depreciation, amortization and accretion expense increased $113.2 million year-to-year primarily due to assets placed into full or limited service since the first quarter of 2019 (e.g., the iBDH plant, Mentone and Orla gas processing facilities, Fracs X and XI and the Enterprise Navigator ethylene terminal).

Non-cash asset impairment charges increased $757.9 million year-to-year primarily due to the recognition in 2020 of the full impairment of goodwill associated with our Natural Gas Pipelines & Services business segment, which accounted for $296.3 million of expense, the partial impairment of our marine transportation business, which accounted for $256.7 million of expense, and the partial impairment of natural gas gathering and processing assets in South Texas, which accounted for an additional $125.7 million of expense.  For information regarding these charges, see Notes 2, 4 and 6 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

General and administrative costs

General and administrative costs for 2020 increased $7.9 million when compared to 2019 primarily due to higher professional services and employee compensation costs.



Equity in income of unconsolidated affiliates

Equity income from our unconsolidated affiliates for 2020 decreased $136.9 million when compared to 2019 primarily due to decreased earnings from our investments in crude oil pipelines.

Operating income

Operating income for the year ended December 31, 2020 decreased $1.04 billion when compared to the year ended December 31, 2019 due to the previously described year-to-year changes in revenues, operating costs and expenses, general and administrative costs and equity in income of unconsolidated affiliates.

Interest expense

The following table presents the components of our consolidated interest expense for the years indicated (dollars in millions):

 
 
For the Year Ended
December 31,
 
 
 
2020
   
2019
 
Interest charged on debt principal outstanding
 
$
1,330.6
   
$
1,251.6
 
Impact of interest rate hedging program, including related amortization (1)
   
39.3
     
107.4
 
Interest costs capitalized in connection with construction projects (2)
   
(115.0
)
   
(143.8
)
Other (3)
   
32.5
     
27.8
 
Total
 
$
1,287.4
   
$
1,243.0
 

(1)
Amount presented for the year ended December 31, 2019 reflects an unrealized, mark-to-market loss of $94.9 million recognized in September 2019 in connection with the exercise of swaptions.  Due to declining interest rates, the counterparties to the swaptions exercised their right to put us into ten forward-starting swaps in September 2019 having an aggregate notional value of $1.0 billion. Since the swaptions were not designated as hedging instruments and were subject to mark-to-market accounting, we incurred an unrealized, mark-to-market loss at inception of the forward-starting swaps that is reflected as an increase in interest expense in 2019. The ten forward-starting swaps resulting from the swaption exercise were designated as hedging instruments and qualified for cash flow hedge accounting.
(2)
We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase.  Capitalized interest amounts become part of the historical cost of an asset and are charged to earnings (as a component of depreciation expense) on a straight-line basis over the estimated useful life of the asset once the asset enters its intended service.  When capitalized interest is recorded, it reduces interest expense from what it would be otherwise.  Capitalized interest amounts fluctuate based on the timing of when projects are placed into service, our capital investment levels and the interest rates charged on borrowings.
(3)
Primarily reflects facility commitment fees charged in connection with our revolving credit facilities and amortization of debt issuance costs.

Interest charged on debt principal outstanding, which is a key driver of interest expense, increased a net $79.0 million year-to-year primarily due to increased debt principal amounts outstanding during 2020, which accounted for a $109.2  million increase, partially offset by the effect of lower overall interest rates during 2020, which accounted for a $30.2  million decrease.  Our weighted-average debt principal balance for 2020 was $29.91 billion compared to $27.41 billion for 2019.  In general, our debt principal balances have increased over time due to the partial debt financing of our capital investments.  For information regarding our debt obligations, see Note 7 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Change in fair value of Liquidity Option

On February 25, 2020, we received notice from Marquard & Bahls AG (“M&B”) of M&B’s election to exercise its rights (the “Liquidity Option”) under the Liquidity Option Agreement among the Partnership, OTA Holdings, Inc., a Delaware corporation previously named Oiltanking Holding Americas, Inc. (“OTA”), and M&B dated October 1, 2014 (the “Liquidity Option Agreement”).  The Partnership settled its obligations under the Liquidity Option Agreement on March 5, 2020.


For the period in which the Liquidity Option was outstanding, we recognized non-cash expense in connection with accretion and changes in management estimates that affected the valuation of the Liquidity Option liability. Expense amounts attributable to changes in the fair value of the Liquidity Option were $2.3 million and $119.6 million during the years ended December 31, 2020 and 2019, respectively.  The expense recognized for 2020 primarily reflects accretion expense for the period in which the Liquidity Option liability was outstanding before it was settled on March 5, 2020.  The higher level of expense recognized in 2019 was primarily due to a decrease in the discount factor used in determining the present value of the liability.

For additional information regarding the exercise, see “Issuance of Common Units due to Settlement of Liquidity Option in March 2020” within the Liquidity and Capital Resources section of this Part II, Item 7.  In addition, please refer to Note 8 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Income taxes

The following table presents the components of our consolidated benefit from (provision for) income taxes for the years indicated (dollars in millions):

 
 
For the Year Ended
December 31,
 
 
 
2020
   
2019
 
Deferred tax benefit attributable to OTA
 
$
155.3
       
Texas Margin Tax
   
(32.1
)
 
$
(44.2
)
Other
   
1.1
     
(1.4
)
Benefit from (provision for) income taxes
 
$
124.3
   
$
(45.6
)

On March 5, 2020, the Partnership settled its obligations under the Liquidity Option Agreement and indirectly assumed the deferred tax liability of OTA, which reflects OTA’s outside basis difference in the limited partner interests it received from the Partnership in October 2014. Upon settlement of the Liquidity Option, the Liquidity Option liability was effectively replaced by the deferred tax liability of OTA calculated in accordance with ASC 740, Income Taxes.

At March 5, 2020, the Liquidity Option liability amount was $511.9 million.  Since the book value of the Liquidity Option liability exceeded OTA’s estimated deferred tax liability of $439.7 million on that date, we recognized a non-cash benefit in earnings of $72.2 million, which is reflected in the “Benefit from (provision for) income tax” line on our Statement of Consolidated Operations for the year ended December 31, 2020.  OTA recognized an additional net, non-cash deferred income tax benefit of $83.1 million primarily due to a decrease in the outside basis difference of its investment in the Partnership attributable to a decline in the market price of the Partnership’s common units subsequent to March 5, 2020 through September 30, 2020.  In total, our earnings for 2020 reflect $155.3 million of deferred income tax benefit attributable to OTA.

On September 30, 2020, OTA exchanged the Partnership common units it owned for non-publicly traded preferred units having a stated value of $1,000 per unit.  As a result and beginning September 30, 2020, OTA’s deferred tax liability no longer fluctuates due to market price changes in our common units.  For information regarding the issuance of preferred units on September 30, 2020, including the OTA-related exchange, see “Liquidity and Capital Resources” within this Part II, Item 7.

For information regarding our income taxes, see Note 16 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Business Segment Highlights

We evaluate segment performance based on our financial measure of gross operating margin.  Gross operating margin is an important performance measure of the core profitability of our operations and forms the basis of our internal financial reporting.  We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. 


The following table presents gross operating margin by segment and non-GAAP total gross operating margin for the years indicated (dollars in millions):

 
 
For the Year Ended
December 31,
 
 
 
2020
   
2019
 
Gross operating margin by segment:
           
   NGL Pipelines & Services
 
$
4,182.4
   
$
4,069.8
 
   Crude Oil Pipelines & Services
   
1,997.3
     
2,087.8
 
   Natural Gas Pipelines & Services
   
926.6
     
1,062.6
 
   Petrochemical & Refined Products Services
   
1,081.8
     
1,069.6
 
   Total segment gross operating margin (1)
   
8,188.1
     
8,289.8
 
   Net adjustment for shipper make-up rights
   
(85.7
)
   
(24.1
)
   Total gross operating margin (non-GAAP)
 
$
8,102.4
   
$
8,265.7
 

(1)
Within the context of this table, total segment gross operating margin represents a subtotal and corresponds to measures similarly titled within our business segment disclosures found under Note 10 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Total gross operating margin includes equity in the earnings of unconsolidated affiliates, but is exclusive of other income and expense transactions, income taxes, the cumulative effect of changes in accounting principles and extraordinary charges.  Total gross operating margin is presented on a 100% basis before any allocation of earnings to noncontrolling interests.  Our calculation of gross operating margin may or may not be comparable to similarly titled measures used by other companies.  Segment gross operating margin for NGL Pipelines & Services and Crude Oil Pipelines & Services reflect adjustments for shipper make-up rights that are included in management’s evaluation of segment results.  However, these adjustments are excluded from non-GAAP total gross operating margin.

The GAAP financial measure most directly comparable to total gross operating margin is operating income.  For a discussion of operating income and its components, see the previous section titled “Income Statement Highlights” within this Part II, Item 7.  The following table presents a reconciliation of operating income to total gross operating margin for the years indicated (dollars in millions):

 
 
For the Year Ended
December 31,
 
 
 
2020
   
2019
 
Operating income
 
$
5,035.1
   
$
6,078.7
 
Adjustments to reconcile operating income to total gross operating margin
(addition or subtraction indicated by sign):
               
   Depreciation, amortization and accretion expense in operating costs and expenses
   
1,961.5
     
1,848.3
 
   Asset impairment and related charges in operating costs and expenses
   
890.6
     
132.7
 
   Net gains attributable to asset sales in operating costs and expenses
   
(4.4
)
   
(5.7
)
   General and administrative costs
   
219.6
     
211.7
 
Total gross operating margin (non-GAAP)
 
$
8,102.4
   
$
8,265.7
 

Each of our business segments benefits from the supporting role of our marketing activities.  The main purpose of our marketing activities is to support the utilization and expansion of assets across our midstream energy asset network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment.  In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of gross operating margin for us.  The financial results of our marketing efforts fluctuate due to changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for the products bought and sold.

As a result of the COVID-19 pandemic and lower energy commodity prices, we experienced a reduction in volumes on a number of our assets (e.g., our crude oil pipelines and export docks and natural gas gathering systems) during the year ended December 31, 2020 due to reduced upstream drilling and production activity and lower downstream refinery activity and demand for transportation fuels. Furthermore, we may continue to experience throughput declines in the future on our gathering systems, long-haul liquids and natural gas pipelines and at our terminal and other facilities until the pandemic ends and economic activity is fully restored.  For a general discussion of the impact of the pandemic on our partnership and industry, see “Current Outlook” within this Part II, Item 7.

NGL Pipelines & Services

The following table presents segment gross operating margin and selected volumetric data for the NGL Pipelines & Services segment for the years indicated (dollars in millions, volumes as noted):

 
 
For the Year Ended
December 31,
 
 
 
2020
   
2019
 
Segment gross operating margin:
           
Natural gas processing and related NGL marketing activities
 
$
997.5
   
$
1,159.7
 
NGL pipelines, storage and terminals