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, 2023 and 2022 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, 2022 (the “2022 Form 10-K”), as filed on February 28, 2023 with the U.S. Securities and Exchange Commission (“SEC”). Our financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the United States (“U.S.”). Cautionary Statement Regarding Forward-Looking Information This quarterly report on Form 10-Q for the three and six months ended June 30, 2023 (our “quarterly report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “scheduled,” “pending,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements. Although we and our general partner believe that our expectations reflected in such forward-looking statements (including any forward-looking statements/expectations of third parties referenced in this 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 2022 Form 10-K. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements. The forward-looking statements in this quarterly report speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason. Key References Used in this Management’s Discussion and Analysis Unless the context requires otherwise, references to “we,” “us” or “our” within this quarterly report are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries. References to the “Partnership” or “Enterprise” mean Enterprise Products Partners L.P. on a standalone basis. References to “EPO” mean Enterprise Products Operating LLC, which is an indirect wholly owned subsidiary of the Partnership, and its consolidated subsidiaries, through which the Partnership conducts its business. We are managed by our general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company. The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Directors of Enterprise GP (the “Board”); (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board; and (iii) W. Randall Fowler, who is also a director and the Co-Chief Executive Officer and Chief Financial Officer of Enterprise GP. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as managers of Dan Duncan LLC. References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates. The outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are: (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO; and (iii) Mr. Fowler, who serves as an Executive Vice President and the Chief Financial Officer of EPCO. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as directors of EPCO. 39 Table of Contents We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees. EPCO, together with its privately held affiliates, owned approximately 32.3% of the Partnership’s common units outstanding at June 30, 2023. As generally used in the energy industry and in this quarterly report, the acronyms below have the following meanings: /d = per day MMBPD = million barrels per day BBtus = billion British thermal units MMBtus = million British thermal units Bcf = billion cubic feet MMcf = million cubic feet BPD = barrels per day MWac = megawatts, alternating current MBPD = thousand barrels per day MWdc = megawatts, direct current MMBbls = million barrels TBtus = trillion British thermal units As used in this quarterly report, the phrase “quarter-to-quarter” means the second quarter of 2023 compared to the second quarter of 2022. Likewise, the phrase “period-to-period” means the six months ended June 30, 2023 compared to the six months ended June 30, 2022. Overview of Business We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” Our preferred units are not publicly traded. We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products. We are owned by our limited partners (preferred and common unitholders) from an economic perspective. Enterprise GP, which owns a non-economic general partner interest in us, manages our Partnership. We conduct substantially all of our business operations through EPO and its consolidated subsidiaries. Our fully integrated, midstream energy asset network (or “value chain”) links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the U.S., Canada and the Gulf of Mexico with domestic consumers and international markets. Our midstream energy operations include: • natural gas gathering, treating, processing, transportation and storage; • NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases (“LPG”) and ethane); • crude oil gathering, transportation, storage, and marine terminals; • propylene production facilities (including propane dehydrogenation (“PDH”) facilities), butane isomerization, octane enhancement, isobutane dehydrogenation (“iBDH”) and high purity isobutylene (“HPIB”) production facilities; • petrochemical and refined products transportation, storage, and marine terminals (including those used to export ethylene and polymer grade propylene (“PGP”)); and • a marine transportation business that operates on key U.S. inland and intracoastal waterway systems. The safe operation of our assets is a top priority. We are committed to protecting the environment and the health and safety of the public and those working on our behalf by conducting our business activities in a safe and environmentally responsible manner. For additional information, see “ Environmental, Safety and Conservation ” within the Regulatory Matters section of Part I, Items 1 and 2 of the 2022 Form 10-K. Like many publicly traded partnerships, we have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers. Our financial position, results of operations and cash flows are subject to certain risks. For information regarding such risks, see “ Risk Factors ” included under Part I, Item 1A of the 2022 Form 10-K. 40 Table of Contents We provide investors access to additional information regarding the Partnership and our consolidated businesses, including information relating to governance procedures and principles, through our website, www.enterpriseproducts.com . Recent Developments Enterprise Begins Service At PDH 2 Plant In July 2023 we placed into service our second propane dehydrogenation plant (“PDH 2”) in Chambers County, Texas. Supported by long-term, fee-based contracts, PDH 2 has the capacity to consume 35 MBPD of propane to produce 1.65 billion pounds of PGP per year, which will help us supply our petrochemical customers with the feedstock to produce products that meet the needs of a growing global population. With the completion and integration of our PDH 2 plant with our existing PDH 1 plant and other propylene production facilities, we now have the capacity to produce approximately 11 billion pounds of propylene per year. Enterprise Begins Service At Its Twelfth NGL Fractionator in Chambers County, Texas In July 2023, our twelfth NGL fractionator (“Frac XII”) located in Chambers County, Texas was placed into service. The incremental 150 MBPD of nameplate capacity at Frac XII will help accommodate growing NGL production from new natural gas processing plants in the Permian Basin and help satisfy the demand for feedstocks by the petrochemical and refining industries and LPG exports to developing nations. Supported by long-term customer agreements, the addition of Frac XII increases total NGL fractionation capacity to approximately 1.2 MMBPD at our Chambers County complex and approximately 1.7 MMBPD company-wide. Enterprise Begins Service At Its Poseidon Natural Gas Processing Plant In July 2023, we placed into service our Poseidon cryogenic natural gas processing plant (“Poseidon”), which is located in Glasscock County, Texas. The new plant, which is our sixth in the Midland Basin, has a nameplate capacity of 300 MMcf/d and can extract more than 40 MBPD of NGLs. Supported by long-term acreage dedication agreements, the new plant will support Permian Basin producers as they meet growing demand in the U.S. and internationally. With the addition of Poseidon, we now have the capability to process 1.3 Bcf/d of natural gas and extract more than 185 MBPD of NGLs in the Midland Basin. Enterprise Completes Expansion of Acadian Haynesville Extension In May 2023, we completed an expansion of our Acadian Haynesville Extension natural gas pipeline. This expansion adds approximately 400 MMcf/d of Haynesville natural gas takeaway capacity to meet growing industrial demand in the Mississippi River Corridor and supports the Louisiana liquefied natural gas export market. The incremental compression added as part of the expansion project increased total natural gas transportation capacity on the Acadian Haynesville Extension from approximately 2.1 Bcf/d to 2.5 Bcf/d. This expansion is underwritten by long-term, take-or-pay contracts. Issuance of $1.75 Billion of Senior Notes in January 2023 In January 2023, EPO issued $1.75 billion aggregate principal amount of senior notes comprised of (i) $750 million principal amount of senior notes due January 2026 (“Senior Notes FFF”) and (ii) $1.0 billion principal amount of senior notes due January 2033 (“Senior Notes GGG”). Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of all of our $1.25 billion principal amount of 3.35% Senior Notes HH at their maturity in March 2023 and amounts outstanding under our commercial paper program). Senior Notes FFF were issued at 99.893% of their principal amount and have a fixed-rate interest rate of 5.05% per year. Senior Notes GGG were issued at 99.803% of their principal amount and have a fixed-rate interest rate of 5.35% per year. The Partnership guaranteed these senior notes through an unconditional guarantee on an unsecured and unsubordinated basis. 41 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) 2022 by quarter: 1st Quarter $4.96 $0.40 $1.30 $1.59 $1.60 $2.21 $0.63 $0.39 $0.55 2nd Quarter $7.17 $0.59 $1.24 $1.50 $1.68 $2.17 $0.61 $0.40 $0.46 3rd Quarter $8.20 $0.55 $1.08 $1.19 $1.44 $1.72 $0.47 $0.28 $0.26 4th Quarter $6.26 $0.39 $0.79 $0.97 $1.03 $1.54 $0.32 $0.18 $0.17 2022 Averages $6.65 $0.48 $1.10 $1.31 $1.44 $1.91 $0.51 $0.31 $0.36 2023 by quarter: 1st Quarter $3.44 $0.25 $0.82 $1.11 $1.16 $1.62 $0.50 $0.22 $0.37 2nd Quarter $2.09 $0.21 $0.67 $0.78 $0.84 $1.44 $0.40 $0.21 $0.37 2023 Averages $2.77 $0.23 $0.75 $0.95 $1.00 $1.53 $0.45 $0.22 $0.37 (1) Natural gas prices are based on Henry-Hub Inside FERC commercial index prices as reported by Platts, which is a division of S&P Global, Inc. (2) NGL prices for ethane, propane, normal butane, isobutane and natural gasoline are based on Mont Belvieu, Texas Non-TET commercial index prices as reported by Oil Price Information Service, which is a division of Dow Jones. (3) Polymer grade propylene prices represent average contract pricing for such product as reported by IHS Markit (“IHS”), which is a division of S&P Global, Inc. Refinery grade propylene (“RGP”) prices represent weighted-average spot prices for such product as reported by IHS. (4) The “Indicative Gas Processing Gross Spread” represents our generic estimate of the gross economic benefit from extracting NGLs from natural gas production based on certain pricing assumptions. Specifically, it is the amount by which the assumed economic value of a composite gallon of NGLs in Chambers County, Texas exceeds the value of the equivalent amount of energy in natural gas at Henry Hub, Louisiana. Our estimate of the indicative spread does not consider the operating costs incurred by a natural gas processing facility to extract the NGLs nor the transportation and fractionation costs to deliver the NGLs to market. In addition, the actual gas processing spread earned at each plant is further influenced by regional pricing and extraction dynamics. The weighted-average indicative market price for NGLs was $0.55 per gallon in the second quarter of 2023 versus $1.06 per gallon in the second quarter of 2022. Likewise, the weighted-average indicative market price for NGLs was $0.61 per gallon during the six months ended June 30, 2023 compared to $1.01 per gallon during the same period in 2022. 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) 2022 by quarter: 1st Quarter $94.29 $96.43 $96.77 $96.77 2nd Quarter $108.41 $109.66 $109.96 $110.17 3rd Quarter $91.56 $93.41 $93.77 $94.17 4th Quarter $82.64 $83.97 $84.33 $85.50 2022 Averages $94.23 $95.87 $96.21 $96.65 2023 by quarter: 1st Quarter $76.13 $77.50 $77.74 $79.00 2nd Quarter $73.78 $74.48 $74.68 $75.87 2023 Averages $74.96 $75.99 $76.21 $77.44 (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. 42 Table of Contents Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices. An increase in our consolidated marketing revenues due to higher energy commodity sales prices may not result in an increase in gross operating margin or cash available for distribution, since our consolidated cost of sales amounts would also be expected to increase due to comparable increases in the purchase prices of the underlying energy commodities. The same type of relationship would be true in the case of lower energy commodity sales prices and purchase costs. We attempt to mitigate commodity price exposure through our hedging activities and the use of fee-based arrangements. See Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report and “ Quantitative and Qualitative Disclosures About Market Risk ” under Part I, Item 3 of this quarterly report for information regarding our commodity hedging activities. Impact of Inflation Inflation rates in the United States increased significantly in 2022 and have continued to remain elevated in 2023 compared to recent historical levels. While pandemic-era supply chain disruptions have largely dissipated and measures taken by the U.S. Federal Reserve Bank have helped slow the growth of inflation in 2023, the high cost environment that began in 2022 has generally remained intact in 2023. However, to the extent that a rising cost environment impacts our results, there are typically offsetting benefits either inherent in our business or that result from other steps we take proactively to reduce the impact of inflation on our net operating results. These benefits include: (1) provisions included in our long-term fee-based revenue contracts that offset cost increases in the form of rate escalations based on positive changes in the U.S. Consumer Price Index, Producer Price Index for Finished Goods or other factors; (2) provisions in other revenue contracts that enable us to pass through higher energy costs to customers in the form of gas, electricity and fuel rebills or surcharges; and (3) higher commodity prices, which generally enhance our results in the form of increased volumetric throughput and demand for our services. Additionally, we take measures to mitigate the impact of cost increases in certain commodities, including a portion of our electricity needs, using fixed-price, term purchase agreements or financial derivatives. For these reasons, the increased cost environment, caused in part by inflation, has not had a material impact on our historical results of operations for the periods presented in this report. However, a significant or prolonged period of high inflation could adversely impact our results if costs were to increase at a rate greater than the increase in the revenues we receive. See “ Capital Investments ” within this Part I, Item 2 for a discussion of the impact of inflation on our capital investment decisions. 43 Table of Contents 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, 2023 2022 2023 2022 Revenues $ 10,651 $ 16,060 $ 23,095 $ 29,068 Costs and expenses: Operating costs and expenses: Cost of sales 7,679 12,908 17,010 23,006 Other operating costs and expenses 895 884 1,763 1,641 Depreciation, amortization and accretion expenses 562 544 1,109 1,070 Asset impairment charges 3 5 16 19 Net losses (gains) attributable to asset sales and related matters (2 ) ‒ (4 ) 2 Total operating costs and expenses 9,137 14,341 19,894 25,738 General and administrative costs 56 62 113 124 Total costs and expenses 9,193 14,403 20,007 25,862 Equity in income of unconsolidated affiliates 121 107 225 224 Operating income 1,579 1,764 3,313 3,430 Other income (expense): Interest expense (302 ) (309 ) (616 ) (628 ) Other, net 19 2 31 5 Total other expense, net (283 ) (307 ) (585 ) (623 ) Income before income taxes 1,296 1,457 2,728 2,807 Provision for income taxes (13 ) (17 ) (23 ) (36 ) Net income 1,283 1,440 2,705 2,771 Net income attributable to noncontrolling interests (29 ) (28 ) (60 ) (62 ) Net income attributable to preferred units (1 ) (1 ) (2 ) (2 ) Net income attributable to common unitholders $ 1,253 $ 1,411 $ 2,643 $ 2,707 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, 2023 2022 2023 2022 NGL Pipelines & Services: Sales of NGLs and related products $ 3,040 $ 5,580 $ 7,304 $ 10,620 Midstream services 649 800 1,314 1,514 Total 3,689 6,380 8,618 12,134 Crude Oil Pipelines & Services: Sales of crude oil 4,005 5,031 7,931 8,747 Midstream services 299 354 554 710 Total 4,304 5,385 8,485 9,457 Natural Gas Pipelines & Services: Sales of natural gas 445 1,359 1,291 2,239 Midstream services 330 302 699 571 Total 775 1,661 1,990 2,810 Petrochemical & Refined Products Services: Sales of petrochemicals and refined products 1,591 2,370 3,405 4,124 Midstream services 292 264 597 543 Total 1,883 2,634 4,002 4,667 Total consolidated revenues $ 10,651 $ 16,060 $ 23,095 $ 29,068 44 Table of Contents Second Quarter of 2023 Compared to Second Quarter of 2022. Total revenues for the second quarter of 2023 decreased $ 5.4 billion when compared to the second quarter of 2022 primarily due to a $ 5.3 billion decrease in marketing revenues. Revenues from the marketing of NGLs decreased $ 2.5 billion quarter-to-quarter primarily due to lower average sales prices, which accounted for a $ 2.3 billion decrease, and lower sales volumes, which accounted for an additional $ 229 million decrease. Revenues from the marketing of crude oil, natural gas and petrochemicals and refined products decreased a combined net $ 2.7 billion quarter-to-quarter primarily due to lower average sales prices, which accounted for a $ 3.5 b illion decrease, partially offset by higher sales volumes, which accounted for a $ 760 million increase. Revenues from midstream services for the second quarter of 2023 decreased a net $ 150 million when compared to the second quarter of 2022. Revenues from our natural gas processing facilities decreased $ 148 million quarter-to-quarter primarily due to lower market values for the equity NGL-equivalent production volumes we receive as non-cash consideration for processing services. R evenues from our crude oil pipeline assets decreased $ 49 million quarter-to-quarter primarily due to lower deficiency revenues as a result of the expiration of minimum volume commitments under certain long-term gathering agreements on our EFS Midstream System. Lastly, revenues from our NGL, natural gas and petrochemicals and refined products pipeline assets increased a combined $ 57 million quarter-to-quarter primarily due to higher demand for transportation services. Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022 . Total revenues for the six months ended June 30, 2023 decreased $ 6.0 billion when compared to the six months ended June 30, 2022 primarily due to a $ 5.8 billion decrease in marketing revenues. Revenues from the marketing of NGLs decreased $ 3.3 billion period-to-period primarily due to lower average sales prices. Revenues from the marketing of crude oil, natural gas and petrochemicals and refined products decreased a combined net $2.5 billion period-to-period primarily due to lower average sales prices, which accounted for a $4.4 billion decrease, partially offset by higher sales volumes, which accounted for a $1.9 billion increase. Revenues from midstream services for the six months ended June 30, 2023 decreased a net $ 174 million when compared to the six months ended June 30, 2022. Revenues from our natural gas processing facilities decreased $181 million period-to-period primarily due to lower market values for the equity NGL-equivalent production volumes we receive as non-cash consideration for processing services. Revenues from our crude oil pipeline assets decreased $ 133 million period-to-period primarily due to lower deficiency revenues as a result of the aforementioned expiration of minimum volume commitments on our EFS Midstream System. Lastly, revenues from our natural gas pipeline assets increased $ 127 million period-to-period primarily due to higher demand for transportation services and the addition of the Midland Basin Gathering System, which was acquired in February 2022. Operating costs and expenses Total operating costs and expenses for the three and six months ended June 30, 2023 decreased $ 5.2 billion and $ 5.8 billion, respectively, when compared to the same periods in 2022. Cost of sales Second Quarter of 2023 Compared to Second Quarter of 2022. Cost of sales for the second quarter of 2023 decreased $ 5.2 b illion when compared to the second quarter of 2022. The cost of sales associated with the marketing of NGLs decreased $ 2.9 billion quarter-to-quarter primarily due to lower average purchase prices, which accounted for a $ 2.7 billion decrease, and lower volumes, which accounted for an additional $ 235 million decrease. The cost of sales associated with the marketing of crude oil, natural gas and petrochemicals and refined products decreased a combined net $ 2.3 billion primarily due to lower average purchase prices, which accounted for a $ 3.0 billion decrease, partially offset by higher volumes, which accounted for a $ 676 million increase. 45 Table of Contents Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022 . Cost of sales for the six months ended June 30, 2023 decreased $ 6.0 billion when compared to the six months ended June 30, 2022. The cost of sales associated with our marketing of NGLs decreased $ 3.5 billion period-to-period primarily due to lower average purchase prices. The cost of sales associated with the marketing of crude oil, natural gas and petrochemicals and refined products decreased a combined net $2.5 billion primarily due to lower average purchase prices, which accounted for a $4.2 billion decrease, partially offset by higher volumes, which accounted for a $1.7 billion increase. Other operating costs and expenses Other operating costs and expenses for the second quarter of 2023 increased a net $ 11 million when compared to the second quarter of 2022 primarily due to higher maintenance, rental and other operating costs, which accounted for a $71 million increase, partially offset by lower utility costs, which accounted for a $60 million decrease. Other operating costs and expenses for the six months ended June 30, 2023 increased $ 122 million when compared to the six months ended June 30, 2022 primarily due to higher maintenance, rental and other operating costs, which accounted for a $183 million increase, partially offset by lower utility costs, which accounted for a $61 million decrease. Depreciation, amortization and accretion expenses Depreciation, amortization and accretion expense for the three and six months ended June 30, 2023 increased a combined $ 18 million and $ 39 million, respectively, when compared to the same periods in 2022. Depreciation expense increased $ 8 million quarter-to-quarter and $ 21 million period-to-period primarily due to the addition of assets attributable to the acquisition of our Midland Basin System in February 2022 and other assets placed into full or limited service since the end of the respective periods in 2022. Additionally, amortization expense associated with our contract-based intangible assets accounted for an additional $5 million of the quarter-to-quarter increase and $10 million of the period-to-period increase . General and administrative costs General and administrative costs for the three and six months ended June 30, 2023 decreased $ 6 million and $ 11 million, respectively, when compared to the same periods in 2022 primarily due to lower employee compensation and professional services costs. Equity in income of unconsolidated affiliates Equity income from our unconsolidated affiliates for the three and six months ended June 30, 2023 increased $ 14 million and $ 1 million, respectively, when compared to the same periods in 2022 primarily due to higher earnings from investments in crude oil pipelines. Operating income Operating income for the three and six months ended June 30, 2023 decreased $ 185 million and $ 117 million, respectively, when compared to the same periods in 2022 due to the previously described quarter-to-quarter and period-to-period changes. 46 Table of Contents 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, 2023 2022 2023 2022 Interest charged on debt principal outstanding (1) $ 336 $ 318 $ 673 $ 641 Impact of interest rate hedging program, including related amortization (3 ) 6 (1 ) 14 Interest costs capitalized in connection with construction projects (2) (37 ) (21 ) (69 ) (38 ) Other 6 6 13 11 Total $ 302 $ 309 $ 616 $ 628 (1) The weighted-average interest rates on debt principal outstanding during the three and six months ended June 30, 2023 were 4.58% and 4.57%, respectively. The weighted-average interest rate on debt principal outstanding during each of the three and six months ended June 30, 2022 was 4.31%. (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. Interest charged on debt principal outstanding, which is a key driver of interest expense, increased a net $ 18 million quarter-to-quarter. This increase was primarily due to the issuance of $1.75 billion fixed-rate senior notes in January 2023, which accounted for a $23 million increase, partially offset by a $15 million decrease as a result of the retirement of $1.25 billion of fixed-rate senior notes in March 2023 and the redemption of $350 million of junior subordinated notes in August 2022 . In addition, interest expense on our outstanding variable-rate junior subordinated notes increased $ 6 million primarily due to a quarter-to-quarter increase in the 3-month LIBOR. Interest charged on debt principal outstanding increased a net $ 32 million period-to-period. This increase was primarily due to the aforementioned issuance of senior notes, which accounted for a $43 million increase, partially offset by a $26 million decrease as a result of the retirement of $1.4 billion and $1.25 billion of fixed-rate senior notes in February 2022 and March 2023, respectively, and the aforementioned junior subordinated notes . In addition, interest expense on our outstanding variable-rate junior subordinated notes increased $ 11 million primarily due to a period-to-period increase in the 3-month LIBOR. 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. Income taxes Our income taxes are primarily comprised of our state tax obligations under the Revised Texas Franchise Tax (“Texas Margin Tax”). Our provision for income taxes for the three and six months ended June 30, 2023 decreased $ 4 million   and $ 13 million, respectively, when compared to the same periods in 2022. 47 Table of Contents Business Segment Highlights Our operations are reported under four business segments: (i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services and (iv) Petrochemical & Refined Products Services. Our business segments are generally organized and managed according to the types of services rendered (or technologies employed) and products produced and/or sold. We evaluate segment performance based on our financial measure of gross operating margin. Gross operating margin is an important performance measure of the core profitability of our operations and forms the basis of our internal financial reporting. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. The following table presents gross operating margin by segment and total gross operating margin, a non-generally accepted accounting principle (“non-GAAP”) financial measure, for the periods indicated (dollars in millions): For the Three Months Ended June 30, For the Six Months Ended June 30, 2023 2022 2023 2022 Gross operating margin by segment: NGL Pipelines & Services $ 1,110 $ 1,327 $ 2,322 $ 2,552 Crude Oil Pipelines & Services 422 407 819 822 Natural Gas Pipelines & Services 238 229 552 449 Petrochemical & Refined Products Services 383 421 802 825 Total segment gross operating margin (1) 2,153 2,384 4,495 4,648 Net adjustment for shipper make-up rights 28 (22 ) 21 (28 ) Total gross operating margin (non-GAAP) $ 2,181 $ 2,362 $ 4,516 $ 4,620 (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, 2023 2022 2023 2022 Operating income $ 1,579 $ 1,764 $ 3,313 $ 3,430 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 (1) 545 531 1,078 1,045 Asset impairment charges in operating costs and expenses 3 5 16 19 Net losses (gains) attributable to asset sales and related matters in operating costs and expenses (2 ) ‒ (4 ) 2 General and administrative costs 56 62 113 124 Total gross operating margin (non-GAAP) $ 2,181 $ 2,362 $ 4,516 $ 4,620 (1) Excludes amortization of major maintenance costs for reaction-based plants, which are a component of gross operating margin. 48 Table of Contents 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 us. The financial results of our marketing efforts fluctuate due to changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for the products bought and sold. 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, 2023 2022 2023 2022 Segment gross operating margin: Natural gas processing and related NGL marketing activities $ 310 $ 587 $ 636 $ 1,002 NGL pipelines, storage and terminals 598 539 1,288 1,105 NGL fractionation 202 201 398 445 Total $ 1,110 $ 1,327 $ 2,322 $ 2,552 Selected volumetric data: NGL pipeline transportation volumes (MBPD) 3,910 3,683 3,944 3,626 NGL marine terminal volumes (MBPD) 765 747 794 696 NGL fractionation volumes (MBPD) 1,376 1,336 1,373 1,327 Equity NGL-equivalent production volumes (MBPD) (1) 173 195 169 189 Fee-based natural gas processing volumes (MMcf/d) (2,3) 5,677 5,133 5,609 5,025 (1) Primarily represents the NGL and condensate volumes we earn and take title to in connection with our processing activities. The total equity NGL-equivalent production volumes also include residue natural gas volumes from our natural gas processing business. (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. Natural gas processing and related NGL marketing activities Second Quarter of 2023 Compared to Second Quarter of 2022 . Gross operating margin from natural gas processing and related NGL marketing activities for the second quarter of 2023 decreased $277 million when compared to the second quarter of 2022. Gross operating margin from our NGL marketing activities decreased $102 million quarter-to-quarter primarily due to lower average sales margins, which accounted for a $76 million decrease, and lower sales volumes, which accounted for an additional $33 million decrease. Gross operating margin from our Midland Basin natural gas processing facilities decreased a net $88 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $108 million decrease, partially offset by a 190 MMcf/d increase in fee-based natural gas processing volumes, which accounted for a $21 million increase. Equity NGL-equivalent production volumes at these facilities were flat quarter-to-quarter. Gross operating margin from our Delaware Basin natural gas processing facilities decreased $29 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes at these facilities increased 64 MMcf/d and equity NGL-equivalent production volumes decreased 3 MBPD quarter-to-quarter. Gross operating margin from our South Texas natural gas processing facilities decreased $29 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes increased 28 MMcf/d and equity NGL-equivalent production volumes decreased 2 MBPD quarter-to-quarter. 49 Table of Contents Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased a combined $20 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities). On a combined basis, fee-based natural gas processing volumes and equity NGL-equivalent production volumes decreased 74 MMcf/d and 10 MBPD, respectively, quarter-to-quarter. Gross operating margin from our Louisiana and Mississippi natural gas processing facilities decreased $7 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes increased 195 MMcf/d and equity NGL-equivalent production volumes decreased 7 MBPD quarter-to-quarter (net to our interest). Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022 . Gross operating margin from natural gas processing and related NGL marketing activities for the six months ended June 30, 2023 decreased $366 million when compared to the six months ended June 30, 2022. Gross operating margin from our NGL marketing activities decreased a net $179 million period-to-period primarily due to lower average sales margins, which accounted for a $152 million decrease, and lower sales volumes, which accounted for an additional $39 million decrease, partially offset by higher non-cash, mark-to-market earnings, which accounted for a $12 million increase. Gross operating margin from our Midland Basin natural gas processing facilities decreased a net $80 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $129 million decrease, and higher operating costs, which accounted for an additional $11 million decrease, partially offset by an increase in total equity NGL-equivalent production volumes, which accounted for a $19 million increase, and an increase in total fee-based natural gas processing volumes, which accounted for an additional $43 million increase. Fee-based natural gas processing volumes at these facilities, which reflect the average daily operating rates from the time the asset was acquired, increased 162 MMcf/d and equity NGL-equivalent production volumes were flat period-to-period. Gross operating margin from our Delaware Basin natural gas processing facilities decreased $51 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes at these facilities increased 130   MMcf/d and equity NGL-equivalent production volumes decreased 2 MBPD period-to-period . Gross operating margin from our South Texas natural gas processing facilities decreased $36 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $24 million decrease, and higher maintenance and other operating costs, which accounted for an additional $11 million decrease. Fee-based natural gas processing volumes and equity NGL-equivalent production volumes increased 53 MMcf/d and 2 MBPD, respectively, period-to-period. Gross operating margin from our Louisiana and Mississippi natural gas processing facilities decreased $14 million   period-to-period primarily due to lower average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes increased 190 MMcf/d and equity NGL-equivalent production volumes decreased 5 MBPD period-to-period (net to our interest). On a combined basis, gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased a net $4 million period-to-period primarily due to a 16 MBPD decrease in equity NGL-equivalent production volumes, which accounted for a $13 million decrease, partially offset by higher average processing fees, which accounted for a $5 million increase. Fee-based natural gas processing volumes decreased a combined 71 MMcf/d period-to-period. NGL pipelines, storage and terminals Second Quarter of 2023 Compared to Second Quarter of 2022 . Gross operating margin from our NGL pipelines, storage and terminal assets during the second quarter of 2023 increased $59 million when compared to the second quarter of 2022. Gross operating margin from our Chambers County storage complex increased $13 million quarter-to-quarter primarily due to lower operating costs. 50 Table of Contents Gross operating margin from LPG-related activities at our Enterprise Hydrocarbons Terminal (“EHT”) increased $12 million quarter-to-quarter primarily due to higher average loading fees. LPG export volumes at EHT decreased 4 MBPD quarter-to-quarter. Gross operating margin at our Morgan’s Point Ethane Export Terminal increased $11 million quarter-to-quarter primarily due to a 22 MBPD increase in export volumes, which accounted for a $6 million increase, and higher average loading fees, which accounted for an additional $3 million increase. Gross operating margin from our related Houston Ship Channel Pipeline System increased $6 million quarter-to-quarter primarily due to higher average transportation fees, which accounted for a $3 million increase, and a 59 MBPD increase in transportation volumes, which accounted for an additional $2 million increase. Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased a combined $4 million quarter-to-quarter   primarily due to higher average transportation fees. Transportation volumes on these pipelines increased a combined 95 MBPD quarter-to-quarter. A number of our pipelines, including the Mid-America Pipeline System, Seminole NGL Pipeline, Chaparral NGL Pipeline, and Shin Oak NGL Pipeline, serve Permian Basin and/or Rocky Mountain producers. On a combined basis, gross operating margin from these pipelines increased a net $2 million quarter-to-quarter primarily due to higher average transportation fees, which accounted for a $6 million increase, and higher other revenues, which accounted for an additional $5 million increase, partially offset by higher operating costs, which accounted for a $9 million decrease. Transportation volumes on these pipelines increased a combined 72 MBPD (net to our interest) quarter-to-quarter. Gross operating margin from our Dixie Pipeline and related terminals decreased $8 million quarter-to-quarter primarily due to higher maintenance and other operating costs. Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022 . Gross operating margin from our NGL pipelines, storage and terminal assets during the six months ended June 30, 2023 increased $183 million when compared to the six months ended June 30, 2022. Gross operating margin from LPG-related activities at EHT increased $37 million period-to-period primarily due to a 68 MBPD increase in LPG export volumes, which accounted for a $17 million increase, and higher average loading fees, which accounted for an additional $15 million increase. Gross operating margin at our Morgan’s Point Ethane Export Terminal increased $25 million period-to-period primarily due to a 30 MBPD increase in export volumes, which accounted for a $16 million increase, and higher average loading fees, which accounted for an additional $6 million increase. Gross operating margin from our related Houston Ship Channel Pipeline System increased $13 million period-to-period primarily due to a 124 MBPD increase in transportation volumes, which accounted for a $10 million increase, and higher average transportation fees, which accounted for an additional $5 million increase. On a combined basis gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased $33 million period-to-period   primarily due to a combined 61 MBPD increase in transportation volumes. Gross operating margin from our South Texas NGL Pipeline System increased $17 million period-to-period primarily due to higher average transportation fees, which accounted for a $6 million increase, higher pipeline capacity fee revenues, which accounted for a $5 million increase, and higher storage and other revenues, which accounted for an additional $5 million increase. Gross operating margin from our Chambers County storage complex increased $9 million period-to-period primarily due to lower operating costs. On a combined basis, gross operating margin for our pipelines that serve Permian Basin and/or Rocky Mountain producers increased a net $5 million period-to-period primarily due to higher other revenues, which accounted for a $12 million increase, higher average transportation fees, which accounted for a $7 million increase, and a 78 MBPD (net to our interest) increase in transportation volumes, which accounted for an additional $5 million increase, partially offset by higher maintenance and other operating costs, which accounted for a $19 million decrease. Gross operating margin from our Dixie Pipeline and related terminals decreased $10 million period-to-period primarily due to higher maintenance and other operating costs. 51 Table of Contents NGL fractionation Second Quarter of 2023 Compared to Second Quarter of 2022 . Gross operating margin from NGL fractionation during the second quarter of 2023 increased $1 million when compared to the second quarter of 2022. Gross operating margin from our Chambers County NGL fractionation complex increased a net $7 million quarter-to-quarter primarily due to lower utility and other operating costs, which accounted for a $35 million increase, and a 34 MBPD (net to our interest) increase in fractionation volumes, which accounted for an additional $6 million increase, partially offset by lower average fractionation fees, which accounted for an $18 million decrease, and lower ancillary service revenues, which accounted for an additional $16 million decrease. On a combined basis, gross operating margin from our other NGL fractionators decreased $7 million quarter-to-quarter primarily due to lower average fractionation fees. NGL fractionation volumes from our other NGL fractionators increased a combined 6 MBPD (net to our interest) quarter-to-quarter. Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022 . Gross operating margin from NGL fractionation during the six months ended June 30, 2023 decreased $47 million when compared to the six months ended June 30, 2022. Gross operating margin from our Chambers County NGL fractionation complex decreased a net $35 million period-to-period primarily due to lower ancillary services revenues, which accounted for a $41 million decrease, and lower average fractionation fees, which accounted for an additional $ 30 million decrease, partially offset by lower utility and other operating costs, which accounted for a $33 million increase. NGL fractionation volumes at our Chambers County NGL fractionation complex increased 15 MBPD (net to our interest) period-to-period. On a combined basis, gross operating margin from our other NGL fractionators decreased a net $16 million period-to-period primarily due to lower average fractionation fees, which accounted for an $11 million decrease, and lower ancillary service revenues, which accounted for an additional $9 million decrease, partially offset by a combined 31 MBPD (net to our interest) increase in NGL fractionation volumes, which accounted for a $6 million increase. 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, 2023 2022 2023 2022 Segment gross operating margin: Midland-to-ECHO System and related business activities $ 155 $ 96 $ 270 $ 197 Other crude oil pipelines, terminals and related marketing results 267 311 549 625 Total $ 422 $ 407 $ 819 $ 822 Selected volumetric data: Crude oil pipeline transportation volumes (MBPD) 2,366 2,197 2,332 2,197 Crude oil marine terminal volumes (MBPD) 814 777 829 786 Second Quarter of 2023 Compared to Second Quarter of 2022 . Gross operating margin from our Crude Oil Pipelines & Services segment for the second quarter of 2023 increased $15 million when compared to the second quarter of 2022. Gross operating margin from our Midland-to-ECHO System and related business activities increased a net $59 million quarter-to-quarter primarily due to higher average transportation fees and related margins from marketing activities, which accounted for a $45 million increase, and a 124 MBPD (net to our interest) increase in transportation volumes, which accounted for an additional $23 million increase, partially offset by higher utility, chemical and other operating costs, which accounted for a $4 million decrease. 52 Table of Contents Gross operating margin from our crude oil marketing activities (excluding those attributable to the Midland-to-ECHO System) increased $51 million quarter-to-quarter primarily due to higher non-cash, mark-to-market earnings, which accounted for a $33 million increase, and higher average sales margins, which accounted for an additional $20 million increase. Gross operating margin from our West Texas Pipeline System increased $42 million quarter-to-quarter primarily due to higher ancillary service and other revenues. Transportation volumes on our West Texas Pipeline System increased 17 MBPD quarter-to-quarter. Gross operating margin from our EFS Midstream System decreased $82 million quarter-to-quarter primarily due to lower deficiency revenues as a result of the expiration of minimum volume commitments under certain long-term gathering agreements at the end of June 2022, which accounted for a $54 million decrease, and lower average transportation fees, which accounted for an additional $20 million decrease. Our EFS Midstream System continues to transport volumes produced on dedicated acreage through the remaining term of these agreements, most of which have a life-of-lease duration. Gross operating margin from our South Texas Crude Oil Pipeline System decreased $30 million quarter-to-quarter primarily due to lower ancillary service and other revenues, which accounted for an $11 million decrease, lower deficiency revenues as a result of the expiration of minimum volume commitments under certain long-term agreements at the end of July 2022, which accounted for an $8 million decrease, and lower average transportation fees, which accounted for an additional $7 million decrease. Transportation volumes on our South Texas Crude Oil Pipeline System decreased 50 MBPD quarter-to-quarter. Gross operating margin from our equity investment in the Seaway Pipeline decreased $24 million quarter-to-quarter primarily due to lower ancillary service and other fee revenues. Transportation volumes on our Seaway Pipeline increased 52 MBPD (net to our interest) quarter-to-quarter. Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022 . Gross operating margin from our Crude Oil Pipelines & Services segment for the six months ended June 30, 2023 decreased $3 million when compared to the six months ended June 30, 2022. Gross operating margin from our crude oil marketing activities (excluding those attributable to the Midland-to-ECHO System) increased $95 million period-to-period primarily due to higher non-cash, mark-to-market earnings, which accounted for a $74 million increase, and higher average sales margins, which accounted for an additional $27 million increase. Gross operating margin from our West Texas Pipeline System increased $87 million period-to-period primarily due to higher ancillary service and other revenues. Transportation volumes on our West Texas Pipeline System increased 14 MBPD period-to-period. Gross operating margin from our Midland-to-ECHO System and related business activities increased a net $73 million period-to-period primarily due to higher average transportation fees and related margins from marketing activities, which accounted for a $49 million increase, and a 93 MBPD (net to our interest) increase in transportation volumes, which accounted for an additional $36 million increase, partially offset by higher utility, chemical and other operating costs, which accounted for a $10 million decrease. Gross operating margin from our EFS Midstream system decreased $157 million period-to-period primarily due to lower deficiency revenues as a result of the aforementioned expiration of minimum volume commitments, which accounted for a $108 million decrease, and lower average transportation fees, which accounted for an additional $41 million decrease. Gross operating margin from our South Texas Crude Oil Pipeline System decreased $42 million period-to-period primarily due to lower deficiency revenues as a result of the aforementioned expiration of minimum volume commitments, which accounted for a $15 million decrease, lower average transportation fees, which accounted for a $13 million decrease, and lower ancillary service and other revenues, which accounted for an additional $9 million decrease. Transportation volumes on our South Texas Crude Oil Pipeline System decreased 41 MBPD period-to-period. 53 Table of Contents Gross operating margin from our equity investment in the Seaway Pipeline decreased $42 million period-to-period primarily due to lower ancillary service and other fee revenues. Transportation volumes on our Seaway Pipeline increased 57 MBPD (net to our interest) period-to-period. Gross operating margin from our Midland terminal decreased $15 million period-to-period primarily due to lower ancillary service and other revenues, which accounted for a $9 million decrease, and higher operating costs, which accounted for an additional $8 million decrease. 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, 2023 2022 2023 2022 Segment gross operating margin $ 238 $ 229 $ 552 $ 449 Selected volumetric data: Natural gas pipeline transportation volumes (BBtus/d) 18,264 16,803 18,145 16,629 Second Quarter of 2023 Compared to Second Quarter of 2022 . Gross operating margin from our Natural Gas Pipelines & Services segment for the second quarter of 2023 increased $9 million when compared to the second quarter of 2022. Gross operating margin from our natural gas marketing activities increased $11 million quarter-to-quarter primarily due to higher average sales margins attributable to location price differentials. Gross operating margin from our East Texas Gathering System increased $8 million quarter-to-quarter primarily due to a 459 BBtus/d increase in gathering volumes. Gross operating margin from our Delaware Basin Gathering System increased $6 million quarter-to-quarter primarily due to higher average gathering fees. Natural gas gathering volumes on our Delaware Basin Gathering System increased 67 BBtus/d quarter-to-quarter. Gross operating margin from our Acadian Gas System increased $4 million quarter-to-quarter primarily due to lower maintenance and other operating costs. Transportation volumes on our Acadian Gas System increased 91 BBtus/d quarter-to-quarter. Gross operating margin from our Texas Intrastate System increased a net $2 million quarter-to-quarter primarily due a 793 BBtus/d increase in transportation volumes, which accounted for a $7 million increase, and higher average transportation fees, which accounted for an additional $5 million increase, partially offset by lower ancillary and other revenues, which accounted for a $10 million decrease. On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System, and San Juan Gathering System in the Rocky Mountains decreased $22 million quarter-to-quarter primarily due to lower average gathering fees on our San Juan Gathering System, which accounted for a $12 million decrease, a combined 126 BBtus/d decrease in gathering volumes, which accounted for a $3 million decrease, and higher maintenance and other operating costs, which accounted for an additional $3 million decrease. Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022 . Gross operating margin from our Natural Gas Pipelines & Services segment for the six months ended June 30, 2023 increased $103 million when compared to the six months ended June 30, 2022. Gross operating margin from our natural gas marketing activities increased $35 million period-to-period primarily due to higher average sales margins attributable to location price differentials. 54 Table of Contents Gross operating margin from our Texas Intrastate System increased a net $20 million period-to-period primarily due to higher average transportation fees, which accounted for a $19 million increase, and a 675 BBtus/d increase in transportation volumes, which accounted for an additional $14 million increase, partially offset by higher operating costs, which accounted for a $9 million decrease, and lower ancillary and other revenues, which accounted for an additional $4 million decrease. Gross operating margin from our East Texas Gathering System increased $13 million period-to-period primarily due to a 406 BBtus/d increase in gathering volumes. Gross operating margin from our Delaware Basin Gathering System increased $9 million period-to-period primarily due to a 165 BBtus/d increase in gathering volumes, which accounted for a $5 million increase, and higher average gathering fees, which accounted for an additional $3 million increase. On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System and San Juan Gathering System in the Rocky Mountains increased a net $6 million period-to-period primarily due to higher average gathering fees on our Jonah Gathering System and San Juan Gathering System, which accounted for a $19 million increase, partially offset by higher maintenance and other operating costs, which accounted for a $7 million decrease, and a decrease in condensate sales, which accounted for an additional $4 million decrease. Natural gas gathering volumes on our Rocky Mountain gathering systems decreased a combined 133 BBtus/d period-to-period. Gross operating margin from our Acadian Gas System increased $4 million period-to-period primarily due to lower maintenance and other operating costs. Transportation volumes on our Acadian Gas System increased 154 BBtus/d period-to-period. 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, 2023 2022 2023 2022 Segment gross operating margin: Propylene production and related activities $ 125 $ 154 $ 307 $ 364 Butane isomerization and related operations 36 28 62 54 Octane enhancement and related plant operations 92 144 177 204 Refined products pipelines and related activities 81 56 168 127 Ethylene exports and related activities 32 28 61 60 Marine transportation and other services 17 11 27 16 Total $ 383 $ 421 $ 802 $ 825 Selected volumetric data: Propylene production volumes (MBPD) 84 109 90 107 Butane isomerization volumes (MBPD) 120 115 109 103 Standalone deisobutanizer (“DIB”) processing volumes (MBPD) 174 162 163 156 Octane enhancement and related plant sales volumes (MBPD) (1) 37 42 31 38 Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD) 837 751 812 749 Marine terminal volumes, primarily refined products and petrochemicals (MBPD) 283 225 303 217 (1) Reflects aggregate sales volumes for our octane enhancement and iBDH facilities located at our Chambers County complex and our HPIB facility located adjacent to the Houston Ship Channel. Propylene production and related activities Second Quarter of 2023 Compared to Second Quarter of 2022 . Gross operating margin from propylene production and related activities for the second quarter of 2023 decreased $29 million when compared to the second quarter of 2022. 55 Table of Contents Gross operating margin from our Chambers County propylene production facilities decreased a combined $34 million quarter-to-quarter primarily due to lower average propylene sales margins, which accounted for a $23 million decrease, and lower propylene sales volumes, which accounted for an additional $13 million decrease. Propylene and associated by-product production volumes at these facilities decreased a combined 25 MBPD (net to our interest) quarter-to-quarter primarily due to planned major maintenance activities at three of our propylene splitters during the second quarter of 2023. Gross operating margin from our propylene pipeline systems increased a combined $6 million quarter-to-quarter primarily due to higher average transportation fees. On a combined basis, transportation volumes were flat (net to our interest) quarter-to-quarter. Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022 . Gross operating margin from propylene production and related activities for the six months ended June 30, 2023 decreased $57 million when compared to the six months ended June 30, 2022. Gross operating margin from our Chambers County propylene production facilities decreased a combined $71 million period-to-period primarily due to lower propylene sales volumes, which accounted for a $48 million decrease, and lower average propylene sales margins, which accounted for an additional $29 million decrease. Propylene and associated by-product production volumes at these facilities decreased a combined 17 MBPD (net to our interest) period-to-period primarily due to planned major maintenance activities at our PDH 1 facility during the first quarter of 2023 and planned major maintenance at three of our propylene splitters during the second quarter of 2023. Gross operating margin from our propylene pipeline systems increased a combined $9 million period-to-period primarily due to higher average transportation fees. On a combined basis, transportation volumes decreased 5 MBPD (net to our interest) period-to-period. Butane isomerization and related operations Second Quarter of 2023 Compared to Second Quarter of 2022 . Gross operating margin from butane isomerization and related operations increased $8 million quarter-to-quarter primarily due to lower utility and other operating costs. Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022 . Gross operating margin from butane isomerization and related operations increased $8 million period-to-period primarily due to lower utility and other operating costs. Octane enhancement and related plant operations Second Quarter of 2023 Compared to Second Quarter of 2022 . Gross operating margin from our octane enhancement and related plant operations for the second quarter of 2023 decreased a net $52 million when compared to the second quarter of 2022 primarily due to lower average sales margins, which accounted for a $38 million decrease, and lower sales volumes, which accounted for an additional $20 million decrease, partially offset by lower utility and other operating costs, which accounted for a $6 million increase. Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022 . Gross operating margin from our octane enhancement and related plant operations during the six months ended June 30, 2023 decreased $27 million when compared to the six months ended June 30, 2022 primarily due to lower sales volumes, which accounted for a $15 million decrease, and lower average sales margins, which accounted for an additional $14 million decrease. Refined products pipelines and related activities Second Quarter of 2023 Compared to Second Quarter of 2022 . Gross operating margin from refined products pipelines and related activities for the second quarter of 2023 increased $25 million when compared to the second quarter of 2022. Gross operating margin from our refined products marketing activities increased $26 million quarter-to-quarter primarily due to higher average sales margins. Gross operating margin from our refined products terminal in Beaumont, Texas increased $5 million quarter-to-quarter primarily due to higher storage and other fee revenues. Refined product marine terminal volumes at Beaumont increased 68 MBPD quarter-to-quarter. 56 Table of Contents Gross operating margin from our TE Products Pipeline System decreased $8 million quarter-to-quarter primarily due to higher operating costs. Overall, transportation volumes on our TE Products Pipeline System increased a net 51 MBPD quarter-to-quarter. Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022 . Gross operating margin from refined products pipelines and related activities for the six months ended June 30, 2023 increased $41 million when compared to the six months ended June 30, 2022. Gross operating margin from our refined products marketing activities increased $50 million period-to-period primarily due to higher average sales margins. Gross operating margin from our refined products terminal in Beaumont, Texas increased $11 million period-to-period primarily due to higher storage and other fee revenues. Refined product marine terminal volumes at Beaumont increased 99 MBPD period-to-period. Gross operating margin from our TE Products Pipeline System decreased $24 million period-to-period primarily due to higher operating costs. Overall, transportation volumes on our TE Products Pipeline System increased a net 38 MBPD period-to-period. Ethylene exports and related activities Second Quarter of 2023 Compared to Second Quarter of 2022 . Gross operating margin from ethylene exports and related activities during the second quarter of 2023 increased a net $4 million when compared to the second quarter of 2022. Gross operating margin from our ethylene pipelines, storage and related marketing activities increased a combined $6 million quarter-to-quarter primarily due to higher transportation, storage and other fee revenues, which accounted for a $3 million increase, and higher average sales margins, which accounted for an additional $2 million increase. Gross operating margin from our ethylene export terminal decreased $2 million quarter-to-quarter primarily due to lower average loading fees. Ethylene transportation volumes and ethylene export volumes increased 17 MBPD and 1 MBPD, respectively, quarter-to-quarter (net to our interest). Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022 . Gross operating margin from ethylene exports and related activities during the six months ended June 30, 2023 increased a net $1 million when compared to the six months ended June 30, 2022. Gross operating margin from our ethylene pipelines, storage and related marketing activities increased a combined $6 million period-to-period primarily due to higher transportation, storage and other fee revenues, which accounted for a $4 million increase, and higher sales volumes, which accounted for an additional $2 million increase. Gross operating margin from our ethylene export terminal decreased $5 million period-to-period primarily due to lower average loading fees. Ethylene transportation volumes increased 15 MBPD and ethylene export volumes were flat period-to-period (net to our interest). Marine transportation and other services Second Quarter of 2023 Compared to Second Quarter of 2022 . Gross operating margin from marine transportation and other services increased $6 million quarter-to-quarter primarily due to higher average fees and fleet utilization rates. Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022 . Gross operating margin from marine transportation and other services increased a net $11 million period-to-period primarily due to higher average fees, which accounted for an $11 million increase, and higher fleet utilization rates, which accounted for an additional $6 million increase, partially offset by higher operating costs, which accounted for a $6 million decrease. Liquidity and Capital Resources Based on current market conditions (as of the filing date of this quarterly report), we believe that the Partnership and its consolidated businesses will have sufficient liquidity, cash flow from operations and access to capital markets to fund their capital investments and working capital needs for the reasonably foreseeable future. At June 30, 2023, we had $4.0 billion of consolidated liquidity. This amount was comprised of $3.8 billion of available borrowing capacity under EPO’s revolving credit facilities, which is the net of $4.2 billion of total borrowing capacity under EPO’s revolving credit facilities and $355 million outstanding under EPO’s commercial paper program, and $183 million of unrestricted cash on hand. 57 Table of Contents We may issue debt and equity securities to assist us in meeting our future funding and liquidity requirements, including those related to capital investments. We have a universal shelf registration statement on file with the SEC which allows the Partnership and EPO to issue an unlimited amount of equity and debt securities, respectively. Enterprise Declares Cash Distribution for Second Quarter of 2023 On July 10, 2023, we announced that the Board declared a quarterly cash distribution of $0.50 per common unit, or $2.00 per unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the second quarter of 2023. The quarterly distribution is payable on August 14, 2023 to unitholders of record as of the close of business on July 31, 2023. The total amount to be paid is $1.1 billion, which includes $10 million for distribution equivalent rights on phantom unit awards. The payment of quarterly cash distributions is subject to management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments and Board approval. Management will evaluate any future increases in cash distributions on a quarterly basis. Consolidated Debt At June 30, 2023, the average maturity of EPO’s consolidated debt obligations was approximately 19.7 years. The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at June 30, 2023 for the years indicated (dollars in millions): Scheduled Maturities of Debt Total Remainder of 2023 2024 2025 2026 2027 Thereafter Commercial Paper Notes $ 355 $ 355 $ – $ – $ – $ – $ – Senior Notes 26,275 – 850 1,150 1,625 575 22,075 Junior Subordinated Notes 2,296 – – – – – 2,296 Total $ 28,926 $ 355 $ 850 $ 1,150 $ 1,625 $ 575 $ 24,371 In January 2023, EPO issued $1.75 billion aggregate principal amount of senior notes comprised of (i) $750 million principal amount of senior notes due January 2026 (“Senior Notes FFF”) and (ii) $1.0 billion principal amount of senior notes due January 2033 (“Senior Notes GGG”). Senior Notes FFF were issued at 99.893% of their principal amount and have a fixed-rate interest rate of 5.05% per year. Senior Notes GGG were issued at 99.803% of their principal amount and have a fixed-rate interest rate of 5.35% per year. Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of all of our $1.25 billion principal amount of 3.35% Senior Notes HH at their maturity in March 2023 and amounts outstanding under our commercial paper program). In March 2023, EPO entered into a new 364-Day Revolving Credit Agreement (the “March 2023 $1.5 Billion 364-Day Revolving Credit Agreement”) that replaced its September 2022 364-Day Revolving Credit Agreement. The March 2023 $1.5 Billion 364-Day Revolving Credit Agreement matures in March 2024. EPO’s borrowing capacity was unchanged from the prior 364-day revolving credit agreement. As of June 30, 2023, there are no principal amounts outstanding under this new revolving credit agreement. In March 2023, EPO entered into a new revolving credit agreement that matures in March 2028 (the “March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement”). The March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement replaced EPO’s prior multi-year revolving credit agreement that was scheduled to mature in September 2026. We proposed to reduce EPO’s borrowing capacity from $3.0 billion under the prior multi-year revolving credit agreement to $2.7 billion under the March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement. Under the new agreement, EPO retains the right to increase its borrowing capacity by up to $500 million to $3.2 billion, provided certain conditions for the election are met. As of June 30, 2023, there are no principal amounts outstanding under this new revolving credit agreement. For additional information regarding our consolidated debt obligations, see Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report. 58 Table of Contents Credit Ratings As of August 9 , 2023, the investment-grade credit ratings of EPO’s long-term senior unsecured debt securities were A- 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. Common Unit Repurchases Under 2019 Buyback Program In January 2019, we announced that the Board had approved a $2.0 billion multi-year unit buyback program (the “2019 Buyback Program”), which provides the Partnership with an additional method to return capital to investors. The Partnership repurchased 2,910,121 and 3,592,710 common units through open market purchases during the three and six months ended June 30, 2023, respectively. The total cost of these repurchases, including commissions and fees, was $ 75 million and $ 92 million, respectively . As of June 30, 2023, the remaining available capacity under the 2019 Buyback Program was $ 1.2 billion. Cash Flow Statement Highlights The following table summarizes our consolidated cash flows from operating, investing and financing activities for the periods indicated (dollars in millions). For the Six Months Ended June 30, 2023 2022 Net cash flows provided by operating activities $ 3,485 $ 4,264 Cash used in investing activities 1,402 3,868 Cash used in financing activities 2,012 2,964 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, petrochemicals 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, public health emergencies, adverse weather conditions and government regulations affecting prices and production levels. We may also incur credit and price risk to the extent customers do not fulfill their contractual obligations to us in connection with our marketing activities and long-term take-or-pay and dedication agreements. For a more complete discussion of these and other risk factors pertinent to our business, see “ Risk Factors ” included under Part I, Item 1A of the 2022 Form 10-K. 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. The following information highlights significant quarter-to-quarter fluctuations in our consolidated cash flow amounts: Operating activities Net cash flows provided by operating activities for the six months ended June 30, 2023 decreased $ 779 million when compared to the six months ended June 30, 2022 primarily due to: • a $ 621 mill ion period-to-period decrease from changes in operating accounts primarily due to the use of working capital employed in our marketing activities, which includes the impact of (i) fluctuations in commodity prices, (ii) timing of our inventory purchase and sale strategies, and (iii) changes in margin deposit requirements associated with our commodity derivative instruments; and 59 Table of Contents • a $ 151 million period-to-period decrease resulting from lower partnership earnings (determined by adjusting our $ 66 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). 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 during the six months ended June 30, 2023 decreased a net $ 2.5 billion when compared to the six months ended June 30,   2022 primarily due to: • a net $ 3.2 billion cash outflow in February 2022 in connection with the acquisition of our Midland Basin System; partially offset by • a $ 702 million period-to-period increase in investments for property, plant and equipment (see “ Capital Investments ” within this Part I, Item 2 for additional information). Financing activities Cash used in financing activities during the six months ended June 30, 2023 decreased a net $ 952 million when compared to the six months ended June 30,   2022 primarily due to: • a net cash inflow of $ 361 million related to debt transactions that occurred during the six months ended June 30, 2023 compared to a net cash outflow of $760 million related to debt transactions that occurred during the six months ended June 30, 2022. During the six months ended June 30, 2023, we issued $1.75 billion aggregate principal amount of senior notes, partially offset by the repayment of $1.25 billion principal amount of senior notes and net repayments of $ 140 million under EPO’s commercial paper program. During the six months ended June 30, 2022, we repaid $ 1.4 billion aggregate principal amount of senior notes, partially offset by net issuances of $640 million under EPO’s commercial paper program; partially offset by • a $ 103 million period-to-period increase in cash distributions paid to common unitholders primarily attributable to increases in the quarterly cash distribution rate per unit. Non-GAAP Cash Flow Measures Distributable Cash Flow Our partnership agreement requires us to make quarterly distributions to our common unitholders of all available cash, after any cash reserves established by Enterprise GP in its sole discretion. Cash reserves include those for the proper conduct of our business, including those for capital investments, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other amounts. The retention of cash allows us to reinvest in our growth and reduce our future reliance on the equity and debt capital markets. We measure available cash by reference to distributable cash flow (“DCF”), which is a non-GAAP cash flow measure. DCF is an important financial measure for our common unitholders since it serves as an indicator of our success in providing a cash return on investment. 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 common unitholders. 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, which has sole authority in approving such matters. Enterprise GP has a non-economic ownership interest in the Partnership and is not entitled to receive any cash distributions from it based on incentive distribution rights or other equity interests. 60 Table of Contents Our use of DCF for the limited purposes described above and in this quarterly report is not a substitute for net cash flows provided by operating activities, which is the most comparable GAAP measure to DCF. For a discussion of net cash flows provided by operating activities, see “ Cash Flow Statement Highlights ” within this Part I, Item 2. 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, 2023 2022 2023 2022 Net income attributable to common unitholders (GAAP) (1) $ 1,253 $ 1,411 $ 2,643 $ 2,707 Adjustments to net income attributable to common unitholders to derive DCF (addition or subtraction indicated by sign): Depreciation, amortization and accretion expenses 576 566 1,143 1,117 Cash distributions received from unconsolidated affiliates (2) 128 159 247 279 Equity in income of unconsolidated affiliates (121 ) (107 ) (225 ) (224 ) Asset impairment charges 3 5 16 19 Change in fair market value of derivative instruments 7 52 10 94 Deferred income tax expense (benefit) (11 ) 7 (8 ) 16 Sustaining capital expenditures (3) (101 ) (82 ) (185 ) (157 ) Other, net (3 ) 4 5 (10 ) Operational DCF (4) $ 1,731 $ 2,015 $ 3,646 $ 3,841 Proceeds from asset sales and other matters 4 3 6 14 Monetization of interest rate derivative instruments accounted for as cash flow hedges ‒ ‒ 21 ‒ DCF (non-GAAP) $ 1,735 $ 2,018 $ 3,673 $ 3,855 Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards $ 1,096 $ 1,044 $ 2,171 $ 2,067 Cash distribution per common unit declared by Enterprise GP with respect to period (5) $ 0.5000 $ 0.4750 $ 0.9900 $ 0.9400 Total DCF retained by the Partnership with respect to period (6) $ 639 $ 974 $ 1,502 $ 1,788 Distribution coverage ratio (7) 1.6 x 1.9 x 1.7 x 1.9 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 aggregate distributions received from unconsolidated affiliates attributable to both earnings and the return of capital. (3) Sustaining capital expenditures include cash payments and accruals applicable to the period. (4) Represents DCF before proceeds from asset sales and the monetization of interest rate derivative instruments accounted for as cash flow hedges. (5) See Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for information regarding our cash distributions declared with respect to the periods indicated. (6) Cash retained by the Partnership may be used for capital investments, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other amounts. The retention of cash reduces our reliance on the capital markets. (7) Distribution coverage ratio is determined by dividing DCF by total cash distributions paid to common unitholders and in connection with distribution equivalent rights with respect to the period. 61 Table of Contents 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, 2023 2022 2023 2022 Net cash flows provided by operating activities (GAAP) $ 1,902 $ 2,119 $ 3,485 $ 4,264 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 (36 ) (27 ) 403 (218 ) Sustaining capital expenditures (101 ) (82 ) (185 ) (157 ) Distributions received from unconsolidated affiliates attributable to the return of capital 15 44 30 55 Proceeds from asset sales and other matters 4 3 6 14 Net income attributable to noncontrolling interests (29 ) (28 ) (60 ) (62 ) Monetization of interest rate derivative instruments accounted for as cash flow hedges ‒ ‒ 21 ‒ Other, net (20 ) (11 ) (27 ) (41 ) DCF (non-GAAP) $ 1,735 $ 2,018 $ 3,673 $ 3,855 Capital Investments During the second quarter of 2023, we completed the 400 MMcf/d expansion of our Acadian Gas System. In addition, PDH 2, Frac XII and our Poseidon natural gas processing plant were placed into service in July 2023. We have approximately $4.1 billion of growth capital projects scheduled to be completed by the first half of 2026, including the following major projects (including their respective scheduled completion dates): • natural gas gathering expansion projects in the Delaware and Midland Basins (2023 and 2024); • our Mentone II natural gas processing plant in the Delaware Basin (fourth quarter of 2023); • our Texas Western Products System, created by repurposing a portion of our Mid-America Pipeline System’s Rocky Mountain segment and adding westbound service to our Chaparral Pipeline business to transport refined products from the U.S. Gulf Coast to markets in West Texas, New Mexico, Colorado and Utah (fourth quarter of 2023 through second quarter of 2024); • our Mentone III natural gas processing plant in the Delaware Basin (first quarter of 2024); • our Leonidas natural gas processing plant in the Midland Basin (first quarter of 2024); • the expansion of our LPG and PGP export capacity at EHT (first half of 2025); • the expansion of our Shin Oak NGL Pipeline (first half of 2025); • an Ethane and Propane Export Terminal located in Orange County, Texas (second half of 2025 and first half of 2026); and • an expansion of our Morgan’s Point terminal to increase ethylene export capacity (second half of 2024 and second half of 2025). Based on information currently available, we expect our total capital investments for 2023, net of contributions from noncontrolling interests, to approximate $2.8   billion to $3.2 billion, which reflects growth capital investments of $2.4   billion to $2.8 billion and sustaining capital expenditures of $400   million. These amounts do not include capital investments associated with our proposed deep-water offshore crude oil terminal (the Sea Port Oil Terminal, or “SPOT”), which remains subject to state and federal permitting, mitigation and related requirements. We received a favorable Record of Decision from the Department of Transportation’s Maritime Administration for SPOT during the fourth quarter of 2022; however, we can give no assurance as to when or whether the project will ultimately be authorized to begin construction or operation. 62 Table of Contents Our forecast of capital investments is 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 resulting from raw material or labor shortages, supply chain disruptions or inflation. Furthermore, our forecast of capital investments may change over time based on future decisions by management, which may include changing the scope or timing of projects or cancelling projects altogether. Our success in raising capital, having the ability to increase revenues commensurate with cost increases and our ability to partner with other companies to share project costs and risks, continue to be significant factors 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 currently expect to make the forecast capital investments noted above, we may revise our plans in response to changes in economic and capital market conditions. The following table summarizes our capital investments for the periods indicated (dollars in millions): For the Six Months Ended June 30, 2023 2022 Capital investments for property, plant and equipment: (1) Growth capital projects (2) $ 1,227 $ 564 Sustaining capital projects (3) 206 167 Total $ 1,433 $ 731 Cash used for business combinations, net (4) $ – $ 3,204 (1) Growth and sustaining capital amounts presented in the table above are presented on a cash basis. In total, these amounts represent “Capital expenditures” as presented on our Unaudited Condensed Statements of Consolidated Cash Flows. (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 projects are capital expenditures (as defined by GAAP) resulting from improvements to existing assets. Such expenditures serve to maintain existing operations but do not generate additional revenues or result in significant cost savings. Sustaining capital expenditures include the costs of major maintenance activities at our reaction-based plants, which are accounted for using the deferral method. (4) Amount for the six months ended June 30, 2022 represents net cash used for the acquisition of our Midland Basin System, which closed on February 17, 2022. Comparison of Six Months Ended June 30, 2023 with Six Months Ended June 30, 2022 In total, investments in growth capital projects increased $663 million period-to-period primarily due to the following: • higher investments in natural gas processing and related pipeline projects in the Permian Basin (e.g., construction of four natural gas processing plants and related gathering systems), which accounted for a $425 million increase; • higher investments in our Texas Western Products System, which accounted for an $88 million increase; • higher investments in ethane, LPG and ethylene export expansion projects at our Gulf Coast terminals, which accounted for an $83 million increase; and • higher investments in Frac XII at our Chambers County complex, which accounted for an additional $68 million increase. Investments attributable to sustaining capital projects increased $39 million period-to-period primarily due to fluctuations in timing and costs of pipeline integrity and similar projects. 63 Table of Contents Critical Accounting Policies and Estimates A discussion of our critical accounting policies and estimates is included in our 2022 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: • valuation of assets and liabilities acquired in a business combination • depreciation methods and estimated useful lives of property, plant and equipment; • measuring recoverability of long-lived assets and fair value of equity method investments; • amortization methods of customer relationships and contract-based intangible assets; • methods we employ to measure the fair value of goodwill and related assets; 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. Other Matters Parent-Subsidiary Guarantor Relationship The Partnership (the “Parent Guarantor”) has guaranteed the payment of principal and interest on the consolidated debt obligations of EPO (the “Subsidiary Issuer”), with the exception of the remaining debt obligations of TEPPCO Partners, L.P. (collectively, the “Guaranteed Debt”). If EPO were to default on any of its Guaranteed Debt, the Partnership would be responsible for full and unconditional repayment of such obligations. At June 30, 2023, the total amount of Guaranteed Debt was $29.4 billion, which was comprised of $26.3 billion of EPO’s senior notes, $2.3 billion of EPO’s junior subordinated notes, $355 million of short-term commercial paper notes and $458 million of related accrued interest. The Partnership’s guarantees of EPO’s senior note obligations, commercial paper notes and borrowings under bank credit facilities represent unsecured and unsubordinated obligations of the Partnership that rank equal in right of payment to all other existing or future unsecured and unsubordinated indebtedness of the Partnership. In addition, these guarantees effectively rank junior in right of payment to any existing or future indebtedness of the Partnership that is secured and unsubordinated, to the extent of the assets securing such indebtedness. The Partnership’s guarantees of EPO’s junior subordinated notes represent unsecured and subordinated obligations of the Partnership that rank equal in right of payment to all other existing or future subordinated indebtedness of the Partnership and senior in right of payment to all existing or future equity securities of the Partnership. The Partnership’s guarantees of EPO’s junior subordinated notes effectively rank junior in right of payment to (i) any existing or future indebtedness of the Partnership that is secured, to the extent of the assets securing such indebtedness and (ii) all other existing or future unsecured and unsubordinated indebtedness of the Partnership. The Partnership may be released from its guarantee obligations only in connection with EPO’s exercise of its legal or covenant defeasance options as described in the underlying agreements. 64 Table of Contents Selected Financial Information of Obligor Group The following tables present summarized financial information of the Partnership (as Parent Guarantor) and EPO (as Subsidiary Issuer) on a combined basis (collectively, the “Obligor Group”), after the elimination of intercompany balances and transactions among the Obligor Group. In accordance with Rule 13.01 of Regulation S-X, the summarized financial information of the Obligor Group excludes the Obligor Group’s equity in income and investments in the consolidated subsidiaries of EPO that are not party to the guarantee obligations (the “Non-Obligor Subsidiaries”). The total carrying value of the Obligor Group’s investments in the Non-Obligor Subsidiaries was $47.3 billion at June 30, 2023. The Obligor Group’s equity in the earnings of the Non-Obligor Subsidiaries for the six months ended June 30, 2023 was $2.7 billion. Although the net assets and earnings of the Non-Obligor Subsidiaries are not directly available to the holders of the Guaranteed Debt to satisfy the repayment of such obligations, there are no significant restrictions on the ability of the Non-Obligor Subsidiaries to pay distributions or make loans to EPO or the Partnership. EPO exercises control over the Non-Obligor Subsidiaries. We continue to believe that the unaudited condensed consolidated financial statements of the Partnership presented under Part I, Item 1 of this quarterly report provide a more appropriate view of our credit standing. Our investment grade credit ratings are based on the Partnership’s consolidated financial statements and not the Obligor Group’s financial information presented below. The following table presents summarized balance sheet information for the combined Obligor Group at the dates indicated (dollars in millions): Selected asset information: June 30, 2023 December 31, 2022 Current receivables from Non-Obligor Subsidiaries $ 1,177 $ 1,012 Other current assets 3,854 4,949 Long-term receivables from Non-Obligor Subsidiaries 187 187 Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries of $47.3 billion at June 30, 2023 and $47.5 billion at December 31, 2022 9,190 9,130 Selected liability information: Current portion of Guaranteed Debt, including interest of $458 million at June 30, 2023 and $426 million at December 31, 2022 $ 1,662 $ 2,171 Current payables to Non-Obligor Subsidiaries 1,206 1,899 Other current liabilities 2,999 4,121 Noncurrent portion of Guaranteed Debt, principal only 27,707 26,807 Noncurrent payables to Non-Obligor Subsidiaries 39 38 Other noncurrent liabilities 87 98 Mezzanine equity of Obligor Group: Preferred units $ 49 $ 49 The following table presents summarized income statement information for the combined Obligor Group for the periods indicated (dollars in millions): For the Six Months Ended June 30, 2023 For the Twelve Months Ended December 31, 2022 Revenues from Non-Obligor Subsidiaries $ 7,845 $ 14,145 Revenues from other sources 7,335 27,312 Operating income of Obligor Group 536 836 Net income (loss) of Obligor Group excluding equity in earnings of Non-Obligor Subsidiaries of $2.7 billion for the six months ended June 30, 2023 and $5.9 billion for the twelve months ended December 31, 2022 (97 ) (450 ) Related Party Transactions For information regarding our related party transactions, see Note 14 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report. 65 Table of Contents ITEM 3. QUANT ITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. General In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. In order to manage risks associated with assets, liabilities and certain anticipated future transactions, we use derivative instruments such as futures, forward contracts, swaps and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities. We assess the risk associated with each of our derivative instrument portfolios using a sensitivity analysis model. This approach measures the change in fair value of the derivative instrument portfolio based on a hypothetical 10% change in the underlying interest rates or quoted market prices on a particular day. In addition to these variables, the fair value of each portfolio is influenced by changes in the notional amounts of the instruments outstanding and the discount rates used to determine the present values. The sensitivity analysis approach does not reflect the impact that the same hypothetical price movement would have on the hedged exposures to which they relate. Therefore, the impact on the fair value of a derivative instrument resulting from a change in interest rates or quoted market prices (as applicable) would normally be offset by a corresponding gain or loss on the hedged debt instrument, inventory value or forecasted transaction assuming: • the derivative instrument functions effectively as a hedge of the underlying risk; • the derivative instrument is not closed out in advance of its expected term; and • the hedged forecasted transaction occurs within the expected time period. We routinely review the effectiveness of our derivative instrument portfolios in light of current market conditions. Accordingly, the nature and volume of our derivative instruments may change depending on the specific exposure being managed. 66 Table of Contents Commodity Hedging Activities The price of energy commodities such as natural gas, NGLs, crude oil, petrochemicals and refined products and power are subject to fluctuations in response to changes in supply and demand, market conditions and a variety of additional factors that are beyond our control. In order to manage such price risks, we enter into commodity derivative instruments such as physical forward contracts, futures contracts, fixed-for-float swaps and basis swaps. At June 30, 2023, our predominant commodity hedging strategies consisted of (i) hedging anticipated future purchases and sales of commodity products associated with transportation, storage and blending activities, (ii) hedging natural gas processing margins, (iii) hedging the fair value of commodity products held in inventory and (iv) hedging anticipated future purchases of power for certain operations in Southeast Texas. For a summary of our portfolio of commodity derivative instruments outstanding, see Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report. Sensitivity Analysis The following tables show the effect of hypothetical price movements on the estimated fair values of our principal commodity derivative instrument portfolios at the dates indicated (dollars in millions). The fair value information presented in the sensitivity analysis tables excludes the impact of applying Chicago Mercantile Exchange (“CME”) Rule 814, which deems that financial instruments cleared by the CME are settled daily in connection with variation margin payments. As a result of this exchange rule, CME-related derivatives are considered to have no fair value at the balance sheet date for financial reporting purposes; however, the derivatives remain outstanding and subject to future commodity price fluctuations until they are settled in accordance with their contractual terms. Derivative transactions cleared on exchanges other than the CME (e.g., the Intercontinental Exchange or ICE) continue to be reported on a gross basis. Natural gas marketing portfolio Portfolio Fair Value at Scenario Resulting Classification December 31, 2022 June 30, 2023 July 14, 2023 Fair value assuming no change in underlying commodity prices Asset (Liability) $ 90 $ 2 $ 4 Fair value assuming 10% increase in underlying commodity prices Asset (Liability) 97 1 3 Fair value assuming 10% decrease in underlying commodity prices Asset (Liability) 83 3 4 NGL and refined products marketing, natural gas processing and octane enhancement portfolio Portfolio Fair Value at Scenario Resulting Classification December 31, 2022 June 30, 2023 July 14, 2023 Fair value assuming no change in underlying commodity prices Asset (Liability) $ 18 $ 78 $ 28 Fair value assuming 10% increase in underlying commodity prices Asset (Liability) (29 ) 20 (27 ) Fair value assuming 10% decrease in underlying commodity prices Asset (Liability) 64 136 83 Crude oil marketing portfolio Portfolio Fair Value at Scenario Resulting Classification December 31, 2022 June 30, 2023 July 14, 2023 Fair value assuming no change in underlying commodity prices Asset (Liability) $ 53 $ 36 $ 13 Fair value assuming 10% increase in underlying commodity prices Asset (Liability) 24 (2 ) ‒ Fair value assuming 10% decrease in underlying commodity prices Asset (Liability) 81 75 26 Commercial energy derivative portfolio Portfolio Fair Value at Scenario Resulting Classification December 31, 2022 June 30, 2023 July 14, 2023 Fair value assuming no change in underlying commodity prices Asset (Liability) $ (38 ) $ (26 ) $ (16 ) Fair value assuming 10% increase in underlying commodity prices Asset (Liability) (10 ) (5 ) 7 Fair value assuming 10% decrease in underlying commodity prices Asset (Liability) (63 ) (48 ) (39 ) 67 Table of Contents Interest Rate Hedging Activities We may utilize interest rate swaps, forward-starting swaps, options to enter into forward-starting swaps (“swaptions”), and similar derivative instruments to manage our exposure to changes in interest rates charged on borrowings under certain consolidated debt agreements. This strategy may be used in controlling our overall cost of capital associated with such borrowings. As of the filing date of this quarterly report, we do not have any interest rate hedging instruments outstanding.