ENTERPRISE PRODUCTS PARTNERS L.P. 10-Q

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. 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. Securities and Exchange Commission (“SEC”). Our financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the United States (“U.S.”). Key References Used in this Management’s Discussion and Analysis Unless the context requires otherwise, references to “we,” “us,” “our” or “Enterprise” are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries. References to “EPD” or the “Partnership” mean Enterprise Products Partners L.P. on a standalone basis. References to “EPO” mean Enterprise Products Operating LLC, which is an indirect wholly owned subsidiary of EPD, and its consolidated subsidiaries, through which EPD conducts its business. Enterprise is managed by its general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company. The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Directors (the “Board”) of Enterprise GP; (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board of Enterprise GP; and (iii) Dr. Ralph S. Cunningham, who is also an advisory director of Enterprise GP. Ms. Duncan Williams and Mr. Bachmann also currently serve as managers of Dan Duncan LLC along with W. Randall Fowler, who is also a director and the Co-Chief Executive Officer and Chief Financial Officer of Enterprise GP. References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates. A majority of the outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are: (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Dr. Cunningham, who serves as Vice Chairman of EPCO; and (iii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO. Ms. Duncan Williams and Mr. Bachmann also currently serve as directors of EPCO along with Mr. Fowler, who is also the Executive Vice President and Chief Financial Officer of EPCO. EPCO, together with its privately held affiliates, owned approximately 32.1% 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: /d = per day MMBbls = million barrels BBtus = billion British thermal units MMBPD = million barrels per day Bcf = billion cubic feet MMBtus = million British thermal units BPD = barrels per day MMcf = million cubic feet MBPD = thousand barrels per day TBtus = trillion British thermal units As used in this quarterly report, the phrase “quarter-to-quarter” means the second quarter of 2020 compared to the second quarter of 2019. Likewise, the phrase “period-to-period” means the six months ended June 30, 2020 compared to the six months ended June 30, 2019. 48 Table of Contents CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION This quarterly report on Form 10-Q contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements. Although we and our general partner believe that our expectations reflected in such forward-looking statements (including the forward-looking statements/expectations of third parties referenced in this quarterly report) are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions as described in more detail under Part I, Item 1A of our 2019 Form 10-K and within Part II, Item 1A of this quarterly report. These risks include recent impacts of the coronavirus disease 2019 (“COVID-19”) and decreases in certain commodity prices resulting from demand weakness and oversupply, which are discussed in Part II, Item 1A “Risk Factors” of this quarterly report, and this Part I, Item 2. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements. The forward-looking statements in this quarterly report speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason. Overview of Business We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products. Our integrated midstream energy asset network links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the U.S., Canada and the Gulf of Mexico with domestic consumers and international markets. Our midstream energy operations currently include: natural gas gathering, treating, processing, transportation and storage; NGL transportation, fractionation, storage, and export and import terminals (including those used to export liquefied petroleum gases, or “LPG,” and ethane); crude oil gathering, transportation, storage, and export and import terminals; petrochemical and refined products transportation, storage, export and import terminals, and related services; and a marine transportation business that operates primarily on the U.S. inland and Intracoastal Waterway systems. Our assets currently include approximately 50,000 miles of pipelines; 260 MMBbls of storage capacity for NGLs, crude oil, petrochemicals and refined products; and 14 Bcf of natural gas storage capacity. We conduct substantially all of our business through EPO and are owned 100% by EPD’s limited partners from an economic perspective. Enterprise GP manages our partnership and owns a non-economic general partner interest in us. We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees. Like many publicly traded partnerships, we have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers. Our operations are reported under four business segments: (i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services, and (iv) Petrochemical & Refined Products Services. Our business segments are generally organized and managed according to the types of services rendered (or technologies employed) and products produced and/or sold. Each of our business segments benefits from the supporting role of our related marketing activities. The main purpose of our marketing activities is to support the utilization and expansion of assets across our midstream energy asset network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment. In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of gross operating margin, a non-generally accepted accounting principle (“non-GAAP”) financial measure, for the partnership. The financial results of our marketing efforts fluctuate due to changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for the products bought and sold. 49 Table of Contents We provide investors access to additional information regarding our partnership, including information relating to our governance procedures and principles, through our website, www.enterpriseproducts.com . Update on 2020 Outlook As noted previously, this quarterly report on Form 10-Q, including this update to our 2020 Outlook, contains forward-looking statements that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us, which includes forecast information published by third parties. See “Cautionary Statement Regarding Forward-Looking Information” within this Part I, Item 2 and “Risk Factors” in Part II, Item 1A, for additional information. The following update to our 2020 Outlook replaces the general outlook provided in our 2019 Form 10-K under Part II, Item 7 and presents our current views on key midstream energy supply and demand fundamentals. The third-party supply and demand forecasts cited in the following analysis, including our internal forecasts based on such information, remain subject to heightened levels of uncertainty because mitigation and reopening efforts related to COVID-19 continue to evolve. The emergence of COVID-19 as a global pandemic in the first quarter of 2020 and the consequences of international COVID-19 containment measures (and the resulting near-term decline in end-user demand for hydrocarbons) have adversely impacted the global economy in general and the energy industry in particular. In addition, disputes between members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (collectively, the “OPEC+” group) in March and April 2020 over crude oil production levels, resulted in major disruptions to global energy markets. Although the OPEC+ group and other producers subsequently reached agreements to reduce the oversupply of crude oil in the near-term caused by demand destruction attributable to COVID-19, the downturn in the energy industry has negatively impacted us, the producers we work with and our other customers to varying degrees. 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. 50 Table of Contents 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. 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. The U.S. 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. 51 Table of Contents 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 during 2020. In addition to reductions made in our capital spending program, we continue to discuss project commitments with customers and joint venture opportunities with strategic partners to optimize our use of available capital. These efforts, which have been slowed in the second quarter of 2020 due to impacts of the pandemic, could further reduce our planned growth capital investments for 2020, 2021 and 2022. We continue to optimize our assets during this difficult period to provide incremental services to customers and to respond to market opportunities; however, as expected w e experienced a reduction in volumes on a number of our assets during the second quarter of 2020 due to reduced upstream drilling activity and lower downstream refinery activity and demand for transportation fuels. Furthermore, we may continue to experience throughput declines in the second half of 2020 on our gathering systems, long-haul liquids and natural gas pipelines and at our terminal, fractionation and other facilities until the pandemic ends and economic activity is fully restored. To the extent that we have firm transportation agreements (e.g., ship-or-pay arrangements) and the shipper/customer has sufficient liquidity to satisfy its contractual commitments, we expect the near-term impacts to be manageable. Our business is predominately fee-based (approximately 86% of gross operating margin in 2019), with a substantial portion backed by take-or-pay arrangements. The reduction in upstream production activity and international demand is negatively impacting the export of crude oil and basic petrochemicals from our marine terminals; however, LPG export demand has remained resilient. As prices for certain NGLs, crude oil and refined products fell precipitously during the second quarter of 2020 due to collapsing demand for refined products as a result of the pandemic, our storage services provided valuable flexibility for our customers. During the second quarter of 2020, we were also able to benefit by using uncontracted storage capacity to capture contango opportunities in NGLs, crude oil and refined products and will continue to see this benefit for the remainder of 2020. Across all of our assets, we have contracted with a large number of quality customers in order to achieve customer diversification. In 2019, our top 200 largest customers represented 96% of consolidated revenues. Based on their respective year-end 2019 debt ratings, 81% of our top 200 customers were either investment grade rated or backed by letters of credit. Additionally, only 6% of our top 200 customer revenues were attributable to sub-investment grade or non-rated upstream producers. Given the current market environment, the rating agencies have taken numerous rating actions, including downgrades, across the energy industry. After adjusting for all ratings actions through April 23, 2020, we estimate that 78% of our top 200 customers remain investment grade rated or are backed by letters of credit. In light of current events, we are closely monitoring the recoverability of our long-lived assets, equity method investments, intangible assets and goodwill carrying values for potential impairment. We did not recognize any significant non-cash asset impairment charges during the first six months of 2020. However, if the impacts from the outbreak of COVID-19 and adverse developments in the global energy markets persist for significantly longer periods than currently expected, these events could result in asset impairment charges in the future. Other Recent Developments Issuance of Senior Notes in January 2020 and August 2020 In January 2020, EPO issued $3.0 billion aggregate principal amount of senior notes comprised of (i) $1.0 billion principal amount of senior notes due January 2030 (“Senior Notes AAA”), (ii) $1.0 billion principal amount of senior notes due January 2051 (“Senior Notes BBB”) and (iii) $1.0 billion principal amount of senior notes due January 2060 (“Senior Notes CCC”). Net proceeds from this offering were used by EPO for the repayment of $500 million principal amount of its Senior Notes Q that matured in January 2020, temporary repayment of amounts outstanding under its commercial paper program and for general company purposes. In addition, net proceeds from this offering will be used by EPO for the repayment of $1.0 billion principal amount of its Senior Notes Y upon their maturity in September 2020. 52 Table of Contents 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. 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. 53 Table of Contents Enterprise Enters Into April 2020 364-Day Revolving Credit Agreement In April 2020, EPO entered into an additional 364-day revolving credit agreement (the “April 2020 364-Day Revolving Credit Agreement ”). The new agreement provides EPO with an incremental $1.0 billion of borrowing capacity, thereby increasing its overall borrowing capacity under its revolving credit agreements to $6.0 billion. The April 2020 364-Day Revolving Credit Agreement enhances our financial flexibility during the economic downturn caused by the COVID-19 pandemic. Under the terms of the April 2020 364-Day Revolving Credit Agreement, EPO may borrow up to $1.0 billion at a variable interest rate for a term of 364 days, subject to the terms and conditions set forth therein. EPO may use proceeds from borrowings under the April 2020 364-Day Revolving Credit Agreement for working capital, capital expenditures, acquisitions and other company purposes. Settlement of Liquidity Option On February 25, 2020, the Partnership received notice from Marquard & Bahls AG (“M&B”) of its election to exercise its rights (the “Liquidity Option”) under the Liquidity Option Agreement among EPD, OTA Holdings, Inc., a Delaware corporation previously named Oiltanking Holding Americas, Inc. (“OTA”) and M&B dated October 1, 2014 (the “Liquidity Option Agreement”). On March 5, 2020, we settled our obligations under the Liquidity Option Agreement by issuing 54,807,352 new EPD common units to Skyline North Americas, Inc. (“Skyline,” an affiliate of M&B) in exchange for the capital stock of OTA. Upon settlement of the Liquidity Option, we indirectly acquired the 54,807,352 EPD common units owned by OTA (which were issued to OTA in October 2014) and assumed all future income tax obligations of OTA, including its deferred tax liability. At March 5, 2020, OTA’s assets and liabilities consisted primarily of the EPD common units it owned and the related deferred tax liability, respectively. At March 5, 2020, our accrual for the Liquidity Option liability was $511.9 million. The Liquidity Option liability, at any measurement date, represents the present value of estimated federal and state income taxes that we believe a market participant would incur due to ownership of OTA, including its deferred income tax liabilities. OTA’s deferred tax liability at March 5, 2020 was $439.7 million. The market value of the new EPD common units issued to Skyline was $1.30 billion based on a closing price of $23.67 per unit on March 5, 2020. The 54,807,352 new EPD common units issued to Skyline upon settlement of the Liquidity Option constitute “restricted securities” in the meaning of Rule 144 under the Securities Act of 1933, as amended (the “Securities Act”) and may not be resold except pursuant to an effective registration statement or an available exemption under the Securities Act. In connection with the settlement of the Liquidity Option, Enterprise entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with Skyline. Pursuant to the Registration Rights Agreement, Skyline has the right to request that we prepare and file a registration statement to permit and otherwise facilitate the public resale of all or a portion of such EPD common units that Skyline and its affiliates then own. Our obligation to Skyline to effect such transactions is limited to five registration statements and underwritten offerings. In May 2020, we filed a registration statement on behalf of Skyline for the resale of up to 54,807,352 EPD common units. This registration statement is effective and, in June 2020, we filed a prospectus supplement to this registration statement that allows Skyline to sell up to $500 million of the EPD common units it owns in connection with an “at-the-market” program that it administers. We will not receive any proceeds from such offerings. As a result of the Liquidity Option settlement, the partners’ equity balance for common units (as presented on our Unaudited Condensed Consolidated Balance Sheet) increased by the $1.30 billion market value of the new EPD common units issued to Skyline. Since OTA does not meet the definition of a business as described in ASC 805, Business Combinations , t he acquisition of OTA was accounted for as the purchase of treasury units and assumption of the related deferred tax liability. In consolidation, we present the 54,807,352 EPD common units owned by OTA as treasury units, with their historical cost based on the $1.30 billion market value of the 54,807,352 new EPD common units issued to Skyline. For information regarding the impact of the settlement on our earnings for the six months ended June 30, 2020, see “ Income Statement Highlights – Income Taxes ” within this Item 2. 54 Table of Contents Selected Energy Commodity Price Data The following table presents selected average index prices for natural gas and selected NGL and petrochemical products for the periods indicated: Polymer Refinery Indicative Gas Natural Normal Natural Grade Grade Processing Gas, Ethane, Propane, Butane, Isobutane, Gasoline, Propylene, Propylene, Gross Spread $/MMBtu $/gallon $/gallon $/gallon $/gallon $/gallon $/pound $/pound $/gallon (1) (2) (2) (2) (2) (2) (3) (3) (4) 2019 by quarter: 1st Quarter $3.15 $0.30 $0.67 $0.82 $0.85 $1.16 $0.38 $0.24 $0.31 2nd Quarter $2.64 $0.21 $0.55 $0.63 $0.65 $1.21 $0.37 $0.24 $0.25 3rd Quarter $2.23 $0.17 $0.44 $0.51 $0.66 $1.06 $0.38 $0.23 $0.21 4th Quarter $2.50 $0.19 $0.50 $0.68 $0.82 $1.20 $0.35 $0.21 $0.25 2019 Averages $2.63 $0.22 $0.54 $0.66 $0.75 $1.16 $0.37 $0.23 $0.26 2020 by quarter: 1st Quarter $1.95 $0.14 $0.37 $0.57 $0.63 $0.93 $0.31 $0.18 $0.19 2nd Quarter $1.71 $0.19 $0.41 $0.43 $0.44 $0.41 $0.26 $0.11 $0.17 2020 Averages $1.83 $0.17 $0.39 $0.50 $0.54 $0.67 $0.29 $0.15 $0.18 (1) 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. (2) NGL prices for ethane, propane, normal butane, isobutane and natural gasoline are based on Mont Belvieu Non-TET commercial index prices as reported by Oil Price Information Service. (3) Polymer grade propylene prices represent average contract pricing for such product as reported by IHS Chemical, a division of IHS Inc. (“IHS Chemical”). Refinery grade propylene prices represent weighted-average spot prices for such product as reported by IHS Chemical. (4) The “Indicative Gas Processing Gross Spread” represents a generic estimate of the gross economic benefit from extracting NGLs from natural gas production based on certain pricing assumptions. Specifically, it is the amount by which the assumed economic value of a composite gallon of NGLs at Mont Belvieu, Texas exceeds the value of the equivalent amount of energy in natural gas at Henry Hub, Louisiana (as presented in the table above). The indicative spread does not consider the operating costs incurred by a natural gas processing facility to extract the NGLs nor the transportation and fractionation costs to deliver the NGLs to market. In addition, the actual gas processing spread earned at each plant is determined by regional pricing and extraction dynamics. As presented in the table above, the indicative spread assumes that a gallon of NGLs is comprised of 47% ethane, 28% propane, 9% normal butane, 6% isobutane and 10% natural gasoline. The value of an equivalent amount of energy in natural gas to one gallon of NGLs is assumed to be 8.4% of the price of a MMBtu of natural gas at Henry Hub. The weighted-average indicative market price for NGLs was $ 0.31 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: WTI Midland Houston LLS Crude Oil, Crude Oil, Crude Oil Crude Oil, $/barrel $/barrel $/barrel $/barrel (1) (2) (2) (3) 2019 by quarter: 1st Quarter $54.90 $53.70 $61.19 $62.35 2nd Quarter $59.81 $57.62 $66.47 $67.07 3rd Quarter $56.45 $56.12 $59.75 $60.64 4th Quarter $56.96 $57.80 $60.04 $60.76 2019 Averages $57.03 $56.31 $61.86 $62.71 2020 by quarter: 1st Quarter $46.17 $45.51 $47.81 $48.15 2nd Quarter $27.85 $28.22 $29.68 $30.12 2020 Averages $37.01 $36.87 $38.75 $39.14 (1) WTI prices are based on commercial index prices at Cushing, Oklahoma as measured by the NYMEX. (2) Midland and Houston crude oil prices are based on commercial index prices as reported by Argus. (3) Light Louisiana Sweet (“LLS”) prices are based on commercial index prices as reported by Platts. 55 Table of Contents The decline in commodity prices since the beginning of 2020 is attributable to the ongoing effects of the COVID-19 pandemic and, with respect to crude oil, the recent oil price dispute between Saudi Arabia and Russia. See “ Update on 2020 Outlook ” within this Item 2 for information regarding these events. Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices. A decrease in our consolidated marketing revenues due to lower energy commodity sales prices may not result in a decrease in gross operating margin or cash available for distribution, since our consolidated cost of sales amounts would also decrease due to comparable decreases in the purchase prices of the underlying energy commodities. The same type of correlation would be true in the case of higher energy commodity sales prices and purchase costs. We attempt to mitigate commodity price exposure through our hedging activities and the use of fee-based arrangements. See Note 14 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for information regarding our commodity hedging activities. Income Statement Highlights The following table summarizes the key components of our consolidated results of operations for the periods indicated (dollars in millions): For the Three Months Ended June 30, For the Six Months Ended June 30, 2020 2019 2020 2019 Revenues $ 5,751.0 $ 8,276.3 $ 13,233.5 $ 16,819.8 Costs and expenses: Operating costs and expenses: Cost of sales 3,195.2 5,609.4 8,018.2 11,445.0 Other operating costs and expenses 670.7 723.8 1,423.5 1,452.6 Depreciation, amortization and accretion expenses 494.3 462.8 977.1 913.7 Net gains attributable to asset sales (1.6 ) (2.1 ) (1.5 ) (2.5 ) Asset impairment and related charges 11.8 7.0 13.4 11.8 Total operating costs and expenses 4,370.4 6,800.9 10,430.7 13,820.6 General and administrative costs 57.0 52.5 112.5 104.7 Total costs and expenses 4,427.4 6,853.4 10,543.2 13,925.3 Equity in income of unconsolidated affiliates 113.3 137.4 254.1 292.0 Operating income 1,436.9 1,560.3 2,944.4 3,186.5 Interest expense (320.2 ) (290.1 ) (637.7 ) (567.3 ) Change in fair value of Liquidity Option – (26.6 ) (2.3 ) (84.4 ) Other, net 3.8 2.6 11.9 4.1 Benefit from (provision for) income taxes (59.7 ) (9.7 ) 119.5 (22.0 ) Net income 1,060.8 1,236.5 2,435.8 2,516.9 Net income attributable to noncontrolling interests (26.1 ) (21.8 ) (51.0 ) (41.7 ) Net income attributable to limited partners $ 1,034.7 $ 1,214.7 $ 2,384.8 $ 2,475.2 56 Table of Contents Revenues The following table presents each business segment’s contribution to consolidated revenues for the periods indicated (dollars in millions): For the Three Months Ended June 30, For the Six Months Ended June 30, 2020 2019 2020 2019 NGL Pipelines & Services: Sales of NGLs and related products $ 1,934.1 $ 2,659.4 $ 4,353.3 $ 5,330.6 Midstream services 542.2 625.3 1,091.1 1,268.5 Total 2,476.3 3,284.7 5,444.4 6,599.1 Crude Oil Pipelines & Services: Sales of crude oil 1,146.7 2,531.7 2,843.6 4,860.1 Midstream services 316.5 334.9 658.5 613.8 Total 1,463.2 2,866.6 3,502.1 5,473.9 Natural Gas Pipelines & Services: Sales of natural gas 347.7 531.4 746.9 1,187.1 Midstream services 237.5 287.9 508.9 559.7 Total 585.2 819.3 1,255.8 1,746.8 Petrochemical & Refined Products Services: Sales of petrochemicals and refined products 1,030.0 1,087.7 2,627.5 2,568.3 Midstream services 196.3 218.0 403.7 431.7 Total 1,226.3 1,305.7 3,031.2 3,000.0 Total consolidated revenues $ 5,751.0 $ 8,276.3 $ 13,233.5 $ 16,819.8 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. 57 Table of Contents 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 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 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. 58 Table of Contents Equity in income of unconsolidated affiliates Equity income from our unconsolidated affiliates for the three and six months ended June 30, 2020 decreased $ 24.1 million and $ 37.9 million, respectively, when compared to the same periods in 2019 primarily due to decreased earnings from our investments in crude oil pipelines. Operating income Operating income for the three and six months ended June 30, 2020 decreased $ 123.4 million and $ 242.1 m illion, respectively, when compared to the same periods in 2019 due to the previously described quarter-to-quarter and period-to-period changes in revenues, operating costs and expenses, general and administrative costs and equity in income of unconsolidated affiliates. Interest expense The following table presents the components of our consolidated interest expense for the periods indicated (dollars in millions): For the Three Months Ended June 30, For the Six Months Ended June 30, 2020 2019 2020 2019 Interest charged on debt principal outstanding $ 334.0 $ 307.4 $ 665.5 $ 614.9 Impact of interest rate hedging program, including related amortization (1) 9.7 8.7 19.3 7.6 Interest costs capitalized in connection with construction projects (2) (31.9 ) (32.8 ) (62.4 ) (69.0 ) Other (3) 8.4 6.8 15.3 13.8 Total $ 320.2 $ 290.1 $ 637.7 $ 567.3 (1) Amount presented for the six months ended June 30, 2019 includes $ 9.8 million of swaption premium income. (2) We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. Capitalized interest amounts become part of the historical cost of an asset and are charged to earnings (as a component of depreciation expense) on a straight-line basis over the estimated useful life of the asset once the asset enters its intended service. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise. Capitalized interest amounts fluctuate based on the timing of when projects are placed into service, our capital investment levels and the interest rates charged on borrowings. (3) Primarily reflects facility commitment fees charged in connection with our revolving credit facilities and amortization of debt issuance costs. Interest charged on debt principal outstanding, which is a key driver of interest expense, increased a net $26.6 million quarter-to-quarter primarily due to increased debt principal amounts outstanding during the second quarter of 2020, which accounted for a $31.0 million increase, partially offset by the effect of lower overall interest rates during the second quarter of 2020, which accounted for a $4.4 million decrease. Our weighted-average debt principal balance for the second quarter of 2020 was $29.9 billion compared to $ 27.1 billion for the second quarter of 2019. For the six months ended June 30, 2020, interest charged on debt principal outstanding increased a net $ 50.6 million period-to-period primarily due to increased debt principal amounts outstanding during the six months ended June 30, 2020, which accounted for a $ 62.2 million increase, partially offset by the effect of lower overall interest rates during the six months ended June 30, 2020, which accounted for an $ 11.6 million decrease. Our weighted-average debt principal balance for the six months ended June 30, 2020 was $ 29.61 billion compared to $ 26.9 billion for the six months ended June 30, 2019. In general, our debt principal balances have increased over time due to the partial debt financing of our capital investments. For additional information regarding our debt obligations, see Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report. For a discussion of our capital projects, see “ Capital Investments ” within this Part I, Item 2. Change in fair value of Liquidity Option For the period in which the Liquidity Option was outstanding, we recognized non-cash expense in connection with accretion and changes in management estimates that affected the valuation of the Liquidity Option liability. As discussed in the following section, Income taxes , our obligations under the Liquidity Option Agreement were settled on March 5, 2020. 59 Table of Contents 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. Income taxes 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, 2020 2019 2020 2019 Settlement of Liquidity Option at March 5, 2020 $ 72.2 Deferred tax benefit (expense) attributable to OTA $ (50.5 ) 64.5 Texas Margin Tax (7.0 ) $ (10.1 ) (14.7 ) $ (21.0 ) Other (2.2 ) 0.4 (2.5 ) (1.0 ) Benefit from (provision for) income taxes $ (59.7 ) $ (9.7 ) $ 119.5 $ (22.0 ) 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 six months ended June 30, 2020. The deferred tax liability of OTA is subject to fluctuation due to changes in the market value of the EPD common units it owns relative to its underlying tax basis in the units. With respect to the second quarter of 2020, OTA recognized deferred income tax expense of $50.5 million primarily due to an increase in the market value of its investment in EPD common units since March 31, 2020. At June 30, 2020, the deferred tax liability of OTA was $375.2 million. OTA recognized a deferred income tax benefit of $64.5 million through June 30, 2020 primarily due to a decrease in the market value of its investment in EPD common units since March 5, 2020. In total, earnings for the six months ended June 30, 2020 reflect a net $136.7 million of deferred income tax benefit attributable to OTA. 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. Business Segment Highlights We evaluate segment performance based on our financial measure of gross operating margin. Gross operating margin is an important performance measure of the core profitability of our operations and forms the basis of our internal financial reporting. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. 60 Table of Contents The following table presents gross operating margin by segment and non-GAAP total gross operating margin for the periods indicated (dollars in millions): For the Three Months Ended June 30, For the Six Months Ended June 30, 2020 2019 2020 2019 Gross operating margin by segment: NGL Pipelines & Services $ 968.1 $ 966.3 $ 2,010.1 $ 1,925.5 Crude Oil Pipelines & Services 634.4 513.2 1,087.3 1,175.5 Natural Gas Pipelines & Services 208.9 301.8 492.7 566.1 Petrochemical & Refined Products Services 191.5 304.9 470.0 547.5 Total segment gross operating margin (1) 2,002.9 2,086.2 4,060.1 4,214.6 Net adjustment for shipper make-up rights (4.5 ) (5.7 ) (14.2 ) (0.4 ) Total gross operating margin (non-GAAP) $ 1,998.4 $ 2,080.5 $ 4,045.9 $ 4,214.2 (1) Within the context of this table, total segment gross operating margin represents a subtotal and corresponds to measures similarly titled within our business segment disclosures found under Note 10 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report. Total gross operating margin includes equity in the earnings of unconsolidated affiliates, but is exclusive of other income and expense transactions, income taxes, the cumulative effect of changes in accounting principles and extraordinary charges. Total gross operating margin is presented on a 100% basis before any allocation of earnings to noncontrolling interests. Our calculation of gross operating margin may or may not be comparable to similarly titled measures used by other companies. Segment gross operating margin for NGL Pipelines & Services and Crude Oil Pipelines & Services reflect adjustments for shipper make-up rights that are included in management’s evaluation of segment results. However, these adjustments are excluded from non-GAAP total gross operating margin. The GAAP financial measure most directly comparable to total gross operating margin is operating income. For a discussion of operating income and its components, see the previous section titled “ Income Statement Highlights ” within this Part I, Item 2. The following table presents a reconciliation of operating income to total gross operating margin for the periods indicated (dollars in millions): For the Three Months Ended June 30, For the Six Months Ended June 30, 2020 2019 2020 2019 Operating income $ 1,436.9 $ 1,560.3 $ 2,944.4 $ 3,186.5 Adjustments to reconcile operating income to total gross operating margin (addition or subtraction indicated by sign): Depreciation, amortization and accretion expense in operating costs and expenses 494.3 462.8 977.1 913.7 Asset impairment and related charges in operating costs and expenses 11.8 7.0 13.4 11.8 Net gains attributable to asset sales in operating costs and expenses (1.6 ) (2.1 ) (1.5 ) (2.5 ) General and administrative costs 57.0 52.5 112.5 104.7 Total gross operating margin (non-GAAP) $ 1,998.4 $ 2,080.5 $ 4,045.9 $ 4,214.2 Each of our business segments benefits from the supporting role of our marketing activities. The main purpose of our marketing activities is to support the utilization and expansion of assets across our midstream energy asset network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment. In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of gross operating margin for the partnership. The financial results of our marketing efforts fluctuate due to changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for the products bought and sold. Our 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. 61 Table of Contents NGL Pipelines & Service s The following table presents segment gross operating margin and selected volumetric data for the NGL Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted): For the Three Months Ended June 30, For the Six Months Ended June 30, 2020 2019 2020 2019 Segment gross operating margin: Natural gas processing and related NGL marketing activities $ 199.2 $ 248.6 $ 451.5 $ 541.3 NGL pipelines, storage and terminals 606.3 588.7 1,259.6 1,146.0 NGL fractionation 162.6 129.0 299.0 238.2 Total $ 968.1 $ 966.3 $ 2,010.1 $ 1,925.5 Selected volumetric data: NGL pipeline transportation volumes (MBPD) 3,482 3,587 3,622 3,523 NGL marine terminal volumes (MBPD) 701 625 721 584 NGL fractionation volumes (MBPD) 1,154 1,000 1,186 984 Equity NGL production volumes (MBPD) (1) 188 144 164 150 Fee-based natural gas processing volumes (MMcf/d) (2, 3) 4,136 4,705 4,398 4,733 (1) Represents the NGL volumes we earn and take title to in connection with our processing activities. (2) Volumes reported correspond to the revenue streams earned by our natural gas processing plants. (3) Fee-based natural gas processing volumes are measured at either the wellhead or plant inlet in MMcf/d. For the third and fourth quarters of 2019, fee-based natural gas processing volumes measured in this manner were 4,724 MMcf/d and 4,763 MMcf/d, respectively, and averaged 4,738 MMcf/d for 2019 and 4,430 MMcf/d for 2018. Natural gas processing and related NGL marketing activities Second Quarter of 2020 Compared to Second Quarter of 2019 . Gross operating margin from natural gas processing and related NGL marketing activities for the second quarter of 2020 decreased $49.4 million when compared to the second quarter of 2019. Gross operating margin from our Rocky Mountain natural gas processing facilities (Meeker, Pioneer and Chaco plants) decreased a combined $39.8 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities). Lower composite NGL prices impacted processing margins, which declined 34% in the second quarter of 2020 when compared to the second quarter of 2019. On a combined basis, fee-based natural gas processing volumes decreased 337 MMcf/d and equity NGL production volumes increased 7 MBPD quarter-to-quarter. Gross operating margin from our South Texas natural gas processing facilities decreased $17.8 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $13.1 million decrease, and lower average processing fees, which accounted for an additional $3.3 million decrease. Fee-based natural gas processing volumes decreased 138 MMcf/d and equity NGL production volumes increased 12 MBPD quarter-to-quarter. Gross operating margin from our Permian Basin natural gas processing facilities decreased $4.7 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $5.0 million decrease, lower average processing fees, which accounted for a $4.9 million decrease, and higher operating costs, which accounted for an additional $4.2 million decrease, partially offset by higher processing volumes, which accounted for a $9.7 million increase. Fee-based natural gas processing and equity NGL production volumes at our Permian Basin natural gas processing facilities increased 243 MMcf/d and 21 MBPD, respectively, quarter-to-quarter primarily due to additional processing capacity at our Orla facility completed in July 2019 and the start-up of our Mentone facility in December 2019. Gross operating margin from our Louisiana and Mississippi natural gas processing facilities decreased $7.3 million quarter-to-quarter primarily due to lower average processing margins, which accounted for an $11.0 million decrease, partially offset by lower operating costs, which accounted for a $4.1 million increase. Net to our interest, fee-based natural gas processing volumes decreased 373 MMcf/d quarter-to-quarter. 62 Table of Contents Gross operating margin from our NGL marketing activities increased a net $23.0 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $79.0 million increase, partially offset by lower average sales margins, which accounted for a $56.2 million decrease. Results from marketing strategies that optimize our transportation and storage assets increased a combined $21.3 million quarter-to-quarter, partially offset by lower earnings from the optimization of our export and plant assets, which accounted for a $30.1 million decrease. In addition, results from NGL marketing increased $31.8 million quarter-to-quarter due to non-cash, mark-to-market gains of $35.4 million in the second quarter of 2020. Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 . Gross operating margin from natural gas processing and related NGL marketing activities for the six months ended June 30, 2020 decreased $89.8 million when compared to the six months ended June 30, 2019. Gross operating margin from our Rocky Mountain natural gas processing facilities decreased a combined $57.6 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities). On a combined basis, fee-based natural gas processing and equity NGL volumes decreased 258 MMcf/d and 5 MBPD, respectively, period-to-period. Gross operating margin from our South Texas natural gas processing facilities decreased $42.6 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $32.4 million decrease, lower processing volumes, which accounted for a $5.4 million decrease, and lower average processing fees, which accounted for an additional $4.5 million decrease. Fee-based natural gas processing volumes decreased 92 MMcf/d and equity NGL production volumes increased 7 MBPD period-to-period. Gross operating margin from our Permian Basin natural gas processing facilities decreased $19.2 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $17.3 million decrease, higher operating costs, which accounted for an $11.8 million decrease, and lower average processing fees, which accounted for an additional decrease of $9.6 million, partially offset by higher processing volumes, which accounted for a $19.6 million increase. Fee-based natural gas processing and equity NGL production volumes at our Permian Basin natural gas processing facilities increased 258 MMcf/d and 11 MBPD, respectively, period-to-period, primarily due to additional processing capacity at our Orla facility completed in July 2019 and the start-up of our Mentone facility in December 2019. Gross operating margin from our Louisiana and Mississippi natural gas processing facilities decreased $12.8 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $19.8 million decrease, partially offset by lower operating costs, which accounted for a $5.2 million increase. Net to our interest, fee-based natural gas processing volumes decreased 291 MMcf/d period-to-period. Gross operating margin from our NGL marketing activities increased a net $48.5 million period-to-period primarily due to higher sales volumes, which accounted for a $159.0 million increase, partially offset by lower average sales margins, which accounted for a $110.2 million decrease. Results from marketing strategies that optimize our storage, transportation and export assets increased a combined $39.1 million period-to-period, partially offset by lower earnings from the optimization of our plant assets, which accounted for a $9.7 million decrease. In addition, results from NGL marketing increased $19.1 million period-to-period due to non-cash, mark-to-market gains of $23.1 million in the six months ended June 30, 2020. NGL pipelines, storage and terminals Second Quarter of 2020 Compared to Second Quarter of 2019 . Gross operating margin from our NGL pipelines, storage and terminal assets during the second quarter of 2020 increased $17.6 million when compared to the second quarter of 2019. 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 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 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. 63 Table of Contents 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. 64 Table of Contents NGL fractionation Second Quarter of 2020 Compared to Second Quarter of 2019 . Gross operating margin from NGL fractionation during the second quarter of 2020 increased $33.6 million when compared to the second quarter of 2019. Gross operating margin from our Mont Belvieu NGL fractionation complex increased $27.7 million quarter-to-quarter primarily due to higher fractionation volumes, which increased 166 MBPD quarter-to-quarter (net to our interest) primarily due to the start-up of the first fractionation train (“Frac X”) at our newly constructed NGL fractionation facility located in Chambers County, Texas. Gross operating margin from our South Texas NGL fractionators increased $5.1 million quarter-to-quarter primarily due to lower operating costs at our Shoup fractionator, which underwent major maintenance activities during the second quarter of 2019. NGL fractionation volumes at our South Texas facilities increased 13 MBPD quarter-to-quarter. Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 . Gross operating margin from NGL fractionation during the six months ended June 30, 2020 increased $60.8 million when compared to the six months ended June 30, 2019. Gross operating margin from our Mont Belvieu NGL fractionation complex increased $27.7 million primarily due to higher fractionation volumes, which increased 168 MBPD period-to-period (net to our interest) primarily due to the start-up of Frac X. Gross operating margin at our Hobbs NGL fractionator increased $17.8 million period-to-period primarily due to major maintenance activities during the first quarter of 2019. 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 The following table presents segment gross operating margin and selected volumetric data for the Crude Oil Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted): For the Three Months Ended June 30, For the Six Months Ended June 30, 2020 2019 2020 2019 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 $ 53.1 $ 109.6 $ 113.3 $ 209.4 Non-cash mark-to-market gains – 14.0 0.9 81.2 Total Midland-to-ECHO 1 pipeline and related business activities 53.1 123.6 114.2 290.6 Midland-to-ECHO 2 pipeline 38.9 28.1 68.2 45.5 Total Midland-to-ECHO System 92.0 151.7 182.4 336.1 Other crude oil pipelines, terminals and related marketing results 542.4 361.5 904.9 839.4 Total $ 634.4 $ 513.2 $ 1,087.3 $ 1,175.5 Selected volumetric data: Crude oil pipeline transportation volumes (MBPD) 1,890 2,378 2,141 2,310 Crude oil marine terminal volumes (MBPD) 726 985 854 935 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. 65 Table of Contents 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. 66 Table of Contents Natural Gas Pipelines & Services The following table presents segment gross operating margin and selected volumetric data for the Natural Gas Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted): For the Three Months Ended June 30, For the Six Months Ended June 30, 2020 2019 2020 2019 Segment gross operating margin $ 208.9 $ 301.8 $ 492.7 $ 566.1 Selected volumetric data: Natural gas pipeline transportation volumes (BBtus/d) 12,975 14,349 13,419 14,274 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. 67 Table of Contents Petrochemical & Refined Products Services The following table presents segment gross operating margin and selected volumetric data for the Petrochemical & Refined Products Services segment for the periods indicated (dollars in millions, volumes as noted): For the Three Months Ended June 30, For the Six Months Ended June 30, 2020 2019 2020 2019 Segment gross operating margin: Propylene production and related activities $ 60.5 $ 133.7 $ 169.1 $ 236.0 Butane isomerization and related operations 10.1 21.2 26.2 45.2 Octane enhancement and related plant operations 36.7 52.5 105.7 76.8 Refined products pipelines and related activities 66.3 85.3 141.4 167.2 Marine transportation and other services 17.9 12.2 27.6 22.3 Total $ 191.5 $ 304.9 $ 470.0 $ 547.5 Selected volumetric data: Propylene production volumes (MBPD) 72 104 85 97 Butane isomerization volumes (MBPD) 68 109 86 110 Standalone DIB processing volumes (MBPD) 130 96 118 94 Octane enhancement and related plant sales volumes (MBPD) (1) 32 39 33 31 Pipeline transportation volumes, primarily refined products & petrochemicals (MBPD) 786 672 748 740 Marine terminal volumes, primarily refined products and petrochemicals (MBPD) 250 396 261 367 (1) 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 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 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 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. 68 Table of Contents 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 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 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 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. 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. 69 Table of Contents Consolidated Debt At June 30, 2020, the average maturity of our consolidated debt obligations was approximately 19.9 years. The following table presents scheduled maturities of our consolidated debt obligations outstanding at June 30, 2020 for the years indicated (dollars in millions): Scheduled Maturities of Debt Total Remainder of 2020 2021 2022 2023 2024 Thereafter Principal amount of senior and junior debt obligations $ 29,896.4 $ 1,000.0 $ 1,325.0 $ 1,400.0 $ 1,250.0 $ 850.0 $ 24,071.4 As discussed under “ Other Recent Developments ” within this Item 2, EPO issued $3.0 billion aggregate principal amount of senior notes in January 2020 and $1.25 billion aggregate principal amount of senior notes in August 2020. In addition, EPO entered into its April 2020 364-Day Revolving Credit Agreement, which provides EPO with an incremental $1.0 billion of borrowing capacity. At June 30, 2020, there were no principal amounts outstanding under the April 2020 364-Day Revolving Credit Agreement. EPO’s September 2019 364-Day Revolving Credit Agreement is scheduled to mature in September 2020. As a result, EPO expects to renew this credit agreement during the third quarter of 2020. At June 30, 2020, there were no principal amounts outstanding under the September 2019 364-Day Revolving Credit Agreement. For additional information regarding our debt agreements, see Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report. Common Unit Buyback Program In January 2020, management announced its intention to use approximately 2.0% of net cash flow provided by operating activities, or cash flow from operations (“CFFO”), in 2020 to repurchase EPD common units under the Buyback Program approved in January 2019 (the “2019 Buyback Program”). EPD repurchased 6,357,739 common units under its 2019 Buyback Program through open market purchases in the six months ended June 30, 2020. The total purchase price of these repurchases (including commissions and fees) was $ 140.1 million, and represented 2.1 % of our consolidated CFFO for the twelve months ended June 30, 2020 . The repurchased units were cancelled immediately upon acquisition. As of June 30, 2020 , the remaining available capacity under the 2019 Buyback Program was $ 1.78 billion. In addition to the 2019 Buyback Program, privately held affiliates of EPCO acquired 1,459,000 of EPD’s common units on the open market during the six months ended June 30, 2020. In the aggregate, 7,816,739 common units were purchased on the open market during the six months ended June 30, 2020 under the 2019 Buyback Program and by privately held affiliates of EPCO. Credit Ratings As of August 10, 2020, the investment-grade credit ratings of EPO’s long-term senior unsecured debt securities were BBB+ from Standard and Poor’s, Baa1 from Moody’s and BBB+ from Fitch Ratings. 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. EPO’s credit ratings reflect only the view of a rating agency and should not be interpreted as a recommendation to buy, sell or hold any of our securities. A credit rating can be revised upward or downward or withdrawn at any time by a rating agency, if it determines that circumstances warrant such a change. A credit rating from one rating agency should be evaluated independently of credit ratings from other rating agencies. 70 Table of Contents Issuance of Common Units On March 5, 2020, we settled our obligations under the Liquidity Option Agreement. As a result, EPD issued 54,807,352 of its common units to Skyline and indirectly reacquired the 54,807,352 EPD common units owned by OTA. For additional information regarding this transaction, see “ Other Recent Developments – Settlement of Liquidity Option ” within this Item 2. EPD has registration statements on file with the SEC in connection with its distribution reinvestment plan (“DRIP”) and employee unit purchase plan (“EUPP”). In July 2019, EPD announced that, beginning with the quarterly distribution payment paid in August 2019, it would use common units purchased on the open market, rather than issuing new common units, to satisfy its delivery obligations under the DRIP and EUPP. This election is subject to change in future quarters depending on the partnership’s need for equity capital. During the six months ended June 30, 2020, a total of 3,379,971 common units were purchased on the open market and delivered to participants in connection with the DRIP and EUPP. Apart from $1.3 million attributable to the plan discount available to all participants in the EUPP, the funds used to effect these purchases were sourced from the DRIP and EUPP participants. No other partnership funds were used to satisfy these obligations. We plan to use open market purchases to satisfy DRIP and EUPP reinvestments in connection with the distribution expected to be paid on August 12, 2020. EPD issued and delivered a combined 2,897,990 common units in the six months ended June 30, 2019 in connection with the DRIP and EUPP, which generated net cash proceeds totaling $ 82.2 million. Cash Flow Statement Highlights The following table summarizes our consolidated cash flows from operating, investing and financing activities for the periods indicated (dollars in millions). For additional information regarding our cash flow amounts, please refer to the Unaudited Condensed Statements of Consolidated Cash Flows included under Part I, Item 1 of this quarterly report. For the Six Months Ended June 30, 2020 2019 Net cash flows provided by operating activities $ 3,193.8 $ 3,183.7 Cash used in investing activities 1,930.5 2,286.5 Cash used in financing activities 236.7 1,200.0 Net cash flows provided by operating activities are largely dependent on earnings from our consolidated business activities. Changes in energy commodity prices may impact the demand for natural gas, NGLs, crude oil, petrochemical and refined products, which could impact sales of our products and the demand for our midstream services. Changes in demand for our products and services may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, adverse weather conditions and government regulations affecting prices and production levels. We may also incur credit and price risk to the extent customers do not fulfill their obligations to us in connection with our marketing activities and long-term take-or-pay agreements. For a more complete discussion of these and other risk factors pertinent to our business, see Part I, Item 1A of the 2019 Form 10-K and Part II, Item 1A of this quarterly report. The following information highlights significant period-to-period fluctuations in our consolidated cash flow amounts: Operating activities Net cash flows provided by operating activities for the six months ended June 30, 2020 increased a net $ 10.1 million when compared to the six months ended June 30, 2019 primarily due to: • a $ 243.0 million period-to-period increase primarily due to the timing of cash receipts and payments related to operations; partially offset by • a $ 199.4 m illion period-to-period decrease resulting from lower partnership earnings in the six months ended June 30, 2020 when compared to the six months ended June 30, 2019 (determined by adjusting our $ 81.1 million period-to-period decrease in net income for changes in the non-cash items identified on our Unaudited Condensed Statements of Consolidated Cash Flows); and 71 Table of Contents • 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 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); and • 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 used in financing activities for the six months ended June 30, 2020 decreased a net $ 963.3 million when compared to the six months ended June 30, 2019 primarily due to: • a net $1.24 billion period-to-period increase in net cash inflows attributable to debt. During the six months ended June 30, 2020, we issued $3.0 billion aggregate principal amount of senior notes, partially offset by the repayment of $500 million principal amount of senior notes. During the six months ended June 30, 2019, we repaid or repurchased $724.2 million principal amount of senior and junior notes. In addition, net repayments of short term notes under EPO’s commercial paper program were $ 481.7 million during the six months ended June 30, 2020 compared to net issuances of $1.42 billion during the six months ended June 30, 2019 ; partially offset by • an $ 82.2 million period-to-period decrease in net cash proceeds from the issuance of common units in connection with our DRIP and EUPP. As noted previously, EPD announced in July 2019 that, beginning with the quarterly distribution payment paid in August 2019, it would use common units purchased on the open market, rather than issuing new common units, to satisfy its delivery obligations under the DRIP and EUPP; • 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; and • 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. 72 Table of Contents Non-GAAP Cash Flow Measures Distributable Cash Flow Our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash, after any cash reserves established by Enterprise GP in its sole discretion. Cash reserves include those for the proper conduct of our business, including those for capital investments, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other amounts. The retention of cash by the partnership allows us to reinvest in our growth and reduce our future reliance on the equity and debt capital markets. We measure available cash by reference to distributable cash flow (“DCF”), which is a non-GAAP cash flow measure. DCF is an important financial measure for our limited partners since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flows at a level that can sustain our declared quarterly cash distributions. DCF is also a quantitative standard used by the investment community with respect to publicly traded partnerships since the value of a partnership unit is, in part, measured by its yield, which is based on the amount of cash distributions a partnership can pay to a unitholder. Our management compares the DCF we generate to the cash distributions we expect to pay our partners. Using this metric, management computes our distribution coverage ratio. Our calculation of DCF may or may not be comparable to similarly titled measures used by other companies. Based on the level of available cash each quarter, management proposes a quarterly cash distribution rate to the Board of Enterprise GP, which has sole authority in approving such matters. Unlike several other master limited partnerships, our general partner has a non-economic ownership interest in us and is not entitled to receive any cash distributions from us based on incentive distribution rights or other equity interests. Our use of DCF for the limited purposes described above and in this report is not a substitute for net cash flows provided by operating activities, which is the most comparable GAAP measure. For a discussion of net cash flows provided by operating activities, see “ Cash Flow Statement Highlights ” within this Part I, Item 2. 73 Table of Contents The following table summarizes our calculation of DCF for the periods indicated (dollars in millions): For the Three Months Ended June 30, For the Six Months Ended June 30, 2020 2019 2020 2019 Net income attributable to limited partners (GAAP) (1) $ 1,034.7 $ 1,214.7 $ 2,384.8 $ 2,475.2 Adjustments to net income attributable to limited partners to derive DCF (addition or subtraction indicated by sign): Depreciation, amortization and accretion expenses 522.7 488.6 1,031.7 963.1 Cash distributions received from unconsolidated affiliates (2) 178.4 171.0 315.6 314.5 Equity in income of unconsolidated affiliates (113.3 ) (137.4 ) (254.1 ) (292.0 ) Change in fair market value of derivative instruments (61.9 ) 12.5 (91.4 ) (83.8 ) Change in fair value of Liquidity Option – 26.6 2.3 84.4 Deferred income tax expense (benefit) 53.4 2.4 (130.7 ) 4.2 Sustaining capital expenditures (3) (74.0 ) (80.1 ) (142.9 ) (141.7 ) Other, net 33.8 9.7 44.8 10.8 Subtotal DCF, before proceeds from asset sales and monetization of interest rate derivative instruments accounted for as cash flow hedges $ 1,573.8 $ 1,708.0 $ 3,160.1 $ 3,334.7 Proceeds from asset sales 3.5 14.4 4.1 16.1 Monetization of interest rate derivative instruments accounted for as cash flow hedges – – (33.3 ) – DCF (non-GAAP) $ 1,577.3 $ 1,722.4 $ 3,130.9 $ 3,350.8 Cash distributions paid to limited partners with respect to period $ 979.9 $ 969.1 $ 1,959.7 $ 1,932.6 Cash distribution per unit declared by Enterprise GP with respect to period (4) $ 0.4450 $ 0.4400 $ 0.8900 $ 0.8775 Total DCF retained by partnership with respect to period (5) $ 597.4 $ 753.3 $ 1,171.2 $ 1,418.2 Distribution coverage ratio (6) 1.6 x 1.8 x 1.6 x 1.7 x (1) For a discussion of the primary drivers of changes in our comparative income statement amounts, see “ Income Statement Highlights ” within this Part I, Item 2. (2) Reflects distributions received from unconsolidated affiliates attributable to earnings and the return of capital. (3) Sustaining capital expenditures include cash payments and accruals applicable to the period. (4) See Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for additional information regarding our quarterly cash distributions declared with respect to the years indicated. (5) At the sole discretion of Enterprise GP, cash retained by the partnership with respect to each of these periods was primarily reinvested in growth capital projects. This retainage of cash substantially reduced our reliance on the equity capital markets to fund such expenditures. (6) Distribution coverage ratio is determined by dividing DCF by total cash distributions paid to limited partners and in connection with distribution equivalent rights with respect to the period. The following table presents a reconciliation of net cash flows provided by operating activities to DCF for the periods indicated (dollars in millions): For the Three Months Ended June 30, For the Six Months Ended June 30, 2020 2019 2020 2019 Net cash flows provided by operating activities (GAAP) $ 1,181.6 $ 2,023.3 $ 3,193.8 $ 3,183.7 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 430.7 (227.8 ) 89.0 332.0 Sustaining capital expenditures (74.0 ) (80.1 ) (142.9 ) (141.7 ) Distributions received from unconsolidated affiliates attributable to the return of capital 47.7 18.9 58.0 23.4 Proceeds from asset sales 3.5 14.4 4.1 16.1 Net income attributable to noncontrolling interest (26.1 ) (21.8 ) (51.0 ) (41.7 ) Monetization of interest rate derivative instruments accounted for as cash flow hedges – – (33.3 ) – Other, net 13.9 (4.5 ) 13.2 (21.0 ) DCF (non-GAAP) $ 1,577.3 $ 1,722.4 $ 3,130.9 $ 3,350.8 74 Table of Contents Free Cash Flow Free Cash Flow (“FCF”), a non-GAAP financial measure, is a traditional cash flow metric that is widely used by a variety of investors and other participants in the financial community, as opposed to DCF, which is a cash flow measure primarily used by investors and others in evaluating master limited partnerships. In general, FCF is a measure of how much cash flow a business generates during a specified time period after accounting for all capital investments, including expenditures for growth and sustaining capital projects. By comparison, only sustaining capital expenditures are reflected in DCF. We believe that FCF is important to traditional investors since it reflects the amount of cash available for reducing debt, investing in additional capital projects, paying distributions, common unit repurchases and similar matters. Since business partners fund certain capital projects of our consolidated subsidiaries, our determination of FCF reflects the amount of cash contributed from and distributed to noncontrolling interests. Our calculation of FCF may or may not be comparable to similarly titled measures used by other companies. Our use of FCF for the limited purposes described above and in this report is not a substitute for net cash flows provided by operating activities, which is the most comparable GAAP measure. FCF fluctuates based on our earnings, the level of investing activities we undertake each period, and the timing of operating cash receipts and payments. In addition to providing the quarterly amounts presented below, we also provide a calculation of aggregate FCF over the twelve months ended 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 June 30, For the Six Months Ended June 30, For the Twelve Months Ended June 30, 2020 2019 2020 2019 2020 Net cash flows provided by operating activities (GAAP) $ 1,181.6 $ 2,023.3 $ 3,193.8 $ 3,183.7 $ 6,530.6 Adjustments to net cash flows provided by operating activities to derive FCF (addition or subtraction indicated by sign): Cash used in investing activities (858.8 ) (1,112.0 ) (1,930.5 ) (2,286.5 ) (4,219.5 ) Cash contributions from noncontrolling interests 14.5 64.8 19.7 99.6 552.9 Cash distributions paid to noncontrolling interests (31.9 ) (28.9 ) (61.8 ) (46.9 ) (121.1 ) FCF (non-GAAP) $ 305.4 $ 947.2 $ 1,221.2 $ 949.9 $ 2,742.9 For a discussion of primary drivers of our quarterly net cash flows provided by operating activities and cash used in investing activities, see “ Cash Flow Statement Highlights ” within this Part I, Item 2. Capital Investments As previously discussed, capital investing activity throughout the domestic energy industry is being significantly reduced in response to the demand and supply disruptions attributable to COVID-19 and the oil price shock. We, along with many other midstream energy companies, have reviewed our planned capital investments in light of these adverse macroeconomic events. As previously noted and based on information currently available, we now expect our total capital investments for 2020 to approximate $2.8 billion to $3.3 billion, which reflects growth capital investments of $2.5 billion to $3.0 billion and approximately $300 million for sustaining capital expenditures. Based on sanctioned projects, we currently expect our growth capital investments for 2021 and 2022 to approximate $2.3 billion and $1.0 billion, respectively. Our revised forecast of capital investments for 2020 is based on announced strategic operating and growth plans (through the filing date of this quarterly report), which are dependent upon our ability to generate the required funds from either operating cash flows or other means, including borrowings under debt agreements, the issuance of additional equity and debt securities, and potential divestitures. We may revise our forecast of capital investments due to factors beyond our control, such as adverse economic conditions, weather-related issues and changes in supplier prices. Furthermore, our forecast of capital investments may change due to decisions made by management at a later date, which may include unforeseen acquisition opportunities. 75 Table of Contents Our success in raising capital, including partnering with other companies to share project costs and risks, continues to be a significant factor in determining how much capital we can invest. We believe our access to capital resources is sufficient to meet the demands of our current and future growth needs and, although we expect to make the forecast capital investments noted above, we may adjust the timing and amounts of projected expenditures in response to changes in capital market conditions. We placed 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. We currently have $6.6 billion of growth capital projects scheduled to be completed by the end of 2023 including the following major projects: • an eleventh NGL fractionator in Chambers County, Texas (“Frac XI,” third quarter of 2020); • components of our Midland-to-ECHO System (third quarter of 2020 into 2021); • expansion of our natural gas pipeline network in northeast Texas in support of our Carthage natural gas processing facilities (fourth quarter of 2020 into 2021); • completion of the Baymark ethylene pipeline in South Texas (fourth quarter of 2020); • expansion of our ethylene export capabilities at Morgan’s Point (fourth quarter of 2020); • expansion and extension of our Acadian Gas System (Gillis Lateral and related projects) (fourth quarter of 2021); and • 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 Six Months Ended June 30, 2020 2019 Capital investments for property, plant and equipment: (1) Growth capital projects (2) $ 1,830.0 $ 2,116.4 Sustaining capital projects (3) 145.9 144.4 Total $ 1,975.9 $ 2,260.8 Investments in unconsolidated affiliates $ 7.3 $ 59.9 (1) Growth and sustaining capital amounts presented in the table above are presented on a cash basis. (2) Growth capital projects either (a) result in new sources of cash flow due to enhancements of or additions to existing assets (e.g., additional revenue streams, cost savings resulting from debottlenecking of a facility, etc.) or (b) expand our asset base through construction of new facilities that will generate additional revenue streams and cash flows. (3) Sustaining capital expenditures are capital expenditures (as defined by GAAP) resulting from improvements to existing assets. Such expenditures serve to maintain existing operations but do not generate additional revenues or result in significant cost savings. 76 Table of Contents 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 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; and • 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. 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 A discussion of our critical accounting policies and estimates is included in our 2019 Form 10-K. The following types of estimates, in our opinion, are subjective in nature, require the exercise of professional judgment and involve complex analysis: • depreciation methods and estimated useful lives of property, plant and equipment; • measuring recoverability of long-lived assets and equity method investments; • amortization methods and estimated useful lives of qualifying intangible assets; • methods we employ to measure the fair value of goodwill; and • revenue recognition policies and the use of estimates for revenue and expenses. When used to prepare our Unaudited Condensed Consolidated Financial Statements, the foregoing types of estimates are based on our current knowledge and understanding of the underlying facts and circumstances. Such estimates may be revised as a result of changes in the underlying facts and circumstances. Subsequent changes in these estimates may have a significant impact on our consolidated financial position, results of operations and cash flows. 77 Table of Contents Other Items Contractual Obligations We have contractual future product purchase commitments for natural gas, NGLs, crude oil, petrochemicals and refined products. These commitments represent enforceable and legally binding agreements as of the reporting date. Our product purchase commitments at 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. Off-Balance Sheet Arrangements We have no off-balance sheet arrangements that have or are reasonably expected to have a material current or future effect on our financial position, results of operations and cash flows. Related Party Transactions For information regarding our related party transactions, see Note 15 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.