What changed in this filing

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Item 2. Management’s Discussion and Analysis

2021-11-08 compared with 2021-08-09 · 308 added, 281 removed, 516 unchanged (53% of the section changed)

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RESULTS OF OPERATIONS.

For the Three and Six Months Ended June 30, 2021 and 2020

For the Three and Nine Months Ended September 30, 2021 and 2020

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

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Cautionary Statement Regarding Forward-Looking Information

This quarterly report on Form 10-Q for the six months ended June 30, 2021 (our “quarterly report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us.

This quarterly report on Form 10-Q for the nine months ended September 30, 2021 (our “quarterly report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us.

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

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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 32.1% of the Partnership’s common units outstanding at June 30, 2021.

EPCO, together with its privately held affiliates, owned approximately 32.2% of the Partnership’s common units outstanding at September 30, 2021.

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

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trillion British thermal units

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

Likewise, the phrase “period-to-period” means the six months ended June 30, 2021 compared to the six months ended June 30, 2020.

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

Likewise, the phrase “period-to-period” means the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020.

Business Summary

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All references to U.S.

Energy Information Administration (“EIA”) forecasts and expectations are derived from its July 2021 Short-Term Energy Outlook (“July 2021 STEO”), which was published on July 7, 2021 .

Energy Information Administration (“EIA”) forecasts and expectations are derived from its October 2021 Short-Term Energy Outlook (“October 2021 STEO”), which was published on October 13, 2021 .

The forecasts and other forward-looking information cited in the following discussion remain subject to uncertainty since global mitigation efforts and medical developments related to COVID-19 continue to evolve.

We believe that the underlying trends described in our 2020 Form 10-K pertaining to hydrocarbon supply and demand fundamentals remain generally intact.

Hydrocarbon demand has rebounded in many regions across the globe as vaccination programs are implemented on a wider scale and many countries have eased their COVID-19 containment measures.

With respect to hydrocarbon supplies, ongoing production quotas within the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (collectively, the “OPEC+” group), along with market-induced discipline in U.S., Brazilian and Canadian supplies, continue to support near-term international energy markets.

The increase in global hydrocarbon demand and restrained crude oil production has contributed to a dramatic rise in crude oil prices since the beginning of 2021.

For example, the price of West Texas Intermediate (“WTI”) at Cushing, Oklahoma (as reported by the NYMEX) averaged $71.35 per barrel in June 2021 compared to $52.10 per barrel in January 2021.

The average price for WTI at Cushing in 2020 was $39.34 per barrel.

From a supply perspective, the EIA estimates that global production of petroleum and related liquids averaged 94.2 MMBPD in 2020, and expects an average of 96.7 MMBPD in 2021 and 101.8 MMBPD in 2022.

The EIA expects U.S.

drilling activity to rise slightly over the remainder of 2021 in response to supportive price levels, with production forecast to average 11.3 MMBPD in the fourth quarter of 2021 compared to an average of 11.2 MMBPD in the second quarter of 2021.

Overall, the EIA forecasts U.S.

crude oil production to average 11.1 MMBPD in 2021 and 11.9 MMBPD in 2022.

By comparison, the EIA estimates that U.S.

crude oil production averaged 10.9 MMBPD in the fourth quarter of 2020.

Likewise, the EIA expects U.S.

natural gas production to increase, especially in the Permian Basin region, and to average 92.6 Bcf/d in 2021 and 94.7 Bcf/d in 2022, compared to an estimated 91.4 Bcf/d in 2020.

With respect to demand, the EIA estimates that global demand for petroleum and related liquids averaged 92.3 MMBPD in 2020, and expects an average of 97.6 MMBPD in 2021 and 101.4 MMBPD in 2022.

Per the EIA, the consumption of petroleum and related liquids in the U.S.

averaged 18.1 MMBPD in 2020, and is forecast to average 19.6 MMBPD and 20.7 MMBPD in 2021 and 2022, respectively.

The current improvement in energy fundamentals (and global economic conditions in general) remain highly dependent on the successful containment of COVID-19, especially its more contagious emerging variants (e.g., the “Delta” variant), through the distribution, acceptance and administration of proven vaccines and therapeutics for the disease.

We continue to believe that our integrated, diversified and fee-based business model will enable us to successfully traverse this extraordinary period in the energy industry.

The Partnership and its consolidated operations remain in a strong position, with our financial strength and operational flexibility demonstrated by $ 5.4 billion of consolidated liquidity at June 30, 2021, investment grade credit ratings on EPO’s long-term senior unsecured debt, a disciplined capital spending approach, the optimization of our assets to provide incremental services to customers and to respond to market opportunities, and a portfolio of diverse, high quality customers.

The outlook on business conditions in our 2020 Form 10-K addressed observations that production cuts within the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (collectively, the “OPEC+” group), along with market-driven cuts in U.S., Brazilian and Canadian supplies, were providing much-needed support for international energy markets coping with the ongoing weakness in hydrocarbon demand attributable to the COVID-19 pandemic.

We also discussed downstream demand beginning to recover from the lows of 2020, but remaining depressed due to the continued effects of the pandemic.

Throughout the first half of 2021, we highlighted the positive impact that the widespread implementation of vaccination programs and the related easing of COVID-19 mobility restrictions have had on global hydrocarbon demand and stated our belief that energy fundamentals (and global economic conditions in general) remained highly dependent on the successful containment of COVID-19, especially its more contagious emerging variants (e.g., the “Delta” variant), through the distribution, acceptance and administration of proven vaccines and therapeutics for the disease.

While we maintain our view that the successful containment of COVID-19 is crucial to sustained improvements in energy markets, we believe that production cuts are no longer necessary to support international energy markets and that global downstream demand, while stronger, has not fully recovered.

The global economy, including the U.S., experienced robust growth during 2021, mainly due to restocking inventories and efforts to satisfy consumer demand suppressed by the pandemic.

According to the EIA, U.S.

gross domestic product (“GDP”) is forecast to increase 5.7% in 2021 and 4.5% in 2022, following a decline of 3.4% in 2020.

During this time, we have observed a steady transition from near record levels of crude oil inventories in the U.S.

to a more normalized level today as U.S.

consumption has outpaced U.S.

We are now seeing temporary shortfalls in global natural gas and coal supplies as reports from some countries, particularly in Europe and Asia, have revealed a rationing of energy supplies and curtailments of industrial production.

Some reports have referred to the current situation as an “energy crisis,” which could become even more severe if the world experiences a colder than normal winter.

We believe that U.S.

supply and demand have become more balanced, but anticipate a slight supply shortfall going into 2022.

The EIA estimates that U.S.

production of petroleum and related liquids will average 18.6 MMBPD in 2021 and 20.0 MMBPD in 2022, while U.S.

demand for petroleum and related liquids will average 19.7 MMBPD in 2021 and 20.4 MMBPD in 2022.

Throughout this period, prices have increased considerably as evidenced by the price of West Texas Intermediate (“WTI”) crude oil at Cushing, Oklahoma (as reported by the New York Mercantile Exchange, or “NYMEX”).

It reached six-year highs in October 2021 and averaged $71.54 per barrel in September 2021 compared to $52.10 per barrel in January 2021 and an average of $39.34 per barrel in 2020.

The price of natural gas at Henry Hub, Louisiana (as reported by NYMEX) reached twelve-year highs in October 2021 and averaged $5.11 per MMBtu in September 2021 compared to $2.65 per MMBtu in January 2021 and an average of $2.13 per MMBtu in 2020.

Significant uncertainty exists with respect to the capabilities and willingness of OPEC+ to increase production enough to alleviate high crude oil prices and whether hydrocarbon demand will remain resilient as prices continue to rise.

Despite ongoing pressures faced by many producers in the U.S.

to preserve cash, return capital to their investors and reduce crude oil and natural gas production activities altogether, potential cash flows from these high price levels may eventually become too attractive for U.S.

energy investors to forego.

The EIA forecasts U.S.

crude oil production will increase from an average of 11.0 MMBPD in 2021 to 11.7 MMBPD in 2022;

however, these levels still lag behind the record level of 12.3 MMBPD in 2019.

production rises, we believe that our integrated, diversified and fee-based business will have additional opportunities to provide midstream services to our producers and customers.

Recent Developments

Enterprise and Chevron Explore Carbon Storage Business Opportunities

In September 2021, we and Chevron U.S.A.

(“Chevron”) jointly announced a framework to study and evaluate opportunities for carbon dioxide capture, utilization and storage from our respective business operations in the U.S.

Midcontinent and Gulf Coast.

Projects resulting from this evaluation would seek to combine our extensive midstream pipeline and storage network with Chevron’s sub-surface expertise to create opportunities to capture, aggregate, transport and sequester carbon dioxide in support of the evolving energy landscape.

The initial phase of the study in which we will evaluate specific business opportunities is expected to last about six months.

Issuance of $1.0 Billion of Senior Notes in September 2021

In September 2021, EPO issued $1.0 billion principal amount of senior notes due February 2053 (“Senior Notes EEE”).

Net proceeds from this offering will be used for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of a portion of our $750.0 million in principal amount of 3.50% Senior Notes VV and/or a portion of our $650.0 million in principal amount of 4.05% Senior Notes CC, in each case at their maturity in February 2022).

Senior Notes EEE were issued at 99.170% of their principal amount and have a fixed rate of interest of 3.30% per year.

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

Enterprise and Magellan Team Up With Intercontinental Exchange for New Houston Crude Oil Futures Contract

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2021 Averages

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

NGL prices for ethane, propane, normal butane, isobutane and natural gasoline are based on Mont Belvieu Non-TET commercial index prices as reported by Oil Price Information Service.

Polymer grade propylene prices represent average contract pricing for such product as reported by IHS Chemical, a division of IHS Inc.

(“IHS Chemical”).

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

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.

NGL prices for ethane, propane, normal butane, isobutane and natural gasoline are based on Mont Belvieu Non-TET commercial index prices as reported by Oil Price Information Service (“OPIS”) by IHS Markit (“IHS”).

Polymer grade propylene prices represent average contract pricing for such product as reported by IHS.

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

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.

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

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

The weighted-average indicative market price for NGLs was $0.64 per gallon in the second quarter of 2021 versus $0.31 per gallon in the second quarter of 2020.

Likewise, the weighted-average indicative market price for NGLs was $0.63 per gallon during the six months ended June 30, 2021 compared to $0.33 per gallon during the same period in 2020.

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 $0.84 per gallon in the third quarter of 2021 versus $0.41 per gallon in the third quarter of 2020.

Likewise, the weighted-average indicative market price for NGLs was $ 0.70 per gallon during the nine months ended September 30, 2021 compared to $0.36 per gallon during the same period in 2020.

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

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

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.

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For the Three Months

Ended June 30,

For the Six Months

Ended June 30,

Ended September 30,

For the Nine Months

Ended September 30,

Costs and expenses:

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Cost of sales

Other operating costs and expenses

Depreciation, amortization and accretion expenses

Asset impairment charges

Other operating costs and expenses

Net losses (gains) attributable to asset sales and related matters

Total operating costs and expenses

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Net income attributable to common unitholders

* Amount is negligible

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

For the Three Months

Ended June 30,

For the Six Months

Ended June 30,

Ended September 30,

For the Nine Months

Ended September 30,

NGL Pipelines & Services:

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Total consolidated revenues

Second Quarter of 2021 Compared to Second Quarter of 2020 .

Total revenues for the second quarter of 2021 increased $ 3.7 billion when compared to the second quarter of 2020 primarily due to a $ 3.52 billion increase in marketing revenues.

Revenues from the marketing of crude oil and petrochemicals and refined products increased a combined $ 2.35 billion quarter-to-quarter primarily due to higher average sales prices, which accounted for a $ 1.77 billion increase, and higher sales volumes, which accounted for an additional $ 577.2 million increase.

Revenues from the marketing of NGLs and natural gas increased a combined net $ 1.17 billion quarter-to-quarter primarily due to higher average sales prices, which accounted for a $1.52 billion increase, partially offset by lower sales volumes, which accounted for a $347.0 million decrease.

Revenues from midstream services for the second quarter of 2021 increased $ 180.0 million when compared to the second quarter of 2020.

Third Quarter of 2021 Compared to Third Quarter of 2020 .

Total revenues for the third quarter of 2021 increased $ 3.91 billion when compared to the third quarter of 2020 primarily due to a $ 3.75 billion increase in marketing revenues.

Revenues from the marketing of NGLs and crude oil increased a combined $2.8 billion quarter-to-quarter primarily due to higher average sales prices, which accounted for a $2.16 billion increase, and higher sales volumes, which accounted for an additional $636.9 million increase.

Revenues from the marketing of natural gas, petrochemicals and refined products increased a combined net $953.2 million quarter-to-quarter primarily due to higher average sales prices, which accounted for a $2.13 billion increase, partially offset by lower sales volumes, which accounted for a $1.18 billion decrease.

Revenues from midstream services for the third quarter of 2021 increased $ 161.1 million when compared to the third quarter of 2020.

Revenues from our terminal facilities increased $58.2 million quarter-to-quarter primarily due to higher deficiency fee revenue.

Revenues from our natural gas processing facilities increased $46.2 million quarter-to-quarter primarily due to higher market values for the equity NGLs we receive as non-cash consideration for processing services.

Revenues from our pipeline assets increased $ 47.6 million quarter-to-quarter primarily due to higher demand for transportation services in Texas.

Revenues from our crude oil pipeline assets increased $43.6 million quarter-to-quarter, primarily due to higher demand for crude oil transportation services.

Revenues from our propylene production facilities increased $22.0 million quarter-to-quarter primarily due to higher processing fees.

Revenues from our terminal facilities increased $ 22.5 million quarter-to-quarter primarily due to higher deficiency fee revenue.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020 .

Total revenues for the six months ended June 30, 2021 increased $ 5.37 billion when compared to the six months ended June 30, 2020 primarily due to a $ 5.19 billion increase in marketing revenues.

Revenues from the marketing of NGLs, natural gas, petrochemicals and refined products increased a combined net $ 4.05 billion period-to-period primarily due to higher average sales prices, which accounted for a $ 4.77 billion increase, partially offset by lower sales volumes, which accounted for a $ 716.8 million decrease.

Revenues from the marketing of crude oil increased $ 1.13 billion period-to-period primarily due to higher average sales prices, which accounted for a $697.5 million increase, and higher sales volumes, which accounted for an additional $ 437.1 million increase.

Revenues from midstream services for the six months ended June 30, 2021 increased $ 186.9 million when compared to the six months ended June 30, 2020.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 .

Total revenues for the nine months ended September 30, 2021 increased $9.28 billion when compared to the nine months ended September 30, 2020 primarily due to an $8.93 billion increase in marketing revenues.

Revenues from the marketing of NGLs, natural gas, petrochemicals and refined products increased a combined net $6.12 billion period-to-period primarily due to higher average sales prices, which accounted for a $7.85 billion increase, partially offset by lower sales volumes, which accounted for a $1.73 billion decrease.

Revenues from the marketing of crude oil increased $2.81 billion period-to-period primarily due to higher average sales prices, which accounted for a $1.8 billion increase, and higher sales volumes, which accounted for an additional $1.01 billion increase.

Revenues from midstream services for the nine months ended September 30, 2021 increased $348.0 million when compared to the nine months ended September 30, 2020.

Revenues from our terminal facilities increased $110.8 million period-to-period primarily due to higher deficiency fee revenue.

Revenues from our natural gas processing facilities increased $104.5 million period-to-period primarily due to higher market values for the equity NGLs we receive as non-cash consideration for processing services.

Revenues from our crude oil pipeline assets increased $87.9 million period-to-period, primarily due to higher demand for crude oil transportation services.

Revenues from our propylene production facilities increased $73.9 million period-to-period primarily due to higher processing fees.

Revenues from our terminal facilities increased $52.6 million period-to-period primarily due to higher deficiency fee revenue.

Operating costs and expenses

Total operating costs and expenses for the three and six months ended June 30, 2021 increased $3.7 billion and $ 5.19 billion, respectively, when compared to the same periods in 2020.

Total operating costs and expenses for the three and nine months ended September 30, 2021 increased $3.84 billion and $ 9.03 billion, respectively, when compared to the same periods in 2020.

Cost of sales

Second Quarter of 2021 Compared to Second Quarter of 2020 .

Cost of sales for the second quarter of 2021 increased $ 3.64 billion when compared to the second quarter of 2020.

The cost of sales associated with our marketing of crude oil and petrochemicals and refined products increased a combined $ 2.35 billion quarter-to-quarter primarily due to higher average purchase prices, which accounted for a $ 1.85 billion increase, and higher sales volumes, which accounted for an additional $ 506.6 million increase.

On a combined basis, the cost of sales associated with our marketing of NGLs and natural gas increased a net $ 1.29 billion quarter-to-quarter primarily due to higher average purchase prices, which accounted for a $ 1.58 billion increase, partially offset by lower sales volumes, which accounted for a $ 285.4 million decrease.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020 .

Cost of sales for the six months ended June 30, 2021 increased $ 5.08 billion when compared to the six months ended June 30, 2020.

On a combined basis, the cost of sales associated with our marketing of NGLs, natural gas, petrochemicals and refined products increased a net $ 3.59 billion period-to-period primarily due to higher average purchase prices, which accounted for a $4.02 billion increase, partially offset by lower sales volumes, which accounted for a $ 424.6 million decrease.

Third Quarter of 2021 Compared to Third Quarter of 2020 .

Cost of sales for the third quarter of 2021 increased $ 3.8 billion when compared to the third quarter of 2020.

The cost of sales associated with our marketing of NGLs and crude oil increased a combined $3.19 billion quarter-to-quarter primarily due to higher average purchase prices, which accounted for a $2.6 billion increase, and higher sales volumes, which accounted for an additional $586.0 million increase.

The cost of sales associated with our marketing of natural gas, petrochemicals and refined products increased a combined net $611.1 million quarter-to-quarter primarily due to higher average purchase prices, which accounted for a $1.74 billion increase, partially offset by lower sales volumes, which accounted for a $1.13 billion decrease.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 .

Cost of sales for the nine months ended September 30, 2021 increased $8.88 billion when compared to the nine months ended September 30, 2020.

The cost of sales associated with our marketing of NGLs, natural gas, petrochemicals and refined products increased a combined net $ 5.58 billion period-to-period primarily due to higher average purchase prices, which accounted for a $7.0 billion increase, partially offset by lower sales volumes, which accounted for a $1.42 billion decrease.

The cost of sales associated with our marketing of crude oil increased $3.3 billion period-to-period primarily due to higher average purchase prices, which accounted for a $2.37 billion increase, and higher sales volumes, which accounted for an additional $930.5 million increase.

Other operating costs and expenses

Other operating costs and expenses for the third quarter of 2021 increased $60.4 million when compared to the third quarter of 2020 primarily due to higher maintenance and utility costs, ad valorem taxes, and costs attributable to new assets placed into service during or since the respective quarter in 2020.

Other operating costs and expenses for the nine months ended September 30, 2021 increased $53.8 million when compared to the nine months ended September 30, 2020 primarily due to higher maintenance and employee compensation costs, ad valorem taxes, and costs attributable to new assets placed into service during or since the respective period in 2020.

Depreciation, amortization and accretion expenses

Depreciation, amortization and accretion expense for the three and six months ended June 30, 2021 increased a combined $ 12.6 million and $ 28.5 million, respectively, primarily due to assets placed into full or limited service (e.g., Chambers County Frac X and XI and the Midland-to-ECHO 3 pipeline) since the end of the respective periods in 2020.

Depreciation, amortization and accretion expense for the three and nine months ended September 30, 2021 increased a combined $27.1 million and $55.6 million, respectively, when compared to the same periods in 2020.

The quarter-to-quarter and period-to-period increases are primarily due to assets placed into full or limited service (e.g., Chambers County Frac X and XI, and the Midland-to-ECHO 3 pipeline) since the end of the respective periods in 2020 and major maintenance activities accounted for under the deferral method.

Under the deferral method, major maintenance costs are capitalized and amortized over the period until the next major overhaul project.

We adopted the deferral method for our reaction-based plants in November 2020.

Asset impairment charges

Non-cash asset impairment charges for the three and six months ended June 30, 2021 increased $ 6.1 million and $70.0 million, respectively, when compared to the same periods in 2020.

We recorded non-cash asset impairment charges of $ 44.3 million during the six months ended June 30, 2021 for the sale of a coal bed natural gas gathering system and the related Val Verde treating facility, both of which were components of our San Juan Gathering System.

The remainder of our asset impairment charges for the three and six month periods ended June 30, 2021 and 2020 are attributable to the complete write-off of assets that are no longer expected to be used or constructed.

Non-cash asset impairment charges for the three and nine months ended September 30, 2021 decreased $47.7 m illion and increased $22.3 million, respectively, when compared to the same periods in 2020.

We recorded non-cash impairment charges of $44.3 million during the nine months ended September 30, 2021 due to the sale of a coal bed natural gas gathering system and the related Val Verde treating facility, both of which were components of our San Juan Gathering System.

The remainder of our asset impairment charges for the three and nine months ended September 30, 2021 and 2020 are attributable to the write-off of assets that are no longer expected to be used or constructed, including the cancellation of the Midland-to-ECHO 4 crude oil pipeline construction project in September 2020.

We are closely monitoring the recoverability of our long-lived assets, investments in unconsolidated affiliates and goodwill in light of the adverse economic effects of the COVID-19 pandemic.

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

Other operating costs and expenses

Other operating costs and expenses for the second quarter of 2021 increased $ 32.8 million when compared to the second quarter of 2020 primarily due to higher maintenance and chemical costs.

Other operating costs and expenses for the six months ended June 30, 2021 increased $ 6.1 million when compared to the six months ended June 30, 2020 primarily due to a non-cash charge of $11.3 million incurred during the six months ended June 30, 2021 related to a warehouse fire.

General and administrative costs

General and administrative costs for the three and six months ended June 30, 2021 decreased $ 5.5 million and $4.7 million, respectively, when compared to the same periods in 2020 primarily due to lower professional services costs.

General and administrative costs for the three and nine months ended September 30, 2021 decreased $3.0 million and $7.7 million, respectively, when compared to the same periods in 2020 primarily due to lower professional services costs.

Equity in income of unconsolidated affiliates

Equity income from our unconsolidated affiliates for the three and six months ended June 30, 2021 increased $ 47.4 million and $ 55.5 million, respectively, when compared to the same periods in 2020 primarily due to increased earnings from investments in crude oil pipelines.

Equity income from our unconsolidated affiliates for the three and nine months ended September 30, 2021 increased $55.6 million and $111.1 million, respectively, when compared to the same periods in 2020 primarily due to higher earnings from investments in crude oil pipelines.

Operating income

Operating income for the three and six months ended June 30, 2021 increased $ 55.7 million and $242.7 million, respectively, when compared to the same periods in 2020 due to the previously described quarter-to-quarter and period-to-period changes.

Operating income for the three and nine months ended September 30, 2021 increased $130.6 million and $373.3 million, respectively, when compared to the same periods in 2020 due to the previously described quarter-to-quarter and period-to-period changes.

Interest expense

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For the Three Months

Ended June 30,

For the Six Months

Ended June 30,

Ended September 30,

For the Nine Months

Ended September 30,

Interest charged on debt principal outstanding

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

Interest charged on debt principal outstanding, which is a key driver of interest expense, decreased $ 13.2 million quarter-to-quarter primarily due to lower debt principal amounts outstanding during the second quarter of 2021, which accounted for an $ 11.5 million decrease, and the effects of lower overall interest rates during the second quarter of 2021, which accounted for an additional $ 1.7 million decrease.

Our weighted-average debt principal balance for the second quarter of 2021 was $ 28.86 billion compared to $29.9 billion for the second quarter of 2020.

For the six months ended June 30, 2021, interest charged on debt principal outstanding decreased $ 17.8 million period-to-period primarily due to lower debt principal amounts outstanding during the six months ended June 30, 2021, which accounted for an $ 11.4 million decrease, and the effects of lower overall interest rates during the six months ended June 30, 2021, which accounted for an additional $ 6.4 million decrease.

Our weighted-average debt principal balance for the six months ended June 30, 2021 was $29.48 billion compared to $ 29.61 billion for the six months ended June 30, 2020.

Interest charged on debt principal outstanding, which is a key driver of interest expense, decreased $ 12.8 million quarter-to-quarter primarily due to lower debt principal amounts outstanding during the third quarter of 2021.

Our weighted-average debt principal balance for the third quarter of 2021 was $ 29.07 billion compared to $30.27 billion for the third quarter of 2020.

For the nine months ended September 30, 2021, interest charged on debt principal outstanding decreased $30.6 million period-to-period primarily due to lower debt principal amounts outstanding during the nine months ended September 30, 2021, which accounted for an $21.8 million decrease, and the effects of lower overall interest rates during the nine months ended September 30, 2021, which accounted for an additional $8.8 million decrease.

Our weighted-average debt principal balance for the nine months ended September 30, 2021 was $29.38 billion compared to $ 29.84 billion for the nine months ended September 30, 2020.

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

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For the Three Months

Ended June 30,

For the Six Months

Ended June 30,

Ended September 30,

For the Nine Months

Ended September 30,

Deferred tax benefit (expense) attributable to OTA

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

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

OTA recognized an additional net, non-cash deferred income tax benefit of $64.5 million, which reflected a decrease in the outside basis difference of its investment in the Partnership caused by a decline in the market price of the Partnership’s common units subsequent to March 5, 2020 through June 30, 2020.

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

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

OTA recognized an additional net, non-cash deferred income tax benefit of $85.8 million, which reflected a decrease in the outside basis difference of its investment in the Partnership caused by a decline in the market price of the Partnership’s common units subsequent to March 5, 2020 through September 30, 2020.

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

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

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Ended September 30,

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Gross operating margin by segment:

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Operating income

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

Estimated Impact of Hurricane Ida on Results for the Third Quarter of 2021

In late August 2021, southern Louisiana and Mississippi, including its critical energy infrastructure, were impacted by the cumulative effects of Hurricane Ida.

Impacts on the energy industry included, but were not limited to, severe flooding and limited access to facilities, disruptions to offshore production in the Gulf of Mexico, and reduced energy demand from area refineries and petrochemical facilities.

Our plant, pipeline and storage assets in southern Louisiana and Mississippi did not experience significant property damage, and the majority have returned to normal operations.

We expect our volumes impacted by the remaining third-party facility disruptions to return to normal levels as repairs are completed and production is fully restored.

We estimate that Hurricane Ida reduced our gross operating margin for the third quarter of 2021 by approximately $30 million, almost all of which is related to our Louisiana and Mississippi processing, transportation and fractionation assets and related marketing activities, which are a component of our NGL Pipelines & Services segment.

Of this amount, approximately $25 million represents the combined net impact of lower than anticipated volumes and lost business opportunities.

The remaining $5 million represents expenses, net of property damage insurance reimbursements, which we incurred during the quarter in connection with hurricane-related repair and recovery costs.

As a result of our deductible levels, we do not expect any reimbursement from insurance in connection with business interruption claims from Hurricane Ida.

NGL Pipelines & Service s

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Segment gross operating margin:

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Natural gas processing and related NGL marketing activities

Second Quarter of 2021 Compared to Second Quarter of 2020 .

Gross operating margin from natural gas processing and related NGL marketing activities for the second quarter of 2021 increased $86.8 million when compared to the second quarter of 2020.

Third Quarter of 2021 Compared to Third Quarter of 2020 .

Gross operating margin from natural gas processing and related NGL marketing activities for the third quarter of 2021 increased $7.1 million when compared to the third quarter of 2020.

Gross operating margin from our Permian Basin natural gas processing facilities increased $30.3 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging), which accounted for a $16.3 million increase, and higher equity NGL production, which accounted for an additional $11.4 million increase.

Fee-based natural gas processing volumes and equity NGL volumes at these facilities increased 144 MMcf/d and 33 MBPD, respectively, quarter-to-quarter.

Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) increased a combined $25.9 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities).

On a combined basis, fee-based natural gas processing volumes at these facilities decreased 239 MMcf/d quarter-to-quarter.

Gross operating margin from our NGL marketing activities increased a net $25.3 million quarter-to-quarter primarily due to higher average sales margins (including the impact of hedging activities), which accounted for a $67.1 million increase, partially offset by lower sales volumes, which accounted for a $42.2 million decrease.

Results from NGL marketing strategies that optimize our transportation, storage and plant assets increased a combined $61.3 million quarter-to-quarter, partially offset by lower earnings from the optimization of our export assets, which accounted for a $16.3 million decrease.

On a combined basis, fee-based natural gas processing volumes and equity NGL production at these facilities decreased 160 MMcf/d and 18 MBPD, respectively, quarter-to-quarter.

Gross operating margin from our Louisiana and Mississippi natural gas processing facilities increased $12.7 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities).

Fee-based natural gas processing volumes decreased 70 MMcf/d and equity NGL production increased 3 MBPD, quarter-to-quarter (net to our interest).

Gross operating margin from our South Texas natural gas processing facilities increased a net $14.0 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $35.8 million increase, partially offset by lower average processing fees, which accounted for a $17.1 million decrease, and lower equity NGL production of 12 MBPD, which accounted for an additional $3.8 million decrease.

Fee-based processing volumes at our South Texas natural gas processing facilities decreased 49 MMcf/d quarter-to-quarter.

Gross operating margin from our Permian Basin natural gas processing facilities increased a net $ 2.3 million quarter-to-quarter primarily due to higher fee-based processing volumes, which accounted for a $ 16.3 million increase, partially offset by lower average processing margins (including the impact of hedging activities), which accounted for an $ 11.0 million decrease.

Fee-based processing volumes and equity NGL production at our Permian Basin natural gas processing facilities increased 427 MMcf/d and 22 MBPD, respectively, quarter-to-quarter.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020 .

Gross operating margin from natural gas processing and related NGL marketing activities for the six months ended June 30, 2021 increased $128.8 million when compared to the six months ended June 30, 2020.

Gross operating margin from our NGL marketing activities increased $122.0 million period-to-period primarily due to higher average sales margins (including the impact of hedging activities).

Results from marketing strategies that optimize our transportation, storage and plant assets increased a combined $155.7 million period-to-period, partially offset by lower earnings from the optimization of our export assets, which accounted for a $62.4 million decrease.

Gross operating margin from our Louisiana and Mississippi natural gas processing facilities increased a net $13.8 million period-to-period primarily due to higher average processing margins (including the impact of hedging activities), which accounted for an $18.7 million increase, partially offset by lower average processing fees and volumes, which accounted for decreases of $6.7 million and $2.5 million, respectively.

Gross operating margin from our South Texas natural gas processing facilities increased a net $4.5 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities).

Fee-based processing volumes and equity NGL production at our South Texas natural gas processing facilities decreased 3 MMcf/d and 5 MBPD, respectively, quarter-to-quarter.

Gross operating margin from our NGL marketing activities decreased $68.9 million quarter-to-quarter primarily due to lower average sales margins (including the impact of hedging activities).

Results from NGL marketing strategies that optimize our transportation, storage, plant and export assets decreased a combined $117.9 million quarter-to-quarter, partially offset by higher earnings from non-cash mark-to-market activities, which accounted for a $49.0 million increase.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 .

Gross operating margin from natural gas processing and related NGL marketing activities for the nine months ended September 30, 2021 increased $135.9 million when compared to the nine months ended September 30, 2020.

Gross operating margin from our NGL marketing activities increased a net $53.0 million period-to-period primarily due to higher average sales margins (including the impact of hedging activities), which accounted for a $70.5 million increase, partially offset by lower sales volumes, which accounted for a $15.6 million decrease.

Results from marketing strategies that optimize our export and storage assets decreased a combined $91.6 million period-to-period, partially offset by higher earnings from the optimization of our transportation and plant assets, which accounted for a $66.9 million increase.

In addition, gross operating margin from our NGL marketing activities attributable to non-cash, mark-to-market earnings increased $77.7 million period-to-period.

Gross operating margin from our Permian Basin natural gas processing facilities increased a net $42.8 million period-to-period primarily due to higher fee-based natural gas processing volumes, which accounted for a $29.5 million increase, and higher average processing margins (including the impact of hedging), which accounted for an additional $20.4 million increase, partially offset by higher operating costs, which accounted for a $6.8 million decrease.

Fee-based natural gas processing volumes and equity NGL production at these facilities increased 255 MMcf/d and 29 MBPD, respectively, period-to-period.

Gross operating margin from our Rockies natural gas processing facilities increased a combined net $33.5 million period-to-period primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $34.5 million increase, and lower operating costs, which accounted for an additional $6.3 million increase, partially offset by lower fee-based natural gas processing volumes, which accounted for a $7.9 million decrease.

On a combined basis, fee-based natural gas processing volumes and equity NGL production at these facilities decreased 268 MMcf/d and 9 MBPD, respectively, period-to-period.

Gross operating margin from our Louisiana and Mississippi natural gas processing facilities increased a net $26.5 million period-to-period primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $28.9 million increase, and lower operating costs, which accounted for an additional $5.1 million increase, partially offset by lower average processing fees and volumes, which accounted for decreases of $7.7 million and $3.0 million, respectively.

Fee-based natural gas processing volumes decreased 108 MMcf/d period-to-period (net to our interest).

Gross operating margin from our Permian Basin natural gas processing facilities increased $ 12.5 million period-to-period primarily due to higher fee-based processing volumes.

Fee-based processing and equity NGL production volumes at these facilities increased 311 MMcf/d and 26 MBPD, respectively, period-to-period.

Gross operating margin from our Rockies natural gas processing facilities increased a combined $7.6 million period-to-period primarily due to higher average processing margins (including the impact of hedging activities), which accounted for an $8.9 million increase, and lower operating costs, which accounted for an additional $5.9 million increase, partially offset by lower fee-based processing volumes, which accounted for a $7.1 million decrease.

On a combined basis, fee-based natural gas processing volumes at these facilities decreased 323 MMcf/d period-to-period.

Gross operating margin from our South Texas natural gas processing facilities decreased a net $27.2 million period-to-period primarily due to lower equity NGL production of 9 MBPD, which accounted for a $49.7 million decrease, lower average processing fees, which accounted for a $28.6 million decrease, and higher operating costs, which accounted for an additional $7.1 million decrease.

Partially offsetting these negative impacts were higher average processing margins (including the impact of hedging activities), which accounted for a $62.6 million period-to-period increase.

Gross operating margin from our South Texas natural gas processing facilities decreased a net $22.7 million period-to-period primarily due to lower equity NGL production of 7 MBPD, which accounted for a $47.6 million decrease, and lower average processing fees, which accounted for an additional $38.3 million decrease, partially offset by higher average processing margins (including the impact of hedging activities), which accounted for a $67.9 million period-to-period increase.

Fee-based processing volumes at these facilities decreased 88 MMcf/d period-to-period.

NGL pipelines, storage and terminals

Second Quarter of 2021 Compared to Second Quarter of 2020 .

Gross operating margin from our NGL pipelines, storage and terminal assets during the second quarter of 2021 decreased $51.2 million when compared to the second quarter of 2020.

Gross operating margin from our Dixie Pipeline and related terminals decreased a combined $19.4 million quarter-to-quarter primarily due to lower transportation volumes of 74 MBPD, which accounted for an $11.5 million decrease, and higher maintenance and other operating costs, which accounted for an additional $6.8 million decrease.

Gross operating margin from our Chambers County, Texas storage complex decreased $15.3 million quarter-to-quarter primarily due to higher operating costs, which accounted for an $8.1 million decrease, and lower throughput fee revenues, which accounted for an additional $4.0 million decrease.

Gross operating margin from LPG-related activities at our Enterprise Hydrocarbons Terminal (“EHT”) decreased $12.1 million quarter-to-quarter primarily due to lower export volumes of 62 MBPD.

Third Quarter of 2021 Compared to Third Quarter of 2020 .

Gross operating margin from our NGL pipelines, storage and terminal assets during the third quarter of 2021 decreased $33.3 million when compared to the third quarter of 2020.

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 decreased a net $6.9 million quarter-to-quarter primarily due to higher operating costs, which accounted for a $16.0 million decrease, partially offset by higher average transportation fees, which accounted for a $10.2 million increase.

On a combined basis, gross operating margin from these pipelines decreased $30.6 million quarter-to-quarter primarily due to lower average transportation fees, which accounted for a $21.9 million decrease, and lower transportation volumes, which accounted for an additional $7.3 million decrease.

Transportation volumes on these pipelines decreased a combined 10 MBPD quarter-to-quarter (net to our interest).

Gross operating margin from our South Texas NGL Pipeline System increased $13.7 million quarter-to-quarter primarily due to higher pipeline capacity fee revenues earned from an affiliate pipeline.

Transportation volumes on our South Texas NGL Pipeline System increased 27 MBPD quarter-to-quarter.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020 .

Gross operating margin from our NGL pipelines, storage and terminal assets during the six months ended June 30, 2021 decreased $77.9 million when compared to the six months ended June 30, 2020.

On a combined basis, our pipelines that serve Permian Basin and/or Rocky Mountain producers had gross operating margin decrease a net $28.2 million period-to-period primarily due to lower transportation volumes of 106 MBPD (net to our interest), which accounted for a $48.2 million decrease, and higher operating costs, which accounted for an additional $15.6 million decrease, partially offset by higher average transportation fees, which accounted for a $30.0 million increase.

Gross operating margin from LPG-related activities at EHT decreased $27.3 million period-to-period primarily due to lower export volumes of 78 MBPD.

Gross operating margin from our related Houston Ship Channel Pipeline System decreased $4.0 million period-to-period primarily due to an 80 MBPD decrease in transportation volumes.

Gross operating margin from our Dixie Pipeline and related terminals decreased a combined $16.4 million period-to-period primarily due to lower transportation volumes of 41 MBPD, which accounted for a $9.2 million decrease, and higher maintenance and other operating costs, which accounted for an additional $6.8 million decrease.

Gross operating margin at our Morgan’s Point Ethane Export Terminal increased $6.3 million quarter-to-quarter primarily due to an increase in loading volumes of 23 MBPD, which accounted for a $4.3 million increase, and lower operating costs, which accounted for an additional $2.1 million increase.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 .

Gross operating margin from our NGL pipelines, storage and terminal assets during the nine months ended September 30, 2021 decreased $111.2 million when compared to the nine months ended September 30, 2020.

On a combined basis, gross operating margin from our pipelines that serve Permian Basin and/or Rocky Mountain producers decreased a net $58.9 million period-to-period primarily due to lower transportation volumes of 73 MBPD (net to our interest), which accounted for a $54.3 million decrease, and higher operating costs, which accounted for an additional $23.0 million decrease, partially offset by higher handling fee revenues, which accounted for an $11.6 million increase, and higher average transportation fees, which accounted for an additional $6.8 million increase.

Gross operating margin from LPG-related activities at our Enterprise Hydrocarbons Terminal (“EHT”) decreased $26.0 million period-to-period primarily due to lower export volumes of 53 MBPD.

Gross operating margin from our related Houston Ship Channel Pipeline decreased $4.9 million period-to-period primarily due to a 54 MBPD decrease in transportation volumes.

Gross operating margin at our Morgan’s Point Ethane Export Terminal increased $7.6 million period-to-period primarily due to higher loading volumes of 18 MBPD.

Gross operating margin from our Dixie Pipeline and related terminals decreased a combined $16.8 million period-to-period primarily due to higher maintenance and other operating costs, which accounted for a $9.6 million decrease, and lower transportation volumes of 20 MBPD, which accounted for an additional $7.3 million decrease.

Gross operating margin from our Chambers County storage complex decreased a net $10.2 million period-to-period primarily due to lower throughput fee revenues, which accounted for a $12.0 million decrease, and higher operating costs, which accounted for an additional $15.2 million decrease, partially offset by higher storage fee revenues, which accounted for a $17.0 million increase.

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NGL fractionation

Second Quarter of 2021 Compared to Second Quarter of 2020 .

Gross operating margin from NGL fractionation during the second quarter of 2021 increased $93.9 million when compared to the second quarter of 2020.

Gross operating margin from our Chambers County NGL fractionation complex increased $102.4 million quarter-to-quarter.

This increase was primarily due to an additional $58.0 million in margins earned on the optimization of our power supply arrangements and $40.5 million of payments received in connection with our participation in the Texas Load Resources Demand Response Program (“LaaR”) during the February 2021 winter storms.

Third Quarter of 2021 Compared to Third Quarter of 2020 .

Gross operating margin from NGL fractionation during the third quarter of 2021 increased $21.0 million when compared to the third quarter of 2020.

Gross operating margin from our Chambers County NGL fractionation complex increased a net $ 23.6 million quarter-to-quarter primarily due to higher fractionation volumes, which accounted for a $35.0 million increase, and higher ancillary service revenues, which accounted for an additional $17.1 million increase, partially offset by higher operating costs, which accounted for a $32.8 million decrease.

NGL fractionation volumes at our Chambers County NGL fractionation complex, which includes the average daily operating rates for newly constructed assets from the time the asset was placed into service, decreased 40 MBPD quarter-to-quarter (net to our interest).

While the average daily operating rate for our Chambers County NGL fractionation complex decreased quarter-to-quarter, total NGL fractionation volumes increased primarily due to a full quarter of contributions from Frac XI, which entered service in September 2020.

Gross operating margin from our Norco NGL fractionator decreased $ 4.9 million quarter-to-quarter primarily due to higher maintenance costs and lower fractionation volumes as a result of Hurricane Ida.

NGL fractionation volumes at our Norco NGL fractionator decreased 22 MBPD quarter-to-quarter.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 .

Gross operating margin from NGL fractionation during the nine months ended September 30, 2021 increased $144.0 million when compared to the nine months ended September 30, 2020.

Gross operating margin from our Chambers County NGL fractionation complex increased a net $ 162.2 million period-to-period.

This increase was primarily due to higher fractionation volumes, which accounted for a $107.6 million increase, and higher ancillary service revenues, which accounted for an additional $45.6 million increase, partially offset by higher operating costs, which accounted for a $114.0 million decrease.

While the average daily operating rate for our Chambers County NGL fractionation complex decreased period-to-period, total NGL fractionation volumes increased primarily due to a full period of contributions from Frac X and Frac XI, which entered service in late March 2020 and September 2020, respectively.

In addition, gross operating margin at our Chambers County NGL fractionation complex increased due to $ 63.2 million in margins on the optimization of our power supply arrangements and $ 40.5 million of payments received in connection with our participation in the Texas Load Resources Demand Response Program (“LaaR”) during the February 2021 winter storms.

The amounts earned from optimization activities were based on the settlement of ERCOT prices, which were finalized by the State of Texas during the second quarter of 2021.

The amounts earned from the LaaR program partially compensate us for higher electricity expenses incurred during the storms and for lost revenues resulting from voluntary outages during the storms.

NGL fractionation volumes at our Chambers County NGL fractionation complex increased 137 MBPD (net to our interest) primarily due to the contributions from Frac XI, which entered service in September 2020.

Gross operating margin from our Norco NGL fractionator decreased $10.8 million quarter-to-quarter primarily due to major maintenance activities completed in the second quarter of 2021.

NGL fractionation volumes at our Norco NGL fractionator decreased 34 MBPD quarter-to-quarter.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020 .

Gross operating margin from NGL fractionation during the six months ended June 30, 2021 increased $123.0 million when compared to the six months ended June 30, 2020.

Gross operating margin from our Chambers County NGL fractionation complex increased a net $138.4 million period-to-period primarily due to the aforementioned LaaR payments and margins earned on the optimization of our power supply arrangements in connection with the February 2021 winter storms, which accounted for $103.7 million of the increase, and higher fractionation volumes of 107 MBPD (net to our interest), which accounted for an additional $72.5 million increase, partially offset by higher utility and maintenance costs, which accounted for a $44.7 million decrease.

The period-to-period increase in NGL fractionation volumes is primarily due to contributions from Frac X, which entered service in late March 2020, and Frac XI, which entered service in September 2020.

Gross operating margin from our Norco NGL fractionator decreased $11.8 million period-to-period primarily due to major maintenance activities completed in the second quarter of 2021.

Gross operating margin from our Norco NGL fractionator decreased $ 16.7 million period-to-period primarily due to higher maintenance costs and lower fractionation volumes as a result of downtime for major maintenance activities during the second quarter of 2021 and Hurricane Ida during the third quarter of 2021.

NGL fractionation volumes at our Norco NGL fractionator decreased 21 MBPD period-to-period.

Gross operating margin from our South Texas NGL fractionators decreased $ 5.0 million period-to-period primarily due to lower NGL fractionation volumes of 31 MBPD.

Crude Oil Pipelines & Services

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Crude oil marine terminal volumes (MBPD)

Second Quarter of 2021 Compared to Second Quarter of 2020 .

Gross operating margin from our Crude Oil Pipelines & Services segment for the second quarter of 2021 decreased $215.5 million when compared to the second quarter of 2020.

Third Quarter of 2021 Compared to Third Quarter of 2020 .

Gross operating margin from our Crude Oil Pipelines & Services segment for the third quarter of 2021 decreased $58.9 million when compared to the third quarter of 2020.

Gross operating margin from our crude oil marketing activities (excluding those attributable to the Midland-to-ECHO System) decreased $ 71.5 million quarter-to-quarter primarily due to lower average sales margins (including the impact of hedging activities).

Results from crude oil marketing strategies that optimize our storage and transportation assets decreased $ 55.3 million and $ 18.0 million quarter-to-quarter, respectively.

In addition, gross operating margin attributable to non-cash, mark-to-market earnings decreased $17.9 million quarter-to-quarter.

Gross operating margin from our West Texas Pipeline System decreased $8.4 million quarter-to-quarter primarily due lower average transportation fees.

Transportation volumes on our West Texas Pipeline System increased 20 MBPD quarter-to-quarter.

Gross operating margin from our South Texas Crude Oil Pipeline System decreased $6.3 million quarter-to-quarter primarily due to lower transportation volumes of 18 MBPD.

Gross operating margin from crude oil activities at EHT decreased $ 8.0 million quarter-to-quarter primarily due to lower storage revenues and other fees.

Crude oil terminal volumes at EHT were flat quarter-to-quarter.

Gross operating margin from our equity investment in the Seaway Pipeline increased $22.7 million quarter-to-quarter primarily due to $16.3 million in LaaR payments from power service providers in connection with the February 2021 winter storms.

Transportation volumes on the Seaway Pipeline decreased 50 MBPD quarter-to-quarter (net to our interest).

Gross operating margin from our Midland-to-ECHO System increased a net $4.0 million quarter-to-quarter primarily due to higher transportation volumes of 206 MBPD (net to our interest), which accounted for a $29.8 million increase, partially offset by lower average sales margins from marketing activities, which accounted for a $16.1 million decrease, and higher operating costs, which accounted for an additional $9.7 million decrease.

Crude oil terminal volumes at EHT decreased 131 MBPD quarter-to-quarter.

Gross operating margin from our South Texas Crude Oil Pipeline System decreased $ 5.8 million quarter-to-quarter primarily due to lower average transportation fees.

Transportation volumes on our South Texas Crude Oil Pipeline System increased 17 MBPD quarter-to-quarter.

Gross operating margin from our West Texas Pipeline System decreased $ 4.8 million quarter-to-quarter primarily due to lower average transportation fees.

Transportation volumes on our West Texas Pipeline System increased 96 MBPD quarter-to-quarter.

Gross operating margin from our Midland-to-ECHO System and related business activities increased a net $ 17.5 million quarter-to-quarter primarily due to higher transportation volumes of 142 MBPD (net to our interest), which accounted for a $ 30.5 million increase, partially offset by lower average sales margins from marketing activities, which accounted for a $ 10.5 million decrease.

The net quarter-to-quarter increase in transportation volumes for this system is generally due to the Midland-to-ECHO 3 pipeline, which was placed into service in October 2020.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020 .

Gross operating margin from our Crude Oil Pipelines & Services segment for the six months ended June 30, 2021 decreased $268.2 million when compared to the six months ended June 30, 2020.

Gross operating margin from our equity investment in the Seaway Pipeline increased $ 9.5 million quarter-to-quarter primarily due to higher transportation volumes.

Transportation volumes on the Seaway Pipeline increased 49 MBPD quarter-to-quarter (net to our interest).

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 .

Gross operating margin from our Crude Oil Pipelines & Services segment for the nine months ended September 30, 2021 decreased $327.1 million when compared to the nine months ended September 30, 2020.

Gross operating margin from our crude oil marketing activities (excluding those attributable to the Midland-to-ECHO System) decreased $ 273.6 million period-to-period primarily due to lower average sales margins (including the impact of hedging activities).

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Gross operating margin from our equity investment in the Eagle Ford Crude Oil Pipeline decreased $ 11.3 million period-to-period primarily due to lower transportation volumes of 52 MBPD (net to our interest).

Gross operating margin from our West Texas Pipeline System decreased $28.3 million period-to-period primarily due to lower average transportation fees, which accounted for a $15.4 million decrease, and lower transportation volumes of 18 MBPD, which accounted for an additional $6.6 million decrease.

Gross operating margin from our Midland-to-ECHO System and related business activities decreased a net $7.4 million period-to-period primarily due to lower average sales margins from marketing activities, which accounted for a $36.4 million decrease, partially offset by higher transportation volumes of 100 MBPD (net to our interest), which accounted for a $28.5 million increase.

As noted previously, the increase in transportation volumes is generally attributable to placing the Midland-to-ECHO 3 pipeline into service during the fourth quarter of 2020.

Gross operating margin from our equity investment in the Seaway Pipeline increased $23.0 million period-to-period primarily due to the aforementioned LaaR payments from power service providers in connection with the February 2021 winter storms.

Gross operating margin from our West Texas Pipeline System decreased $ 33.1 million period-to-period primarily due to lower average transportation fees.

Transportation volumes on our West Texas Pipeline System increased 20 MBPD period-to-period.

Gross operating margin from crude oil activities at EHT decreased $6.7 million period-to-period primarily due to lower storage revenues and other fees.

Crude oil terminal volumes at EHT decreased 175 MBPD period-to-period.

Gross operating margin from our equity investment in the Seaway Pipeline increased $ 32.5 million period-to-period primarily due to LaaR payments from power service providers in connection with the February 2021 winter storms.

Transportation volumes on our Seaway Pipeline decreased 61 MBPD period-to-period (net to our interest).

Gross operating margin from our Midland-to-ECHO System and related business activities increased a net $ 10.1 million period-to-period primarily due to higher transportation volumes of 115 MBPD (net to our interest), which accounted for a $ 45.8 million increase, and lower operating costs, which accounted for an additional $8.5 million increase, partially offset by lower average sales margins from marketing activities, which accounted for a $ 46.9 million decrease.

As noted previously, the increase in transportation volumes is generally attributable to placing the Midland-to-ECHO 3 pipeline into service during the fourth quarter of 2020.

Natural Gas Pipelines & Services

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Natural gas pipeline transportation volumes (BBtus/d)

Second Quarter of 2021 Compared to Second Quarter of 2020 .

Gross operating margin from our Natural Gas Pipelines & Services segment for the second quarter of 2021 decreased $6.9 million compared to the second quarter of 2020.

Gross operating margin from our natural gas marketing activities decreased $27.1 million quarter-to-quarter primarily due to lower average sales margins (including the impact of hedging).

Gross operating margin from our Texas Intrastate System decreased a net $7.1 million quarter-to-quarter primarily due to lower capacity reservation revenues, which accounted for a $25.1 million decrease, partially offset by higher storage and other fees, which accounted for an $11.9 million increase, and higher transportation volumes of 1,012 BBtus/d, which accounted for an additional $6.3 million increase.

The quarter-to-quarter increase in transportation volumes for this system is primarily due to the addition of new customers under firm and interruptible transportation agreements.

On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System and San Juan Gathering System decreased $3.1 million quarter-to-quarter primarily due to aggregate lower volumes of 595 BBtus/d.

Gross operating margin from our Permian Basin Gathering System increased $31.6 million quarter-to-quarter primarily due to higher average condensate sales prices, which accounted for a $17.9 million increase, higher condensate sales volumes, which accounted for a $10.5 million increase, and higher natural gas gathering volumes of 534 BBtus/d, which accounted for an additional $5.3 million increase.

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

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020 .

Gross operating margin from our Natural Gas Pipelines & Services segment for the six months ended June 30, 2021 increased $244.5 million when compared to the six months ended June 30, 2020.

Third Quarter of 2021 Compared to Third Quarter of 2020 .

Gross operating margin from our Natural Gas Pipelines & Services segment for the third quarter of 2021 increased $14.9 million compared to the third quarter of 2020.

Gross operating margin from our natural gas marketing activities increased $37.5 million quarter-to-quarter primarily due to higher average sales margins, which benefited from higher regional natural gas price spreads in Louisiana and Texas.

Gross operating margin from our Acadian Gas System and Haynesville Gathering System increased a combined $10.1 million quarter-to-quarter primarily due to higher transportation volumes, which accounted for a $5.9 million increase, and higher capacity reservation revenues, which accounted for an additional $4.4 million increase.

On a combined basis, transportation volumes increased 543 BBtus/d.

Gross operating margin from our Texas Intrastate System decreased a net $22.1 million quarter-to-quarter primarily due to lower capacity reservation revenues, which accounted for a $33.5 million decrease, partially offset by higher storage and other fees, which accounted for a $5.3 million increase, and higher transportation volumes of 782 BBtus/d, which accounted for an additional $3.8 million increase.

The quarter-to-quarter increase in transportation volumes for this system is primarily due to the addition of new firm and interruptible transportation agreements.

Gross operating margin from our Permian Basin Gathering System decreased a net $8.8 million quarter-to-quarter primarily due to lower condensate sales, which accounted for a $9.5 million decrease, partially offset by higher natural gas gathering volumes of 184 BBtus/d, which accounted for a $2.3 million increase.

The quarter-to-quarter increase in natural gas gathering volumes is attributable to deliveries at our Orla facility.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 .

Gross operating margin from our Natural Gas Pipelines & Services segment for the nine months ended September 30, 2021 increased $259.4 million when compared to the nine months ended September 30, 2020.

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

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Gross operating margin from our natural gas marketing activities increased $276.3 million period-to-period primarily due to higher average sales margins (including the impact of hedging activities) in connection with these unusual storm events.

Gross operating margin from our Permian Basin Gathering System increased $45.8 million period-to-period primarily due to higher average condensate sales prices, which accounted for a $24.2 million increase, higher condensate sales volumes, which accounted for a $14.7 million increase, and higher natural gas gathering volumes of 448 BBtus/d, which accounted for an additional $6.7 million increase.

Gross operating margin from our Texas Intrastate System decreased a net $19.3 million period-to-period primarily due to lower capacity reservation revenues, which accounted for a $51.8 million decrease, partially offset by higher storage and other fees, which accounted for an $18.3 million increase, and higher transportation volumes of 502 BBtus/d, which accounted for an additional $10.7 million increase.

Gross operating margin from our Acadian Gas System decreased $9.9 million period-to-period primarily due to a one-time producer payment in the first quarter of 2020.

Transportation volumes for the Acadian Gas System decreased 50 BBtus/d period-to-period.

Gross operating margin from our Haynesville Gathering System decreased $3.6 million period-to-period primarily due to lower gathering, compression and other fee revenues.

Gathering volumes on our Haynesville Gathering System increased 86 BBtus/d period-to-period.

On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System and San Juan Gathering System decreased $2.4 million period-to-period primarily due to aggregate lower volumes of 549 BBtus/d.

Gross operating margin from our Permian Basin Gathering System increased $36.9 million period-to-period primarily due to higher condensate sales, which accounted for a $29.5 million increase, and higher natural gas gathering volumes of 359 BBtus/d, which accounted for an additional $8.9 million increase.

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

Gross operating margin from our Texas Intrastate System decreased a net $41.3 million period-to-period primarily due to lower capacity reservation revenues, which accounted for an $85.3 million decrease, partially offset by higher storage and other fees, which accounted for a $23.7 million increase, and higher transportation volumes of 596 BBtus/d, which accounted for an additional $14.5 million increase.

Petrochemical & Refined Products Services

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For the Three Months

Ended June 30,

For the Six Months

Ended June 30,

Ended September 30,

For the Nine Months

Ended September 30,

Segment gross operating margin:

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Propylene production and related activities

Second Quarter of 2021 Compared to Second Quarter of 2020 .

Gross operating margin from propylene production and related activities for the second quarter of 2021 increased $143.3 million when compared to the second quarter of 2020.

Gross operating margin from our Chambers County propylene production facilities increased a combined $ 140.7 million quarter-to-quarter primarily due to higher average sales margins, which accounted for a $69.3 million increase, higher propylene and associated by-product sales volumes, which accounted for a $ 41.1 million increase, and higher propylene fractionation fees, which accounted for an additional $ 35.4 million increase.

Third Quarter of 2021 Compared to Third Quarter of 2020 .

Gross operating margin from propylene production and related activities for the third quarter of 2021 increased $126.6 million when compared to the third quarter of 2020.

Gross operating margin from our Chambers County propylene production facilities increased a combined $128.8 million quarter-to-quarter primarily due to higher average sales margins.

Propylene and associated by-product production volumes at these facilities increased a combined 12 MBPD quarter-to-quarter (net to our interest).

Gross operating margin from our propylene pipelines in Louisiana increased $ 6.1 million quarter-to-quarter primarily due to higher transportation volumes of 26 MBPD.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020 .

Gross operating margin from propylene production and related activities for the six months ended June 30, 2021 increased $180.7 million when compared to the six months ended June 30, 2020.

Gross operating margin from our propylene production facilities increased a combined $ 172.8 million period-to-period primarily due to higher average sales margins, which accounted for an $86.4 million increase, higher propylene fractionation fees, which accounted for a $ 64.5 million increase, and higher propylene and associated by-product sales volumes, which accounted for an additional $ 27.8 million increase.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 .

Gross operating margin from propylene production and related activities for the nine months ended September 30, 2021 increased $307.3 million when compared to the nine months ended September 30, 2020.

Gross operating margin from our Chambers County propylene production facilities increased a combined $301.5 million period-to-period primarily due to higher average sales margins, which accounted for a $194.4 million increase, and higher propylene fractionation fees, which accounted for an additional $103.0 million increase.

Propylene and associated by-product production volumes at these facilities increased a combined 12 MBPD period-to-period (net to our interest).

Volumes in 2021 were negatively impacted by planned major maintenance activities at our PDH 1 facility during the first quarter.

Gross operating margin from our propylene pipelines in Louisiana increased $ 12.4 million period-to-period primarily due to higher transportation volumes of 25 MBPD.

Butane isomerization and related operations

Second Quarter of 2021 Compared to Second Quarter of 2020 .

Gross operating margin from butane isomerization and related operations increased a net $4.0 million quarter-to-quarter primarily due to higher by-product sales, which accounted for a $7.8 million increase, and higher isomerization and standalone DIB processing volumes, which accounted for an additional $6.4 million increase, partially offset by higher operating costs, which accounted for a $6.9 million decrease.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020 .

Gross operating margin from isomerization and related operations decreased a net $0.9 million period-to-period primarily due to higher operating costs, which accounted for a $14.4 million decrease, partially offset by higher by-product sales, which accounted for an $8.9 million increase, and higher standalone DIB processing volumes, which accounted for an additional $4.5 million increase.

Third Quarter of 2021 Compared to Third Quarter of 2020 .

Gross operating margin from butane isomerization and related operations increased $9.1 million quarter-to-quarter primarily due to higher by-product sales.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 .

Gross operating margin from butane isomerization and related operations increased $8.2 million period-to-period primarily due to higher by-product sales, which accounted for a $17.3 million increase, partially offset by higher operating costs, which accounted for a $10.5 million decrease.

Octane enhancement and related plant operations

Second Quarter of 2021 Compared to Second Quarter of 2020 .

Gross operating margin from our octane enhancement and related plant operations decreased $18.6 million quarter-to-quarter primarily due to higher operating costs, which accounted for a $7.3 million decrease, and lower sales volumes, which accounted for an additional $6.8 million decrease.

Production volumes at our octane enhancement plant were down 4 MBPD quarter-to-quarter primarily due to planned major maintenance activities that were completed at the beginning of May 2021.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020 .

Gross operating margin from our octane enhancement and related plant operations decreased $72.1 million period-to-period primarily due to lower average sales margins (including the impact of hedging activities), which accounted for a $33.9 million decrease, lower sales volumes, which accounted for a $26.3 million decrease, and higher operating costs, which accounted for an additional $12.3 million decrease.

Third Quarter of 2021 Compared to Third Quarter of 2020 .

Gross operating margin from our octane enhancement and related plant operations increased $5.2 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $9.3 million increase, partially offset by higher operating costs, which accounted for a $5.7 million decrease.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 .

Gross operating margin from our octane enhancement and related plant operations decreased $66.9 million period-to-period primarily due to lower average sales margins (including the impact of hedging activities), which accounted for a $41.3 million decrease, lower sales volumes, which accounted for an $8.2 million decrease, and higher operating costs, which accounted for an additional $17.9 million decrease.

Production volumes at these facilities for 2021 were lower when compared to 2020 primarily due to planned major maintenance activities, which were completed in the last week of January 2021 for our HPIB plant and the beginning of May 2021 for our octane enhancement plant.

Refined products pipelines and related activities

Second Quarter of 2021 Compared to Second Quarter of 2020 .

Gross operating margin from refined products pipelines and related activities for the second quarter of 2021 increased $3.3 million when compared to the second quarter of 2020.

Gross operating margin from our TE Products Pipeline System increased $ 14.8 million quarter-to-quarter primarily due to higher interstate refined product transportation volumes of 52 MBPD.

Overall, transportation volumes on our TE Products Pipeline System increased a net 146 MBPD quarter-to-quarter primarily due to recovering demand for motor fuels.

Gross operating margin at our refined products terminal in Beaumont, Texas increased $ 1.2 million quarter-to-quarter primarily due to lower maintenance and other operating costs.

Terminaling volumes at Beaumont decreased 59 MBPD quarter-to-quarter.

Gross operating margin from our refined products marketing activities decreased $ 12.0 million quarter-to-quarter primarily due to lower sales volumes.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020 .

Gross operating margin from refined products pipelines and related activities for the six months ended June 30, 2021 increased $30.5 million when compared to the six months ended June 30, 2020.

Gross operating margin from our refined products marketing activities increased a net $ 16.2 million period-to-period primarily due to higher sales volumes, which accounted for a $ 23.2 million increase, partially offset by lower average sales margins (including the impact of hedging activities), which accounted for a $6.8 million decrease.

Gross operating margin at our TE Products Pipeline System increased $ 13.2 million period-to-period primarily due to higher aggregate interstate and intrastate refined product transportation volumes of 86 MBPD.

Third Quarter of 2021 Compared to Third Quarter of 2020 .

Gross operating margin from refined products pipelines and related activities for the third quarter of 2021 decreased $43.6 million when compared to the third quarter of 2020.

Gross operating margin from our refined products marketing activities decreased $43.1 million quarter-to-quarter primarily due to lower average sales margins (including the impact of hedging activities).

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 .

Gross operating margin from refined products pipelines and related activities for the nine months ended September 30, 2021 decreased $13.1 million when compared to the nine months ended September 30, 2020.

Gross operating margin from our refined products marketing activities decreased a net $27.1 million period-to-period primarily due to lower average sales margins (including the impact of hedging activities), which accounted for a $44.3 million decrease, partially offset by higher sales volumes, which accounted for a $17.6 million increase.

Gross operating margin at our TE Products Pipeline System increased $11.1 million period-to-period primarily due to higher aggregate transportation volumes and related fees.

Overall, transportation volumes on our TE Products Pipeline System increased a net 82 MBPD period-to-period.

Ethylene exports and other services

Second Quarter of 2021 Compared to Second Quarter of 2020 .

Gross operating margin from ethylene exports and other services during the second quarter of 2021 increased $2.8 million when compared to the second quarter of 2020.

Gross operating margin from our ethylene export terminal and related operations increased $ 10.1 million quarter-to-quarter primarily due to higher loading volumes of 6 MBPD (net to our interest).

Gross operating margin from marine transportation decreased $ 7.3 million quarter-to-quarter primarily due to lower average fees.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020 .

Gross operating margin from ethylene exports and other services during the six months ended June 30, 2021 decreased $0.4 million when compared to the six months ended June 30, 2020.

Third Quarter of 2021 Compared to Third Quarter of 2020 .

Gross operating margin from ethylene exports and other services during the third quarter of 2021 decreased $1.0 million when compared to the third quarter of 2020.

Gross operating margin from marine transportation decreased $5.5 million quarter-to-quarter primarily due to higher operating costs.

Gross operating margin from our ethylene export terminal and related operations increased $4.4 million quarter-to-quarter primarily due to higher storage revenues and other fees.

Loading volumes at our ethylene terminal decreased 3 MBPD (net to our interest).

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 .

Gross operating margin from ethylene exports and other services during the nine months ended September 30, 2021 decreased $1.4 million when compared to the nine months ended September 30, 2020.

Gross operating margin from marine transportation decreased $24.2 million period-to-period primarily due to lower average fees and lower fleet utilization rates.

Gross operating margin from our ethylene export terminal and its related operations increased $22.7 million period-to-period primarily due to higher loading volumes of 3 MBPD (net to our interest).

Gross operating margin from marine transportation decreased $ 18.7 million period-to-period primarily due to lower fleet utilization rates and lower average fees.

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, 2021, we had $ 5.4 billion of consolidated liquidity, which was comprised of $ 5.0 billion of available borrowing capacity under EPO’s revolving credit facilities and $ 404.5 million of unrestricted cash on hand.

At September 30, 2021, we had $ 6.7 billion of consolidated liquidity, which was comprised of $ 4.5 billion of available borrowing capacity under EPO’s revolving credit facilities and $ 2.2 billion of unrestricted cash on hand.

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

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

Enterprise Declares Cash Distribution for Second Quarter of 2021

On July 9, 2021, we announced that the Board declared a quarterly cash distribution of $0.45 per common unit, or $1.80 per unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the second quarter of 2021.

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

Enterprise Declares Cash Distribution for Third Quarter of 2021

On October 12 , 2021, we announced that the Board declared a quarterly cash distribution of $0.45 per common unit, or $1.80 per unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the third quarter of 2021.

The quarterly distribution is payable on November 12 , 2021 to unitholders of record as of the close of business on October 29, 2021.

The total amount to be paid is $ 989.7 million, which includes $ 7.8 million for distribution equivalent rights on phantom unit awards.

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Consolidated Debt

At June 30, 2021, the average maturity of EPO’s consolidated debt obligations was approximately 20.8 years.

The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at June 30, 2021 for the years indicated (dollars in millions):

At September 30, 2021, the average maturity of EPO’s consolidated debt obligations was approximately 20.9 years.

The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at September 30, 2021 for the years indicated (dollars in millions):

Scheduled Maturities of Debt

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

Expected Renewal of September 2020 364-Day Revolving Credit Agreement

and Extension of Multi-Year Revolving Credit Agreement

EPO’s September 2020 364-Day Revolving Credit Agreement is scheduled to mature in September 2021.

As a result, EPO expects to renew this credit agreement during the third quarter of 2021.

In addition, EPO expects to extend the maturity date of its Multi-Year Revolving Credit Agreement from September 2024 to September 2026 during the third quarter of 2021.

At June 30, 2021, there were no principal amounts outstanding under either the September 2020 364-Day Revolving Credit Agreement or the Multi-Year Revolving Credit Agreement.

In September 2021, EPO entered into a new 364-Day Revolving Credit Agreement (the “September 2021 364-Day Revolving Credit Agreement”) that replaced its September 2020 364-Day Revolving Credit Agreement.

The September 2021 364-Day Revolving Credit Agreement matures in September 2022.

EPO’s borrowing capacity was unchanged from the prior 364-day revolving credit agreement.

As of September 30, 2021, there are no principal amounts outstanding under this new revolving credit agreement.

In September 2021, EPO entered into a new revolving credit agreement that matures in September 2026 (the “September 2021 Multi-Year Revolving Credit Agreement”).

The September 2021 Multi-Year Revolving Credit Agreement replaced EPO’s prior multi-year revolving credit agreement that was scheduled to mature in September 2024.

EPO’s borrowing capacity decreased from $3.5 billion under the prior multi-year revolving credit agreement to $3.0 billion (which may be increased by up to $500.0 million to $3.5 billion at EPO’s election, provided certain conditions are met) under the September 2021 Multi-Year Revolving Credit agreement.

As of September 30, 2021, there are no principal amounts outstanding under this new revolving credit agreement.

In September 2021, EPO issued $1.0 billion in principal amount of senior notes due February 2053 (“Senior Notes EEE”).

Senior Notes EEE were issued at 99.170% of their principal amount and have a fixed rate of interest of 3.30% per year.

Net proceeds from the issuance of these senior notes will be used for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of a portion of our $750.0 million in principal amount of 3.50% Senior Notes VV and/or a portion of our $650.0 million in principal amount of 4.05% Senior Notes CC, in each case at their maturity in February 2022).

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

Credit Ratings

As of August 9, 2021, the investment-grade credit ratings of EPO’s long-term senior unsecured debt securities were BBB+ from Standard and Poor’s, Baa1 from Moody’s and BBB+ from Fitch Ratings.

As of November 8 , 2021, the investment-grade credit ratings of EPO’s long-term senior unsecured debt securities were BBB+ from Standard and Poor’s, Baa1 from Moody’s and BBB+ from Fitch Ratings.

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

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

In January 2021, the Partnership settled open market repurchase transactions initiated in December 2020 involving an aggregate 709,816 common units.

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

As of June 30, 2021, the remaining available capacity under the 2019 Buyback Program was $1.72 billion.

The Partnership repurchased an aggregate 3,367,377 and 4,077,193 common units through open market purchases during the three and nine months ended September 30, 2021, respectively.

The total cost of these repurchases, including commissions and fees, was $74.9 million and $88.8 million, respectively.

As of September 30, 2021, the remaining available capacity under the 2019 Buyback Program was $1.64 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,

For the Nine Months

Ended September 30,

Net cash flows provided by operating activities

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Operating activities

Net cash flows provided by operating activities for the six months ended June 30, 2021 increased $ 823.2 million when compared to the six months ended June 30, 2020 primarily due to:

a $330.6 million period-to-period increase attributable to the return of working capital employed in our marketing activities.

Cash receipts attributable to the return of working capital employed in our marketing activities were $ 189.8 million in the six months ended June 30, 2021 compared to cash payments of $140.8 million in the six months ended June 30, 2020;

Net cash flows provided by operating activities for the nine months ended September 30, 2021 increased $ 2.1 billion when compared to the nine months ended September 30, 2020 primarily due to:

a $ 1.02 b illion period-to-period increase primarily due to the timing of cash receipts and payments related to operations;

a $715.9 million period-to-period increase attributable to the return of working capital employed in our marketing activities primarily related to storage optimization strategies;

a $288.1 million period-to-period increase resulting from higher partnership earnings (determined by adjusting our $170.9 million period-to-period increase in net income for changes in the non-cash items identified on our Unaudited Condensed Statements of Consolidated Cash Flows);

a $ 157.6 million period-to-period increase in cash related to the timing of cash receipts and payments related to operations.

a $68.5 million period-to-period increase in cash distributions received on earnings from unconsolidated affiliates primarily attributable to our investments in crude oil pipelines.

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

Investing activities

Cash used in investing activities during the six months ended June 30, 2021 decreased $ 701.8 million when compared to the six months ended June 30, 2020 primarily due to a $ 674.7 million period-to-period decrease in investments for property, plant and equipment (see “ Capital Investments ” within this Part I, Item 2 for additional information).

Cash used in investing activities during the nine months ended September 30, 2021 decreased $842.7 million when compared to the nine months ended September 30, 2020 primarily due to an $865.9 million period-to-period decrease in investments for property, plant and equipment (see “ Capital Investments ” within this Part I, Item 2 for additional information).

Financing activities

Cash used in financing activities during the six months ended June 30, 2021 increased $ 3.1 billion when compared to the six months ended June 30, 2020 primarily due to:

a net cash outflow of $ 1.25 billion related to debt during the six months ended June 30, 2021 compared to a net cash inflow of $ 1.94 billion during the six months ended June 30, 2020.

During the six months ended June 30, 2021, we repaid $1.33 billion aggregate principal amount of senior notes.

During the six months ended June 30, 2020, we issued $3.0 billion aggregate principal amount of senior notes, partially offset by the repayment of $500 million principal amount of senior notes.

In addition, net repayments of short term notes under EPO’s commercial paper program were $481.8 million during the six months ended June 30, 2020;

cash used to acquire Partnership common units under the 2019 Buyback Program decreased $ 126.2 million period-to-period.

Cash used in financing activities during the nine months ended September 30, 2021 increased $2.46 billion when compared to the nine months ended September 30, 2020.

The period-to-period increase was primarily due to a net cash outflow of $273.2 million related to debt during the nine months ended September 30, 2021 compared to a net cash inflow of $2.19 billion during the nine months ended September 30, 2020.

During the nine months ended September 30, 2021, we repaid $1.33 billion aggregate principal amount of senior notes, partially offset by the issuance of $1.0 billion principal amount of senior notes.

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

In addition, net repayments of short term notes under EPO’s commercial paper program were $481.8 million during the nine months ended September 30, 2020.

Non-GAAP Cash Flow Measures

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For the Three Months

Ended June 30,

For the Six Months

Ended June 30,

Ended September 30,

For the Nine Months

Ended September 30,

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

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

The six months ended June 30, 2021 includes $99.7 million of trade accounts receivable that we do not expect to collect in the normal billing cycle.

The nine months ended September 30, 2021 includes $100 million of trade accounts receivable that we do not expect to collect in the normal billing cycle.

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

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For the Three Months

Ended June 30,

For the Six Months

Ended June 30,

Ended September 30,

For the Nine Months

Ended September 30,

Net cash flows provided by operating activities (GAAP)

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For the Three Months

Ended June 30,

For the Six Months

Ended June 30,

Ended September 30,

For the Nine Months

Ended September 30,

Net cash flows provided by operating activities (GAAP)

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

For the Six Months

Ended June 30,

For the Nine Months

Ended September 30,

Capital investments for property, plant and equipment:

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Sustaining capital expenditures include the costs of major maintenance activities at our reaction-based plants, which are accounted for using the deferral method.

We currently have $ 3.1 billion of growth capital projects scheduled to be completed by the end of 2023, which includes completion of a natural gasoline hydrotreater facility at our Chambers County complex in the fourth quarter of 2021, the Gillis Lateral natural gas pipeline and related infrastructure in the fourth quarter of 2021, and our PDH 2 facility in the second quarter of 2023.

As of September 30, 2021, we have $ 2.9 billion of growth capital projects scheduled to be placed into service by the end of 2023.

This includes a natural gasoline hydrotreater facility at our Chambers County complex, which was placed into service in October 2021, the Gillis Lateral natural gas pipeline and its related infrastructure in the fourth quarter of 2021 and our PDH 2 facility in the second quarter of 2023.

Based on information currently available, we expect our total capital investments for 2021, net of expected contributions from noncontrolling interests, to approximate $ 2.2 billion for sanctioned projects, which reflects growth capital investments of $ 1.7 billion and sustaining capital expenditures of $ 440 million.

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

In addition, we currently expect our growth capital investments in 2022 for sanctioned projects to approximate $ 800 million;

however, growth capital expenditures for 2022 could ultimately be in the range of $1.0 billion to $1.5 billion considering projects currently under development.

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

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

We currently anticipate receiving approval for SPOT as early as mid-2022;

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

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

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.

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

Comparison of Six Months Ended June 30, 2021 with Six Months Ended June 30, 2020

Comparison of Nine Months Ended September 30, 2021 with Nine Months Ended September 30, 2020

In total, investments in growth capital projects decreased $966.6 million period-to-period primarily due to the following:

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lower investments in Permian Basin natural gas processing facilities and related infrastructure, which accounted for a $68.7 million decrease;

lower investments in projects attributable to our ethylene business, which accounted for a $53.6 million decrease;

lower investments in natural gas pipelines and related infrastructure in support of East Texas and Louisiana producers, which accounted for a $14.9 million decrease.

Investments attributable to sustaining capital projects increased $105.2 million period-to-period primarily due to the cost of major maintenance activities performed during the six months ended June 30, 2021 at certain of our reaction-based plants (PDH 1, octane enhancement and high purity isobutylene facilities).

lower investments in projects related to our ethylene business, which accounted for a $52.6 million decrease.

Investments attributable to sustaining capital projects increased $100.7 million period-to-period primarily due to the cost of major maintenance activities performed during the nine months ended September 30, 2021 at certain of our reaction-based plants (PDH 1, octane enhancement and high purity isobutylene facilities).

These costs accounted for $97.0 million of the period-to-period increase in sustaining capital investments.

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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, 2021, the total amount of Guaranteed Debt was $ 29.25 billion, which was comprised of $26.18 billion of EPO’s senior notes, $2.63 billion of EPO’s junior subordinated notes and $ 443.0 million of related accrued interest.

At September 30, 2021, the total amount of Guaranteed Debt was $ 30.03 billion, which was comprised of $ 27.17 billion of EPO’s senior notes, $ 2.63 billion of EPO’s junior subordinated notes and $ 225.1 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.

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

The total carrying value of the Obligor Group’s investments in the Non-Obligor Subsidiaries was $ 45.38 billion at June 30, 2021.

The Obligor Group’s equity in the earnings of the Non-Obligor Subsidiaries for the six months ended June 30, 2021 was $ 1.91 billion.

The total carrying value of the Obligor Group’s investments in the Non-Obligor Subsidiaries was $ 45.62 billion at September 30, 2021.

The Obligor Group’s equity in the earnings of the Non-Obligor Subsidiaries for the nine months ended September 30, 2021 was $ 3.15 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.

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Selected asset information:

June 30, 2021

December 31, 2020

September 30,

Current receivables from Non-Obligor Subsidiaries

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Long-term receivables from Non-Obligor Subsidiaries

Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries of $ 45.38 billion at June 30, 2021 and $45.98 billion at December 31, 2020

Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries of $ 45.62 billion at September 30, 2021 and $45.98 billion at December 31, 2020

Selected liability information:

Current portion of Guaranteed Debt, including interest of $ 443.0 million at June 30, 2021 and $455.6 million at December 31, 2020

Current portion of Guaranteed Debt, including interest of $ 225.1 million at September 30, 2021 and $455.6 million at December 31, 2020

Current payables to Non-Obligor Subsidiaries

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

June 30, 2021

September 30,

For the Twelve

December 31, 2020

Revenues from Non-Obligor Subsidiaries

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Operating income of Obligor Group

Net income (loss) of Obligor Group excluding equity in earnings of Non-Obligor Subsidiaries of $ 1.91 billion for the six months ended June 30, 2021 and $3.54 billion for the twelve months ended December 31, 2020

Net income (loss) of Obligor Group excluding equity in earnings of Non-Obligor Subsidiaries of $ 3.15 billion for the nine months ended September 30, 2021 and $3.54 billion for the twelve months ended December 31, 2020

Contractual Obligations

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

Our product purchase commitments increased from $14.80 billion at December 31, 2020 to $ 20.95 billion at June 30, 2021 primarily due to an increase in crude oil and NGL prices between the two reporting dates.

Our product purchase commitments increased from $14.8 billion at December 31, 2020 to $ 22.1 billion at September 30, 2021 primarily due to an increase in crude oil and NGL prices between the two reporting dates.

Off-Balance Sheet Arrangements

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

What changed 10-Q

Item 2. Management’s Discussion and Analysis