What changed in this filing

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Item 2. Management’s Discussion and Analysis

2021-05-07 compared with 2020-11-06 · 347 added, 573 removed, 286 unchanged (76% of the section changed)

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RESULTS OF OPERATIONS.

For the Three and Nine Months Ended September 30, 2020 and 2019

The following information should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and accompanying Notes included in this quarterly report on Form 10-Q and the Audited Consolidated Financial Statements and related Notes, together with our discussion and analysis of financial position and results of operations, included in our annual report on Form 10-K for the year ended December 31, 2019 (the “2019 Form 10-K”), as filed on February 28, 2020 with the U.S.

For the Three Months Ended March 31, 2021 and 2020

The following information should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and accompanying Notes included in this quarterly report on Form 10-Q and the Audited Consolidated Financial Statements and related Notes, together with our discussion and analysis of financial position and results of operations, included in our annual report on Form 10-K for the year ended December 31, 2020 (the “2020 Form 10-K”), as filed on March 1, 2021 with the U.S.

Securities and Exchange Commission (“SEC”).

Our financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the United States (“U.S.”).

Cautionary Statement Regarding Forward-Looking Information

This quarterly report on Form 10-Q for the year ended March 31, 2021 (our “quarterly report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us.

When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “scheduled,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements.

Although we and our general partner believe that our expectations reflected in such forward-looking statements (including any forward-looking statements/expectations of third parties referenced in this quarterly 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 (including those attributable to the Coronavirus disease 2019 (“COVID-19”) pandemic), uncertainties and assumptions as described in more detail under Part I, Item 1A of our 2020 Form 10-K.

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 quarterly 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 Management’s Discussion and Analysis

Unless the context requires otherwise, references to “we,” “us,” “our” or “Enterprise” are intended to mean the business and operations of Enterprise Products Partners L.P.

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

and its consolidated subsidiaries.

References to “EPD” or the “Partnership” mean Enterprise Products Partners L.P.

References to the “Partnership” mean Enterprise Products Partners L.P.

on a standalone basis.

References to “EPO” mean Enterprise Products Operating LLC, which is an indirect wholly owned subsidiary of EPD, and its consolidated subsidiaries, through which EPD conducts its business.

Enterprise is managed by its general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company.

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:

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Bachmann, who is also a director and Vice Chairman of the Board of Enterprise GP;

and (iii) Dr.

Cunningham, who is also an advisory director of Enterprise GP.

Duncan Williams and Mr.

Bachmann also currently serve as managers of Dan Duncan LLC along with W.

Randall Fowler, who is also a director and the Co-Chief Executive Officer and Chief Financial Officer of Enterprise GP.

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.

A majority of the outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are:

The outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are:

Duncan Williams, who serves as Chairman of EPCO;

Cunningham, who serves as Vice Chairman of EPCO;

and (iii) Mr.

Bachmann, who serves as the President and Chief Executive Officer of EPCO;

Duncan Williams and Mr.

Bachmann also currently serve as directors of EPCO along with Mr.

Fowler, who is also the Executive Vice President and Chief Financial Officer of EPCO.

EPCO, together with its privately held affiliates, owned approximately 32.2% of EPD’s common units outstanding and 30% of its Series A Cumulative Convertible Preferred Units (“preferred units”) outstanding at September 30, 2020.

and (iii) Mr.

Fowler, who serves as an Executive Vice President and the Chief Financial Officer of EPCO.

Duncan Williams and Messrs.

Bachmann and Fowler also currently serve as directors of EPCO.

We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees.

EPCO, together with its privately held affiliates, owned approximately 32.2% of the Partnership’s common units outstanding at March 31, 2021.

In March 2021, a privately held affiliate of EPCO sold its entire ownership interest in the Partnership’s Series A Cumulative Convertible Preferred Units (“preferred units”) to third parties.

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

million barrels

billion British thermal units

million barrels per day

billion cubic feet

billion British thermal units

million British thermal units

barrels per day

billion cubic feet

million cubic feet

barrels per day

megawatts, alternating current

thousand barrels per day

megawatts, direct current

million barrels

trillion British thermal units

As used in this quarterly report, the phrase “quarter-to-quarter” means the third quarter of 2020 compared to the third quarter of 2019.

Likewise, the phrase “period-to-period” means the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This quarterly report on Form 10-Q 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,” “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 the forward-looking statements/expectations of third parties referenced in this quarterly 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 our 2019 Form 10-K and within Part II, Item 1A of this quarterly report.

These risks include recent impacts of the coronavirus disease 2019 (“COVID-19”) and decreases in certain commodity prices resulting from demand weakness and oversupply, which are discussed in Part II, Item 1A “Risk Factors” of this quarterly report, and this Part I, Item 2.

You should not put undue reliance on any forward-looking statements.

The forward-looking statements in this quarterly report speak only as of the date hereof.

Overview of Business

The Partnership is 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.” The Partnership’s preferred units are not publicly traded.

As used in this quarterly report, the phrase “quarter-to-quarter” means the first quarter of 2021 compared to the first quarter of 2020.

Business Summary

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.

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

Our midstream energy operations currently include:

We are owned by our limited partners (preferred and common unitholders) from an economic perspective.

Enterprise GP, which owns a non-economic general partner interest in us, manages our Partnership.

We conduct substantially all of our business operations through EPO and its consolidated subsidiaries.

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

Our midstream energy operations include:

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

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

crude oil gathering, transportation, storage, and export and import terminals;

petrochemical and refined products transportation, storage, export and import terminals, and related services;

and a marine transportation business that operates primarily on the U.S.

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

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

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

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

a marine transportation business that operates on key U.S.

inland and intracoastal waterway systems.

Our assets currently include approximately 50,000 miles of pipelines;

260 MMBbls of storage capacity for NGLs, crude oil, petrochemicals and refined products;

and 14 Bcf of natural gas storage capacity.

The Partnership is owned by its limited partners (preferred and common unitholders) from an economic perspective.

Enterprise GP, which owns a non-economic general partner interest in the Partnership, manages our operations.

The Partnership conducts substantially all of its business through EPO.

We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees.

The safe operation of our assets is a top priority.

We are committed to protecting the environment and the health and safety of the public and those working on our behalf by conducting our business activities in a safe and environmentally responsible manner.

For additional information, see “ Environmental, Safety and Conservation ” within the Regulatory Matters section of Part I, Items 1 and 2 of the 2020 Form 10-K.

Like many publicly traded partnerships, we have no employees.

All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers.

Our operations are reported under four business segments:

(i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services, and (iv) Petrochemical & Refined Products Services.

Our business segments are generally organized and managed according to the types of services rendered (or technologies employed) and products produced and/or sold.

We provide investors access to additional information regarding the Partnership, including information relating to our governance procedures and principles, through our website, www.enterpriseproducts.com .

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 the 2020 Form 10-K.

We provide investors access to additional information regarding the Partnership and our consolidated businesses, including information relating to governance procedures and principles, through our website, www.enterpriseproducts.com .

Current Outlook

As noted previously, this quarterly report on Form 10-Q, including this update to our outlook on business conditions, contains forward-looking statements that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us, which includes forecast information published by third parties.

See “Cautionary Statement Regarding Forward-Looking Information” within this Part I, Item 2 and “Risk Factors” in Part II, Item 1A, for additional information.

The following update to our Current Outlook replaces the general outlook provided in our 2019 Form 10-K under Part II, Item 7 and presents our current views on key midstream energy supply and demand fundamentals for the remainder of 2020 and extending, where appropriate, into 2021.

The third-party supply and demand forecasts cited in the following discussion, including our internal forecasts based on such information, remain subject to significant uncertainty because mitigation and reopening efforts related to COVID-19 and the introduction of approved vaccines or proven therapeutics continue to evolve.

As described in our 2019 Form 10-K, changes in the supply of and demand for hydrocarbon products impacts both the volume of products that we sell and the level of services that we provide to customers, which in turn has a direct impact on our financial position, results of operations and cash flows.

The global effects of the COVID-19 pandemic, which began in the first quarter of 2020 and include the consequences of international COVID-19 containment measures (e.g., quarantines, travel restrictions, temporary business closures and similar protective actions), reduced near-term demand for hydrocarbon products by record amounts and created a significant oversupply situation.

Also, in the early stages of the pandemic, disputes between members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (collectively, the “OPEC+” group) over crude oil production levels led to unprecedented volatility in global energy markets and a historic collapse in crude oil prices in April 2020.

Although the OPEC+ group and other producers subsequently reached agreements to gradually reduce the oversupply of crude oil through production cuts, the downturn in the energy industry caused by lower demand and prices negatively impacted us, the producers we work with and our other customers to varying degrees.

Demand Side Observations

Across the globe, d ownstream demand for petroleum products such as gasoline and jet fuel has recovered from the lows of the second quarter of 2020, but remains depressed due to the effects of the pandemic and refiners have reduced their utilization rates in response.

Many countries have begun to ease their COVID-19 containment measures and central banks and governments have instituted fiscal measures in an effort to stimulate economic activity.

As noted previously under “Cautionary Statement Regarding Forward-Looking Information” within this Part I, Item 2, this quarterly report on Form 10-Q, 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.

With regards to the outlook for hydrocarbon supply and demand fundamentals described in our 2020 Form 10-K, we believe that the underlying trends remain generally intact.

Ongoing production cuts within the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (collectively, the “OPEC+” group), along with market-driven cuts in U.S., Brazilian and Canadian supplies, continue to provide much-needed support for international energy markets in coping with weakness in hydrocarbon demand attributable to the COVID-19 pandemic.

As vaccination programs are implemented on a wider scale, many countries have eased their COVID-19 containment measures and governments have instituted fiscal measures in an effort to support economic activity.

As a result, hydrocarbon demand has started to recover;

however, a continuation of this trend remains dependent on successful containment of the disease and the development of approved vaccines and proven therapeutics.

In its October 2020 Short-Term Energy Outlook dated October 6, 2020 (the “October 2020 STEO”), the U.S.

Energy Information Administration (“EIA”) forecast that global demand for petroleum and related liquids would average 92.8 MMBPD in 2020 and 99.1 MMBPD in 2021.

By contrast, the EIA estimates that global crude oil demand for 2019 (pre-pandemic) averaged 101.5 MMBPD.

The decrease in hydrocarbon demand attributable to COVID-19 and the resulting oversupply situation caused a significant decrease in crude oil prices.

Prior to the pandemic, crude oil prices for West Texas Intermediate (“WTI”) at Cushing, Oklahoma (as reported by the NYMEX) closed at $61.06 per barrel on December 31, 2019.

By March 31, 2020, WTI prices closed at $20.48 per barrel and, notwithstanding the announced OPEC+ production cuts, closed at a record low of a negative $37.63 per barrel on April 20, 2020.

As demand began to recover starting in the second quarter of 2020, WTI prices rebounded from the April lows and closed at $39.27 per barrel on June 30, 2020.

At September 30, 2020, WTI prices closed at $ 40.22 per barrel.

Supply Side Observations

Production cuts within the OPEC+ group, along with market-driven cuts in U.S., Brazilian and Canadian supplies due to lower crude oil prices, continue to provide much-needed support for international energy markets in coping with the ongoing weakness in hydrocarbon demand attributable to the pandemic.

The OPEC+ group resolved their production dispute by agreeing to reduce their combined crude oil production by 9.7 MMBPD in May and June 2020, 9.6 MMBPD in July 2020, 7.7 MMBPD from August through December 2020 and 5.8 MMBPD from January 2021 to April 2022.

The OPEC+ agreement is scheduled to be reevaluated in December 2021.

In the meantime, global supply and demand fundamentals are continually evaluated by the OPEC+ Joint Ministerial Monitoring Committee.

The duration of market-driven production cuts by non-OPEC countries such as U.S., Brazil and Canada will depend on supply and demand fundamentals.

According to the October 2020 STEO, the EIA expects global crude oil production to average 94.6 MMBPD in 2020, which represents a decline of 6.1 MMBPD when compared to 2019, and to average 98.8 MMBPD in 2021.

As a result of the current business environment, most oil producers in North America have reduced their drilling and completion of new wells.

Baker Hughes reported that the total number of drilling rigs working in the continental U.S.

(combined crude oil and natural gas rigs) declined from 805 at December 31, 2019 to 728 at March 31, 2020 and further to 265 at June 30, 2020.

drilling rig count stood at 266 on October 2, 2020.

In its October 2020 STEO, the EIA forecasts that U.S.

crude oil production will average 11.5 MMBPD in 2020, which is down from 12.3 MMBPD in 2019.

Furthermore, the EIA expects U.S.

crude oil production to average 11.1 MMBPD in 2021.

According to the October 2020 STEO, the EIA expects U.S.

crude oil production to decline to an average of 11.0 MMBPD in the second quarter of 2021 since near-term drilling and completion activity will not generate enough production to offset declines from existing wells.

The EIA expects drilling activity to rise later in 2021, contributing to U.S.

crude oil production returning to 11.2 MMBPD in the fourth quarter of 2021.

Enterprise Outlook

Given the combination of the record retrenchment in drilling and completion activities by U.S.

producers in 2020, along with steep decline curves in shale basins that result in lower near-term production through mid-2021, and the expected continuing recovery of global hydrocarbon demand following the pandemic, we believe that crude oil prices could begin to increase as early as the second half of 2021.

However, i n the interim, we believe the midstream industry will be challenged in its producer-facing businesses and that the challenges and opportunities will be different for each producing basin.

Although the current industry and business outlooks remain challenging, we believe that our integrated, diversified and fee-based business model, will enable us to successfully traverse this difficult period.

The Partnership and its consolidated operations remain in a strong position, with o ur financial strength and operational flexibility demonstrated by the following:

At September 30, 2020, we had $6.03 billion of consolidated liquidity, which was comprised of $5.0 billion of available borrowing capacity under EPO’s revolving credit facilities and $1.03 b illion of unrestricted cash on hand.

Our liquidity is supported by investment grade credit ratings on EPO’s long-term senior unsecured debt of BBB+, Baa1 and BBB+ from Standard & Poors, Moody’s and Fitch, respectively.

EPO successfully issued $4.25 billion in principal amount of senior notes in the first nine months of 2020.

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

In light of the current downturn in the domestic energy industry, we reevaluated our planned capital investments .

Based on information currently available, we now expect our total capital investments for 2020, net of contributions from joint venture partners, to approximate $3.2 billion (originally forecast in our 2019 Form 10-K at $3.4 billion to $4.4 billion), which reflects growth capital investments of $2.9 billion and approximately $300 million for sustaining capital expenditures.

In addition, we currently expect our growth capital investments in 2021 and 2022 for sanctioned projects to approximate $1.6 billion and $800 million, respectively.

These amounts do not include capital investments associated with our proposed deepwater offshore crude oil terminal (the Sea Port Oil Terminal or “SPOT”), which remains subject to governmental approvals.

We do not expect to receive the approvals for SPOT in 2020.

We continue to optimize our assets to provide incremental services to customers and to respond to market opportunities.

As prices for certain NGLs, crude oil and refined products fell in 2020 due to collapsing demand for refined products as a result of the pandemic, our storage services provided valuable flexibility for our customers.

In addition, o ur earnings from marketing activities for the nine months ended September 30, 2020 benefited from using uncontracted storage capacity to capture contango opportunities in NGLs, crude oil and refined products .

Across all of our assets, we have contracted with a large number of quality customers in order to achieve customer diversification.

In 2019, our top 200 largest customers represented 96% of consolidated revenues.

Based on their respective year-end 2019 debt ratings, 81% of our top 200 customers were either investment grade rated or backed by letters of credit.

Additionally, only 6% of our top 200 customer revenues were attributable to sub-investment grade or non-rated upstream producers.

Given the current market environment, the rating agencies have taken numerous rating actions, including downgrades, across the energy industry.

After adjusting for all ratings actions through April 23, 2020, we estimate that 78% of our top 200 customers remain investment grade rated or are backed by letters of credit.

In light of current events, we are closely monitoring the recoverability of our long-lived assets for potential impairment.

We recognized $77.0 million and $90.4 million of non-cash asset impairment charges during the three and nine months ended September 30, 2020, respectively.

If the adverse economic impacts of the pandemic persist for longer periods than currently expected, these developments could result in our recognition of additional non-cash impairment charges in the future.

Significant Recent Commercial Developments

Expansion of Midland-to-ECHO System Enters Service

In July 2019, we announced an expansion of our Midland-to-ECHO System comprised of a 36-inch pipeline extending from Midland, Texas to our Enterprise Crude Houston (“ECHO”) terminal, and further from ECHO to a third-party terminal in Webster, Texas (collectively, the “Midland-to-Webster pipeline”).

In October 2020, we announced that the Midland-to-ECHO segment was placed into service.

We expect the ECHO-to-Webster segment to enter service in the fourth quarter of 2020.

Once all facilities are placed into full commercial service, our transportation capacity on the pipeline is expected to be approximately 450 MBPD.

We proportionately consolidate a 29% undivided interest in the Midland-to-Webster pipeline, which we refer to as the “Midland-to-ECHO 3” pipeline.

Amendments to Crude Oil Transportation Agreements;

Cancellation of Midland-to-ECHO 4 Pipeline

In September 2020, we announced the amendment of certain crude oil transportation agreements and the related cancellation of the Midland-to-ECHO 4 pipeline.

In general, the amendments provide for the reduction of near-term pipeline volume commitments in exchange for extending the term of the related transportation agreements and using existing pipeline infrastructure.

Cancellation of the Midland-to-ECHO 4 pipeline reduced our growth capital investments by an aggregate $800 million over the years 2020 through 2022.

As a result of the cancellation, we recorded an impairment charge of $42.0 million during the third quarter of 2020.

Enterprise Co-Loads Export Vessels at Houston Ship Channel Terminals

In July 2020, we completed the simultaneous loading of propane and polymer grade propylene (“PGP”) into separate compartments on a Very Large Gas Carrier at our Enterprise Hydrocarbons Terminal (“EHT”), as well as the simultaneous loading of ethane and ethylene on a vessel at our Morgan’s Point Marine Terminal.

Both vessels were the first export cargoes of their kind from the U.S.

Enterprise Enters Into Long-Term Sales Agreement in Support of PDH 2 Facility

In June 2020, we announced the execution of a long-term sales agreement with Marubeni Corporation to supply PGP from our second propane dehydrogenation plant (“PDH 2”), which is currently under construction at our Mont Belvieu complex.

Marubeni Corporation is a major Japanese integrated trading and investment business conglomerate and the world’s largest olefins trader.

PGP is a primary petrochemical that has global demand growth as a feedstock to manufacture consumer, medical and industrial products that improve the daily lives and protect the health of people around the world.

PDH 2 is expected to have the capacity to upgrade 35 MBPD of propane into 1.65 billion pounds per year (equivalent to 25 MBPD) of PGP and begin service in the second quarter of 2023.

Upon completion of PDH 2, our total capacity to produce PGP is expected to be 11 billion pounds per year, representing the largest PGP production complex in the world.

Enterprise Ramps Up Ethylene Exports at its Morgan’s Point Marine Terminal

In June 2020, we announced that the loading capacity of our jointly-owned ethylene export terminal located on the Houston Ship Channel at Morgan’s Point, Texas was exceeding our interim design expectations and that ethylene exports for June would exceed 175 million pounds.

In fact, the marine terminal loaded a record-sized ethylene cargo of 44 million pounds on the Navigator Eclipse .

We expect to complete the construction of an ethylene storage tank at the terminal site by the end of 2020, which should increase the terminal’s total loading capacity to 2.2 billion pounds per year.

The marine terminal volumes are supported by our high-capacity ethylene storage hub and pipeline system, which is connected to four ethylene pipeline systems.

We expect to complete three additional connections by the end of 2020, linking the system to a majority of ethylene production capacity in Texas.

Our open access ethylene storage hub and pipeline system provides domestic ethylene producers access to both domestic and global markets.

however, a continuation of this trend remains dependent on successful containment of the disease, the efficacy and distribution of approved vaccines on COVID-19 and its emerging variants, and proven therapeutics.

We continue to believe that our integrated, diversified and fee-based business model will enable us to successfully traverse this difficult period.

The Partnership and its consolidated operations remain in a strong position, with our financial strength and operational flexibility demonstrated by $5.11 billion of consolidated liquidity at March 31, 2021, investment grade credit ratings on EPO’s long-term senior unsecured debt, a disciplined capital spending approach, the optimization of our assets to provide incremental services to customers and to respond to market opportunities, and a portfolio of diverse, high quality customers.

The value of our diversified and integrated midstream system was exhibited again in the first quarter of 2021.

Our propylene, NGL, refined products and natural gas businesses benefited from greater demand associated with the early stages of an economic recovery, winter demand and higher commodity prices.

This was partially offset by plant and pipeline disruptions and lower volumes attributable to the impacts of major winter storms in mid-February 2021 and major maintenance activities at our PDH 1 and octane enhancement facilities.

Impact of February 2021 Winter Storms

Two major winter storms, Uri and Viola, impacted Texas and the southern U.S.

in mid-February 2021 (the “February 2021 winter storms”).

The storms had a major impact on the electric power grid in Texas, which resulted in widespread power outages.

Voluntarily and in accordance with our agreements with the Electric Reliability Council of Texas, Inc.

(“ERCOT”), we temporarily shut down our non-essential plants and other operations in Texas to support residential power consumption.

Those Texas assets that remained operational (e.g., our natural gas processing plants, storage facilities and Texas Intrastate System) were impacted by rolling blackouts.

The economic impacts of these disruptions, higher power and natural gas costs, as well as losses on natural gas hedges, were mitigated by sales of natural gas to electricity generators, natural gas utilities and industrial customers to assist them in meeting their requirements.

During and following the storms, many of our customers also experienced downtime due to freeze-related damage and repairs that impacted our volumes.

Significant Recent Developments

Enterprise to Increase Its Use of Power from Renewable Resources

In March 2021, we announced the execution of a power purchase agreement with EDF Renewables North America that will increase our use of electricity from solar power by 100 MWac/132 MWdc.

We are committed to being a responsible steward of the environment, including using energy sustainably across our footprint.

We estimate that by 2025, approximately 25% of our power will be from renewable resources.

Enterprise and Magellan to Develop Joint Houston Crude Oil Futures Contract

In January 2021, we and Magellan Midstream Partners, L.P (“Magellan”) announced that our affiliates had entered into an agreement to jointly develop a futures contract for the physical delivery of crude oil in the Houston, Texas area in response to market interest for a Houston-based index with greater scale, flow assurance and price transparency.

The quality specifications will be consistent with WTI crude oil originating from the Permian Basin with delivery capabilities at either our ECHO terminal in Houston or Magellan’s East Houston terminal.

Selected Energy Commodity Price Data

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2021 by quarter:

2020 Averages

Natural gas prices are based on Henry-Hub Inside FERC commercial index prices as reported by Platts, which is a division of McGraw Hill Financial, Inc.

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Refinery grade propylene (“RGP”) prices represent weighted-average spot prices for such product as reported by IHS Chemical.

The “Indicative Gas Processing Gross Spread” represents a generic estimate of the gross economic benefit from extracting NGLs from natural gas production based on certain pricing assumptions.

Specifically, it is the amount by which the assumed economic value of a composite gallon of NGLs at Mont Belvieu, Texas exceeds the value of the equivalent amount of energy in natural gas at Henry Hub, Louisiana (as presented in the table above).

The indicative spread does not consider the operating costs incurred by a natural gas processing facility to extract the NGLs nor the transportation and fractionation costs to deliver the NGLs to market.

The “Indicative Gas Processing Gross Spread” represents our generic estimate of the gross economic benefit from extracting NGLs from natural gas production based on certain pricing assumptions.

Our estimate of the indicative spread does not consider the operating costs incurred by a natural gas processing facility to extract the NGLs nor the transportation and fractionation costs to deliver the NGLs to market.

In addition, the actual gas processing spread earned at each plant is determined by regional pricing and extraction dynamics.

As presented in the table above, the indicative spread assumes that a gallon of NGLs is comprised of 47% ethane, 28% propane, 9% normal butane, 6% isobutane and 10% natural gasoline.

The value of an equivalent amount of energy in natural gas to one gallon of NGLs is assumed to be 8.4% of the price of a MMBtu of natural gas at Henry Hub.

The weighted-average indicative market price for NGLs was $ 0.41 per gallon in the third quarter of 2020 versus $0.39 per gallon during the third quarter of 2019.

Likewise, the weighted-average indicative market price for NGLs was $ 0.36 per gallon during the nine months ended September 30, 2020 compared to $0.48 per gallon during the same period in 2019.

The weighted-average indicative market price for NGLs was $0.61 per gallon in the first quarter of 2021 versus $0.35 per gallon in the first quarter of 2020.

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

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2021 by quarter:

2020 Averages

WTI prices are based on commercial index prices at Cushing, Oklahoma as measured by the NYMEX.

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Light Louisiana Sweet (“LLS”) prices are based on commercial index prices as reported by Platts.

The decline in commodity prices since the beginning of 2020 is attributable to the ongoing effects of the COVID-19 pandemic and, with respect to crude oil, the production dispute between Saudi Arabia and Russia.

See “ Current Outlook ” within this Part I, Item 2 for information regarding these events.

Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices.

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

The same type of correlation would be true in the case of higher energy commodity sales prices and purchase costs.

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 increase due to comparable increases in the purchase prices of the underlying energy commodities.

The same type of correlation 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 Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for information regarding our commodity hedging activities.

See Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report and “ Quantitative and Qualitative Disclosures About Market Risk ” under Part I, Item 3 of this quarterly report for information regarding our commodity hedging activities.

Income Statement Highlights

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For the Three Months

Ended September 30,

For the Nine Months

Ended September 30,

Ended March 31,

Costs and expenses:

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Cost of sales

Other operating costs and expenses

Depreciation, amortization and accretion expenses

Net gains attributable to asset sales

Asset impairment and related charges

Asset impairment charges

Other operating costs and expenses

Total operating costs and expenses

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Operating income

Other income (expense):

Interest expense

Change in fair value of Liquidity Option

Total other expense, net

Income before income taxes

Benefit from (provision for) income taxes

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Net income attributable to common unitholders

* Amount is negligible

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

For the Three Months

Ended September 30,

For the Nine Months

Ended September 30,

Ended March 31,

NGL Pipelines & Services:

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Total consolidated revenues

Third Quarter of 2020 Compared to Third Quarter of 2019 .

Total revenues for the third quarter of 2020 decreased $1.04 billion when compared to the third quarter of 2019 primarily due to a net $912.5 million decrease in marketing revenues.

Revenues from the marketing of crude oil and natural gas decreased $1.0 billion quarter-to-quarter primarily due to lower average sales prices, which accounted for a $935.0 million decrease, and lower sales volumes, which accounted for an additional $68.2 million decrease.

Revenues from the marketing of NGLs decreased $576.5 million quarter-to-quarter primarily due to lower average sales prices, which accounted for a $504.8 million decrease, and lower sales volumes, which resulted in an additional $71.7 million decrease.

Revenues from the marketing of petrochemicals and refined products increased a net $667.2 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $982.3 million increase, partially offset by lower average sales prices, which resulted in a $315.1 million decrease.

Revenues from midstream services for the third quarter of 2020 decreased $ 129.6 million when compared to the third quarter of 2019.

Revenues from our natural gas processing facilities decreased $ 54.8 million quarter-to-quarter primarily due to lower market values for the equity NGLs we receive as non-cash consideration for processing services.

Revenues from our pipeline assets decreased $43.7 million quarter-to-quarter primarily due to lower demand for crude oil, natural gas and refined products transportation services.

Lastly, third-party revenues from our Mont Belvieu NGL fractionation complex decreased $ 19.5 million quarter-to-quarter primarily due to lower fractionation fees.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019 .

Total revenues for the nine months ended September 30, 2020 decreased $4.63 billion when compared to the nine months ended September 30, 2019 primarily due to a net $4.29 billion decrease in marketing revenues.

Revenues from the marketing of crude oil and natural gas decreased $3.46 billion period-to-period primarily due to lower average sales prices, which accounted for a $2.73 billion decrease, and lower sales volumes, which accounted for an additional $728.5 million decrease.

Revenues from the marketing of NGLs decreased a net $1.55 billion period-to-period primarily due to lower average sales prices, which accounted for a $2.56 billion decrease, partially offset by the effects of higher sales volumes, which resulted in a $1.0 billion increase.

Revenues from the marketing of petrochemicals and refined products increased a net $726.4 million period-to-period primarily due to higher sales volumes, which accounted for a $1.69 billion increase, partially offset by lower average sales prices, which resulted in a $965.8 million decrease.

Revenues from midstream services for the nine months ended September 30, 2020 decreased $ 341.1 million when compared to the nine months ended September 30, 2019.

Revenues from our natural gas processing facilities decreased $ 176.9 million period-to-period primarily due to lower market values for the equity NGLs we receive as non-cash consideration for processing services.

Revenues from our Midland-to-ECHO 2 pipeline, which commenced limited service in February 2019 and full service in April 2019, increased $ 17.8 million period-to-period.

Revenues from our other pipeline assets decreased $107.3 million period-to-period primarily due to lower demand for crude oil, natural gas and refined products.

Lastly, third party revenues from our Mont Belvieu NGL fractionation complex decreased $ 84.1 million period-to-period primarily due to lower fractionation fees.

Total revenues for the first quarter of 2021 increased $1.67 billion when compared to the first quarter of 2020 primarily due to a net $1.67 billion increase in marketing revenues.

Revenues from the marketing of NGLs, natural gas, petrochemicals and refined products increased a combined $1.52 billion quarter-to-quarter primarily due to higher average sales prices, which accounted for a $2.1 billion increase, partially offset by lower sales volumes, which accounted for a $580.3 million decrease.

Revenues from the marketing of crude oil increased $142.0 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $121.7 million increase, and higher average sales prices, which accounted for an additional $20.3 million increase.

Revenues from midstream services for the first quarter of 2021 increased $6.9 million when compared to the first quarter of 2020.

Revenues from our terminal facilities increased $30.2 million quarter-to-quarter primarily due to higher deficiency fee revenue.

Revenues from our pipeline assets decreased $24.6 million quarter-to-quarter primarily due to lower demand for natural gas transportation services.

Operating costs and expenses

Third Quarter of 2020 Compared to Third Quarter of 2019 .

Total operating costs and expenses for the third quarter of 2020 decreased $1.0 billion when compared to the third quarter of 2019 primarily due to lower cost of sales.

The cost of sales associated with our marketing of crude oil and natural gas decreased a combined $986.2 million quarter-to-quarter primarily due to lower average purchase prices, which accounted for a $942.1 million decrease, and lower sales volumes, which accounted for an additional $44.1 million decrease.

The cost of sales associated with our marketing of NGLs decreased $564.4 million quarter-to-quarter primarily due to lower average purchase prices, which accounted for a $505.0 million decrease, and lower sales volumes, which accounted for an additional $59.4 million decrease.

The cost of sales associated with our marketing of petrochemicals and refined products increased a net $587.8 million quarter-to-quarter primarily due to higher sales volumes, which accounted for an $897.8 million increase, partially offset by lower average purchase prices, which accounted for a $310.0 million decrease.

Other operating costs and expenses for the third quarter of 2020 decreased $93.9 million quarter-to-quarter primarily due to lower maintenance, chemical and power-related expenses.

Depreciation, amortization and accretion expense increased $17.1 million quarter-to-quarter primarily due to assets placed into full or limited service since the third quarter of 2019 (e.g., the isobutane dehydrogenation (“iBDH”) plant, Mentone facility, Mont Belvieu Frac X and the Enterprise Navigator ethylene terminal).

Non-cash asset impairment charges increased $37.6 million quarter-to-quarter primarily due to our cancellation of the Midland-to-ECHO 4 crude oil pipeline construction project.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019 .

Total operating costs and expenses for the nine months ended September 30, 2020 decreased $4.39 billion when compared to the nine months ended September 30, 2019 primarily due to lower cost of sales.

The cost of sales associated with our marketing of crude oil and natural gas decreased a combined $3.2 billion period-to-period primarily due to lower average purchase prices, which accounted for a $2.67 billion decrease, and lower sales volumes, which accounted for an additional $524.3 million decrease.

The cost of sales associated with our marketing of NGLs decreased a net $1.82 billion period-to-period primarily due to lower average purchase prices, which accounted for a $2.63 billion decrease, partially offset by higher sales volumes, which accounted for an $809.9 million increase.

The cost of sales associated with our marketing of petrochemicals and refined products increased a net $628.4 million period-to-period primarily due to higher sales volumes, which accounted for a $1.55 billion increase, partially offset by lower average purchase prices, which accounted for a $921.1 million decrease.

Other operating costs and expenses for the nine months ended September 30, 2020 decreased $123.0 million period-to-period primarily due to lower maintenance, chemicals and power-related expenses, which accounted for a $191.7 million decrease, partially offset by higher ad valorem taxes and employee compensation costs, which accounted for a $52.3 million increase.

Depreciation, amortization and accretion expense increased $80.5 million period-to-period primarily due to assets placed into full or limited service since the first quarter of 2019 (e.g., the iBDH plant, Mentone and Orla facilities, Mont Belvieu Frac X and the Enterprise Navigator ethylene terminal).

Non-cash asset impairment charges increased $39.2 million period-to-period primarily due to our cancellation of the Midland-to-ECHO 4 crude oil pipeline construction project.

Total operating costs and expenses for the first quarter of 2021 increased $1.49 billion when compared to the first quarter of 2020 primarily due to higher cost of sales.

Cost of sales

Cost of sales increased $1.44 billion for the first quarter of 2021 when compared to the first quarter of 2020.

On a combined basis, the cost of sales associated with our marketing of NGLs, natural gas, petrochemicals and refined products increased a net $1.13 billion quarter-to-quarter primarily due to higher average purchase prices, which accounted for a $1.44 billion increase, partially offset by lower sales volumes, which accounted for a $313.7 million decrease.

The cost of sales associated with our marketing of crude oil increased $311.6 million quarter-to-quarter primarily due to higher average purchase prices, which accounted for a $199.8 million increase, and higher sales volumes, which accounted for an additional $111.8 million increase.

Depreciation, amortization and accretion expenses

Depreciation, amortization and accretion expense for the first quarter of 2021 increased a combined $15.9 million when compared to the first quarter of 2020 primarily due to assets placed into full or limited service since the first quarter of 2020 (e.g., Chambers County Fracs X and XI and the Midland-to-ECHO 3 pipeline).

Asset impairment charges

Non-cash asset impairment charges for the first quarter of 2021 increased $63.9 million when compared to the first quarter of 2020 primarily due to a $43.4 million charge attributable to a coal bed natural gas gathering system and related Val Verde treating facility, both of which were components of our San Juan Gathering System and classified as held-for-sale at March 31, 2021.

See Note 4 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for additional information regarding our asset impairment charges.

Other operating costs and expenses

Other operating costs and expenses for the first quarter of 2021 decreased $26.7 million when compared the first quarter of 2020 primarily due to lower maintenance, chemical and facility charges.

General and administrative costs

General and administrative costs decreased $5.2 million quarter-to-quarter primarily due to lower employee compensation expenses and legal and other professional services costs.

General and administrative costs increased $2.6 million period-to-period primarily due to higher professional services costs.

General and administrative costs for the first quarter of 2021 increased $0.8 million when compared to the first quarter of 2020 primarily due to higher employee compensation costs.

Equity in income of unconsolidated affiliates

Equity income from our unconsolidated affiliates for the three and nine months ended September 30, 2020 decreased $ 57.3 million and $ 95.2 million, respectively, when compared to the same periods in 2019 primarily due to decreased earnings from our investments in crude oil pipelines.

Equity income from our unconsolidated affiliates for the first quarter of 2021 increased $8.1 million when compared to the first quarter of 2020 primarily due to increased earnings from our investments in crude oil pipelines.

Operating income

Operating income for the three and nine months ended September 30, 2020 decreased $ 91.7 million and $ 333.8 m illion, respectively, when compared to the same periods in 2019 due to the previously described quarter-to-quarter and period-to-period changes in revenues, operating costs and expenses, general and administrative costs and equity in income of unconsolidated affiliates.

Operating income for the first quarter of 2021 increased $187.0 million when compared to the first quarter of 2020 due to the previously described quarter-to-quarter changes.

Interest expense

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For the Three Months

Ended September 30,

For the Nine Months

Ended September 30,

Ended March 31,

Interest charged on debt principal outstanding

1 unchanged sentence

Interest costs capitalized in connection with construction projects (1)

Amounts presented for the three and nine months ended September 30, 2019 reflect an unrealized, mark-to-market loss of $94.9 million recognized in September 2019 in connection with the exercise of swaptions.

Due to declining interest rates, the counterparties to the swaptions exercised their right to put us into ten forward-starting swaps on September 30, 2019 having an aggregate notional value of $1.0 billion.

Since the swaptions were not designated as hedging instruments and were subject to mark-to-market accounting, we incurred an unrealized, mark-to-market loss at inception of the forward-starting swaps that is reflected as an increase in interest expense for the three and nine months ended September 30, 2019.

We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase.

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Primarily reflects facility commitment fees charged in connection with our revolving credit facilities and amortization of debt issuance costs.

Interest charged on debt principal outstanding, which is a key driver of interest expense, increased a net $15.6 million quarter-to-quarter primarily due to increased debt principal amounts outstanding during the third quarter of 2020, which accounted for a $22.1 million increase, partially offset by the effect of lower overall interest rates during the third quarter of 2020, which accounted for a $6.5 million decrease.

Our weighted-average debt principal balance for the third quarter of 2020 was $30.27 billion compared to $ 27.93 billion for the third quarter of 2019.

Interest charged on debt principal outstanding, which is a key driver of interest expense, decreased a net $4.6 million quarter-to-quarter primarily due to the effects of lower overall interest rates during the first quarter of 2021, which accounted for an $8.9 million decrease, partially offset by higher debt principal amounts outstanding during the first quarter of 2021, which accounted for a $4.3 million increase.

Our weighted-average debt principal balance for the first quarter of 2021 was $29.96 billion compared to $29.39 billion for the first quarter of 2020.

In general, our debt principal balances have increased over time due to the partial debt financing of our capital investments.

For the nine months ended September 30, 2020, interest charged on debt principal outstanding increased a net $ 66.2 million period-to-period primarily due to increased debt principal amounts outstanding during the nine months ended September 30, 2020, which accounted for an $ 84.2 million increase, partially offset by the effect of lower overall interest rates during the nine months ended September 30, 2020, which accounted for an $ 18.0 million decrease.

Our weighted-average debt principal balance for the nine months ended September 30, 2020 was $ 29.84 billion compared to $27.29 billion for the nine months ended September 30, 2019.

For additional information regarding our debt obligations, see Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

For a discussion of our capital projects, see “ Capital Investments ” within this Part I, Item 2.

Change in fair value of Liquidity Option

On February 25, 2020, the Partnership received notice from Marquard & Bahls AG (“M&B”) of M&B’s election to exercise its rights (the “Liquidity Option”) under the Liquidity Option Agreement among the Partnership, OTA Holdings, Inc., a Delaware corporation previously named Oiltanking Holding Americas, Inc.

(“OTA”), and M&B dated October 1, 2014 (the “Liquidity Option Agreement”).

The Partnership settled its obligations under the Liquidity Option Agreement on March 5, 2020.

For the period in which the Liquidity Option was outstanding, we recognized non-cash expense in connection with accretion and changes in management estimates that affected the valuation of the Liquidity Option liability.

Expense amounts attributable to changes in the fair value of the Liquidity Option were $38.7 million and $123.1 million during the three and nine months ended September 30, 2019, respectively.

Expense of $2.3 million for the first quarter of 2020 primarily reflects accretion expense for the period in which the Liquidity Option liability was outstanding before it was settled on March 5, 2020.

The higher level of expense recognized in the three and nine months ended September 30, 2019 was primarily due to a decrease in the discount factor used in determining the present value of the liability.

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

For the Three Months

Ended September 30,

For the Nine Months

Ended September 30,

Ended March 31,

Deferred tax benefit (expense) attributable to OTA

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Benefit from (provision for) income taxes

On March 5, 2020, the Partnership settled its obligations under the Liquidity Option Agreement and indirectly assumed the deferred tax liability of OTA, which reflects OTA’s outside basis difference in the limited partner interests it received from the Partnership in October 2014.

Upon settlement of the Liquidity Option, the Liquidity Option liability was effectively replaced by the deferred tax liability of OTA calculated in accordance with ASC 740, Income Taxes .

At March 5, 2020, the Liquidity Option liability amount was $511.9 million.

Since the book value of the Liquidity Option liability exceeded OTA’s estimated deferred tax liability of $439.7 million on that date, we recognized a non-cash benefit in earnings of $72.2 million, which is reflected in the “Benefit from (provision for) income tax” line on our Unaudited Condensed Statement of Consolidated Operations for the nine months ended September 30, 2020.

Subsequent to March 5, 2020 and through September 30, 2020, OTA recognized an additional net, non-cash deferred income tax benefit of $85.8 million due to a decrease in the outside basis difference of its investment in the Partnership, which in turn was driven by a decline in the market price of Partnership common units since March 5, 2020.

In total, earnings for the three and nine months ended September 30, 2020 reflect $ 21.3 million and $ 158.0 million, respectively, of net deferred income tax benefit attributable to OTA.

On February 25, 2020, we received notice from Marquard & Bahls AG (“M&B”) of its election to exercise its rights under the Liquidity Option Agreement among the Partnership, OTA Holdings, Inc.

(a Delaware corporation previously named Oiltanking Holding Americas, Inc.

(“OTA”)), and M&B dated October 1, 2014 (the “Liquidity Option Agreement”).

The Partnership settled its obligations under the Liquidity Option Agreement on March 5, 2020 and indirectly assumed the deferred tax liability of OTA, which reflects OTA’s outside basis difference in the limited partner interests it received from the Partnership in October 2014.

At March 5, 2020, the Partnership’s liability recognized in connection with the Liquidity Option Agreement was $511.9 million (referred to as the “Liquidity Option liability”).

Upon settlement of the Liquidity Option Agreement, the Liquidity Option liability was effectively replaced by the deferred tax liability of OTA calculated in accordance with ASC 740, Income Taxes .

OTA recognized an additional net, non-cash deferred income tax benefit of $115.0 million primarily due to a decrease in the outside basis difference of its investment in the Partnership attributable to a decline in the market price of the Partnership’s common units subsequent to March 5, 2020 through March 31, 2020.

In total, our earnings for the first quarter of 2020 reflect $187.2 million of deferred income tax benefit attributable to OTA.

On September 30, 2020, OTA exchanged the Partnership common units it owned for non-publicly traded preferred units having a stated value of $1,000 per unit.

As a result and beginning September 30, 2020, OTA’s deferred tax liability no longer fluctuates due to market price changes in the Partnership’s common units.

For information regarding the issuance of preferred units on September 30, 2020, including the OTA-related exchange, see “Liquidity and Capital Resources” within this Part I, Item 2.

For additional information regarding income taxes, see Note 11 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

As a result, beginning September 30, 2020, OTA’s deferred tax liability no longer fluctuates due to market price changes in our common units.

Business Segment Highlights

We evaluate segment performance based on our financial measure of gross operating margin.

Our operations are reported under four business segments:

(i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services and (iv) Petrochemical & Refined Products Services.

Our business segments are generally organized and managed according to the types of services rendered (or technologies employed) and products produced and/or sold.

We evaluate segment performance based on our non-generally accepted accounting principle (“non-GAAP”) financial measure of gross operating margin.

Gross operating margin is an important performance measure of the core profitability of our operations and forms the basis of our internal financial reporting.

We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results.

The following table presents gross operating margin by segment and non-generally accepted accounting principle (“non-GAAP”) total gross operating margin for the periods indicated (dollars in millions):

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

For the Three Months

Ended September 30,

For the Nine Months

Ended September 30,

Ended March 31,

Gross operating margin by segment:

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For the Three Months

Ended September 30,

For the Nine Months

Ended September 30,

Ended March 31,

Operating income

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(addition or subtraction indicated by sign):

Depreciation, amortization and accretion expense in operating costs and

Asset impairment and related charges in operating costs and expenses

Net gains attributable to asset sales in operating costs and expenses

Depreciation, amortization and accretion expense in operating costs and expenses (1)

Asset impairment charges in operating costs and expenses

Net losses attributable to asset sales and related matters in operating costs

General and administrative costs

Total gross operating margin (non-GAAP)

Excludes amortization of major maintenance costs for reaction-based plants, which are a component of gross operating margin.

Each of our business segments benefits from the supporting role of our marketing activities.

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The financial results of our marketing efforts fluctuate due to changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for the products bought and sold.

As a result of the COVID-19 pandemic and lower energy commodity prices, we experienced a reduction in volumes on a number of our assets (e.g., crude oil pipelines and export docks, natural gas gathering systems) during the three and nine months ended September 30, 2020 due to reduced upstream drilling and production activity and lower downstream refinery activity and demand for transportation fuels.

Furthermore, we may continue to experience throughput declines in the future on our gathering systems, long-haul liquids and natural gas pipelines and at our terminal and other facilities until the pandemic ends and economic activity is fully restored.

For a general discussion of the impact of the pandemic on our partnership and industry, see “ Current Outlook” within this Part I, Item 2.

NGL Pipelines & Service s

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For the Three Months

Ended September 30,

For the Nine Months

Ended September 30,

Ended March 31,

Segment gross operating margin:

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Natural gas processing and related NGL marketing activities

Third Quarter of 2020 Compared to Third Quarter of 2019 .

Gross operating margin from natural gas processing and related NGL marketing activities for the third quarter of 2020 decreased $ 31.2 million when compared to the third quarter of 2019.

Gross operating margin from our natural gas processing facilities located in the Rocky Mountains (Meeker, Pioneer and Chaco plants) decreased a combined $ 23.0 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $27.2 million decrease, and lower processing volumes, which accounted for an additional $8.2 million decrease, partially offset by lower operating costs, which accounted for a $9.0 million increase.

On a combined basis, fee-based natural gas processing volumes at these plants decreased 398 MMcf/d and equity NGL production volumes increased 28 MBPD quarter-to-quarter.

Gross operating margin from our South Texas natural gas processing facilities decreased $ 22.9 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for an $ 8.9 million decrease, lower average processing fees, which accounted for a $ 6.8 million decrease, and lower processing volumes, which accounted for an additional $5.5 million decrease.

On a combined basis, fee-based natural gas processing volumes at our South Texas plants decreased 242 MMcf/d and equity NGL production volumes increased 6 MBPD quarter-to-quarter.

Gross operating margin from our Louisiana and Mississippi natural gas processing facilities decreased $ 8.1 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $4.7 million decrease, and lower processing volumes, which accounted for an additional $3.9 million decrease.

On a combined basis, fee-based natural gas processing and equity NGL production volumes at our Louisiana and Mississippi plants decreased 374 MMcf/d and 7 MBPD, respectively, quarter-to-quarter (net to our interest).

Certain plants in Louisiana and Mississippi were impacted by lower Gulf of Mexico production as a result of shut-ins associated with Hurricane Laura in August 2020.

Gross operating margin from our Permian Basin natural gas processing facilities increased a net $ 5.4 million quarter-to-quarter primarily due to higher processing volumes, which accounted for a $13.4 million increase, partially offset by lower average processing fees, which accounted for a $ 5.8 million decrease, and lower average processing margins (including the impact of hedging activities), which accounted for an additional $3.7 million decrease.

On a combined basis, fee-based natural gas processing volumes at our Permian Basin plants increased 345 MMcf/d quarter-to-quarter.

Gross operating margin from our NGL marketing activities increased a net $ 16.8 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $36.1 million increase, partially offset by lower average sales margins (including the impact of hedging activities), which accounted for a $19.4 million decrease.

The quarter-to-quarter increase in gross operating margin can be attributed to results from marketing strategies that seek to optimize our storage assets, which accounted for a $68.5 million increase, partially offset by lower earnings from strategies that seek to optimize our export, plant and transportation assets, which accounted for a combined $40.6 million decrease.

In addition, gross operating margin from our NGL marketing activities attributable to non-cash, mark-to-market earnings decreased $11.1 million quarter-to-quarter.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019 .

Gross operating margin from natural gas processing and related NGL marketing activities for the nine months ended September 30, 2020 decreased $ 121.0 million when compared to the nine months ended September 30, 2019.

Gross operating margin from our Rocky Mountains natural gas processing facilities decreased a combined $ 80.8 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities).

On a combined basis, fee-based natural gas processing volumes at our plants in the Rockies decreased 305 MMcf/d and equity NGL production volumes increased 6 MBPD period-to-period.

Gross operating margin from our South Texas natural gas processing facilities decreased $ 65.5 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $ 41.4 million decrease, lower average processing fees, which accounted for an $ 11.0 million decrease, and lower processing volumes, which accounted for an additional $11.2 million decrease.

On a combined basis, fee-based natural gas processing volumes at these plants decreased 141 MMcf/d and equity NGL production volumes increased 7 MBPD period-to-period.

Gross operating margin from our Permian Basin natural gas processing facilities decreased a net $ 13.8 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $ 20.9 million decrease, lower average processing fees, which accounted for a $15.4 million decrease, and higher operating costs, which accounted for an additional $ 9.9 million decrease, partially offset by higher processing volumes, which accounted for a $33.0 million increase.

On a combined basis, fee-based natural gas processing and equity NGL production volumes at our Permian Basin plants increased 287 MMcf/d and 7 MBPD, respectively, period-to-period, primarily due to additional processing capacity at our Orla facility placed into service in July 2019 and the start-up of our Mentone facility in December 2019.

Gross operating margin from our Louisiana and Mississippi natural gas processing facilities decreased a net $ 20.9 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $ 22.6 million decrease, and lower processing volumes, which accounted for an additional $10.3 million decrease, partially offset by higher average processing fees, which accounted for a $7.9 million increase, and lower operating costs, which accounted for an additional $ 6.6 million increase.

Net to our interest, fee-based natural gas processing volumes at these plants decreased a combined 319 MMcf/d period-to-period.

Gross operating margin from our NGL marketing activities increased a net $ 65.4 million period-to-period primarily due to higher sales volumes, which accounted for a $193.7 million increase, partially offset by lower average sales margins (including the impact of hedging activities), which accounted for a $128.2 million decrease.

The period-to-period increase in gross operating margin can be attributed to results from marketing strategies that seek to optimize our storage and transportation assets, which accounted for a combined $97.7 million increase, partially offset by lower earnings from strategies that seek to optimize our export and plant assets, which accounted for a combined $40.2 million decrease.

In addition, gross operating margin from our NGL marketing activities attributable to non-cash, mark-to-market earnings increased $7.9 million period-to-period.

Gross operating margin from natural gas processing and related NGL marketing activities for the first quarter of 2021 increased $42.0 million when compared to the first quarter of 2020.

Gross operating margin from our NGL marketing activities increased $96.7 million quarter-to-quarter primarily due to higher average sales margins (including the impact of hedging activities), which accounted for a $53.7 million increase, and higher sales volumes, which accounted for an additional $46.6 million increase.

Results from marketing strategies that optimize our transportation, storage and plant assets increased a combined $95.4 million quarter-to-quarter, partially offset by lower earnings from the optimization of our export assets, which accounted for a $47.1 million decrease.

Gross operating margin from our Permian Basin natural gas processing facilities increased $10.0 million quarter-to-quarter primarily due to higher fee-based processing volumes, which accounted for a $6.7 million increase, and higher average processing margins (including the impact of hedging activities), which accounted for an additional $3.5 million increase.

Fee-based processing volumes and equity NGL production at our Permian Basin natural gas processing facilities increased 193 MMcf/d and 31 MBPD, respectively, quarter-to-quarter.

Gross operating margin from our South Texas natural gas processing facilities decreased $41.2 million quarter-to-quarter primarily due to lower equity NGL production of 6 MBPD, which accounted for a $28.8 million decrease, lower average processing fees and volumes, which accounted for decreases of $12.3 million and $3.7 million, respectively, and higher operating and maintenance costs, which accounted for an additional $6.1 million decrease.

Partially offsetting these negative impacts were higher average processing margins (including the impact of hedging activities), which accounted for a $9.8 million quarter-to-quarter increase.

Fee-based processing volumes at our South Texas natural gas processing facilities decreased 213 MMcf/d quarter-to-quarter.

Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased a combined $21.5 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $19.4 million decrease, and lower fee-based processing volumes, which accounted for an additional $6.2 million decrease, partially offset by lower operating costs, which accounted for a $4.1 million increase.

On a combined basis, fee-based natural gas processing volumes decreased 402 MMcf/d quarter-to-quarter.

Gross operating margin from our Louisiana and Mississippi natural gas processing facilities decreased $1.2 million quarter-to-quarter primarily due to lower average processing fees.

Net to our interest, fee-based natural gas processing volumes and equity NGL production decreased 184 MMcf/d and 5 MBPD, respectively, quarter-to-quarter.

NGL pipelines, storage and terminals

Third Quarter of 2020 Compared to Third Quarter of 2019 .

Gross operating margin from our NGL pipelines, storage and terminal assets for the third quarter of 2020 increased $9.5 million when compared to the third quarter of 2019.

Gross operating margin from our NGL pipelines, storage and terminal assets during the first quarter of 2021 decreased $26.7 million when compared to the first quarter of 2020.

A number of our pipelines, including the Mid-America Pipeline System, Seminole NGL Pipeline, Chaparral NGL Pipeline, Shin Oak NGL Pipeline, Texas Express Pipeline and Front Range Pipeline, serve Permian Basin and/or Rocky Mountain producers.

On a combined basis, gross operating margin from these pipelines increased a net $11.1 million quarter-to-quarter primarily due to higher average transportation fees, which accounted for an $18.0 million increase, lower operating costs, which accounted for an additional $6.4 million increase, partially offset by lower transportation volumes of 43 MBPD (net to our interest), which accounted for a $7.1 million decrease.

Gross operating margin from LPG-related activities at EHT increased $4.5 million quarter-to-quarter primarily due to higher export volumes of 45 MBPD.

Gross operating margin from our Houston Ship Channel Pipeline System increased $ 3.1 million quarter-to-quarter primarily due to a 39 MBPD increase in transportation volumes.

Gross operating margin from our Mont Belvieu storage facility decreased a net $ 7.7 million quarter-to-quarter primarily due to lower handling and throughput fee revenues, which accounted for an $ 18.5 million decrease, partially offset by higher storage fees, which accounted for a $ 13.3 million increase.

Gross operating margin from our Dixie Pipeline and related terminals decreased a combined $ 4.7 million quarter-to-quarter primarily due to lower transportation volumes of 57 MBPD.

Gross operating margin from our South Louisiana NGL Pipeline System and related storage facilities decreased a combined $7.1 million quarter-to-quarter primarily due to lower transportation volumes of 69 MBPD, which accounted for a $4.9 million decrease, and lower loading and other fee revenues, which accounted for an additional $1.3 million decrease.

The decrease in transportation volumes for these pipelines in the third quarter of 2020 was partially due to the effects of Hurricane Laura, which caused shut-ins of Gulf of Mexico production as well as power outages at certain pump stations.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019 .

Gross operating margin from our NGL pipelines, storage and terminal assets for the nine months ended September 30, 2020 increased $123.1 million when compared to the nine months ended September 30, 2019.

On a combined basis, gross operating margin from our pipelines serving Permian Basin and/or Rocky Mountain producers increased a net $63.1 million period-to-period primarily due to higher average transportation fees, which accounted for a $47.1 million increase, and lower operating costs, which accounted for an additional $26.8 million increase, partially offset by lower transportation volumes, which accounted for a $7.2 million decrease.

Transportation volumes from these pipelines decreased a combined 99 MBPD (net to our interest).

Gross operating margin from LPG-related activities at EHT increased $53.1 million period-to-period primarily due to higher export volumes of 116 MBPD.

The increase in export volumes is attributable to an LPG expansion project at EHT that was completed in the third quarter of 2019.

Gross operating margin from our Houston Ship Channel Pipeline System increased $ 14.9 million period-to-period primarily due to a 92 MBPD increase in transportation volumes.

Gross operating margin from our Aegis Pipeline increased $29.8 million period-to-period primarily due to a 115 MBPD increase in transportation volumes associated with contract commitments.

Gross operating margin from our Mont Belvieu storage facility decreased a net $ 15.4 million period-to-period primarily due to lower handling and throughput fee revenues, which accounted for a $ 31.5 million decrease, partially offset by higher storage fees, which accounted for an $ 18.4 million increase.

Gross operating margin from our South Louisiana NGL Pipeline System and related storage facilities decreased a combined $ 15.1 million period-to-period primarily due to lower transportation volumes of 42 MBPD, which accounted for a $6.3 million decrease, and lower terminal revenues, which accounted for an additional $6.2 million decrease.

Gross operating margin from our South Texas NGL Pipeline System decreased $ 9.6 million period-to-period primarily due to lower pipeline capacity fee revenues earned from an affiliate pipeline.

Transportation volumes on our South Texas NGL Pipeline System increased 30 MBPD period-to-period.

On a combined basis, gross operating margin from these pipelines decreased a net $21.8 million quarter-to-quarter primarily due to lower transportation volumes of 213 MBPD (net to our interest), which accounted for a $44.0 million decrease, partially offset by higher average transportation fees, which accounted for an $18.6 million increase.

Gross operating margin from LPG-related activities at EHT decreased $15.1 million quarter-to-quarter primarily due to lower export volumes of 95 MBPD.

Gross operating margin from our related Houston Ship Channel Pipeline System decreased $3.6 million quarter-to-quarter primarily due to a 144 MBPD decrease in transportation volumes.

Our marine terminal operations on the Houston Ship Channel were halted for 3 days due to closure of the ship channel during the February 2021 winter storms.

Gross operating margin from our South Texas NGL Pipeline System decreased $4.9 million quarter-to-quarter primarily due to lower transportation volumes of 55 MBPD.

Gross operating margin from our South Louisiana storage facilities increased $4.6 million quarter-to-quarter primarily due to higher product blending revenues.

Gross operating margin from our Chambers County storage complex increased a net $4.4 million quarter-to-quarter primarily due to higher storage fees, which accounted for a $15.1 million increase, partially offset by lower throughput fee revenues, which accounted for an $8.4 million decrease, and higher operating costs, which accounted for an additional $3.4 million decrease.

NGL fractionation

Third Quarter of 2020 Compared to Third Quarter of 2019 .

Gross operating margin from NGL fractionation for the third quarter of 2020 increased $41.5 million when compared to the third quarter of 2019 primarily due to higher fractionation volumes at our Mont Belvieu NGL fractionation complex, which increased 348 MBPD quarter-to-quarter (net to our interest) primarily due to the start-up of the first and second fractionation units (“Frac X” and “Frac XI”) in March 2020 and September 2020, respectively, at our newly completed NGL fractionation facility located in Chambers County, Texas.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019 .

Gross operating margin from NGL fractionation during the nine months ended September 30, 2020 increased $102.3 million when compared to the nine months ended September 30, 2019.

Gross operating margin from our Mont Belvieu NGL fractionation complex increased $ 65.4 million primarily due to higher fractionation volumes, which increased 341 MBPD period-to-period (net to our interest) primarily due to the start-up of Frac X and Frac XI.

Gross operating margin from our Hobbs NGL fractionator increased $ 21.3 million period-to-period primarily due to major maintenance activities during the first quarter of 2019.

NGL fractionation volumes at our Hobbs NGL fractionator increased 17 MBPD period-to-period.

Gross operating margin from our South Texas NGL fractionators increased $ 8.6 million period-to-period primarily due to lower maintenance and other operating costs, which accounted for a $4.4 million increase, and higher NGL fractionation volumes of 17 MBPD, which accounted for an additional $4.2 million increase.

Gross operating margin from NGL fractionation during the first quarter of 2021 increased $29.1 million when compared to the first quarter of 2020.

Gross operating margin from our Chambers County NGL fractionation complex increased $41.2 million quarter-to-quarter primarily due to higher volumes, including contributions from Frac X, which entered service in late March 2020, and Frac XI, which entered service in September 2020.

NGL fractionation volumes increased 159 MBPD quarter-to-quarter (net to our interest).

Gross operating margin from our South Texas NGL fractionators decreased $4.7 million quarter-to-quarter primarily due to lower NGL fractionation volumes of 49 MBPD.

Crude Oil Pipelines & Services

1 unchanged sentence

For the Three Months

Ended September 30,

For the Nine Months

Ended September 30,

Ended March 31,

Segment gross operating margin:

Midland-to-ECHO System:

Midland-to-ECHO 1 pipeline and related business activities,

excluding associated non-cash mark-to-market results

Non-cash mark-to-market gains (losses)

Total Midland-to-ECHO 1 pipeline and related business activities

Midland-to-ECHO 2 pipeline

Total Midland-to-ECHO System

Midland-to-ECHO System and related business activities

Other crude oil pipelines, terminals and related marketing results

2 unchanged sentences

Crude oil marine terminal volumes (MBPD)

In general, segment volumes for the three and nine months ended September 30, 2020 were adversely impacted by the reduction in upstream crude oil production activities caused by the pandemic and crude oil price shock.

Third Quarter of 2020 Compared to Third Quarter of 2019 .

Gross operating margin from our Crude Oil Pipelines & Services segment for the third quarter of 2020 decreased $14.4 million when compared to the third quarter of 2019.

Gross operating margin from our Midland-to-ECHO System and related business activities decreased a net $ 40.7 million quarter-to-quarter primarily due to lower average sales margins from marketing activities (including the impact of hedging activities), which accounted for a $42.9 million decrease, lower transportation volumes, which accounted for a $10.1 million decrease, and lower deficiency and other revenues, which accounted for an additional $12.1 million decrease, partially offset by lower chemical and other operating costs of $ 21.8 million.

Gross operating margin from our equity investment in the Eagle Ford Crude Oil Pipeline decreased $8.9 million quarter-to-quarter primarily due to lower transportation volumes.

Gross operating margin from our South Texas Crude Oil Pipeline System decreased $15.6 million quarter-to-quarter primarily due to lower transportation volumes.

On an aggregate basis, transportation volumes on these three pipeline systems decreased 180 MBPD quarter-to-quarter (net to our interest).

Gross operating margin from our equity investment in the Seaway Pipeline decreased $17.5 million quarter-to-quarter primarily due to lower average transportation fees, which accounted for a $10.9 million decrease, and lower transportation volumes, which accounted for an additional $7.5 million decrease.

Net to our interest, transportation and marine volumes on the Seaway Pipeline decreased 269 MBPD and 75 MBPD, respectively, quarter-to-quarter.

Gross operating margin from our Crude Oil Pipelines & Services segment for the first quarter of 2021 decreased $52.7 million when compared to the first quarter of 2020.

Gross operating margin from our South Texas Crude Oil Pipeline System decreased $25.7 million quarter-to-quarter primarily due to lower transportation and other fees, which accounted for a $15.3 million decrease, and lower transportation volumes of 49 MBPD, which accounted for an additional $12.4 million decrease.

Gross operating margin from our equity investment in the Eagle Ford Crude Oil Pipeline decreased $11.3 million quarter-to-quarter primarily due to lower transportation volumes of 93 MBPD (net to our interest).

Gross operating margin from our West Texas Pipeline System decreased $19.9 million quarter-to-quarter primarily due to lower transportation volumes of 57 MBPD, which accounted for an $8.4 million decrease, and lower average fees, which accounted for an additional $7.9 million decrease.

Gross operating margin from our Midland-to-ECHO System and related business activities decreased $11.4 million quarter-to-quarter primarily due to lower average sales margins from marketing activities (including the impact of hedging activities), which accounted for a $21.2 million decrease, partially offset by lower chemical and other operating costs, which accounted for a $12.1 million increase.

Transportation volumes for our Midland-to-ECHO System decreased an aggregate 6 MBPD quarter-to-quarter (net to our interest).

Gross operating margin from our ECHO terminal decreased $4.9 million quarter-to-quarter primarily due to lower terminaling and storage revenues.

Gross operating margin from crude oil activities at EHT decreased a net $14.2 million quarter-to-quarter primarily due to lower deficiency fees, which accounted for a $22.7 million decrease, partially offset by higher storage and other revenues, which accounted for an $8.5 million increase, and lower operating costs, which accounted for an additional $3.0 million increase.

Crude oil terminal volumes at EHT decreased by 183 MBPD quarter-to-quarter.

Gross operating margin from our other crude oil marketing activities increased $16.6 million quarter-to-quarter primarily due to higher average sales margins (including the impact of hedging activities).

The quarter-to-quarter increase in gross operating margin from our crude oil marketing activities, including those related to our Midland-to-ECHO System, is primarily due to results from marketing strategies that seek to optimize our storage assets.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019 .

Gross operating margin from our Crude Oil Pipelines & Services segment for the nine months ended September 30, 2020 decreased $102.6 million when compared to the nine months ended September 30, 2019.

Gross operating margin from our Midland-to-ECHO System and related business activities decreased $ 194.3 million period-to-period primarily due to lower average sales margins from marketing activities (including the impact of hedging activities) of $ 208.0 million, partially offset by lower chemical and other operating costs of $37.7 million.

Gross operating margin from our South Texas Crude Oil Pipeline System decreased $32.8 million period-to-period primarily due to lower transportation volumes, which accounted for a $24.2 million decrease, and lower transportation and other fees, which accounted for an additional $13.0 million decrease.

Gross operating margin from our equity investment in the Eagle Ford Crude Oil Pipeline decreased $21.5 million period-to-period primarily due to lower transportation volumes.

On an aggregate basis, transportation volumes on these three pipeline systems decreased 98 MBPD period-to-period (net to our interest).

Gross operating margin from our equity investment in the Seaway Pipeline decreased a net $44.7 million period-to-period primarily due to lower transportation volumes, which accounted for a $30.3 million decrease, and lower average transportation fees, which accounted for an additional $17.4 million decrease.

Net to our interest, transportation and marine volumes on the Seaway Pipeline decreased 171 MBPD and 23 MBPD, respectively, period-to-period.

Gross operating margin from our ECHO terminal decreased $25.0 million period-to-period primarily due to a benefit recognized during the second quarter of 2019 in connection with a settlement, which accounted for $13.9 million of the decrease, and lower terminaling and storage revenue, which accounted for an additional $12.9 million decrease.

Gross operating margin from our other crude oil marketing activities increased $192.9 million period-to-period primarily due to higher average sales margins (including the impact of hedging activities).

The period-to-period increase in gross operating margin from our crude oil marketing activities, including those related to our Midland-to-ECHO System, is primarily due to results from marketing strategies that seek to optimize our storage assets.

Gross operating margin from our West Texas System increased $9.5 million period-to-period primarily due to higher deficiency fees.

Transportation volumes decreased 4 MBPD period-to-period.

Lastly, gross operating margin from our EFS Midstream system increased $9.1 million period-to-period primarily due to higher average transportation fees.

Gross operating margin from crude oil activities at EHT increased $8.9 million quarter-to-quarter primarily due to lower operating costs.

Loading volumes at EHT decreased 380 MBPD in the first quarter of 2021 due to lower export activity.

Gross operating margin from our equity investment in the Seaway Pipeline increased slightly quarter-to-quarter.

Higher capacity and other fees of $9.0 million quarter-to-quarter were substantially offset by the effects of lower transportation volumes of 182 MBPD (net to our interest), which accounted for a $7.7 million decrease.

Natural Gas Pipelines & Services

1 unchanged sentence

For the Three Months

Ended September 30,

For the Nine Months

Ended September 30,

Ended March 31,

Segment gross operating margin

1 unchanged sentence

Natural gas pipeline transportation volumes (BBtus/d)

Third Quarter of 2020 Compared to Third Quarter of 2019 .

Gross operating margin from our Natural Gas Pipelines & Services segment for the third quarter of 2020 decreased $50.1 million when compared to the third quarter of 2019.

Gross operating margin from our natural gas marketing activities decreased $35.0 million quarter-to-quarter primarily due to lower average sales margins (including the impact of hedging activities), which were negatively impacted by lower regional natural gas price spreads across Texas.

The indicative price spreads averaged $0.72 per MMBtu for the third quarter of 2020 versus $1.36 per MMBtu for the third quarter of 2019.

Gross operating margin from our Acadian Gas System decreased $19.4 million quarter-to-quarter primarily due to benefits from settlements received in the third quarter of 2019, which accounted for a $16.7 million decrease, and lower capacity reservation revenues on the Haynesville Extension pipeline, which accounted for an additional $6.0 million decrease.

Transportation volumes on our Acadian Gas System decreased 302 BBtus/d quarter-to-quarter.

Gross operating margin from our Permian Basin Gathering System increased $9.2 million quarter-to-quarter primarily due to higher volumes of 432 BBtus/d.

On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System, and San Juan Gathering System in the Rocky Mountains decreased a net $2.4 million quarter-to-quarter primarily due to lower volumes of 577 BBtus/d, which accounted for an $11.9 million decrease, partially offset by lower operating costs, which accounted for an $8.0 million increase.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019 .

Gross operating margin from our Natural Gas Pipelines & Services segment for the nine months ended September 30, 2020 decreased $123.5 million when compared to the nine months ended September 30, 2019.

Gross operating margin from our Texas Intrastate System decreased $45.5 million period-to-period primarily due to lower capacity reservation revenues.

Transportation volumes on our Texas Intrastate System decreased 280 BBtus/d period-to-period.

Gross operating margin from our Acadian Gas System decreased $42.8 million period-to-period primarily due to lower capacity reservation revenues on the Haynesville Extension pipeline, which accounted for a $27.1 million decrease, and net benefits from settlements, which accounted for an additional $15.4 million decrease.

Transportation volumes on our Acadian Gas System decreased 164 BBtus/d period-to-period.

Gross operating margin from our Haynesville Gathering System decreased $17.2 million period-to-period primarily due to lower gathering volumes of 223 BBtus/d, which accounted for an $11.0 million decrease, and lower gathering, compression and other fee revenues, which accounted for an additional $9.7 million decrease.

On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System, and San Juan Gathering System in the Rockies decreased a net $13.6 million period-to-period primarily due to lower volumes of 483 BBtus/d, which accounted for a $30.6 million decrease, partially offset by lower operating costs, which accounted for a $16.3 million increase.

Gross operating margin from our natural gas marketing activities decreased $38.9 million period-to-period primarily due to lower average sales margins (including the impact of hedging activities), which accounted for a $27.3 million decrease, and lower sales volumes, which accounted for an additional $11.6 million decrease.

Gross operating margin from our Permian Basin Gathering System increased $22.9 million period-to-period primarily due to a 337 BBtus/d increase in natural gas gathering volumes.

Gross operating margin from our Natural Gas Pipelines & Services segment for the first quarter of 2021 increased $251.4 million when compared to the first quarter of 2020.

As noted previously, two major winter storms impacted Texas and the southern U.S.

in mid-February 2021.

Given the high demand for natural gas during the storms, we sold natural gas to assist electricity generators, natural gas utilities and industrial customers in meeting their requirements.

Gross operating margin from natural gas marketing activities increased $265.9 million quarter-to-quarter primarily due to higher average sales margins (including the impact of hedging activities) in connection with these unusual storm events.

Gross operating margin from our Permian Basin Gathering System increased $14.1 million quarter-to-quarter primarily due to higher average condensate sales prices, which accounted for a $6.1 million increase, higher condensate sales volumes, which accounted for a $4.5 million increase, and higher natural gas gathering volumes of 361 BBtus/d, which accounted for an additional $4.3 million increase, partially offset by lower average gathering fees, which accounted for a $2.9 million decrease.

The quarter-to-quarter increase in gathering volumes is attributable to deliveries at our Orla and Mentone facilities.

On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System, and San Juan Gathering System in the Rocky Mountains increased a net $0.8 million quarter-to-quarter primarily due to higher average gathering and other fees, which accounted for a $6.9 million increase, and lower operating costs, which accounted for an additional $3.6 million increase, partially offset by lower gathering volumes of 503 BBtus/d, which accounted for a $9.7 million decrease.

Gross operating margin from our Acadian Gas System decreased $14.2 million primarily due to a one-time producer payment in the first quarter of 2020, which accounted for a $12.5 million quarter-to-quarter decrease, and lower capacity reservation fees, which accounted for an additional $4.9 million decrease.

Transportation volumes for the Acadian Gas System decreased 60 BBtus/d quarter-to-quarter.

Gross operating margin from our Texas Intrastate System decreased $12.1 million quarter-to-quarter primarily due to lower capacity reservation revenues.

Transportation volumes on our Texas Intrastate System decreased 11 BBtus/d.

Petrochemical & Refined Products Services

1 unchanged sentence

For the Three Months

Ended September 30,

For the Nine Months

Ended September 30,

Ended March 31,

Segment gross operating margin:

7 unchanged sentences

Butane isomerization volumes (MBPD)

Standalone DIB processing volumes (MBPD)

Standalone deisobutanizer (“DIB”) processing volumes (MBPD)

Octane enhancement and related plant sales volumes (MBPD) (1)

Pipeline transportation volumes, primarily refined products &

petrochemicals (MBPD)

Marine terminal volumes, primarily refined products and

petrochemicals (MBPD)

Reflects aggregate sales volumes for our octane additive and iBDH facilities located at our Mont Belvieu complex and our high-purity isobutylene production facility located adjacent to the Houston Ship Channel.

Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD)

Marine terminal volumes, primarily refined products and petrochemicals (MBPD)

Reflects aggregate sales volumes for our octane additive and iBDH facilities located at our Chambers County complex and our HPIB facility located adjacent to the Houston Ship Channel.

Propylene production and related activities

Third Quarter of 2020 Compared to Third Quarter of 2019 .

Gross operating margin from propylene production and related activities for the third quarter of 2020 increased $2.3 million when compared to the third quarter of 2019.

Gross operating margin from our Lou-Tex propylene pipeline increased a net $2.9 million quarter-to-quarter primarily due to higher average transportation fees, which accounted for a $5.6 million increase, partially offset by lower transportation volumes of 5 MBPD, which accounted for a $2.5 million decrease.

Gross operating margin from our Louisiana RGP Gathering System increased $2.4 million quarter-to-quarter primarily due to higher deficiency fee revenues.

Gross operating margin from our propylene production facilities decreased a combined $4.3 million quarter-to-quarter primarily due to lower average sales margins, which accounted for an $11.6 million decrease, lower propylene and associated by-product sales volumes, which accounted for an additional $11.2 million decrease, partially offset by higher fractionation and other fees, which accounted for a $12.4 million increase, and lower operating costs, which accounted for an additional $6.1 million increase.

Propylene and associated by-product volumes at these facilities decreased a combined 20 MBPD quarter-to-quarter (net to our interest).

As refiners reduced their utilization rates in response to lower demand for refined products caused by the pandemic, there was a decrease in the availability of refinery grade propylene feedstock used by our facilities to create polymer grade propylene, which contributed to the reduction in our volumes.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019 .

Gross operating margin from propylene production and related activities for the nine months ended September 30, 2020 decreased $64.6 million.

Gross operating margin from our propylene production facilities decreased a combined $70.7 million period-to-period when compared to the nine months ended September 30, 2019 primarily due to lower average sales margins, which accounted for a $62.2 million decrease, and lower propylene and associated by-product sales volumes, which accounted for an additional $23.6 million decrease, partially offset by lower operating costs, which accounted for a $7.1 million increase.

Propylene production volumes at these facilities decreased a combined 14 MBPD period-to-period (net to our interest).

Gross operating margin from our propylene export terminals increased $7.0 million period-to-period primarily due to higher average terminal fees.

Propylene export volumes decreased 6 MBPD period-to-period.

Isomerization and related operations

Third Quarter of 2020 Compared to Third Quarter of 2019 .

Gross operating margin from isomerization and related operations increased $3.2 million quarter-to-quarter primarily due to an increase in blending revenues, which accounted for a $1.9 million increase, and higher standalone DIB processing volumes of 17 MBPD, which accounted for an additional $1.3 million increase.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019 .

Gross operating margin from isomerization and related operations decreased $15.8 million period-to-period primarily due to lower average by-product sales prices, which accounted for a $17.9 million decrease, and lower isomerization volumes of 18 MBPD, which accounted for an additional $9.5 million decrease, partially offset by lower operating costs, which accounted for a $13.7 million increase.

Gross operating margin from propylene production and related activities for the first quarter of 2021 increased $37.4 million when compared to the first quarter of 2020.

Gross operating margin from our propylene production facilities increased a combined $27.8 million quarter-to-quarter primarily due to higher propylene fractionation fees, which accounted for a $24.7 million increase, and lower operating costs, which accounted for an additional $10.2 million increase, partially offset by lower propylene and associated by-product sales volumes, which accounted for an $8.2 million decrease.

Propylene and associated by-product volumes at these facilities decreased a combined 16 MBPD quarter-to-quarter (net to our interest) primarily due to planned major maintenance activities at our PDH 1 facility during the first quarter of 2021.

The PDH 1 facility returned to service during the second half of March 2021.

Gross operating margin from our propylene pipelines in Louisiana increased $6.3 million quarter-to-quarter primarily due to higher transportation volumes of 22 MBPD.

Butane isomerization and related operations

Gross operating margin from butane isomerization and related operations decreased $4.9 million quarter-to-quarter primarily due to lower isomerization volumes, which accounted for a $6.4 million decrease.

Octane enhancement and related plant operations

Third Quarter of 2020 Compared to Third Quarter of 2019 .

Gross operating margin from our octane enhancement and related plant operations decreased $14.6 million quarter-to-quarter primarily due to lower average sales margins, which accounted for a $9.1 million decrease, and higher operating expenses, which accounted for an additional $7.1 million decrease.

The increase in operating expenses is primarily due to our iBDH plant, which is integrated with our legacy octane enhancement and high purity isobutylene assets and was placed into service in December 2019.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019 .

Gross operating margin from our octane enhancement and related plant operations increased $14.3 million period-to-period primarily due to higher average sales margins, which accounted for a $19.1 million increase, and higher sales volumes, which accounted for an additional $9.3 million increase, partially offset by higher operating expenses, which accounted for a $17.6 million decrease and largely attributable to start-up of the iBDH plant.

Gross operating margin from our octane enhancement and related plant operations decreased $53.5 million quarter-to-quarter primarily due to lower average sales margins (including the impact of hedging), which accounted for a $32.4 million decrease, and lower sales volumes, which accounted for an additional $21.1 million decrease.

Volumes at these facilities were lower in the first quarter of 2021 due to planned major maintenance activities, which were completed in the last week of January 2021 for our HPIB plant and the beginning of May 2021 for our octane enhancement plant.

Refined products pipelines and related activities

Third Quarter of 2020 Compared to Third Quarter of 2019 .

Gross operating margin from refined products pipelines and related activities for the third quarter of 2020 increased $27.1 million when compared to the third quarter of 2019.

Gross operating margin from our refined products marketing activities increased a net $30.6 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $45.7 million increase, partially offset by lower average sales margins (including the impact of hedging activities), which accounted for a $15.2 million decrease.

The quarter-to-quarter increase in gross operating margin from our refined products marketing activities is primarily due to results from marketing strategies that seek to optimize our storage assets.

Gross operating margin from our TE Products Pipeline System decreased a net $8.1 million quarter-to-quarter primarily due to lower average NGL transportation fees, which accounted for a $17.4 million decrease, partially offset by higher average petrochemical transportation fees, which accounted for a $10.6 million increase.

Overall transportation volumes on our TE Products Pipeline System increased a net 54 MBPD quarter-to-quarter.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019 .

Gross operating margin from refined products pipelines and related activities for the nine months ended September 30, 2020 increased $1.3 million when compared to the nine months ended September 30, 2019.

Gross operating margin from our refined products marketing activities increased a net $31.9 million period-to-period primarily due to higher sales volumes.

The period-to-period increase in gross operating margin from our refined products marketing activities is primarily due to results from marketing strategies that seek to optimize our storage assets.

Gross operating margin from our TE Products Pipeline System decreased $26.3 million period-to-period primarily due to lower interstate refined products transportation volumes, which accounted for a $17.3 million decrease, and lower average NGL transportation fees, which accounted for an additional $13.4 million decrease, partially offset by higher average petrochemical transportation fees, which accounted for an $11.8 million increase.

Overall transportation volumes on our TE Products Pipeline System increased a net 17 MBPD period-to-period.

Gross operating margin from our refined products terminal in Beaumont, Texas decreased a net $8.9 million period-to-period primarily due to lower storage revenues, which accounted for a $14.8 million decrease, partially offset by lower operating costs, which accounted for a $7.7 million increase.

Terminaling volumes at Beaumont decreased a net 82 MBPD period-to-period.

Gross operating margin from refined products pipelines and related activities during the first quarter of 2021 increased $27.2 million when compared to the first quarter of 2020.

Gross operating margin from our refined products marketing activities increased $28.2 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $34.9 million increase, partially offset by lower average sales margins (including the impact of hedging activities), which accounted for a $6.6 million decrease.

Ethylene exports and other services

Third Quarter of 2020 Compared to Third Quarter of 2019 .

Gross operating margin from ethylene exports and other services for the third quarter of 2020 increased a net $ 8.6 million when compared to the third quarter of 2019.

Gross operating margin from our ethylene export terminal, which was first placed into limited service in December 2019, and its related operations was a combined $ 13.9 million for the third quarter of 2020.

Loading volumes at our ethylene export terminal for the third quarter of 2020 were 15 MBPD (net to our interest).

Gross operating margin from ethylene exports and other services for the first quarter of 2021 decreased a net $3.2 million when compared to the first quarter of 2020.

Gross operating margin from marine transportation decreased $11.4 million quarter-to-quarter primarily due to lower fleet utilization rates.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019 .

Gross operating margin from ethylene exports and other services during the nine months ended September 30, 2020 increased $ 13.9 million when compared to the nine months ended September 30, 2019.

Gross operating margin from our ethylene export terminal and related operations was $ 16.2 million for the nine months ended September 30, 2020.

Loading volumes at our ethylene export terminal were 9 MBPD (net to our interest) during the nine months ended September 30, 2020.

Gross operating margin from our ethylene export terminal and its related operations increased $8.2 million quarter-to-quarter primarily due to higher loading volumes of 6 MBPD (net to our interest).

Liquidity and Capital Resources

Based on current market conditions (as of the filing date of this quarterly report), we believe that the Partnership and its consolidated businesses will have sufficient liquidity, cash flow from operations and access to capital markets to fund their capital investments and working capital needs for the reasonably foreseeable future.

We may issue equity and debt securities to assist us in meeting our future funding and liquidity requirements, including those related to capital investments.

We have a universal shelf registration statement (the “2019 Shelf”) on file with the SEC which allows the Partnership and EPO to issue an unlimited amount of equity and debt securities, respectively.

Enterprise Declares Cash Distribution for Third Quarter of 2020

On October 7 , 2020, we announced that the Board declared a quarterly cash distribution of $0.4450 per common unit, or $1.78 per unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the third quarter of 2020.

The quarterly distribution is payable on November 12 , 2020, to unitholders of record as of the close of business on October 30 , 2020.

At March 31, 2021, we had $5.11 billion of consolidated liquidity, which was comprised of $4.88 billion of available borrowing capacity under EPO’s revolving credit facilities and $229.4 million of unrestricted cash on hand.

We may issue debt and equity securities to assist us in meeting our future funding and liquidity requirements, including those related to capital investments.

We have a universal shelf registration statement on file with the SEC which allows the Partnership and EPO to issue an unlimited amount of equity and debt securities, respectively.

Enterprise Declares Cash Distribution for First Quarter of 2021

On April 8, 2021, we announced that the Board declared a quarterly cash distribution of $0.45 per common unit, or $1.80 per unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the first quarter of 2021.

The quarterly distribution is payable on May 12, 2021 to unitholders of record as of the close of business on April 30, 2021.

The total amount to be paid is $991.5 million, which includes $8.1 million for distribution equivalent rights on phantom unit awards.

The payment of quarterly cash distribution is subject to management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments and Board approval.

In light of current economic conditions, management will evaluate any future increases in cash distributions on a quarterly basis.

The payment of any quarterly cash distribution is subject to management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments and Board approval.

Consolidated Debt

At September 30, 2020, the average maturity of EPO’s consolidated debt obligations was approximately 20.6 years.

The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at September 30, 2020 for the years indicated (dollars in millions):

At March 31, 2021, the average maturity of EPO’s consolidated debt obligations was approximately 21 years.

The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at March 31, 2021 for the years indicated (dollars in millions):

Scheduled Maturities of Debt

Principal amount of senior and junior debt obligations

In January 2020, EPO issued $3.0 billion aggregate principal amount of senior notes comprised of (i) $1.0 billion principal amount of 2.80% fixed-rate senior notes due January 2030 (“Senior Notes AAA”), (ii) $1.0 billion principal amount of 3.70% fixed-rate senior notes due January 2051 (“Senior Notes BBB”) and (iii) $1.0 billion principal amount of 3.95% fixed-rate senior notes due January 2060 (“Senior Notes CCC”).

Net proceeds from this offering were used by EPO for the repayment of $500 million principal amount of its Senior Notes Q that matured in January 2020, temporary repayment of amounts outstanding under its commercial paper program and for general company purposes.

In addition, net proceeds from this offering were used by EPO for the repayment of $1.0 billion principal amount of its Senior Notes Y that matured in September 2020.

In August 2020, EPO issued $1.0 billion principal amount of 3.20% fixed-rate senior notes due February 2052 (“Senior Notes DDD”) and $250.0 million principal amount of reopened 2.80% fixed-rate Senior Notes AAA.

We received aggregate net proceeds of $1.25 billion from the sale of the notes after deducting underwriting discounts and other estimated offering expenses payable by us.

Net proceeds from the issuance of these senior notes will be used for general company purposes, including for growth capital investments, and to repay all or part of $750.0 million in principal amount of Senior Notes TT, which mature in February 2021.

In September 2020, EPO entered into a new 364-Day Revolving Credit Agreement that replaced its September 2019 364-Day Revolving Credit Agreement.

The new 364-Day Revolving Credit Agreement matures in September 2021.

There was no principal amount outstanding under the September 2019 364-Day Revolving Credit Agreement when it expired and was replaced by the September 2020 364-Day Revolving Credit Agreement.

In addition, following execution of the September 2020 364-Day Revolving Credit Agreement, EPO terminated its April 2020 364-Day Revolving Credit Agreement on September 11, 2020.

Commercial Paper Notes

Junior Subordinated Notes

In February 2021, EPO repaid all of the $750.0 million in principal amount of its Senior Notes TT using remaining cash on hand attributable to its August 2020 senior notes offering and proceeds from the issuance of short-term notes under its commercial paper program.

In March 2021, EPO redeemed all of the $575.0 million outstanding principal amount of its Senior Notes RR one month prior to their scheduled maturity in April 2021.

These notes were redeemed at par (i.e., at a redemption price equal to the outstanding principal amount of such notes to be redeemed, plus accrued and unpaid interest thereon) using proceeds from the issuance of short-term notes under its commercial paper program.

For additional information regarding our consolidated debt obligations, see Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Credit Ratings

As of November 6 , 2020, the investment-grade credit ratings of EPO’s long-term senior unsecured debt securities were BBB+ from Standard and Poor’s, Baa1 from Moody’s and BBB+ from Fitch Ratings.

As of May 7, 2021, the investment-grade credit ratings of EPO’s long-term senior unsecured debt securities were BBB+ from Standard and Poor’s, Baa1 from Moody’s and BBB+ from Fitch Ratings.

In addition, the credit ratings of EPO’s short-term senior unsecured debt securities were A-2 from Standard and Poor’s, P-2 from Moody’s and F-2 from Fitch Ratings.

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In January 2019, we announced that the Board had approved a $2.0 billion multi-year unit buyback program (the “2019 Buyback Program”), which provides the Partnership with an additional method to return capital to investors.

The Partnership repurchased an aggregate 8,342,246 common units under the 2019 Buyback Program through open market and private purchases during the nine months ended September 30, 2020.

The total purchase price of these repurchases was $173.8 million including commissions and fees .

Units repurchased under the 2019 Buyback Program are immediately cancelled upon acquisition.

As of September 30, 2020 , the remaining available capacity under the 2019 Buyback Program was $ 1.75 billion.

In addition to the 2019 Buyback Program, privately held affiliates of EPCO acquired 1,459,000 of the Partnership’s common units on the open market during the nine months ended September 30, 2020.

In the aggregate, 9,801,246 common units were purchased on the open market during the nine months ended September 30, 2020 under the 2019 Buyback Program and by privately held affiliates of EPCO.

March 2020 Issuance of Common Units to Skyline North Americas, Inc.

and related acquisition of Treasury Units

On March 5, 2020, the Partnership settled its obligations under the Liquidity Option Agreement by issuing 54,807,352 new common units to Skyline North Americas, Inc.

in exchange for the capital stock of OTA.

Upon settlement of the Liquidity Option, we indirectly acquired the 54,807,352 Partnership common units owned by OTA (which were issued by the Partnership to OTA in October 2014) and assumed all future income tax obligations of OTA, including its deferred tax liability.

For additional information regarding settlement of the Liquidity Option, see Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

September 2020 Issuance of Series A Cumulative Convertible Preferred Units

On September 30, 2020, the Partnership issued and sold an aggregate of 50,000 Series A Cumulative Convertible Preferred Units in a private placement transaction.

The stated value of each preferred unit is $1,000 per unit.

The total offering price for the preferred units was $50.0 million, of which $32.5 million was received in cash with the remaining $17.5 million funded through the exchange of 1,120,588 of the Partnership’s common units owned by the purchasers.

Cash proceeds from the preferred unit offering include $15.0 million received from a privately held affiliate of EPCO for the purchase of 15,000 preferred units.

Concurrently, the Partnership exchanged all of the 54,807,352 Partnership common units owned directly by OTA for 855,915 of the Partnership’s new preferred units having an equivalent value.

The preferred units held by OTA, like the common units OTA held prior to the exchange, are accounted for as treasury units by the Partnership in consolidation.

The historical cost of the treasury units did not change as a result of the exchange and remains at the $1.3 billion recognized in March 2020 in connection with settlement of the Liquidity Option.

For additional information regarding the preferred units, see Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

During the first quarter of 2021, the Partnership settled open market repurchase transactions initiated in December 2020 involving an aggregate 709,816 common units.

The total cost of these repurchases was $13.9 million including commissions and fees.

As of March 31, 2021, the remaining available capacity under the 2019 Buyback Program was $1.72 billion.

Cash Flow Statement Highlights

The following table summarizes our consolidated cash flows from operating, investing and financing activities for the periods indicated (dollars in millions).

For additional information regarding our cash flow amounts, please refer to the Unaudited Condensed Statements of Consolidated Cash Flows included under Part I, Item 1 of this quarterly report.

For the Nine Months

Ended September 30,

For the Three Months

Ended March 31,

Net cash flows provided by operating activities

Cash used in investing activities

Cash used in financing activities

Cash provided by (used in) financing activities

Net cash flows provided by operating activities are largely dependent on earnings from our consolidated business activities.

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We may also incur credit and price risk to the extent customers do not fulfill their contractual obligations to us in connection with our marketing activities and long-term take-or-pay agreements.

For a more complete discussion of these and other risk factors pertinent to our business, see Part I, Item 1A of the 2019 Form 10-K and Part II, Item 1A of this quarterly report.

The following information highlights significant period-to-period fluctuations in our consolidated cash flow amounts:

For a more complete discussion of these and other risk factors, see “ Risk Factors ” included under Part I, Item 1A of the 2020 Form 10-K.

For additional information regarding our cash flow amounts, please refer to our Unaudited Condensed Statements of Consolidated Cash Flows included under Part I, Item 1 of this quarterly report.

The following information highlights significant quarter-to-quarter fluctuations in our consolidated cash flow amounts:

Operating activities

Net cash flows provided by operating activities for the nine months ended September 30, 2020 decreased $ 534.6 million when compared to the nine months ended September 30, 2019 primarily due to:

a $ 283.0 million period-to-period decrease primarily due to higher levels of working capital employed in our marketing activities, which accounted for a $1.3 billion decrease, partially offset by the timing of cash receipts and payments related to operations;

a $ 157.8 m illion period-to-period decrease resulting from lower partnership earnings in the nine months ended September 30, 2020 when compared to the nine months ended September 30, 2019 (determined by adjusting our $ 41.9 million period-to-period decrease in net income for changes in the non-cash items identified on our Unaudited Condensed Statements of Consolidated Cash Flows);

a $ 93.8 million period-to-period decrease in cash distributions attributable to earnings from unconsolidated affiliates, with those unconsolidated affiliates owning crude oil pipelines and terminals accounting for substantially all of the decrease.

For information regarding significant period-to-period changes in our consolidated net income and underlying segment results, see “ Income Statement Highlights ” and “ Business Segment Highlights ” within this Part I, Item 2.

Net cash flows provided by operating activities for the first quarter of 2021 increased a net $10.9 million when compared to the first quarter of 2020 primarily due to:

a $362.7 million quarter-to-quarter increase in cash related to the timing of cash receipts and payments related to operations;

a $268.6 million quarter-to-quarter increase resulting from higher partnership earnings (determined by adjusting our $12.4 million quarter-to-quarter decrease in net income for changes in the non-cash items identified on our Unaudited Condensed Statements of Consolidated Cash Flows);

partially offset by

a $605.4 million quarter-to-quarter decrease in cash receipts attributable to the return of working capital employed in our marketing activities, which was $638.4 million in the first quarter of 2020 compared to $33.0 million in the first quarter of 2021.

For information regarding significant quarter-to-quarter changes in our consolidated net income and underlying segment results, see “ Income Statement Highlights ” and “ Business Segment Highlights ” within this Part I, Item 2.

Investing activities

Cash used in investing activities for the nine months ended September 30, 2020 decreased $ 808.6 m illion when compared to the nine months ended September 30, 2019 primarily due to:

a $ 630.5 million period-to-period decrease in investments for property, plant and equipment (see “ Capital Investments ” within this Part I, Item 2 for additional information);

a $ 90.2 million period-to-period decrease in investments in unconsolidated affiliates primarily due to lower cash outlays for NGL and crude oil pipeline projects;

a $ 71.0 million period-to-period increase in cash distributions attributable to the return of capital from unconsolidated affiliates, with those unconsolidated affiliates owning crude oil pipelines and terminals accounting for substantially all of the increase.

Cash used in investing activities during the first quarter of 2021 decreased $414.7 million when compared to the first quarter of 2020 primarily due to a $400.5 million quarter-to-quarter decrease in investments for property, plant and equipment (see “ Capital Investments ” within this Part I, Item 2 for additional information).

Financing activities

Cash used in financing activities for the nine months ended September 30, 2020 increased a net $ 350.6 million when compared to the nine months ended September 30, 2019 primarily due to:

a $ 569.6 million period-to-period decrease in cash contributions from noncontrolling interests.

In July 2019, an affiliate of Apache Corporation acquired a noncontrolling 33% equity interest in our consolidated subsidiary that owns the Shin Oak NGL Pipeline for $440.7 million.

In addition, cash contributions from noncontrolling interests in connection with our Pascagoula natural gas processing plant and ethylene export facility decreased a combined $95.0 million period-to-period;

a $ 92.7 million period-to-period increase in cash used to acquire common units under our 2019 Buyback Program;

an $ 82.2 million period-to-period decrease in net cash proceeds from the issuance of common units under our distribution reinvestment plan (“DRIP”) and employee unit purchase plan (“EUPP”).

In July 2019, the Partnership announced that, beginning with the quarterly distribution payment paid in August 2019, it would use common units purchased on the open market, rather than issuing new common units, to satisfy its delivery obligations under the DRIP and EUPP;

a $ 48.5 million period-to-period increase in cash distributions paid to common unitholders attributable to increases in the quarterly cash distribution rate per unit;

partially offset by

a net $437.9 million period-to-period increase in net cash inflows from debt.

For the nine months ended September 30, 2020, we issued $4.25 billion aggregate principal amount of senior notes, partially offset by the repayment of $1.5 billion principal amount of senior notes.

For the nine months ended September 30, 2019, we issued $2.5 billion aggregate principal amount of senior notes, partially offset by the repayment or repurchase of $724.2 million principal amount of senior and junior subordinated notes.

In addition, net repayments of short term notes under EPO’s commercial paper program were $ 481.7 million during the nine months ended September 30, 2020 ;

a $ 32.5 million increase in cash proceeds from the issuance of preferred units on September 30, 2020.

Cash used in financing activities during the first quarter of 2021 was $2.19 billion compared to cash provided by financing activities of $765.1 million in the first quarter of 2020.

The $2.95 billion quarter-to-quarter change in financing cash flows was primarily due to a net cash outflow of $1.13 billion related to debt during the first quarter of 2021 compared to a net cash inflow of $1.94 billion related to debt during the first quarter of 2020.

During the first quarter of 2021, we repaid $1.33 billion aggregate principal amount of senior notes.

During the first quarter of 2020, we issued $3.0 billion aggregate principal amount of senior notes, partially offset by the repayment of $500 million principal amount of senior notes.

In addition, net issuances of short term notes under EPO’s commercial paper program were $115.0 million during the first quarter of 2021 compared to net repayments of $481.8 million during the first quarter of 2020.

In addition, cash used to acquire Partnership common units under the 2019 Buyback Program decreased $126.2 million quarter-to-quarter.

Non-GAAP Cash Flow Measures

Distributable Cash Flow

Our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash, after any cash reserves established by Enterprise GP in its sole discretion.

Our partnership agreement requires us to make quarterly distributions to our common unitholders of all available cash, after any cash reserves established by Enterprise GP in its sole discretion.

Cash reserves include those for the proper conduct of our business, including those for capital investments, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other amounts.

The retention of cash by the partnership allows us to reinvest in our growth and reduce our future reliance on the equity and debt capital markets.

The retention of cash allows us to reinvest in our growth and reduce our future reliance on the equity and debt capital markets.

We measure available cash by reference to distributable cash flow (“DCF”), which is a non-GAAP cash flow measure.

DCF is an important financial measure for our common unitholders since it serves as an indicator of our success in providing a cash return on investment.

DCF is an important financial measure for our limited partners since it serves as an indicator of our success in providing a cash return on investment.

Specifically, this financial measure indicates to investors whether or not we are generating cash flows at a level that can sustain our declared quarterly cash distributions.

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Our calculation of DCF may or may not be comparable to similarly titled measures used by other companies.

Based on the level of available cash each quarter, management proposes a quarterly cash distribution rate to the Board of Enterprise GP, which has sole authority in approving such matters.

Unlike several other master limited partnerships, our general partner has a non-economic ownership interest in us and is not entitled to receive any cash distributions from us based on incentive distribution rights or other equity interests.

Our use of DCF for the limited purposes described above and in this report is not a substitute for net cash flows provided by operating activities, which is the most comparable GAAP measure.

Based on the level of available cash each quarter, management proposes a quarterly cash distribution rate to the Board, which has sole authority in approving such matters.

Enterprise GP has a non-economic ownership interest in the Partnership and is not entitled to receive any cash distributions from it based on incentive distribution rights or other equity interests.

Our use of DCF for the limited purposes described above and in this quarterly report is not a substitute for net cash flows provided by operating activities, which is the most comparable GAAP measure to DCF.

For a discussion of net cash flows provided by operating activities, see “ Cash Flow Statement Highlights ” within this Part I, Item 2.

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For the Three Months

Ended September 30,

For the Nine Months

Ended September 30,

Ended March 31,

Net income attributable to common unitholders (GAAP) (1)

Adjustments to net income attributable to common unitholders to

derive DCF (addition or subtraction indicated by sign):

Adjustments to net income attributable to common unitholders to derive DCF (addition or subtraction indicated by sign):

Depreciation, amortization and accretion expenses

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Equity in income of unconsolidated affiliates

Asset impairment and related charges

Asset impairment charges

Change in fair market value of derivative instruments

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Sustaining capital expenditures (3)

Other, net (4)

Operational DCF (5)

Proceeds from asset sales

Monetization of interest rate derivative instruments accounted

for as cash flow hedges

Monetization of interest rate derivative instruments accounted for as cash flow hedges

DCF (non-GAAP)

Cash distributions paid to common unitholders with respect to period

Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards

Cash distribution per common unit declared by Enterprise GP with respect to period (6)

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For a discussion of the primary drivers of changes in our comparative income statement amounts, see “ Income Statement Highlights ” within this Part I, Item 2.

Reflects distributions received from unconsolidated affiliates attributable to earnings and the return of capital.

Reflects aggregate distributions received from unconsolidated affiliates attributable to both earnings and the return of capital.

Sustaining capital expenditures include cash payments and accruals applicable to the period.

First quarter of 2021 includes $107.0 million of accounts receivable that we do not expect to collect in the normal billing cycle.

Represents DCF before proceeds from asset sales and the monetization of interest rate derivative instruments accounted for as cash flow hedges.

See Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for additional information regarding our quarterly cash distributions declared with respect to the years indicated.

At the sole discretion of Enterprise GP, cash retained by the partnership with respect to each of these periods was primarily reinvested in growth capital projects.

This retainage of cash substantially reduced our reliance on the equity capital markets to fund such expenditures.

See Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for information regarding our cash distributions declared with respect to the periods indicated.

Cash retained by the Partnership may be used for capital investments, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other amounts.

The retention of cash reduces our reliance on the capital markets.

Distribution coverage ratio is determined by dividing DCF by total cash distributions paid to common unitholders and in connection with distribution equivalent rights with respect to the period.

1 unchanged sentence

For the Three Months

Ended September 30,

For the Nine Months

Ended September 30,

Ended March 31,

Net cash flows provided by operating activities (GAAP)

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Sustaining capital expenditures

Distributions received from unconsolidated affiliates attributable

to the return of capital

Distributions received from unconsolidated affiliates attributable to the return of capital

Proceeds from asset sales

Net income attributable to noncontrolling interest

Monetization of interest rate derivative instruments accounted

for as cash flow hedges

Net income attributable to noncontrolling interests

Monetization of interest rate derivative instruments accounted for as cash flow hedges

DCF (non-GAAP)

Free Cash Flow

Free Cash Flow (“FCF”), a non-GAAP financial measure, is a traditional cash flow metric that is widely used by a variety of investors and other participants in the financial community, as opposed to DCF, which is a cash flow measure primarily used by investors and others in evaluating midstream energy companies, including master limited partnerships.

In general, FCF is a measure of how much cash flow a business generates during a specified time period after accounting for all capital investments, including expenditures for growth and sustaining capital projects.

Free Cash Flow (“FCF”), a non-GAAP cash flow measure that is widely used by investors and other participants in the financial community, reflects how much cash flow a business generates during a period after accounting for all capital investments, including those for growth and sustaining capital projects.

By comparison, only sustaining capital expenditures are reflected in DCF.

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Our calculation of FCF may or may not be comparable to similarly titled measures used by other companies.

Our use of FCF for the limited purposes described above and in this report is not a substitute for net cash flows provided by operating activities, which is the most comparable GAAP measure.

FCF fluctuates based on our earnings, the level of investing activities we undertake each period, and the timing of operating cash receipts and payments.

In addition to providing the quarterly amounts presented below, we also provide a calculation of aggregate FCF over the twelve months ended September 30, 2020 in order to measure FCF over a longer term.

Our use of FCF for the limited purposes described above and in this report is not a substitute for net cash flows provided by operating activities, which is the most comparable GAAP measure to FCF.

FCF fluctuates quarter-to-quarter based on a number of factors including earnings, the level of investing activities, the timing of operating cash receipts and payments, and contributions from noncontrolling interests.

The following table summarizes our calculation of FCF for the periods indicated (dollars in millions):

For the Three Months

Ended September 30,

For the Nine Months

Ended September 30,

For the Twelve Months Ended

September 30,

Ended March 31,

Net cash flows provided by operating activities (GAAP)

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FCF (non-GAAP)

For a discussion of primary drivers of our quarterly net cash flows provided by operating activities and cash used in investing activities, see “ Cash Flow Statement Highlights ” within this Part I, Item 2.

The elements used in calculating FCF are sourced directly from our Unaudited Condensed Statements of Consolidated Cash Flows presented under Part I, Item 1 of this quarterly report.

For a discussion of significant quarter-to-quarter changes in our cash flow statement amounts, see “ Cash Flow Statement Highlights ” within this Part I, Item 2.

Capital Investments

Capital investing activity throughout the domestic energy industry has been reduced significantly in response to the supply and demand disruptions caused by the COVID-19 pandemic and the related oil price shock.

In light of these adverse macroeconomic conditions, we have reevaluated our planned capital investments in order to maximize available liquidity.

Based on information currently available, we expect our total capital investments for 2020, net of contributions from joint venture partners, to approximate $3.2 billion, which reflects growth capital investments of $2.9 billion and approximately $300 million for sustaining capital expenditures.

In addition, we currently expect our growth capital investments in 2021 and 2022 for sanctioned projects to approximate $1.6 billion and $800 million, respectively.

These amounts do not include capital investments associated with SPOT, our proposed deepwater offshore crude oil terminal, which remains subject to governmental approvals.

Our forecast of capital investments for 2020 through 2022 is based on announced strategic operating and growth plans (through the filing date of this quarterly report), which are dependent upon our ability to generate the required funds from either operating cash flows or other means, including borrowings under debt agreements, the issuance of additional equity and debt securities, and potential divestitures.

We may revise our forecast of capital investments due to factors beyond our control, such as adverse economic conditions, weather-related issues and changes in supplier prices.

Furthermore, our forecast of capital investments may change due to decisions made by management at a later date, which may include unforeseen acquisition opportunities.

Our success in raising capital, including partnering with other companies to share project costs and risks, continues to be a significant factor in determining how much capital we can invest.

We believe our access to capital resources is sufficient to meet the demands of our current and future growth needs and, although we expect to make the forecast capital investments noted above, we may adjust the timing and amounts of projected expenditures in response to changes in capital market conditions.

We placed Frac X and Frac XI into service in March 2020 and September 2020, respectively.

In addition, expansion projects on our Texas Express Pipeline and Front Range Pipeline were placed into commercial service in April 2020.

We also placed the Midland-to-ECHO segment of the Midland-to-Webster pipeline into service in October 2020.

We currently have $3.9 billion of growth capital projects scheduled to be completed by the end of 2023, which includes completion of our PDH 2 facility in the second quarter of 2023.

The following table summarizes our capital investments for the periods indicated (dollars in millions):

For the Nine Months

Ended September 30,

For the Three Months

Ended March 31,

Capital investments for property, plant and equipment:

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Investments in unconsolidated affiliates

Growth and sustaining capital amounts presented in the table above are presented on a cash basis.

Growth and sustaining capital amounts are presented on a cash basis.

In total, these amounts represent “Capital expenditures” as presented on our Unaudited Condensed Statements of Consolidated Cash Flows.

Growth capital projects either (a) result in new sources of cash flow due to enhancements of or additions to existing assets (e.g., additional revenue streams, cost savings resulting from debottlenecking of a facility, etc.) or (b) expand our asset base through construction of new facilities that will generate additional revenue streams and cash flows.

Sustaining capital expenditures are capital expenditures (as defined by GAAP) resulting from improvements to existing assets.

Sustaining capital projects are capital expenditures (as defined by GAAP) resulting from improvements to existing assets.

Such expenditures serve to maintain existing operations but do not generate additional revenues or result in significant cost savings.

Comparison of Nine Months Ended September 30, 2020 with Nine Months Ended September 30, 2019

In total, investments in growth capital projects decreased $632.2 million period-to-period primarily due to the following:

completion of projects at our Mont Belvieu complex, which accounted for a $510.6 million decrease and included placing into service our iBDH facility (December 2019), Frac X (March 2020) and Frac XI (September 2020);

completion of the Shin Oak NGL Pipeline (in stages through the fourth quarter of 2019), which accounted for a $316.4 million decrease;

lower investments in natural gas processing facilities and related infrastructure that support Permian Basin production, which accounted for a $274.5 million decrease.

We completed the final phase of our Orla plant in July 2019 and placed our Mentone plant into service in December 2019;

Sustaining capital amounts include the costs of major maintenance activities accounted for using the deferral method.

We currently have $3.6 billion of growth capital projects scheduled to be completed by the end of 2023, which includes completion of a natural gasoline hydrotreater facility at our Chambers County complex in the fourth quarter of 2021, the Gillis Lateral natural gas pipeline and related infrastructure in the fourth quarter of 2021, and our PDH 2 facility in the second quarter of 2023.

Based on information currently available, we expect our total capital investments for 2021, net of expected contributions from noncontrolling interests, to approximate $2.1 billion, which reflects growth capital investments of $1.6 billion and sustaining capital expenditures of $440 million.

In addition, we currently expect our growth capital investments in 2022 and 2023 for sanctioned projects to approximate $800 million and $400 million, respectively.

These amounts do not include capital investments associated with SPOT, our proposed deepwater offshore crude oil terminal, which remains subject to governmental approvals.

We currently anticipate receiving approval for SPOT as early as the second half of 2021;

however, we can give no assurance as to whether the project will ultimately be approved or the timing of such decision.

Our forecast of capital investments for 2021 through 2023 is based on announced strategic operating and growth plans (through the filing date of this quarterly report), which are dependent upon our ability to generate the required funds from either operating cash flows or other means, including borrowings under debt agreements, the issuance of additional equity and debt securities, and potential divestitures.

We may revise our forecast of capital investments due to factors beyond our control, such as adverse economic conditions, weather-related issues and changes in supplier prices.

Furthermore, our forecast of capital investments may change due to decisions made by management at a later date, which may include unforeseen acquisition opportunities.

Our success in raising capital, including partnering with other companies to share project costs and risks, continues to be a significant factor in determining how much capital we can invest.

Comparison of First Quarter of 2021 with the First Quarter of 2020

In total, investments in growth capital projects decreased $433.0 million quarter-to-quarter primarily due to the following:

completion of projects at our Chambers County complex (e.g., the completion of Frac X and Frac XI), which accounted for a $193.4 million decrease;

completion of projects associated with crude oil pipelines (e.g., expansion projects involving the Midland-to-ECHO System and related crude oil-related infrastructure supporting Permian Basin producers), which accounted for a combined $121.4 million decrease;

lower investments in Permian Basin natural gas processing facilities and related infrastructure, which accounted for a $52.4 million decrease;

lower investments in projects attributable to our ethylene business, which accounted for a $26.7 million decrease;

partially offset by,

higher investments in our PDH 2 facility, which accounted for a $293.7 million increase;

higher investments in crude oil pipelines, including those expanding our Midland-to-ECHO System, and related infrastructure that support Permian Basin production, which accounted for a combined $98.8 million increase;

higher investments in natural gas pipelines and related infrastructure in support of East Texas and Louisiana production, which accounted for a $50.9 million increase.

Investments in unconsolidated affiliates decreased $90.2 million period-to-period primarily due to lower spending on joint venture dock infrastructure at Corpus Christi and other crude oil-related projects, which accounted for a $46.4 million decrease, and NGL pipeline expansion projects, which accounted for an additional $38.1 million decrease.

Fluctuations in investments for sustaining capital projects are primarily due to the timing and cost of pipeline integrity and similar projects.

lower investments in natural gas pipelines and related infrastructure in support of East Texas and Louisiana producers, which accounted for a net $25.1 million decrease.

Investments attributable to sustaining capital projects increased $32.5 million quarter-to-quarter primarily due to major maintenance activities performed during the first quarter of 2021 at our PDH 1, octane enhancement and high purity isobutylene facilities.

The remaining change is primarily due to changes in the timing and cost of pipeline integrity and similar projects.

Critical Accounting Policies and Estimates

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depreciation methods and estimated useful lives of property, plant and equipment;

measuring recoverability of long-lived assets and equity method investments;

amortization methods and estimated useful lives of qualifying intangible assets;

methods we employ to measure the fair value of goodwill;

revenue recognition policies and the use of estimates for revenue and expenses.

measuring recoverability of long-lived assets and fair value of equity method investments;

valuation and amortization methods of customer relationships and contract-based intangible assets;

methods we employ to measure the fair value of goodwill and related assets;

the use of estimates for revenue and expenses.

When used to prepare our Unaudited Condensed Consolidated Financial Statements, the foregoing types of estimates are based on our current knowledge and understanding of the underlying facts and circumstances.

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Subsequent changes in these estimates may have a significant impact on our consolidated financial position, results of operations and cash flows.

Parent-Subsidiary Guarantor Relationship

The Partnership (the “Parent Guarantor”) has guaranteed the payment of principal and interest on the consolidated debt obligations of EPO (the “Subsidiary Issuer”), with the exception of the remaining debt obligations of TEPPCO Partners, L.P.

(collectively, the “Guaranteed Debt”).

If EPO were to default on any of its Guaranteed Debt, the Partnership would be responsible for full and unconditional repayment of such obligations.

At March 31, 2021, the total amount of Guaranteed Debt was $29.15 billion, which was comprised of $26.18 billion of EPO’s senior notes, $115.0 million of short-term commercial paper notes, $2.63 billion of EPO’s junior subordinated notes and $224.2 million of related accrued interest.

The Partnership’s guarantees of EPO’s senior note obligations, commercial paper notes and borrowings under bank credit facilities represent unsecured and unsubordinated obligations of the Partnership that rank equal in right of payment to all other existing or future unsecured and unsubordinated indebtedness of the Partnership.

In addition, these guarantees effectively rank junior in right of payment to any existing or future indebtedness of the Partnership that is secured and unsubordinated, to the extent of the assets securing such indebtedness.

The Partnership’s guarantees of EPO’s junior subordinated notes represent unsecured and subordinated obligations of the Partnership that rank equal in right of payment to all other existing or future subordinated indebtedness of the Partnership and senior in right of payment to all existing or future equity securities of the Partnership.

The Partnership’s guarantees of EPO’s junior subordinated notes effectively rank junior in right of payment to (i) any existing or future indebtedness of the Partnership that is secured, to the extent of the assets securing such indebtedness and (ii) all other existing or future unsecured and unsubordinated indebtedness of the Partnership.

The Partnership may be released from its guarantee obligations only in connection with EPO’s exercise of its legal or covenant defeasance options as described in the underlying agreements.

Selected Financial Information of Obligor Group

The following tables present summarized financial information of the Partnership (as Parent Guarantor) and EPO (as Subsidiary Issuer) on a combined basis (collectively, the “Obligor Group”), after the elimination of intercompany balances and transactions among the Obligor Group.

In accordance with Rule 13.01 of Regulation S-X, the summarized financial information of the Obligor Group excludes the Obligor Group’s equity in income and investments in the consolidated subsidiaries of EPO that are not party to the guarantee obligations (the “Non-Obligor Subsidiaries”).

The total carrying value of the Obligor Group’s investments in the Non-Obligor Subsidiaries was $45.86 billion at March 31, 2021.

The Obligor Group’s equity in the earnings of the Non-Obligor Subsidiaries for the first quarter of 2021 was $878.0 million.

Although the net assets and earnings of the Non-Obligor Subsidiaries are not directly available to the holders of the Guaranteed Debt to satisfy the repayment of such obligations, there are no significant restrictions on the ability of the Non-Obligor Subsidiaries to pay distributions or make loans to EPO or the Partnership.

EPO exercises control over the Non-Obligor Subsidiaries.

We continue to believe that the unaudited condensed consolidated financial statements of the Partnership presented under Part I, Item 1 of this quarterly report provide a more appropriate view of our credit standing.

Our investment grade credit ratings are based on the Partnership’s consolidated financial statements and not the Obligor Group financial information presented below.

The following table presents summarized balance sheet information for the combined Obligor Group at the dates indicated (dollars in millions):

Selected asset information:

March 31, 2021

December 31, 2020

Current receivables from Non-Obligor Subsidiaries

Other current assets

Long-term receivables from Non-Obligor Subsidiaries

Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries of $45.86 billion at March 31, 2021 and $45.98 billion at December 31, 2020

Selected liability information:

Current portion of Guaranteed Debt, including interest of $224.2 million at March 31, 2021 and $455.6 million at December 31, 2020

Current payables to Non-Obligor Subsidiaries

Other current liabilities

Noncurrent portion of Guaranteed Debt, principal only

Noncurrent payables to Non-Obligor Subsidiaries

Other noncurrent liabilities

Mezzanine equity of Obligor Group:

Preferred units

The following table presents summarized income statement information for the combined Obligor Group for the periods indicated (dollars in millions):

For the three months ended

March 31, 2021

For the twelve months ended

December 31, 2020

Revenues from Non-Obligor Subsidiaries

Revenues from other sources

Operating income of Obligor Group

Net income (loss) of Obligor Group excluding equity in earnings of Non-Obligor Subsidiaries of $878.0 million for the three months ended March 31, 2021 and $3.54 billion for the twelve months ended December 31, 2020

Contractual Obligations

We have contractual future product purchase commitments for natural gas, NGLs, crude oil, petrochemicals and refined products.

These commitments represent enforceable and legally binding agreements as of the reporting date.

Our product purchase commitments at September 30, 2020 declined by an estimated $6.3 billion when compared to those reported in our 2019 Form 10-K primarily due to lower NGL and crude oil prices since December 31, 2019.

The principal amount of our consolidated debt obligations were $30.1 billion at September 30, 2020 compared to $27.88 billion at December 31, 2019.

See “ Liquidity and Capital Resources – Consolidated Debt ” within this Part I, Item 2 for information regarding EPO’s senior notes offerings during 2020.

We have contractual future product purchase commitments for natural gas, NGLs, crude oil, petrochemicals and refined products representing enforceable and legally binding agreements as of the reporting date.

Our product purchase commitments increased from $14.80 billion at December 31, 2020 to $19.34 billion at March 31, 2021 primarily due to an increase in crude oil and NGL prices between the two reporting dates.

Off-Balance Sheet Arrangements

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What changed 10-Q

Item 2. Management’s Discussion and Analysis