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Item 2. Management’s Discussion and Analysis

2020-08-10 compared with 2020-05-08 · 438 added, 292 removed, 441 unchanged (62% of the section changed)

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RESULTS OF OPERATIONS.

For the Three Months Ended March 31, 2020 and 2019

For the Three and Six Months Ended June 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 March 31, 2020.

EPCO, together with its privately held affiliates, owned approximately 32.1% of EPD’s limited partner common units at June 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 first quarter of 2020 compared to the first quarter of 2019.

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.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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Forward-looking statements are subject to a variety of risks, uncertainties and assumptions as described in more detail under Part I, Item 1A of our 2019 Form 10-K and within Part II, Item 1A of this quarterly report.

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

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

If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected.

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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 – Coronavirus and Oil Price Shock

As noted previously, this quarterly report on Form 10-Q, including this Update on 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.

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.

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.

The global energy industry is being severely impacted by two historic events that began during the first quarter of 2020:

the emergence of coronavirus disease 2019 (“COVID-19”) as a global pandemic and its devastating effect on the global economy and energy demand;

the initiation of a crude oil price war in March 2020 between members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (collectively, the “OPEC+” group) and its effect on global crude oil supplies.

OPEC+ subsequently agreed in April 2020 to reduce global supplies by 9.7 MMBPD beginning with the May 2020 production month.

The consequences of international COVID-19 containment measures (and the resulting dramatic declines in end-user demand for hydrocarbons in general), paired with threatened and actual overproduction of crude oil in April 2020 by Saudi Arabia and Russia (in their attempt to gain market share from each other and U.S.

shale producers), resulted in major disruptions to global energy markets.

As a midstream energy company, these macroeconomic events have a direct impact on our financial position, results of operations and cash flows.

As noted 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.

The ongoing COVID-19 public health emergency has resulted in record, near-term decreases in hydrocarbon demand due to travel restrictions, quarantines, temporary business closures and other measures.

In its April 2020 Oil Market Report dated April 15, 2020 (the “April 2020 Report”), the International Energy Agency (“IEA”) estimated that global crude oil demand for April 2020 declined by approximately 29 MMBPD when compared to April 2019.

For May 2020, the IEA forecasts that demand may be down by approximately 26 MMBPD when compared to May 2019.

Within a few months of its initial discovery in China, the highly infectious COVID-19 virus spread across the globe and achieved pandemic status at the end of January 2020.

federal, state and local governments, along with governments of most other developed economies, have imposed significant restrictions, including stay-at-home directives, on their populations in an attempt to stem the spread of the disease.

As of April 15, 2020, a total of 187 countries and territories had enacted some form of containment measures.

Although these restrictions have had significant economic repercussions, including dramatic declines in end-user demand for hydrocarbons in general, the spread of the disease has been slowed in some regions.

Many countries, including the U.S., have either enacted or are considering enacting stimulus measures to support recovery of their economies.

For example, on March 27, 2020, the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted by the U.S., which, at $2.2 trillion, is the largest-ever economic stimulus package in U.S.

In addition, many central banks across the globe have embarked on significant monetary stimulus programs.

On February 13, 2020, the IEA forecasted that global demand for crude oil would fall to its lowest rate since 2011 due to the effects of COVID-19.

As a result, and in connection with a significant drop in hydrocarbon demand in China due to spread of the disease in that country, the OPEC+ group met in early March 2020 to discuss cutting its crude oil production by an additional 1.5 MMBPD through the second quarter of 2020.

OPEC called on Russia to join them in the proposed cuts, which was promptly rejected by Russia.

On March 10, 2020, Saudi Arabia responded by initiating a price war with Russia by increasing its April production from 9.7 MMBPD to approximately 12.3 MMBPD, while Russia responded by declaring that it would increase its crude oil production by 300 MBPD to approximately 11.5 MMBPD.

The actual and threatened actions by Saudi Arabia and Russia resulted in an immediate, severe decline in crude oil prices.

For example, West Texas Intermediate (“WTI”) crude oil prices at Cushing, Oklahoma (as reported by the NYMEX) decreased from $41.28 per barrel on March 6, 2020 to $31.13 on March 9, 2020.

Subsequently, WTI prices fluctuated from a high of $34.36 per barrel to a low of $20.09 per barrel through March 31, 2020.

In contrast, WTI prices closed at $61.06 per barrel on December 31, 2019.

In April 2020, at the urging of President Trump, OPEC and Russia met again to discuss ways to stabilize the global oil markets.

After intense negotiations, OPEC and Russia agreed to reduce their combined oil production by 9.7 MMBPD in May and June 2020, 7.7 MMBPD from July through December 2020 and 5.8 MMBPD from January 2021 to April 2022.

Moreover, the U.S., Brazil and Canada contributed an aggregate 3.7 MMBPD of additional reductions on the basis that adverse market dynamics (e.g., COVID-19 demand destruction) will naturally result in lower production from their respective energy industries.

The new OPEC+ agreement will be reevaluated in December 2021.

The length of the output restrictions by U.S., Brazil and Canada will depend on market forces, which are based on supply and demand fundamentals.

Even with the recent production cuts announced by the OPEC+ group and others, the IEA in its April 2020 Report expects that global crude oil inventories will continue to rise over the near term.

Notwithstanding the announced production cuts, crude oil prices further collapsed in April 2020, with the WTI price for May delivery closing at negative $37.63 per barrel on April 20, 2020.

Per its April 2020 Report, the IEA expects that a gradual recovery in crude oil demand will gain traction in June 2020, although demand is estimated to be approximately 15 MMBPD lower than in June 2019.

Overall, the IEA expects global crude oil demand to average 90.6 MMBPD in 2020, which represents a decline of approximately 9 MMBPD from 2019.

As demand increases in the second half of 2020, the IEA expects that global crude oil and refined product inventories will begin to decrease, which should support moderate increases in energy commodity prices.

WTI closed at $24.56 per barrel on May 5, 2020.

These macroeconomic events are contributing to a number of significant developments within the domestic energy industry that impact our industry outlook for 2020.

According to published reports, these developments include:

Most oil producers in North America will have to reduce the drilling and completion of new wells.

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.

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.

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.

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.

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.

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.

As a result of lower crude oil prices, bankruptcies by shale oil producers are expected to increase according to a Rystad Energy report published on April 3, 2020.

In April 2020, Whiting Petroleum Corporation was the first notable producer to declare Chapter 11 bankruptcy due to the crude oil price crash.

Notwithstanding reductions in the drilling and completion of new wells, U.S.

producers continued to pump at near-record highs of approximately 13 MMBPD in late March 2020 (down to 12.3 MMBPD by April 10, 2020).

With the reduction in end-user demand caused by COVID-19, certain independent producers filed a complaint seeking that the Railroad Commission of Texas (“Texas RRC”), which has certain regulatory power over crude oil production in Texas, consider curtailing production for the first time in 50 years.

Other states are also considering production curtailments.

The Texas RRC held an open meeting on April 14, 2020 to discuss prorationing with various energy companies and other interested parties;

however, on May 5, 2020, the commissioners passed a motion to dismiss the prorationing complaint.

We continue to monitor state regulatory developments.

Although we expect a near-term reduction in volumes as the effects of these developments ripple through the major production basins, the long term impacts are not known at this time.

We may 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 export facilities.

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.

The expected reduction in upstream production and a lack of downstream global markets is negatively impacting the export of crude oil and basic petrochemicals from our marine terminals;

however, LPG export demand has thus far remained resilient.

Notably, markets that experience extreme demand shocks like the current environment generally need significant amounts of immediate storage capacity, which we can help provide.

Capital spending throughout the domestic energy industry is being significantly reduced to protect cash flow.

For example, integrated oil majors Chevron Corporation and ExxonMobil recently announced reductions in their 2020 capital expenditure budgets of 20% (as of March 24, 2020) and 30% (as of April 7, 2020), respectively.

Many smaller and independent energy producers are not expected to have the same level of access to the capital markets as they did during the previous downturn in 2015/2016.

Based on information currently available, we now expect our total capital investments for 2020 to approximate $2.8 billion to $3.3 billion (previously $3.4 billion to $4.4 billion), which reflects growth capital investments of $2.5 billion to $3.0 billion (previously $3.0 billion to $4.0 billion) and approximately $300 million for sustaining capital expenditures (previously $400 million).

We currently expect our growth capital investments on sanctioned projects for 2021 and 2022 to approximate $2.5 billion and $1.5 billion, respectively.

Baker Hughes reports 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.

Furthermore, the EIA expects U.S.

crude oil production to average 11.0 MMBPD in 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.

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 in 2020.

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

Refiners have significantly reduced their utilization rates in response to the lack of domestic and international demand.

According to the IEA’s April 2020 Report, global refining throughput for 2020 is forecast to fall 7.6 MMBPD to 74.3 MMBPD in 2020 on sharply reduced demand for transportation fuels.

Global refinery intake is expected to decrease 16 MMBPD in the second quarter of 2020 when compared to the second quarter of 2019.

Although refinery runs are falling, the IEA expects that refined product inventories will increase by 6 MMBPD due to drastically lower demand.

The IEA expects that refining activity will slowly recover in the second half of 2020.

As a result of the decline in downstream refinery activity and demand for transportation fuels, we expect near-term declines in our petrochemical and refined products businesses, particularly in volumes attributable to our Mont Belvieu octane enhancement facilities and related plants.

We also expect near-term reductions in propylene fractionation volumes in the second quarter of 2020.

Volumes at our facilities should improve as COVID-19 containment measures are lifted and economic conditions improve.

Although the outlook for 2020 includes major challenges for the domestic energy industry, we believe that our partnership was in a strong financial position entering into these unprecedented events and can endure through this economic cycle due to the following:

We entered 2020 in the strongest financial position in our 22-year history, with a solid balance sheet, strong liquidity and good coverage of the cash distribution.

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;

At April 30, 2020, our liquidity was $ 8.1 billion comprised of an aggregate $6.0 billion from undrawn revolving credit facilities and $ 2.1 billion of cash on hand.

This includes a second 364-Day Revolving Credit Agreement that we entered into on April 3, 2020 that increased our liquidity by $1.0 billion;

We do not currently anticipate any need to access the debt capital markets until 2021.

We completed a $3.0 billion senior notes offering in January 2020 that provided funds to repay all of our $1.5 billion of senior note maturities in 2020, and believe that we will have sufficient liquidity and/or access to debt capital markets to fund $1.33 billion of senior notes maturing in 2021;

In addition to the adjustments we made to our capital spending program for 2020 noted previously, we continue to discuss project commitments with customers and joint venture opportunities with strategic partners to optimize our use of available liquidity.

These efforts could further reduce our planned growth capital investments for 2020, 2021 and 2022;

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

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.

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.

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.

We continue to leverage our assets to provide incremental services to customers during this difficult period and to respond to market opportunities caused by the destruction in near-term hydrocarbon demand and the related price shocks on crude oil, NGLs, refined products and petrochemicals.

Currently, crude oil prices, along with those of certain refined products, are in contango as near-term deliveries trade at steep discounts to contracts further out in time;

Our LPG export terminals continue to operate at high levels of utilization, thus far demonstrating resilient international demand for these energy commodities;

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 quarter of 2020.

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

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 Credit Agreement ”).

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

The April 2020 364-Day Credit Agreement enhances our financial flexibility during the current economic downturn caused by the COVID-19 pandemic and oil price shock.

Under the terms of the April 2020 364-Day 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 Credit Agreement for working capital, capital expenditures, acquisitions and other company purposes.

Enterprise Provides Distribution and Buyback Guidance for 2020

On March 18, 2020, the Board declared a quarterly cash distribution to be paid to our limited partners with respect to the first quarter of 2020 of $0.4450 per common unit, or $1.78 per unit on an annualized basis.

The quarterly distribution associated with the first quarter of 2020 is payable on May 12, 2020, to unitholders of record as of the close of business on April 30, 2020.

This distribution represents a 1.7% increase over the distribution declared with respect to the first quarter of 2019.

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.

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.

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”).

For information regarding the 2019 Buyback Program, including repurchases of common units in the first quarter of 2020, see “ Liquidity and Capital Resources – Common Unit Buyback Program ” within this Part I, Item 2.

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

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

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

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

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

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

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

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

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

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

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

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

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

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, Oiltanking Holding Americas, Inc.

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

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

As a result of the Liquidity Option settlement, the partners’ capital 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 the assumption of related deferred income tax liability.

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 first quarter of 2020, see “ Income Statement Highlights – Income Taxes ” within this Item 2.

Issuance of $3.0 Billion of Senior Notes in January 2020

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.

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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2020 by quarter:

2020 Averages

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

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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 $0.35 per gallon in the first quarter of 2020 versus $0.57 per gallon during the first quarter of 2019.

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

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2020 by quarter:

2020 Averages

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

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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 – Coronavirus and Oil Price Shock ” within this Item 2 for information regarding these events.

See “ Update on 2020 Outlook ” within this 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 March 31,

Ended June 30,

For the Six Months

Ended June 30,

Costs and expenses:

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Depreciation, amortization and accretion expenses

Net losses (gains) attributable to asset sales

Net gains attributable to asset sales

Asset impairment and related charges

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For the Three Months

Ended March 31,

Ended June 30,

For the Six Months

Ended June 30,

NGL Pipelines & Services:

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Total consolidated revenues

Total revenues for the first quarter of 2020 decreased $1.06 billion when compared to the first quarter of 2019 primarily due to a net $1.02 billion decrease in marketing revenues.

Revenues from the marketing of crude oil and natural gas decreased $888.0 million quarter-to-quarter primarily due to lower sales prices, which accounted for a $610.0 million decrease, and lower sales volumes, which accounted for an additional $278.0 million decrease.

Revenues from the marketing of NGLs decreased a net $252.0 million quarter-to-quarter primarily due to lower sales prices, which accounted for a $962.4 million decrease, partially offset by the effects of higher sales volumes, which resulted in a $710.4 million increase.

Revenues from the marketing of petrochemicals and refined products increased a net $116.9 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $197.1 million increase, partially offset by lower sales prices, which resulted in an $80.2 million decrease.

Revenues from midstream services for the first quarter of 2020 decreased $37.9 million when compared to the first quarter of 2019.

Revenues from our natural gas processing facilities decreased a net $45.3 million quarter-to-quarter primarily due to the impact of lower NGL prices in the first quarter of 2020 compared to the first quarter of 2019 on the value of 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 $41.0 million quarter-to-quarter.

Lastly, revenues from our Mont Belvieu NGL fractionation complex decreased $35.8 million quarter-to-quarter primarily due to lower fractionation fee revenues from third parties.

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.

Revenues from our pipeline assets decreased $71.4 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 $28.8 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.

Revenues from our Midland-to-ECHO 2 pipeline, which commenced limited service in February 2019 and full service in April 2019, increased $ 29.6 million period-to-period.

Revenues from our other pipeline assets decreased $76.5 million period-to-period primarily due to lower demand for crude oil, natural gas and refined products.

Lastly, third party revenues from our Mont Belvieu NGL fractionation complex decreased $ 64.6 million period-to-period primarily due to lower fractionation fees.

Operating costs and expenses

Total operating costs and expenses for the first quarter of 2020 decreased $959.4 million when compared to the first 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 $703.1 million quarter-to-quarter primarily due to lower purchase prices, which accounted for a $488.4 million decrease, and lower sales volumes, which accounted for an additional $214.7 million decrease.

The cost of sales associated with our marketing of NGLs, petrochemicals and refined products decreased a combined net $309.5 million quarter-to-quarter primarily due to lower purchase prices, which accounted for a $1.02 billion decrease, partially offset by higher sales volumes, which accounted for a $706.6 million increase.

Other operating costs and expenses for the first quarter of 2020 increased $24.0 million quarter-to-quarter primarily due to higher employee compensation costs and ad valorem taxes.

Depreciation, amortization and accretion expense increased $31.9 million quarter-to-quarter primarily due to assets placed into full or limited service since the first quarter of 2019 (e.g., the isobutane dehydrogenation (“iBDH”) plant, Mentone and Orla facilities and the Enterprise Navigator ethylene terminal).

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.

Depreciation, amortization and accretion expense increased $63.4 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).

General and administrative costs

General and administrative costs for the first quarter of 2020 increased $ 3.3 million when compared to the first quarter of 2019 primarily due to higher employee compensation costs and professional services expense.

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.

Equity in income of unconsolidated affiliates

Equity income from our unconsolidated affiliates for the first quarter of 2020 decreased $ 13.8 million when compared to the first quarter of 2019 primarily due to decreased earnings from our investments in crude oil pipelines.

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.

Operating income

Operating income for the first quarter of 2020 decreased $ 118.7 million when compared to the first quarter of 2019 due to the previously described quarter-to-quarter changes in revenues, operating costs and expenses, general and administrative costs and equity in income of unconsolidated affiliates.

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.

Interest expense

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For the Three Months

Ended March 31,

Ended June 30,

For the Six Months

Ended June 30,

Interest charged on debt principal outstanding

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Interest costs capitalized in connection with construction projects (2)

Amount presented for the first quarter of 2019 includes a $9.8 million benefit from swaption premiums.

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

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 $ 24.0 million quarter-to-quarter primarily due to increased debt principal amounts outstanding during the first quarter of 2020, which accounted for a $31.2 million increase, partially offset by the effect of lower overall interest rates during the first quarter of 2020, which accounted for a $ 7.2 million decrease.

Our weighted-average debt principal balance for the first quarter of 2020 was $ 29.39 billion compared to $26.76 billion for the first quarter of 2019.

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.

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

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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 $2.3 million and $57.8 million during the first quarters of 2020 and 2019, respectively.

Expense 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 first quarter of 2019 was primarily due to a decrease in the discount factor used in determining the present value of the liability.

We recognized a non-cash benefit from income taxes in the first quarter of 2020 in the amount of $179.2 million primarily due to settlement of the Liquidity Option liability on March 5, 2020, which accounted for $72.2 million of the benefit, and a subsequent decrease in the related deferred income tax amounts through March 31, 2020, which accounted for an additional $115.0 million benefit.

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 mainly comprised the outside basis difference of OTA in the 54,807,352 EPD common units it received in October 2014.

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

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 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 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

Deferred tax benefit (expense) attributable to OTA

Texas Margin Tax

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.

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 three months ended March 31, 2020.

At March 31, 2020, OTA’s deferred tax liability decreased to $324.7 million primarily due to a decline in the fair value of OTA’s assets, which resulted in an additional non-cash benefit of $115.0 million in income tax expense for the first quarter of 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.

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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For the Three Months

Ended March 31,

Ended June 30,

For the Six Months

Ended June 30,

Gross operating margin by segment:

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For the Three Months

Ended March 31,

Ended June 30,

For the Six Months

Ended June 30,

Operating income

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(addition or subtraction indicated by sign):

Depreciation, amortization and accretion expense in operating costs and expenses

Depreciation, amortization and accretion expense in operating costs and

Asset impairment and related charges in operating costs and expenses

Net losses (gains) attributable to asset sales in operating costs and expenses

Net gains attributable to asset sales in operating costs and expenses

General and administrative costs

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

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.

NGL Pipelines & Service s

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For the Three Months

Ended March 31,

Ended June 30,

For the Six Months

Ended June 30,

Segment gross operating margin:

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Represents the NGL volumes we earn and take title to in connection with our processing activities.

Volumes reported correspond to the revenue streams earned by our natural gas processing facilities.

Volumes reported correspond to the revenue streams earned by our natural gas processing plants.

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

For the second, third and fourth quarters of 2019, fee-based natural gas processing volumes measured in this manner were 4,705 MMcf/d, 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.

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

Gross operating margin from natural gas processing and related NGL marketing activities for the first quarter of 2020 decreased $ 40.4 million when compared to the first quarter of 2019.

Gross operating margin from our South Texas natural gas processing facilities decreased $24.8 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for an $18.6 million decrease, and lower average processing fees, which accounted for an additional $5.2 million decrease.

Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased a combined $ 17.9 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $ 21.9 million decrease, partially offset by higher processing and other fees, which accounted for a $5.2 million increase.

On a combined basis, fee-based natural gas processing volumes and equity NGL production volumes decreased 181 MMcf/d and 16 MBPD, respectively, quarter-to-quarter.

Gross operating margin from our Permian Basin natural gas processing facilities decreased $ 14.4 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 higher operating costs, which accounted for an additional $7.6 million decrease, partially offset by higher fee-based natural gas processing volumes, which accounted for an $11.0 million increase.

Fee-based processing volumes at our Permian Basin natural gas processing facilities increased 273 MMcf/d quarter-to-quarter primarily due to processing volumes contributed by the third processing train at our Orla natural gas processing facility and our Mentone natural gas processing facility, which were placed into service in July 2019 and December 2019, respectively.

Gross operating margin from our Louisiana and Mississippi natural gas processing facilities decreased $5.4 million quarter-to-quarter primarily due to lower average processing margins, which accounted for a $7.7 million decrease, and lower processing volumes, which accounted for an additional $1.5 million decrease, partially offset by higher average processing fees, which accounted for a $3.9 million increase.

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 Carthage natural gas processing facilities (Panola and Bulldog) decreased $4.1 million quarter-to-quarter primarily due to lower average processing margins.

Fee-based natural gas processing volumes at these facilities increased 70 MMcf/d.

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 export, storage and plant assets increased a combined $41.5 million quarter-to-quarter, partially offset by lower earnings from the optimization of our transportation assets, which accounted for a $3.4 million decrease.

In addition, results from NGL marketing decreased $12.6 million quarter-to-quarter due to non-cash, mark-to-market losses of $12.2 million in the first quarter of 2020.

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.

NGL pipelines, storage and terminals

Gross operating margin from our NGL pipelines, storage and terminal assets during the first quarter of 2020 increased $96.0 million when compared to the first quarter of 2019.

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.

Gross operating margin from LPG-related activities at EHT increased $15.5 million quarter-to-quarter primarily due to higher export volumes of 99 MBPD.

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

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 $ 3.7 million quarter-to-quarter primarily due to a 29 MBPD increase in transportation volumes.

Gross operating margin from our Shin Oak NGL Pipeline increased $24.7 million quarter-to-quarter primarily due to higher direct tariff transportation volumes, which accounted for a $22.4 million increase.

Net to our interest, direct tariff movements on the Shin Oak NGL Pipeline increased 26 MBPD quarter-to-quarter.

Gross operating margin from our Chaparral NGL Pipeline increased $14.2 million quarter-to-quarter primarily due to higher transportation volumes of 43 MBPD, which accounted for a $9.9 million increase, and higher average transportation fees, which accounted for an additional $2.9 million increase.

Gross operating margin from our Aegis Pipeline increased $19.0 million quarter-to-quarter primarily due to a 154 MBPD increase in transportation volumes.

Gross operating margin from our equity investment in the Front Range Pipeline increased $ 3.9 million quarter-to-quarter primarily due to higher average transportation fees, which accounted for a $2.9 million increase, and higher transportation volumes of 14 MBPD (net to our interest), which accounted for an additional $2.8 million increase.

Gross operating margin from our Morgan’s Point Ethane Export Terminal increased $3.7 million quarter-to-quarter primarily due to lower utility and compensation costs.

Gross operating margin from our Dixie Pipeline and related terminals increased a combined $3.0 million quarter-to-quarter primarily due to higher transportation volumes of 24 MBPD.

Gross operating margin from our Appalachia-to-Texas Express, or “ATEX,” pipeline decreased $10.3 million quarter-to-quarter primarily due to lower transportation volumes, which decreased 32 MBPD quarter-to-quarter.

Gross operating margin from our Mont Belvieu storage facility decreased $7.4 million quarter-to-quarter primarily due to lower handling fee revenues.

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 LPG-related activities at EHT increased $48.6 million period-to-period primarily due to higher export volumes of 151 MBPD.

Gross operating margin from our Houston Ship Channel Pipeline System increased $ 11.8 million period-to-period primarily due to a 118 MBPD increase in transportation volumes.

Gross operating margin from our Aegis Pipeline increased $27.8 million period-to-period primarily due to a 161 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 South Texas NGL Pipeline System decreased $8.9 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 25 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

Gross operating margin from NGL fractionation during the first quarter of 2020 increased $27.2 million when compared to the first quarter of 2019.

Gross operating margin at our Hobbs NGL fractionator increased $ 18.5 million quarter-to-quarter primarily due to lower major maintenance costs, which accounted for a $ 14.4 million increase, and higher fractionation volumes of 18 MBPD, which accounted for an additional $ 3.5 million increase.

The first quarter of 2019 included downtime for major maintenance activities at Hobbs.

Gross operating margin at our Norco NGL fractionator increased $5.3 million quarter-to-quarter primarily due to lower maintenance and other operating costs, which accounted for a $2.5 million increase, and higher fractionation volumes of 13 MBPD, which accounted for an additional $2.0 million increase.

Gross operating margin from our Mont Belvieu NGL fractionation complex was essentially flat quarter-to-quarter primarily due to lower product blending revenues, which accounted for a $7.6 million decrease, being nearly offset by the impact of higher fractionation volumes, which accounted for a $7.4 million increase.

NGL fractionation volumes increased 87 MBPD quarter-to-quarter (net to our interest) in part due to start-up of the first fractionation train at our newly constructed NGL fractionation facility located in Chambers County, Texas (“Frac X”).

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.

NGL fractionation volumes at our Hobbs NGL fractionator increased 11 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.

Crude Oil Pipelines & Services

1 unchanged sentence

For the Three Months

Ended March 31,

Ended June 30,

For the Six Months

Ended June 30,

Segment gross operating margin:

Midland-to-ECHO System:

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

non-cash mark-to-market results

Non-cash mark-to-market gain attributable to the Midland-to-ECHO 1 pipeline

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

excluding associated non-cash mark-to-market results

Non-cash mark-to-market gains

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

5 unchanged sentences

Crude oil marine terminal volumes (MBPD)

Gross operating margin from our Crude Oil Pipelines & Services segment for the first quarter of 2020 decreased $209.4 million when compared to the first quarter of 2019.

Gross operating margin from our Midland-to-ECHO 1 pipeline and related business activities decreased $105.8 million quarter-to-quarter primarily due to lower non-cash mark-to-market earnings, which accounted for a $66.3 million decrease, and lower earnings from related marketing activities, which accounted for an additional $44.9 million decrease.

Gross operating margin from our Midland-to-ECHO 2 pipeline increased $11.9 million primarily due to higher transportation volumes of 64 MBPD, which accounted for a $22.2 million increase, partially offset by higher operating costs of $10.6 million.

Gross operating margin from other crude oil marketing activities decreased $118.0 million quarter-to-quarter primarily due to lower average sales margins, which accounted for a $94.9 million decrease, and lower non-cash mark-to-market earnings, which accounted for an additional $22.8 million decrease.

Gross operating margin from our equity investment in the Seaway Pipeline decreased $16.5 million quarter-to-quarter primarily due to lower average transportation fees, which accounted for a $9.9 million decrease, and lower transportation volumes, which accounted for an additional $8.1 million decrease.

Transportation volumes on the Seaway Pipeline decreased 52 MBPD quarter-to-quarter (net to our interest).

Gross operating margin from our South Texas Crude Oil Pipeline System decreased $9.5 million quarter-to-quarter primarily due to lower deficiency fees in the first quarter of 2020.

Transportation volumes on the South Texas Crude Oil Pipeline System increased 10 MBPD quarter-to-quarter.

Gross operating margin from our West Texas System increased $13.4 million quarter-to-quarter primarily due to higher transportation volumes of 74 MBPD.

Lastly, gross operating margin from crude oil activities at EHT increased $15.4 million quarter-to-quarter primarily due to higher net export volumes of 64 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.

Gross operating margin from our equity investment in the Eagle Ford Crude Oil Pipeline decreased $12.1 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.

On an aggregate basis, transportation volumes on these three pipeline systems decreased 225 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.

Natural Gas Pipelines & Services

1 unchanged sentence

For the Three Months

Ended March 31,

Ended June 30,

For the Six Months

Ended June 30,

Segment gross operating margin

1 unchanged sentence

Natural gas pipeline transportation volumes (BBtus/d)

Gross operating margin from our Natural Gas Pipelines & Services segment for the first quarter of 2020 increased $19.5 million when compared to the first quarter of 2019.

Gross operating margin from our natural gas marketing activities increased $31.6 million quarter-to-quarter primarily due to higher non-cash mark-to-market earnings.

Gross operating margin from our Permian Basin Gathering System increased $10.9 million quarter-to-quarter primarily due to higher condensate sales, which accounted for a $7.2 million increase, and a 306 BBtus/d increase in natural gas volumes, which accounted for an additional $5.5 million increase.

Gross operating margin from our Haynesville Gathering System decreased $13.2 million quarter-to-quarter primarily due to lower gathering, compression and other fee revenues, which accounted for a $10.0 million decrease, and lower gathering volumes of 245 BBtus/d, which accounted for an additional $3.9 million decrease.

Gross operating margin from our Texas Intrastate System decreased $8.8 million quarter-to-quarter primarily due to lower capacity reservation fees.

Transportation volumes on our Texas Intrastate System increased 31 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.

Transportation volumes on our Acadian Gas System decreased 163 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 Texas Intrastate System decreased $43.5 million period-to-period primarily due to lower capacity reservation revenues.

Transportation volumes on our Texas Intrastate System decreased 281 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.

Transportation volumes on our Acadian Gas System decreased 94 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 Permian Basin Gathering System increased $13.7 million period-to-period primarily due to a 290 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

1 unchanged sentence

For the Three Months

Ended March 31,

Ended June 30,

For the Six Months

Ended June 30,

Segment gross operating margin:

9 unchanged sentences

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

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

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

Pipeline transportation volumes, primarily refined products &

petrochemicals (MBPD)

Marine terminal volumes, primarily refined products and

petrochemicals (MBPD)

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

Propylene production and related activities

Gross operating margin from propylene production and related activities for the first quarter of 2020 increased $6.3 million when compared to the first quarter of 2019.

Gross operating margin from our initial propane dehydrogenation (“ PDH 1”) facility increased $12.2 million quarter-to-quarter primarily due to higher propylene and associated by-product sales volumes.

Plant production for PDH 1, which includes by-products, increased 5 MBPD quarter-to-quarter.

Gross operating margin from our Mont Belvieu propylene splitters decreased $3.6 million quarter-to-quarter primarily due to higher major maintenance costs incurred during the first quarter of 2020.

Propylene production volumes from our splitter units increased 3 MBPD (net to our interest).

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).

Isomerization and related operations

Gross operating margin from isomerization and related operations decreased $7.9 million quarter-to-quarter primarily due to lower average by-product sales prices.

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.

Octane enhancement and related plant operations

Gross operating margin from our octane enhancement and related plant operations, which includes our recently completed iBDH facility, increased $44.7 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $26.0 million increase, and higher average sales margins, which accounted for an additional $24.1 million increase, partially offset by higher operating expenses, which accounted for a $6.5 million decrease.

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.

Refined products pipelines and related activities

Gross operating margin from refined products pipelines and related activities during the first quarter of 2020 decreased $6.8 million when compared to the first quarter of 2019 primarily due to lower storage revenues from our refined products terminal in Beaumont, Texas.

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.

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

Marine transportation and other services

Gross operating margin from marine transportation and other services during the first quarter of 2020 decreased $0.4 million when compared to the first quarter of 2019.

Gross operating margin from our marine transportation business increased $2.1 million quarter-to-quarter primarily due to higher day rates.

Gross operating margin from our ethylene export terminal and related operations was a $2.7 million loss in the first quarter of 2020 due to operating expenses incurred for the start-up of our ethylene export terminal, which was placed into limited service in December 2019.

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.

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.

At March 31, 2020, we had $7.0 billion of consolidated liquidity, which was comprised of $5.0 billion of available borrowing capacity under EPO’s revolving credit facilities and $2.0 b illion of unrestricted cash on hand.

On April 3, 2020, our liquidity position was enhanced when EPO entered into its April 2020 364-Day Credit Agreement, which provides EPO with an incremental $1.0 billion of borrowing capacity (see “ Other Recent Developments ” within this Item 2).

EPO’s aggregate borrowing capacity under its revolving credit facilities, including that of the April 2020 364-Day Credit Agreement, is now $6.0 billion.

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.

Common Unit Buyback Program

EPD repurchased 6,357,739 common units under its 2019 Buyback Program through open market purchases in the first quarter of 2020.

The total purchase price of these repurchases (including commissions and fees) was $140.1 million, and represented 1.9 % of our consolidated CFFO for the twelve months ended March 31, 2020 .

The repurchased units were cancelled immediately upon acquisition.

As of March 31, 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 first quarter of 2020.

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

Consolidated Debt

The following table presents scheduled maturities of our consolidated debt obligations outstanding at March 31, 2020 for the years indicated (dollars in millions):

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):

Scheduled Maturities of Debt

Principal amount of senior and junior debt obligations

At March 31, 2020, there were no borrowings outstanding under EPO’s revolving credit facilities.

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

The net proceeds from this debt offering were used (i) to repay $500 million principal amount of senior notes maturing in January 2020, (ii) for the temporary repayment of amounts outstanding under EPO’s commercial paper program and (iii) for general company purposes.

In addition, net proceeds from the January 2020 senior notes offering will be used for the repayment of $1.0 billion principal amount of senior notes maturing in September 2020.

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

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.

Credit Ratings

As of May 8, 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 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.

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

In February 2020, a total of 1,422,063 common units were purchased on the open market and delivered to participants in connection with the DRIP and EUPP.

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 May 12, 2020.

EPD issued and delivered a combined 1,516,779 common units in the first quarter of 2019 in connection with the DRIP and EUPP, which generated net cash proceeds totaling $42.7 million.

Cash Distributions

The quarterly distribution associated with the first quarter of 2020 is payable on May 12, 2020, to unitholders of record as of the close of business on April 30, 2020.

This distribution represents a 1.7% increase over the distribution declared with respect to the first quarter of 2019.

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

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.

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 Three Months

Ended March 31,

For the Six Months

Ended June 30,

Net cash flows provided by operating activities

Cash used in investing activities

Cash provided by (used in) financing activities

Cash used in financing activities

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

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

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

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

Operating activities

Net cash flows provided by operating activities for the first quarter of 2020 increased a net $ 851.8 million when compared to the first quarter of 2019 primarily due to:

a $901.5 million quarter-to-quarter increase primarily due to the timing of cash receipts and payments related to operations;

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 $37.6 m illion quarter-to-quarter decrease resulting from lower partnership earnings in the first quarter of 2020 when compared to the first quarter of 2019 (determined by adjusting our $94.6 million quarter-to-quarter increase in net income for changes in the non-cash items identified on our Unaudited Condensed Statements of Consolidated Cash Flows).

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

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.

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 first quarter of 2020 decreased a net $ 102.8 m illion when compared to the first quarter of 2019 primarily due to:

a $69.4 million quarter-to-quarter decrease in expenditures for consolidated property, plant and equipment (see “ Capital Investments ” within this Part I, Item 2 for additional information);

a $25.8 million quarter-to-quarter decrease in investments in unconsolidated affiliates primarily related to NGL and crude oil pipeline projects.

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.

Financing activities

Cash provided by financing activities for the first quarter of 2020 was $765.1 million compared to cash used in financing activities of $ 288.5 m illion in the first quarter of 2019.

The $1.05 billion quarter-to-quarter change in cash flow from financing activities was primarily due to:

a net $1.25 billion quarter-to-quarter increase in net cash inflows attributable to debt.

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

During the first quarter of 2019, we repaid $700 million principal amount of senior notes.

In addition, net repayments of short term notes under EPO’s commercial paper program were $481.7 million in the first quarter of 2020 compared to net issuances of $1.39 billion in first quarter of 2019 ;

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 $ 88.5 million quarter-to-quarter increase in cash used to acquire common units under our 2019 Buyback Program;

a $ 42.7 million quarter-to-quarter decrease in net cash proceeds from the issuance of common units in connection with the DRIP and EUPP.

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;

a $ 29.6 million quarter-to-quarter decrease in cash contributions from noncontrolling interests.

C ash contributions from noncontrolling interests in connection with the construction of our ethylene export facility decreased $ 31.5 million quarter-to-quarter;

a $ 23.8 million quarter-to-quarter increase in cash distributions paid to limited partners primarily due to an increase in the quarterly cash distribution rate per unit.

a $ 79.9 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 ;

a $ 59.0 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.

Non-GAAP Cash Flow Measures

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For the Three Months

Ended March 31,

Ended June 30,

For the Six Months

Ended June 30,

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

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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

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

Proceeds from asset sales

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For the Three Months

Ended March 31,

Ended June 30,

For the Six Months

Ended June 30,

Net cash flows provided by operating activities (GAAP)

Adjustments to reconcile net cash flows provided by operating activities to DCF

(addition or subtraction indicated by sign):

Adjustments to reconcile net cash flows provided by operating activities to DCF (addition or subtraction indicated by sign):

Net effect of changes in operating accounts

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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 March 31, 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 June 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 March 31,

Ended June 30,

For the Six Months

Ended June 30,

For the Twelve Months Ended

Net cash flows provided by operating activities (GAAP)

Adjustments to net cash flows provided by operating activities to

derive FCF (addition or subtraction indicated by sign):

Adjustments to net cash flows provided by operating activities to derive FCF (addition or subtraction indicated by sign):

Cash used in investing activities

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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 (previously $3.4 billion to $4.4 billion), which reflects growth capital investments of $2.5 billion to $3.0 billion (previously $3.0 billion to $4.0 billion) and approximately $300 million for sustaining capital expenditures (previously $400 million).

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.

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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 the first quarter of 2020.

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

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

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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);

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

an eighth deep-water ship dock at EHT for loading crude oil (fourth quarter of 2021);

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).

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

For the Three Months

Ended March 31,

For the Six Months

Ended June 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 Three Months Ended March 31, 2020 with Three Months Ended March 31, 2019

Fluctuations in investments attributable to our growth capital projects and those of our unconsolidated affiliates are explained in large part by increases or decreases in the funding of announced major expansion projects.

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

In total, investments in growth capital projects decreased $70.9 million quarter-to-quarter primarily due to the following (all of which occurred since the first quarter of 2019):

completion of the Shin Oak NGL Pipeline, which accounted for a $154.8 million decrease;

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

In total, investments in growth capital projects decreased $286.4 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.

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

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;

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 natural gas pipelines and related infrastructure in support of East Texas and Louisiana production, which accounted for a $71.4 million increase.

higher investments in propylene production, NGL fractionation and other related plant assets and infrastructure at our Mont Belvieu complex, which accounted for a combined $42.3 million increase.

Investments in our unconsolidated affiliates decreased $25.8 million quarter-to-quarter primarily due to lower spending on our Texas Express Pipeline expansion project, which accounted for a $10.5 million decrease, and lower spending on our joint venture dock infrastructure at Corpus Christi, which accounted for an additional $8.2 million decrease.

Investments in unconsolidated affiliates decreased $52.6 million period-to-period primarily due to lower spending on joint venture dock infrastructure at Corpus Christi and other crude oil-related projects, which accounted for a $27.3 million decrease, and NGL pipeline expansion projects, which accounted for an additional $25.8 million decrease.

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

Critical Accounting Policies and Estimates

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

Our product purchase commitments at March 31, 2020 declined by an estimated $10.45 billion when compared to those reported in our 2019 Form 10-K primarily due to lower NGL and crude oil prices in the first quarter of 2020.

The principal amount of our consolidated debt obligations were $29.90 billion at March 31, 2020 compared to $27.88 billion at December 31, 2019.

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.

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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