ENTERPRISE PRODUCTS PARTNERS L.P. - Annual Report: 2022 (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

12/31

OR

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___  to  ___.

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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.  ☑

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   Yes ☐    No ☑

The aggregate market value of our common units held by non-affiliates at June 30, 2022 (the last business day of the registrant’s most recently completed second fiscal quarter) was $35.99 billion based on a closing price on that date of $24.13 per common unit on the New York Stock Exchange Composite ticker tape.  There were 2,170,806,347 common units outstanding at January 31, 2023.

ENTERPRISE PRODUCTS PARTNERS L.P.

TABLE OF CONTENTS

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This annual report on Form 10-K for the year ended December 31, 2022 (our “annual report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us.  When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “scheduled,” “pending,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements.  Although we and our general partner believe that our expectations reflected in such forward-looking statements (including any forward-looking statements/expectations of third parties referenced in this annual report) are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct.  

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

KEY REFERENCES USED IN THIS REPORT

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

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

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

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

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

We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees.  EPCO, together with its privately held affiliates, owned approximately 32.4% of the Partnership’s common units outstanding at December 31, 2022.

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

ITEMS 1 AND 2.  BUSINESS AND PROPERTIES

General

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

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

Our business strategy seeks to manage these operations to:

Our financial position, results of operations and cash flows are contingent on the supply of, and demand for the energy commodities we handle across our integrated midstream energy asset network.  See “Current Outlook” included under Part II, Item 7 of this annual report for management’s views on key midstream energy supply and demand fundamentals in 2023.

Business Segments

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

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

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

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

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

NGL Pipelines & Services

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

At the core of our natural gas processing business are processing facilities located in Colorado, Louisiana, Mississippi, New Mexico, Texas and Wyoming.

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

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

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

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

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

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

The following table presents selected information regarding our natural gas processing facilities at February 1, 2023:

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 66.5%, 58.1% and 57.6% during the years ended December 31, 2022, 2021 and 2020, respectively.

Midland Basin natural gas processing facility.  The Midland Basin natural gas processing facility consists of five natural gas processing plants, which includes four natural gas processing plants (Newberry I, Newberry II, Trident and Taylor) that we acquired as part of our acquisition of Navitas Midstream Partners, LLC (“Navitas Midstream”) in February 2022 and a fifth natural gas processing plant (Leiker), which we completed construction of and placed into service in March 2022.  See Part II, Item 7 of this annual report for additional information regarding our acquisition of Navitas Midstream.

During 2022, we announced plans to construct two new natural gas processing plants in the Midland Basin, Poseidon (previously referred to as Plant 6) and Leonidas (previously referred to as Plant 7), which are expected to be placed into service in the third quarter of 2023 and first quarter of 2024, respectively.  Each of these plants will have the capacity to process 300 MMcf/d of natural gas and extract over 40 MBPD of NGLs and are supported by long-term acreage dedication agreements.

Once the Poseidon and Leonidas plants are completed and placed into service, we expect to have an aggregate 1.6 Bcf/d of natural gas processing capacity and more than 220 MBPD of NGL production capacity from our natural gas processing facility in the Midland Basin.

Delaware Basin natural gas processing facility.  During 2022, we announced plans to construct two additional natural gas processing plants in the Delaware Basin, the Mentone II and III plants, which are expected to be placed into service in the fourth quarter of 2023 and first quarter of 2024, respectively.  Each of these plants will have the capacity to process 300 MMcf/d of natural gas and extract 40 MBPD of NGLs and are supported by long-term capacity agreements.

When the Mentone II and III plants are completed and placed into service, we expect to have an aggregate 2.2 Bcf/d of natural gas processing capacity and more than 300 MBPD of NGL production capacity from our natural gas processing facility in the Delaware Basin.

Our NGL marketing activities utilize a fleet of approximately 480 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 180 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.

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

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

The following table presents selected information regarding our NGL pipelines at February 1, 2023:

The maximum number of barrels per day that our NGL pipelines can transport depends on the operating rates achieved at a given point in time between various segments of each system (e.g., demand levels at each injection and delivery point and the mix of products being transported).  As a result, we measure the utilization rates of our NGL pipelines in terms of net throughput, which is based on our ownership interest.  In the aggregate, net throughput volumes for these pipelines were 3,703 MBPD, 3,412 MBPD and 3,589 MBPD during the years ended December 31, 2022, 2021 and 2020, respectively.

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

In August 2022, we announced plans to expand our Shin Oak NGL Pipeline transportation capacity by up to 275 MBPD to approximately 825 MBPD.  We anticipate that this expansion project will be completed in the first half of 2025.

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

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

The following table presents selected information regarding our NGL fractionation facilities at February 1, 2023:

On a weighted-average basis, the overall utilization rates for our NGL fractionators (based on nameplate capacities) were 100.0%, 93.8% and 101.6% during the years ended December 31, 2022, 2021 and 2020, respectively.

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

In April 2022, we announced plans to construct a twelfth NGL fractionator (“Frac XII”) in Chambers County, Texas. Frac XII is expected to be capable of processing 150 MBPD of NGLs and enter service in the third quarter of 2023. Completion of this fractionator is expected to increase our total Chambers County NGL fractionation capacity to approximately 1.2 MMBPD.

We also own and operate a 60 MBPD natural gasoline hydrotreater facility at our Chambers County complex along with related storage and pipeline infrastructure, which is designed to lower the sulfur content of natural gasoline.

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

The following table presents selected information regarding our NGL and related product storage assets at February 1, 2023:

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

Our largest underground storage facility is located 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 36 MMBbls of above-ground brine storage capacity and five wells used in brine production.

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

The following information describes our Houston Ship Channel terminals:

EHT can load refrigerated cargoes of low-ethane propane and/or butane (collectively referred to as LPG) onto multiple tanker vessels simultaneously.  Our LPG export services continue to benefit from increased NGL supplies produced from domestic shale plays, international demand for propane as a feedstock in ethylene and propylene production, and for power generation and heating purposes.  The current estimated maximum loading capacity for LPG at EHT is approximately 835 MBPD.  EHT has the capability to load up to six Very Large Gas Carrier (“VLGC”) vessels simultaneously, while maintaining the option to switch between loading propane and butane.  EHT can load a single VLGC in less than 24 hours, creating greater efficiencies and cost savings for our customers.  LPG loading volumes at EHT averaged 555 MBPD, 501 MBPD and 588 MBPD during the years ended December 31, 2022, 2021 and 2020, respectively.

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

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

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

In April 2022, we announced plans to build a new Ethane Export Terminal, which will be located in Orange County, Texas.  The project is expected to be completed in 2025.

Crude Oil Pipelines & Services

This business segment includes our 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 our crude oil pipelines are primarily dependent upon the volume of crude oil transported (or capacity reserved) and the associated fees we charge for such transportation services.  Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the FERC, or contractual arrangements.  See “Regulatory Matters” within this Part I, Items 1 and 2 for information regarding governmental regulation of our liquids pipelines.

The following table presents selected information regarding our crude oil pipelines and related operations at February 1, 2023:

The maximum number of barrels per day that our crude oil pipelines can transport depends on the operating rates achieved at a given point in time between various segments of each system (e.g., demand levels at each delivery point and the grades of crude oil being transported).  As a result, we measure the utilization rates of our crude oil pipelines in terms of net throughput, which is based on our ownership interest.  In the aggregate, net throughput volumes for these pipelines were 2,222 MBPD, 2,088 MBPD and 2,166 MBPD during the years ended December 31, 2022, 2021 and 2020, respectively.

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

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

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

The Midland-to-ECHO 3 Pipeline is comprised of a 36-inch pipeline extending from Midland, Texas to our ECHO terminal, and further from ECHO to a third-party terminal in Webster, Texas (collectively, the “Midland-to-Webster pipeline”).  The maximum transportation capacity on the Midland-to-Webster pipeline is approximately 450 MBPD.

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

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

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

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

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

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

The following table presents selected information regarding our crude oil terminals at February 1, 2023:

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

Sea Port Oil Terminal.  In January 2019, we filed our application for regulatory permitting of our Sea Port Oil Terminal (“SPOT”) in the Gulf of Mexico with the Department of Transportation’s Maritime Administration.  SPOT would consist of proposed onshore and offshore facilities, including a fixed platform located approximately 30 nautical miles off the Texas coast in approximately 115 feet of water.  SPOT is designed to load VLCCs and other crude oil tankers at rates of approximately 85,000 barrels per hour.  The platform would be connected to an onshore storage facility with approximately 4.8 MMBbls of capacity in Brazoria County, Texas, by two 36-inch, bi-directional pipelines.  The SPOT project includes state-of-the-art pipeline control, vapor recovery and leak detection systems that are designed 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.

In November 2022, we received a favorable Record of Decision (“ROD”) from the Department of Transportation’s Maritime Administration in accordance with the provisions of the Deepwater Port Act of 1974.  The receipt of the ROD is a significant milestone in the process to obtain a license for SPOT under the Deepwater Port Act.  Remaining conditions that we must address and satisfy to obtain approval for the license issuance include routine construction, operating and decommissioning guarantees, submission of public outreach, wetland restoration and volatile organic compound (“VOC”) monitoring plans, and other state approvals.  We expect to satisfy these remaining conditions in 2023; however, we can give no assurance as to when or whether the project will ultimately be authorized to begin construction or operation.

We continue to commercialize this project in order to support a final investment decision, which is subject to the execution of long-term customer contracts and receiving a license to construct and operate the facility.

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 245 tractor-trailer tank trucks, the majority of which we own and operate, that are used to transport crude oil.

Natural Gas Pipelines & Services

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

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

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

The following table presents selected information regarding our natural gas pipelines and related infrastructure at February 1, 2023:

On a weighted-average basis, overall utilization rates for our natural gas pipelines were approximately 65.0%, 60.4% and 57.2% during the years ended December 31, 2022, 2021 and 2020, respectively.  These utilization rates represent actual natural gas volumes delivered as a percentage of our nominal delivery capacity and do not reflect firm capacity reservation agreements where capacity fees are earned whether or not the shipper actually utilizes such capacity.

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

In April 2022, we announced plans for an additional 400 MMcf/d expansion of our Acadian Gas System. The expansion is expected to be completed in the second quarter of 2023.

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, Midland Basin, Delaware 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

This business segment includes our:

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

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

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

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

The following table presents selected information regarding our propylene production facilities at February 1, 2023:

We produce PGP at our Chambers County facilities and CGP at our BRPC facility.  On a weighted-average basis, the overall utilization rate of our propylene production facilities was approximately 90.0%, 88.7% and 79.4% during the years ended December 31, 2022, 2021 and 2020, respectively.

Global demand for propylene is increasing; however, the use of lighter crude oil feedstocks by U.S. refiners and increased use of ethane by steam crackers has reduced propylene production from these traditional sources.  This has led to the development of more “on purpose” propylene production facilities such as our PDH 1 facility located in Chambers County, Texas.  This facility has the capacity to produce up to 1.65 billion pounds per year, or approximately 25 MBPD, of PGP.  At this nameplate production rate, the facility upgrades approximately 35 MBPD of propane as feedstock. The PDH 1 facility is integrated with our legacy Chambers County 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.

In November 2022, we reached a settlement related to legal proceedings involving the former general contractor for PDH 1.  For additional information regarding this litigation, see Note 17 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

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

Propylene pipelines.  The results of operations from our petrochemical pipelines are primarily dependent upon the volume of products transported and the associated fees we charge for such transportation services.  The following table presents selected information regarding our propylene pipelines at February 1, 2023:

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 163 MBPD, 152 MBPD and 140 MBPD during the years ended December 31, 2022, 2021 and 2020, respectively.

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

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

We own and operate three isomerization units located in Chambers County, Texas having an aggregate processing capacity of 116 MBPD that comprise the largest commercial isomerization facility in the U.S.  We also own and operate an 83-mile pipeline system used to transport high-purity isobutane from Chambers County, Texas to Port Neches, Texas and to Channelview, Texas.

The demand for commercial isomerization services depends upon the energy industry’s requirements for isobutane and high-purity isobutane in excess of the isobutane produced through the process of NGL fractionation and refinery operations.  Isomerization units convert normal butane feedstock into mixed butane, which is a stream of isobutane and normal butane.  DIB units, of which we own and operate ten located at our Chambers County 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 93.1%, 73.3% and 82.8% during the years ended December 31, 2022, 2021 and 2020, respectively.

We own and operate an octane enhancement production facility located in Chambers County, Texas 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 26 MBPD, 14 MBPD and 15 MBPD during the years ended December 31, 2022, 2021 and 2020, 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 106.6%, 91.7% and 97.6% for the years ended December 31, 2022, 2021 and 2020, 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. We own and operate an iBDH facility located in Chambers County, Texas that is capable of processing approximately 25 MBPD of butane into nearly 1 billion pounds per year of isobutylene.  Production from the iBDH plant enables us to optimize our MTBE and high purity isobutylene assets and meet growing market demand for isobutylene.

Steam crackers and refineries have historically been the major source of propane and butane olefins for downstream use; however, with the increased use of light-end feedstocks such as ethane, the need for “on purpose” olefins production has increased.  Like our PDH facility, the iBDH plant helps meet market demand where traditional supplies have been reduced.  The iBDH plant increases 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 3,041-mile pipeline system comprised of 2,923 miles of regulated interstate pipelines and 118 miles of unregulated intrastate Texas pipelines.  The system primarily transports refined products from the upper Texas Gulf Coast to Seymour, Indiana. From Seymour, segments of the TE Products Pipeline extend to Chicago, Illinois; Lima, Ohio; Selkirk, New York; and a location near Philadelphia, Pennsylvania.  East of Seymour, Indiana, the TE Products Pipeline is primarily dedicated to NGL transportation service. The refined products transported by the TE Products Pipeline are produced by refineries and include motor gasoline and distillates.  

The results of operations for this pipeline system are dependent upon the volume of products transported and the level of fees charged to shippers.  The tariffs charged for such services are either contractual or regulated by governmental agencies, including the FERC. See “Regulatory Matters” within this Part I, Items 1 and 2 discussion for information regarding governmental regulation 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 20.9 MMBbls of aggregate storage capacity.

In April 2022, we announced plans for our Texas Western Products System, created by repurposing a portion of our Mid-America Pipeline System’s Rocky Mountain segment and adding westbound service to our Chaparral Pipeline business to transport refined products from the U.S. Gulf Coast to markets in West Texas, New Mexico, Colorado and Utah.  The system is expected to be completed in phases beginning in the fourth quarter of 2023.

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 10.4 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 2.4 MMBbls of aggregate storage capacity through the use of 20 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.

Our ethylene export terminal located at our Morgan’s Point facility on the Houston Ship Channel features two docks with a combined nameplate capacity to load 1 million tons of ethylene per year and a refrigerated storage tank capable of handling 66 million pounds of ethylene.  Ethylene is the primary feedstock for a wide variety of consumer products, including cell phones and computer parts, food packaging, apparel, textiles and personal protective equipment.  We own a 50% member interest in Enterprise Navigator Ethylene Terminal LLC, which owns the export facility.  In April 2022, we announced plans to expand the ethylene export capacity of our Morgan’s Point facility.  The expansion project, which will be completed in two phases, will expand our existing capacity by 50% during 2024 and to more than double our current capacity by 2025.

Our ethylene system serves as an open market storage and trading hub for the ethylene industry by incorporating storage capacity, connections to multiple ethylene pipelines, and high-volume export capabilities.  In support of our ethylene business, our Chambers County storage complex includes a high-capacity underground ethylene storage well having a storage capacity of 600 million pounds of ethylene.  The storage well is connected to our Morgan’s Point ethylene export terminal and further to Bayport, Texas through a 58-mile pipeline system.

We also operate the Baymark ethylene pipeline in South Texas, which is a leading growth area for new ethylene crackers and related facilities.  The Baymark pipeline, which is supported by long-term customer commitments, originates in Bayport and extends 92 miles to Markham, Texas.  We own a 70% consolidated interest in the Baymark pipeline through our majority owned subsidiary, Baymark Pipeline LLC.  Customers using the Baymark pipeline have pipeline access to our high-capacity ethylene storage well in Chambers County and our export terminal at Morgan’s Point.

Our marine transportation business consists of 64 tow boats and 157 tank barges used to transport refined products, crude oil, asphalt, condensate, heavy fuel oil, LPG and other petroleum products on key U.S. inland and intracoastal waterway systems.  The marine transportation industry uses tow boats as power sources and tank barges for freight capacity. We operate our marine transportation assets that serve refinery and storage terminal customers along the Mississippi River, the intracoastal waterway between Texas and Florida, and the Tennessee-Tombigbee waterway system.  We own and operate shipyard and repair facilities located in Houma and Morgan City, Louisiana and marine fleeting facilities located in Bourg, Louisiana and Channelview, Texas.

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

Our fleet of marine vessels operated at an average utilization rate of 92.3%, 85.2% and 86.1% during the years ended December 31, 2022, 2021 and 2020, 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 pipelines and associated facilities, including breakout tanks and gas storage facilities.  These statutes require companies that own or operate pipelines and associated facilities 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”), and in many cases, enforcement authority is delegated to state agencies.  Noncompliance with these requirements can result in substantial penalties.  We believe we are in material compliance with DOT regulations.

Congress has periodically amended the pipeline safety laws to become more stringent and more broadly applicable.  Similarly, PHMSA has undertaken several actions in recent years to increase the applicability and stringency of its regulations.  Some examples of the types of subject areas governed through the pipeline safety laws, as specified in current or pending PHMSA regulations, include:  (i) complying with industry consensus standards for safety of pipeline breakout tanks and underground natural gas storage facilities; (ii) maintaining and updating gas and hazardous liquid pipeline facility inspection and maintenance plans; (iii) leak detection and repair requirements; (iv) managing the maximum pressure of a pipeline facility, depending on factors such as its design, condition, inspection history, and material; and (v) additional integrity management, inspection, and other activities in designated “High Consequence Areas” such as populated areas, unusually sensitive areas, and commercially navigable waterways.

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

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 receive, 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 discharges of petroleum products 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 regulated 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 is applicable to regulated vessels, deep-water 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, potentially 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.  Under enforcement provisions, the EPA and, in some instances, third parties can 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 provide 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 certain 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, a carrier’s rates and related rules that are already in effect.  If the FERC concludes, after holding a hearing on such complaint, that the challenged rate or rule was not just and reasonable, it may order a carrier to change the rate or rule prospectively and pay damages (i.e., reparations) caused by the imposition of such rate or rule for a period of up to two years prior to the filing of the 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 primarily 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 changes in the pipeline’s operating costs.  The FERC indexing is subject to review and revision every five years.  On December 17, 2020, the FERC issued a final rule setting the index for the five-year period beginning July 1, 2021, and ending on June 30, 2026, at PPI plus 0.78%.  On January 20, 2022, the FERC granted rehearing of certain aspects of the final rule and revised the index level to PPI minus 0.21% effective March 1, 2022 through June 30, 2026.  The FERC ordered pipelines with filed rates that exceed their index ceiling levels based on PPI minus 0.21% to file rate reductions effective March 1, 2022.  Enterprise, together with a number of other midstream companies, is currently contesting this index change in the U.S. Court of Appeals for the District of Columbia Circuit.  This appeal could result in a further change to the index.  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.  Certain of our pipelines have been granted market-based rate authority by the FERC, including Seaway.

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

The Revised Policy and Order on Rehearing do not impact oil and liquids pipelines with market-based rate authority, or those that charge “settlement rates.”  Following issuance of the Revised Policy, the FERC now requires crude oil and liquids pipelines owned by MLPs to remove the ITA from their cost-of-service reporting in FERC Form No. 6.  In its final rule issued December 17, 2020, the FERC removed any effect of the change in ITA treatment in determining the index for rates that became effective on July 1, 2021.

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

FERC Regulation – Natural Gas Pipelines and Related Matters

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

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

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

The resale of natural gas in interstate commerce is subject to FERC regulation.  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 NGA, or any rules, regulations or orders of the FERC, were approximately $1.5 million per day per violation as of January 2023.  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 global warming and climate change including the environmental effects of greenhouse gas emissions and their associated consequences on global climate, oceans and ecosystems. Climate change could have a long-term impact on our operations.  For example, our facilities that are located in low lying areas such as the coastal regions of Louisiana and Texas may be at increased risk due to flooding, rising sea levels, or disruption of operations from more frequent and severe weather events.  Facilities in areas with limited water availability may be impacted if droughts become more frequent or severe.  Changes in climate or weather may hinder exploration and production activities or increase the cost of production of oil and gas resources and consequently affect the volume of hydrocarbon products entering our system.  Changes in climate or weather may also affect consumer demand for energy or alter the overall energy mix.

In response to governmental, scientific and public concerns that emissions of certain gases, commonly referred to as greenhouse gases, including gases associated with oil and natural gas production such as carbon dioxide, methane and nitrous oxide among others, contribute to a warming of the earth’s atmosphere and other adverse environmental effects, various governmental authorities have considered or taken actions to reduce emissions of greenhouse gases.  For example, the EPA has taken action under the CAA to regulate greenhouse gas emissions.  In addition, certain states (individually or in regional cooperation), including states in which some of our facilities or operations are located, have taken or proposed measures to reduce emissions of greenhouse gases. Also, the U.S. Congress from time to time has proposed legislative measures for imposing restrictions or requiring fees or carbon taxes for the emission of greenhouse gases.  One such fee applicable to certain of our operations has been imposed by the Inflation Reduction Act of 2022, and is known as the “Methane emissions and waste reduction incentive program.”

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

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

Finally, changes in regulatory policies or market preferences that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to greenhouse gases, or restrictions on their use, may reduce volumes available to us for processing, transportation, marketing and storage.

Competition

NGL Pipelines & Services

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

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

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

Crude Oil Pipelines & Services

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

Natural Gas Pipelines & Services

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

Petrochemical & Refined Products Services

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

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

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

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

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

Seasonality

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

Workforce and Related Matters

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

As of February 1, 2023, there were approximately 7,300 EPCO personnel who spend all or a substantial portion of their time engaged in our business.  From a diversity perspective, approximately 14% of these personnel were female and approximately 32% of these personnel were minorities.  We believe that the diversity of our workforce compares favorably to that of related energy industries.

The health and safety of those working on our behalf is a top priority. We promote a culture in which all personnel share the same commitment to health and safety, and recognize the importance of mitigating risks.  Acting upon our commitment to safety, we engage all levels of employees and management, our Board, our contractors, and various external entities and organizations.  We strive to achieve a goal of zero incidents and injuries.  We track our safety performance by monitoring our Total Recordable Incident Rate (“TRIR”), which is an OSHA measure that generally reflects the number of recordable incidents per 100 full-time workers during a one-year period.  Our TRIR for 2022 was 0.33, which compares favorably to the average TRIR for the midstream industry over the last six years.  We strive for year-to-year improvement in our safety performance.

Title to Properties

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

Available Information

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

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

ITEM 1A.  RISK FACTORS.

Summary of Key Risk Factors

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

Risks Relating to Our Business

Risks Relating to Our Partnership Structure

Tax Risks to Common Unitholders

Discussion of Key Risk Factors

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

Risks Relating to Our Business

Changes in the supply of and demand for hydrocarbon products impacts both the volume of products that we purchase and sell and the level of services that we provide to customers, which in turn impacts our financial position, results of operations and cash flows.

The COVID-19 pandemic continues to have global effects on demand, including as a result of international COVID-19 containment measures (e.g., quarantines, travel restrictions, temporary business closures and similar protective actions), and related reduced near-term demand for hydrocarbon products.

While many countries have eased their COVID-19 containment measures and economic activity has resumed to near pre-COVID levels, emerging variants and the potential resumption of containment measures could threaten the full recovery of hydrocarbon demand.  A continuation of hydrocarbon demand recovery remains partially dependent on successful containment of the disease, the efficacy and distribution of approved vaccines on COVID-19 and its emerging variants, and proven therapeutics. Any resumed period of economic slowdown or recession, or the return to a period of depressed demand or prices for crude oil or other products that we handle, could have significant adverse consequences on our financial condition and the financial condition of our customers, suppliers and other counterparties, and could diminish our liquidity and negatively affect the volumes of products handled by our pipelines and other facilities.

The Russian invasion of Ukraine and related sanctions have also significantly disrupted supply chains for crude oil, natural gas and hydrocarbon products.  While initial impacts of the war in 2022 resulted in increased European demand for U.S. natural gas and hydrocarbon products, we cannot predict the level of future demand, effects on domestic pricing, and impacts on U.S. oil and gas production.  Any economic slowdown or recession in Europe or globally, including as a result of such supply chain disruptions or sanctions, may also impact demand and depress the price for crude oil, natural gas or other products that we handle, which could have significant adverse consequences on our financial condition and the financial condition of our customers, suppliers and other counterparties, and could diminish our liquidity and negatively affect the volumes of products handled by our pipelines and other facilities.

The future impact of these current events on our financial condition, results of operations and cash flows depends largely on developments outside our control, including the duration of the outbreak, the related impact on overall economic activity and the potential long-term impacts on demand for crude oil and other products, all of which cannot be predicted with certainty.

The operation of our assets and the execution of capital projects require significant expenditures for labor, materials, property, equipment and services.  As a result, such costs may increase during periods of general business inflation, including as a result of higher commodity prices, supply chain disruptions and tight labor markets.  Recent inflationary pressures affecting the general economy and the energy industry have increased our expenses and capital costs, and those costs may continue to increase.  While the majority of long-term contracts for our services contain index-based changes and inflation adjustments, we may not be able to pass all of these increased costs to our customers in the form of higher fees for our services.  In addition, we use the FERC’s PPI-based price indexing methodology to establish tariff rates in certain markets served by our pipelines.  In periods of general price deflation, the ceiling level provided by the FERC’s PPI-based price indexing methodology could decrease, requiring us to reduce our index-based rates, even if the actual costs we incur to operate our assets increase.  As such, our revenues and operating margins are impacted by changes in price levels.  Prior to adjustments to our applicable rates, material cost increases may affect our operating margins, even if margins in subsequent periods may be normalized following applicable rate adjustments.  Accordingly, increased costs during periods of general business inflation that are not passed through to customers or offset by other factors may have a material adverse effect on our financial position, results of operations and cash flows.

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

Crude oil and natural gas prices have been volatile in recent years.  For example, crude oil prices (based on WTI as measured by the NYMEX) ranged from a high of $123.70 per barrel to a low of a negative $37.63 per barrel in the three year period ended December 31, 2022.  For the period January 1, 2023 through January 31, 2023, WTI prices ranged from a high of $81.62 per barrel to a low of $72.84 per barrel.  Natural gas prices (based on Henry Hub as measured by the NYMEX) ranged from a high of $9.68 per MMBtu to a low of $1.48 per MMBtu over the three-year period ended December 31, 2022.  Henry Hub natural gas prices ranged from a high of $4.17 per MMBtu to a low of $2.68 per MMBtu from January 1, 2023 through January 31, 2023.

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

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

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

For a discussion regarding our current outlook on industry fundamentals for 2023, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Current Outlook” included under Part II, Item 7 of this annual report.

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, 2022, we had $25.8 billion in principal amount of consolidated senior long-term debt outstanding and $2.3 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 the energy sector or our credit ratings, we could experience an increase in our borrowing costs, difficulty assessing capital markets and/or a reduction in the market price of our securities.  Such a development could adversely affect our ability to obtain financing for working capital, capital investments or acquisitions, or to refinance existing indebtedness.  If we are unable to access the capital markets on favorable terms in the future, we might be forced to seek extensions for some of our short-term debt obligations or to refinance some of our debt obligations through bank credit, as opposed to long-term public debt securities or equity securities.  The price and terms upon which we might receive such extensions or additional bank credit, if at all, could be more onerous than those contained in existing debt agreements.  Any such arrangements could, in turn, increase the risk that our leverage may adversely affect our future financial and operating flexibility and thereby impact our ability to pay cash distributions at expected levels.

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, acquisitions, 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 2022 reflected $5.2 billion of cash payments for capital projects, acquisitions and other investments.  Based on information currently available, we expect our total capital investments for 2023, net of contributions from joint venture partners, to approximate $2.7 billion to $2.9 billion, which includes growth capital projects of $2.3 billion to $2.5 billion and sustaining capital expenditures of $400 million.  These amounts do not include capital investments associated with our proposed deep-water offshore crude oil terminal (the Sea Port Oil Terminal or “SPOT”), which remains subject to state and federal permitting, mitigation and related requirements.  In November 2022, we received a favorable ROD from the Department of Transportation’s Maritime Administration for SPOT; however, we can give no assurance as to when or whether the project will ultimately be authorized to begin construction or operation.  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, geopolitical, 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 our unitholders.

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.  Additionally, we may be unable to complete maintenance or repairs due to the unavailability of necessary materials as a result of supply chain disruptions (including those caused by COVID-19 restrictions or geopolitical events, such as the Russian invasion of Ukraine), which may result in the suspension of operations of the impacted assets until such activities can be completed.  Any significant increase in these expenditures or delays in completing necessary maintenance or repairs 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 construction activities and 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 and severe weather, including hurricanes, tornadoes, storms, extreme winter events, 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 extraordinary 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.

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.

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

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

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 credit losses.

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, 2022, we had $27.5 billion in principal amount of consolidated fixed-rate debt outstanding, including current maturities thereof.  Additionally, at December 31, 2022, we had $1.1 billion of variable-rate debt, which includes our outstanding commercial paper notes.  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 lowered benchmark interest rates three times during 2019 and twice during 2020.  Benchmark interest rates remained near zero during 2021 but increased seven times in 2022, once in 2023 and are expected to rise further in 2023.  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.

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, 2022, 2021 and 2020 were $105 million, $114 million and $83 million, respectively.  Of these annual totals, we charged $61 million, $62 million and $53 million to operating costs and expenses during the years ended December 31, 2022, 2021 and 2020, 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 $96 million for 2023.

For additional information regarding the pipeline safety regulations, 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.

Climate Change.  Responding to reports regarding global warming and climate change matters, the U.S. Congress from time to time has considered and adopted legislation intended to reduce emissions of greenhouse gases or implement carbon taxes.  In addition, certain states, including states in which our facilities or operations are located, have, individually or in regional cooperation, taken or proposed measures to reduce emissions of greenhouse gases.  The Infrastructure Investment and Jobs Act passed in November 2021 provides for, among other things, $7.5 billion to build out a national network of electric vehicle (“EV”) chargers in the United States, as part of a plan to accelerate the adoption of EVs, as well as funding for electric school buses and low- and no-emission buses for public transit.  Various other 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 resulted, 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.

We are in the process of exploring and developing opportunities to capitalize on changes in law and market dynamics relating to greenhouse gas emissions, such as projects related to carbon capture and sequestration and the production and use of hydrogen.  These types of projects pose a variety of risks to us, including that we could (i) overestimate market demand for such services, and therefore divert capital from more profitable opportunities; or (ii) come to rely on temporary subsidies or similar market distortions for an increasing portion of our revenue, which could reduce the long-term economic sustainability of our associated operations.

In March 2022, the SEC proposed new climate-related disclosure rules, which if adopted as proposed, would require significant new climate-related disclosure in SEC filings, including certain climate-related metrics and greenhouse gas emissions data, and third-party attestation requirements.  At this time, we cannot predict the costs of compliance with, or any potential adverse impacts resulting from, the new rules if adopted as proposed.

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

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

The FERC regulates our interstate liquids pipelines under the ICA.  State regulatory agencies regulate our other assets, including 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, decisions and legislation pertaining to our assets 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 Bureau of Labor’s PPI for Finished Goods (“PPI”).   The FERC indexing is subject to review and revision every five years.  On December 17, 2020, the FERC issued a final rule setting the index for the five-year period beginning July 1, 2021, and ending on June 30, 2026, at PPI plus 0.78%.  On January 20, 2022, the FERC granted rehearing of certain aspects of the final rule and revised the index level to PPI minus 0.21%, effective March 1, 2022 through June 30, 2026.  The FERC ordered pipelines with filed rates that exceed their index ceiling levels based on PPI minus 0.21% to file rate reductions effective March 1, 2022.  Pending appellate review could result in a further change to the index.  As an alternative to this indexing methodology, we may also choose to support changes in 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.  The requirements imposed by these methodologies may limit our ability to set rates based on our actual costs or may delay our ability to charge rates reflecting increased costs.   Adverse decisions by the FERC related to our rates could adversely affect our financial position, results of operations and cash flows.

The intrastate liquids and natural gas 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.  The rates we charge and the provision of our services may be subject to challenge at the state level and any adverse decisions could adversely affect our financial position, results of operations and cash flows.

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.

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

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

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

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 our unitholders 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 result in a reduction in the anticipated cash-flow and after-tax return to our unitholders, which would cause a reduction in the value of our common units.

From 2013 through 2017, several publicly traded partnerships merged into their corporate general partner sponsors.  In 2018 and continuing into 2022, 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.  From time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships or an investment in our common units, including elimination of partnership tax treatment for certain publicly traded partnerships.

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

We 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.

Under current law, for open tax years, 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.

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

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

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

Moreover, upon the sale, exchange or other disposition of a common unit by a non-U.S. unitholder, the transferee is generally required to withhold 10% of the amount realized on such sale, exchange or other disposition if any portion of the gain on such sale, exchange or other disposition would be treated as effectively connected with a U.S. trade or business.  The U.S. Department of the Treasury and the IRS have issued final regulations providing guidance on the application of these rules for transfers of certain publicly traded partnership interests, including transfers of our common units.  Under these regulations, the “amount realized” on a transfer of our common units will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and such broker will generally be responsible for the relevant withholding obligations.  The U.S. Department of the Treasury and the IRS have provided that these rules generally apply to transfers of and distributions on our common units occurring on or after January 1, 2023.  Distributions to non-U.S. unitholders may also be subject to additional withholding under these rules to the extent a portion of a distribution is attributable to an amount in excess of our cumulative net income that has not previously been distributed.  We currently anticipate all of our distributions will be in excess of the amount of our cumulative net income that has not previously been distributed.  Accordingly, a distribution to a non-U.S. unitholder is expected to be subject to withholding at the highest applicable effective tax rate. Under these final regulations, we are required to issue qualified notices regarding these matters. Our qualified notices can be found on our public company website.  Non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment 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.

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

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

On occasion, we are assessed monetary penalties by governmental authorities related to administrative or judicial proceedings involving environmental matters.  The following information summarizes matters where the eventual resolution of each of these matters may result in monetary sanctions in excess of $0.3 million.  We do not expect that any expenditures related to the following matters will be material to our consolidated financial statements.

•	In June 2019, we received a Notice of Violation from the U.S. Environmental Protection Agency (“EPA”) in connection with regulatory requirements applicable to facilities that we operate in Baton Rouge, Louisiana.

•	In July 2021, we received a civil penalty demand from the U.S. Department of Justice and the State of Colorado regarding alleged violations of hydrocarbon leak detection and repair regulations applicable to our Meeker gas processing plant in Colorado.

•	In August 2022, we received a Notice of Violation from the U.S. EPA alleging that gasoline at two of our refined products terminals in Texas had exceeded certain Clean Air Act-related standards during two past regulatory control periods.

•	In August 2022, we received two Notices of Enforcement from the Texas Commission on Environmental Quality for alleged exceedances of air permit emission limits at our PDH 1 and iBDH facilities in Texas.

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, 2023, there were approximately 1,896 unitholders of record of our common units.  For information regarding our quarterly cash distributions to partners, see Note 8 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Recent Issuances of Unregistered Securities

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

The Partnership made quarterly PIK distributions of 16,823, 17,128, 17,438 and 17,754 preferred units to OTA Holdings, Inc. (“OTA”), an indirect, wholly owned subsidiary of the Partnership, in the first, second, third and fourth quarters of 2022, respectively.  The preferred units held by OTA are accounted for as treasury units in consolidation.  For additional information regarding the preferred units, see Note 8 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

The issuances of preferred units as PIK distributions during the year ended December 31, 2022 were undertaken in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof.

Other than as described above, there were no sales of unregistered equity securities during the fourth quarter of 2022.

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 2022:

ITEM 6.  RESERVED.

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

For the Years Ended December 31, 2022, 2021 and 2020

The following discussion and analysis of our financial condition, results of operations and related information for the years ended December 31, 2022 and 2021, 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, 2020 and year-to-year comparisons between the years ended December 31, 2021 and 2020 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, 2021 that was filed on February 28, 2022. 

Key References Used in this Management’s Discussion and Analysis

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

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

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

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

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

We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees.  EPCO, together with its privately held affiliates, owned approximately 32.4% of the Partnership’s common units outstanding at December 31, 2022.

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, 2022 (our “annual report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us.  When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “scheduled,” “pending,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements.  Although we and our general partner believe that our expectations reflected in such forward-looking statements (including any forward-looking statements/expectations of third parties referenced in this annual report) are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct.  

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

Overview of Business

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

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

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 “Regulatory Matters - Environmental, Safety and Conservation” within Part I, Items 1 and 2 of this annual report.

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

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

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

As noted previously, this annual report on Form 10-K, including this update to our outlook on business conditions, contains forward-looking statements that are based on our beliefs and those of Enterprise GP.  In addition, it reflects assumptions made by us and information currently available to us, which includes forecast information published by third parties. See “Cautionary Statement Regarding Forward-Looking Information” within this Part II, Item 7 and “Risk Factors” in Part I, Item 1A, for additional information.  The following information presents our current views on key midstream energy supply and demand fundamentals. All references to U.S. Energy Information Administration (“EIA”) forecasts and expectations are derived from its February 2023 Short-Term Energy Outlook (“February 2023 STEO”), which was published on February 7, 2023.

The level of services we provide and the amount of volumes we purchase and sell are directly affected by changes in supply and demand for hydrocarbon products, which impacts our financial position, results of operations and cash flows.  Beginning in the first quarter of 2020, supply and demand for most hydrocarbon products were significantly reduced by the global effects of the COVID-19 pandemic and the consequences of containment measures including quarantines, travel restrictions, temporary business closures and similar protective actions.

Beginning in late 2020 and throughout 2021, most countries began to gradually reduce mobility restrictions to less stringent methods of COVID-19 containment (e.g., vaccines, mask requirements and social distancing) allowing for the resumption of travel and business activities.  These changes, coupled with strong fiscal and economic stimulus programs worldwide, helped bolster an economic recovery in most industrial economies.  According to the EIA, U.S. gross domestic product (“GDP”) increased 5.9% in 2021 compared to a decrease of 2.8% in 2020.

In China, however, strategies for responding to the COVID-19 virus evolved through various stages that ultimately resulted in longer-lasting mobility restrictions than in most other industrialized nations.  China adopted a strategy of “zero-COVID” which was based on a strict testing regime intended to pinpoint and then isolate localized clusters of the population infected with the virus.  The large-scale lockdowns dramatically slowed Chinese economic output between late 2021 and 2022 and ended up constricting the global supply chain due to the significant reductions in intermediate and finished goods manufactured in China.  These reductions occurred just as the rest of the world was demanding increases in goods upon emerging from the pandemic.

To make matters worse, Russia invaded the independent country of Ukraine in February 2022 in a major escalation of the conflict that began when Russia annexed Crimea from Ukraine in 2014.  To counter Russia’s aggression and to prevent a larger regional conflict, members of the North Atlantic Treaty Organization (“NATO”), among other countries, imposed sanctions on Russia including limits on exports of crude oil, refined products and natural gas, which sent global Brent crude oil prices soaring from $90 per barrel in early February 2022 to $123 per barrel by early June 2022.  Natural gas prices in Europe (based on the Dutch Title Transfer Facility, a virtual trading hub for gas in the Netherlands and primary gas pricing hub for the European gas market) increased even more dramatically from $26 per MMBtu in January 2022 to nearly $100 per MMBtu in August 2022.  The higher cost of energy led to government subsidies and the rationing of natural gas, electricity and commodities in Europe, which further reduced global economic output.

Several factors, including massive fiscal stimulus from the U.S. and other global governments, increases in energy prices due to higher demand for energy and commodities following the pandemic, the significant global supply chain disruptions caused in large part by lockdowns in China and the reduction in energy supplies due to sanctions on Russia contributed to inflation rates not seen in the U.S. in over four decades.  Between June 2021 and June 2022, the inflation rate, as measured by the U.S. Consumer Price Index (“CPI”), increased from 5.4% to a peak of 9.1%.  To counteract these pressures, the U.S. Federal Reserve Bank (“the Fed”) increased interest rates by 25 basis points in March 2022 and 50 basis points in May 2022.  As inflation continued to rise, the Fed further increased rates by 75 basis points in each of its June, July, September and November meetings during 2022.

Under the weight of these pressures, including higher interest rates, the U.S. economy began to experience a slowdown in growth as evidenced by U.S. GDP decreasing 1.6% and 0.6% in the first and second quarters of 2022, respectively.  Some economists labeled this period a recession based on the general indicator of two consecutive quarters of negative growth.  After peaking in June 2022 at 9.1%, the inflation rate slowly began to moderate in each of the subsequent months, declining to a rate of 6.5% in December 2022.  In response to the decline in inflation, the Fed slowed the pace of interest rate increases to 50 basis points in December 2022.  Despite these increases, U.S. GDP turned positive again with a growth rate of 3.2% in the third quarter of 2022 and 2.9% in the fourth quarter of 2022.

During the latter half of 2022, energy prices began falling to levels consistent with the start of the year as countries braced for recession, lockdowns in China persisted, the U.S. and International Energy Agency member countries released an aggregate 240 million barrels from their respective strategic petroleum reserves and the U.S. and other non-OPEC countries increased petroleum and other liquids production volumes by approximately 2.0 MMBPD during the second half of 2022 (as reported by the EIA).  Energy prices in Europe fell to pre-war levels as a relatively warm winter and alternatives to Russian natural gas from the U.S., Qatar and other exporting nations led to a healthy buildup of storage inventories.  Despite sanctions and price caps, Russian crude oil continued to find its way to refineries, albeit with redirected trade flows to China, India and other nations encouraged by the ability to purchase crude oil from Russia at steep discounts.

The EIA provided expectations of continued growth in U.S. petroleum and liquid fuels production by nearly 1.0 MMBPD to reach a total of 21.1 MMBPD in 2023.  Global production of petroleum and liquid fuels is expected to reach an average of 102.6 MMBPD in 2024, up from 100.0 MMBPD in 2022, driven mostly by growth in U.S. and other non-OPEC production.  With respect to demand, the EIA forecasts that global liquids fuel consumption will increase from 99.4 MMBPD in 2022 to 102.3 MMBPD in 2024, driven primarily by growth from China and other non-OECD countries.  However, the EIA qualified that this forecast is subject to significant uncertainty over Russia’s oil supply, ongoing concerns about global economic conditions and the easing of COVID-19 restrictions in China.  We acknowledge that these uncertainties exist, however, the upside from the recently more upbeat economic news and the continued reopening of the Chinese economy helps us remain constructive on crude oil prices.  We are not as constructive on natural gas prices considering we see domestic production rising, consumption declining and liquefied natural gas (“LNG”) exports remaining relatively flat until 2025 when additional capacity will be available from new facilities that are expected to be placed in service.  A wider crude oil-to-natural gas price spread, however, makes U.S. petrochemicals more cost-advantaged due to locally produced feedstocks more closely aligning with natural gas prices, whereas feedstocks derived from naphtha are more closely aligned with crude oil prices.

We believe that these coming additions to petroleum production and consumption levels, along with favorable pricing trends, will create additional opportunities to provide midstream services to our customers while leveraging the strengths of our portfolio, which include:

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Our Assets – Our people find innovative ways to optimize our large, integrated and diversified asset base to provide incremental services to customers and to respond to market opportunities.  Additional production volumes could lead to higher demand for processing, transportation, fractionation and terminaling services.  Storage services provide valuable flexibility for customers seeking to balance supply and demand while also allowing us to capture valuable contango and other marketing opportunities should they arise.  U.S. energy and feedstock advantages position our assets well to compete globally for incremental production and processing volumes.  To the extent a rising operating cost environment impacts our results, there are typically offsetting benefits either inherent in our business or that result from other steps we take proactively to reduce the impact of inflation on our operating results.  These steps include revenue rate escalations based on inflation factors, fuel and electricity surcharges and additional volumetric throughputs often achieved during periods of higher prices.

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Our Customers – We have contracted with a large number of quality customers in order to achieve revenue diversification.  In 2022, our top 200 largest customers represented 95.3% of consolidated revenues.  Based on their respective year-end 2022 debt ratings, 89.6% of revenues from our top 200 customers were either investment grade rated or backed by letters of credit.  Additionally, less than 4% of our top 200 customer revenues were attributable to sub-investment grade or non-rated upstream producers.

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Our Balance Sheet and Liquidity – We currently maintain investment grade credit ratings on EPO’s long-term senior unsecured debt of BBB+, Baa1 and BBB+ from Standard and Poor’s, Moody’s and Fitch, respectively.  Based on current market conditions, we believe that we have sufficient consolidated liquidity as of December 31, 2022, which was comprised of $4.0 billion of available borrowing capacity under EPO’s revolving credit facilities and $76 million of unrestricted cash on hand.  As of December 31, 2022,  approximately 96.2% of our debt portfolio is fixed rate debt at a weighted average cost of 4.5% and weighted-average maturity of 20 years.

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Our Access to Capital Markets – EPO successfully issued $1.75 billion in principal amount of senior notes in January 2023.  Based on current conditions, we believe that we will have sufficient liquidity and/or access to debt capital markets to fund our operations, capital investments and the remaining principal amount of senior notes maturing through 2023 and beyond.

Recent Developments

Enterprise’s SPOT Project Receives Record of Decision

In November 2022, we announced that our Sea Port Oil Terminal (“SPOT”) project received a favorable Record of Decision (“ROD”) from the U.S. Department of Transportation’s Maritime Administration in accordance with the provisions of the Deepwater Port Act of 1974.

The proposed SPOT project consists of onshore and offshore facilities, including a fixed platform located approximately 30 nautical miles off the Texas coast in approximately 115 feet of water.  SPOT is designed to load VLCCs and other crude oil tankers at rates of approximately 85,000 barrels per hour.  The platform will be connected to an onshore storage facility with approximately 4.8 MMBbls of capacity in Brazoria County, Texas, by two 36-inch, bi-directional pipelines.  Additionally, the SPOT project includes state-of-the-art pipeline control, vapor recovery and leak detection systems that are designed to minimize emissions.

The receipt of the ROD is a significant milestone in the process to obtain a license for SPOT under the Deepwater Port Act.  Remaining conditions that we must address and satisfy to obtain approval for the license issuance include routine construction, operating and decommissioning guarantees, submission of public outreach, wetland restoration and volatile organic compound (“VOC”) monitoring plans, and other state approvals.  We expect to satisfy these remaining conditions in 2023; however, we can give no assurance as to when or whether the project will ultimately be authorized to begin construction or operation.

Enterprise Announces Three Expansions in the Permian Basin

In August 2022, we announced the following three new projects to support ongoing production growth in the Permian Basin (including their respective scheduled completion dates):

Enterprise and OLCV Sign Letter of Intent for Gulf Coast CO₂ Transportation and Sequestration Project

In April 2022, Enterprise and Oxy Low Carbon Ventures, LLC (“OLCV”), a subsidiary of Occidental Petroleum Corporation, announced that we have executed a letter of intent to work toward a potential carbon dioxide (“CO₂”) transportation and sequestration solution for the Texas Gulf Coast.  The joint project would initially be focused on providing services to emitters in the industrial corridors from the greater Houston to Beaumont/Port Arthur areas.  The initiative would combine Enterprise’s leadership position in the midstream energy sector with OLCV’s extensive experience in subsurface characterization and CO₂ sequestration.

Enterprise would develop the CO₂ aggregation and transportation network utilizing a combination of new and existing pipelines along its expansive Gulf Coast footprint. OLCV, through its 1PointFive business unit, is developing sequestration hubs on the Gulf Coast and across the U.S., some of which are expected to be anchored by direct air capture facilities. The hubs will provide access to high quality pore space and efficient transportation infrastructure, bringing more options to emitters looking to explore viable carbon management strategies.  Enterprise and OLCV have begun exploring the commercialization of the potential joint service offering with customers.

Enterprise Announces Seven New Projects During Analyst and Investor Day

On April 12, 2022, Enterprise hosted a meeting with securities analysts and investors where we announced seven new projects that we expect will be completed by 2025.  The announced projects included the following (including their respective scheduled completion dates):

Enterprise Announces Acquisition of Navitas Midstream

In January 2022, we announced that an affiliate of Enterprise entered into a definitive agreement to acquire Navitas Midstream Partners, LLC (“Navitas Midstream”) from an affiliate of Warburg Pincus LLC in a debt-free transaction for $3.25 billion in cash consideration (subject to adjustment in accordance with the agreement). Navitas Midstream’s assets include approximately 1,750 miles of pipelines and over 1.0 Bcf/d of cryogenic natural gas processing capacity. The purchase price was paid in cash at closing on February 17, 2022. We funded the cash consideration for this acquisition using proceeds from the issuance of short-term notes under EPO’s commercial paper program and cash on hand.  See Note 12 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for additional information regarding this acquisition.

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 weighted-average indicative market price for NGLs was $0.91 per gallon in 2022 versus $0.75 per gallon for 2021.

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

Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices. An increase in our consolidated marketing revenues due to higher energy commodity sales prices may not result in an increase in gross operating margin or cash available for distribution, since our consolidated cost of sales amounts would also be expected to increase due to comparable increases in the purchase prices of the underlying energy commodities.  The same type of relationship would be true in the case of lower energy commodity sales prices and purchase costs.

We attempt to mitigate commodity price exposure through our hedging activities and the use of fee-based arrangements.  See Note 14 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report and “Quantitative and Qualitative Disclosures About Market Risk” under Part II, Item 7A of this annual report for information regarding our commodity hedging activities.

After being relatively moderate in recent years, inflation in the United States increased significantly in late 2021 into 2022.  This rise in inflation, coupled with supply chain disruptions, labor shortages and increased commodity prices, has generally resulted in higher costs in 2022.  However, to the extent that a rising cost environment impacts our results, there are typically offsetting benefits either inherent in our business or that result from other steps we take proactively to reduce the impact of inflation on our net operating results.  These benefits include: (1) provisions included in our long-term fee-based revenue contracts that offset cost increases in the form of rate escalations based on positive changes in the U.S. Consumer Price Index, Producer Price Index for Finished Goods or other factors; (2) provisions in other revenue contracts that enable us to pass through higher energy costs to customers in the form of gas, electricity and fuel rebills or surcharges; and (3) higher commodity prices, which generally enhance our results in the form of increased volumetric throughput and demand for our services.  Additionally, we take measures to mitigate the impact of cost increases in certain commodities, including a portion of our electricity needs, using fixed-price, term purchase agreements.  For these reasons, the increased cost environment, caused in part by inflation, has not had a material impact on our historical results of operations for the periods presented in this report.  However, a significant or prolonged period of high inflation could adversely impact our results if costs were to increase at a rate greater than the increase in the revenues we receive.

See “Capital Investments” within this Part II, Item 7 for a discussion of the impact of inflation on our capital investment decisions.  Additionally, see Part I, Item 1A “Risk Factors - Changes in price levels could negatively impact our revenue, our expenses, or both, which could adversely affect our business.”

Income Statement Highlights

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

Revenues

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

Total revenues for 2022 increased $17.4 billion when compared to 2021 primarily due to a $16.8 billion increase in marketing revenues.

Revenues from the marketing of NGLs, crude oil and natural gas increased a combined $17.0 billion year-to-year primarily due to higher average sales prices, which accounted for a $12.0 billion increase, and higher sales volumes, which accounted for an additional $5.0 billion increase.

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

Operating costs and expenses

Total operating costs and expenses for 2022 increased $16.4 billion when compared to 2021.

Cost of sales for 2022 increased $15.9 billion when compared to 2021.  The cost of sales associated with our marketing of NGLs, crude oil and natural gas increased a combined $16.5 billion year-to-year primarily due to higher average purchase prices, which accounted for a $12.1 billion increase, and higher sales volumes, which accounted for an additional $4.4 billion increase.

Other operating costs and expenses increased $539 million year-to-year primarily due to higher utility, employee compensation and rental costs.

Depreciation, amortization and accretion expense increased $120 million year-to-year.  The addition of assets attributable to the Navitas Midstream acquisition accounted for $86 million of the year-to-year increase.  The remainder of the year-to-year increase is due to assets placed into full or limited service since the first quarter of 2021 (e.g., the Gillis Lateral natural gas pipeline and the Baymark ethylene pipeline) and major maintenance activities accounted for under the deferral method.

Non-cash asset impairment charges decreased $180 million year-to-year primarily due to the partial impairment of our marine transportation business in December 2021, which accounted for $114 million of expense, and the sale of a coal bed natural gas gathering system and related Val Verde treating facility in March 2021, both of which were components of our San Juan Gathering System, which accounted for an additional $44 million of expense.  For information regarding these charges, see Note 4 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

General and administrative costs

General and administrative costs for 2022 increased $32 million when compared to 2021 primarily due to higher employee compensation and professional services costs.

Equity in income of unconsolidated affiliates

Equity income from our unconsolidated affiliates for 2022 decreased $119 million when compared to 2021 primarily due to lower earnings from investments in crude oil pipelines.

Operating income

Operating income for the year ended December 31, 2022 increased $804 million when compared to the year ended December 31, 2021 due to the previously described year-to-year changes in revenues, operating costs and expenses, general and administrative costs and equity in income of unconsolidated affiliates.

Interest expense

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