ENTERPRISE PRODUCTS PARTNERS L.P. - Annual Report: 2019 (Form 10-K)

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

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___  to  ___.

ENTERPRISE PRODUCTS PARTNERS L.P.

(Exact name of Registrant as Specified in Its Charter)

 

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

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 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.

ENTERPRISE PRODUCTS PARTNERS L.P.

TABLE OF CONTENTS

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:

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.

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, 10^th 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:

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.

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.

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:

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.

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.

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

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.

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.

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.

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

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 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.

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.

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.

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.

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.

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.

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

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.

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.

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.

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.

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

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.

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.

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.

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.

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.

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.

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

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 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.

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 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.

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.

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.

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

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

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.

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.

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.

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.

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.

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

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.

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.

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.

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:

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:

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:

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.

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.

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.

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.

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.

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:

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

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.

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.

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.

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.

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.

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.

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

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

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

On occasion, we are assessed monetary sanctions by governmental authorities related to administrative or judicial proceedings involving environmental matters.  See Part I, Item 3 of this annual report for additional information.

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.

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

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

Contamination resulting from spills or releases of petroleum products is an inherent risk within the pipeline industry.

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

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

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.

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

FERC Regulation – Liquids Pipelines

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

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

The rates charged for our interstate liquids pipeline services are generally based on a FERC-approved indexing methodology, which allows a pipeline to charge rates up to a prescribed ceiling that changes annually based on the year-to-year change in the U.S. Producer Price Index for Finished Goods (“PPI”).  A rate increase within the indexed rate ceiling is presumed to be just and reasonable unless a protesting party can demonstrate that the rate increase is substantially in excess of the pipeline’s operating costs.  For the five-year period ending June 30, 2021, we are permitted to adjust the indexed rate ceiling annually by PPI plus 1.23%.  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.

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 distribution company served by an interstate pipeline, without becoming subject to the FERC’s broader regulatory authority under the Natural Gas Act of 1938 (“NGA”).  These services must be provided on an open and nondiscriminatory basis, and the rates charged for these services may not exceed a “fair and equitable” level as determined by the FERC in periodic rate proceedings.

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

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

The resale of natural gas in interstate commerce is subject to FERC oversight.  In order to increase transparency in natural gas markets, the FERC has established rules requiring the annual reporting of data regarding natural gas sales.  The FERC has also established regulations that prohibit manipulation of energy markets.  A violation of the FERC’s regulations may subject us to civil penalties, suspension or loss of authorization to perform services or make sales of natural gas, disgorgement of unjust profits or other appropriate non-monetary remedies imposed by the FERC.  Pursuant to the Energy Policy Act of 2005, the potential civil and criminal penalties for any violation of the NGPA, or any rules, regulations or orders of the FERC, were $1.2 million per day per violation as of January 2018.  The Federal Trade Commission and the Commodity Futures Trading Commission (“CFTC”) have also issued rules and regulations prohibiting energy market manipulation.  We believe that our natural gas sales activities are in compliance with all applicable regulatory requirements.

State Regulation of Pipeline Transportation Services

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

Federal Regulation of Marine Operations

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

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

Climate Change Discussion

There is considerable discussion over climate change and the environmental effects of greenhouse gas emissions and their associated consequences on global climate, oceans and ecosystems.  As a commercial enterprise, we are not in a position to validate or repudiate the existence of global warming or various aspects of the scientific discussion.  However, if global warming is occurring, it could have a long-term impact on our operations.  For example, our facilities that are located in low lying areas such as the coastal regions of Louisiana and Texas may be at increased risk due to flooding, rising sea levels, or disruption of operations from more frequent and severe weather events.  Facilities in areas with limited water availability may be impacted if droughts become more frequent or severe.  Changes in climate or weather may hinder exploration and production activities or increase the cost of production of oil and gas resources and consequently affect the volume of hydrocarbon products entering our system.  Changes in climate or weather may also affect consumer demand for energy or alter the overall energy mix.

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

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

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

Competition

NGL Pipelines & Services

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

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

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

Crude Oil Pipelines & Services

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

Natural Gas Pipelines & Services

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

Petrochemical & Refined Products Services

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

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

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

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

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

Seasonality

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

Title to Properties

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

Available Information

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

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

ITEM 1A.  RISK FACTORS.

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

Risks Relating to Our Business

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

Crude oil and natural gas prices have been volatile in recent years.  For example, crude oil prices (based on WTI as measured by the NYMEX) ranged from a high of $76.41 per barrel to a low of $42.53 per barrel in the three year period ending December 31, 2019.  WTI prices in 2020 have ranged from a high of $63.27 per barrel to a low of $49.57 per barrel through February 10, 2020.  Likewise, natural gas prices (based on Henry Hub as measured by the NYMEX) ranged from a high of $4.84 per MMBtu to a low of $2.07 per MMBtu over the same three-year period.   Henry Hub natural gas prices in 2020 have ranged from a high of $2.20 per MMBtu to a low of $1.77 per MMBtu through February 10, 2020.

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

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

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

For a discussion regarding our current fundamentals outlook for 2020, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Outlook for 2020” included under Part II, Item 7 of this annual report.

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

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

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

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

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

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

As of December 31, 2019, we had $24.75 billion in principal amount of consolidated senior long-term debt outstanding and $2.65 billion in principal amount of junior subordinated debt outstanding.  The amount of our future debt could have significant effects on our operations, including, among other things:

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

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

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

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

We will require substantial new capital to finance the future development and acquisition of assets and businesses.  For example, our capital investments for 2019 reflected $4.66 billion of cash payments for capital projects and other investments.  Based on information currently available, we expect our total capital investments for 2020 to approximate $3.4 billion to $4.4 billion, which includes approximately $400 million for sustaining capital expenditures. Any limitations on our access to capital may impair our ability to execute this growth strategy.  If our cost of debt or equity capital becomes too expensive, our ability to develop or acquire accretive assets will be limited.  We also may not be able to raise the necessary funds on satisfactory terms, if at all.  

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

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

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

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

One of the ways we intend to grow our business is through the construction of new midstream energy infrastructure assets.  The construction of new assets involves numerous operational, regulatory, environmental, political, legal and economic risks beyond our control and may require the expenditure of significant amounts of capital.  These potential risks include, among other things, the following:

 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

At December 31, 2019, we had $27.15 billion in principal amount of consolidated fixed-rate debt outstanding, including current maturities thereof.  Due to the short term nature of commercial paper notes, we view the interest rates charged in connection with these instruments as variable.

The Board of Governors of the Federal Reserve System raised benchmark interest rates three times during 2017, four times during 2018, and again in early 2019 before lowering rates three times by the end of 2019.  Should interest rates increase significantly, the amount of cash required to service our debt (including any future refinancing of our fixed-rate debt instruments) would increase.  Additionally, from time to time, we may enter into interest rate swap arrangements, which could increase our exposure to variable interest rates.  As a result, significant increases in interest rates could have a material adverse effect on our financial position, results of operations and cash flows.

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

We currently do not expect the transition from LIBOR to have a material impact on us.  However, if clear market standards and transition methodologies have not developed by the time LIBOR becomes unavailable, we may have difficulty reaching agreements on acceptable replacement rates.  If we are unable to negotiate replacement rates on favorable terms, it could have an adverse effect on our results of operations and cash flows.

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

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

In total, our pipeline integrity costs for the years ended December 31, 2019, 2018 and 2017 were $110.6 million, $122.0 million and $91.1 million, respectively.  Of these annual totals, we charged $56.4 million, $71.8 million and $52.3 million to operating costs and expenses during the years ended December 31, 2019, 2018 and 2017, respectively.  The remaining annual pipeline integrity costs were capitalized and treated as sustaining capital projects.  We expect the cost of our pipeline integrity program, regardless of whether such costs are capitalized or expensed, to approximate $122 million for 2020.

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

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

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

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

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

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

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

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

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

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

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

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

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

The FERC uses prescribed rate methodologies for approving regulated tariff rate changes for interstate liquids pipelines.  The FERC’s indexing methodology currently allows a pipeline to increase its rates by a percentage linked to the PPI.  For the five-year period ending June 30, 2021, the index is measured by the year-over-year change in the Bureau of Labor’s producer price index for finished goods, plus 1.23%.  However, in any year in which the index is negative, a pipeline must file to lower its rates if its rates would be above the indexed rate ceiling.  As an alternative to this indexing methodology, we may also choose to support our rates based on a cost-of-service methodology, or by obtaining advance approval to charge “market-based rates,” or by charging “settlement rates” agreed to by all affected shippers.  These methodologies may limit our ability to set rates based on our actual costs or may delay the use of rates reflecting increased costs.  

In October 2016, the FERC issued an Advanced Notice of Proposed Rulemaking (the “ANOPR”) 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 ANOPR remains pending.  If adopted, changes in the FERC’s methodology for approving rates, or challenges to our application of that methodology, could adversely affect us.  Adverse decisions by the FERC in approving our regulated rates could adversely affect our  financial position, results of operations and cash flows.

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

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

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

In September 2012, the U.S. District Court for the District of Columbia vacated and remanded the position limits rules adopted by the CFTC based on a necessity finding.  In December 2013, the CFTC responded by proposing amended rules in an effort to better conform to the Dodd-Frank Act and in December 2016, the CFTC further refined and re-proposed rules on position limits.  Under the re-proposed rules, the CFTC would place volumetric limitations on certain positions in 25 core physical commodity futures contracts and their economically equivalent futures, options and swaps.  While we believe that the majority of our hedging transactions would meet one or more of the enumerated categories for Bona Fide Hedges, the rules could have an adverse impact on our ability to hedge certain risks associated with our business and could potentially affect our profitability. The comment period on the re-proposed rules closed on February 28, 2017, and the proposal remains pending.

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

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

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

Risks Relating to Our Partnership Structure

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

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

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

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

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

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

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

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

Unitholders’ voting rights are further restricted by a provision in our partnership agreement stating that any units held by a person that owns 20% or more of any class of our common units then outstanding, other than our general partner and its affiliates, cannot be voted on any matter.  In addition, our partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence our management.  As a result of this provision, the trading price of our common units may be lower than other forms of equity ownership because of the absence of a takeover premium in the trading price.

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

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

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

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

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

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

Tax Risks to Common Unitholders

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

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

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, capital, and other forms of business taxes, as well as subjecting nonresident partners to taxation through the imposition of withholding obligations and composite, combined, group, block, or similar filing obligations on nonresident partners receiving a distributive share of state “sourced” income. We currently own property or do business in a substantial number of states. Imposition on us of any of these taxes in jurisdictions in which we own assets or conduct business or an increase in the existing tax rates could substantially reduce the cash available for distribution to our unitholders.

From 2013 through 2017, several publicly traded partnerships merged into their corporate general partner sponsors.  In 2018 and continuing into 2019, the combination of a number of additional factors, including the passage of the Tax Cuts and Jobs Act (the “Tax Act”) of 2017 (which lowered the federal corporate tax rate from 35% to 21% and generally provides for the expensing of certain capital investments and acquisitions), the FERC issuing its Revised Policy Statement on the Treatment of Income Taxes in March 2018, and, generally, continued lower demand and related liquidity for midstream energy companies (including those structured as publicly traded partnerships), led to additional publicly traded partnerships to either (i) merge into their corporate general partner sponsors, (ii) merge into their general partner structured as a partnership and then elect for the combined entity to be taxed as a corporation, or (iii) voluntarily elect to be taxed as a corporation.  These conversions have materially reduced the number of publicly traded partnerships and the total market capitalization and the depth of capital available for the publicly traded partnership sector.

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

In addition, the Tax Act enacted in 2017, made significant changes to the federal income tax rules applicable to both individuals and entities, including changes to the effective tax rate on an individual or other non-corporate unitholder’s allocable share of certain income from a publicly traded partnership. The Tax Act is complex and the Treasury Department and IRS continue to release regulations relating to and interpretive guidance of the legislation contained in the Tax Act.  Thus, unitholders should consult their tax advisor regarding the Tax Act and its effect on an investment in our common units.

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

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

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

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Our general partner would cause us to pay the taxes (including any applicable penalties and interest) directly to the IRS. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own common units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced.

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

If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units.  Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in the unitholder’s common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if the unitholder sells such common units at a price greater than the unitholder’s tax basis in those common units, even if the price received is less than the unitholder’s original cost.  A substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items such as depreciation.  In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of the cash received from the sale.

Investments in our common units by tax-exempt entities, such as individual retirement accounts (“IRAs”) or other retirement plans, and non-U.S. persons raise issues unique to them.  For example, virtually all of our income allocated to unitholders who are organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them.  Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income.

Additionally, gain recognized by a non-U.S. person on the sale of common units occurring on or after November 27, 2017, will generally be treated as effectively connected income and subject to U.S. federal income tax. The transferee of such common units is generally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferee but were not withheld. The IRS has issued proposed regulations that would treat the total cash purchase price for a common unit as the amount realized for purposes of this 10% withholding tax. This withholding tax obligation is currently suspended in the case of a disposition of certain publicly traded partnership interests, including our common units, until 60 days after the proposed regulations are finalized.  A unitholder that is a tax-exempt entity or a non-U.S. person should consult a tax advisor before investing in our common units.

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

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

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

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our respective assets.  Although we may from time to time consult with professional appraisers regarding valuation matters, we make fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our respective assets.  The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the amount, character, and timing of taxable income or loss being allocated to our unitholders.  It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

ITEM 1B.  UNRESOLVED SEC STAFF COMMENTS.

None.

ITEM 3.  LEGAL PROCEEDINGS.

As part of our normal business activities, we may be named as defendants in legal proceedings.  Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully indemnify us against losses arising from legal proceedings.  We will vigorously defend the partnership in litigation matters.  Except as set forth below, we are not aware of any material pending legal proceedings as of the filing date of this annual report to which we are a party, other than routine litigation incidental to our business.

Energy Transfer Matter

In connection with a proposed pipeline project, we and Energy Transfer Partners, L.P. (“ETP”) signed a non-binding letter of intent in April 2011 that disclaimed any partnership or joint venture related to such project absent executed definitive documents and board approvals of the respective companies.  Definitive agreements were never executed and board approval was never obtained for the potential pipeline project.  In August 2011, the proposed pipeline project was cancelled due to a lack of customer support.

In September 2011, ETP filed suit against us and a third party in connection with the cancelled project alleging, among other things, that we and ETP had formed a “partnership.”  The case was tried in the District Court of Dallas County, Texas, 298th Judicial District.  While we firmly believe, and argued during our defense, that no agreement was ever executed forming a legal joint venture or partnership between the parties, the jury found that the actions of the two companies, nevertheless, constituted a legal partnership.  As a result, the jury found that ETP was wrongfully excluded from a subsequent pipeline project involving a third party, and awarded ETP $319.4 million in actual damages on March 4, 2014.  On July 29, 2014, the trial court entered judgment against us in an aggregate amount of $535.8 million, which included (i) $319.4 million as the amount of actual damages awarded by the jury, (ii) an additional $150.0 million in disgorgement for the alleged benefit we received due to a breach of fiduciary duties by us against ETP and (iii) prejudgment interest in the amount of $66.4 million.  The trial court also awarded post-judgment interest on such aggregate amount, to accrue at a rate of 5%, compounded annually.

We filed our Brief of the Appellant in the Court of Appeals for the Fifth District of Dallas, Texas on March 30, 2015 and ETP filed its Brief of Appellees on June 29, 2015.  We filed our Reply Brief of Appellant on September 18, 2015.  Oral argument was conducted on April 20, 2016, and the case was then submitted to the Court of Appeals for its consideration.  On July 18, 2017, a panel of the Dallas Court of Appeals issued a unanimous opinion reversing the trial court’s judgment as to all of ETP’s claims against us, rendering judgment that ETP take nothing on those claims, and affirming our counterclaim against ETP of $0.8 million, plus interest.

On August 31, 2017, ETP filed a motion for rehearing before the Dallas Court of Appeals, which was denied on September 13, 2017.  On December 27, 2017, ETP filed its Petition for Review with the Supreme Court of Texas and we filed our Response to the Petition for Review on February 26, 2018.   On June 8, 2018, the Supreme Court of Texas requested that the parties file briefs on the merits, and the parties filed their respective submittals.  On June 28, 2019, the Supreme Court of Texas requested oral argument, which was held on October 8, 2019. On January 31, 2020, the Supreme Court of Texas issued a unanimous opinion affirming the judgment of the Dallas Court of Appeals.

We did not record a provision for this matter at December 31, 2019 as management believed that payment of damages by us was not probable.

PDH Litigation

In July 2013, we executed a contract with Foster Wheeler USA Corporation (“Foster Wheeler”) pursuant to which Foster Wheeler was to serve as the general contractor responsible for the engineering, procurement, construction and installation of our PDH 1 facility.  In November 2014, Foster Wheeler was acquired by an affiliate of AMEC plc to form Amec Foster Wheeler plc, and Foster Wheeler is now known as Amec Foster Wheeler USA Corporation (“AFW”).  In December 2015, Enterprise and AFW entered into a transition services agreement under which AFW was partially terminated from the PDH 1 project.  In December 2015, Enterprise engaged a second contractor, Optimized Process Designs LLC (“OPD”), to complete the construction and installation of PDH 1.

On September 2, 2016, we terminated AFW for cause and filed a lawsuit in the 151st Judicial Civil District Court of Harris County, Texas against AFW and its parent company, Amec Foster Wheeler plc, asserting claims for breach of contract, breach of warranty, fraudulent inducement, string-along fraud, gross negligence, professional negligence, negligent misrepresentation and attorneys’ fees.  We intend to diligently prosecute these claims and seek all direct, consequential, and exemplary damages to which we may be entitled.

Other

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

In June 2019, we received a Notice of Violation from the U.S. Environmental Protection Agency in connection with regulatory requirements applicable to facilities that we operate in Baton Rouge, Louisiana.  The eventual resolution of this matter may result in monetary sanctions in excess of $0.1 million; however, we do not expect such expenditures to be material to our consolidated financial statements.

ITEM 4.  MINE SAFETY DISCLOSURES.

Not applicable.

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS

AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common units are listed on the NYSE under the ticker symbol “EPD.”  As of January 31, 2020, there were approximately 2,300 unitholders of record of our common units.  For information regarding our quarterly cash distributions to partners, see Note 8 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Recent Issuance of Unregistered Securities

There were no issuances of unregistered equity securities during the year ended December 31, 2019.

Common Units Authorized for Issuance Under Equity Compensation Plan

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

Issuer Purchases of Equity Securities

The following table summarizes our equity repurchase activity during the fourth quarter of 2019:

ITEM 6.  SELECTED FINANCIAL DATA.

The following table presents selected historical consolidated financial data of our partnership.  This information has been derived from and should be read in conjunction with our audited financial statements included under Part II, Item 8 of this annual report.  As presented in the table, amounts are in millions (except per unit data).

Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices.  Energy commodity prices fluctuate for a variety of reasons, including supply and demand imbalances and geopolitical tensions.  For additional information regarding energy commodity prices, see “Selected Energy Commodity Price Data” included under Part II, Item 7 of this annual report.  General information regarding our results of operations can also be found under Part II, Item 7 of this annual report.

Our property, plant and equipment amounts increased over the last five years primarily due to investments in growth capital projects.   For information regarding our capital investment program, see “Capital Investments” included under Part II, Item 7 of this annual report.

Debt increased over the last five years primarily due to the funding of a portion of our capital investments using borrowings under bank credit agreements and the issuance of short- and long-term notes.  For information regarding our debt, see Note 7 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Our equity balances, along with the number of common units outstanding, increased in each of the years presented due to the issuance of units in connection with our at-the-market program, distribution reinvestment plan and employee unit purchase plan. Net proceeds generated from the sale of common units were used to fund a portion of our capital investments.

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

For the Years Ended December 31, 2019, 2018 and 2017

The following discussion and analysis of our financial condition, results of operations and related information for the years ended December 31, 2019 and 2018, including applicable year-to-year comparisons, should be read in conjunction with our Consolidated Financial Statements and accompanying notes included under Part II, Item 8 of this annual report.  Our financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the United States (“U.S.”).

Discussion and analysis of matters pertaining to the year ended December 31, 2017 and year-to-year comparisons between the years ended December 31, 2018 and 2017 are not included in this Form 10-K, but can be found under Part II, Item 7 of our annual report on Form 10-K for the year ended December 31, 2018 that was filed on March 1, 2019. 

Key References Used in this Management’s Discussion and Analysis

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:

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.

Overview of Business

We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.”  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 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 Part I, Items 1 and 2 of this annual report.

We conduct substantially all of our business through EPO and are owned 100% by our 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.  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.

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 and other matters.  For a discussion of the principal effects of such laws and regulations on our business activities, see “Regulatory Matters” included under Part I, Items 1 and 2 of this annual report.

Significant Recent Developments

Enterprise Provides Distribution and Buyback Guidance for 2020

In January 2020, management announced its plans to continue to recommend to the Board of Enterprise GP an increase of $0.0025 per unit per quarter to our cash distribution rate with respect to 2020.  The anticipated rate of increase would result in distributions for 2020 (of $1.805 per unit) being 2.3% higher than those paid with respect to 2019 (of $1.765 per unit).  The payment of any quarterly cash distribution is subject to Board approval and management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments.

In addition, management announced its intention to use approximately 2.0% of net cash flow provided by operating activities, or cash flow from operations (“CFFO”), in 2020 to repurchase EPD common units under the Buyback Program approved in January 2019 (the “2019 Buyback Program”).   For information regarding the 2019 Buyback Program, including repurchases of common units in 2019, see “Liquidity and Capital Resources – Common Unit Buyback Program” within this Part II, Item 7.

Enterprise Begins Service at 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 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.  With Mentone I in operation, we have the capability to process up to 1.6 Bcf/d of natural gas and extract up to 250 MBPD of NGL production from our processing facilities in the Delaware Basin.

On a related note, 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 in July 2019. The Orla facility is capable of processing up to 900 MMcf/d of natural gas and extracting up to 140 MBPD of NGLs.  Like Mentone, the Orla facility and related infrastructure supports continued growth of NGL-rich natural gas production from the Delaware Basin.  We own and operate the Orla facility.

Enterprise Begins Service at Bulldog Natural Gas Processing Plant

In November 2019, we placed our Bulldog cryogenic natural gas processing plant, which is located near Carthage, Texas, 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, Bulldog 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 supports continued growth of natural gas production from the Cotton Valley and Haynesville formations in East Texas.  In addition, the Bulldog plant complements our value chain as the mixed NGLs produced at the plant are transported on the Panola pipeline to Mont Belvieu for fractionation.

Enterprise Begins Service at Isobutane Dehydrogenation Unit

In December 2019, we completed construction and placed our isobutane dehydrogenation (“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 methyl tertiary butyl ether (“MTBE”) and high purity isobutylene (“HPIB”) 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.

Enterprise Begins Service at Ethylene Export Terminal

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 8 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.

Enterprise Announces Final Investment Decision Regarding the 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 Very Large Crude Carriers (“VLCCs”) 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.

In December 2019, we announced the execution of a letter of intent (“LOI”) with an affiliate of Enbridge Inc. (“Enbridge”) to jointly develop our 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.

Enterprise to Build Midland-to-ECHO 4 Pipeline

In October 2019, we announced long-term agreements supporting construction of  the “Midland-to-ECHO 4” pipeline.  The Midland-to-ECHO 4 pipeline will connect our Midland terminal in Midland, Texas with our ECHO terminal in Houston, Texas utilizing both new construction and segments of our existing crude oil pipelines in South Texas.  The Midland-to-ECHO 4 pipeline is expected to enter 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 Midland-to-ECHO 4 pipeline complements our Midland-to-ECHO 1 and 2 pipelines, which entered full service in the second quarter of 2018 and first quarter of 2019, respectively, as well as our Midland-to-ECHO 3 pipeline.  The Midland-to-ECHO 3 pipeline, which is comprised of a 29% undivided interest in 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, is expected to provide 200 MBPD of transportation capacity when placed into service during the third quarter of 2020, increasing to approximately 450 MBPD during the fourth quarter of 2020.  Together, these four projects (Midland-to-ECHO 1, 2, 3 and 4) comprise our Midland-to-ECHO System, which supports crude oil production growth from the Permian Basin (and Eagle Ford Shale, as applicable) by providing producers and other shippers with transportation solutions that are both cost-efficient and operationally flexible.  The Midland-to-ECHO System is expected to include 6 MMBbls of storage at our Midland terminal and access to more than 45 MMBbls of storage and approximately 4 MMBPD of export capacity at partnership assets along the Texas Gulf Coast.  The network connects to every refinery in the Houston, Texas City and Beaumont/Port Arthur area, which we believe represents approximately 8 MMBPD of refining capacity.

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.

Enterprise to Build Second Propane Dehydrogenation (“PDH”) Plant

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”).  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.

Enterprise to Expand and Extend Acadian Gas System

In September 2019, we announced plans to expand and extend our Acadian Gas System in order to deliver growing 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.  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 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.

Shin Oak NGL Pipeline Commences Operations; Altus Acquires 33% Equity Interest in Shin Oak

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 24-inch diameter 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 20-inch diameter 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.

Expansion Projects at EHT

In July 2019, we announced expansion projects at EHT that are expected to increase our loading capacity for crude oil and LPG at the terminal.  With respect to crude oil, we are adding 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, which is the largest ship class that can navigate the Houston Ship Channel, and is scheduled to be placed into service during the fourth quarter of 2020.

With respect to LPG, our current estimated maximum loading capacity at EHT is approximately 835 MBPD, with 175 MBPD of this loading capacity placed into service during the third quarter of 2019. The expansion project announced in July 2019 is currently expected to increase our LPG loading capacity at EHT by an additional 265 MBPD and be placed into service during the second half of 2021.  When this latest expansion project is completed, EHT will have a new maximum LPG loading capacity of approximately 1.1 MMBPD, or 33 MMBbls per month.

In light of growing international demand for PGP, we also announced in July 2019 an expansion project at EHT that is currently expected to increase its export capability for semi- or fully-refrigerated PGP by 3,500 barrels per hour, or approximately 84 MBPD.  Our current loading capacity at EHT for PGP is approximately 2,500 barrels per hour, or 60 MBPD, of semi-refrigerated product.  With the addition of fully refrigerated volumes due to the expansion project, EHT will be able 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.

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.  The following information presents our views on key midstream energy supply and demand fundamentals going into 2020.

Supply Side Observations

The upstream energy industry, led by the efforts of major oil companies, continues to shift resources to shale supply basins.  Domestic shale resources continue to play a key role in both U.S. and global markets, further supporting that the U.S. is a major oil supplier on par with the Organization of Petroleum Exporting Countries (“OPEC”) and Russia.  The U.S. became a net natural gas exporter on an annual basis in 2017, and it continued to export more natural gas than it imported in both 2018 and 2019. We believe that a significant portion of the expected growth in U.S. crude oil, natural gas and NGL production in 2020 will be destined for export markets.

As measured by New York Mercantile Exchange (“NYMEX”), WTI oil prices started 2019 at $45.41 per barrel but rapidly increased to $66.30 per barrel on April 23, 2019 as OPEC and Russia maintained their supply cuts and the U.S. imposed sanctions on Iran, which restricted crude oil exports from that country to a minimum. However, prices subsequently softened as a result of continued trade disputes between the U.S. and other countries, with China in particular. Counteracting these “trade headwinds” was the fact that crude oil production growth in the U.S. was slowing in response to producers cutting back on drilling activities in an effort to preserve cash and enhance their financial condition in a capital-constrained environment. Consequently, WTI prices fluctuated between $51 and $66 per barrel for the rest of 2019.  The WTI oil price finished 2019 at $61.06 per barrel and averaged $57.03 per barrel for all of 2019 compared to an average of $64.77 per barrel for 2018.  WTI prices in 2020 have ranged from a high of $63.27 per barrel to a low of $49.57 per barrel through February 10, 2020.  The forward commodity markets for WTI (as reported by the NYMEX) currently indicate monthly pricing in the range of $51.17 to $52.11 per barrel for periods extending through February 2021.

As reported by the EIA, U.S. crude oil production, having finished 2018 at 12 MMBPD, spent the first seven months of 2019 between 11.7 MMBPD and 12.1 MMBPD.  Nevertheless, U.S. crude oil production accelerated during the latter part of the year at a record high of 12.9 MMBPD in November 2019.  In addition, as reported by the EIA, U.S. production of NGLs increased steadily throughout 2019 and averaged a record 4.8 MMBPD for the year. For 2018, U.S. production of NGLs averaged 4.4 MMBPD. The focus of U.S. exploration and production companies in 2019 was more on exercising capital discipline than increasing production.  Rig counts (as reported by Baker Hughes) reflect this emphasis, declining 26% over the course of 2019 from 1,083 in December 2018 to 805 in December 2019.   However, not all regions slowed equally. The Permian Basin rig count fell 17% while the Haynesville Shale rig count fell 6%, whereas the Cana Woodford rig count fell 64%. As rig counts declined and fewer wells were drilled in 2019, producers gradually began to work off their inventory of drilled but uncompleted wells (“DUCs”).  As reported by the EIA, the DUC count declined to approximately 7,600 in November 2019 from 8,000 in December 2018.  Of the current DUCs, approximately 3,600 are in the Permian Basin.  DUCs represent a significant potential volume that will continue to be brought into production.

Near-term global economic growth has been adversely impacted by the emergence of the coronavirus, officially designated as Covid-19, in China, and then in several other countries and regions including the U.S., Japan and Europe.  As a result of this public health concern, a significant amount of global commerce has been affected due to travel restrictions, quarantines, and similar measures.  Analysts from S&P recently estimated that the virus could lower China’s gross domestic product by approximately 1% in 2020, with a peak effect in the first quarter of 2020 before rebounding in the third quarter of 2020.  Overall, economists estimate that headwinds from the virus could reduce global economic growth in 2020 by 0.2% to 0.3%, while in the U.S. first quarter of 2020 growth could be reduced by 0.2% to 0.4%.  The impact of reduced hydrocarbon demand in Asia due to the virus has been felt in the price of crude oil.  WTI prices have declined approximately 22% since the beginning of 2020 (as reported by the NYMEX), which we believe was largely attributable to perceived global economic weakness caused by responses to the virus. In response to the crisis, OPEC is considering production cuts to limit the potential oversupply of crude oil in global markets.  We continue to monitor this situation and its potential impact on our operations.

U.S. natural gas production increased from an average of 84 Bcf/d in 2018 to 91 Bcf/d in 2019 per the EIA.  As a result, natural gas prices, as measured by the NYMEX at Henry Hub, averaged $2.53 per MMBtu in 2019 compared to an average of $3.07 per MMBtu in 2018.  Henry Hub natural gas prices in 2020 have ranged from a high of $2.20 per MMBtu to a low of $1.77 per MMBtu through February 10, 2020.  The decline in price is generally due to lower demand due to warmer winter weather and abundant natural gas supplies due to shale production.  The forward commodity markets for Henry Hub natural gas (as reported by the NYMEX) currently indicate monthly pricing in the range of $1.85 to $2.61 per MMBtu for periods extending through March 2021, with longer term prices currently indicated at $2.20 to $3.20 per MMBtu. Assuming stable natural gas prices, we believe that U.S. natural gas production should be sufficient to meet both domestic and export demand.

With the continued growth in shale production, the EIA reports that the U.S. is becoming a major exporter of natural gas, with LNG exports averaging 4.6 Bcf/d in 2019 and pipeline exports to Mexico averaging 5.1 Bcf/d in 2019. With the completion of several construction projects by the end of 2020, U.S. LNG liquefaction capacity (according to the Federal Energy Regulatory Commission (“FERC”)) is expected to exceed 9 Bcf/d, which we believe will make natural gas production and prices highly sensitive to fluctuations in LNG exports. In fact, some in the industry would argue that U.S. gas prices could become more dependent on international LNG markets in contrast to being traditionally dependent on domestic demand and weather.

We operate in a number of major domestic supply basins, including the Permian, Eagle Ford, Haynesville and Rockies.   The following information represents our general outlook for each of these key basins:

A prime example of our commitment to Permian Basin producers is our Midland-to-ECHO System. This network supports crude oil production growth from the basin by providing producers and other shippers with transportation solutions that are both cost efficient and operationally flexible.  We placed our Midland-to-ECHO 1 and Midland-to-ECHO 2 pipelines into full commercial service during the second quarter of 2018 and second quarter of 2019, respectively.  The Midland-to-ECHO 3 and Midland-to-ECHO 4 projects are expected to begin service during the third quarter of 2020 and first half of 2021, respectively.  When fully complete, our Midland-to-ECHO System is expected to provide us with up to 1.8 MMBPD of crude oil transportation capacity to U.S. Gulf Coast and international markets, while assuring the quality and grade of the crude oil being shipped.

An area of particular focus for us has been the development of midstream infrastructure serving producers in the Delaware Basin, which is part of the Permian Basin.  Prior to the shale production boom, the Delaware Basin was a lightly drilled area due to a lack of conventional targets; however, with the introduction of horizontal drilling techniques and identification of stacked targets of tight rock and shales, drilling in the Delaware Basin has accelerated greatly over the past five years. These drilling targets have proven to produce not only crude oil but also condensate and NGLs, which present us with a significant number of opportunities to provide midstream services to producers. We are actively working with producers to identify those midstream infrastructure projects that best serve their needs and complement our integrated asset network.

Two examples of our initiatives in the Delaware Basin are the Orla and Mentone natural gas processing facilities. At our Orla processing facility, we placed two processing trains (Orla I and II) into service in 2018, and a third processing train (Orla III) was placed into service in July 2019. With three trains, the Orla facility has 900 MMcf/d of total processing capacity and allows us to extract up to 140 MBPD of mixed NGLs. Our Mentone natural gas processing facility was announced in October 2018 and its first processing train (Mentone I) entered service in December 2019. Following the 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. Given our investment in NGL pipeline infrastructure in the region (e.g., Shin Oak), we believe that we are well positioned to accommodate NGL production growth from these plants and third party natural gas processing facilities in the Permian Basin.

Overall, we have a positive outlook regarding the Permian Basin and continue to evaluate projects that meet the midstream needs of producers.

Production acreage in the Eagle Ford continued to change ownership during 2019, which contributed to increased drilling activity in the region by the new owners. ConocoPhillips, EOG and other producers continue to show strong interest in the Eagle Ford, which could result in higher volumes for our midstream network; however, until volumes for the basin exceed historical peak production, there will be excess capacity of midstream infrastructure available in the region.  According to the EIA, the historical peak for Eagle Ford crude oil and natural gas production occurred in March 2015 and was 1.7 MMBPD and 7.4 Bcf/d, respectively. 

We believe that the Eagle Ford offers producers some of the best returns on capital of any region in the country due to its proximity to major consumption and export markets along the U.S. Gulf Coast.  Furthermore, we believe that our integrated midstream network will provide us with operating leverage as production increases.

In 2017, the U.S. Geological Survey estimated that the Haynesville and the associated Bossier Shale plays hold a combined 304 trillion cubic feet of technically recoverable shale gas resources, which is the second highest level in the U.S. after the Appalachia region.  The Haynesville benefits from its close proximity to U.S. Gulf Coast markets where significant petrochemical plant projects and LNG export facilities are being constructed.  According to the FERC, the LNG market in South Louisiana and Southeast Texas, including facilities under construction, is expected to reach an aggregate 15 Bcf/d of export capacity.  In September 2019, we announced construction of the Gillis Lateral and Mansfield compressor station project, both of which will support continued production growth in the Haynesville.

Producers in the Rockies benefit from sufficient natural gas and NGL pipeline infrastructure, which helps the region compete with other North American regions where production takeaway capacity is constrained.  We believe that our Rocky Mountain assets will continue to benefit regional producers by allowing them access to major downstream markets such as U.S. Gulf Coast and export destinations.

Demand Side Observations

Global economic growth continues to drive demand for petroleum-based products.  In February 2020, the International Energy Agency (“IEA”) reported that global demand for crude oil and NGLs grew by a combined 1.0 MMBPD in 2019 and expects demand to grow by approximately 0.8 MMBPD in 2020.  Recent statements by the IEA and other sources suggest that the coronavirus will soften near-term global demand for hydrocarbons, particularly in Asia, in the first quarter of 2020, with a likely rebound in demand during the third quarter of 2020.  In December 2019, the IEA forecast that overall long-term demand for crude oil and NGLs by the countries represented by the Organization for Economic Co-operation and Development (“OECD”) will decline by approximately 0.3 MMBPD between 2019 and 2024, while non-OECD demand would increase by 6 MMBPD over the same period. The IEA expects that petrochemicals will account for approximately 31% of the increase in long-term global demand for crude oil and NGLs over this period. As its reference case, the IEA’s long-term outlook for crude oil and NGL demand points to either a plateau after 2030, or to slow growth of approximately 0.2% from 2025 to 2040.

We, along with a majority of forecasters, expect that long-term demand for liquid hydrocarbons such as crude oil and NGLs should not decline before the year 2040. Demand for liquid hydrocarbons is generally driven by the following sectors: airline and rail transportation, marine bunker fuel, motor fuels (gasoline and diesel) for cars, trucks and similar vehicles, industrial users, residential and commercial heating, and feedstocks in petrochemical and plastics manufacturing. Practically speaking, liquid hydrocarbons cannot be reasonably or economically replaced for each of these uses by other forms of energy in this forecast period given current technologies.  Although the IEA and other forecasters project electric-powered vehicles modestly supplanting gasoline and diesel-powered vehicles in certain markets during this period, the decrease in motor fuel demand is outweighed by demand growth in other sectors for liquid hydrocarbons.

We continuously review third-party economic forecasts in connection with our long-term planning.  In general, third party forecasts such as the IEA’s are subject to a variety of assumptions including: (i) current views of leading economic forecasters and demographers with respect to assumed economic and demographic trends; (ii) improvements in energy production, delivery and consumption technologies; (iii) current laws and regulations that affect the energy sector are unchanged throughout the 2020-2050 projection period; (iv) future commodity prices and (v) reduced costs for renewables.  Changes to these and other assumptions by forecasters may yield higher or lower outlooks for hydrocarbon demand and supply over the long-term.

The North American “shale revolution” has transformed the U.S. into the global, low-cost supplier of NGLs.  We expect this trend to continue into 2020 and beyond supported by, among other things: (i) the ability of U.S. shale producers to reduce development costs and improve the productivity of new and existing wells, (ii) regulatory changes in various international markets such as India and China favoring the use of clean-burning fuels and low-sulfur hydrocarbons such as those found in U.S. shale oil basins and (iii) higher demand in developing economics for liquid hydrocarbons in general. As a midstream energy company, we continue to foresee a variety of long-term, demand-side opportunities from these developments, including higher demand from the U.S. petrochemical industry and increased exports of hydrocarbons (e.g., ethane, LPG and crude oil) to growing international markets.

International demand for U.S. ethane is expected to remain robust in 2020, as ethane from domestic shale basins offers the global petrochemical industry a low-cost feedstock option plus supply diversification. Our Morgan’s Point Ethane Export Terminal, the largest of its kind in the world, enables us to meet this demand and has an aggregate loading rate (nameplate capacity) of approximately 10,000 barrels per hour of fully refrigerated ethane.

With respect to the U.S. petrochemical industry, abundant supplies of shale-sourced ethane provides the U.S. with one of the cheapest feedstocks available for ethylene production. The American Chemistry Council estimates that over $200 billion is being invested in domestic petrochemical plants, with most of those investments tied directly to producing ethylene from cost-advantaged U.S. ethane.  Of the new domestic facilities, seven world-scale ethylene plants are currently operational and we estimate that they have a combined ethylene production capacity of 17.7 billion pounds per year and an ethane consumption rate of approximately 490 MBPD.  An additional four plants are being commissioned and expected to enter service in 2020, with an estimated aggregate ethylene production capacity of 7.2 billion pounds per year and an ethane consumption rate of approximately 205 MBPD.  An additional four plants are expected to enter service in the early 2020s.  We anticipate that these later plants will have a combined ethylene production capacity of 7.5 billion pounds per year and an ethane consumption rate of approximately 205 MBPD.  We also anticipate demand growth for ethane as a feedstock resulting from modifications (e.g., debottlenecking, furnace modifications, etc.) made to other existing domestic facilities. 

Our midstream assets are located in close proximity to virtually all domestic ethane-consuming petrochemical plants, as well as associated derivative plants that produce various polymer products from ethylene.  As a result of the expected growth in U.S. ethylene production capacity, we completed and commissioned an ethylene export terminal located at Morgan’s Point on the Houston Ship Channel in December 2019.  The project, which is underwritten by long-term customer commitments, is expected to be fully operational in the fourth quarter of 2020 once certain refrigeration assets are completed.

To a limited extent, global demand for the end products produced by the petrochemical and plastics sector is currently under pressure mostly due to improper plastic disposal methods, particularly the accumulation of plastic garbage in the world’s oceans. This situation has resulted in calls for better collection, recycling and disposal of plastics and bans of certain single-use plastic items. Although higher recycling rates and bans of certain single-use items would effectively reduce the rate of growth in global demand for plastics, we do not believe that such actions will result in a significant long-term decline in the production of plastics (or in the use of liquid hydrocarbons as feedstocks in the production of such items).

With respect to long-term LPG demand, we believe that U.S. exports to Asia, particularly China and India, as well as markets in Northwest Europe and Latin America, will continue to be strong.  According to EIA data available through November 2019, U.S. LPG exports increased 17% in 2019 to 1.4 MMBPD, with volumes headed to Asian markets accounting for approximately 51% of this amount.   We estimate that LPG exports could reach 2.5 to 2.8 MMBPD by 2025.  Our outlook for LPG exports to Asia is supported by several factors including long-term economic growth rates in Asian markets and favorable domestic policies in countries like India and Indonesia where governments are subsidizing their population’s switch from wood-based fuels to LPG for domestic use as a means of reducing pollution and protecting against deforestation.  The competitiveness of U.S. Gulf Coast supplies of LPG are enhanced by the recent widening of the Panama Canal in 2016.  Due to our expectation of continued growth in LPG exports, we completed an expansion project at EHT in 2019 that increased our LPG loading capacity at the terminal to approximately 835 MBPD.  In July 2019, we announced an additional expansion project at EHT that would increase our LPG loading capacity by an additional 265 MBPD and be placed into service during the second half of 2021.

Lastly, as U.S. crude oil production increased, these new domestic barrels continue to supplant more of the U.S.’s crude oil imports, while the remainder are exported to international markets in Central and South America, Asia and Western Europe where the lighter U.S. crudes are used as feedstock in their refining and petrochemical facilities. We expect U.S. refiners to continue to operate at high rates as a result of steady U.S. demand and growing exports of refined products. We believe that our marine terminals and related storage and pipeline infrastructure that handle crude oil, refined products and petrochemicals are strategically located to meet the concurrent needs of export and import customers. We have significant export capabilities, with expansion potential, on the Houston Ship Channel, Beaumont, Freeport and Texas City, Texas.

In July 2019, we announced long-term agreements with Chevron that support the development of SPOT in the Gulf of Mexico.  SPOT is designed to load VLCCs at rates of approximately 85,000 barrels per hour.  Construction of SPOT remains subject to obtaining the required approvals and licenses from the federal Maritime Administration, which is currently reviewing our SPOT application. 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.

Selected Energy Commodity Price Data

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

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