Income Statement Highlights
The following table summarizes the key components of our consolidated results of operations for the periods indicated (dollars in millions):
Revenues
The following table presents each business segment’s contribution to consolidated revenues for the periods indicated (dollars in millions):
Third Quarter of 2020 Compared to Third Quarter of 2019. Total revenues for the third quarter of 2020 decreased $1.04 billion when compared to the third quarter of 2019 primarily due to a net $912.5 million decrease in marketing revenues. Revenues from the marketing of crude oil and natural gas decreased $1.0 billion quarter-to-quarter primarily due to lower average sales prices, which accounted for a $935.0 million decrease, and lower sales volumes, which accounted for an additional $68.2 million decrease. Revenues from the marketing of NGLs decreased $576.5 million quarter-to-quarter primarily due to lower average sales prices, which accounted for a $504.8 million decrease, and lower sales volumes, which resulted in an additional $71.7 million decrease. Revenues from the marketing of petrochemicals and refined products increased a net $667.2 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $982.3 million increase, partially offset by lower average sales prices, which resulted in a $315.1 million decrease.
Revenues from midstream services for the third quarter of 2020 decreased $129.6 million when compared to the third quarter of 2019. Revenues from our natural gas processing facilities decreased $54.8 million quarter-to-quarter primarily due to lower market values for the equity NGLs we receive as non-cash consideration for processing services. Revenues from our pipeline assets decreased $43.7 million quarter-to-quarter primarily due to lower demand for crude oil, natural gas and refined products transportation services. Lastly, third-party revenues from our Mont Belvieu NGL fractionation complex decreased $19.5 million quarter-to-quarter primarily due to lower fractionation fees.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019. Total revenues for the nine months ended September 30, 2020 decreased $4.63 billion when compared to the nine months ended September 30, 2019 primarily due to a net $4.29 billion decrease in marketing revenues. Revenues from the marketing of crude oil and natural gas decreased $3.46 billion period-to-period primarily due to lower average sales prices, which accounted for a $2.73 billion decrease, and lower sales volumes, which accounted for an additional $728.5 million decrease. Revenues from the marketing of NGLs decreased a net $1.55 billion period-to-period primarily due to lower average sales prices, which accounted for a $2.56 billion decrease, partially offset by the effects of higher sales volumes, which resulted in a $1.0 billion increase. Revenues from the marketing of petrochemicals and refined products increased a net $726.4 million period-to-period primarily due to higher sales volumes, which accounted for a $1.69 billion increase, partially offset by lower average sales prices, which resulted in a $965.8 million decrease.
Revenues from midstream services for the nine months ended September 30, 2020 decreased $341.1 million when compared to the nine months ended September 30, 2019. Revenues from our natural gas processing facilities decreased $176.9 million period-to-period primarily due to lower market values for the equity NGLs we receive as non-cash consideration for processing services. Revenues from our Midland-to-ECHO 2 pipeline, which commenced limited service in February 2019 and full service in April 2019, increased $17.8 million period-to-period. Revenues from our other pipeline assets decreased $107.3 million period-to-period primarily due to lower demand for crude oil, natural gas and refined products. Lastly, third party revenues from our Mont Belvieu NGL fractionation complex decreased $84.1 million period-to-period primarily due to lower fractionation fees.
Operating costs and expenses
Third Quarter of 2020 Compared to Third Quarter of 2019. Total operating costs and expenses for the third quarter of 2020 decreased $1.0 billion when compared to the third quarter of 2019 primarily due to lower cost of sales. The cost of sales associated with our marketing of crude oil and natural gas decreased a combined $986.2 million quarter-to-quarter primarily due to lower average purchase prices, which accounted for a $942.1 million decrease, and lower sales volumes, which accounted for an additional $44.1 million decrease. The cost of sales associated with our marketing of NGLs decreased $564.4 million quarter-to-quarter primarily due to lower average purchase prices, which accounted for a $505.0 million decrease, and lower sales volumes, which accounted for an additional $59.4 million decrease. The cost of sales associated with our marketing of petrochemicals and refined products increased a net $587.8 million quarter-to-quarter primarily due to higher sales volumes, which accounted for an $897.8 million increase, partially offset by lower average purchase prices, which accounted for a $310.0 million decrease.
Other operating costs and expenses for the third quarter of 2020 decreased $93.9 million quarter-to-quarter primarily due to lower maintenance, chemical and power-related expenses. Depreciation, amortization and accretion expense increased $17.1 million quarter-to-quarter primarily due to assets placed into full or limited service since the third quarter of 2019 (e.g., the isobutane dehydrogenation (“iBDH”) plant, Mentone facility, Mont Belvieu Frac X and the Enterprise Navigator ethylene terminal). Non-cash asset impairment charges increased $37.6 million quarter-to-quarter primarily due to our cancellation of the Midland-to-ECHO 4 crude oil pipeline construction project.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019. Total operating costs and expenses for the nine months ended September 30, 2020 decreased $4.39 billion when compared to the nine months ended September 30, 2019 primarily due to lower cost of sales. The cost of sales associated with our marketing of crude oil and natural gas decreased a combined $3.2 billion period-to-period primarily due to lower average purchase prices, which accounted for a $2.67 billion decrease, and lower sales volumes, which accounted for an additional $524.3 million decrease. The cost of sales associated with our marketing of NGLs decreased a net $1.82 billion period-to-period primarily due to lower average purchase prices, which accounted for a $2.63 billion decrease, partially offset by higher sales volumes, which accounted for an $809.9 million increase. The cost of sales associated with our marketing of petrochemicals and refined products increased a net $628.4 million period-to-period primarily due to higher sales volumes, which accounted for a $1.55 billion increase, partially offset by lower average purchase prices, which accounted for a $921.1 million decrease.
Other operating costs and expenses for the nine months ended September 30, 2020 decreased $123.0 million period-to-period primarily due to lower maintenance, chemicals and power-related expenses, which accounted for a $191.7 million decrease, partially offset by higher ad valorem taxes and employee compensation costs, which accounted for a $52.3 million increase. Depreciation, amortization and accretion expense increased $80.5 million period-to-period primarily due to assets placed into full or limited service since the first quarter of 2019 (e.g., the iBDH plant, Mentone and Orla facilities, Mont Belvieu Frac X and the Enterprise Navigator ethylene terminal). Non-cash asset impairment charges increased $39.2 million period-to-period primarily due to our cancellation of the Midland-to-ECHO 4 crude oil pipeline construction project.
General and administrative costs
General and administrative costs decreased $5.2 million quarter-to-quarter primarily due to lower employee compensation expenses and legal and other professional services costs.
General and administrative costs increased $2.6 million period-to-period primarily due to higher professional services costs.
Equity in income of unconsolidated affiliates
Equity income from our unconsolidated affiliates for the three and nine months ended September 30, 2020 decreased $57.3 million and $95.2 million, respectively, when compared to the same periods in 2019 primarily due to decreased earnings from our investments in crude oil pipelines.
Operating income
Operating income for the three and nine months ended September 30, 2020 decreased $91.7 million and $333.8 million, respectively, when compared to the same periods in 2019 due to the previously described quarter-to-quarter and period-to-period changes in revenues, operating costs and expenses, general and administrative costs and equity in income of unconsolidated affiliates.
Interest expense
The following table presents the components of our consolidated interest expense for the periods indicated (dollars in millions):
Interest charged on debt principal outstanding, which is a key driver of interest expense, increased a net $15.6 million quarter-to-quarter primarily due to increased debt principal amounts outstanding during the third quarter of 2020, which accounted for a $22.1 million increase, partially offset by the effect of lower overall interest rates during the third quarter of 2020, which accounted for a $6.5 million decrease. Our weighted-average debt principal balance for the third quarter of 2020 was $30.27 billion compared to $27.93 billion for the third quarter of 2019. In general, our debt principal balances have increased over time due to the partial debt financing of our capital investments.
For the nine months ended September 30, 2020, interest charged on debt principal outstanding increased a net $66.2 million period-to-period primarily due to increased debt principal amounts outstanding during the nine months ended September 30, 2020, which accounted for an $84.2 million increase, partially offset by the effect of lower overall interest rates during the nine months ended September 30, 2020, which accounted for an $18.0 million decrease. Our weighted-average debt principal balance for the nine months ended September 30, 2020 was $29.84 billion compared to $27.29 billion for the nine months ended September 30, 2019.
For additional information regarding our debt obligations, see Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report. For a discussion of our capital projects, see “Capital Investments” within this Part I, Item 2.
Change in fair value of Liquidity Option
On February 25, 2020, the Partnership received notice from Marquard & Bahls AG (“M&B”) of M&B’s election to exercise its rights (the “Liquidity Option”) under the Liquidity Option Agreement among the Partnership, OTA Holdings, Inc., a Delaware corporation previously named Oiltanking Holding Americas, Inc. (“OTA”), and M&B dated October 1, 2014 (the “Liquidity Option Agreement”). The Partnership settled its obligations under the Liquidity Option Agreement on March 5, 2020.
For the period in which the Liquidity Option was outstanding, we recognized non-cash expense in connection with accretion and changes in management estimates that affected the valuation of the Liquidity Option liability. Expense amounts attributable to changes in the fair value of the Liquidity Option were $38.7 million and $123.1 million during the three and nine months ended September 30, 2019, respectively. Expense of $2.3 million for the first quarter of 2020 primarily reflects accretion expense for the period in which the Liquidity Option liability was outstanding before it was settled on March 5, 2020. The higher level of expense recognized in the three and nine months ended September 30, 2019 was primarily due to a decrease in the discount factor used in determining the present value of the liability.
Income taxes
The following table presents the components of our consolidated benefit from (provision for) income taxes for the periods indicated (dollars in millions):
On March 5, 2020, the Partnership settled its obligations under the Liquidity Option Agreement and indirectly assumed the deferred tax liability of OTA, which reflects OTA’s outside basis difference in the limited partner interests it received from the Partnership in October 2014. Upon settlement of the Liquidity Option, the Liquidity Option liability was effectively replaced by the deferred tax liability of OTA calculated in accordance with ASC 740, Income Taxes.
At March 5, 2020, the Liquidity Option liability amount was $511.9 million. Since the book value of the Liquidity Option liability exceeded OTA’s estimated deferred tax liability of $439.7 million on that date, we recognized a non-cash benefit in earnings of $72.2 million, which is reflected in the “Benefit from (provision for) income tax” line on our Unaudited Condensed Statement of Consolidated Operations for the nine months ended September 30, 2020. Subsequent to March 5, 2020 and through September 30, 2020, OTA recognized an additional net, non-cash deferred income tax benefit of $85.8 million due to a decrease in the outside basis difference of its investment in the Partnership, which in turn was driven by a decline in the market price of Partnership common units since March 5, 2020. In total, earnings for the three and nine months ended September 30, 2020 reflect $21.3 million and $158.0 million, respectively, of net 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 and beginning September 30, 2020, OTA’s deferred tax liability no longer fluctuates due to market price changes in the Partnership’s common units. For information regarding the issuance of preferred units on September 30, 2020, including the OTA-related exchange, see “Liquidity and Capital Resources” within this Part I, Item 2.
For additional information regarding income taxes, see Note 11 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.
Business Segment Highlights
We evaluate segment performance based on our financial measure of gross operating margin. Gross operating margin is an important performance measure of the core profitability of our operations and forms the basis of our internal financial reporting. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results.
The following table presents gross operating margin by segment and non-generally accepted accounting principle (“non-GAAP”) total gross operating margin for the periods indicated (dollars in millions):
Total gross operating margin includes equity in the earnings of unconsolidated affiliates, but is exclusive of other income and expense transactions, income taxes, the cumulative effect of changes in accounting principles and extraordinary charges. Total gross operating margin is presented on a 100% basis before any allocation of earnings to noncontrolling interests. Our calculation of gross operating margin may or may not be comparable to similarly titled measures used by other companies. Segment gross operating margin for NGL Pipelines & Services and Crude Oil Pipelines & Services reflect adjustments for shipper make-up rights that are included in management’s evaluation of segment results. However, these adjustments are excluded from non-GAAP total gross operating margin.
The GAAP financial measure most directly comparable to total gross operating margin is operating income. For a discussion of operating income and its components, see the previous section titled “Income Statement Highlights” within this Part I, Item 2. The following table presents a reconciliation of operating income to total gross operating margin for the periods indicated (dollars in millions):
Each of our business segments benefits from the supporting role of our marketing activities. The main purpose of our marketing activities is to support the utilization and expansion of assets across our midstream energy asset network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment. In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of gross operating margin for us. The financial results of our marketing efforts fluctuate due to changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for the products bought and sold.
As a result of the COVID-19 pandemic and lower energy commodity prices, we experienced a reduction in volumes on a number of our assets (e.g., crude oil pipelines and export docks, natural gas gathering systems) during the three and nine months ended September 30, 2020 due to reduced upstream drilling and production activity and lower downstream refinery activity and demand for transportation fuels. Furthermore, we may continue to experience throughput declines in the future on our gathering systems, long-haul liquids and natural gas pipelines and at our terminal and other facilities until the pandemic ends and economic activity is fully restored. For a general discussion of the impact of the pandemic on our partnership and industry, see “Current Outlook” within this Part I, Item 2.
NGL Pipelines & Services
The following table presents segment gross operating margin and selected volumetric data for the NGL Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted):
Natural gas processing and related NGL marketing activities
Third Quarter of 2020 Compared to Third Quarter of 2019. Gross operating margin from natural gas processing and related NGL marketing activities for the third quarter of 2020 decreased $31.2 million when compared to the third quarter of 2019.
Gross operating margin from our natural gas processing facilities located in the Rocky Mountains (Meeker, Pioneer and Chaco plants) decreased a combined $23.0 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $27.2 million decrease, and lower processing volumes, which accounted for an additional $8.2 million decrease, partially offset by lower operating costs, which accounted for a $9.0 million increase. On a combined basis, fee-based natural gas processing volumes at these plants decreased 398 MMcf/d and equity NGL production volumes increased 28 MBPD quarter-to-quarter.
Gross operating margin from our South Texas natural gas processing facilities decreased $22.9 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for an $8.9 million decrease, lower average processing fees, which accounted for a $6.8 million decrease, and lower processing volumes, which accounted for an additional $5.5 million decrease. On a combined basis, fee-based natural gas processing volumes at our South Texas plants decreased 242 MMcf/d and equity NGL production volumes increased 6 MBPD quarter-to-quarter.
Gross operating margin from our Louisiana and Mississippi natural gas processing facilities decreased $8.1 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $4.7 million decrease, and lower processing volumes, which accounted for an additional $3.9 million decrease. On a combined basis, fee-based natural gas processing and equity NGL production volumes at our Louisiana and Mississippi plants decreased 374 MMcf/d and 7 MBPD, respectively, quarter-to-quarter (net to our interest). Certain plants in Louisiana and Mississippi were impacted by lower Gulf of Mexico production as a result of shut-ins associated with Hurricane Laura in August 2020.
Gross operating margin from our Permian Basin natural gas processing facilities increased a net $5.4 million quarter-to-quarter primarily due to higher processing volumes, which accounted for a $13.4 million increase, partially offset by lower average processing fees, which accounted for a $5.8 million decrease, and lower average processing margins (including the impact of hedging activities), which accounted for an additional $3.7 million decrease. On a combined basis, fee-based natural gas processing volumes at our Permian Basin plants increased 345 MMcf/d quarter-to-quarter.
Gross operating margin from our NGL marketing activities increased a net $16.8 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $36.1 million increase, partially offset by lower average sales margins (including the impact of hedging activities), which accounted for a $19.4 million decrease. The quarter-to-quarter increase in gross operating margin can be attributed to results from marketing strategies that seek to optimize our storage assets, which accounted for a $68.5 million increase, partially offset by lower earnings from strategies that seek to optimize our export, plant and transportation assets, which accounted for a combined $40.6 million decrease. In addition, gross operating margin from our NGL marketing activities attributable to non-cash, mark-to-market earnings decreased $11.1 million quarter-to-quarter.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019. Gross operating margin from natural gas processing and related NGL marketing activities for the nine months ended September 30, 2020 decreased $121.0 million when compared to the nine months ended September 30, 2019. Gross operating margin from our Rocky Mountains natural gas processing facilities decreased a combined $80.8 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities). On a combined basis, fee-based natural gas processing volumes at our plants in the Rockies decreased 305 MMcf/d and equity NGL production volumes increased 6 MBPD period-to-period.
Gross operating margin from our South Texas natural gas processing facilities decreased $65.5 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $41.4 million decrease, lower average processing fees, which accounted for an $11.0 million decrease, and lower processing volumes, which accounted for an additional $11.2 million decrease. On a combined basis, fee-based natural gas processing volumes at these plants decreased 141 MMcf/d and equity NGL production volumes increased 7 MBPD period-to-period.
Gross operating margin from our Permian Basin natural gas processing facilities decreased a net $13.8 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $20.9 million decrease, lower average processing fees, which accounted for a $15.4 million decrease, and higher operating costs, which accounted for an additional $9.9 million decrease, partially offset by higher processing volumes, which accounted for a $33.0 million increase. On a combined basis, fee-based natural gas processing and equity NGL production volumes at our Permian Basin plants increased 287 MMcf/d and 7 MBPD, respectively, period-to-period, primarily due to additional processing capacity at our Orla facility placed into service in July 2019 and the start-up of our Mentone facility in December 2019.
Gross operating margin from our Louisiana and Mississippi natural gas processing facilities decreased a net $20.9 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $22.6 million decrease, and lower processing volumes, which accounted for an additional $10.3 million decrease, partially offset by higher average processing fees, which accounted for a $7.9 million increase, and lower operating costs, which accounted for an additional $6.6 million increase. Net to our interest, fee-based natural gas processing volumes at these plants decreased a combined 319 MMcf/d period-to-period.
Gross operating margin from our NGL marketing activities increased a net $65.4 million period-to-period primarily due to higher sales volumes, which accounted for a $193.7 million increase, partially offset by lower average sales margins (including the impact of hedging activities), which accounted for a $128.2 million decrease. The period-to-period increase in gross operating margin can be attributed to results from marketing strategies that seek to optimize our storage and transportation assets, which accounted for a combined $97.7 million increase, partially offset by lower earnings from strategies that seek to optimize our export and plant assets, which accounted for a combined $40.2 million decrease. In addition, gross operating margin from our NGL marketing activities attributable to non-cash, mark-to-market earnings increased $7.9 million period-to-period.
NGL pipelines, storage and terminals
Third Quarter of 2020 Compared to Third Quarter of 2019. Gross operating margin from our NGL pipelines, storage and terminal assets for the third quarter of 2020 increased $9.5 million when compared to the third quarter of 2019.
A number of our pipelines, including the Mid-America Pipeline System, Seminole NGL Pipeline, Chaparral NGL Pipeline, Shin Oak NGL Pipeline, Texas Express Pipeline and Front Range Pipeline, serve Permian Basin and/or Rocky Mountain producers. On a combined basis, gross operating margin from these pipelines increased a net $11.1 million quarter-to-quarter primarily due to higher average transportation fees, which accounted for an $18.0 million increase, lower operating costs, which accounted for an additional $6.4 million increase, partially offset by lower transportation volumes of 43 MBPD (net to our interest), which accounted for a $7.1 million decrease.
Gross operating margin from LPG-related activities at EHT increased $4.5 million quarter-to-quarter primarily due to higher export volumes of 45 MBPD. Gross operating margin from our Houston Ship Channel Pipeline System increased $3.1 million quarter-to-quarter primarily due to a 39 MBPD increase in transportation volumes.
Gross operating margin from our Mont Belvieu storage facility decreased a net $7.7 million quarter-to-quarter primarily due to lower handling and throughput fee revenues, which accounted for an $18.5 million decrease, partially offset by higher storage fees, which accounted for a $13.3 million increase.
Gross operating margin from our Dixie Pipeline and related terminals decreased a combined $4.7 million quarter-to-quarter primarily due to lower transportation volumes of 57 MBPD. Gross operating margin from our South Louisiana NGL Pipeline System and related storage facilities decreased a combined $7.1 million quarter-to-quarter primarily due to lower transportation volumes of 69 MBPD, which accounted for a $4.9 million decrease, and lower loading and other fee revenues, which accounted for an additional $1.3 million decrease. The decrease in transportation volumes for these pipelines in the third quarter of 2020 was partially due to the effects of Hurricane Laura, which caused shut-ins of Gulf of Mexico production as well as power outages at certain pump stations.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019. Gross operating margin from our NGL pipelines, storage and terminal assets for the nine months ended September 30, 2020 increased $123.1 million when compared to the nine months ended September 30, 2019.
On a combined basis, gross operating margin from our pipelines serving Permian Basin and/or Rocky Mountain producers increased a net $63.1 million period-to-period primarily due to higher average transportation fees, which accounted for a $47.1 million increase, and lower operating costs, which accounted for an additional $26.8 million increase, partially offset by lower transportation volumes, which accounted for a $7.2 million decrease. Transportation volumes from these pipelines decreased a combined 99 MBPD (net to our interest).
Gross operating margin from LPG-related activities at EHT increased $53.1 million period-to-period primarily due to higher export volumes of 116 MBPD. The increase in export volumes is attributable to an LPG expansion project at EHT that was completed in the third quarter of 2019. Gross operating margin from our Houston Ship Channel Pipeline System increased $14.9 million period-to-period primarily due to a 92 MBPD increase in transportation volumes.
Gross operating margin from our Aegis Pipeline increased $29.8 million period-to-period primarily due to a 115 MBPD increase in transportation volumes associated with contract commitments.
Gross operating margin from our Mont Belvieu storage facility decreased a net $15.4 million period-to-period primarily due to lower handling and throughput fee revenues, which accounted for a $31.5 million decrease, partially offset by higher storage fees, which accounted for an $18.4 million increase.
Gross operating margin from our South Louisiana NGL Pipeline System and related storage facilities decreased a combined $15.1 million period-to-period primarily due to lower transportation volumes of 42 MBPD, which accounted for a $6.3 million decrease, and lower terminal revenues, which accounted for an additional $6.2 million decrease.
Gross operating margin from our South Texas NGL Pipeline System decreased $9.6 million period-to-period primarily due to lower pipeline capacity fee revenues earned from an affiliate pipeline. Transportation volumes on our South Texas NGL Pipeline System increased 30 MBPD period-to-period.
NGL fractionation
Third Quarter of 2020 Compared to Third Quarter of 2019. Gross operating margin from NGL fractionation for the third quarter of 2020 increased $41.5 million when compared to the third quarter of 2019 primarily due to higher fractionation volumes at our Mont Belvieu NGL fractionation complex, which increased 348 MBPD quarter-to-quarter (net to our interest) primarily due to the start-up of the first and second fractionation units (“Frac X” and “Frac XI”) in March 2020 and September 2020, respectively, at our newly completed NGL fractionation facility located in Chambers County, Texas.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019. Gross operating margin from NGL fractionation during the nine months ended September 30, 2020 increased $102.3 million when compared to the nine months ended September 30, 2019. Gross operating margin from our Mont Belvieu NGL fractionation complex increased $65.4 million primarily due to higher fractionation volumes, which increased 341 MBPD period-to-period (net to our interest) primarily due to the start-up of Frac X and Frac XI. Gross operating margin from our Hobbs NGL fractionator increased $21.3 million period-to-period primarily due to major maintenance activities during the first quarter of 2019. NGL fractionation volumes at our Hobbs NGL fractionator increased 17 MBPD period-to-period. Gross operating margin from our South Texas NGL fractionators increased $8.6 million period-to-period primarily due to lower maintenance and other operating costs, which accounted for a $4.4 million increase, and higher NGL fractionation volumes of 17 MBPD, which accounted for an additional $4.2 million increase.
Crude Oil Pipelines & Services
The following table presents segment gross operating margin and selected volumetric data for the Crude Oil Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted):
In general, segment volumes for the three and nine months ended September 30, 2020 were adversely impacted by the reduction in upstream crude oil production activities caused by the pandemic and crude oil price shock.
Third Quarter of 2020 Compared to Third Quarter of 2019. Gross operating margin from our Crude Oil Pipelines & Services segment for the third quarter of 2020 decreased $14.4 million when compared to the third quarter of 2019.
Gross operating margin from our Midland-to-ECHO System and related business activities decreased a net $40.7 million quarter-to-quarter primarily due to lower average sales margins from marketing activities (including the impact of hedging activities), which accounted for a $42.9 million decrease, lower transportation volumes, which accounted for a $10.1 million decrease, and lower deficiency and other revenues, which accounted for an additional $12.1 million decrease, partially offset by lower chemical and other operating costs of $21.8 million.
Gross operating margin from our equity investment in the Eagle Ford Crude Oil Pipeline decreased $8.9 million quarter-to-quarter primarily due to lower transportation volumes. Gross operating margin from our South Texas Crude Oil Pipeline System decreased $15.6 million quarter-to-quarter primarily due to lower transportation volumes. On an aggregate basis, transportation volumes on these three pipeline systems decreased 180 MBPD quarter-to-quarter (net to our interest).
Gross operating margin from our equity investment in the Seaway Pipeline decreased $17.5 million quarter-to-quarter primarily due to lower average transportation fees, which accounted for a $10.9 million decrease, and lower transportation volumes, which accounted for an additional $7.5 million decrease. Net to our interest, transportation and marine volumes on the Seaway Pipeline decreased 269 MBPD and 75 MBPD, respectively, quarter-to-quarter.
Gross operating margin from our ECHO terminal decreased $7.0 million quarter-to-quarter primarily due to lower terminaling and storage revenues. Gross operating margin from crude oil activities at EHT decreased a net $14.2 million quarter-to-quarter primarily due to lower deficiency fees, which accounted for a $22.7 million decrease, partially offset by higher storage and other revenues, which accounted for an $8.5 million increase, and lower operating costs, which accounted for an additional $3.0 million increase. Crude oil terminal volumes at EHT decreased by 183 MBPD quarter-to-quarter.
Gross operating margin from our other crude oil marketing activities increased $91.7 million quarter-to-quarter primarily due to higher average sales margins (including the impact of hedging activities). The quarter-to-quarter increase in gross operating margin from our crude oil marketing activities, including those related to our Midland-to-ECHO System, is primarily due to results from marketing strategies that seek to optimize our storage assets.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019. Gross operating margin from our Crude Oil Pipelines & Services segment for the nine months ended September 30, 2020 decreased $102.6 million when compared to the nine months ended September 30, 2019.
Gross operating margin from our Midland-to-ECHO System and related business activities decreased $194.3 million period-to-period primarily due to lower average sales margins from marketing activities (including the impact of hedging activities) of $208.0 million, partially offset by lower chemical and other operating costs of $37.7 million. Gross operating margin from our South Texas Crude Oil Pipeline System decreased $32.8 million period-to-period primarily due to lower transportation volumes, which accounted for a $24.2 million decrease, and lower transportation and other fees, which accounted for an additional $13.0 million decrease. Gross operating margin from our equity investment in the Eagle Ford Crude Oil Pipeline decreased $21.5 million period-to-period primarily due to lower transportation volumes. On an aggregate basis, transportation volumes on these three pipeline systems decreased 98 MBPD period-to-period (net to our interest).
Gross operating margin from our equity investment in the Seaway Pipeline decreased a net $44.7 million period-to-period primarily due to lower transportation volumes, which accounted for a $30.3 million decrease, and lower average transportation fees, which accounted for an additional $17.4 million decrease. Net to our interest, transportation and marine volumes on the Seaway Pipeline decreased 171 MBPD and 23 MBPD, respectively, period-to-period.
Gross operating margin from our ECHO terminal decreased $25.0 million period-to-period primarily due to a benefit recognized during the second quarter of 2019 in connection with a settlement, which accounted for $13.9 million of the decrease, and lower terminaling and storage revenue, which accounted for an additional $12.9 million decrease.
Gross operating margin from our other crude oil marketing activities increased $192.9 million period-to-period primarily due to higher average sales margins (including the impact of hedging activities). The period-to-period increase in gross operating margin from our crude oil marketing activities, including those related to our Midland-to-ECHO System, is primarily due to results from marketing strategies that seek to optimize our storage assets.
Gross operating margin from our West Texas System increased $9.5 million period-to-period primarily due to higher deficiency fees. Transportation volumes decreased 4 MBPD period-to-period. Lastly, gross operating margin from our EFS Midstream system increased $9.1 million period-to-period primarily due to higher average transportation fees.
Natural Gas Pipelines & Services
The following table presents segment gross operating margin and selected volumetric data for the Natural Gas Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted):
Third Quarter of 2020 Compared to Third Quarter of 2019. Gross operating margin from our Natural Gas Pipelines & Services segment for the third quarter of 2020 decreased $50.1 million when compared to the third quarter of 2019.
Gross operating margin from our natural gas marketing activities decreased $35.0 million quarter-to-quarter primarily due to lower average sales margins (including the impact of hedging activities), which were negatively impacted by lower regional natural gas price spreads across Texas. The indicative price spreads averaged $0.72 per MMBtu for the third quarter of 2020 versus $1.36 per MMBtu for the third quarter of 2019.
Gross operating margin from our Acadian Gas System decreased $19.4 million quarter-to-quarter primarily due to benefits from settlements received in the third quarter of 2019, which accounted for a $16.7 million decrease, and lower capacity reservation revenues on the Haynesville Extension pipeline, which accounted for an additional $6.0 million decrease. Transportation volumes on our Acadian Gas System decreased 302 BBtus/d quarter-to-quarter.
Gross operating margin from our Permian Basin Gathering System increased $9.2 million quarter-to-quarter primarily due to higher volumes of 432 BBtus/d.
On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System, and San Juan Gathering System in the Rocky Mountains decreased a net $2.4 million quarter-to-quarter primarily due to lower volumes of 577 BBtus/d, which accounted for an $11.9 million decrease, partially offset by lower operating costs, which accounted for an $8.0 million increase.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019. Gross operating margin from our Natural Gas Pipelines & Services segment for the nine months ended September 30, 2020 decreased $123.5 million when compared to the nine months ended September 30, 2019.
Gross operating margin from our Texas Intrastate System decreased $45.5 million period-to-period primarily due to lower capacity reservation revenues. Transportation volumes on our Texas Intrastate System decreased 280 BBtus/d period-to-period. Gross operating margin from our Acadian Gas System decreased $42.8 million period-to-period primarily due to lower capacity reservation revenues on the Haynesville Extension pipeline, which accounted for a $27.1 million decrease, and net benefits from settlements, which accounted for an additional $15.4 million decrease. Transportation volumes on our Acadian Gas System decreased 164 BBtus/d period-to-period. Gross operating margin from our Haynesville Gathering System decreased $17.2 million period-to-period primarily due to lower gathering volumes of 223 BBtus/d, which accounted for an $11.0 million decrease, and lower gathering, compression and other fee revenues, which accounted for an additional $9.7 million decrease.
On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System, and San Juan Gathering System in the Rockies decreased a net $13.6 million period-to-period primarily due to lower volumes of 483 BBtus/d, which accounted for a $30.6 million decrease, partially offset by lower operating costs, which accounted for a $16.3 million increase.
Gross operating margin from our natural gas marketing activities decreased $38.9 million period-to-period primarily due to lower average sales margins (including the impact of hedging activities), which accounted for a $27.3 million decrease, and lower sales volumes, which accounted for an additional $11.6 million decrease.
Gross operating margin from our Permian Basin Gathering System increased $22.9 million period-to-period primarily due to a 337 BBtus/d increase in natural gas gathering volumes.
Petrochemical & Refined Products Services
The following table presents segment gross operating margin and selected volumetric data for the Petrochemical & Refined Products Services segment for the periods indicated (dollars in millions, volumes as noted):
Propylene production and related activities
Third Quarter of 2020 Compared to Third Quarter of 2019. Gross operating margin from propylene production and related activities for the third quarter of 2020 increased $2.3 million when compared to the third quarter of 2019.
Gross operating margin from our Lou-Tex propylene pipeline increased a net $2.9 million quarter-to-quarter primarily due to higher average transportation fees, which accounted for a $5.6 million increase, partially offset by lower transportation volumes of 5 MBPD, which accounted for a $2.5 million decrease. Gross operating margin from our Louisiana RGP Gathering System increased $2.4 million quarter-to-quarter primarily due to higher deficiency fee revenues.
Gross operating margin from our propylene production facilities decreased a combined $4.3 million quarter-to-quarter primarily due to lower average sales margins, which accounted for an $11.6 million decrease, lower propylene and associated by-product sales volumes, which accounted for an additional $11.2 million decrease, partially offset by higher fractionation and other fees, which accounted for a $12.4 million increase, and lower operating costs, which accounted for an additional $6.1 million increase. Propylene and associated by-product volumes at these facilities decreased a combined 20 MBPD quarter-to-quarter (net to our interest). As refiners reduced their utilization rates in response to lower demand for refined products caused by the pandemic, there was a decrease in the availability of refinery grade propylene feedstock used by our facilities to create polymer grade propylene, which contributed to the reduction in our volumes.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019. Gross operating margin from propylene production and related activities for the nine months ended September 30, 2020 decreased $64.6 million.
Gross operating margin from our propylene production facilities decreased a combined $70.7 million period-to-period when compared to the nine months ended September 30, 2019 primarily due to lower average sales margins, which accounted for a $62.2 million decrease, and lower propylene and associated by-product sales volumes, which accounted for an additional $23.6 million decrease, partially offset by lower operating costs, which accounted for a $7.1 million increase. Propylene production volumes at these facilities decreased a combined 14 MBPD period-to-period (net to our interest).
Gross operating margin from our propylene export terminals increased $7.0 million period-to-period primarily due to higher average terminal fees. Propylene export volumes decreased 6 MBPD period-to-period.
Isomerization and related operations
Third Quarter of 2020 Compared to Third Quarter of 2019. Gross operating margin from isomerization and related operations increased $3.2 million quarter-to-quarter primarily due to an increase in blending revenues, which accounted for a $1.9 million increase, and higher standalone DIB processing volumes of 17 MBPD, which accounted for an additional $1.3 million increase.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019. Gross operating margin from isomerization and related operations decreased $15.8 million period-to-period primarily due to lower average by-product sales prices, which accounted for a $17.9 million decrease, and lower isomerization volumes of 18 MBPD, which accounted for an additional $9.5 million decrease, partially offset by lower operating costs, which accounted for a $13.7 million increase.
Octane enhancement and related plant operations
Third Quarter of 2020 Compared to Third Quarter of 2019. Gross operating margin from our octane enhancement and related plant operations decreased $14.6 million quarter-to-quarter primarily due to lower average sales margins, which accounted for a $9.1 million decrease, and higher operating expenses, which accounted for an additional $7.1 million decrease. The increase in operating expenses is primarily due to our iBDH plant, which is integrated with our legacy octane enhancement and high purity isobutylene assets and was placed into service in December 2019.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019. Gross operating margin from our octane enhancement and related plant operations increased $14.3 million period-to-period primarily due to higher average sales margins, which accounted for a $19.1 million increase, and higher sales volumes, which accounted for an additional $9.3 million increase, partially offset by higher operating expenses, which accounted for a $17.6 million decrease and largely attributable to start-up of the iBDH plant.
Refined products pipelines and related activities
Third Quarter of 2020 Compared to Third Quarter of 2019. Gross operating margin from refined products pipelines and related activities for the third quarter of 2020 increased $27.1 million when compared to the third quarter of 2019.
Gross operating margin from our refined products marketing activities increased a net $30.6 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $45.7 million increase, partially offset by lower average sales margins (including the impact of hedging activities), which accounted for a $15.2 million decrease. The quarter-to-quarter increase in gross operating margin from our refined products marketing activities is primarily due to results from marketing strategies that seek to optimize our storage assets.
Gross operating margin from our TE Products Pipeline System decreased a net $8.1 million quarter-to-quarter primarily due to lower average NGL transportation fees, which accounted for a $17.4 million decrease, partially offset by higher average petrochemical transportation fees, which accounted for a $10.6 million increase. Overall transportation volumes on our TE Products Pipeline System increased a net 54 MBPD quarter-to-quarter.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019. Gross operating margin from refined products pipelines and related activities for the nine months ended September 30, 2020 increased $1.3 million when compared to the nine months ended September 30, 2019.
Gross operating margin from our refined products marketing activities increased a net $31.9 million period-to-period primarily due to higher sales volumes. The period-to-period increase in gross operating margin from our refined products marketing activities is primarily due to results from marketing strategies that seek to optimize our storage assets.
Gross operating margin from our TE Products Pipeline System decreased $26.3 million period-to-period primarily due to lower interstate refined products transportation volumes, which accounted for a $17.3 million decrease, and lower average NGL transportation fees, which accounted for an additional $13.4 million decrease, partially offset by higher average petrochemical transportation fees, which accounted for an $11.8 million increase. Overall transportation volumes on our TE Products Pipeline System increased a net 17 MBPD period-to-period.
Gross operating margin from our refined products terminal in Beaumont, Texas decreased a net $8.9 million period-to-period primarily due to lower storage revenues, which accounted for a $14.8 million decrease, partially offset by lower operating costs, which accounted for a $7.7 million increase. Terminaling volumes at Beaumont decreased a net 82 MBPD period-to-period.
Ethylene exports and other services
Third Quarter of 2020 Compared to Third Quarter of 2019. Gross operating margin from ethylene exports and other services for the third quarter of 2020 increased a net $8.6 million when compared to the third quarter of 2019. Gross operating margin from our ethylene export terminal, which was first placed into limited service in December 2019, and its related operations was a combined $13.9 million for the third quarter of 2020. Loading volumes at our ethylene export terminal for the third quarter of 2020 were 15 MBPD (net to our interest). Gross operating margin from marine transportation decreased $5.8 million quarter-to-quarter primarily due to lower fleet utilization rates.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019. Gross operating margin from ethylene exports and other services during the nine months ended September 30, 2020 increased $13.9 million when compared to the nine months ended September 30, 2019. Gross operating margin from our ethylene export terminal and related operations was $16.2 million for the nine months ended September 30, 2020. Loading volumes at our ethylene export terminal were 9 MBPD (net to our interest) during the nine months ended September 30, 2020.
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 September 30, 2020, we had $6.03 billion of consolidated liquidity, which was comprised of $5.0 billion of available borrowing capacity under EPO’s revolving credit facilities and $1.03 billion of unrestricted cash on hand.
We may issue equity and debt securities to assist us in meeting our future funding and liquidity requirements, including those related to capital investments. We have a universal shelf registration statement (the “2019 Shelf”) on file with the SEC which allows the Partnership and EPO to issue an unlimited amount of equity and debt securities, respectively.
Enterprise Declares Cash Distribution for Third Quarter of 2020
On October 7, 2020, we announced that the Board declared a quarterly cash distribution of $0.4450 per common unit, or $1.78 per unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the third quarter of 2020. The quarterly distribution is payable on November 12, 2020, to unitholders of record as of the close of business on October 30, 2020. In light of current economic conditions, management will evaluate any future increases in cash distributions on a quarterly basis. The payment of any 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.
Consolidated Debt
At September 30, 2020, the average maturity of EPO’s consolidated debt obligations was approximately 20.6 years. The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at September 30, 2020 for the years indicated (dollars in millions):
In January 2020, EPO issued $3.0 billion aggregate principal amount of senior notes comprised of (i) $1.0 billion principal amount of 2.80% fixed-rate senior notes due January 2030 (“Senior Notes AAA”), (ii) $1.0 billion principal amount of 3.70% fixed-rate senior notes due January 2051 (“Senior Notes BBB”) and (iii) $1.0 billion principal amount of 3.95% fixed-rate senior notes due January 2060 (“Senior Notes CCC”). Net proceeds from this offering were used by EPO for the repayment of $500 million principal amount of its Senior Notes Q that matured in January 2020, temporary repayment of amounts outstanding under its commercial paper program and for general company purposes. In addition, net proceeds from this offering were used by EPO for the repayment of $1.0 billion principal amount of its Senior Notes Y that matured in September 2020.
In August 2020, EPO issued $1.0 billion principal amount of 3.20% fixed-rate senior notes due February 2052 (“Senior Notes DDD”) and $250.0 million principal amount of reopened 2.80% fixed-rate Senior Notes AAA. We received aggregate net proceeds of $1.25 billion from the sale of the notes after deducting underwriting discounts and other estimated offering expenses payable by us. Net proceeds from the issuance of these senior notes will be used for general company purposes, including for growth capital investments, and to repay all or part of $750.0 million in principal amount of Senior Notes TT, which mature in February 2021.
In September 2020, EPO entered into a new 364-Day Revolving Credit Agreement that replaced its September 2019 364-Day Revolving Credit Agreement. The new 364-Day Revolving Credit Agreement matures in September 2021. There was no principal amount outstanding under the September 2019 364-Day Revolving Credit Agreement when it expired and was replaced by the September 2020 364-Day Revolving Credit Agreement. In addition, following execution of the September 2020 364-Day Revolving Credit Agreement, EPO terminated its April 2020 364-Day Revolving Credit Agreement on September 11, 2020.
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 November 6, 2020, the investment-grade credit ratings of EPO’s long-term senior unsecured debt securities were BBB+ from Standard and Poor’s, Baa1 from Moody’s and BBB+ from Fitch Ratings. In addition, the credit ratings of EPO’s short-term senior unsecured debt securities were A-2 from Standard and Poor’s, P-2 from Moody’s and F-2 from Fitch Ratings. EPO’s credit ratings reflect only the view of a rating agency and should not be interpreted as a recommendation to buy, sell or hold any of our securities. A credit rating can be revised upward or downward or withdrawn at any time by a rating agency, if it determines that circumstances warrant such a change. A credit rating from one rating agency should be evaluated independently of credit ratings from other rating agencies.
Common Unit Repurchases Under 2019 Buyback Program
In January 2019, we announced that the Board had approved a $2.0 billion multi-year unit buyback program (the “2019 Buyback Program”), which provides the Partnership with an additional method to return capital to investors. The Partnership repurchased an aggregate 8,342,246 common units under the 2019 Buyback Program through open market and private purchases during the nine months ended September 30, 2020. The total purchase price of these repurchases was $173.8 million including commissions and fees. Units repurchased under the 2019 Buyback Program are immediately cancelled upon acquisition. As of September 30, 2020, the remaining available capacity under the 2019 Buyback Program was $1.75 billion.
In addition to the 2019 Buyback Program, privately held affiliates of EPCO acquired 1,459,000 of the Partnership’s common units on the open market during the nine months ended September 30, 2020. In the aggregate, 9,801,246 common units were purchased on the open market during the nine months ended September 30, 2020 under the 2019 Buyback Program and by privately held affiliates of EPCO.
March 2020 Issuance of Common Units to Skyline North Americas, Inc. and related acquisition of Treasury Units
On March 5, 2020, the Partnership settled its obligations under the Liquidity Option Agreement by issuing 54,807,352 new common units to Skyline North Americas, Inc. in exchange for the capital stock of OTA. Upon settlement of the Liquidity Option, we indirectly acquired the 54,807,352 Partnership common units owned by OTA (which were issued by the Partnership to OTA in October 2014) and assumed all future income tax obligations of OTA, including its deferred tax liability. For additional information regarding settlement of the Liquidity Option, see Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.
September 2020 Issuance of Series A Cumulative Convertible Preferred Units
On September 30, 2020, the Partnership issued and sold an aggregate of 50,000 Series A Cumulative Convertible Preferred Units in a private placement transaction. The stated value of each preferred unit is $1,000 per unit. The total offering price for the preferred units was $50.0 million, of which $32.5 million was received in cash with the remaining $17.5 million funded through the exchange of 1,120,588 of the Partnership’s common units owned by the purchasers. Cash proceeds from the preferred unit offering include $15.0 million received from a privately held affiliate of EPCO for the purchase of 15,000 preferred units.
Concurrently, the Partnership exchanged all of the 54,807,352 Partnership common units owned directly by OTA for 855,915 of the Partnership’s new preferred units having an equivalent value. The preferred units held by OTA, like the common units OTA held prior to the exchange, are accounted for as treasury units by the Partnership in consolidation. The historical cost of the treasury units did not change as a result of the exchange and remains at the $1.3 billion recognized in March 2020 in connection with settlement of the Liquidity Option.
For additional information regarding the preferred units, see Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.
Cash Flow Statement Highlights
The following table summarizes our consolidated cash flows from operating, investing and financing activities for the periods indicated (dollars in millions). For additional information regarding our cash flow amounts, please refer to the Unaudited Condensed Statements of Consolidated Cash Flows included under Part I, Item 1 of this quarterly report.
Net cash flows provided by operating activities are largely dependent on earnings from our consolidated business activities. Changes in energy commodity prices may impact the demand for natural gas, NGLs, crude oil, petrochemical and refined products, which could impact sales of our products and the demand for our midstream services. Changes in demand for our products and services may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, public health emergencies, adverse weather conditions and government regulations affecting prices and production levels. We may also incur credit and price risk to the extent customers do not fulfill their contractual obligations to us in connection with our marketing activities and long-term take-or-pay agreements. For a more complete discussion of these and other risk factors pertinent to our business, see Part I, Item 1A of the 2019 Form 10-K and Part II, Item 1A of this quarterly report.
The following information highlights significant period-to-period fluctuations in our consolidated cash flow amounts:
Operating activities
Net cash flows provided by operating activities for the nine months ended September 30, 2020 decreased $534.6 million when compared to the nine months ended September 30, 2019 primarily due to:
For information regarding significant period-to-period changes in our consolidated net income and underlying segment results, see “Income Statement Highlights” and “Business Segment Highlights” within this Part I, Item 2.
Investing activities
Cash used in investing activities for the nine months ended September 30, 2020 decreased $808.6 million when compared to the nine months ended September 30, 2019 primarily due to:
Financing activities
Cash used in financing activities for the nine months ended September 30, 2020 increased a net $350.6 million when compared to the nine months ended September 30, 2019 primarily due to:
Non-GAAP Cash Flow Measures
Distributable Cash Flow
Our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash, after any cash reserves established by Enterprise GP in its sole discretion. Cash reserves include those for the proper conduct of our business, including those for capital investments, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other amounts. The retention of cash by the partnership allows us to reinvest in our growth and reduce our future reliance on the equity and debt capital markets.
We measure available cash by reference to distributable cash flow (“DCF”), which is a non-GAAP cash flow measure. DCF is an important financial measure for our common unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flows at a level that can sustain our declared quarterly cash distributions. DCF is also a quantitative standard used by the investment community with respect to publicly traded partnerships since the value of a partnership unit is, in part, measured by its yield, which is based on the amount of cash distributions a partnership can pay to a unitholder. Our management compares the DCF we generate to the cash distributions we expect to pay our common unitholders. Using this metric, management computes our distribution coverage ratio. Our calculation of DCF may or may not be comparable to similarly titled measures used by other companies.
Based on the level of available cash each quarter, management proposes a quarterly cash distribution rate to the Board of Enterprise GP, which has sole authority in approving such matters. Unlike several other master limited partnerships, our general partner has a non-economic ownership interest in us and is not entitled to receive any cash distributions from us based on incentive distribution rights or other equity interests.
Our use of DCF for the limited purposes described above and in this report is not a substitute for net cash flows provided by operating activities, which is the most comparable GAAP measure. For a discussion of net cash flows provided by operating activities, see “Cash Flow Statement Highlights” within this Part I, Item 2.
The following table summarizes our calculation of DCF for the periods indicated (dollars in millions):
The following table presents a reconciliation of net cash flows provided by operating activities to DCF for the periods indicated (dollars in millions):
Free Cash Flow
Free Cash Flow (“FCF”), a non-GAAP financial measure, is a traditional cash flow metric that is widely used by a variety of investors and other participants in the financial community, as opposed to DCF, which is a cash flow measure primarily used by investors and others in evaluating midstream energy companies, including master limited partnerships. In general, FCF is a measure of how much cash flow a business generates during a specified time period after accounting for all capital investments, including expenditures for growth and sustaining capital projects. By comparison, only sustaining capital expenditures are reflected in DCF.
We believe that FCF is important to traditional investors since it reflects the amount of cash available for reducing debt, investing in additional capital projects, paying distributions, common unit repurchases and similar matters. Since business partners fund certain capital projects of our consolidated subsidiaries, our determination of FCF reflects the amount of cash contributed from and distributed to noncontrolling interests. Our calculation of FCF may or may not be comparable to similarly titled measures used by other companies.
Our use of FCF for the limited purposes described above and in this report is not a substitute for net cash flows provided by operating activities, which is the most comparable GAAP measure.
FCF fluctuates based on our earnings, the level of investing activities we undertake each period, and the timing of operating cash receipts and payments. In addition to providing the quarterly amounts presented below, we also provide a calculation of aggregate FCF over the twelve months ended September 30, 2020 in order to measure FCF over a longer term. The following table summarizes our calculation of FCF for the periods indicated (dollars in millions):
For a discussion of primary drivers of our quarterly net cash flows provided by operating activities and cash used in investing activities, see “Cash Flow Statement Highlights” within this Part I, Item 2.
Capital Investments
Capital investing activity throughout the domestic energy industry has been reduced significantly in response to the supply and demand disruptions caused by the COVID-19 pandemic and the related oil price shock. In light of these adverse macroeconomic conditions, we have reevaluated our planned capital investments in order to maximize available liquidity.
Based on information currently available, we expect our total capital investments for 2020, net of contributions from joint venture partners, to approximate $3.2 billion, which reflects growth capital investments of $2.9 billion and approximately $300 million for sustaining capital expenditures. In addition, we currently expect our growth capital investments in 2021 and 2022 for sanctioned projects to approximate $1.6 billion and $800 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.
Our forecast of capital investments for 2020 through 2022 is based on announced strategic operating and growth plans (through the filing date of this quarterly report), which are dependent upon our ability to generate the required funds from either operating cash flows or other means, including borrowings under debt agreements, the issuance of additional equity and debt securities, and potential divestitures. We may revise our forecast of capital investments due to factors beyond our control, such as adverse economic conditions, weather-related issues and changes in supplier prices. Furthermore, our forecast of capital investments may change due to decisions made by management at a later date, which may include unforeseen acquisition opportunities. Our success in raising capital, including partnering with other companies to share project costs and risks, continues to be a significant factor in determining how much capital we can invest. We believe our access to capital resources is sufficient to meet the demands of our current and future growth needs and, although we expect to make the forecast capital investments noted above, we may adjust the timing and amounts of projected expenditures in response to changes in capital market conditions.
We placed Frac X and Frac XI into service in March 2020 and September 2020, respectively. In addition, expansion projects on our Texas Express Pipeline and Front Range Pipeline were placed into commercial service in April 2020. We also placed the Midland-to-ECHO segment of the Midland-to-Webster pipeline into service in October 2020. We currently have $3.9 billion of growth capital projects scheduled to be completed by the end of 2023, which includes completion of our PDH 2 facility in the second quarter of 2023.
The following table summarizes our capital investments for the periods indicated (dollars in millions):
Comparison of Nine Months Ended September 30, 2020 with Nine Months Ended September 30, 2019
In total, investments in growth capital projects decreased $632.2 million period-to-period primarily due to the following:
Investments in unconsolidated affiliates decreased $90.2 million period-to-period primarily due to lower spending on joint venture dock infrastructure at Corpus Christi and other crude oil-related projects, which accounted for a $46.4 million decrease, and NGL pipeline expansion projects, which accounted for an additional $38.1 million decrease.
Fluctuations in investments for sustaining capital projects are primarily due to the timing and cost of pipeline integrity and similar projects.
Critical Accounting Policies and Estimates
A discussion of our critical accounting policies and estimates is included in our 2019 Form 10-K. The following types of estimates, in our opinion, are subjective in nature, require the exercise of professional judgment and involve complex analysis:
When used to prepare our Unaudited Condensed Consolidated Financial Statements, the foregoing types of estimates are based on our current knowledge and understanding of the underlying facts and circumstances. Such estimates may be revised as a result of changes in the underlying facts and circumstances. Subsequent changes in these estimates may have a significant impact on our consolidated financial position, results of operations and cash flows.
Other Items
Contractual Obligations
We have contractual future product purchase commitments for natural gas, NGLs, crude oil, petrochemicals and refined products. These commitments represent enforceable and legally binding agreements as of the reporting date. Our product purchase commitments at September 30, 2020 declined by an estimated $6.3 billion when compared to those reported in our 2019 Form 10-K primarily due to lower NGL and crude oil prices since December 31, 2019.
The principal amount of our consolidated debt obligations were $30.1 billion at September 30, 2020 compared to $27.88 billion at December 31, 2019. See “Liquidity and Capital Resources – Consolidated Debt” within this Part I, Item 2 for information regarding EPO’s senior notes offerings during 2020.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements that have or are reasonably expected to have a material current or future effect on our financial position, results of operations and cash flows.
Related Party Transactions
For information regarding our related party transactions, see Note 15 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.