What changed in this filing

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Item 2. Management’s Discussion and Analysis

2020-11-06 compared with 2020-08-10 · 425 added, 445 removed, 434 unchanged (67% of the section changed)

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RESULTS OF OPERATIONS.

For the Three and Six Months Ended June 30, 2020 and 2019

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.

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

EPCO, together with its privately held affiliates, owned approximately 32.1% of EPD’s limited partner common units at June 30, 2020.

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.

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

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trillion British thermal units

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

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

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

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Overview of Business

We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products.

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.

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.

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and 14 Bcf of natural gas storage capacity.

We conduct substantially all of our business through EPO and are owned 100% by EPD’s limited partners from an economic perspective.

Enterprise GP manages our partnership and owns a non-economic general partner interest in us.

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.

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

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

The main purpose of our marketing activities is to support the utilization and expansion of assets across our midstream energy asset network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment.

In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of gross operating margin, a non-generally accepted accounting principle (“non-GAAP”) financial measure, for the partnership.

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

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

Update on 2020 Outlook

As noted previously, this quarterly report on Form 10-Q, including this update to our 2020 Outlook, 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.

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 .

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 2020 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.

The third-party supply and demand forecasts cited in the following analysis, including our internal forecasts based on such information, remain subject to heightened levels of uncertainty because mitigation and reopening efforts related to COVID-19 continue to evolve.

The emergence of COVID-19 as a global pandemic in the first quarter of 2020 and the consequences of international COVID-19 containment measures (and the resulting near-term decline in end-user demand for hydrocarbons) have adversely impacted the global economy in general and the energy industry in particular.

In addition, disputes between members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (collectively, the “OPEC+” group) in March and April 2020 over crude oil production levels, resulted in major disruptions to global energy markets.

Although the OPEC+ group and other producers subsequently reached agreements to reduce the oversupply of crude oil in the near-term caused by demand destruction attributable to COVID-19, the downturn in the energy industry has negatively impacted us, the producers we work with and our other customers to varying degrees.

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

The COVID-19 public health emergency resulted in record, near-term decreases in hydrocarbon demand due to lockdowns, travel restrictions, quarantines, temporary business closures and other measures instituted as early as February 2020 as the virus spread across several continents.

By May 2020, several major economies across the world began to work towards reopening their economies by targeting a balance between containing and eradicating the virus and supporting their economies, versus the initial more complete shut-downs.

The U.S., China, India, much of Europe and parts of Latin America have begun to ease their COVID-19 containment measures and central banks and governments have instituted significant measures in an effort to stimulate economic activity.

As a result, energy demand began to recover, with notable improvements in China, India, Europe and to some extent in the U.S.

A continuation of this trend remains dependent on successful containment of the disease and its elimination as a widespread threat to public health.

It is encouraging to note that, according to information published by the New York Times on July 22, 2020, researchers around the world are developing more than 160 vaccines against the virus, and 27 vaccines are in human trials.

Although vaccines typically require years of research and testing before being made available to the public, scientists are racing to produce a safe and effective vaccine.

While we are encouraged by efforts to reopen the global economy, the pace and the scope of the reopening is uncertain at this time and may extend well into 2021.

In its July 2020 Oil Market Report published on July 10, 2020 (the “July 2020 OMR”), the International Energy Agency (“IEA”) estimated that global crude oil demand for calendar year 2020 would fall by 7.9 MMBPD before recovering by 5.3 MMBPD in 2021.

Overall, the July 2020 OMR forecasts that crude oil demand will approximate 92.1 MMBPD in 2020 and 97.4 MMBPD in 2021.

In addition, the IEA forecasts crude oil demand will approximate 94.5 MMBPD and 97.0 MMBPD in the third and fourth quarters of 2020, respectively.

The destruction in hydrocarbon demand attributable to COVID-19 resulted in a severe drop in crude oil prices.

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 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 production cuts, closed at a record low of a negative $37.63 per barrel on April 20, 2020.

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

According to the July 2020 OMR, futures markets are anticipating a transformation in the oil market from substantial daily surplus in the first half of 2020 to a daily deficit in the second half of 2020.

Downstream demand for hydrocarbon products such as gasoline and jet fuel is expected to remain depressed until the COVID-19 containment measures are substantially lifted and the economy sufficiently improves.

Refiners have reduced their utilization rates in response to lower domestic and international demand.

According to the July 2020 OMR, global refining throughput for 2020 is forecast to fall 6.4 MMBPD to 75.1 MMBPD in 2020 due to reduced demand for transportation fuels and increase by 4.7 MMBPD in 2021.

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 agreements within the OPEC+ group in the second quarter of 2020, 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 decline in hydrocarbon demand attributable to COVID-19.

The OPEC+ group agreed to reduce their combined 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.

Global supply and demand fundamentals are being continually evaluated by the OPEC+ Joint Ministerial Monitoring Committee and the existing OPEC+ agreement is scheduled to be reevaluated in December 2021.

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

According to the July 2020 OMR, the record output cuts from OPEC+ and steep declines from other non-OPEC producers resulted in global oil production for June 2020 falling by 13.7 MMBPD when compared to April 2020.

Overall, the IEA states that global oil supply fell to a nine-year low of 86.9 MMBPD in June 2020.

According to the July 2020 OMR, global oil supply is forecast to decline by 7.1 MMBPD on average in 2020 (assuming the OPEC+ production cuts stay in place), and increase by 1.7 MMBPD in 2021.

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.

According to a report published by the Federal Reserve Bank of Dallas, average breakeven prices in the Permian Basin range from $48 per barrel to $54 per barrel, with breakeven costs in the Eagle Ford Shale averaging $51 per barrel.

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

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.

Energy Information Administration (“EIA”) in its July 2020 Short-Term Energy Outlook (“July 2020 STEO” dated July 7, 2020) expects U.S.

crude oil production to average 11.6 MMBPD in 2020, which is down 0.6 MMBPD from 2019.

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

Although the current business outlook remains challenging, we believe that our partnership remains in a strong financial position to endure through these circumstances.

We enter the second half of 2020 with a solid balance sheet, ample liquidity and good coverage of our cash distribution.

At June 30, 2020, we had $ 7.3 billion of consolidated liquidity, which was comprised of $ 6.0 billion of available borrowing capacity under EPO’s revolving credit facilities and $ 1.3 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 & Poor's, Moody’s and Fitch, respectively.

EPO completed a $3.0 billion senior notes offering in January 2020 that provided funds to repay all of its $1.5 billion of senior note maturities in 2020, amounts then outstanding under its commercial paper program and for general company purposes.

In August 2020, EPO issued $1.0 billion in principal amount of 3.20% senior notes due February 2052 and $250.0 million in principal amount of reopened senior notes due January 2030.

Net proceeds from the issuance of senior notes in August 2020 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.

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 in 2021.

Capital spending throughout the domestic energy industry has been significantly reduced to preserve capital during the current downturn.

We are no exception to this trend.

Based on information currently available, we now expect our total capital investments for 2020 to approximate $2.8 billion to $3.3 billion (originally forecast at $3.4 billion to $4.4 billion), which reflects growth capital investments of $2.5 billion to $3.0 billion and approximately $300 million for sustaining capital expenditures.

In addition, we currently expect our growth capital investments on sanctioned projects for 2021 and 2022 to approximate $2.3 billion and $1.0 billion, respectively.

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 governmental approvals for SPOT during 2020.

In addition to reductions made in our capital spending program, we continue to discuss project commitments with customers and joint venture opportunities with strategic partners to optimize our use of available capital.

These efforts, which have been slowed in the second quarter of 2020 due to impacts of the pandemic, could further reduce our planned growth capital investments for 2020, 2021 and 2022.

We continue to optimize our assets during this difficult period to provide incremental services to customers and to respond to market opportunities;

however, as expected w e experienced a reduction in volumes on a number of our assets during the second quarter of 2020 due to reduced upstream drilling activity and lower downstream refinery activity and demand for transportation fuels.

Furthermore, we may continue to experience throughput declines in the second half of 2020 on our gathering systems, long-haul liquids and natural gas pipelines and at our terminal, fractionation and other facilities until the pandemic ends and economic activity is fully restored.

To the extent that we have firm transportation agreements (e.g., ship-or-pay arrangements) and the shipper/customer has sufficient liquidity to satisfy its contractual commitments, we expect the near-term impacts to be manageable.

Our business is predominately fee-based (approximately 86% of gross operating margin in 2019), with a substantial portion backed by take-or-pay arrangements.

The reduction in upstream production activity and international demand is negatively impacting the export of crude oil and basic petrochemicals from our marine terminals;

however, LPG export demand has remained resilient.

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

During the second quarter of 2020, we were also able to benefit by using uncontracted storage capacity to capture contango opportunities in NGLs, crude oil and refined products and will continue to see this benefit for the remainder of 2020.

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.

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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, equity method investments, intangible assets and goodwill carrying values for potential impairment.

We did not recognize any significant non-cash asset impairment charges during the first six months of 2020.

However, if the impacts from the outbreak of COVID-19 and adverse developments in the global energy markets persist for significantly longer periods than currently expected, these events could result in asset impairment charges in the future.

Other Recent Developments

Issuance of Senior Notes in January 2020 and August 2020

In January 2020, EPO issued $3.0 billion aggregate principal amount of senior notes comprised of (i) $1.0 billion principal amount of senior notes due January 2030 (“Senior Notes AAA”), (ii) $1.0 billion principal amount of senior notes due January 2051 (“Senior Notes BBB”) and (iii) $1.0 billion principal amount of 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 will be used by EPO for the repayment of $1.0 billion principal amount of its Senior Notes Y upon their maturity in September 2020.

Senior Notes AAA were issued at 99.921% of their principal amount and have a fixed-rate interest rate of 2.80% per year.

Senior Notes BBB were issued at 99.413% of their principal amount and have a fixed-rate interest rate of 3.70% per year.

Senior Notes CCC were issued at 99.360% of their principal amount and have a fixed-rate interest rate of 3.95% per year.

EPD guaranteed these senior notes through an unconditional guarantee on an unsecured and unsubordinated basis.

In August 2020, EPO issued $1.0 billion in principal amount of 3.20% senior notes due February 2052 (“Senior Notes DDD”) and $250.0 million in principal amount of reopened 2.80% senior notes due January 2030 (“Senior Notes AAA”).

The reopened Senior Notes AAA and the Senior Notes DDD were issued at 107.211% and 99.233% of their principal amounts, respectively.

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 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 Ethane Export Terminal facility.

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

Enterprise Declares Cash Distribution for Second Quarter of 2020

On July 7 , 2020, we announced that the Board declared a quarterly cash distribution to be paid to our limited partners with respect to the second quarter of 2020 of $0.4450 per common unit, or $1.78 per unit on an annualized basis.

The quarterly distribution associated with the second quarter of 2020 is payable on August 12 , 2020, to unitholders of record as of the close of business on July 31 , 2020.

This distribution represents a 1.1 % increase over the distribution declared with respect to the second quarter of 2019.

We paid our limited partners a distribution of $0.4450 per common unit with respect to the first quarter of 2020 on May 12 , 2020.

In light of current economic conditions, management will evaluate future cash distributions in 2020 on a quarterly basis.

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

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

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

Enterprise Enters Into April 2020 364-Day Revolving Credit Agreement

In April 2020, EPO entered into an additional 364-day revolving credit agreement (the “April 2020 364-Day Revolving Credit Agreement ”).

The new agreement provides EPO with an incremental $1.0 billion of borrowing capacity, thereby increasing its overall borrowing capacity under its revolving credit agreements to $6.0 billion.

The April 2020 364-Day Revolving Credit Agreement enhances our financial flexibility during the economic downturn caused by the COVID-19 pandemic.

Under the terms of the April 2020 364-Day Revolving Credit Agreement, EPO may borrow up to $1.0 billion at a variable interest rate for a term of 364 days, subject to the terms and conditions set forth therein.

EPO may use proceeds from borrowings under the April 2020 364-Day Revolving Credit Agreement for working capital, capital expenditures, acquisitions and other company purposes.

Settlement of Liquidity Option

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

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

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

(“Skyline,” an affiliate of M&B) in exchange for the capital stock of OTA.

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

At March 5, 2020, OTA’s assets and liabilities consisted primarily of the EPD common units it owned and the related deferred tax liability, respectively.

At March 5, 2020, our accrual for the Liquidity Option liability was $511.9 million.

The Liquidity Option liability, at any measurement date, represents the present value of estimated federal and state income taxes that we believe a market participant would incur due to ownership of OTA, including its deferred income tax liabilities.

OTA’s deferred tax liability at March 5, 2020 was $439.7 million.

The market value of the new EPD common units issued to Skyline was $1.30 billion based on a closing price of $23.67 per unit on March 5, 2020.

The 54,807,352 new EPD common units issued to Skyline upon settlement of the Liquidity Option constitute “restricted securities” in the meaning of Rule 144 under the Securities Act of 1933, as amended (the “Securities Act”) and may not be resold except pursuant to an effective registration statement or an available exemption under the Securities Act.

In connection with the settlement of the Liquidity Option, Enterprise entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with Skyline.

Pursuant to the Registration Rights Agreement, Skyline has the right to request that we prepare and file a registration statement to permit and otherwise facilitate the public resale of all or a portion of such EPD common units that Skyline and its affiliates then own.

Our obligation to Skyline to effect such transactions is limited to five registration statements and underwritten offerings.

In May 2020, we filed a registration statement on behalf of Skyline for the resale of up to 54,807,352 EPD common units.

This registration statement is effective and, in June 2020, we filed a prospectus supplement to this registration statement that allows Skyline to sell up to $500 million of the EPD common units it owns in connection with an “at-the-market” program that it administers.

We will not receive any proceeds from such offerings.

As a result of the Liquidity Option settlement, the partners’ equity balance for common units (as presented on our Unaudited Condensed Consolidated Balance Sheet) increased by the $1.30 billion market value of the new EPD common units issued to Skyline.

Since OTA does not meet the definition of a business as described in ASC 805, Business Combinations , t he acquisition of OTA was accounted for as the purchase of treasury units and assumption of the related deferred tax liability.

In consolidation, we present the 54,807,352 EPD common units owned by OTA as treasury units, with their historical cost based on the $1.30 billion market value of the 54,807,352 new EPD common units issued to Skyline.

For information regarding the impact of the settlement on our earnings for the six months ended June 30, 2020, see “ Income Statement Highlights – Income Taxes ” within this Item 2.

Selected Energy Commodity Price Data

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(“IHS Chemical”).

Refinery grade propylene prices represent weighted-average spot prices for such product as reported by IHS Chemical.

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.

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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 $ 0.31 per gallon in the second quarter of 2020 versus $0.47 per gallon during the second quarter of 2019.

Likewise, the weighted-average indicative market price for NGLs was $ 0.33 per gallon during the six months ended June 30, 2020 compared to $0.52 per gallon during the same period in 2019.

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

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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 recent oil price dispute between Saudi Arabia and Russia.

See “ Update on 2020 Outlook ” within this Item 2 for information regarding these events.

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.

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For the Three Months

Ended June 30,

For the Six Months

Ended June 30,

Ended September 30,

For the Nine Months

Ended September 30,

Costs and expenses:

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Net income attributable to noncontrolling interests

Net income attributable to limited partners

Net income attributable to preferred units

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 June 30,

For the Six Months

Ended June 30,

Ended September 30,

For the Nine Months

Ended September 30,

NGL Pipelines & Services:

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Total consolidated revenues

Second Quarter of 2020 Compared to Second Quarter of 2019 .

Total revenues for the second quarter of 2020 decreased $2.53 billion when compared to the second quarter of 2019 primarily due to a net $2.35 billion decrease in marketing revenues.

Revenues from the marketing of crude oil and natural gas decreased $1.57 billion quarter-to-quarter primarily due to lower sales prices, which accounted for a $1.18 billion decrease, and lower sales volumes, which accounted for an additional $389.7 million decrease.

Revenues from the marketing of NGLs, petrochemicals and refined products decreased a net $783.0 million quarter-to-quarter primarily due to lower sales prices, which accounted for a $1.46 billion decrease, partially offset by the effects of higher sales volumes, which resulted in a $678.7 million increase.

Revenues from midstream services for the second quarter of 2020 decreased $ 173.6 million when compared to the second quarter of 2019.

Revenues from our natural gas processing facilities decreased a net $ 76.8 million quarter-to-quarter primarily due to the impact of lower NGL prices in the second quarter of 2020 compared to the second quarter of 2019 on the value of equity NGLs we receive as non-cash consideration for processing services.

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.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 .

Total revenues for the six months ended June 30, 2020 decreased $3.59 billion when compared to the six months ended June 30, 2019 primarily due to a net $3.37 billion decrease in marketing revenues.

Revenues from the marketing of crude oil and natural gas decreased $2.46 billion period-to-period primarily due to lower sales prices, which accounted for a $1.76 billion decrease, and lower sales volumes, which accounted for an additional $700.7 million decrease.

Revenues from the marketing of NGLs decreased a net $977.3 million period-to-period primarily due to lower sales prices, which accounted for a $2.02 billion decrease, partially offset by the effects of higher sales volumes, which resulted in a $1.04 billion increase.

Revenues from the marketing of petrochemicals and refined products increased a net $59.2 million period-to-period primarily due to higher sales volumes, which accounted for a $691.1 million increase, partially offset by lower sales prices, which resulted in a $631.9 million decrease.

Revenues from midstream services for the six months ended June 30, 2020 decreased $ 211.5 million when compared to the six months ended June 30, 2019.

Revenues from our natural gas processing facilities decreased a net $ 122.1 million period-to-period primarily due to the impact of lower NGL prices in the six months ended June 30, 2020 compared to the six months ended June 30, 2019 on the value of equity NGLs we receive as non-cash consideration for processing services.

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.

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Operating costs and expenses

Second Quarter of 2020 Compared to Second Quarter of 2019 .

Total operating costs and expenses for the second quarter of 2020 decreased $2.43 billion when compared to the second 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 $1.51 billion quarter-to-quarter primarily due to lower purchase prices, which accounted for a $1.24 billion decrease, and lower sales volumes, which accounted for an additional $264.6 million decrease.

The cost of sales associated with our marketing of NGLs decreased a net $949.5 million quarter-to-quarter primarily due to lower purchase prices, which accounted for a $1.2 billion decrease, partially offset by higher sales volumes, which accounted for a $255.4 million increase.

The cost of sales associated with our marketing of petrochemicals and refined products increased a net $43.3 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $350.9 million increase, partially offset by lower purchase prices, which accounted for a $307.6 million decrease.

Other operating costs and expenses for the second quarter of 2020 decreased $53.1 million quarter-to-quarter primarily due to lower maintenance, chemical and power-related expenses, which accounted for a $79.7 million decrease, partially offset by higher ad valorem taxes, which accounted for a $20.3 million increase.

Depreciation, amortization and accretion expense increased $31.5 million quarter-to-quarter primarily due to assets placed into full or limited service since the second quarter of 2019 (e.g., the isobutane dehydrogenation (“iBDH”) plant, Mentone facility, Mont Belvieu Frac X and the Enterprise Navigator ethylene terminal).

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 .

Total operating costs and expenses for the six months ended June 30, 2020 decreased $3.39 billion when compared to the six months ended June 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 $2.21 billion period-to-period primarily due to lower purchase prices, which accounted for a $1.69 billion decrease, and lower sales volumes, which accounted for an additional $520.8 million decrease.

The cost of sales associated with our marketing of NGLs decreased a net $1.26 billion period-to-period primarily due to lower purchase prices, which accounted for a $2.08 billion decrease, partially offset by higher sales volumes, which accounted for an $828.5 million increase.

The cost of sales associated with our marketing of petrochemicals and refined products increased a net $40.6 million period-to-period primarily due to higher sales volumes, which accounted for a $628.0 million increase, partially offset by lower purchase prices, which accounted for a $587.4 million decrease.

Other operating costs and expenses for the six months ended June 30, 2020 decreased $29.1 million period-to-period primarily due to lower maintenance and power-related expenses, which accounted for an $82.3 million decrease, partially offset by higher ad valorem taxes and employee compensation costs, which accounted for a $56.9 million increase.

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.

General and administrative costs

General and administrative costs for the three and six months ended June 30, 2020 increased $ 4.5 million and $ 7.8 million, respectively, when compared to the same periods in 2019 primarily due to higher employee compensation costs and professional services expense.

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.

Equity in income of unconsolidated affiliates

Equity income from our unconsolidated affiliates for the three and six months ended June 30, 2020 decreased $ 24.1 million and $ 37.9 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 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.

Operating income

Operating income for the three and six months ended June 30, 2020 decreased $ 123.4 million and $ 242.1 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 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.

Interest expense

1 unchanged sentence

For the Three Months

Ended June 30,

For the Six Months

Ended June 30,

Ended September 30,

For the Nine Months

Ended September 30,

Interest charged on debt principal outstanding

1 unchanged sentence

Interest costs capitalized in connection with construction projects (2)

Amount presented for the six months ended June 30, 2019 includes $ 9.8 million of swaption premium income.

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 $26.6 million quarter-to-quarter primarily due to increased debt principal amounts outstanding during the second quarter of 2020, which accounted for a $31.0 million increase, partially offset by the effect of lower overall interest rates during the second quarter of 2020, which accounted for a $4.4 million decrease.

Our weighted-average debt principal balance for the second quarter of 2020 was $29.9 billion compared to $ 27.1 billion for the second quarter of 2019.

For the six months ended June 30, 2020, interest charged on debt principal outstanding increased a net $ 50.6 million period-to-period primarily due to increased debt principal amounts outstanding during the six months ended June 30, 2020, which accounted for a $ 62.2 million increase, partially offset by the effect of lower overall interest rates during the six months ended June 30, 2020, which accounted for an $ 11.6 million decrease.

Our weighted-average debt principal balance for the six months ended June 30, 2020 was $ 29.61 billion compared to $ 26.9 billion for the six months ended June 30, 2019.

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.

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.

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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.

As discussed in the following section, Income taxes , our obligations under the Liquidity Option Agreement were settled on March 5, 2020.

Expense attributable to changes in the fair value of the Liquidity Option were $26.6 million and $84.4 million during the three and six months ended June 30, 2019, respectively.

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 six months ended June 30, 2019 was primarily due to a decrease in the discount factor used in determining the present value of the liability.

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 June 30,

For the Six Months

Ended June 30,

Settlement of Liquidity Option at March 5, 2020

Ended September 30,

For the Nine Months

Ended September 30,

Deferred tax benefit (expense) attributable to OTA

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Benefit from (provision for) income taxes

On March 5, 2020, we settled the Liquidity Option (see “ Other Recent Developments ” within this Item 2) and assumed OTA’s deferred tax liability, which reflects the outside basis difference of OTA in the 54,807,352 EPD common units it owns.

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 taxes” line on our Unaudited Condensed Statement of Consolidated Operations for the six months ended June 30, 2020.

The deferred tax liability of OTA is subject to fluctuation due to changes in the market value of the EPD common units it owns relative to its underlying tax basis in the units.

With respect to the second quarter of 2020, OTA recognized deferred income tax expense of $50.5 million primarily due to an increase in the market value of its investment in EPD common units since March 31, 2020.

At June 30, 2020, the deferred tax liability of OTA was $375.2 million.

OTA recognized a deferred income tax benefit of $64.5 million through June 30, 2020 primarily due to a decrease in the market value of its investment in EPD common units since March 5, 2020.

In total, earnings for the six months ended June 30, 2020 reflect a net $136.7 million of deferred income tax benefit attributable to OTA.

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 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.

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

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

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):

For the Three Months

Ended June 30,

For the Six Months

Ended June 30,

Ended September 30,

For the Nine Months

Ended September 30,

Gross operating margin by segment:

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For the Three Months

Ended June 30,

For the Six Months

Ended June 30,

Ended September 30,

For the Nine Months

Ended September 30,

Operating income

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In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of gross operating margin for the partnership.

In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of gross operating margin for us.

Our segment results for the second quarter of 2020 reflect the challenging business environment we are currently experiencing due to the COVID-19 pandemic.

A number of our assets were impacted by lower volumes due to reduced drilling activity and downstream refinery activity and demand for transportation fuels.

For a general discussion of the impact of COVID-19 on our partnership and industry, see “ Update on 2020 Outlook” within this Item 2.

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

1 unchanged sentence

For the Three Months

Ended June 30,

For the Six Months

Ended June 30,

Ended September 30,

For the Nine Months

Ended September 30,

Segment gross operating margin:

11 unchanged sentences

Fee-based natural gas processing volumes are measured at either the wellhead or plant inlet in MMcf/d.

For the third and fourth quarters of 2019, fee-based natural gas processing volumes measured in this manner were 4,724 MMcf/d and 4,763 MMcf/d, respectively, and averaged 4,738 MMcf/d for 2019 and 4,430 MMcf/d for 2018.

Natural gas processing and related NGL marketing activities

Second Quarter of 2020 Compared to Second Quarter of 2019 .

Gross operating margin from natural gas processing and related NGL marketing activities for the second quarter of 2020 decreased $49.4 million when compared to the second quarter of 2019.

Gross operating margin from our Rocky Mountain natural gas processing facilities (Meeker, Pioneer and Chaco plants) decreased a combined $39.8 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities).

Lower composite NGL prices impacted processing margins, which declined 34% in the second quarter of 2020 when compared to the second quarter of 2019.

On a combined basis, fee-based natural gas processing volumes decreased 337 MMcf/d and equity NGL production volumes increased 7 MBPD quarter-to-quarter.

Gross operating margin from our South Texas natural gas processing facilities decreased $17.8 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $13.1 million decrease, and lower average processing fees, which accounted for an additional $3.3 million decrease.

Fee-based natural gas processing volumes decreased 138 MMcf/d and equity NGL production volumes increased 12 MBPD quarter-to-quarter.

Gross operating margin from our Permian Basin natural gas processing facilities decreased $4.7 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $5.0 million decrease, lower average processing fees, which accounted for a $4.9 million decrease, and higher operating costs, which accounted for an additional $4.2 million decrease, partially offset by higher processing volumes, which accounted for a $9.7 million increase.

Fee-based natural gas processing and equity NGL production volumes at our Permian Basin natural gas processing facilities increased 243 MMcf/d and 21 MBPD, respectively, quarter-to-quarter primarily due to additional processing capacity at our Orla facility completed 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 $7.3 million quarter-to-quarter primarily due to lower average processing margins, which accounted for an $11.0 million decrease, partially offset by lower operating costs, which accounted for a $4.1 million increase.

Net to our interest, fee-based natural gas processing volumes decreased 373 MMcf/d quarter-to-quarter.

Gross operating margin from our NGL marketing activities increased a net $23.0 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $79.0 million increase, partially offset by lower average sales margins, which accounted for a $56.2 million decrease.

Results from marketing strategies that optimize our transportation and storage assets increased a combined $21.3 million quarter-to-quarter, partially offset by lower earnings from the optimization of our export and plant assets, which accounted for a $30.1 million decrease.

In addition, results from NGL marketing increased $31.8 million quarter-to-quarter due to non-cash, mark-to-market gains of $35.4 million in the second quarter of 2020.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 .

Gross operating margin from natural gas processing and related NGL marketing activities for the six months ended June 30, 2020 decreased $89.8 million when compared to the six months ended June 30, 2019.

Gross operating margin from our Rocky Mountain natural gas processing facilities decreased a combined $57.6 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 and equity NGL volumes decreased 258 MMcf/d and 5 MBPD, respectively, period-to-period.

Gross operating margin from our South Texas natural gas processing facilities decreased $42.6 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $32.4 million decrease, lower processing volumes, which accounted for a $5.4 million decrease, and lower average processing fees, which accounted for an additional $4.5 million decrease.

Fee-based natural gas processing volumes decreased 92 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 $19.2 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $17.3 million decrease, higher operating costs, which accounted for an $11.8 million decrease, and lower average processing fees, which accounted for an additional decrease of $9.6 million, partially offset by higher processing volumes, which accounted for a $19.6 million increase.

Fee-based natural gas processing and equity NGL production volumes at our Permian Basin natural gas processing facilities increased 258 MMcf/d and 11 MBPD, respectively, period-to-period, primarily due to additional processing capacity at our Orla facility completed 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 $12.8 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $19.8 million decrease, partially offset by lower operating costs, which accounted for a $5.2 million increase.

Net to our interest, fee-based natural gas processing volumes decreased 291 MMcf/d period-to-period.

Gross operating margin from our NGL marketing activities increased a net $48.5 million period-to-period primarily due to higher sales volumes, which accounted for a $159.0 million increase, partially offset by lower average sales margins, which accounted for a $110.2 million decrease.

Results from marketing strategies that optimize our storage, transportation and export assets increased a combined $39.1 million period-to-period, partially offset by lower earnings from the optimization of our plant assets, which accounted for a $9.7 million decrease.

In addition, results from NGL marketing increased $19.1 million period-to-period due to non-cash, mark-to-market gains of $23.1 million in the six months ended June 30, 2020.

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.

NGL pipelines, storage and terminals

Second Quarter of 2020 Compared to Second Quarter of 2019 .

Gross operating margin from our NGL pipelines, storage and terminal assets during the second quarter of 2020 increased $17.6 million when compared to the second quarter of 2019.

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.

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.

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 $ 3.1 million quarter-to-quarter primarily due to a 39 MBPD increase in transportation volumes.

Gross operating margin from our Aegis Pipeline increased $8.9 million quarter-to-quarter primarily due to a 168 MBPD increase in transportation volumes associated with contract commitments.

Gross operating margin from our Dixie Pipeline and related terminals increased a combined $ 4.9 million quarter-to-quarter primarily due to higher average transportation fees.

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 $5.3 million quarter-to-quarter primarily due to higher average fees, which accounted for a $15.7 million increase, lower operating costs, which accounted for an additional $6.7 million increase, partially offset by lower transportation volumes of 166 MBPD (net to our interest), which accounted for a $17.9 million decrease.

Gross operating margin from our South Texas NGL Pipeline System decreased $6.6 million quarter-to-quarter primarily due to lower pipeline capacity fee revenues earned from an affiliate pipeline.

Transportation volumes on our South Texas NGL Pipeline System increased 16 MBPD quarter-to-quarter.

Gross operating margin from our Lou-Tex NGL Pipeline decreased $3.8 million quarter-to-quarter primarily due to lower transportation volumes of 42 MBPD.

Gross operating margin from our South Louisiana NGL Pipeline System decreased $3.5 million quarter-to-quarter primarily due to lower transportation volumes of 78 MBPD.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 .

Gross operating margin from our NGL pipelines, storage and terminal assets during the six months ended June 30, 2020 increased $113.6 million when compared to the six months ended June 30, 2019.

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 Dixie Pipeline and related terminals increased a combined $ 7.9 million period-to-period primarily due to higher transportation volumes of 13 MBPD, which accounted for a $3.6 million increase, and higher average transportation fees, which accounted for an additional $2.6 million increase.

On a combined basis, gross operating margin from our pipelines serving Permian Basin and/or Rocky Mountain producers increased $52.1 million period-to-period primarily due to higher average fees, which accounted for a $29.0 million increase, lower operating costs, which accounted for an additional $19.7 million increase, partially offset by lower transportation volumes of 114 MBPD (net to our interest), which accounted for a $23.8 million decrease.

The $52.1 million increase also includes gross operating margin from our Shin Oak NGL Pipeline, which increased $24.3 million period-to-period primarily due to the first six months of 2019 reflecting a ramp-up of transportation volumes following its start-up in February 2019.

Gross operating margin from our Appalachia-to-Texas Express (“ATEX”) pipeline decreased $ 8.9 million period-to-period primarily due to lower transportation volumes, which decreased 17 MBPD period-to-period.

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.

Gross operating margin from our Mont Belvieu storage facility decreased $ 7.7 million period-to-period primarily due to lower handling fee revenues, which accounted for an $18.5 million decrease, partially offset by higher storage and throughput fees, which accounted for a $10.6 million increase.

NGL fractionation

Second Quarter of 2020 Compared to Second Quarter of 2019 .

Gross operating margin from NGL fractionation during the second quarter of 2020 increased $33.6 million when compared to the second quarter of 2019.

Gross operating margin from our Mont Belvieu NGL fractionation complex increased $27.7 million quarter-to-quarter primarily due to higher fractionation volumes, which increased 166 MBPD quarter-to-quarter (net to our interest) primarily due to the start-up of the first fractionation train (“Frac X”) at our newly constructed NGL fractionation facility located in Chambers County, Texas.

Gross operating margin from our South Texas NGL fractionators increased $5.1 million quarter-to-quarter primarily due to lower operating costs at our Shoup fractionator, which underwent major maintenance activities during the second quarter of 2019.

NGL fractionation volumes at our South Texas facilities increased 13 MBPD quarter-to-quarter.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 .

Gross operating margin from NGL fractionation during the six months ended June 30, 2020 increased $60.8 million when compared to the six months ended June 30, 2019.

Gross operating margin from our Mont Belvieu NGL fractionation complex increased $27.7 million primarily due to higher fractionation volumes, which increased 168 MBPD period-to-period (net to our interest) primarily due to the start-up of Frac X.

Gross operating margin at our Hobbs NGL fractionator increased $17.8 million period-to-period primarily due to major maintenance activities during the first quarter of 2019.

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 $5.7 million period-to-period primarily due to higher NGL fractionation volumes of 22 MBPD.

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.

Crude Oil Pipelines & Services

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For the Three Months

Ended June 30,

For the Six Months

Ended June 30,

Ended September 30,

For the Nine Months

Ended September 30,

Segment gross operating margin:

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excluding associated non-cash mark-to-market results

Non-cash mark-to-market gains

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

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

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Crude oil marine terminal volumes (MBPD)

Second Quarter of 2020 Compared to Second Quarter of 2019 .

Gross operating margin from our Crude Oil Pipelines & Services segment for the second quarter of 2020 increased $121.2 million when compared to the second quarter of 2019.

Gross operating margin from other crude oil marketing activities increased $ 219.3 million quarter-to-quarter primarily due to higher average sales margins, which accounted for a $ 185.2 million increase, and higher non-cash mark-to-market earnings, which accounted for an additional $36.6 million increase.

Results for the second quarter of 2020 were primarily attributable to higher margins from using uncontracted storage capacity for contango opportunities and regional price spreads.

Gross operating margin from crude oil activities at EHT increased $5.4 million quarter-to-quarter primarily due to higher average terminal fees, which accounted for an $18.0 million increase, lower operating costs, which accounted for an additional $7.7 million increase, partially offset by a $20.7 million decrease due to lower volumes of 249 MBPD.

Gross operating margin from our Midland-to-ECHO System (Midland-to-ECHO 1 and 2 pipelines) and related business activities decreased $59.7 million quarter-to-quarter primarily due to lower earnings from marketing activities, which accounted for a $53.9 million decrease (including lower non-cash mark-to-market results of $14.0 million), lower transportation volumes, which accounted for an additional $22.7 million decrease, partially offset by lower chemical and other operating costs of $21.5 million.

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 $7.8 million quarter-to-quarter primarily due to lower transportation and other fees in the second quarter of 2020.

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 ECHO terminal decreased $16.3 million quarter-to-quarter primarily due to a benefit recognized during the second quarter of 2019 in connection with a settlement.

Gross operating margin from our equity investment in the Seaway Pipeline decreased $10.7 million quarter-to-quarter primarily due to lower average transportation volumes, which accounted for a $17.1 million decrease, and lower transportation fees, which accounted for an additional $10.0 million decrease, partially offset by lower operating costs of $12.3 million.

Net to our interest, transportation volumes on the Seaway Pipeline decreased 193 MBPD quarter-to-quarter.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 .

Gross operating margin from our Crude Oil Pipelines & Services segment for the six months ended June 30, 2020 decreased $88.2 million when compared to the six months ended June 30, 2019.

Gross operating margin from our Midland-to-ECHO System and related business activities decreased $153.7 million period-to-period primarily due to lower earnings from marketing activities of $165.2 million, which includes lower non-cash mark-to-market results of $80.3 million period-to-period, partially offset by lower chemical and other operating costs of $15.9 million.

Gross operating margin from our South Texas Crude Oil Pipeline System decreased $17.3 million period-to-period primarily due to lower deficiency and other fees during the six months ended June 30, 2020.

Gross operating margin from our equity investment in the Eagle Ford Crude Oil Pipeline decreased $12.5 million period-to-period primarily due to lower transportation volumes of 32 MBPD (net to our interest).

Gross operating margin from our ECHO terminal decreased $18.0 million period-to-period primarily due to a benefit recognized during the second quarter of 2019 in connection with a settlement.

Gross operating margin from our equity investment in the Seaway Pipeline decreased $27.2 million period-to-period primarily due to lower average transportation volumes, which accounted for a $25.1 million decrease, and lower transportation fees, which accounted for an additional $18.0 million decrease, partially offset by lower operating costs of $14.4 million.

Net to our interest, transportation volumes on the Seaway Pipeline decreased 122 MBPD period-to-period.

Gross operating margin from other crude oil marketing activities increased $ 101.3 million period-to-period primarily due to higher average sales margins, which accounted for a $ 90.3 million increase, and higher non-cash mark-to-market earnings, which accounted for an additional $ 13.8 million increase.

Gross operating margin from crude oil activities at EHT increased $20.8 million period-to-period primarily due to higher storage revenues and average terminal fees, which accounted for a combined $22.8 million increase, lower operating costs, which accounted for an additional $6.6 million increase, partially offset by a $12.1 million decrease due to lower volumes of 93 MBPD.

Lastly, gross operating margin from our West Texas System increased $11.3 million period-to-period primarily due to higher transportation volumes of 22 MBPD.

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 ECHO terminal decreased $7.0 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 $91.7 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.

Natural Gas Pipelines & Services

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For the Three Months

Ended June 30,

For the Six Months

Ended June 30,

Ended September 30,

For the Nine Months

Ended September 30,

Segment gross operating margin

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Natural gas pipeline transportation volumes (BBtus/d)

Second Quarter of 2020 Compared to Second Quarter of 2019 .

Gross operating margin from our Natural Gas Pipelines & Services segment for the second quarter of 2020 decreased $92.9 million when compared to the second quarter of 2019.

Gross operating margin from our natural gas marketing activities decreased $35.5 million quarter-to-quarter primarily due to lower average sales margins from regional natural gas price spreads across Texas.

Gross operating margin from our Texas Intrastate System decreased $34.8 million quarter-to-quarter primarily due to lower capacity reservation revenues.

Transportation volumes on our Texas Intrastate System decreased 593 BBtus/d quarter-to-quarter.

Gross operating margin from our Acadian Gas System decreased $24.0 million quarter-to-quarter primarily due to lower capacity reservation revenues on the Haynesville Extension pipeline, which accounted for a $12.1 million decrease, and a benefit recognized during the second quarter of 2019 in connection with a settlement, which accounted for an additional decrease of $11.3 million.

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.

On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System, San Juan Gathering System and equity investment in the White River Hub decreased $4.4 million quarter-to-quarter primarily due to aggregate lower volumes of 586 BBtus/d.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 .

Gross operating margin from our Natural Gas Pipelines & Services segment for the six months ended June 30, 2020 decreased $73.4 million when compared to the six months ended June 30, 2019.

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 $23.3 million period-to-period primarily due to lower capacity reservation revenues on the Haynesville Extension pipeline.

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 $12.5 million period-to-period primarily due to lower gathering, compression and other fee revenues, which accounted for a $9.6 million decrease, and lower gathering volumes of 175 BBtus/d, which accounted for an additional $5.5 million decrease.

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.

On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System, San Juan Gathering System and equity investment in the White River Hub decreased $11.3 million period-to-period primarily due to aggregate lower volumes of 497 BBtus/d.

Gross operating margin from our natural gas marketing activities decreased $3.9 million period-to-period primarily due to lower average sales margins, which accounted for a $27.5 million decrease, lower sales volumes, which accounted for an additional $8.2 million decrease, partially offset by higher mark-to-market results.

The first six months of 2020 includes $32.7 million of mark-to-market gains compared to $0.9 million of such gains for the same period in 2019.

Petrochemical & Refined Products Services

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For the Three Months

Ended June 30,

For the Six Months

Ended June 30,

Ended September 30,

For the Nine Months

Ended September 30,

Segment gross operating margin:

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Refined products pipelines and related activities

Marine transportation and other services

Ethylene exports and other services

Selected volumetric data:

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Propylene production and related activities

Second Quarter of 2020 Compared to Second Quarter of 2019 .

Gross operating margin from propylene production and related activities for the second quarter of 2020 decreased $73.2 million when compared to the second quarter of 2019 primarily due to lower average sales margins, which accounted for a $51.9 million decrease, and lower propylene and associated by-product sales volumes, which accounted for an additional $20.1 million decrease.

Propylene production volumes decreased 32 MBPD quarter-to-quarter (net to our interest).

Our propane dehydrogenation facility experienced 46 days of unplanned downtime in the second quarter of 2020 primarily for major maintenance activities.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 .

Gross operating margin from propylene production and related activities for the six months ended June 30, 2020 decreased $66.9 million when compared to the six months ended June 30, 2019 primarily due to lower average sales margins, which accounted for a $50.4 million decrease, and lower propylene and associated by-product sales volumes, which accounted for an additional $12.6 million decrease.

Propylene production volumes decreased 12 MBPD period-to-period (net to our interest).

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

Second Quarter of 2020 Compared to Second Quarter of 2019 .

Gross operating margin from isomerization and related operations decreased $11.1 million quarter-to-quarter primarily due to lower average by-product sales prices, which accounted for a $7.7 million decrease, and lower volumes of 41 MBPD, which accounted for an additional $7.3 million decrease, partially offset by lower operating costs, which accounted for a $6.3 million increase.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 .

Gross operating margin from isomerization and related operations decreased $19.0 million period-to-period primarily due to lower average by-product sales prices, which accounted for a $15.9 million decrease, and lower volumes of 24 MBPD, which accounted for an additional $8.3 million decrease, partially offset by lower operating costs, which accounted for a $10.6 million increase.

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.

Octane enhancement and related plant operations

Second Quarter of 2020 Compared to Second Quarter of 2019 .

Gross operating margin from our octane enhancement and related plant operations decreased $15.8 million quarter-to-quarter primarily due to lower sales volumes, which accounted for a $10.9 million decrease, and higher operating expenses, which accounted for an additional $4.0 million decrease.

The decrease in sales volumes for the second quarter of 2020 was primarily due to lower international demand for motor gasoline resulting from shelter-in-place mandates caused by the pandemic.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 .

Gross operating margin from our octane enhancement and related plant operations increased $28.9 million period-to-period primarily due to higher average sales margins, which accounted for a $30.0 million increase, and higher sales volumes, which accounted for an additional $7.5 million increase, partially offset by higher operating expenses, which accounted for a $10.4 million decrease.

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.

Refined products pipelines and related activities

Second Quarter of 2020 Compared to Second Quarter of 2019 .

Gross operating margin from refined products pipelines and related activities during the second quarter of 2020 decreased $19.0 million when compared to the second quarter of 2019 primarily due to lower interstate refined product transportation volumes of 55 MBPD on our TE Products Pipeline System, which accounted for a $9.5 million decrease, and higher operating expenses, which accounted for an additional $5.6 million decrease.

Overall transportation volumes on our TE Products Pipeline System increased a net 82 MBPD quarter-to-quarter, which was primarily due to higher petrochemical transport volumes in southeast Texas.

Gross operating margin at our refined products terminal in Beaumont, Texas decreased $4.9 million quarter-to-quarter primarily due to lower storage revenues.

Terminaling volumes at Beaumont decreased a net 127 MBPD quarter-to-quarter.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 .

Gross operating margin from refined products pipelines and related activities during the six months ended June 30, 2020 decreased $25.8 million when compared to the six months ended June 30, 2019.

Gross operating margin at our TE Products Pipeline System decreased $18.2 million when compared to the six months ended June 30, 2019 primarily due to higher operating costs, which accounted for a $9.6 million decrease, and lower interstate refined product transportation volumes of 31 MBPD, which accounted for an additional $8.3 million decrease.

Overall transportation volumes on our TE Products Pipeline System decreased a net 2 MBPD period-to-period.

Gross operating margin at our refined products terminal in Beaumont, Texas decreased $10.2 million period-to-period primarily due to lower storage revenues.

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.

Marine transportation and other services

Second Quarter of 2020 Compared to Second Quarter of 2019 .

Gross operating margin from marine transportation and other services during the second quarter of 2020 increased $5.7 million when compared to the second quarter of 2019.

Gross operating margin from our ethylene export terminal and related operations was $5.0 million for the second quarter of 2020.

Loading volumes at our ethylene export terminal, which was placed into limited service in December 2019, were 9 MBPD during the second quarter of 2020.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 .

Gross operating margin from marine transportation and other services during the six months ended June 30, 2020 increased $5.3 million when compared to the six months ended June 30, 2019.

Gross operating margin from our ethylene export terminal and related operations was $2.3 million for the six months ended June 30, 2020.

Loading volumes at our ethylene export terminal were 6 MBPD during the six months ended June 30, 2020.

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 marine transportation decreased $5.8 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.

Liquidity and Capital Resources

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

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 EPD and EPO (each on a standalone basis) to issue an unlimited amount of equity and debt securities, respectively.

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.

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 June 30, 2020, the average maturity of our consolidated debt obligations was approximately 19.9 years.

The following table presents scheduled maturities of our consolidated debt obligations outstanding at June 30, 2020 for the years indicated (dollars in millions):

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):

Scheduled Maturities of Debt

Principal amount of senior and junior debt obligations

As discussed under “ Other Recent Developments ” within this Item 2, EPO issued $3.0 billion aggregate principal amount of senior notes in January 2020 and $1.25 billion aggregate principal amount of senior notes in August 2020.

In addition, EPO entered into its April 2020 364-Day Revolving Credit Agreement, which provides EPO with an incremental $1.0 billion of borrowing capacity.

At June 30, 2020, there were no principal amounts outstanding under the April 2020 364-Day Revolving Credit Agreement.

EPO’s September 2019 364-Day Revolving Credit Agreement is scheduled to mature in September 2020.

As a result, EPO expects to renew this credit agreement during the third quarter of 2020.

At June 30, 2020, there were no principal amounts outstanding under the September 2019 364-Day Revolving Credit Agreement.

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

Common Unit Buyback Program

In January 2020, management announced its intention to use approximately 2.0% of net cash flow provided by operating activities, or cash flow from operations (“CFFO”), in 2020 to repurchase EPD common units under the Buyback Program approved in January 2019 (the “2019 Buyback Program”).

EPD repurchased 6,357,739 common units under its 2019 Buyback Program through open market purchases in the six months ended June 30, 2020.

The total purchase price of these repurchases (including commissions and fees) was $ 140.1 million, and represented 2.1 % of our consolidated CFFO for the twelve months ended June 30, 2020 .

The repurchased units were cancelled immediately upon acquisition.

As of June 30, 2020 , the remaining available capacity under the 2019 Buyback Program was $ 1.78 billion.

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

In the aggregate, 7,816,739 common units were purchased on the open market during the six months ended June 30, 2020 under the 2019 Buyback Program and by privately held affiliates of EPCO.

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”).

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.

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.

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 August 10, 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 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.

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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A credit rating from one rating agency should be evaluated independently of credit ratings from other rating agencies.

Issuance of Common Units

On March 5, 2020, we settled our obligations under the Liquidity Option Agreement.

As a result, EPD issued 54,807,352 of its common units to Skyline and indirectly reacquired the 54,807,352 EPD common units owned by OTA.

For additional information regarding this transaction, see “ Other Recent Developments – Settlement of Liquidity Option ” within this Item 2.

EPD has registration statements on file with the SEC in connection with its distribution reinvestment plan (“DRIP”) and employee unit purchase plan (“EUPP”).

In July 2019, EPD 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.

This election is subject to change in future quarters depending on the partnership’s need for equity capital.

During the six months ended June 30, 2020, a total of 3,379,971 common units were purchased on the open market and delivered to participants in connection with the DRIP and EUPP.

Apart from $1.3 million attributable to the plan discount available to all participants in the EUPP, the funds used to effect these purchases were sourced from the DRIP and EUPP participants.

No other partnership funds were used to satisfy these obligations.

We plan to use open market purchases to satisfy DRIP and EUPP reinvestments in connection with the distribution expected to be paid on August 12, 2020.

EPD issued and delivered a combined 2,897,990 common units in the six months ended June 30, 2019 in connection with the DRIP and EUPP, which generated net cash proceeds totaling $ 82.2 million.

Common Unit Repurchases Under 2019 Buyback Program

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.

Cash Flow Statement Highlights

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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 Six Months

Ended June 30,

For the Nine Months

Ended September 30,

Net cash flows provided by operating activities

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Changes in energy commodity prices may impact the demand for natural gas, NGLs, crude oil, petrochemical and refined products, which could impact sales of our products and the demand for our midstream services.

Changes in demand for our products and services may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, adverse weather conditions and government regulations affecting prices and production levels.

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

Changes in demand for our products and services may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, public health emergencies, adverse weather conditions and government regulations affecting prices and production levels.

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.

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Operating activities

Net cash flows provided by operating activities for the six months ended June 30, 2020 increased a net $ 10.1 million when compared to the six months ended June 30, 2019 primarily due to:

a $ 243.0 million period-to-period increase primarily due to the timing of cash receipts and payments related to operations;

partially offset by

a $ 199.4 m illion period-to-period decrease resulting from lower partnership earnings in the six months ended June 30, 2020 when compared to the six months ended June 30, 2019 (determined by adjusting our $ 81.1 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 $ 33.5 million period-to-period decrease in cash distributions received on earnings from unconsolidated affiliates primarily attributable to our investments in crude oil pipelines.

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.

Investing activities

Cash used in investing activities for the six months ended June 30, 2020 decreased a net $ 356.0 m illion when compared to the six months ended June 30, 2019 primarily due to:

a $ 284.9 million period-to-period decrease in expenditures for consolidated property, plant and equipment (see “ Capital Investments ” within this Part I, Item 2 for additional information);

a $ 52.6 million period-to-period decrease in investments in unconsolidated affiliates primarily related to NGL and crude oil pipeline projects.

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.

Financing activities

Cash used in financing activities for the six months ended June 30, 2020 decreased a net $ 963.3 million when compared to the six months ended June 30, 2019 primarily due to:

a net $1.24 billion period-to-period increase in net cash inflows attributable to debt.

During the six months ended June 30, 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.

During the six months ended June 30, 2019, we repaid or repurchased $724.2 million principal amount of senior and junior notes.

In addition, net repayments of short term notes under EPO’s commercial paper program were $ 481.7 million during the six months ended June 30, 2020 compared to net issuances of $1.42 billion during the six months ended June 30, 2019 ;

partially offset by

an $ 82.2 million period-to-period decrease in net cash proceeds from the issuance of common units in connection with our DRIP and EUPP.

As noted previously, EPD announced in July 2019 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;

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.

C ash contributions from noncontrolling interests in connection with the construction of our ethylene export facility decreased $ 42.0 million period-to-period.

In addition, in June 2019, an affiliate of Third Coast Midstream, LLC acquired a noncontrolling 25% equity interest in our consolidated subsidiary that owns the Pascagoula natural gas processing plant for $36.0 million in cash ;

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;

a $ 39.0 million period-to-period increase in cash distributions paid to limited partners primarily due to an increase in the quarterly cash distribution rate per unit.

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.

Non-GAAP Cash Flow Measures

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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 limited partners since it serves as an indicator of our success in providing a cash return on investment.

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.

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.

DCF is also a quantitative standard used by the investment community with respect to publicly traded partnerships since the value of a partnership unit is, in part, measured by its yield, which is based on the amount of cash distributions a partnership can pay to a unitholder.

Our management compares the DCF we generate to the cash distributions we expect to pay our partners.

Our management compares the DCF we generate to the cash distributions we expect to pay our common unitholders.

Using this metric, management computes our distribution coverage ratio.

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For the Three Months

Ended June 30,

For the Six Months

Ended June 30,

Net income attributable to limited partners (GAAP) (1)

Adjustments to net income attributable to limited partners to derive DCF

(addition or subtraction indicated by sign):

Ended September 30,

For the Nine Months

Ended September 30,

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):

Depreciation, amortization and accretion expenses

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Equity in income of unconsolidated affiliates

Asset impairment and related charges

Change in fair market value of derivative instruments

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Sustaining capital expenditures (3)

Subtotal DCF, before proceeds from asset sales and monetization of interest rate derivative instruments accounted for as cash flow hedges

Operational DCF (4)

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 limited partners with respect to period

Cash distribution per unit declared by Enterprise GP with respect to period (4)

Total DCF retained by partnership with respect to period (5)

Cash distributions paid to common unitholders with respect to period

Cash distribution per common unit declared by Enterprise GP with respect to period (5)

Total DCF retained by the Partnership with respect to period (6)

Distribution coverage ratio (7)

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

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.

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

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

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.

The following table presents a reconciliation of net cash flows provided by operating activities to DCF for the periods indicated (dollars in millions):

For the Three Months

Ended June 30,

For the Six Months

Ended June 30,

Ended September 30,

For the Nine Months

Ended September 30,

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

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 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.

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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 June 30, 2020 in order to measure FCF over a longer term.

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.

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

For the Three Months

Ended June 30,

For the Six Months

Ended June 30,

Ended September 30,

For the Nine Months

Ended September 30,

For the Twelve Months Ended

September 30,

Net cash flows provided by operating activities (GAAP)

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Capital Investments

As previously discussed, capital investing activity throughout the domestic energy industry is being significantly reduced in response to the demand and supply disruptions attributable to COVID-19 and the oil price shock.

We, along with many other midstream energy companies, have reviewed our planned capital investments in light of these adverse macroeconomic events.

As previously noted and based on information currently available, we now expect our total capital investments for 2020 to approximate $2.8 billion to $3.3 billion, which reflects growth capital investments of $2.5 billion to $3.0 billion and approximately $300 million for sustaining capital expenditures.

Based on sanctioned projects, we currently expect our growth capital investments for 2021 and 2022 to approximate $2.3 billion and $1.0 billion, respectively.

Our revised forecast of capital investments for 2020 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.

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.

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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 a tenth NGL fractionator (“Frac X”) located in Chambers County, Texas into service in March 2020.

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 currently have $6.6 billion of growth capital projects scheduled to be completed by the end of 2023 including the following major projects:

an eleventh NGL fractionator in Chambers County, Texas (“Frac XI,” third quarter of 2020);

components of our Midland-to-ECHO System (third quarter of 2020 into 2021);

expansion of our natural gas pipeline network in northeast Texas in support of our Carthage natural gas processing facilities (fourth quarter of 2020 into 2021);

completion of the Baymark ethylene pipeline in South Texas (fourth quarter of 2020);

expansion of our ethylene export capabilities at Morgan’s Point (fourth quarter of 2020);

expansion and extension of our Acadian Gas System (Gillis Lateral and related projects) (fourth quarter of 2021);

construction of our PDH 2 facility (second quarter of 2023).

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 Six Months

Ended June 30,

For the Nine Months

Ended September 30,

Capital investments for property, plant and equipment:

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

Comparison of Six Months Ended June 30, 2020 with Six Months Ended June 30, 2019

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 $262.9 million decrease.

We placed our iBDH facility and Frac X into service in December 2019 and March 2020, respectively;

completion of the Shin Oak NGL Pipeline (which was completed in stages extending through the fourth quarter of 2019), which accounted for a $253.3 million decrease;

lower investments in natural gas processing facilities and related infrastructure that support Permian Basin production, which accounted for an additional $223.6 million decrease.

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;

lower investments in projects attributable to our ethylene business, which accounted for an $83.8 million decrease;

lower investments in projects attributable to our ethylene business, which accounted for a $129.0 million decrease;

partially offset by,

higher investments in propylene production, NGL fractionation and related plant assets and infrastructure at our Mont Belvieu complex, which accounted for a combined $251.3 million increase;

higher investments in crude oil pipelines, including those comprising our Midland-to-ECHO System, and related infrastructure that support Permian Basin production, which accounted for an overall $188.9 million increase;

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.

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

Our product purchase commitments at June 30, 2020 declined by an estimated $ 8.63 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 $29.9 billion at June 30, 2020 compared to $27.88 billion at December 31, 2019.

See “ Other Recent Developments ” within this Item 2 for information regarding EPO’s senior notes offering in January 2020 and the related use of proceeds.

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.

Off-Balance Sheet Arrangements

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-Q

Item 2. Management’s Discussion and Analysis