What changed in this filing

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Item 2. Management’s Discussion and Analysis

2021-08-09 compared with 2021-05-07 · 342 added, 178 removed, 455 unchanged (53% of the section changed)

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RESULTS OF OPERATIONS.

For the Three Months Ended March 31, 2021 and 2020

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

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 32.2% of the Partnership’s common units outstanding at March 31, 2021.

EPCO, together with its privately held affiliates, owned approximately 32.1% of the Partnership’s common units outstanding at June 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 first quarter of 2021 compared to the first quarter of 2020.

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.

Business Summary

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As noted previously under “Cautionary Statement Regarding Forward-Looking Information” within this Part I, Item 2, this quarterly report on Form 10-Q, including this update to our outlook on business conditions, contains forward-looking statements that are based on our beliefs and those of Enterprise GP.

In addition, it reflects assumptions made by us and information currently available to us.

With regards to the outlook for hydrocarbon supply and demand fundamentals described in our 2020 Form 10-K, we believe that the underlying trends remain generally intact.

Ongoing 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, continue to provide much-needed support for international energy markets in coping with weakness in hydrocarbon demand attributable to the COVID-19 pandemic.

As vaccination programs are implemented on a wider scale, many countries have eased their COVID-19 containment measures and governments have instituted fiscal measures in an effort to support economic activity.

As a result, hydrocarbon demand has started to recover;

however, a continuation of this trend remains dependent on successful containment of the disease, the efficacy and distribution of approved vaccines on COVID-19 and its emerging variants, and proven therapeutics.

We continue to believe that our integrated, diversified and fee-based business model will enable us to successfully traverse this difficult period.

The Partnership and its consolidated operations remain in a strong position, with our financial strength and operational flexibility demonstrated by $5.11 billion of consolidated liquidity at March 31, 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 value of our diversified and integrated midstream system was exhibited again in the first quarter of 2021.

Our propylene, NGL, refined products and natural gas businesses benefited from greater demand associated with the early stages of an economic recovery, winter demand and higher commodity prices.

This was partially offset by plant and pipeline disruptions and lower volumes attributable to the impacts of major winter storms in mid-February 2021 and major maintenance activities at our PDH 1 and octane enhancement facilities.

Impact of February 2021 Winter Storms

Two major winter storms, Uri and Viola, impacted Texas and the southern U.S.

in mid-February 2021 (the “February 2021 winter storms”).

The storms had a major impact on the electric power grid in Texas, which resulted in widespread power outages.

Voluntarily and in accordance with our agreements with the Electric Reliability Council of Texas, Inc.

(“ERCOT”), we temporarily shut down our non-essential plants and other operations in Texas to support residential power consumption.

Those Texas assets that remained operational (e.g., our natural gas processing plants, storage facilities and Texas Intrastate System) were impacted by rolling blackouts.

The economic impacts of these disruptions, higher power and natural gas costs, as well as losses on natural gas hedges, were mitigated by sales of natural gas to electricity generators, natural gas utilities and industrial customers to assist them in meeting their requirements.

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

Significant Recent Developments

In addition, it reflects assumptions made by us and information currently available to us, which includes forecast information published by third parties.

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 .

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.

Recent Developments

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

In June 2021, we, Magellan Midstream Partners, L.P (“Magellan”) and Intercontinental Exchange, Inc.

(“ICE”) announced the establishment of a new futures contract for the physical delivery of crude oil in the Houston , Texas area in response to market interest for a Houston-based index with greater scale, flow assurance and price transparency .

It will utilize the capabilities and global reach of ICE’s industry-recognized, state-of-the-art trading platform and is due to be launched by ICE by early 2022, subject to regulatory approval.

The quality specifications of the new futures contract will be consistent with WTI originating from the Permian Basin with common delivery options at either our ECHO terminal in Houston or Magellan’s East Houston terminal.

In support of this new futures contract, we and Magellan expect to discontinue provisions for delivery services under legacy futures contracts that are deliverable at each terminal once the new futures contract is finalized and receives regulatory approval.

Enterprise to Increase Its Use of Power from Renewable Resources

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We estimate that by 2025, approximately 25% of our power will be from renewable resources.

Enterprise and Magellan to Develop Joint Houston Crude Oil Futures Contract

In January 2021, we and Magellan Midstream Partners, L.P (“Magellan”) announced that our affiliates had entered into an agreement to jointly develop a futures contract for the physical delivery of crude oil in the Houston, Texas area in response to market interest for a Houston-based index with greater scale, flow assurance and price transparency.

The quality specifications will be consistent with WTI crude oil originating from the Permian Basin with delivery capabilities at either our ECHO terminal in Houston or Magellan’s East Houston terminal.

Selected Energy Commodity Price Data

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2021 by quarter:

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.

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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 $0.61 per gallon in the first quarter of 2021 versus $0.35 per gallon in the first quarter of 2020.

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.

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

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2021 by quarter:

2021 Averages

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

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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.

The same type of correlation would be true in the case of lower energy commodity sales prices and purchase costs.

The same type of relationship would be true in the case of lower energy commodity sales prices and purchase costs.

We attempt to mitigate commodity price exposure through our hedging activities and the use of fee-based arrangements.

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For the Three Months

Ended March 31,

Ended June 30,

For the Six Months

Ended June 30,

Costs and expenses:

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For the Three Months

Ended March 31,

Ended June 30,

For the Six Months

Ended June 30,

NGL Pipelines & Services:

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Total consolidated revenues

Total revenues for the first quarter of 2021 increased $1.67 billion when compared to the first quarter of 2020 primarily due to a net $1.67 billion increase in marketing revenues.

Revenues from the marketing of NGLs, natural gas, petrochemicals and refined products increased a combined $1.52 billion quarter-to-quarter primarily due to higher average sales prices, which accounted for a $2.1 billion increase, partially offset by lower sales volumes, which accounted for a $580.3 million decrease.

Revenues from the marketing of crude oil increased $142.0 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $121.7 million increase, and higher average sales prices, which accounted for an additional $20.3 million increase.

Revenues from midstream services for the first quarter of 2021 increased $6.9 million when compared to the first quarter of 2020.

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.

Revenues from our natural gas processing facilities increased $70.6 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 propylene production facilities increased $36.3 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.

Revenues from our pipeline assets decreased $24.6 million quarter-to-quarter primarily due to lower demand for natural gas transportation services.

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.

Revenues from our natural gas processing facilities increased $58.3 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 propylene production facilities increased $51.9 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 first quarter of 2021 increased $1.49 billion when compared to the first quarter of 2020 primarily due to higher cost of sales.

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.

Cost of sales

Cost of sales increased $1.44 billion for the first quarter of 2021 when compared to the first quarter of 2020.

On a combined basis, the cost of sales associated with our marketing of NGLs, natural gas, petrochemicals and refined products increased a net $1.13 billion quarter-to-quarter primarily due to higher average purchase prices, which accounted for a $1.44 billion increase, partially offset by lower sales volumes, which accounted for a $313.7 million decrease.

The cost of sales associated with our marketing of crude oil increased $311.6 million quarter-to-quarter primarily due to higher average purchase prices, which accounted for a $199.8 million increase, and higher sales volumes, which accounted for an additional $111.8 million increase.

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.

The cost of sales associated with our marketing of crude oil increased $ 1.49 billion period-to-period primarily due to higher average purchase prices, which accounted for a $ 1.09 billion increase, and higher sales volumes, which accounted for an additional $ 401.5 million increase.

Depreciation, amortization and accretion expenses

Depreciation, amortization and accretion expense for the first quarter of 2021 increased a combined $15.9 million when compared to the first quarter of 2020 primarily due to assets placed into full or limited service since the first quarter of 2020 (e.g., Chambers County Fracs X and XI and the Midland-to-ECHO 3 pipeline).

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.

Asset impairment charges

Non-cash asset impairment charges for the first quarter of 2021 increased $63.9 million when compared to the first quarter of 2020 primarily due to a $43.4 million charge attributable to a coal bed natural gas gathering system and related Val Verde treating facility, both of which were components of our San Juan Gathering System and classified as held-for-sale at March 31, 2021.

See Note 4 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for additional information regarding our 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.

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 first quarter of 2021 decreased $26.7 million when compared the first quarter of 2020 primarily due to lower maintenance, chemical and facility charges.

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 first quarter of 2021 increased $0.8 million when compared to the first quarter of 2020 primarily due to higher employee compensation 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.

Equity in income of unconsolidated affiliates

Equity income from our unconsolidated affiliates for the first quarter of 2021 increased $8.1 million when compared to the first quarter of 2020 primarily due to increased earnings from our investments in crude oil pipelines.

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.

Operating income

Operating income for the first quarter of 2021 increased $187.0 million when compared to the first quarter of 2020 due to the previously described quarter-to-quarter changes.

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.

Interest expense

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For the Three Months

Ended March 31,

Ended June 30,

For the Six Months

Ended June 30,

Interest charged on debt principal outstanding

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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 a net $4.6 million quarter-to-quarter primarily due to the effects of lower overall interest rates during the first quarter of 2021, which accounted for an $8.9 million decrease, partially offset by higher debt principal amounts outstanding during the first quarter of 2021, which accounted for a $4.3 million increase.

Our weighted-average debt principal balance for the first quarter of 2021 was $29.96 billion compared to $29.39 billion for the first quarter of 2020.

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

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.

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 March 31,

Ended June 30,

For the Six Months

Ended June 30,

Deferred tax benefit (expense) attributable to OTA

Texas Margin Tax

Revised Texas Franchise Tax (“Texas Margin Tax”)

Benefit from (provision for) income taxes

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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 first quarter of 2020.

OTA recognized an additional net, non-cash deferred income tax benefit of $115.0 million primarily due to a decrease in the outside basis difference of its investment in the Partnership attributable to a decline in the market price of the Partnership’s common units subsequent to March 5, 2020 through March 31, 2020.

In total, our earnings for the first quarter of 2020 reflect $187.2 million of deferred income tax benefit attributable to OTA.

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.

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

As a result, beginning September 30, 2020, OTA’s deferred tax liability no longer fluctuates due to market price changes in our common units.

Income tax expense attributable to the Texas Margin Tax increased $17.1 million quarter-to-quarter and $12.7 million period-to-period primarily due to an increase in the Texas apportionment factor and higher Partnership earnings.

Business Segment Highlights

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For the Three Months

Ended March 31,

Ended June 30,

For the Six Months

Ended June 30,

Gross operating margin by segment:

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For the Three Months

Ended March 31,

Ended June 30,

For the Six Months

Ended June 30,

Operating income

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(addition or subtraction indicated by sign):

Depreciation, amortization and accretion expense in operating costs and expenses (1)

Depreciation, amortization and accretion expense in operating costs

and expenses (1)

Asset impairment charges in operating costs and expenses

Net losses attributable to asset sales and related matters in operating costs

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

costs and expenses

General and administrative costs

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

Two major winter storms, Uri and Viola, impacted Texas and the southern U.S.

in mid-February 2021 (the “February 2021 winter storms”).

The storms had a major impact on the electric power grid in Texas, which resulted in widespread power outages.

Voluntarily and in accordance with our agreements with the Electric Reliability Council of Texas, Inc.

(“ERCOT”), we temporarily shut down our non-essential plants and other operations in Texas to support residential power consumption.

Those Texas assets that remained operational (e.g., our natural gas processing plants, storage facilities and Texas Intrastate System) were impacted by rolling blackouts.

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

NGL Pipelines & Service s

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For the Three Months

Ended March 31,

Ended June 30,

For the Six Months

Ended June 30,

Segment gross operating margin:

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Natural gas processing and related NGL marketing activities

Gross operating margin from natural gas processing and related NGL marketing activities for the first quarter of 2021 increased $42.0 million when compared to the first quarter of 2020.

Gross operating margin from our NGL marketing activities increased $96.7 million quarter-to-quarter primarily due to higher average sales margins (including the impact of hedging activities), which accounted for a $53.7 million increase, and higher sales volumes, which accounted for an additional $46.6 million increase.

Results from marketing strategies that optimize our transportation, storage and plant assets increased a combined $95.4 million quarter-to-quarter, partially offset by lower earnings from the optimization of our export assets, which accounted for a $47.1 million decrease.

Gross operating margin from our Permian Basin natural gas processing facilities increased $10.0 million quarter-to-quarter primarily due to higher fee-based processing volumes, which accounted for a $6.7 million increase, and higher average processing margins (including the impact of hedging activities), which accounted for an additional $3.5 million increase.

Fee-based processing volumes and equity NGL production at our Permian Basin natural gas processing facilities increased 193 MMcf/d and 31 MBPD, respectively, quarter-to-quarter.

Gross operating margin from our South Texas natural gas processing facilities decreased $41.2 million quarter-to-quarter primarily due to lower equity NGL production of 6 MBPD, which accounted for a $28.8 million decrease, lower average processing fees and volumes, which accounted for decreases of $12.3 million and $3.7 million, respectively, and higher operating and maintenance costs, which accounted for an additional $6.1 million decrease.

Partially offsetting these negative impacts were higher average processing margins (including the impact of hedging activities), which accounted for a $9.8 million quarter-to-quarter increase.

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.

Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) increased a combined $29.1 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.

Gross operating margin from our Louisiana and Mississippi natural gas processing facilities increased $14.9 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities).

Fee-based natural gas processing volumes decreased 71 MMcf/d and equity NGL production increased 6 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 Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased a combined $21.5 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $19.4 million decrease, and lower fee-based processing volumes, which accounted for an additional $6.2 million decrease, partially offset by lower operating costs, which accounted for a $4.1 million increase.

On a combined basis, fee-based natural gas processing volumes decreased 402 MMcf/d quarter-to-quarter.

Gross operating margin from our Louisiana and Mississippi natural gas processing facilities decreased $1.2 million quarter-to-quarter primarily due to lower average processing fees.

Net to our interest, fee-based natural gas processing volumes and equity NGL production decreased 184 MMcf/d and 5 MBPD, respectively, 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.

Fee-based natural gas processing volumes decreased 127 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.

Fee-based processing volumes at these facilities decreased 130 MMcf/d period-to-period.

NGL pipelines, storage and terminals

Gross operating margin from our NGL pipelines, storage and terminal assets during the first quarter of 2021 decreased $26.7 million when compared to the first quarter of 2020.

A number of our pipelines, including the Mid-America Pipeline System, Seminole NGL Pipeline, Chaparral NGL Pipeline, Shin Oak NGL Pipeline, Texas Express Pipeline and Front Range Pipeline, serve Permian Basin and/or Rocky Mountain producers.

On a combined basis, gross operating margin from these pipelines decreased a net $21.8 million quarter-to-quarter primarily due to lower transportation volumes of 213 MBPD (net to our interest), which accounted for a $44.0 million decrease, partially offset by higher average transportation fees, which accounted for an $18.6 million increase.

Gross operating margin from LPG-related activities at EHT decreased $15.1 million quarter-to-quarter primarily due to lower export volumes of 95 MBPD.

Gross operating margin from our related Houston Ship Channel Pipeline System decreased $3.6 million quarter-to-quarter primarily due to a 144 MBPD decrease in transportation volumes.

Our marine terminal operations on the Houston Ship Channel were halted for 3 days due to closure of the ship channel during the February 2021 winter storms.

Gross operating margin from our South Texas NGL Pipeline System decreased $4.9 million quarter-to-quarter primarily due to lower transportation volumes of 55 MBPD.

Gross operating margin from our South Louisiana storage facilities increased $4.6 million quarter-to-quarter primarily due to higher product blending revenues.

Gross operating margin from our Chambers County storage complex increased a net $4.4 million quarter-to-quarter primarily due to higher storage fees, which accounted for a $15.1 million increase, partially offset by lower throughput fee revenues, which accounted for an $8.4 million decrease, and higher operating costs, which accounted for an additional $3.4 million decrease.

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.

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.

Transportation volumes on these pipelines decreased a combined 5 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 from our Chambers County storage complex decreased a net $10.9 million period-to-period primarily due to lower throughput fee revenues, which accounted for a $16.0 million decrease, and higher operating costs, which accounted for an additional $14.7 million decrease, partially offset by higher storage fee revenues, which accounted for a $19.8 million increase.

Gross operating margin from our South Texas NGL Pipeline System increased $8.8 million period-to-period primarily due to higher pipeline capacity fee revenues earned from an affiliate pipeline.

Transportation volumes on our South Texas NGL Pipeline System decreased 14 MBPD period-to-period.

NGL fractionation

Gross operating margin from NGL fractionation during the first quarter of 2021 increased $29.1 million when compared to the first quarter of 2020.

Gross operating margin from our Chambers County NGL fractionation complex increased $41.2 million quarter-to-quarter primarily due to higher volumes, including contributions from Frac X, which entered service in late March 2020, and Frac XI, which entered service in September 2020.

NGL fractionation volumes increased 159 MBPD quarter-to-quarter (net to our interest).

Gross operating margin from our South Texas NGL fractionators decreased $4.7 million quarter-to-quarter primarily due to lower NGL fractionation volumes of 49 MBPD.

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.

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.

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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For the Three Months

Ended March 31,

Ended June 30,

For the Six Months

Ended June 30,

Segment gross operating margin:

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Crude oil marine terminal volumes (MBPD)

Gross operating margin from our Crude Oil Pipelines & Services segment for the first quarter of 2021 decreased $52.7 million when compared to the first quarter of 2020.

Gross operating margin from our South Texas Crude Oil Pipeline System decreased $25.7 million quarter-to-quarter primarily due to lower transportation and other fees, which accounted for a $15.3 million decrease, and lower transportation volumes of 49 MBPD, which accounted for an additional $12.4 million decrease.

Gross operating margin from our equity investment in the Eagle Ford Crude Oil Pipeline decreased $11.3 million quarter-to-quarter primarily due to lower transportation volumes of 93 MBPD (net to our interest).

Gross operating margin from our West Texas Pipeline System decreased $19.9 million quarter-to-quarter primarily due to lower transportation volumes of 57 MBPD, which accounted for an $8.4 million decrease, and lower average fees, which accounted for an additional $7.9 million decrease.

Gross operating margin from our Midland-to-ECHO System and related business activities decreased $11.4 million quarter-to-quarter primarily due to lower average sales margins from marketing activities (including the impact of hedging activities), which accounted for a $21.2 million decrease, partially offset by lower chemical and other operating costs, which accounted for a $12.1 million increase.

Transportation volumes for our Midland-to-ECHO System decreased an aggregate 6 MBPD quarter-to-quarter (net to our interest).

Gross operating margin from our ECHO terminal decreased $4.9 million quarter-to-quarter primarily due to lower terminaling and storage revenues.

Gross operating margin from our other crude oil marketing activities increased $16.6 million quarter-to-quarter primarily due to higher average sales margins (including the impact of hedging activities).

Gross operating margin from crude oil activities at EHT increased $8.9 million quarter-to-quarter primarily due to lower operating costs.

Loading volumes at EHT decreased 380 MBPD in the first quarter of 2021 due to lower export activity.

Gross operating margin from our equity investment in the Seaway Pipeline increased slightly quarter-to-quarter.

Higher capacity and other fees of $9.0 million quarter-to-quarter were substantially offset by the effects of lower transportation volumes of 182 MBPD (net to our interest), which accounted for a $7.7 million decrease.

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.

Gross operating margin from our crude oil marketing activities (excluding those attributable to the Midland-to-ECHO System) decreased $218.7 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 $141.8 million and $35.4 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 $7.6 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.

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 crude oil marketing activities (excluding those attributable to the Midland-to-ECHO System) decreased $202.1 million period-to-period 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 $117.3 million and $37.2 million period-to-period, respectively.

In addition, gross operating margin attributable to non-cash, mark-to-market earnings decreased $29.0 million period-to-period.

Gross operating margin from our South Texas Crude Oil Pipeline System decreased $32.0 million period-to-period primarily due to lower transportation volumes of 34 MBPD, which accounted for a $19.1 million decrease, and lower average transportation fees, which accounted for an additional $15.1 million decrease.

Gross operating margin from our equity investment in the Eagle Ford Crude Oil Pipeline decreased $9.5 million period-to-period primarily due to lower transportation volumes of 56 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.

Transportation volumes on our Seaway Pipeline decreased 117 MBPD period-to-period (net to our interest).

Natural Gas Pipelines & Services

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For the Three Months

Ended March 31,

Ended June 30,

For the Six Months

Ended June 30,

Segment gross operating margin

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Natural gas pipeline transportation volumes (BBtus/d)

Gross operating margin from our Natural Gas Pipelines & Services segment for the first quarter of 2021 increased $251.4 million when compared to the first quarter of 2020.

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.

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

in mid-February 2021.

Given the high demand for natural gas during the storms, we sold natural gas to assist electricity generators, natural gas utilities and industrial customers in meeting their requirements.

Gross operating margin from natural gas marketing activities increased $265.9 million quarter-to-quarter 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 $14.1 million quarter-to-quarter primarily due to higher average condensate sales prices, which accounted for a $6.1 million increase, higher condensate sales volumes, which accounted for a $4.5 million increase, and higher natural gas gathering volumes of 361 BBtus/d, which accounted for an additional $4.3 million increase, partially offset by lower average gathering fees, which accounted for a $2.9 million decrease.

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

On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System, and San Juan Gathering System in the Rocky Mountains increased a net $0.8 million quarter-to-quarter primarily due to higher average gathering and other fees, which accounted for a $6.9 million increase, and lower operating costs, which accounted for an additional $3.6 million increase, partially offset by lower gathering volumes of 503 BBtus/d, which accounted for a $9.7 million decrease.

Gross operating margin from our Acadian Gas System decreased $14.2 million primarily due to a one-time producer payment in the first quarter of 2020, which accounted for a $12.5 million quarter-to-quarter decrease, and lower capacity reservation fees, which accounted for an additional $4.9 million decrease.

Transportation volumes for the Acadian Gas System decreased 60 BBtus/d quarter-to-quarter.

Gross operating margin from our Texas Intrastate System decreased $12.1 million quarter-to-quarter primarily due to lower capacity reservation revenues.

Transportation volumes on our Texas Intrastate System decreased 11 BBtus/d.

Given the higher demand for natural gas during the storms, we sold natural gas to assist electricity generators, natural gas utilities and industrial customers in meeting their requirements.

Gross operating margin from our natural gas marketing activities increased $238.8 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.

Petrochemical & Refined Products Services

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For the Three Months

Ended March 31,

Ended June 30,

For the Six Months

Ended June 30,

Segment gross operating margin:

13 unchanged sentences

Propylene production and related activities

Gross operating margin from propylene production and related activities for the first quarter of 2021 increased $37.4 million when compared to the first quarter of 2020.

Gross operating margin from our propylene production facilities increased a combined $27.8 million quarter-to-quarter primarily due to higher propylene fractionation fees, which accounted for a $24.7 million increase, and lower operating costs, which accounted for an additional $10.2 million increase, partially offset by lower propylene and associated by-product sales volumes, which accounted for an $8.2 million decrease.

Propylene and associated by-product volumes at these facilities decreased a combined 16 MBPD quarter-to-quarter (net to our interest) primarily due to planned major maintenance activities at our PDH 1 facility during the first quarter of 2021.

The PDH 1 facility returned to service during the second half of March 2021.

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.

Propylene and associated by-product production volumes at these facilities increased a combined 39 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.

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

Gross operating margin from butane isomerization and related operations decreased $4.9 million quarter-to-quarter primarily due to lower isomerization volumes, which accounted for a $6.4 million decrease.

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.

Octane enhancement and related plant operations

Gross operating margin from our octane enhancement and related plant operations decreased $53.5 million quarter-to-quarter primarily due to lower average sales margins (including the impact of hedging), which accounted for a $32.4 million decrease, and lower sales volumes, which accounted for an additional $21.1 million decrease.

Volumes at these facilities were lower in the first quarter of 2021 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.

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.

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

Gross operating margin from refined products pipelines and related activities during the first quarter of 2021 increased $27.2 million when compared to the first quarter of 2020.

Gross operating margin from our refined products marketing activities increased $28.2 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $34.9 million increase, partially offset by lower average sales margins (including the impact of hedging activities), which accounted for a $6.6 million decrease.

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.

Overall, transportation volumes on our TE Products Pipeline System increased a net 70 MBPD period-to-period.

Ethylene exports and other services

Gross operating margin from ethylene exports and other services for the first quarter of 2021 decreased a net $3.2 million when compared to the first quarter of 2020.

Gross operating margin from marine transportation decreased $11.4 million quarter-to-quarter primarily due to lower fleet utilization rates.

Gross operating margin from our ethylene export terminal and its related operations increased $8.2 million quarter-to-quarter primarily due to higher loading volumes of 6 MBPD (net to our interest).

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.

Gross operating margin from our ethylene export terminal and its related operations increased $ 18.3 million period-to-period primarily due to higher loading volumes of 6 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 March 31, 2021, we had $5.11 billion of consolidated liquidity, which was comprised of $4.88 billion of available borrowing capacity under EPO’s revolving credit facilities and $229.4 million of unrestricted cash on hand.

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.

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 First Quarter of 2021

On April 8, 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 first quarter of 2021.

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

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.

The total amount to be paid is $991.4 million, which includes $8.0 million for distribution equivalent rights on phantom unit awards.

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

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

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

Consolidated Debt

At March 31, 2021, the average maturity of EPO’s consolidated debt obligations was approximately 21 years.

The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at March 31, 2021 for the years indicated (dollars in millions):

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):

Scheduled Maturities of Debt

Commercial Paper Notes

Junior Subordinated Notes

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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.

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 May 7, 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 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.

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.

During the first quarter of 2021, the Partnership settled open market repurchase transactions initiated in December 2020 involving an aggregate 709,816 common units.

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 March 31, 2021, the remaining available capacity under the 2019 Buyback Program was $1.72 billion.

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

Ended March 31,

For the Six Months

Ended June 30,

Net cash flows provided by operating activities

Cash used in investing activities

Cash provided by (used in) financing activities

Cash used in financing activities

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

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For additional information regarding our cash flow amounts, please refer to our Unaudited Condensed Statements of Consolidated Cash Flows included under Part I, Item 1 of this quarterly report.

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

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

Operating activities

Net cash flows provided by operating activities for the first quarter of 2021 increased a net $10.9 million when compared to the first quarter of 2020 primarily due to:

a $362.7 million quarter-to-quarter increase in cash related to the timing of cash receipts and payments related to operations;

a $268.6 million quarter-to-quarter increase resulting from higher partnership earnings (determined by adjusting our $12.4 million quarter-to-quarter decrease in net income for changes in the non-cash items identified on our Unaudited Condensed Statements of Consolidated Cash Flows);

partially offset by

a $605.4 million quarter-to-quarter decrease in cash receipts attributable to the return of working capital employed in our marketing activities, which was $638.4 million in the first quarter of 2020 compared to $33.0 million in the first quarter of 2021.

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

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;

a $ 330.2 million period-to-period increase resulting from higher partnership earnings (determined by adjusting our $ 72.8 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.

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 first quarter of 2021 decreased $414.7 million when compared to the first quarter of 2020 primarily due to a $400.5 million quarter-to-quarter 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 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).

Financing activities

Cash used in financing activities during the first quarter of 2021 was $2.19 billion compared to cash provided by financing activities of $765.1 million in the first quarter of 2020.

The $2.95 billion quarter-to-quarter change in financing cash flows was primarily due to a net cash outflow of $1.13 billion related to debt during the first quarter of 2021 compared to a net cash inflow of $1.94 billion related to debt during the first quarter of 2020.

During the first quarter of 2021, we repaid $1.33 billion aggregate principal amount of senior notes.

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

In addition, net issuances of short term notes under EPO’s commercial paper program were $115.0 million during the first quarter of 2021 compared to net repayments of $481.8 million during the first quarter of 2020.

In addition, cash used to acquire Partnership common units under the 2019 Buyback Program decreased $126.2 million quarter-to-quarter.

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.

Non-GAAP Cash Flow Measures

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For the Three Months

Ended March 31,

Ended June 30,

For the Six Months

Ended June 30,

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

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

First quarter of 2021 includes $107.0 million of accounts receivable that we do not expect to collect in the normal billing cycle.

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.

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 March 31,

Ended June 30,

For the Six Months

Ended June 30,

Net cash flows provided by operating activities (GAAP)

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For the Three Months

Ended March 31,

Ended June 30,

For the Six Months

Ended June 30,

Net cash flows provided by operating activities (GAAP)

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

For the Three Months

Ended March 31,

For the Six Months

Ended June 30,

Capital investments for property, plant and equipment:

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

Sustaining capital amounts include the costs of major maintenance activities accounted for using the deferral method.

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.

Based on information currently available, we expect our total capital investments for 2021, net of expected contributions from noncontrolling interests, to approximate $2.1 billion, which reflects growth capital investments of $1.6 billion and sustaining capital expenditures of $440 million.

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.

These amounts do not include capital investments associated with SPOT, our proposed deepwater offshore crude oil terminal, which remains subject to governmental approvals.

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;

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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 First Quarter of 2021 with the First Quarter of 2020

In total, investments in growth capital projects decreased $433.0 million quarter-to-quarter primarily due to the following:

completion of projects at our Chambers County complex (e.g., the completion of Frac X and Frac XI), which accounted for a $193.4 million decrease;

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

In total, investments in growth capital projects decreased $779.9 million period-to-period primarily due to the following:

completion of projects associated with crude oil pipelines (e.g., expansion projects involving the Midland-to-ECHO System and related crude oil-related infrastructure supporting Permian Basin producers), which accounted for a combined $275.2 million decrease;

completion of projects at our Chambers County complex (e.g., the completion of Frac X and Frac XI), which accounted for a $240.5 million decrease;

lower investments in Permian Basin natural gas processing facilities and related infrastructure, which accounted for a $76.8 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 net $25.1 million decrease.

Investments attributable to sustaining capital projects increased $32.5 million quarter-to-quarter primarily due to major maintenance activities performed during the first quarter of 2021 at our PDH 1, octane enhancement and high purity isobutylene facilities.

The remaining change is primarily due to changes in the timing and cost of pipeline integrity and similar projects.

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).

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

For reaction-based plants, we use the deferral method when accounting for major maintenance activities.

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.

Historically, the costs of major maintenance activities attributable to our reaction-based facilities, principally our octane enhancement assets, were not material to our consolidated financial statements.

Critical Accounting Policies and Estimates

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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 March 31, 2021, the total amount of Guaranteed Debt was $29.15 billion, which was comprised of $26.18 billion of EPO’s senior notes, $115.0 million of short-term commercial paper notes, $2.63 billion of EPO’s junior subordinated notes and $224.2 million of related accrued interest.

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.

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 $45.86 billion at March 31, 2021.

The Obligor Group’s equity in the earnings of the Non-Obligor Subsidiaries for the first quarter of 2021 was $878.0 million.

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.

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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We continue to believe that the unaudited condensed consolidated financial statements of the Partnership presented under Part I, Item 1 of this quarterly report provide a more appropriate view of our credit standing.

Our investment grade credit ratings are based on the Partnership’s consolidated financial statements and not the Obligor Group financial information presented below.

Our investment grade credit ratings are based on the Partnership’s consolidated financial statements and not the Obligor Group’s financial information presented below.

The following table presents summarized balance sheet information for the combined Obligor Group at the dates indicated (dollars in millions):

Selected asset information:

March 31, 2021

June 30, 2021

December 31, 2020

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Long-term receivables from Non-Obligor Subsidiaries

Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries of $45.86 billion at March 31, 2021 and $45.98 billion at December 31, 2020

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

Selected liability information:

Current portion of Guaranteed Debt, including interest of $224.2 million at March 31, 2021 and $455.6 million at December 31, 2020

Current portion of Guaranteed Debt, including interest of $ 443.0 million at June 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):

For the three months ended

March 31, 2021

For the twelve months ended

June 30, 2021

For the Twelve

December 31, 2020

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Operating income of Obligor Group

Net income (loss) of Obligor Group excluding equity in earnings of Non-Obligor Subsidiaries of $878.0 million for the three months ended March 31, 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 $ 1.91 billion for the six months ended June 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 $19.34 billion at March 31, 2021 primarily due to an increase in crude oil and NGL prices between the two reporting dates.

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.

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