ENTERPRISE PRODUCTS PARTNERS L.P. For the Years Ended
The following discussion and analysis of our financial condition, results of operations and related information for the years endedDecember 31, 2020 and 2019, including applicable year-to-year comparisons, should be read in conjunction with our Consolidated Financial Statements and accompanying notes included under Part II, Item 8 of this annual report. Our financial statements have been prepared in accordance with generally accepted accounting principles ("GAAP") inthe United States ("U.S."). Discussion and analysis of matters pertaining to the year endedDecember 31, 2018 and year-to-year comparisons between the years endedDecember 31, 2019 and 2018 are not included in this Form 10-K, but can be found under Part II, Item 7 of our annual report on Form 10-K for the year endedDecember 31, 2019 that was filed onFebruary 28, 2020 .
Key References Used in this Management's Discussion and Analysis
Unless the context requires otherwise, references to "we," "us" or "our" within
this annual report are intended to mean the business and operations of
References to the "Partnership" mean
References to "EPO" meanEnterprise Products Operating LLC , which is an indirect wholly owned subsidiary of the Partnership, and its consolidated subsidiaries, through which the Partnership conducts its business. We are managed by our general partner,Enterprise Products Holdings LLC ("Enterprise GP"), which is a wholly owned subsidiary ofDan Duncan LLC , a privately heldTexas limited liability company. The membership interests ofDan Duncan LLC are owned by a voting trust, the current trustees ("DD LLC Trustees") of which are: (i)Randa Duncan Williams , who is also a director and Chairman of the Board of Directors (the "Board") of Enterprise GP; (ii)Richard H. Bachmann , who is also a director and Vice Chairman of theBoard of Enterprise GP ; and (iii)W. Randall Fowler , who is also a director and the Co-Chief Executive Officer and Chief Financial Officer of Enterprise GP. Ms.Duncan Williams and Messrs. Bachmann and Fowler also currently serve as managers ofDan Duncan LLC . References to "EPCO" meanEnterprise Products Company , a privately heldTexas corporation, and its privately held affiliates. The outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees ("EPCO Trustees") of which are: (i) Ms.Duncan Williams , who serves as Chairman of EPCO; (ii)Mr. Bachmann , who serves as the President and Chief Executive Officer of EPCO; and (iii)Mr. Fowler , who serves as an Executive Vice President and the Chief Financial Officer of EPCO. Ms.Duncan Williams and Messrs. Bachmann and Fowler also currently serve as directors of EPCO.We, Enterprise GP, EPCO andDan Duncan LLC are affiliates under the collective common control of theDD LLC Trustees and the EPCO Trustees. EPCO, together with its privately held affiliates, owned approximately 32.2% of the Partnership's common units outstanding and 30.2% of its Series A Cumulative Convertible Preferred Units ("preferred units") outstanding atDecember 31, 2020 .
As generally used in the energy industry and in this annual report, the acronyms below have the following meanings:
/d = per day MMBbls = million barrels
BBtus = billion British thermal units MMBPD = million barrels per day Bcf = billion cubic feet
MMBtus = million British thermal units
BPD = barrels per day MMcf = million cubic feet
MBPD = thousand barrels per day TBtus = trillion British thermal units
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This annual report on Form 10-K for the year ended December 31, 2020 (our
"annual 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. Although we and our general partner
believe that our expectations reflected in such forward-looking statements
(including any forward-looking statements/expectations of third parties
referenced in this annual report) are reasonable, neither we nor our general
partner can give any assurances that such expectations will prove to be
correct.
Forward-looking statements are subject to a variety of risks, uncertainties and
assumptions as described in more detail under Part I, Item 1A of this annual
report. If one or more of these risks or uncertainties materialize, or if
underlying assumptions prove incorrect, our actual results may vary materially
from those anticipated, estimated, projected or expected. You should not put
undue reliance on any forward-looking statements. The forward-looking statements
in this annual report speak only as of the date hereof. Except as required by
federal and state securities laws, we undertake no obligation to publicly update
or revise any forward-looking statements, whether as a result of new
information, future events or any other reason.
Overview of Business
We are a publicly tradedDelaware limited partnership, the common units of which are listed on theNew York Stock Exchange ("NYSE") under the ticker symbol "EPD." Our preferred units are not publicly traded. We were formed inApril 1998 to own and operate certain natural gas liquids ("NGLs") related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products. We are owned by our limited partners (preferred and common unitholders) from an economic perspective. Enterprise GP, which owns a non-economic general partner interest in us, manages our Partnership. We conduct substantially all of our business operations through EPO and its consolidated subsidiaries. Our fully integrated, midstream energy asset network (or "value chain") links producers of natural gas, NGLs and crude oil from some of the largest supply basins inthe United States ("U.S."),Canada and theGulf of Mexico with domestic consumers and international markets. Our midstream energy operations include:
• natural gas gathering, treating, processing, transportation and storage;
• NGL transportation, fractionation, storage, and marine terminals (including
those used to export liquefied petroleum gases, or "LPG," and ethane);
• crude oil gathering, transportation, storage, and marine terminals;
• propylene production facilities (including propane dehydrogenation ("PDH")
facilities), butane isomerization, octane enhancement, isobutane
dehydrogenation ("iBDH") and high purity isobutylene ("HPIB") production
facilities;
• petrochemical and refined products transportation, storage, and marine
terminals (including those used to export ethylene and polymer grade propylene
("PGP"); and
• a marine transportation business that operates on key
intracoastal waterway systems.
The safe operation of our assets is a top priority. We are committed to
protecting the environment and the health and safety of the public and those
working on our behalf by conducting our business activities in a safe and
environmentally responsible manner. For additional information, see
"Environmental, Safety and Conservation" within the Regulatory Matters section
of Part I, Items 1 and 2 of this annual report.
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Like many publicly traded partnerships, we have no employees. All of our
management, administrative and operating functions are performed by employees of
EPCO pursuant to an administrative services agreement (the "ASA") or by other
service providers.
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, a
non-generally accepted accounting principle ("non-GAAP") financial measure, 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.
Our financial position, results of operations and cash flows are subject to certain risks. For information regarding such risks, see "Risk Factors" included under Part I, Item 1A of this annual report.
Current Outlook
As noted previously, this annual report on Form 10-K, including this update to our outlook on business conditions, contains forward-looking statements that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us, which includes forecast information published by third parties. See "Cautionary Statement Regarding Forward-Looking Information" within this Part II, Item 7 and "Risk Factors" in Part I, Item 1A, for additional information. The following information presents our current views on key midstream energy supply and demand fundamentals. The third-party supply and demand forecasts cited in the following discussion, including our internal forecasts based on such information, remain subject to significant uncertainty because mitigation and reopening efforts related to COVID-19, emerging variants of COVID-19 and the introduction of approved vaccines and proven therapeutics continue to evolve.
All references to
Changes in the supply of and demand for hydrocarbon products impacts both the volume of products that we sell and the level of services that we provide to customers, which in turn has a direct impact on our financial position, results of operations and cash flows. The continued global effects of the COVID-19 pandemic, which began in the first quarter of 2020 and include the consequences of international COVID-19 containment measures (e.g., quarantines, travel restrictions, temporary business closures and similar protective actions), reduced near-term demand for hydrocarbon products by record amounts and created a significant oversupply situation. Also, in the early stages of the pandemic, disputes between members of theOrganization of the Petroleum Exporting Countries ("OPEC") andRussia (collectively, the "OPEC+" group) over crude oil production levels led to unprecedented volatility in global energy markets and a historic collapse in crude oil prices inApril 2020 . Although the OPEC+ group and other producers subsequently reached agreements to gradually reduce the oversupply of crude oil through production cuts, the downturn in the energy industry caused by lower demand and prices negatively impacted us, the producers we work with and our other customers to varying degrees. 66
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Table of Contents Supply Side Observations Ongoing production cuts within the OPEC+ group, along with market-driven cuts inU.S. , Brazilian and Canadian supplies, continue to provide much-needed support for international energy markets in coping with the ongoing weakness in hydrocarbon demand attributable to the pandemic. InApril 2020 , the OPEC+ group resolved their production dispute by agreeing to reduce their combined crude oil production by 9.7 MMBPD in May andJune 2020 , 9.6 MMBPD inJuly 2020 , 7.7 MMBPD from August throughDecember 2020 , and 5.8 MMBPD fromJanuary 2021 toApril 2022 . InDecember 2020 , the OPEC+ group revised their post-2020 production curtailments in light of current market dynamics and agreed to reduce their combined crude oil production by 7.2 MMBPD beginning inJanuary 2021 . The group will also hold monthly meetings to sign off on production adjustments for the following month, which would be no more than a 0.5 MMBPD increase. In addition,Saudi Arabia , the world's biggest oil exporter, said it would voluntarily reduce its production by 1.0 MMBPD in February and March in recognition of demand uncertainty related to the pandemic. The duration of market-driven production cuts by non-OPEC countries such as theU.S. ,Brazil andCanada will depend on supply and demand fundamentals. According to theFebruary 2021 STEO, the EIA estimates that global production of petroleum and related liquids averaged 94.2 MMBPD in 2020, which represents a decline of 6.4 MMBPD when compared to 2019, and expects an average of 97.3 MMBPD in 2021 and 100.8 MMBPD in 2022. As a result of the current business environment, most crude oil producers inNorth America have significantly reduced their drilling and completion of new wells compared to prior years.Baker Hughes reported that the total number of drilling rigs working in the continentalU.S. (combined crude oil and natural gas rigs) declined from 805 atDecember 27, 2019 to 265 atJune 26, 2020 . TheU.S. drilling rig count stood at 266 onOctober 2, 2020 , but increased to 392 byFebruary 5, 2021 due to strengthening energy fundamentals. In itsFebruary 2021 STEO, the EIA estimates thatU.S. crude oil production averaged 11.3 MMBPD in 2020, which is down from an average of 12.3 MMBPD in 2019. According to theFebruary 2021 STEO, the EIA expectsU.S. crude oil production to decline to an average of 10.9 MMBPD in the second quarter of 2021 since near-term drilling and completion activity will not generate enough production to offset declines from existing wells. The EIA expects drilling activity to rise later in 2021, contributing toU.S. crude oil production returning to an average of 11.2 MMBPD in the fourth quarter of 2021 and 11.0 MBPD for 2021. The EIA forecastsU.S. crude oil production to average 11.5 MMBPD in 2022. In itsFebruary 2021 STEO, the EIA estimates thatU.S. natural gas production averaged 91.3 Bcf/d in 2020, which is down from an average of 93.1 Bcf/d in 2019. The EIA forecasts natural gas production to average 90.5 Bcf/d in 2021 and 91.0 Bcf/d in 2022. With the expected increase inU.S. crude oil production in late-2021, the EIA expects associated natural gas production from crude oil-directed wells to increase, especially in thePermian Basin region, and to average 90.5 Bcf/d in the fourth quarter of 2021.
Demand Side Observations
Across the globe, downstream demand for petroleum products such as gasoline and jet fuel has recovered from the lows of the second quarter of 2020, but remains depressed due to the effects of the pandemic and refiners have reduced their utilization rates in response. Many countries have eased their COVID-19 containment measures and central banks and governments have instituted fiscal measures in an effort to stimulate 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. In itsFebruary 2021 STEO, the EIA estimates that global demand for petroleum and related liquids averaged 92.3 MMBPD in 2020, and expects an average of 97.7 MMBPD in 2021 and 101.2 MMBPD in 2022. By contrast, the EIA estimates that global demand for petroleum and related liquids averaged 101.2 MMBPD in 2019 (pre-pandemic). 67
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The decrease in hydrocarbon demand attributable to COVID-19 and the resulting
oversupply situation caused a significant decrease in crude oil prices. Prior
to the pandemic, crude oil prices for West Texas Intermediate ("WTI") at
Cushing, Oklahoma (as reported by the NYMEX) closed at $61.06 per barrel on
December 31, 2019 . By March 31, 2020 , WTI prices closed at $20.48 per barrel
and, notwithstanding the announced OPEC+ production cuts, closed at a record low
of a negative $37.63 per barrel on April 20, 2020 . As demand began to recover
starting in the second quarter of 2020, WTI prices rebounded from the April lows
and closed at $39.27 per barrel on June 30, 2020 . At September 30, 2020 , WTI
prices closed at $40.22 per barrel. At December 31, 2020 , WTI prices closed at
$48.52 per barrel as supply and demand fundamentals strengthened. Prices
continue to increase as we begin 2021, averaging $52.10 per barrel in January
2021 .
In its February 2021 STEO, the EIA estimates that U.S. consumption of natural
gas averaged 83.3 Bcf/d in 2020, which reflects a 2.2% decrease from the 2019
average of 85.2 Bcf/d. The EIA expects U.S. consumption of natural gas to
decrease to an average of 81.7 Bcf/d in 2021 and 81.0 Bcf/d in 2022 due to
rising natural gas prices, which are expected to negatively impact demand from
the electric power sector. Natural gas prices, as measured by the NYMEX at
Henry Hub and reported in the February 2021 STEO, averaged $2.03 per MMBtu in
2020 compared to an average of $2.57 per MMBtu in 2019. The EIA forecasts Henry
Hub spot prices to increase to an average $2.95 per MMBtu in 2021 due to rising
space heating demand and liquefied natural gas exports amid the overall decrease
in U.S. natural gas production expected for 2021. The EIA expects Henry Hub
spot prices to average $3.27 per MMBtu in 2022.
Enterprise Outlook
We believe that crude oil prices will continue to increase. Our view considers the record retrenchment in drilling and completion activities worldwide, including byU.S. producers in 2020, along with steep decline curves in shale basins that result in lower near-term production through mid-2021, and the expected continuing recovery of global hydrocarbon demand following the pandemic. However, in the interim, we believe the midstream industry will be challenged in its supply-side businesses and that challenges and opportunities will be different for each producing basin.
Although the current industry and business outlooks remain challenging, we 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 the following:
• At
comprised of
credit facilities and
liquidity is supported by investment grade credit ratings on EPO's long-term
senior unsecured debt of BBB+, Baa1 and BBB+ from Standard and Poors, Moody's
and Fitch, respectively.
• EPO successfully issued
2020. Based on current conditions, we believe that we will have sufficient
liquidity and/or access to debt capital markets to fund the remaining principal
amount of senior notes maturing through 2021.
• In light of the current downturn in the domestic energy industry, we
reevaluated our planned capital investments. Based on information currently
available, we expect our total capital investments for 2021, net of
contributions from joint venture partners, to approximate
reflects growth capital investments of
expenditures of
capital investments in 2022 and 2023 for sanctioned projects to approximate
capital investments associated with our proposed deepwater offshore crude oil
terminal (the
governmental approvals. We currently anticipate receiving approval for SPOT as
early as the third quarter of 2021; however, we can give no assurance as to
whether the project will ultimately be approved or the timing of such decision.
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• We continue to optimize our assets to provide incremental services to customers
and to respond to market opportunities. As prices for certain NGLs, crude oil
and refined products fell in 2020 due to collapsing demand for refined products
as a result of the pandemic, our storage services provided valuable flexibility
for our customers. In addition, our earnings from marketing activities in 2020
benefited from using uncontracted storage capacity to capture contango
opportunities in NGLs, crude oil and refined products.
• Across all of our assets, we have contracted with a large number of quality
customers in order to achieve customer diversification. In 2020, our top 200
largest customers represented 95.3% of consolidated revenues. Based on their
respective year-end 2020 debt ratings, 81.4% of our top 200 customers were
either investment grade rated or backed by letters of credit. Additionally,
only 8.1% of our top 200 customer revenues were attributable to sub-investment
grade or non-rated upstream producers.
In light of current events, we are closely monitoring the recoverability of our long-lived assets for potential impairment. We recognized a combined$890.6 million of non-cash asset impairment charges during the year endedDecember 31, 2020 . If the adverse economic impacts of the pandemic persist for longer periods than currently expected, these developments could result in our recognition of additional non-cash impairment charges in the future.
Significant Recent Developments
Enterprise and Magellan to Develop Joint Houston Crude Oil Futures Contract
InJanuary 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 theHouston, Texas area in response to market interest for aHouston -based index with greater scale, flow assurance and price transparency. The quality specifications will be consistent with WTI crude oil originating from thePermian Basin with delivery capabilities at either our ECHO terminal inHouston or Magellan'sEast Houston terminal.
Ethylene Export Terminal Enters Full Service
InDecember 2020 , our ethylene export terminal located at our Morgan's Point facility on the Houston Ship Channel entered full service with the commissioning of a refrigerated storage tank capable of handling 66 million pounds of ethylene. The ethylene export terminal, which had been in limited service sinceDecember 2019 , features two docks and a nameplate capacity to load 1 million tons of ethylene per year. Ethylene is the primary feedstock for a wide variety of consumer products, including cell phones and computer parts, food packaging, apparel, textiles and personal protective equipment. We own a 50% member interest inEnterprise Navigator Ethylene Terminal LLC , which owns the export facility. Our ethylene system serves as an open market storage and trading hub for the ethylene industry by incorporating storage capacity, connections to multiple ethylene pipelines, and high-volume export capabilities. In support of our ethylene business, ourMont Belvieu storage operations include a high-capacity underground ethylene storage well having a storage capacity of 600 million pounds of ethylene. The storage well is connected to our Morgan's Point ethylene export terminal and further to Bayport,Texas by a 27-mile pipeline.
Enterprise Joins The Alliance To End
InDecember 2020 , we became the first midstream company member of The Alliance to EndPlastic Waste (the "Alliance"), which represents an international community of chief executive officers from across the plastic industry that are committed to addressing the global plastic waste challenge. Formed in 2019, the Alliance partners with a diverse and growing network of organizations, technical leaders, engineers and scientists, all dedicated to the goal of ending plastic waste. To achieve this goal, the Alliance focuses on four strategic areas - infrastructure, innovation, education and clean up - to unlock innovative solutions that will bring the world closer to the Alliance's ambition of diverting millions of tons of plastic waste in more than 100 at-risk cities across the globe by 2025. 69
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Expansion of
InJuly 2019 , we announced a third expansion of ourMidland -to-ECHO System comprised of a 36-inch pipeline extending fromMidland, Texas to our Enterprise Crude Houston ("ECHO") terminal, and further from ECHO to a third-party terminal inWebster, Texas (collectively, the "Midland -to-Webster pipeline"). We proportionately consolidate a 29% undivided interest in theMidland -to-Webster pipeline, which we refer to as the "Midland -to-ECHO 3" pipeline. InOctober 2020 , we announced that theMidland -to-ECHO segment was placed into service. The ECHO-to-Webster segment was mechanically complete inDecember 2020 . Once all facilities are placed into full commercial service, our maximum transportation capacity on the pipeline is expected to approximate 450 MBPD.
Amendments to Crude Oil Transportation Agreements; Cancellation of
InSeptember 2020 , we announced the amendment of certain crude oil transportation agreements and the related cancellation of theMidland -to-ECHO 4 pipeline. In general, the amendments provide for the reduction of near-term pipeline volume commitments in exchange for extending the term of the related transportation agreements and using existing pipeline infrastructure. Cancellation of theMidland -to-ECHO 4 pipeline reduced our growth capital investments by an aggregate$800 million over the years 2020 through 2022. As a result of the cancellation, we recorded an impairment charge of$42.2 million .
Execution of Long-Term PGP Sales Agreement in Support of PDH 2 Facility
InJune 2020 , we announced the execution of a long-term sales agreement with Marubeni Corporation to supply PGP from our second propane dehydrogenation plant ("PDH 2"), which is currently under construction at ourMont Belvieu complex. Marubeni Corporation is a major Japanese integrated trading and investment business conglomerate and the world's largest olefins trader. PGP is a primary petrochemical that has global demand growth as a feedstock to manufacture consumer, medical and industrial products that improve the daily lives and protect the health of people around the world. PDH 2 is expected to have the capacity to upgrade 35 MBPD of propane into 1.65 billion pounds per year (equivalent to 25 MBPD) of PGP and begin service in the second quarter of 2023. Once PDH 2 is placed into service and integrated with PDH 1 and our other propylene production facilities, we will have the capability to produce 11 billion pounds of propylene per year. 70
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Selected Energy Commodity Price Data
The following table presents selected average index prices for natural gas and selected NGL and petrochemical products for the periods indicated:
Polymer Refinery
Natural Normal Natural Grade Grade Processing
Gas, Ethane, Propane, Butane, Isobutane, Gasoline, Propylene, Propylene, Gross Spread
$/MMBtu $/gallon $/gallon $/gallon $/gallon $/gallon $/pound $/pound $/gallon
(1) (2) (2) (2) (2) (2) (3) (3) (4)
2019 by quarter:
1st Quarter $3.15 $0.30 $0.67 $0.82 $0.85 $1.16 $0.38 $0.24 $0.31
2nd Quarter $2.64 $0.21 $0.55 $0.63 $0.65 $1.21 $0.37 $0.24 $0.25
3rd Quarter $2.23 $0.17 $0.44 $0.51 $0.66 $1.06 $0.38 $0.23 $0.21
4th Quarter $2.50 $0.19 $0.50 $0.68 $0.82 $1.20 $0.35 $0.21 $0.25
2019 Averages $2.63 $0.22 $0.54 $0.66 $0.75 $1.16 2020 by quarter: 1st Quarter$1.95 $0.14 $0.37 $0.57 $0.63 $0.93 $0.31 $0.18 $0.19 2nd Quarter$1.71 $0.19 $0.41 $0.43 $0.44 $0.41 $0.26 $0.11 $0.17 3rd Quarter$1.98 $0.22 $0.50 $0.58 $0.60 $0.80 $0.35 $0.17 $0.25 4th Quarter$2.67 $0.21 $0.57 $0.76 $0.68 $0.92 $0.41 $0.24 $0.22 2020 Averages$2.08 $0.19 $0.46 $0.59 $0.59 $0.77
(1) Natural gas prices are based on Henry-Hub Inside FERC commercial index prices
as reported by Platts, which is a division of
are based on Mont Belvieu Non-TET commercial index prices as reported by Oil
product as reported by IHS Chemical, a division of
Chemical"). Refinery grade propylene ("RGP") prices represent
weighted-average spot prices for such product as reported by IHS Chemical. (4) The "Indicative Gas Processing Gross Spread" represents our generic estimate
of the gross economic benefit from extracting NGLs from natural gas
production based on certain pricing assumptions. Specifically, it is the
amount by which the assumed economic value of a composite gallon of NGLs at
natural gas at Henry Hub,
does not consider the operating costs incurred by a natural gas processing
facility to extract the NGLs nor the transportation and fractionation costs
to deliver the NGLs to market. In addition, the actual gas processing spread
earned at each plant is determined by regional pricing and extraction
dynamics.
The weighted-average indicative market price for NGLs was
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The following table presents selected average index prices for crude oil for the periods indicated:
WTI Midland Houston LLS
Crude Oil, Crude Oil, Crude Oil Crude Oil,
$/barrel $/barrel $/barrel $/barrel
(1) (2) (2) (3)
2019 by quarter:
1st Quarter $54.90 $53.70 $61.19 $62.35
2nd Quarter $59.81 $57.62 $66.47 $67.07
3rd Quarter $56.45 $56.12 $59.75 $60.64
4th Quarter $56.96 $57.80 $60.04 $60.76
2019 Averages $57.03 $56.31 $61.86 $62.71
2020 by quarter:
1st Quarter $46.17 $45.51 $47.81 $48.15
2nd Quarter $27.85 $28.22 $29.68 $30.12
3rd Quarter $40.93 $41.05 $41.77 $42.47
4th Quarter $42.66 $43.07 $43.63 $44.08
2020 Averages $39.40 $39.46 $40.72 $41.21 (1) WTI prices are based on commercial index prices at
measured by the NYMEX.
(2)
reported by Argus. (3) Light Louisiana Sweet ("LLS") prices are based on commercial index prices as
reported by Platts.
Fluctuations in our consolidated revenues and cost of sales amounts are
explained in large part by changes in energy commodity prices. Energy commodity
prices in 2020 fluctuated significantly due to the adverse economic effects of
the COVID-19 pandemic and, with respect to crude oil prices in early 2020, the
production dispute between Saudi Arabia and Russia . See "Current Outlook"
within this Part II, Item 7 for information regarding these recent events.
A decrease in our consolidated marketing revenues due to lower energy commodity
sales prices may not result in a decrease in gross operating margin or cash
available for distribution, since our consolidated cost of sales amounts would
also decrease due to comparable decreases in the purchase prices of the
underlying energy commodities. The same type of correlation would be true in
the case of higher energy commodity sales prices and purchase costs.
We attempt to mitigate commodity price exposure through our hedging activities
and the use of fee-based arrangements. See Note 14 of the Notes to Consolidated
Financial Statements included under Part II, Item 8 of this annual report for
information regarding our commodity hedging activities.
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The following table summarizes the key components of our consolidated results of operations for the years indicated (dollars in millions):
For the Year Ended
December 31,
2020 2019
Revenues $ 27,199.7 $ 32,789.2
Costs and expenses:
Operating costs and expenses:
Cost of sales 16,723.2 22,065.8
Other operating costs and expenses 2,800.2 3,020.7
Depreciation, amortization and accretion expenses 1,961.5 1,848.3 Net gains attributable to asset sales
(4.4 ) (5.7 )
Asset impairment and related charges 890.6 132.7
Total operating costs and expenses 22,371.1
27,061.8
General and administrative costs 219.6
211.7
Total costs and expenses 22,590.7
27,273.5
Equity in income of unconsolidated affiliates 426.1 563.0 Operating income 5,035.1 6,078.7 Interest expense (1,287.4 ) (1,243.0 ) Change in fair value of Liquidity Option (2.3 ) (119.6 ) Other, net 16.0
16.6
Benefit from (provision for) income taxes 124.3 (45.6 ) Net income 3,885.7
4,687.1
Net income attributable to noncontrolling interests (110.1 ) (95.8 ) Net income attributable to preferred units
(0.9 ) -
Net income attributable to common unitholders
Revenues
The following table presents each business segment's contribution to consolidated revenues for the years indicated (dollars in millions):
For the Year Ended
December 31,
2020 2019
NGL Pipelines & Services:
Sales of NGLs and related products $ 8,970.7 $ 10,934.3
Midstream services 2,206.5 2,536.4
Total 11,177.2 13,470.7
Crude Oil Pipelines & Services:
Sales of crude oil 5,410.8 9,007.8
Midstream services 1,278.2 1,279.5
Total 6,689.0 10,287.3
Natural Gas Pipelines & Services:
Sales of natural gas 1,530.5 2,075.4
Midstream services 1,022.6 1,094.0
Total 2,553.1 3,169.4
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products 5,942.6 4,985.2
Midstream services 837.8 876.6
Total 6,780.4 5,861.8
Total consolidated revenues $ 27,199.7 $ 32,789.2
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Total revenues for 2020 decreased$5.59 billion when compared to 2019 primarily due to a net$5.15 billion decrease in marketing revenues. Revenues from the marketing of crude oil and natural gas decreased$4.14 billion year-to-year primarily due to lower average sales prices, which accounted for a$3.27 billion decrease, and lower sales volumes, which accounted for an additional$867.8 million decrease. Revenues from the marketing of NGLs decreased a net$1.96 billion year-to-year primarily due to lower average sales prices, which accounted for a$3.16 billion decrease, partially offset by the effects of higher sales volumes, which resulted in a$1.2 billion increase. Revenues from the marketing of petrochemicals and refined products increased a net$957.4 million year-to-year primarily due to higher sales volumes, which accounted for a$2.05 billion increase, partially offset by lower average sales prices, which resulted in a$1.1 billion decrease. Revenues from midstream services for 2020 decreased$441.4 million when compared to 2019. Revenues from our natural gas processing facilities decreased$229.9 million year-to-year primarily due to lower market values for the equity NGLs we receive as non-cash consideration for processing services. Revenues from ourMidland -to-ECHO 2 pipeline, which commenced limited service inFebruary 2019 and full service inApril 2019 andMidland -to-ECHO 3 pipeline, which commenced service inOctober 2020 , increased a combined$49.6 million year-to-year. Revenues from our other pipeline assets decreased$179.8 million year-to-year primarily due to lower demand for crude oil, natural gas and refined products transportation services. Lastly, revenues from ourMont Belvieu -area NGL fractionators decreased$82.0 million year-to-year primarily due to lower fractionation fees. For additional information regarding our revenues, see Note 9 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. Operating costs and expenses Total operating costs and expenses for 2020 decreased$4.69 billion when compared to 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$3.83 billion year-to-year primarily due to lower average purchase prices, which accounted for a$3.19 billion decrease, and lower sales volumes, which accounted for an additional$634.4 million decrease. The cost of sales associated with our marketing of NGLs decreased a net$2.25 billion year-to-year primarily due to lower average purchase prices, which accounted for a$3.22 billion decrease, partially offset by higher sales volumes, which accounted for a$970.7 million increase. The cost of sales associated with our marketing of petrochemicals and refined products increased a net$736.9 million year-to-year primarily due to higher sales volumes, which accounted for a$1.81 billion increase, partially offset by lower average purchase prices, which accounted for a$1.07 billion decrease. Other operating costs and expenses for 2020 decreased$220.5 million year-to-year primarily due to lower maintenance, chemicals and power-related expenses, which accounted for a$282.2 million decrease, partially offset by higher ad valorem taxes and employee compensation costs, which accounted for a$50.2 million increase. Depreciation, amortization and accretion expense increased$113.2 million year-to-year primarily due to assets placed into full or limited service since the first quarter of 2019 (e.g., the iBDH plant,Mentone andOrla gas processing facilities, Fracs X and XI and the Enterprise Navigator ethylene terminal). Non-cash asset impairment charges increased$757.9 million year-to-year primarily due to the recognition in 2020 of the full impairment of goodwill associated with our Natural Gas Pipelines & Services business segment, which accounted for$296.3 million of expense, the partial impairment of our marine transportation business, which accounted for$256.7 million of expense, and the partial impairment of natural gas gathering and processing assets inSouth Texas , which accounted for an additional$125.7 million of expense. For information regarding these charges, see Notes 2, 4 and 6 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
General and administrative costs
General and administrative costs for 2020 increased$7.9 million when compared to 2019 primarily due to higher professional services and employee compensation costs. 74
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Equity in income of unconsolidated affiliates
Equity income from our unconsolidated affiliates for 2020 decreased
Operating income
Operating income for the year ended
Interest expense
The following table presents the components of our consolidated interest expense for the years indicated (dollars in millions):
For the Year Ended
December 31,
2020 2019
Interest charged on debt principal outstanding $ 1,330.6
39.3 107.4
Interest costs capitalized in connection with construction projects (2) (115.0 ) (143.8 ) Other (3) 32.5 27.8 Total$ 1,287.4 $ 1,243.0
(1) Amount presented for the year ended
mark-to-market loss of
connection with the exercise of swaptions. Due to declining interest rates,
the counterparties to the swaptions exercised their right to put us into ten
forward-starting swaps in
of
instruments and were subject to mark-to-market accounting, we incurred an
unrealized, mark-to-market loss at inception of the forward-starting swaps
that is reflected as an increase in interest expense in 2019. The ten
forward-starting swaps resulting from the swaption exercise were designated
as hedging instruments and qualified for cash flow hedge accounting. (2) We capitalize interest costs incurred on funds used to construct property,
plant and equipment while the asset is in its construction phase.
Capitalized interest amounts become part of the historical cost of an asset
and are charged to earnings (as a component of depreciation expense) on a
straight-line basis over the estimated useful life of the asset once the
asset enters its intended service. When capitalized interest is recorded, it
reduces interest expense from what it would be otherwise. Capitalized
interest amounts fluctuate based on the timing of when projects are placed
into service, our capital investment levels and the interest rates charged on
borrowings.
(3) Primarily reflects facility commitment fees charged in connection with our
revolving credit facilities and amortization of debt issuance costs.
Interest charged on debt principal outstanding, which is a key driver of interest expense, increased a net$79.0 million year-to-year primarily due to increased debt principal amounts outstanding during 2020, which accounted for a$109.2 million increase, partially offset by the effect of lower overall interest rates during 2020, which accounted for a$30.2 million decrease. Our weighted-average debt principal balance for 2020 was$29.91 billion compared to$27.41 billion for 2019. In general, our debt principal balances have increased over time due to the partial debt financing of our capital investments. For information regarding our debt obligations, see Note 7 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
Change in fair value of Liquidity Option
OnFebruary 25, 2020 , we received notice fromMarquard & 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. , aDelaware corporation previously namedOiltanking Holding Americas, Inc. ("OTA"), and M&B datedOctober 1, 2014 (the "Liquidity Option Agreement"). The Partnership settled its obligations under the Liquidity Option Agreement onMarch 5, 2020 . 75
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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$2.3 million and$119.6 million during the years endedDecember 31, 2020 and 2019, respectively. The expense recognized for 2020 primarily reflects accretion expense for the period in which the Liquidity Option liability was outstanding before it was settled onMarch 5, 2020 . The higher level of expense recognized in 2019 was primarily due to a decrease in the discount factor used in determining the present value of the liability. For additional information regarding the exercise, see "Issuance of Common Units due to Settlement of Liquidity Option inMarch 2020 " within the Liquidity and Capital Resources section of this Part II, Item 7. In addition, please refer to Note 8 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. Income taxes
The following table presents the components of our consolidated benefit from (provision for) income taxes for the years indicated (dollars in millions):
For the Year Ended
December 31,
2020 2019
Deferred tax benefit attributable to OTA
(32.1 ) $ (44.2 )
Other 1.1 (1.4 )
Benefit from (provision for) income taxes
OnMarch 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 inOctober 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. AtMarch 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 Statement of Consolidated Operations for the year endedDecember 31, 2020 . OTA recognized an additional net, non-cash deferred income tax benefit of$83.1 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 toMarch 5, 2020 throughSeptember 30, 2020 . In total, our earnings for 2020 reflect$155.3 million of deferred income tax benefit attributable to OTA. OnSeptember 30, 2020 , OTA exchanged the Partnership common units it owned for non-publicly traded preferred units having a stated value of$1,000 per unit. As a result and beginningSeptember 30, 2020 , OTA's deferred tax liability no longer fluctuates due to market price changes in our common units. For information regarding the issuance of preferred units onSeptember 30, 2020 , including the OTA-related exchange, see "Liquidity and Capital Resources" within this Part II, Item 7.
For information regarding our income taxes, see Note 16 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
Business Segment Highlights
We evaluate segment performance based on our financial measure of gross
operating margin. Gross operating margin is an important performance measure of
the core profitability of our operations and forms the basis of our internal
financial reporting. We believe that investors benefit from having access to
the same financial measures that our management uses in evaluating segment
results.
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The following table presents gross operating margin by segment and non-GAAP total gross operating margin for the years indicated (dollars in millions):
For the Year Ended
December 31,
2020 2019
Gross operating margin by segment:
NGL Pipelines & Services$ 4,182.4 $ 4,069.8 Crude Oil Pipelines & Services 1,997.3 2,087.8 Natural Gas Pipelines & Services 926.6 1,062.6 Petrochemical & Refined Products Services 1,081.8 1,069.6 Total segment gross operating margin (1) 8,188.1 8,289.8 Net adjustment for shipper make-up rights (85.7 ) (24.1 ) Total gross operating margin (non-GAAP)$ 8,102.4 $ 8,265.7
(1) Within the context of this table, total segment gross operating margin
represents a subtotal and corresponds to measures similarly titled within our
business segment disclosures found under Note 10 of the Notes to Consolidated
Financial Statements included under Part II, Item 8 of this annual report.
Total gross operating margin includes equity in the earnings of unconsolidated
affiliates, but is exclusive of other income and expense transactions, income
taxes, the cumulative effect of changes in accounting principles and
extraordinary charges. Total gross operating margin is presented on a 100%
basis before any allocation of earnings to noncontrolling interests. Our
calculation of gross operating margin may or may not be comparable to similarly
titled measures used by other companies. Segment gross operating margin for NGL
Pipelines & Services and Crude Oil Pipelines & Services reflect adjustments for
shipper make-up rights that are included in management's evaluation of segment
results. However, these adjustments are excluded from non-GAAP total gross
operating margin.
The GAAP financial measure most directly comparable to total gross operating
margin is operating income. For a discussion of operating income and its
components, see the previous section titled "Income Statement Highlights" within
this Part II, Item 7. The following table presents a reconciliation of
operating income to total gross operating margin for the years indicated
(dollars in millions):
For the Year Ended
December 31,
2020 2019
Operating income $ 5,035.1 $ 6,078.7
Adjustments to reconcile operating income to total gross
operating margin
(addition or subtraction indicated by sign):
Depreciation, amortization and accretion expense in operating costs and expenses
1,961.5 1,848.3
Asset impairment and related charges in operating costs and expenses
890.6 132.7
Net gains attributable to asset sales in operating costs and expenses
(4.4 ) (5.7 )
General and administrative costs 219.6
211.7
Total gross operating margin (non-GAAP)$ 8,102.4
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., our crude oil pipelines and export docks and natural gas gathering systems) during the year endedDecember 31, 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 II, Item 7. 77
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Table of Contents NGL Pipelines & Services
The following table presents segment gross operating margin and selected volumetric data for the NGL Pipelines & Services segment for the years indicated (dollars in millions, volumes as noted):
For the Year Ended
December 31,
2020 2019
Segment gross operating margin:
Natural gas processing and related NGL marketing activities $ 997.5 $ 1,159.7
NGL pipelines, storage and terminals 2,524.1 2,402.2
NGL fractionation 660.8 507.9
Total $ 4,182.4 $ 4,069.8
Selected volumetric data:
NGL pipeline transportation volumes (MBPD) 3,589 3,615
NGL marine terminal volumes (MBPD) 722
626
NGL fractionation volumes (MBPD) 1,359
1,017
Equity NGL production volumes (MBPD) (1) 151
144
Fee-based natural gas processing volumes (MMcf/d) (2, 3) 4,285
4,738
(1) Represents the NGL volumes we earn and take title to in connection with our
processing activities. (2) Volumes reported correspond to the revenue streams earned by our natural gas
processing plants. (3) Fee-based natural gas processing volumes are measured at either the wellhead
or plant inlet in MMcf/d.
Natural gas processing and related NGL marketing activities
Gross operating margin from natural gas processing and related NGL marketing
activities for the year ended December 31, 2020 decreased $162.2 million when
compared to the year ended December 31, 2019 .
Gross operating margin from our natural gas processing facilities located in the
Rocky Mountains (Meeker, Pioneer and Chaco plants) decreased a combined $94.2
million year-to-year primarily due to lower average processing margins
(including the impact of hedging activities). On a combined basis, fee-based
natural gas processing volumes at these plants decreased 319 MMcf/d
year-to-year.
Gross operating margin from our South Texas natural gas processing facilities
decreased $90.2 million year-to-year primarily due to lower average processing
margins (including the impact of hedging activities), which accounted for a
$51.2 million decrease, lower average processing fees, which accounted for a
$23.9 million decrease, and lower processing volumes, which accounted for an
additional $12.8 million decrease. On a combined basis, fee-based natural gas
processing volumes at these plants decreased 156 MMcf/d and equity NGL
production volumes increased 5 MBPD year-to-year.
Gross operating margin from our Louisiana and Mississippi natural gas processing
facilities decreased a net $32.4 million year-to-year primarily due to lower
average processing margins (including the impact of hedging activities), which
accounted for a $33.4 million decrease, and lower processing volumes, which
accounted for an additional $17.9 million decrease, partially offset by lower
operating costs, which accounted for a $10.7 million increase, and higher
average processing fees, which accounted for an additional $9.5 million
increase. Net to our interest, fee-based natural gas processing and equity NGL
production volumes at these plants decreased a combined 389 MMcf/d and 8 MBPD,
respectively, year-to-year.
Gross operating margin from our Permian Basin natural gas processing facilities
decreased a net $18.9 million year-to-year primarily due to lower average
processing margins (including the impact of hedging activities), which accounted
for a $42.5 million decrease, and lower average processing fees, which accounted
for an additional $25.2 million decrease, partially offset by higher processing
volumes, which accounted for a $54.8 million increase. On a combined basis,
fee-based natural gas processing and equity NGL production volumes at our
Permian Basin plants increased 363 MMcf/d and 8 MBPD, respectively,
year-to-year, primarily due to additional processing capacity at our Orla
facility that was placed into service in July 2019 and the start-up of our
Mentone facility in December 2019 .
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Gross operating margin from our NGL marketing activities increased a net$71.5 million year-to-year primarily due to higher sales volumes, which accounted for a$248.9 million increase, partially offset by lower average sales margins (including the impact of hedging activities), which accounted for a$177.7 million decrease. The year-to-year increase in gross operating margin can be attributed to results from marketing strategies that seek to optimize our storage assets, which accounted for a$123.7 million increase, partially offset by lower earnings from strategies that seek to optimize our export, plant and transportation assets, which accounted for a combined$98.2 million decrease. In addition, gross operating margin from our NGL marketing activities attributable to non-cash, mark-to-market earnings increased$46.0 million year-to-year. NGL pipelines, storage and terminals Gross operating margin from our NGL pipelines, storage and terminal assets for the year endedDecember 31, 2020 increased$121.9 million when compared to the year endedDecember 31, 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 andFront Range Pipeline , servePermian Basin and/orRocky Mountain producers. On a combined basis, gross operating margin from these pipelines increased a net$65.8 million year-to-year primarily due to higher average transportation fees, which accounted for a$64.9 million increase, and lower operating costs, which accounted for an additional$36.4 million increase, partially offset by lower transportation volumes of 101 MBPD (net to our interest), which accounted for a$25.9 million decrease. Gross operating margin from LPG-related activities at EHT increased$62.7 million year-to-year primarily due to higher export volumes of 105 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$21.5 million year-to-year primarily due to an 86 MBPD increase in transportation volumes. Gross operating margin at our Morgan'sPoint Ethane Export Terminal increased$8.6 million year-to-year primarily due to lower operating costs. Export volumes from our Morgan'sPoint Ethane Export Terminal decreased 9 MBPD year-to-year. Gross operating margin from our Aegis Pipeline increased a net$27.3 million year-to-year primarily due to a 107 MBPD increase in transportation volumes associated with contract commitments, which accounted for a$43.0 million increase, partially offset by higher operating costs, which accounted for a$9.5 million decrease. Gross operating margin from our South Louisiana NGL Pipeline System and related storage facilities decreased a combined$22.6 million year-to-year primarily due to lower transportation volumes of 60 MBPD, which accounted for an$11.9 million decrease, and lower terminal revenues, which accounted for an additional$6.0 million decrease. Gross operating margin from our Lou-Tex NGL Pipeline decreased$8.4 million year-to-year primarily due to lower transportation volumes of 24 MBPD. Gross operating margin from ourMont Belvieu storage facility decreased a net$16.6 million year-to-year primarily due to lower handling and throughput fee revenues, which accounted for a$45.6 million decrease, partially offset by higher storage fees, which accounted for a$32.1 million increase. Gross operating margin from our South Texas NGL Pipeline System decreased$11.9 million year-to-year primarily due to lower pipeline capacity fee revenues earned from an affiliate pipeline. Transportation volumes on ourSouth Texas NGL Pipeline System increased 15 MBPD year-to-year. NGL fractionation Gross operating margin from NGL fractionation during the year endedDecember 31, 2020 increased$152.9 million when compared to the year endedDecember 31 2019 . Gross operating margin from ourMont Belvieu -area NGL fractionators increased$123.9 million primarily due to higher fractionation volumes, which increased 353 MBPD year-to-year (net to our interest) primarily due to the start-up of Frac X and Frac XI inMarch 2020 andSeptember 2020 , respectively. Gross operating margin from our Hobbs NGL fractionator increased$20.2 million year-to-year primarily due to major maintenance activities completed in the first quarter of 2019. NGL fractionation volumes at our Hobbs NGL fractionator increased 12 MBPD year-to-year. 79
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Crude Oil Pipelines & Services
The following table presents segment gross operating margin and selected volumetric data for the Crude Oil Pipelines & Services segment for the years indicated (dollars in millions, volumes as noted):
For the Year Ended
December 31,
2020 2019Segment gross operating margin:
excluding associated non-cash mark-to-market results
88.4
TotalMidland -to-ECHO System 359.2
551.4
Other crude oil pipelines, terminals and related marketing results 1,638.1 1,536.4 Total$ 1,997.3 $ 2,087.8 Selected volumetric data: (1)
Crude oil pipeline transportation volumes (MBPD) 2,166 2,304 Crude oil marine terminal volumes (MBPD) 724 964
(1) In general, segment volumes for the year ended
adversely impacted by the reduction in upstream crude oil production
activities caused by the COVID-19 pandemic and crude oil price shock.
Gross operating margin from our Crude Oil Pipelines & Services segment for the
year ended December 31, 2020 decreased $90.5 million when compared to the year
ended December 31, 2019 .
Gross operating margin from our Midland -to-ECHO System and related business
activities decreased $192.2 million year-to-year primarily due to lower average
sales margins from marketing activities (including the impact of hedging
activities) of $217.2 million . Gross operating margin from our Midland -to-ECHO
3 pipeline, which commenced operations in October 2020 , was $30.0 million with
transportation volumes of 214 MBPD.
Gross operating margin from our South Texas Crude Oil Pipeline System decreased
$50.0 million year-to-year primarily due to lower transportation volumes, which
accounted for a $32.4 million decrease, and lower transportation and other fees,
which accounted for an additional $23.5 million decrease. Gross operating
margin from our equity investment in the Eagle Ford Crude Oil Pipeline decreased
$24.2 million year-to-year primarily due to lower transportation volumes. On an
aggregate basis, transportation volumes on these two pipeline systems decreased
a combined 68 MBPD year-to-year (net to our interest).
Gross operating margin from our equity investment in the Seaway Pipeline
decreased $53.2 million year-to-year primarily due to lower average
transportation fees, which accounted for a $36.7 million decrease, and lower
transportation volumes, which accounted for an additional $18.9 million
decrease. Net to our interest, transportation and marine terminal volumes for
the Seaway Pipeline decreased 164 MBPD and 32 MBPD, respectively, year-to-year.
Gross operating margin from our ECHO terminal decreased
Gross operating margin from our other crude oil marketing activities increased$225.8 million year-to-year primarily due to higher average sales margins (including the impact of hedging activities). The year-to-year increase in gross operating margin from these activities is primarily due to results from marketing strategies that seek to optimize our storage assets.
Gross operating margin from crude oil activities at EHT increased
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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 years indicated (dollars in millions, volumes as noted):
For the Year Ended
December 31,
2020 2019
Segment gross operating margin $ 926.6 $ 1,062.6
Selected volumetric data:
Natural gas pipeline transportation volumes (BBtus/d) 13,421 14,198
Gross operating margin from our Natural Gas Pipelines & Services segment for the year endedDecember 31, 2020 decreased$136.0 million when compared to the year endedDecember 31, 2019 . Gross operating margin from our Acadian Gas System decreased$45.4 million year-to-year primarily due to lower capacity reservation revenues on the Haynesville Extension pipeline, which accounted for a$32.5 million decrease, and lower net benefits from settlements, which accounted for an additional$15.4 million decrease. Transportation volumes on our Acadian Gas System decreased 144 BBtus/d year-to-year. Gross operating margin from our Texas Intrastate System decreased$36.8 million year-to-year primarily due to lower capacity reservation revenues. Transportation volumes on our Texas Intrastate System decreased 171 BBtus/d year-to-year. Gross operating margin from ourHaynesville Gathering System decreased$19.9 million year-to-year primarily due to lower gathering volumes of 211 BBtus/d, which accounted for a$14.4 million decrease, and lower average gathering fees, which accounted for an additional$4.9 million decrease. On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System, and San Juan Gathering System in theRocky Mountains decreased a net$17.2 million year-to-year primarily due to lower volumes of 492 BBtus/d, which accounted for a$44.9 million decrease, partially offset by higher average fees, which accounted for a$22.5 million increase. Gross operating margin from our natural gas marketing activities decreased$51.1 million year-to-year primarily due to lower average sales margins (including the impact of hedging activities), which accounted for a$37.0 million decrease, and lower sales volumes, which accounted for an additional$14.1 million decrease.
Gross operating margin from our Permian Basin Gathering System increased
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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 years indicated (dollars in millions, volumes as noted):
For the Year Ended
December 31,
2020 2019Segment gross operating margin:
Propylene production and related activities $
471.0
Butane isomerization and related operations
67.6 79.9
Octane enhancement and related plant operations
161.7 166.0
Refined products pipelines and related activities
318.6 330.8
Ethylene exports and other services 62.9 47.8 Total$ 1,081.8 $ 1,069.6 Selected volumetric data: Propylene production volumes (MBPD) 89 97 Butane isomerization volumes (MBPD) 96 109 Standalone DIB processing volumes (MBPD) 127 99 Octane enhancement and related plant sales volumes (MBPD) (1) 35 32
Pipeline transportation volumes, primarily refined products and
petrochemicals (MBPD) 802 739
Marine terminal volumes, primarily refined products and
petrochemicals (MBPD) 262 325
(1) Reflects aggregate sales volumes for our octane additive and iBDH facilities
located at our
to the Houston Ship Channel.
Propylene production and related activities Gross operating margin from propylene production and related activities for the year endedDecember 31, 2020 increased$25.9 million when compared to the year endedDecember 31, 2019 . Gross operating margin from our propylene production facilities increased a combined$14.1 million year-to-year primarily due to lower operating costs, which accounted for an$18.9 million increase, and higher exchange and storage fee revenues, which accounted for an additional$15.6 million increase, partially offset by lower propylene and associated by-product sales volumes, which accounted for a$23.6 million decrease. Propylene production volumes at these facilities decreased a combined 6 MBPD year-to-year (net to our interest). As refiners reduced their utilization rates in response to lower demand for refined products caused by the COVID-19 pandemic, there was a decrease in the availability of refinery grade propylene feedstock used by our facilities to create polymer grade propylene. As a result, our propylene production volumes were reduced, with the largest impacts occurring in the second quarter of 2020.
Gross operating margin from our propylene export terminals increased
Isomerization and related operations Gross operating margin from isomerization and related operations decreased a net$12.3 million year-to-year primarily due to lower average by-product sales prices, which accounted for a$21.9 million decrease, and lower isomerization volumes of 13 MBPD, which accounted for an additional$9.5 million decrease, partially offset by lower operating costs, which accounted for a$19.7 million increase. Octane enhancement and related plant operations Gross operating margin from our octane enhancement and related plant operations decreased a net$4.3 million year-to-year primarily due to lower average sales margins, which accounted for a$23.4 million decrease, and higher operating costs, which accounted for an additional$13.5 million decrease, partially offset by higher sales volumes, which accounted for a$27.6 million increase. 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 inDecember 2019 . 82
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Refined products pipelines and related activities Gross operating margin from refined products pipelines and related activities for the year endedDecember 31, 2020 decreased$12.2 million when compared to the year endedDecember 31, 2019 . Gross operating margin from our TE Products Pipeline System and associated terminals decreased a combined$37.3 million year-to-year primarily due to lower interstate refined products transportation volumes, which accounted for a$12.5 million decrease, and lower NGL transportation volumes, which accounted for a$12.0 million decrease, higher operating costs, which accounted for a$3.8 million decrease, and lower average intrastate refined products transportation fees, which accounted for an additional$2.7 million decrease. Overall transportation volumes on our TE Products Pipeline System increased a net 34 MBPD year-to-year.
Gross operating margin from our refined products terminal in
Gross operating margin from our refined products marketing activities increased
Ethylene exports and other services Gross operating margin from ethylene exports and other services for the year endedDecember 31, 2020 increased$15.1 million when compared to the year endedDecember 31, 2019 . Gross operating margin from our ethylene export terminal and its related operations was a combined$25.6 million for 2020. Our ethylene export terminal and associated infrastructure were placed into limited service inDecember 2019 and full service inDecember 2020 . Loading volumes at our ethylene export terminal for 2020 were 10 MBPD (net to our interest).
Gross operating margin from marine transportation services decreased
Liquidity and Capital Resources
Based on current market conditions (as of the filing date of this annual 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. AtDecember 31, 2020 , we had$6.06 billion of consolidated liquidity, which was comprised of$5.0 billion of available borrowing capacity under EPO's revolving credit facilities and$1.06 billion of unrestricted cash on hand.
We may issue debt and equity securities to assist us in meeting our future
funding and liquidity requirements, including those related to capital
investments. We have a universal shelf registration statement (the "2019
Shelf") on file with the
Enterprise Declares Cash Distribution for Fourth Quarter of 2020
OnJanuary 7, 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 fourth quarter of 2020. The quarterly distribution was paid onFebruary 11, 2021 to unitholders of record as of the close of business onJanuary 29, 2021 . The total amount paid was$988.8 million , which includes$7.1 million for distribution equivalent rights on phantom unit awards. 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. 83
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Table of Contents Consolidated Debt
At
Total 2021 2022 2023 2024 2025 Thereafter
Principal
amount of
senior and
junior debt
obligations $ 30,146.4 $ 1,325.0 $ 1,400.0 $ 1,250.0 $
850.0
InJanuary 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 dueJanuary 2030 ("Senior Notes AAA"), (ii)$1.0 billion principal amount of 3.70% fixed-rate senior notes dueJanuary 2051 ("Senior Notes BBB") and (iii)$1.0 billion principal amount of 3.95% fixed-rate senior notes dueJanuary 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 inJanuary 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 inSeptember 2020 . InAugust 2020 , EPO issued$1.0 billion principal amount of 3.20% fixed-rate senior notes dueFebruary 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 were used for general company purposes, including for growth capital investments, and to repay a portion of the$750.0 million in principal amount of Senior Notes TT that matured inFebruary 2021 . InSeptember 2020 , EPO entered into a new 364-Day Revolving Credit Agreement that replaced itsSeptember 2019 364-Day Revolving Credit Agreement. The new 364-Day Revolving Credit Agreement matures inSeptember 2021 . There was no principal amount outstanding under theSeptember 2019 364-Day Revolving Credit Agreement when it expired and was replaced by theSeptember 2020 364-Day Revolving Credit Agreement. InFebruary 2021 , EPO notified its trustee and paying agent to redeem all of the$575.0 million outstanding principal amount of its Senior Notes RR effective as ofMarch 15, 2021 (one month prior to their scheduled maturity inApril 2021 ). These notes are redeemable at EPO's election 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). On a short term basis, the redemption of EPO's Senior Notes RR is expected to be made using proceeds from the issuance of short term notes under EPO's commercial paper program. For additional information regarding our consolidated debt obligations, see Note 7 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. Credit Ratings As ofMarch 1, 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. 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. 84
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Common Unit Repurchases Under 2019 Buyback Program
InJanuary 2019 , we announced that the Board had approved a$2.0 billion multi-year unit buyback program (the "2019 Buyback Program"), which provides us with an additional method to return capital to investors. The 2019 Buyback Program authorizes the Partnership to repurchase its common units from time to time, including through open market purchases and negotiated transactions. The timing and pace of buy backs under the program will be determined by a number of factors including (i) our financial performance and flexibility, (ii) organic growth and acquisition opportunities with higher potential returns on investment, (iii) the market price of the Partnership's common units and implied cash flow yield and (iv) maintaining targeted financial leverage, which is currently a debt-to-normalized adjusted EBITDA (earnings before interest, taxes, depreciation and amortization) ratio in the range of 3.25 to 3.75 times. No time limit has been set for completion of the 2019 Buyback Program, and it may be suspended or discontinued at any time. We repurchased an aggregate 8,978,317 common units under the 2019 Buyback Program through open market and private purchases during the year endedDecember 31, 2020 . The total purchase price of these repurchases was$186.3 million including commissions and fees. Units repurchased under the 2019 Buyback Program are immediately cancelled upon acquisition. As ofDecember 31, 2020 , the remaining available capacity under the 2019 Buyback Program was$1.73 billion . In addition to the 2019 Buyback Program, privately held affiliates of EPCO acquired 1,459,000 of our common units on the open market during the year endedDecember 31, 2020 . In the aggregate, 10,437,317 common units were purchased on the open market during the year endedDecember 31, 2020 under the 2019 Buyback Program and by privately held affiliates of EPCO.
Issuance of Common Units due to Settlement of Liquidity Option in
OnMarch 5, 2020 , we settled our obligations under the Liquidity Option Agreement by issuing 54,807,352 new common units toSkyline 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 us to OTA inOctober 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 Consolidated Financial Statements included under Part II, Item 8 of this annual report.
OnSeptember 30, 2020 , we 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 our 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. Offering expenses were approximately$1.0 million . Concurrently, we exchanged all of the 54,807,352 Partnership common units owned directly by OTA for 855,915 of our 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 us 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 inMarch 2020 in connection with settlement of the Liquidity Option.
For additional information regarding the preferred units, see Note 8 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
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Cash Flow Statement Highlights
The following table summarizes our consolidated cash flows from operating,
investing and financing activities for the years indicated (dollars in
millions).
For the Year Ended
December 31,
2020 2019
Net cash flows provided by operating activities
3,120.7 4,575.5
Cash used in financing activities 2,022.7 1,945.1
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 this annual
report.
For additional information regarding our cash flow amounts, please refer to the
Statements of Consolidated Cash Flows included under Part II, Item 8 of this
annual report.
The following information highlights significant year-to-year fluctuations in our consolidated cash flow amounts:
Operating activities Net cash flows provided by operating activities for the year endedDecember 31, 2020 decreased$629.0 million when compared to the year endedDecember 31, 2019 primarily due to:
• a
working capital employed in our marketing activities, which accounted for a
payments related to operations;
• a
earnings in 2020 when compared to 2019 (determined by adjusting our
million year-to-year decrease in net income for changes in the non-cash items
identified on our Statements of Consolidated Cash Flows); and
• a
earnings from unconsolidated affiliates, with those unconsolidated affiliates
owning crude oil pipelines and terminals accounting for substantially all of
the decrease. For information regarding significant year-to-year changes in our consolidated net income and underlying segment results, see "Income Statement Highlights" and "Business Segment Highlights" within this Part II, Item 7. Investing activities Cash used in investing activities for the year endedDecember 31, 2020 decreased$1.45 billion when compared to the year endedDecember 31, 2019 primarily due to:
• a
equipment (see "Capital Investments" within this Part II, Item 7 for additional
information);
• a
the return of capital from unconsolidated affiliates, with those unconsolidated
affiliates owning crude oil pipelines and terminals accounting for a majority
of the increase; and
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• a
affiliates primarily due to lower cash outlays for NGL and crude oil pipeline
projects. Financing activities Cash used in financing activities for the year endedDecember 31, 2020 increased a net$77.6 million when compared to the year endedDecember 31, 2019 primarily due to:
• a
noncontrolling interests. In
acquired a noncontrolling 33% equity interest in our consolidated subsidiary
that owns the Shin Oak NGL Pipeline for
contributions from noncontrolling interests in connection with our
natural gas processing plant and ethylene export facility decreased a combined
• a
under our 2019 Buyback Program;
• an
of common units under our distribution reinvestment plan ("DRIP") and employee
unit purchase plan ("EUPP"). In
beginning with the quarterly distribution payment paid in
use common units purchased on the open market, rather than issuing new common
units, to satisfy its delivery obligations under the DRIP and EUPP; and
• a
unitholders attributable to increases in the quarterly cash distribution rate
per unit; partially offset by
• a net
2020, we issued
partially offset by the repayment of
notes. In 2019, we issued
notes, partially offset by the repayment or repurchase of
principal amount of senior and junior subordinated notes. In addition, net
repayments of short term notes under EPO's commercial paper program were
million in 2020 compared to net issuances of
• a$31.5 million increase in net cash proceeds from the issuance of preferred units inSeptember 2020 . 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. 87
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Based on the level of available cash each quarter, management proposes a quarterly cash distribution rate to theBoard 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 II, Item 7. The following table summarizes our calculation of DCF for the years indicated (dollars in millions): For the Year EndedDecember 31, 2020 2019
Net income attributable to common unitholders (GAAP) (1)
derive DCF (addition or subtraction indicated by sign): Depreciation, amortization and accretion expenses
2,071.9 1,949.3
Cash distributions received from unconsolidated affiliates (2)
614.1 631.3
Equity in income of unconsolidated affiliates (426.1 ) (563.0 ) Asset impairment and related charges 890.6
132.8
Change in fair market value of derivative instruments (79.3 )
27.2
Change in fair value of Liquidity Option 2.3
119.6
Deferred income tax expense (benefit) (147.6 )
20.0
Sustaining capital expenditures (3) (293.6 ) (325.2 ) Other, net 20.2 20.0 Operational DCF (4)$ 6,427.2 $ 6,603.3 Proceeds from asset sales 12.8 20.6 Monetization of interest rate derivative instruments accounted for as cash flow hedges (33.3 ) - DCF (non-GAAP)$ 6,406.7 $ 6,623.9
Cash distributions paid to common unitholders with respect to period,
including distribution equivalent rights on phantom unit awards
$ 3,926.9
Cash distribution per common unit declared by Enterprise GP with respect to period (5)
$ 1.7850
Total DCF retained by the Partnership with respect to period (6)
$ 2,479.8
Distribution coverage ratio (7) 1.63 x
1.70 x
(1) For a discussion of the primary drivers of changes in our comparative income
statement amounts, see "Income Statement Highlights" within this Part II,
Item 7. (2) Reflects distributions received from unconsolidated affiliates attributable
to earnings and the return of capital.
(3) Sustaining capital expenditures include cash payments and accruals
applicable to the period.
(4) Represents DCF before proceeds from asset sales and the monetization of
interest rate derivative instruments accounted for as cash flow hedges. (5) See Note 8 of the Notes to Consolidated Financial Statements included under
Part II, Item 8 of this annual report for information regarding our
quarterly cash distributions declared with respect to the years indicated. (6) At the sole discretion of Enterprise GP, cash retained by the partnership
with respect to each of these periods was primarily reinvested in growth
capital projects. This retainage of cash substantially reduced our reliance
on the equity capital markets to fund such expenditures. (7) Distribution coverage ratio is determined by dividing DCF by total cash
distributions paid to common unitholders and in connection with distribution
equivalent rights with respect to the period.
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The following table presents a reconciliation of net cash flows provided by operating activities to DCF for the years indicated (dollars in millions):
For the Year Ended
December 31,
2020 2019
Net cash flows provided by operating activities (GAAP)
DCF (addition or subtraction indicated by sign): Net effect of changes in operating accounts 767.5 457.4 Sustaining capital expenditures (293.6 ) (325.2 )
Distributions received from unconsolidated affiliates attributable
to the return of capital 187.5 63.3
Proceeds from asset sales 12.8 20.6
Net income attributable to noncontrolling interest (110.1 ) (95.8 )
Monetization of interest rate derivative instruments
accounted
for as cash flow hedges (33.3 ) -
Other, net (15.6 ) (16.9 )
DCF (non-GAAP) $ 6,406.7 $ 6,623.9
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.
The following table summarizes our calculation of FCF for the years indicated
(dollars in millions):
For the Year Ended
December 31,
2020 2019
Net cash flows provided by operating activities (GAAP) $ 5,891.5 $ 6,520.5
Adjustments to net cash flows provided by operating activities to
derive FCF (addition or subtraction indicated by sign):
Cash used in investing activities
(3,120.7 ) (4,575.5 )
Cash contributions from noncontrolling interests
30.9 632.8
Cash distributions paid to noncontrolling interests (131.3 ) (106.2 ) FCF (non-GAAP)$ 2,670.4 $ 2,471.6 The elements used in calculating FCF are sourced directly from our statements of consolidated cash flows presented under Part II, Item 8 of this annual report. For a discussion of significant year-to-year changes in our cash flow statement amounts, see "Cash Flow Statement Highlights" within this Part II, Item 7. 89
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Capital Investments
The following table summarizes our capital investments for the years indicated
(dollars in millions):
For the Years Ended
December 31,
2020 2019Capital investments for property, plant and equipment: (1) Growth capital projects (2)
$ 2,985.8 $ 4,208.1 Sustaining capital projects (3) 302.1
323.6
Total$ 3,287.9
Investments in unconsolidated affiliates$ 15.6
(1) Growth and sustaining capital amounts presented in the table above are
presented on a cash basis. In total, these amounts represent "Capital
expenditures" as presented on our Statements of Consolidated Cash Flows. (2) Growth capital projects either (a) result in new sources of cash flow due to
enhancements of or additions to existing assets (e.g., additional revenue
streams, cost savings resulting from debottlenecking of a facility, etc.) or
(b) expand our asset base through construction of new facilities that will
generate additional revenue streams and cash flows. (3) Sustaining capital expenditures are capital expenditures (as defined by GAAP)
resulting from improvements to existing assets. Such expenditures serve to
maintain existing operations but do not generate additional revenues or
result in significant cost savings.
We placed a number of growth capital projects into commercial service during 2020 including:
• Frac X and Frac XI in
• expansion projects on the Texas Express Pipeline and
• the
and
• refrigerated storage at our ethylene export terminal in
We currently have$3.6 billion of growth capital projects scheduled to be completed by the end of 2023, which includes completion of a natural gasoline hydrotreater facility at ourMont Belvieu -area 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. Capital investing activity throughout the domestic energy industry has been significantly reduced in response to the supply and demand disruptions caused by the COVID-19 pandemic. In light of these adverse macroeconomic conditions, we discussed with our customers and reevaluated our planned capital investments in order to modify the capacity, timing and need for certain capital projects and to maximize available liquidity. Based on information currently available, we expect our total capital investments for 2021, net of contributions from joint venture partners, to approximate$2.1 billion , which reflects growth capital investments of$1.6 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. We currently anticipate receiving approval for SPOT as early as the third quarter of 2021; however, we can give no assurance as to whether the project will ultimately be approved or the timing of such decision. Our forecast of capital investments for 2021 through 2023 is based on announced strategic operating and growth plans (through the filing date of this quarterly report), which are dependent upon our ability to generate the required funds from either operating cash flows or other means, including borrowings under debt agreements, the issuance of additional equity and debt securities, and potential divestitures. 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. 90
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Comparison of Year Ended
In total, investments in growth capital projects decreased
• completion of projects at our
(
• lower investments in natural gas processing facilities and related
infrastructure that support
2019 and placed our
• completion of the Shin Oak NGL Pipeline (in stages through the fourth quarter
of 2019), which accounted for a
• lower investments in projects attributable to our ethylene business, which
accounted for a
• higher investments in our PDH 2 facility, which accounted for a
increase;
• higher investments in crude oil pipelines, including those expanding our
production, which accounted for a combined
• higher investments in natural gas pipelines and related infrastructure in
support of
million increase. Investments in unconsolidated affiliates decreased$96.0 million year-to-year primarily due to lower spending on NGL pipeline expansion projects, which accounted for a$49.4 million decrease, and lower spending on our joint venture dock infrastructure atCorpus Christi and other crude oil-related projects, which accounted for an additional$44.2 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
In our financial reporting processes, we employ methods, estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of our financial statements. These methods, estimates and assumptions also affect the reported amounts of revenues and expenses for each reporting period. Investors should be aware that actual results could differ from these estimates if the underlying assumptions prove to be incorrect. The following sections discuss the use of estimates within our critical accounting policies:
Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment
In general, depreciation is the systematic and rational allocation of an asset's
cost, less its residual value (if any), to the periods it benefits. The
majority of our property, plant and equipment is depreciated using the
straight-line method, which results in depreciation expense being incurred
evenly over the life of an asset. Depreciation expense incorporates management
estimates regarding the useful economic lives and residual values of our
assets. At the time we place our assets into service, we believe such
assumptions are reasonable; however, circumstances may develop that cause us to
change these assumptions, which would change our depreciation amounts
prospectively. Examples of such circumstances include (i) changes in laws and
regulations that limit the estimated economic life of an asset, (ii) changes in
technology that render an asset obsolete, (iii) changes in expected salvage
values or (iv) significant changes in our forecast of the remaining life for the
associated resource basins, if applicable.
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AtDecember 31, 2020 and 2019, the net carrying value of our property, plant and equipment was$41.91 billion and$41.6 billion , respectively. We recorded$1.68 billion and$1.56 billion of depreciation expense during the years endedDecember 31, 2020 and 2019, respectively. For information regarding our property, plant and equipment, see Note 4 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
Measuring Recoverability of Long-Lived Assets and Fair Value of Equity Method Investments
Long-lived assets, which consist of intangible assets with finite useful lives and property, plant and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable through future cash flows. Examples of such events or changes might be production declines that are not replaced by new discoveries or long-term decreases in the demand for or price of natural gas, NGLs, crude oil, petrochemicals or refined products. The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted estimated cash flows expected to result from the use and eventual disposition of the asset. Estimates of undiscounted cash flows are based on a number of assumptions including anticipated operating margins and volumes; estimated useful life of the asset or asset group; and estimated residual values. If the carrying value of a long-lived asset is not recoverable, an impairment charge would be recorded for the excess of the asset's carrying value over its estimated fair value, which is derived from an analysis of the asset's estimated future cash flows, the market value of similar assets and replacement cost of the asset less any applicable depreciation or amortization. In addition, fair value estimates also include the usage of probabilities when there is a range of possible outcomes. We evaluate our equity method investments for impairment when there are events or changes in circumstances that indicate there is a potential loss in value of the investment attributable to an other than temporary decline. Examples of such events or changes in circumstances include continuing operating losses of the entity and/or long-term negative changes in the entity's industry. In the event we determine that the value of an investment is not recoverable due to an other than temporary decline, we record a non-cash impairment charge to adjust the carrying value of the investment to its estimated fair value. We assess the fair value of our equity method investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party sales and discounted estimated cash flow models. Estimates of discounted cash flows are based on a number of assumptions including discount rates; probabilities assigned to different cash flow scenarios; anticipated margins and volumes and estimated useful lives of the investment's underlying assets. A significant change in the assumptions we use to measure recoverability of long-lived assets and the fair value of equity method investments could result in our recording a non-cash impairment charge. Any write-down of the carrying values of such assets would increase operating costs and expenses at that time. In 2020 and 2019, we recognized non-cash asset impairment charges attributable to assets other than goodwill totaling$594.3 million and$132.8 million , respectively, which are a component of operating costs and expenses. For information regarding impairment charges involving property, plant and equipment and investments in unconsolidated affiliates, see Notes 4 and 5, respectively, of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
Valuation and Amortization Methods of Customer Relationships and Contract-Based Intangible Assets
The specific, identifiable intangible assets of an acquired business depend
largely upon the nature of its operations and include items such as customer
relationships and contracts. The method used to value such assets depends on a
number of factors, including the nature of the asset and the economic returns
the asset is expected to generate.
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Customer relationship intangible assets represent the estimated economic value assigned to commercial relationships acquired in connection with business combinations. In certain instances, the acquisition of these intangible assets provides us with access to customers in a defined resource basin and is analogous to having a franchise in a particular area. Efficient operation of the acquired assets (e.g., a natural gas gathering system) helps to support the commercial relationships with existing producers and provides us with opportunities to establish new ones within our existing asset footprint. The duration of this type of customer relationship is limited by the estimated economic life of the associated resource basin that supports the customer group. When estimating the economic life of a resource basin, we consider a number of factors, including reserve estimates and the economic viability of production and exploration activities. In other situations, the acquisition of a customer relationship intangible asset provides us with access to customers whose hydrocarbon volumes are not attributable to specific resource basins. As with basin-specific customer relationships, efficient operation of the associated assets (e.g., a marine terminal that handles volumes originating from multiple sources) helps to support the commercial relationships with existing customers and provides us with opportunities to establish new ones. The duration of this type of customer relationship is typically limited to the term of the underlying service contracts, including assumed renewals. The value we assign to customer relationships is amortized to earnings using methods that closely resemble the pattern in which the estimated economic benefits will be consumed (i.e., the manner in which the intangible asset is expected to contribute directly or indirectly to our cash flows). For example, the amortization period for a basin-specific customer relationship asset is limited by the estimated finite economic life of the associated hydrocarbon resource basin. Contract-based intangible assets represent specific commercial rights we own arising from discrete contractual agreements. A contract-based intangible asset with a finite life is amortized over its estimated economic life, which is the period over which the contract is expected to contribute directly or indirectly to our cash flows. Our estimates of the economic life of contract-based intangible assets are based on a number of factors, including (i) the expected useful life of the related tangible assets (e.g., a marine terminal, pipeline or other asset), (ii) any legal or regulatory developments that would impact such contractual rights and (iii) any contractual provisions that enable us to renew or extend such arrangements. If our assumptions regarding the estimated economic life of an intangible asset were to change, then the amortization period for such asset would be adjusted accordingly. Changes in the estimated useful life of an intangible asset would impact operating costs and expenses prospectively from the date of change. If we determine that an intangible asset's carrying value is not recoverable through its future cash flows, we would be required to reduce the asset's carrying value to its estimated fair value through the recording of a non-cash impairment charge. Any such write-down of the value of an intangible asset would increase operating costs and expenses at that time. AtDecember 31, 2020 and 2019, the carrying value of our customer relationship and contract-based intangible asset portfolio was$3.31 billion and$3.45 billion , respectively. We recorded$143.2 million and$174.7 million of amortization expense attributable to intangible assets during the years endedDecember 31, 2020 and 2019, respectively. For information regarding our intangible assets, see Note 6 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
Methods We Employ to Measure the Fair Value of
Our goodwill balance was$5.45 billion and$5.75 billion atDecember 31, 2020 and 2019, respectively.Goodwill , which represents the cost of an acquired business in excess of the fair value of its net assets at the acquisition date, is subject to annual impairment testing in the fourth quarter of each year or when events or changes in circumstances indicate that the carrying amount of the goodwill may not be recoverable.Goodwill impairment charges represent the amount by which a reporting unit's carrying value (including its respective goodwill) exceeds its fair value, not to exceed the carrying amount of the reporting unit's goodwill. 93
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We determine the fair value of each reporting unit using accepted valuation techniques, primarily through the use of discounted cash flows (i.e., an income approach to fair value) supplemented by market-based assessments, if available. The estimated fair values of our reporting units incorporate assumptions regarding the future economic prospects of the assets and operations that comprise each reporting unit including: (i) discrete financial forecasts for the assets comprising the reporting unit, which, in turn, rely on management's estimates of long-term operating margins, throughput volumes, capital investments and similar factors; (ii) long-term growth rates for the reporting unit's cash flows beyond the discrete forecast period; and (iii) appropriate discount rates. The fair value estimates are based on Level 3 inputs of the fair value hierarchy. We believe that the assumptions we use in estimating reporting unit fair values are consistent with those that market participants would use in their fair value estimation process. However, due to uncertainties in the estimation process and volatility in the supply and demand for hydrocarbons and similar risk factors, actual results could differ significantly from our estimates. InDecember 2020 , management determined that the carrying value of our natural gas pipelines and services reporting unit exceeded its estimated fair value. This reporting unit, which reflects the operations of our Natural Gas Pipelines & Services business segment, includes our natural gas gathering and transmission pipelines, storage facilities and related marketing activities. The long-term outlook for natural gas production in certain supply basins such as theRocky Mountains andEast Texas is expected to remain lower for longer due to reduced drilling activity. In addition, the decline in pipeline revenues attributable to lower regional natural gas price spreads is expected to adversely impact the future cash flows of our transmission pipelines. These factors, coupled with an increase in the estimated rate of return required for such businesses by market participants, resulted in the fair value of this reporting unit being less than its carrying value atDecember 31, 2020 . The resulting goodwill impairment charge of$296.3 million represents the entire amount of goodwill attributable to this reporting unit. We did not record any goodwill impairment charges during the year endedDecember 31, 2019 . Based on our most recent goodwill impairment test atDecember 31, 2020 , the estimated fair value of each of our reporting units, with the exception of our natural gas pipelines and services reporting unit, was at least 10% in excess of its carrying value.
For information regarding our goodwill, see Note 6 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
Use of Estimates for Revenues and Expenses
As noted previously, preparing our consolidated financial statements in
conformity with GAAP requires us to make estimates that affect amounts presented
in the financial statements. Due to the time required to compile actual billing
information and receive third party data needed to record transactions, we
routinely employ estimates in connection with revenue and expense amounts in
order to meet our accelerated financial reporting deadlines.
Our most significant routine estimates involve revenues and costs of certain
natural gas processing facilities, pipeline transportation revenues,
fractionation revenues, marketing revenues and related purchases, and power and
utility costs. These types of transactions must be estimated since the actual
amounts are generally unavailable at the time we complete our accounting close
process. The estimates subsequently reverse in the next accounting period when
the corresponding actual customer billing or vendor-invoiced amounts are
recorded.
Changes in facts and circumstances may result in revised estimates, which could
affect our reported financial statements and accompanying disclosures. Prior to
issuing our financial statements, we review our revenue and expense estimates
based on currently available information to determine if adjustments are
required. Investors should be aware that actual results could differ from these
estimates if the underlying assumptions prove to be incorrect.
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Parent-Subsidiary Guarantor Relationship
The Partnership (the "Parent Guarantor") has guaranteed the payment of principal and interest on the consolidated debt obligations of EPO (the "Subsidiary Issuer"), with the exception of the remaining debt obligations ofTEPPCO Partners, L.P. (collectively, the "Guaranteed Debt"). If EPO were to default on any of its Guaranteed Debt, the Partnership would be responsible for full and unconditional repayment of such obligations. AtDecember 31, 2020 , the total amount of Guaranteed Debt was$30.59 billion , which was comprised of$27.5 billion of EPO's senior notes,$2.63 billion of EPO's junior subordinated notes and$455.6 million of related accrued interest. The Partnership's guarantees of EPO's senior note obligations, commercial paper notes and borrowings under bank credit facilities represent unsecured and unsubordinated obligations of the Partnership that rank equal in right of payment to all other existing or future unsecured and unsubordinated indebtedness of the Partnership. In addition, these guarantees effectively rank junior in right of payment to any existing or future indebtedness of the Partnership that is secured and unsubordinated, to the extent of the assets securing such indebtedness. The Partnership's guarantees of EPO's junior subordinated notes represent unsecured and subordinated obligations of the Partnership that rank equal in right of payment to all other existing or future subordinated indebtedness of the Partnership and senior in right of payment to all existing or future equity securities of the Partnership. The Partnership's guarantees of EPO's junior subordinated notes effectively rank junior in right of payment to (i) any existing or future indebtedness of the Partnership that is secured, to the extent of the assets securing such indebtedness and (ii) all other existing or future unsecured and unsubordinated indebtedness of the Partnership.
The Partnership may be released from its guarantee obligations only in connection with EPO's exercise of its legal or covenant defeasance options as described in the underlying agreements.
Selected Financial Information ofObligor Group The following tables present summarized financial information of the Partnership (as Parent Guarantor) and EPO (as Subsidiary Issuer) on a combined basis (collectively, the "Obligor Group "), after the elimination of intercompany balances and transactions among theObligor Group . In accordance with Rule 13.01 of Regulation S-X, the summarized financial information of theObligor Group excludes theObligor 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 theObligor Group's investments in the Non-Obligor Subsidiaries was$45.98 billion atDecember 31, 2020 .The Obligor Group's equity in the earnings of the Non-Obligor Subsidiaries for the year endedDecember 31, 2020 was$3.54 billion . Although the net assets and earnings of the Non-Obligor Subsidiaries are not directly available to the holders of the Guaranteed Debt to satisfy the repayment of such obligations, there are no significant restrictions on the ability of the Non-Obligor Subsidiaries to pay distributions or make loans to EPO or the Partnership. EPO exercises control over the Non-Obligor Subsidiaries. We continue to believe that the consolidated financial statements of the Partnership presented under Item 8 of this annual 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 theObligor Group financial information presented below. 95
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The following table presents summarized balance sheet information for the
combined
Selected asset information:
Current receivables from Non-Obligor Subsidiaries $
775.4
Other current assets
5,805.7
Long-term receivables from Non-Obligor Subsidiaries
187.3
Other noncurrent assets, excluding investments in Non-Obligor
Subsidiaries of
8,198.5
Selected liability information:
Current portion of Guaranteed Debt, including interest of
$ 1,780.6
Current payables to Non-Obligor Subsidiaries
1,129.0
Other current liabilities
3,858.6
Noncurrent portion of Guaranteed Debt, principal only
28,806.8
Noncurrent payables to Non-Obligor Subsidiaries 27.0 Other noncurrent liabilities 42.9
Mezzanine equity of
Preferred units$ 49.3
The following table presents summarized income statement information for the
combined
Revenues from Non-Obligor Subsidiaries $
2,602.4
Revenues from other sources
15,361.4
Operating income ofObligor Group
1,069.7
Net loss of
(157.0 ) Contractual Obligations
The following table summarizes our significant contractual obligations at
Payment or Settlement due by Period
In less than In 1-3 In 4-5 More than
Contractual Obligations Total 1 year years years 5 years
Scheduled maturities of debt
obligations (1) $ 30,146.4 $ 1,325.0 $ 2,650.0 $ 2,000.0 $ 24,171.4
Estimated cash payments for
interest (2) 28,834.6 1,294.0 2,442.2 2,284.2 22,814.2
Operating lease obligations (3) 460.5 33.7 69.3 58.7 298.8
Purchase obligations:
Product purchase commitments
(4) 14,800.7 2,266.6 4,230.6 3,501.4 4,802.1
Service payment commitments
(4,5) 278.8 62.0 102.0 29.0 85.8
Other long-term liabilities (6) 365.8 - 85.8 50.8 229.2
Total contractual payment
obligations $ 74,886.8 $ 4,981.3 $ 9,579.9 $ 7,924.1 $ 52,401.5 (1) Represents scheduled future maturities of our current and long-term debt
principal obligations. For information regarding our consolidated debt
obligations, see Note 7 of the Notes to Consolidated Financial Statements
included under Part II, Item 8 of this annual report. (2) Estimated cash payments for interest are based on the principal amount of
our consolidated debt obligations outstanding at
contractually scheduled maturities of such balances, and the applicable
interest rates. Our estimated cash payments for interest are influenced by
the long-term maturities of our
(due
that (i) the junior subordinated notes are not repaid prior to their
respective maturity dates and (ii) the amount of interest paid on the junior
subordinated notes is based on either (a) the current fixed interest rate
charged or (b) the weighted-average variable rate paid in 2020, as
applicable, for each note through the respective maturity date. (3) Primarily represents (i) land held pursuant to property leases, (ii) the
lease of underground storage caverns for natural gas and NGLs, (iii) the
lease of transportation equipment used in our operations and (iv) office
space leased from affiliates of EPCO. (4) Represents enforceable and legally binding agreements to purchase goods or
services as of
based on contractual prices in effect at
future volume commitments. Actual future payment obligations may vary
depending on prices at the time of delivery.
(5) Primarily represents our unconditional payment obligations under firm
pipeline transportation contracts. (6) Primarily represents the noncurrent portion of asset retirement obligations
and deferred revenues.
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We are obligated to spend up to an aggregate$270 million over a ten-year period ending in 2025 on specified midstream gathering assets for certain producers utilizing our EFS Midstream System. If constructed, these new assets would be owned by us and be a component of the EFS Midstream System. As ofDecember 31, 2020 , we have spent$151 million of the$270 million commitment. Due to the uncertain timing of the remaining potential capital expenditures, we have excluded this amount from the preceding table. For additional information regarding our significant contractual obligations, see Note 17 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
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 Consolidated Financial Statements included under Part II, Item 8 of this annual report as well as Part III, Item 13 of this annual report.
Insurance
For information regarding insurance matters, see Note 18 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
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