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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, 2019

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 is a shell company (as defined in Rule 12b-2 of the Exchange Act).   Yes     No

The aggregate market value of the partnership’s common units held by non-affiliates at June 28, 2019 (the last business day of the registrant’s most recently completed second fiscal quarter) was $43.04 billion based on a closing price on that date of $28.87 per common unit on the New York Stock Exchange Composite ticker tape.  There were 2,189,226,130 common units outstanding at January 31, 2020.




Table of Contents

ENTERPRISE PRODUCTS PARTNERS L.P.
TABLE OF CONTENTS

 
Page
   
Number
PART I
Items 1 and 2.
Business and Properties.
2
Item 1A.
Risk Factors.
40
Item 1B.
Unresolved Staff Comments.
61
Item 3.
Legal Proceedings.
62
Item 4.
Mine Safety Disclosures.
63
     
PART II
Item 5.
Market for Registrant’s Common Equity, Related Unitholder
Matters and Issuer Purchases of Equity Securities.
64
Item 6.
Selected Financial Data.
65
Item 7.
Management’s Discussion and Analysis of Financial Condition and
Results of Operations.
66
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
104
Item 8.
Financial Statements and Supplementary Data.
108
Item 9.
Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
108
Item 9A.
Controls and Procedures.
108
Item 9B.
Other Information.
111
     
PART III
Item 10.
Directors, Executive Officers and Partnership Governance.
111
Item 11.
Executive Compensation.
122
Item 12.
Security Ownership of Certain Beneficial Owners and Management
and Related Unitholder Matters.
133
Item 13.
Certain Relationships and Related Transactions, and Director Independence.
136
Item 14.
Principal Accountant Fees and Services.
139
     
PART IV
Item 15.
Exhibits, Financial Statement Schedules.
140
Item 16.
Form 10-K Summary.
149
     
Signatures
 
150










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KEY REFERENCES USED IN THIS REPORT

Unless the context requires otherwise, references to “we,” “us,” “our” or “Enterprise” are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.  References to “EPD” 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 EPD, and its consolidated subsidiaries, through which EPD conducts its business.  Enterprise is managed by its 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) Dr. Ralph S. Cunningham, who is also an advisory director of Enterprise GP.  Ms. Duncan Williams and Mr. Bachmann also currently serve as managers of Dan Duncan LLC along with W. Randall Fowler, who is also a director and the Co-Chief Executive Officer and Chief Financial Officer of Enterprise GP.

References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates.  A majority of 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) Dr. Cunningham, who serves as Vice Chairman of EPCO; and (iii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO.  Ms. Duncan Williams and Mr. Bachmann also currently serve as directors of EPCO along with Mr. Fowler, who is also the Executive Vice President and Chief Financial Officer of EPCO. EPCO, together with its privately held affiliates, owned approximately 32% of EPD’s limited partner common units at December 31, 2019.

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, 2019 (our “annual report”) contains various forward-looking statements and information that are based on our beliefs and those of Enterprise GP, 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,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements.  Although we and Enterprise GP believe that our expectations reflected in such forward-looking statements are reasonable, neither we nor Enterprise GP 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.


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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.”  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. 

Our integrated midstream energy asset network 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 currently include: natural gas gathering, treating, processing, transportation and storage; NGL transportation, fractionation, storage, and export and import terminals (including those used to export liquefied petroleum gases, or “LPG,” and ethane); crude oil gathering, transportation, storage, and export and import terminals; petrochemical and refined products transportation, storage, export and import terminals, and related services; and a marine transportation business that operates primarily on the U.S. inland and Intracoastal Waterway systems.  Our assets currently include approximately 50,000 miles of pipelines; 260 MMBbls of storage capacity for NGLs, crude oil, petrochemicals and refined products; and 14 Bcf of natural gas storage capacity.  

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 this Part I, Items 1 and 2 discussion.

We conduct substantially all of our business through EPO and are owned 100% by EPD’s limited partners from an economic perspective.  Enterprise GP manages our partnership and owns a non-economic general partner interest in us.  We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees.  Our principal executive offices are located at 1100 Louisiana Street, 10th Floor, Houston, Texas 77002, our telephone number is (713) 381-6500 and our website address is www.enterpriseproducts.com.

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.  As of February 1, 2020, there were approximately 7,300 EPCO personnel who spend all or a substantial portion of their time engaged in our business.  For additional information regarding the ASA, see Note 15 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Business Strategy

Our integrated midstream energy asset network links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the U.S., Canada and Gulf of Mexico with domestic consumers and international markets.  Our business strategy seeks to leverage this network to:

capitalize on expected 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
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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.

General Outlook for 2020

We provide midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined 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 “General Outlook for 2020” included under Part II, Item 7 of this annual report for our views on key midstream energy supply and demand fundamentals going into 2020.

Major Customer Information

Substantially all of our consolidated revenues are earned in the U.S. and derived from a wide customer base.  Our largest non-affiliated customer for the years ended December 31, 2019, 2018 and 2017 was Vitol Holding B.V. and its affiliates (collectively, “Vitol”), which accounted for 10.1%, 7.8% and 11.2%, respectively, of our consolidated revenues.  Vitol is a global energy and commodity trading company.

Business Segments

General

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:  (i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services, and (iv) Petrochemical & Refined Products Services.  Our business segments are generally organized and managed according to the types of services rendered (or technologies employed) and products produced and/or sold.

Each of our business segments benefits from the supporting role of our related 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 the partnership.  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 results of operations and financial condition are subject to certain significant risks.  Factors that can affect the demand for our products and services include domestic and international economic conditions, the market price and demand for energy, the cost to develop natural gas and crude oil reserves in the U.S., federal and state regulation, the cost and availability of capital to energy companies to invest in upstream exploration and production activities and the credit quality of our customers.  For information regarding such risks, see 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, see Note 10 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

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NGL Pipelines & Services Segment

Our NGL Pipelines & Services business segment currently includes 22 natural gas processing facilities and related NGL marketing activities; approximately 19,900 miles of NGL pipelines; NGL and related product storage facilities; and 16 NGL fractionators.  This segment also includes our LPG and ethane export terminals and related operations.

Natural gas processing facilities and related NGL marketing activities
At the core of our natural gas processing business are 22 processing facilities located in Colorado, Louisiana, Mississippi, New Mexico, Texas and Wyoming.  The results of operations from our natural gas processing facilities 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.

In its raw form, natural gas produced at the wellhead (especially in association with crude oil) contains varying amounts of NGLs, such as ethane and propane.  Natural gas streams containing NGLs are usually not acceptable for transportation in natural gas pipelines or for commercial use as a fuel; therefore, the raw (or unprocessed) natural gas streams must be transported to a natural gas processing facility to remove the NGLs and other impurities.  Once the natural gas is processed and NGLs and impurities are removed, the residue natural gas meets pipeline and commercial quality specifications.  Natural gas that has a high NGL content is referred to as “rich” or “wet” natural gas, whereas natural gas from the wellhead that is relatively free of NGLs and impurities is referred to as “lean” or “dry” natural gas.  Dry natural gas can be shipped on pipelines and used as fuel with little to no processing.

In general, on an energy-equivalent basis, most NGLs have greater economic value as feedstock for petrochemical and motor gasoline production than as components of a natural gas stream. Once the mixed NGLs are extracted at a natural gas processing facility, they are transported to a centralized fractionation facility for separation into purity NGL products (ethane, propane, normal butane, isobutane and natural gasoline).  Typical uses of purity NGL products 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.

In our natural gas processing business, contracts are either fee-based, commodity-based or a combination of the two.  When a cash fee for natural gas processing services is stipulated by a contract, we record revenue when a producer’s natural gas has been processed and redelivered.  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 earn all or a portion of the extracted NGLs as consideration for our processing services, we refer to such volumes as our “equity NGL production.”  The terms of our natural gas processing agreements typically range from month-to-month to life of the associated production lease, with intermediate terms of one to ten years being common.


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In recent years, our portfolio of natural gas processing contracts has become increasingly weighted towards those with fee-based terms as producers seek to maximize the value of their production by retaining all or a portion of the NGLs extracted from their natural gas stream.  As of December 31, 2019, we estimate that approximately 53% of our portfolio of natural gas processing contracts (based on natural gas inlet volumes) were entirely fee-based, with an additional 21% of this portfolio reflecting a combination of fee-based and commodity-based terms.  The terms of the remaining 26% of our portfolio of natural gas processing contracts were entirely commodity-based.

The value of natural gas that is removed from the processed stream as a result of NGL extraction (i.e., the “shrinkage”) and the value of natural gas that is consumed as plant fuel are significant costs of natural gas processing.  To the extent that we are obligated under keepwhole and margin-band contracts to compensate the producer for shrinkage and plant fuel, we are exposed to fluctuations in the price of natural gas; however, margin-band contracts typically contain terms that limit our exposure to such risks.  Under the terms of our other processing arrangements (i.e., those agreements with fee-based, percent-of-liquids and percent-of-proceeds terms), the producer typically bears the cost of shrinkage. If the operating costs of a natural gas processing facility are higher than the incremental value of the NGL products that would be extracted, then recovery levels of certain NGL products, principally ethane, may be purposefully reduced. This scenario is typically referred to as “ethane rejection” and leads to a reduction in NGL volumes available 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.  In general, sales prices referenced in the underlying contracts are market-based and may include pricing adjustments for factors such as location, timing or product quality.  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.

Our NGL marketing activities utilize a fleet of approximately 850 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 90 tractor-trailer tank trucks that are used to transport LPG for us and on behalf of third parties.  We lease and operate the majority of these trucks and trailers.















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The following table presents selected information regarding our natural gas processing facilities at February 1, 2020:

       
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%
 1,400
 1,400
Yoakum
Texas
Eagle Ford
100.0%
 1,050
 1,050
Pascagoula
Mississippi
Gulf of Mexico
  75.0%   (2)
750
 1,000
Chaco
New Mexico
San Juan
100.0%
 600
 600
Orla
Texas
Delaware
100.0%
900
900
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
Fairway
Texas
Cotton Valley
100.0%
 5
 5
    Total
     
9,920
11,370

(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 75.0% 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 facility consists of two plants: our legacy Panola gas plant and our recently completed Bulldog gas plant.
(5)
Our 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 57.4%, 52.7% and 51.8% for the years ended December 31, 2019, 2018 and 2017, respectively.

Orla natural gas processing facility.  In July 2019, we completed and placed into service a third processing train (“Orla III”) at our cryogenic natural gas processing facility located near Orla, Texas in Reeves County.  The Orla facility, which has the capability to process up to 900 MMcf/d of natural gas and extract up to 140 MBPD of mixed NGLs, is designed to support the continued growth of NGL-rich natural gas production in the Delaware Basin and is supported by long-term customer commitments.  We own and operate the Orla facility.

Bulldog natural gas processing plant. In November 2019, we placed our Bulldog cryogenic natural gas processing plant, which is part of our Carthage facility, into service.  The Bulldog plant has the capability to process up to 200 MMcf/d of natural gas and extract up to 12 MBPD of NGLs.  When combined with our legacy Panola cryogenic plant, the Bulldog plant provides us with the capacity to process up to a total of 320 MMcf/d of natural gas and extract up to 18 MBPD of NGLs in the region. The new plant, along with related natural gas pipeline infrastructure we are building that is scheduled to be placed into service in the third quarter of 2020, supports continued growth of natural gas from the Cotton Valley and Haynesville formations in East Texas.  In addition, the Bulldog plant complements our value chain as mixed NGLs produced at the plant are transported on the Panola pipeline to our Mont Belvieu complex for fractionation.
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Mentone natural gas processing facility.  In December 2019, we completed the first processing train at our Mentone cryogenic natural gas processing facility (“Mentone I”) and placed it into service. The Mentone facility, which is located in Loving County, Texas, has a current capacity to process up to 300 MMcf/d of natural gas and extract more than 40 MBPD of NGLs.  Mentone and its related infrastructure further extends our presence in the Delaware Basin and provides producers access to our fully integrated midstream asset network, including our Texas Intrastate System and Shin Oak NGL Pipeline.  We own and operate the Mentone facility and related infrastructure.  Following completion of Mentone I, we have the capability to process up to 1.6 Bcf/d of natural gas and extract up to 250 MBPD of NGLs from our processing facilities in the Delaware Basin.

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 federal governmental agencies, including the Federal Energy Regulatory Commission (“FERC”), or contractual arrangements.  See “Regulatory Matters” within this Part I, Items 1 and 2 for additional information regarding governmental oversight of our liquids pipelines.

Excluding certain linefill volumes and volumes shipped in connection with our marketing activities, we typically do not take title to NGLs transported by third party shippers on our pipelines; rather, the third party shipper retains title and the associated commodity price risk.

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The following table presents selected information regarding our NGL pipelines at February 1, 2020:

   
Pipeline
   
Ownership
Length
Description of Asset
Location(s)
Interest
(Miles)
Mid-America Pipeline System (1)
Midwest and Western U.S.
 100.0%
7,985
South Texas NGL Pipeline System
Texas
 100.0%
2,001
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%
876
Seminole NGL Pipeline (1,2)
Texas
 100.0%
869
Shin Oak NGL Pipeline
Texas
   67.0%
662
Texas Express Pipeline (1)
Texas
   35.0%
594
Skelly-Belvieu Pipeline (1)
Texas, Oklahoma
   50.0%
572
Front Range Pipeline (1)
Colorado, Oklahoma, Texas
   33.3%
 447
Houston Ship Channel Pipeline System
Texas
 100.0%
304
Aegis Ethane Pipeline (1)
Texas, Louisiana
 100.0%
299
Rio Grande Pipeline (1)
Texas
 100.0%
249
Panola Pipeline (1)
Texas
   55.0%
249
Lou-Tex NGL Pipeline (1)
Texas, Louisiana
 100.0%
206
Promix NGL Gathering System
Louisiana
   50.0%
197
Texas Express Gathering System
Texas
   45.0%
170
Tri-States NGL Pipeline (1)
Alabama, Mississippi, Louisiana
   83.3%
168
Others (eight systems) (3)
Various
 Various (4)
459
   Total
   
19,891

(1)
Interstate transportation services provided by these liquids pipelines, in whole or part, are regulated by federal governmental agencies.
(2)
Pipeline mileage shown for the Seminole NGL Pipeline excludes 379 miles converted to crude oil service in January 2019 and used by our Midland-to-ECHO 2 pipeline.
(3)
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.
(4)
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 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 3,615 MBPD, 3,461 MBPD and 3,168 MBPD during the years ended December 31, 2019, 2018 and 2017, respectively.

The following information describes our principal NGL pipelines.  We operate our NGL pipelines with the exception of the Skelly-Belvieu Pipeline and Texas Express Gathering System.

The Mid-America Pipeline System is an NGL pipeline system consisting of four primary segments:  the 3,119-mile Rocky Mountain pipeline, the 2,138-mile Conway North pipeline, the 632-mile Ethane-Propane (“EP”) Mix pipeline, and the 2,096-mile Conway South pipeline. The Mid-America Pipeline System operates in 13 states: Colorado, Illinois, Iowa, Kansas, Minnesota, Missouri, Nebraska, New Mexico, Oklahoma, Texas, Utah, Wisconsin and Wyoming.  Volumes transported on the Mid-America Pipeline System primarily originate from natural gas processing facilities located in the Rocky Mountains and Mid-Continent regions, as well as NGL fractionation and storage facilities in Kansas and Texas.

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The Rocky Mountain pipeline transports mixed NGLs from production fields located in the Rocky Mountain Overthrust and San Juan Basin areas 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) located in South Texas to our NGL fractionators in South Texas and NGL fractionation and storage complex located in and near Mont Belvieu, Texas.  The Mont Belvieu area in Chambers County, Texas, with its significant energy-related infrastructure, is a key hub of the global NGL industry (the “Mont Belvieu hub”). 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 is a component of our ethane header system, extending it from the Mont Belvieu hub to Corpus Christi, Texas.

The Dixie Pipeline transports propane and other NGLs and extends from southeast Texas to markets in the southeastern U.S.  Propane supplies transported on this system primarily originate from southeast Texas, south Louisiana and Mississippi.  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 ATEX, or Appalachia-to-Texas Express, 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.  The ethane extracted by these fractionation facilities originates from the Marcellus and Utica Shale production areas.  ATEX operates in nine states: Arkansas, Illinois, Indiana, Louisiana, Missouri, Ohio, Pennsylvania, Texas and West Virginia.

In October 2019, we announced an expansion project on the ATEX pipeline that would increase its transportation capacity from 145 MBPD to 190 MBPD.  The incremental capacity is expected to be achieved through improvements and modifications to existing infrastructure.  We anticipate that this expansion project will be completed in 2022.

The Chaparral NGL System transports mixed NGLs from natural gas processing facilities located in West Texas and New Mexico to Mont Belvieu.  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 located in southern Louisiana.  This system transports 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.

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In January 2019, we completed the conversion of a portion of one of the two pipelines comprising the Seminole NGL Pipeline system from NGL service to crude oil service. The converted segment, which extends from Midland, Texas to Sealy, Texas, makes up substantially all of our Midland-to-ECHO 2 crude oil pipeline.  The conversion did not reduce our overall NGL transportation capacity since displaced NGLs are transported using our other NGL pipelines, including our Shin Oak NGL Pipeline.  We have the ability to convert this pipeline back to NGL service should market and physical takeaway conditions warrant.

See “Crude Oil Pipelines & Services Segment – Crude Oil Pipelines” within this Items 1 and 2 for additional information regarding our Midland-to-ECHO System.

The Shin Oak NGL Pipeline (“Shin Oak”) transports NGL production from the Permian Basin to our NGL fractionation and storage complex located at the Mont Belvieu hub.  In February 2019, the mainline segment of Shin Oak from Orla, Texas to Mont Belvieu was placed into limited service with an initial transportation capacity of 250 MBPD.  In June 2019, an additional pipeline segment, the Waha lateral, was placed into service and increased Shin Oak’s transportation capacity to 350 MBPD.  We completed construction of the remaining components of Shin Oak in the fourth quarter of 2019, which increased its transportation capacity to 550 MBPD.

In May 2018, we granted Apache Midstream LLC (“Apache”) an option to acquire up to a 33% equity interest in our consolidated subsidiary that owns Shin Oak.  In November 2018, Apache contributed this option to Altus Midstream Processing LP (“Altus”), which is a consolidated subsidiary of Apache.  In July 2019, Altus exercised the option and acquired a 33% equity interest (effective July 31, 2019) in our subsidiary that owns Shin Oak.  As a result, we received a $440.7 million cash payment from Altus, which is included in contributions from noncontrolling interests as presented on our Statement of Consolidated Cash Flows for the year ended December 31, 2019.

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.  Our 35% ownership interest in the Texas Express Pipeline is held indirectly through our equity method investment in Texas Express Pipeline LLC.

In 2018, we initiated expansion projects to increase transportation capacity on the Texas Express Pipeline and the Front Range Pipeline by 90 MBPD and 100 MBPD, respectively. The expansions, which are expected to be completed and placed into service in the second quarter of 2020, are designed to facilitate growing production of NGLs from domestic shale basins, including the DJ Basin, by providing producers with flow assurance and greater access to Gulf Coast markets.

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.  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.

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. Our 33.3% ownership interest in the Front Range Pipeline is held indirectly through our equity method investment in Front Range Pipeline LLC.  As previously mentioned, we expect to complete an expansion project during the second quarter of 2020 that will increase transportation capacity on the Front Range Pipeline by 100 MBPD.

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.
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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 Rio Grande Pipeline transports mixed NGLs from near Odessa, Texas to a pipeline interconnect at the Mexican border south of El Paso, Texas.  In March 2019, we acquired the remaining 30% ownership interest in the Rio Grande Pipeline.

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.  We own a 55% consolidated interest in the Panola Pipeline through our majority owned subsidiary, Panola Pipeline Company, LLC.

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

The Promix NGL Gathering System gathers mixed NGLs from natural gas processing facilities in southern Louisiana for delivery to our Promix NGL fractionator.  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. (“Promix”).

The Texas Express Gathering System is comprised of two gathering systems, Elk City and North Texas, that deliver mixed NGLs to the Texas Express Pipeline.  Our 45% ownership interest in the Texas Express Gathering System is held indirectly through our equity method investment in Texas Express Gathering LLC.

The Tri-States NGL Pipeline transports mixed NGLs from Mobile Bay, Alabama to points near Kenner, Louisiana.  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.

NGL fractionation
We own or have interests in 16 NGL fractionators located in Texas and Louisiana that separate mixed NGL streams into purity NGL products for third party customers and also our NGL marketing activities.  Mixed NGLs extracted by domestic natural gas processing facilities represent the largest source of volumes processed by 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, along the Gulf Coast and in the Rocky Mountains and Mid-Continent regions, will be available for fractionation in commercially viable quantities for the foreseeable future.  Significant volumes of mixed NGLs are contractually committed to be processed at our NGL fractionators by joint owners and third party customers.

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

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The following table presents selected information regarding our NGL fractionation facilities at February 1, 2020:

   
Net Plant
Total Plant
   
Ownership
Capacity
Capacity
Description of Asset
Location
Interest
(MBPD) (1)
(MBPD)
NGL fractionation facilities:
       
Mont Belvieu complex:
       
   Fracs I, II and III
Texas
  75.0% (2)
189
245
   Fracs IV, V, VI , and IX
Texas
100.0%
345
345
   Fracs VII and VIII
Texas
  75.0% (3)
128
170
   Total Mont Belvieu complex
   
662
760
Shoup and Armstrong
Texas
100.0%
93
93
Hobbs
Texas
100.0%
75
75
Norco
Louisiana
100.0%
75
75
Promix
Louisiana
  50.0%
73
145
Tebone
Louisiana
100.0%
30
30
Baton Rouge
Louisiana
  32.2%
19
60
   Total
   
1,027
1,238

(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.

On a weighted-average basis, overall utilization rates for our NGL fractionators were 97.8%, 94.0% and 91.0% during the years ended December 31, 2019, 2018 and 2017, respectively.

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

The Mont Belvieu NGL fractionation complex includes fractionators located either in Mont Belvieu, Texas or in surrounding areas of Chambers County, Texas.  This complex processes 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.  In addition, the Mont Belvieu NGL fractionation complex features connectivity 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.   Demand for NGL fractionation capacity continues to expand as producers in domestic shale plays such as the Permian Basin, Eagle Ford Shale and DJ Basin seek market access and end users require supply assurance.

In November 2018, we announced plans to construct a new NGL fractionation facility in Chambers County, Texas adjacent to our existing Mont Belvieu NGL fractionation complex.  The new facility consists of two fractionation trains capable of processing a combined 300 MBPD of NGLs. The first of the two fractionation trains, referred to as “Frac X,” has a nameplate capacity of 150 MBPD and is expected to enter service in the first quarter of 2020. The second of these fractionation trains, referred to as “Frac XI,” will also have a nameplate capacity of 150 MBPD, and is scheduled to begin service in the third quarter of 2020.  We will own and operate both Frac X and Frac XI.  Once Frac XI enters service, total NGL fractionation capacity at our Mont Belvieu complex will approximate 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 the Shoup and Armstrong 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.

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In November 2018, we announced a project to optimize our Shoup NGL fractionator by expanding and repurposing a portion of our South Texas pipeline infrastructure. The project entailed the construction of approximately 20 miles of new pipeline along with the conversion of approximately 60 miles of existing natural gas pipelines to NGL service.  The expansion project, which allows us to supply Shoup with an additional 25 MBPD of NGL volumes, was completed in the second quarter of 2019.

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.

The Promix NGL fractionator receives mixed NGLs from natural gas processing facilities located in south Louisiana and along the Mississippi Gulf Coast, including our Neptune and Pascagoula plants. The Promix NGL fractionation facility includes three NGL storage caverns and a barge dock that are integral to its operations.  Our 50% ownership interest in the Promix fractionator is held indirectly through our equity method investment in Promix.

The Tebone NGL fractionator, which was restarted in February 2019 in light of regional demand for fractionation services, receives mixed NGLs from our Louisiana natural gas processing facilities, as well as our Mont Belvieu storage complex.  The resumption of service at our Tebone fractionator complements our operations at the Norco and Promix NGL fractionators and provides us with another processing option for mixed NGLs delivered to Mont Belvieu.

The Baton Rouge NGL fractionator receives mixed NGLs from natural gas processing facilities located in Alabama, Mississippi and south Louisiana.  This facility includes a leased NGL storage cavern. Our 32.2% ownership interest in the Baton Rouge fractionator is held indirectly through our equity method investment in Baton Rouge Fractionators LLC.

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 level of associated fees we charge.

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The following table presents selected information regarding our NGL and related product storage assets at February 1, 2020:

   
Net Usable
     
Storage
   
Ownership
Capacity
Description of Asset
Location
Interest
(MMBbls) (1)
Mont Belvieu storage complex
Texas
100.0%
129.8
Almeda and Markham (2)
Texas
Leased
12.4
Breaux Bridge, Anse La Butte and Sorrento (3)
Louisiana
100.0%
12.7
Petal (4)
Mississippi
100.0%
5.4
Hutchinson (5)
Kansas
100.0%
4.0
Others (6)
Various
Various
14.2
   Total
   
178.5

(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 South Texas NGL Pipeline System.
(3)
These storage facilities are used in connection with our Louisiana 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 export and import terminals for NGLs. The results of operations from these facilities, all of which are located on the Houston Ship Channel, are primarily dependent upon the level of volumes handled and the associated loading/unloading fees we charge for such services.

The following information describes our Houston Ship Channel terminals, both of which we operate.

The Enterprise Hydrocarbons Terminal (“EHT”) is located on the Houston Ship Channel and 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 and one barge 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 and dock 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 such as the Permian Basin and Eagle Ford Shale, international demand for propane as a feedstock in ethylene production and for power generation and heating purposes.  LPG loading volumes at EHT averaged 483 MBPD, 445 MBPD and 424 MBPD during the years ended December 31, 2019, 2018 and 2017, respectively.

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Our current maximum estimated loading capacity for LPG at EHT is approximately 835 MBPD, with 175 MBPD of this loading capacity placed into service during the third quarter of 2019.  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.  In 2019, we commenced construction on an expansion project at EHT that is currently expected to increase our LPG loading capacity by an additional 265 MBPD.  When this latest expansion project is completed in the second half of 2021, EHT will have a new maximum LPG loading capacity of approximately 1.1 MMBPD, or 33 MMBbls per month.

The primary customer of EHT is our NGL marketing group, which uses EHT 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 14,000 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, petrochemical and refined products.  EHT’s assets and activities associated with crude oil terminaling and storage are classified and presented as a component of our Crude Oil Pipelines & Services business segment.  EHT’s activities associated with petrochemicals and refined products are classified and described within our Petrochemical & Refined Products Services business segment.

The Morgan’s Point Ethane Export Terminal, located on the Houston Ship Channel, has an aggregate loading rate (nameplate 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 NGL fractionation and storage complex.  Ethane loading volumes at the terminal averaged 143 MBPD, 146 MBPD and 90 MBPD during the years ended December 31, 2019, 2018 and 2017, respectively.

Crude Oil Pipelines & Services Segment

Our Crude Oil Pipelines & Services business segment currently includes approximately 5,300 miles of 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 providing crude oil transportation services is primarily dependent upon the volume handled (or capacity reserved) and the level of fees charged (typically on a per barrel basis). 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 discussion for additional information regarding governmental oversight of our crude oil pipelines and storage facilities.

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The following table presents selected information regarding our crude oil pipelines and related operations at February 1, 2020:

   
Operational
 
   
Our
Storage
Pipeline
   
Ownership
Capacity
Length
Description of Asset
Location(s)
Interest
(MMBbls) (2)
(Miles)
Seaway Pipeline (1)
Texas, Oklahoma
    50.0%
9.8
1,271
West Texas System (1)
Texas, New Mexico
  100.0%
1.1
1,061
Midland-to-ECHO System
Texas
 Various (3)
3.9
862
South Texas Crude Oil Pipeline System
Texas
  100.0%
4.2
648
Basin Pipeline (1)
Texas, New Mexico, Oklahoma
   13.0% (4)
6.0
618
EFS Midstream System
Texas
  100.0%
0.3
486
Eagle Ford Crude Oil Pipeline System
Texas
    50.0%
4.5
380
   Total
   
29.8
5,326

(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)
We own an 80% consolidated equity interest in the 418-mile Midland-to-ECHO 1 pipeline through our majority owned subsidiary, Whitethorn Pipeline Company LLC (“Whitethorn”).   We own 100% of the 444-mile Midland-to-ECHO 2 pipeline.
(4)
We proportionately consolidate our 13% undivided interest in the Basin Pipeline.

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 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 2,304 MBPD, 2,000 MBPD and 1,820 MBPD during the years ended December 31, 2019, 2018 and 2017, respectively.

The following information describes our principal crude oil pipelines, all of which we operate with the exception of the Basin Pipeline and Eagle Ford Crude Oil Pipeline System.

The Seaway Pipeline connects the Cushing, Oklahoma crude oil hub with markets in southeast Texas. Our 50% ownership interest in the Seaway Pipeline is held indirectly through our equity method investment in Seaway Crude Holdings LLC (“Seaway”). 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 West Texas Intermediate (“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 Enterprise Crude Houston (“ECHO”) storage 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.

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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.  The Loving County pipeline can currently transport 200 MBPD of crude oil and condensate from various points in New Mexico and West Texas to our Midland crude oil terminal; however, we expect to complete an expansion project by March 2020 that will increase its transportation capacity up to 350 MBPD. At Midland, shippers will 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 Midland-to-ECHO System, which is currently comprised of our Midland-to-ECHO 1 and 2 pipelines, 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 transports multiple grades of crude oil, including WTI, WTI light sweet crude oil (“West Texas Light”), West Texas Sour, and condensate, to our ECHO terminal (using batched shipments to safeguard crude quality) for further delivery to markets along the Gulf Coast.

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.  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 also includes certain storage assets located at Sealy, Texas.  The pipeline entered limited service in November 2017 and full service in April 2018.   As a result of operating enhancements and supplementary infrastructure completed in March 2019, the Midland-to-ECHO 1 pipeline currently has a transportation capacity of 620 MBPD.

The majority of the Midland-to-ECHO 1 pipeline is owned by Whitethorn, in which we own an 80% equity interest.  In June 2018, an affiliate of Western Gas Partners, LP acquired a 20% equity interest in Whitethorn for $189.6 million in cash.

In January 2019, we completed the conversion of the Midland-to-Sealy segment of one of our two Seminole NGL pipelines from NGL service to crude oil service, thus creating the Midland-to-ECHO 2 pipeline.  The 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, which was placed into limited service in February 2019 and full service in April 2019, provides us with up to 225 MBPD of incremental crude oil transportation capacity.  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.

In July 2019, we announced an expansion of our Midland-to-ECHO System that we refer to as the “Midland-to-ECHO 3” pipeline, which is comprised of a 36-inch pipeline we are currently constructing from Midland, Texas to our ECHO terminal and further to a third-party terminal in Webster, Texas (“Midland-to-Webster”).  We expect the Midland-to-ECHO segment of Midland-to-Webster to be placed into service during the third quarter of 2020, with the ECHO-to-Webster segment following in the fourth quarter of 2020.  Prior to completion of the ECHO-to-Webster segment, our transportation capacity will be 200 MBPD.  Once Midland-to-Webster is placed into full commercial service, our transportation capacity is expected to increase to approximately 450 MBPD.  We proportionately consolidate our 29% undivided interest in Midland-to-Webster.

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In October 2019, we announced plans to construct a fourth pipeline (the “Midland-to-ECHO 4” pipeline) that will connect our Midland terminal with our ECHO terminal in Houston, Texas by utilizing existing segments of our South Texas Crude Oil Pipeline System along with new construction.  The Midland-to-ECHO 4 pipeline is expected to be completed and placed into service during the second quarter of 2021 and have an initial transportation capacity of 450 MBPD (expandable up to 540 MBPD).

When placed into service, the Midland-to-ECHO 4 pipeline will allow our shippers with crude oil and condensate production in both the Permian Basin and the Eagle Ford Shale to maximize the value of their contracted pipeline capacity by allowing shippers to source barrels from the Permian Basin and/or the Eagle Ford Shale.  This unmatched flexibility will allow shippers and producers to dynamically match their pipeline capacity to their allocation of capital and respective production profiles between the two basins. Their production will be delivered into our integrated storage, pipeline, distribution and marine terminal system that has access to both domestic and international markets.

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 486 miles of gathering pipelines, 11 central gathering plants having a combined condensate storage capacity of 0.3 MMBbls, 171 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 380 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 recently completed Corpus Christi marine terminal.  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.

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 and the associated loading/unloading fees we charge for such services.

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The following table presents selected information regarding our crude oil terminals at February 1, 2020:

     
Number of
Net Storage
   
Ownership
Number of
Above-Ground
Capacity
Description of Asset
Location(s)
Interest
Marine Docks
Tanks in Service
(MMBbls)
EHT (crude oil)
Texas
100.0%
7 deep-water ship; 1 barge
85
24.2
ECHO (1)
Texas
100.0%
n/a
14
5.9
Beaumont Marine West
Texas
100.0%
4 deep-water ship; 2 barge
12
4.2
Cushing
Oklahoma
100.0%
n/a
18
3.2
Midland
Texas
100.0%
n/a
9
2.6
Corpus Christi
Texas
  50.0%
1 deep-water ship
4
0.7
   Total
     
142
40.8

(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.

The following information describes our principal crude oil terminals, all of which we operate.

The EHT crude oil terminal is one of the largest such facilities on the Gulf Coast and part of our EHT complex, which is located on the Houston Ship Channel and features extensive waterfront access consisting of seven deep-water ship docks and a barge dock.  As noted previously, 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.

In July 2019, we announced plans to add an eighth deep-water ship dock at EHT that is expected to increase our crude oil loading capacity by 840 MBPD, thereby increasing our overall nameplate crude oil loading capacity at EHT to 2.75 MMBPD, or nearly 83 MMBbls per month.  The new dock is designed to accommodate a Suezmax vessel and is scheduled to be placed into service during the fourth quarter of 2020.

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.

In September 2018, the CME Group, a leading derivatives marketplace, announced that suppliers, refiners and end users of U.S. crude oil have a new way to price and hedge WTI in Houston, Texas.  Participants will have the flexibility to make or take delivery of WTI at our ECHO terminal, EHT or pipeline interconnect at Genoa Junction. The futures contracts are listed with and subject to the rules of the NYMEX.

The Beaumont Marine West terminal is located on the Neches River near Beaumont, Texas.  This terminal includes four deep-water docks and two barge docks 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, which commenced operations in the third quarter of 2019, is located in Corpus Christi, Texas and capable of loading ocean-going vessels with either crude oil or condensate.  Initial storage capacity of the terminal is approximately 1.4 MMBbls (0.7 MMBbls net to our ownership interest).  The facility has access to production from both the Eagle Ford Shale and the Permian Basin through a connection with our Eagle Ford Crude Oil Pipeline System.  Our 50% ownership interest in the terminal is held indirectly through our equity method investment in Eagle Ford Terminals Corpus Christi LLC.


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Sea Port Oil Terminal.  In July 2019, we announced the execution of long-term customer agreements with Chevron U.S.A. Inc. (“Chevron”) supporting the development of our Sea Port Oil Terminal (“SPOT”) in the Gulf of Mexico.  As a result of the Chevron 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.

The SPOT project consists of 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 Segment

Our Natural Gas Pipelines & Services business segment currently includes approximately 19,400 miles of natural gas pipeline systems that provide for the gathering, treating and transportation of natural gas in Colorado, Louisiana, New Mexico, Texas and Wyoming.  This segment also includes our natural gas marketing activities.

Natural gas pipelines and related storage assets
Our natural gas pipeline systems gather, treat and transport natural gas from producing regions including the Permian Basin, Eagle Ford Shale, Haynesville Shale, and the Piceance, San Juan and Greater Green River supply basins. In addition, certain of these pipelines receive natural gas production from Gulf of Mexico developments. Our natural gas pipelines redeliver the natural gas to processing facilities, electric generation plants, local gas distribution companies, industrial and municipal customers, storage facilities or other onshore 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 associated fees we charge for such activities.  Transportation fees charged to shippers (typically per MMBtu of natural gas) 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 discussion for additional information regarding governmental oversight of our natural gas pipelines.

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The following table presents selected information regarding our natural gas pipelines and related infrastructure at February 1, 2020:

     
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
6,916
7,345
80
12.9
Acadian Gas System (2)
Louisiana
 100.0%
1,312
3,100
1.3
Jonah Gathering System
Wyoming
 100.0%
761
2,360
Piceance Basin Gathering System
Colorado
 100.0%
191
1,800
San Juan Gathering System
New Mexico, Colorado
 100.0%
6,078
1,750
420
Permian Basin Gathering System
Texas, New Mexico
 100.0%
1,681
1,575
150
White River Hub (3)
Colorado
   50.0%
10
1,500
Haynesville Gathering System
Louisiana, Texas
 100.0%
360
1,300
810
BTA Gathering System (4)
Texas
 100.0%  (5)
723
925
160
Indian Springs Gathering System (4)
Texas
   80.0%  (6)
145
160
Delmita Gathering System
Texas
 100.0%
201
145
South Texas Gathering System
Texas
 100.0%
518
143
220
Old Ocean Pipeline
Texas
   50.0%
240
80
Big Thicket Gathering System
Texas
 100.0%
250
60
Central Treating Facility
Colorado
 100.0%
200
   Total
   
19,386
22,243
2,040
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)
This system includes approximately 52 miles of pipeline held under an operating lease.
(6)
We proportionately consolidate our 80% undivided interest in the Indian Springs Gathering System.

On a weighted-average basis, overall utilization rates for our natural gas pipelines were approximately 60.0%, 58.3% and 57.1% during the years ended December 31, 2019, 2018 and 2017, 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.

The following information describes our principal natural gas pipelines.  With the exception of the White River Hub and certain segments of the Texas Intrastate System, we operate our natural gas pipelines and storage facilities.

The Texas Intrastate System is comprised of the 6,299-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.

In January 2019, we completed an expansion project on the 36-inch diameter North Texas pipeline (a component of the Texas Intrastate System) that provides us with an additional 150 MMcf/d of natural gas takeaway capacity from West Texas, including deliveries into the reactivated Old Ocean Pipeline.

We proportionately consolidate our undivided interests, which range from 22% to 80%, in 1,471 miles of pipeline.  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.

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The Acadian Gas System transports, stores and markets natural gas in Louisiana.  The Acadian Gas System is comprised of the 582-mile Cypress pipeline, 429-mile Acadian pipeline, 275-mile Haynesville Extension pipeline and 26-mile Enterprise Pelican pipeline.  The Acadian Gas System includes a leased underground salt dome natural gas storage cavern located at Napoleonville, Louisiana.  The Acadian Gas System links natural gas supplies from Louisiana (e.g., from 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 15 Bcf/d of export capacity. The Gillis Lateral will 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 third 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 (if dry natural gas) or to regional natural gas plants, including our Chaco facility, for further processing (if rich natural gas) prior to being transported on interstate pipelines.

The Permian Basin Gathering System is comprised of the 993-mile Carlsbad pipeline system, the 636-mile Waha pipeline system, the 34-mile Orla pipeline system and the 18-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.  Our 50% ownership interest in White River Hub is held indirectly through our equity method investment in White River Hub, LLC.

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.

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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 into our Texas Intrastate System, which delivers the natural gas 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.  Our 50% ownership interest in the Old Ocean Pipeline is held indirectly through our equity method investment in Old Ocean Pipeline, LLC.  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.

Petrochemical & Refined Products Services Segment

Our Petrochemical & Refined Products Services business segment currently includes:

propylene production facilities, which include propylene fractionation units and a propane dehydrogenation (“PDH”) facility, approximately 800 miles of pipelines, and related marketing activities;

a butane isomerization complex and related deisobutanizer (“DIB”) operations, along with approximately 70 miles of associated pipelines;

isobutane dehydrogenation (“iBDH”), octane enhancement and high purity isobutylene (“HPIB”) production facilities;
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refined products pipelines aggregating approximately 3,300 miles, terminals and related marketing activities;

an ethylene export terminal and related operations; and

marine transportation.

Propylene production facilities and related operations
Our propylene production and related operations include seven propylene fractionation (or splitter) units, a PDH facility, approximately 800 miles of related pipelines, marine export dock infrastructure, and related 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 (“PGP”) with a minimum purity of 99.5%; chemical grade (“CGP”) with a minimum purity of approximately 93-94%; and refinery grade (“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, 2020:

 
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:
       
Mont Belvieu – 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 ownership interest in the BRPC facility is held indirectly through our equity method investment in Baton Rouge Propylene Concentrator LLC (“BRPC”).

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We produce PGP at our propylene fractionation units and PDH 1 facility located at the Mont Belvieu hub and CGP at our BRPC facility located in Baton Rouge, Louisiana.  On a weighted-average basis, the overall utilization rate of our propylene production facilities was approximately 86.7%, 86.7% and 89.9% during the years ended December 31, 2019, 2018 and 2017, 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 current PDH facility (“PDH 1”), which entered service in April 2018.  The 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 consumes 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”).  Like PDH 1, the new plant is expected to have the capacity to consume 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 first 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 level of fees charged to shippers.  The following table presents selected information regarding our propylene pipelines at February 1, 2020:

 
Ownership
Length
Description of Asset
Location(s)
Interest
(Miles)
Lou-Tex Propylene Pipeline
Texas, Louisiana
  100.0%
263
Texas City RGP Gathering System
Texas
  100.0%
157
North Dean Pipeline 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
   
794

(1)
We proportionately consolidate our 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 124 MBPD, 125 MBPD and 106 MBPD during the years ended December 31, 2019, 2018 and 2017, respectively.

The Lou-Tex Propylene pipeline is used to transport CGP from Sorrento, Louisiana to Mont Belvieu.  In June 2015, we announced plans to convert the Lou-Tex Propylene pipeline from CGP to PGP service.  This conversion is scheduled for completion in the second quarter of 2020.
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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.  This business includes export assets located at EHT that are currently capable of loading up to 2,500 barrels per hour, or 60 MBPD, of semi-refrigerated product.  In July 2019, we announced plans to increase our export capacity at EHT for semi- or fully-refrigerated PGP.  This project is currently expected to increase our export capacity by 3,500 barrels per hour, or approximately 84 MBPD.  With the addition of fully refrigerated volumes, this expansion project will enable EHT to co-load fully refrigerated PGP and LPG volumes onto the same vessel. This expansion project is expected to be placed into service during the second half of 2021.

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.  These operations also include a 70-mile pipeline system used to transport high-purity isobutane from the Mont Belvieu hub to Port Neches, Texas.  We own and operate this pipeline system.

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 nine 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 94.0%, 92.2% and 92.2% during the years ended December 31, 2019, 2018 and 2017, respectively.

In January 2018, we announced plans to expand our butane isomerization facility by up to 30 MBPD of incremental capacity.  The expansion is supported by long-term agreements to provide butane isomerization, storage and related pipeline services.  We currently expect this project to be completed in the first quarter of 2022.

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 22 MBPD, 24 MBPD and 23 MBPD during the years ended December 31, 2019, 2018 and 2017, respectively.

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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 77.6%, 88.9% and 75.9% for the years ended December 31, 2019, 2018 and 2017, 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 will enable 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 3,252-mile pipeline system comprised of 2,927 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 additional 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,
 
   
2019
   
2018
   
2017
 
Refined products transportation (MBPD)
   
407
     
456
     
456
 
Petrochemical transportation (MBPD)
   
126
     
148
     
156
 
NGL transportation (MBPD)
   
63
     
71
     
57
 

The TE Products Pipeline system includes five non-regulated refined products truck terminals and 19.6 MMBbls of aggregate storage capacity.
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In December 2019, we recorded a $76.4 million impairment charge to fully write-off our 50% equity method investment in Centennial Pipeline LLC (“Centennial”), which owns the Centennial Pipeline and related terminal infrastructure. These assets were idled in 2013 while management investigated multiple capital project opportunities to repurpose the pipeline. Due to recent declines in the viability of potential commercial transactions involving the pipeline, we concluded that our investment was not recoverable and had no remaining fair value at December 31, 2019.  We continue to own a 50% equity interest in the Centennial Pipeline, which is being maintained in an idled state in accordance with governmental regulations.

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 10.9 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 2.0 MMBbls of aggregate storage capacity through the use of 24 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 2019, we placed our ethylene export terminal into limited service, with the first cargo of 25 million pounds of ethylene exported in January 2020. The terminal, which we operate, is located at our Morgan’s Point facility on the Houston Ship Channel and features two docks and the capacity to load 2.2 billion pounds of ethylene per year. A refrigerated storage tank for 66 million pounds of ethylene is being constructed on-site that will allow the terminal to load ethylene up to a rate of 2.2 million pounds per hour. Full commercial operations at the terminal are expected in the fourth quarter of 2020 once certain refrigeration assets are complete.  We own a 50% member interest in Enterprise Navigator Ethylene Terminal LLC, which owns the export facility.

Our ethylene system is being developed to serve as an open market storage and trading hub for the ethylene industry using storage capacity, connections to multiple ethylene pipelines, and high-volume export capabilities.  In support of our ethylene business, we recently placed into service a high-capacity underground ethylene storage well at our Mont Belvieu complex having a storage capacity of 600 million pounds of ethylene. The storage well is connected to our Morgan’s Point ethylene export terminal by a 16-mile pipeline, which was placed into service in December 2019.  An additional nine miles of ethylene pipelines extending from Morgan’s Point to Bayport, Texas are under construction and expected to be completed and placed into service in the fourth quarter of 2020.

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, Texas 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 the fourth quarter of 2020.  We will own a 70% interest in and operate the Baymark pipeline.  Customers using the Baymark pipeline will have access to our high-capacity ethylene storage well in Mont Belvieu and our export terminal at Morgan’s Point.


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Marine transportation
Our marine transportation business consists of 66 tow boats and 153 tank barges used to transport refined products, crude oil, asphalt, condensate, heavy fuel oil, LPG and other petroleum products along 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 (e.g., set day rates or fee per cargo movement) to transport petroleum products.

Our fleet of marine vessels operated at an average utilization rate of 94.0%, 93.5% and 86.3% during the years ended December 31, 2019, 2018 and 2017, 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.


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.

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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 extends the PHMSA’s statutory mandate through 2019 and 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.

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.

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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 becomes 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 and requiring operators to report maximum allowable operating pressure 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, becomes effective on July 1, 2020, and imposes numerous requirements on such pipelines, including maximum allowable operating pressure (“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 remaining rulemakings comprising the gas mega rule are expected to be issued in 2020.

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 or the SAFE PIPES Act, or legislation that is expected to be introduced to reauthorize PHMSA pipeline safety programs, 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 the 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.
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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.  See Part I, Item 3 of this annual report for additional information.

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.

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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.

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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%.  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 October 2016, the FERC issued an Advance Notice of Proposed Rulemaking that sought comments regarding potential modifications to its policies for evaluating changes in oil pipeline indexed rates and the associated reporting requirements. The FERC observed that some pipelines continue to obtain additional index rate increases despite reporting on Form No. 6 that their revenues exceed their costs. The FERC is considering whether to propose a new policy that would deny proposed index increases if a pipeline’s Form No. 6 reflects (i) revenues that exceed the total cost-of-service by 15% for the two preceding years or (ii) the proposed increase in the rate index exceeds the percentage change in the pipeline’s annual costs by 5%. The FERC is also considering requiring pipelines to file additional information for crude and refined product pipelines, non-contiguous systems and major pipeline systems.  Comments on these proposals were filed with the FERC through March 2017; however, the FERC has taken no position at this time and we are unable to predict the outcome of this proceeding.

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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. Two third parties filed petitions for review of the Revised Policy and Order on Rehearing in the D.C. Circuit in September 2018 and the matters are pending.  We are unable to predict the outcome of these pending proceedings.

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 oil and liquid pipelines with rates set using the indexing methodology, given that the current index will remain in effect through June 30, 2021. However, following issuance of the Revised Policy, the FERC now requires oil and liquids pipelines owned by MLPs to remove the ITA from their cost-of-service reporting in FERC Form No. 6.  The FERC has stated that it will incorporate the effects of this change when it commences its next five-year review of the oil pipeline index in 2020, for rates that will take effect on July 1, 2021.  The FERC has not yet commenced this proceeding and we are unable predict the outcome at this time.

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 distri