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, 2021 and 2020, 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, 2019 and year-to-year comparisons between the years endedDecember 31, 2020 and 2019 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, 2020 that was filed onMarch 1, 2021 .
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" or "Enterprise" 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 32.3% of the Partnership's common units outstanding atDecember 31, 2021 . InMarch 2021 , a privately held affiliate of EPCO sold its entire ownership interest in the Partnership's Series A Cumulative Convertible Preferred Units ("preferred units") to third parties.
As generally used in the energy industry and in this annual report, the acronyms below have the following meanings:
/d = per day MMBPD = million barrels per day
BBtus = billion British thermal units MMBtus = million British thermal units Bcf = billion cubic feet
MMcf = million cubic feet
BPD = barrels per day MWac = megawatts, alternating current
MBPD = thousand barrels per day MWdc = megawatts, direct current
MMBbls = million barrels TBtus = trillion British thermal units
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This annual report on Form 10-K for the year ended December 31, 2021 (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 segment 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.
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 Enterprise GP. In addition, it reflects 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. All references toU.S. Energy Information Administration ("EIA") forecasts and expectations are derived from itsFebruary 2022 Short-Term Energy Outlook ("February 2022 STEO"), which was published onFebruary 8, 2022 . The level of services we provide and the amount of volumes we purchase and sell are directly affected by changes in supply and demand for hydrocarbon products, which impacts our financial position, results of operations and cash flows. Beginning in the first quarter of 2020, supply and demand for hydrocarbon products were significantly reduced by the global effects of the COVID-19 pandemic and the consequences of containment measures including quarantines, travel restrictions, temporary business closures and similar protective actions. During late 2020 and early 2021, most countries began to gradually reduce mobility restrictions to less stringent methods of COVID-19 containment (e.g., vaccines, mask requirements and social distancing) allowing for the resumption of travel and business activities. These changes, coupled with strong fiscal and economic stimulus worldwide, helped bolster an economic recovery in most industrial economies. According to the EIA,U.S. gross domestic product increased 5.7% in 2021 compared to a decrease of 3.4% in 2020. This strong economic recovery has increased the demand for hydrocarbon products necessary to produce energy, transportation fuels and raw materials. Preliminary EIA estimates showed that the global consumption of petroleum and other liquid fuels grew by 5.2 MMBPD in 2021 while at the same time global liquid fuels inventories fell by an average of 1.6 MMBPD. Crude oil and other liquids production from a combination of members of theOrganization of Petroleum Exporting Countries ("OPEC") and non-OPEC members increased by only 1.7 MMBPD during this period. The growth in global crude oil consumption relative to production has led to a significant increase in crude oil prices as demonstrated by the average price of Brent crude oil, which increased from an average of$44 per barrel in the fourth quarter of 2020 to$79 per barrel in the fourth quarter of 2021. The EIA forecasts a reversal of this trend with a prediction that global crude oil and other liquids production will outpace consumption in 2022 and 2023, leading to a rise in global liquid fuels inventories. Their forecast shows global crude oil and other liquids consumption growing by a cumulative 5.4 MMBPD through 2023, while production is expected to grow by a cumulative 8.0 MMBPD through 2023. This is expected to cause a rise in global liquid fuels inventories by an average of 0.8 MMBPD in 2022 and 1.0 MMBPD in 2023, which is forecast to put downward pressure on crude oil prices. According to the EIA, Brent crude oil prices are forecasted to average$83 per barrel in 2022 before decreasing to$68 per barrel in 2023. 59
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We acknowledge some uncertainties exist with respect to the forecasted increases in liquid fuels consumption levels due to the potential for continued supply chain disruptions, labor shortages, inflationary pressures and the potential for additional restrictions associated with COVID-19 containment measures should more contagious variants emerge. However, we are optimistic that these risks remain outweighed by the strength in the global economy, a seemingly widespread fatigue from COVID-19 related mobility and activity restrictions and the desire by the entire global population to improve their living conditions through the use of hydrocarbons for energy and materials. We believe that these additional production and consumption trends, along with the associated increases in inventory levels, will create additional opportunities to provide midstream services to our customers while leveraging the strengths of our portfolio, which include:
• Our Assets - Our people find creative ways to optimize our large, integrated
and diversified asset base to provide incremental services to customers and to
respond to market opportunities. Additional production volumes could lead to
higher demand for processing, transportation, fractionation and terminaling
services. Storage services provide valuable flexibility for customers seeking
to balance supply and demand while also allowing us to capture valuable contango and other marketing opportunities should they arise.
• Our Customers - We have contracted with a large number of quality customers in
order to achieve revenue diversification. In 2021, our top 200 largest
customers represented 98.6% of consolidated revenues. Based on their
respective year-end 2021 debt ratings, 87.0% of revenues from our top 200
customers were either investment grade rated or backed by letters of credit.
Additionally, less than 3% of our top 200 customer revenues were attributable
to sub-investment grade or non-rated upstream producers.
• Our Liquidity - At
liquidity, which was comprised of
under EPO's revolving credit facilities and
on hand. Our liquidity is supported by investment grade credit ratings on
EPO's long-term senior unsecured debt of BBB+, Baa1 and BBB+ from Standard and
Poor's, Moody's and Fitch, respectively.
• Our Access to Capital Markets - EPO successfully issued
principal amount of senior notes in 2021. Based on current conditions, we
believe that we will have sufficient liquidity and/or access to debt capital
markets to fund our operations, capital investments and the remaining principal
amount of senior notes maturing through 2022.
Recent Developments
Enterprise Announces Acquisition of
InJanuary 2022 , we announced that an affiliate of Enterprise entered into a definitive agreement to acquireNavitas Midstream Partners, LLC ("Navitas Midstream") from an affiliate of Warburg Pincus LLC in a debt-free transaction for$3.25 billion in cash consideration.Navitas Midstream's assets include approximately 1,750 miles of pipelines and over 1.0 Bcf/d of cryogenic natural gas processing capacity. The purchase price was paid in cash at closing onFebruary 17, 2022 . We funded the cash consideration for this acquisition using proceeds from the issuance of short-term notes under our commercial paper program and cash on hand. 60
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Enterprise Completes Expansion of Acadian Natural Gas Pipeline System in
InDecember 2021 , we announced recently starting commercial service on our new Gillis Lateral pipeline and the associated expansion of our existing Acadian Haynesville Extension system to serve the growing liquefied natural gas ("LNG") market on theGulf Coast . The 83-mile Gillis Lateral pipeline originates nearAlexandria, Louisiana on our Acadian Haynesville Extension system and extends to third party pipeline interconnects near Gillis,Louisiana , including multiple pipelines serving regional LNG export facilities. The recently completed Gillis Lateral pipeline has the capability to transport approximately 1.0 Bcf/d of natural gas. To accommodate the additional volumes, we increased capacity on our Acadian Haynesville Extension pipeline from 1.8 Bcf/d to 2.1 Bcf/d by adding horsepower at ourMansfield Compressor Station located inMansfield, Louisiana . The Legacy Acadian and Haynesville Extension pipelines are part of the Acadian Gas System, which is comprised of approximately 1,300 miles of natural gas pipelines and leased underground storage. It links natural gas supplies inLouisiana and offshoreGulf of Mexico to distribution companies, electric utility plants and industrial customers located primarily in theBaton Rouge/New Orleans/Mississippi River corridor. Our 378-mile Haynesville Gathering System has a capacity of approximately 1.3 Bcf/d, can treat up to 810 MMcf/d of natural gas and provides a significant and reliable source of supply for theAcadian Gas System.
Enterprise and Chevron Explore
InSeptember 2021 , we andChevron U.S.A. Inc. ("Chevron") jointly announced a framework to study and evaluate opportunities forcarbon dioxide capture, utilization and storage from our respective business operations in theU.S. Midcontinent andGulf Coast . Projects resulting from this evaluation would seek to combine our extensive midstream pipeline and storage network withChevron's sub-surface expertise to create opportunities to capture, aggregate, transport and sequestercarbon dioxide in support of the evolving energy landscape. The initial phase of the study in which we will evaluate specific business opportunities is expected to last about six months.
Issuance of
InSeptember 2021 , EPO issued$1.0 billion principal amount of senior notes dueFebruary 2053 ("Senior Notes EEE"). Net proceeds from this offering were used for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of a portion of our$750.0 million in principal amount of 3.50% Senior Notes VV and a portion of our$650.0 million in principal amount of 4.05% Senior Notes CC, in each case at their maturity inFebruary 2022 ).
Senior Notes EEE were issued at 99.170% of their principal amount and have a fixed rate of interest of 3.30% per year. The Partnership guaranteed these senior notes through an unconditional guarantee on an unsecured and unsubordinated basis.
Enterprise and Magellan Team Up With Intercontinental Exchange for New Houston Crude Oil Futures Contract
InJune 2021 , we, Magellan Midstream Partners, L.P ("Magellan") and Intercontinental Exchange, Inc. ("ICE") announced the establishment of a new futures contract for the physical delivery of crude oil in theHouston, Texas area in response to market interest for aHouston -based index with greater scale, flow assurance and price transparency. OnJanuary 24, 2022 , theICE Midland WTI American Gulf Coast futures contract went live for trading with theMarch 2022 contract being the first contract month for deliveries. The quality specifications of the new futures contract are consistent with West Texas Intermediate ("WTI") originating from thePermian Basin with common delivery options at either our ECHO terminal inHouston or Magellan'sEast Houston terminal. In support of this new futures contract, we and Magellan have discontinued provisions for delivery services under legacy futures contracts that are deliverable at each terminal. 61
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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)
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 2021 by quarter: 1st Quarter$2.71 $0.24 $0.89 $0.94 $0.93 $1.33 $0.73 $0.44 $0.38 2nd Quarter$2.83 $0.26 $0.87 $0.97 $0.98 $1.46 $0.67 $0.27 $0.41 3rd Quarter$4.02 $0.35 $1.16 $1.34 $1.34 $1.62 $0.82 $0.36 $0.51 4th Quarter$5.84 $0.39 $1.24 $1.46 $1.46 $1.82 $0.66 $0.33 $0.41 2021 Averages$3.85 $0.31 $1.04 $1.18 $1.18 $1.56
(1) Natural gas prices are based on Henry-Hub Inside FERC commercial index prices
as reported by Platts, which is a division of S&P Global, Inc. (2) NGL prices for ethane, propane, normal butane, isobutane and natural gasoline
are based on
by
product as reported by IHS. Refinery grade propylene ("RGP") prices
represent weighted-average spot prices for such product as reported by IHS. (4) The "Indicative Gas Processing Gross Spread" represents our generic estimate
of the gross economic benefit from extracting NGLs from natural gas
production based on certain pricing assumptions. Specifically, it is the
amount by which the assumed economic value of a composite gallon of NGLs in
in 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 further influenced 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)
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
2021 by quarter:
1st Quarter $57.84 $59.00 $59.51 $59.99
2nd Quarter $66.07 $66.41 $66.90 $67.95
3rd Quarter $70.56 $70.74 $71.17 $71.51
4th Quarter $77.19 $77.82 $78.27 $78.41
2021 Averages $67.92 $68.49 $68.96 $69.47 (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. An increase in
our consolidated marketing revenues due to higher energy commodity sales prices
may not result in an increase in gross operating margin or cash available for
distribution, since our consolidated cost of sales amounts would also be
expected to increase due to comparable increases in the purchase prices of the
underlying energy commodities. The same type of relationship would be true in
the case of lower energy commodity sales prices and purchase costs.
We attempt to mitigate commodity price exposure through our hedging activities
and the use of fee-based arrangements. See Note 13 of the Notes to Consolidated
Financial Statements included under Part II, Item 8 of this annual report and
"Quantitative and Qualitative Disclosures About Market Risk" under Part II, Item
7A 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,
2021 2020
Revenues $ 40,806.9 $ 27,199.7
Costs and expenses:
Operating costs and expenses:
Cost of sales 29,887.0 16,723.2
Other operating costs and expenses 2,914.1 2,800.2
Depreciation, amortization and accretion expenses 2,037.5
1,961.5
Asset impairment charges 232.6
890.6
Net gains attributable to asset sales and related matters 6.1
(4.4 )
Total operating costs and expenses 35,077.3 22,371.1
General and administrative costs 209.3
219.6
Total costs and expenses 35,286.6
22,590.7
Equity in income of unconsolidated affiliates 583.4 426.1 Operating income 6,103.7 5,035.1 Other income (expense): Interest expense (1,283.0 ) (1,287.4 ) Other, net 4.6 13.7 Total other expense, net (1,278.4 ) (1,273.7 ) Income before income taxes 4,825.3 3,761.4 Benefit from (provision for) income taxes (70.0 )
124.3
Net income 4,755.3
3,885.7
Net income attributable to noncontrolling interests (117.6 ) (110.1 ) Net income attributable to preferred units (3.6 ) (0.9 ) Net income attributable to common unitholders$ 4,634.1 $ 3,774.7 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,
2021 2020
NGL Pipelines & Services:
Sales of NGLs and related products $ 13,716.5 $ 8,970.7
Midstream services 2,586.1 2,206.5
Total 16,302.6 11,177.2
Crude Oil Pipelines & Services:
Sales of crude oil 9,519.0 5,410.8
Midstream services 1,383.2 1,278.2
Total 10,902.2 6,689.0
Natural Gas Pipelines & Services:
Sales of natural gas 3,412.7 1,530.5
Midstream services 986.9 1,022.6
Total 4,399.6 2,553.1
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products 8,195.7 5,942.6
Midstream services 1,006.8 837.8
Total 9,202.5 6,780.4
Total consolidated revenues $ 40,806.9 $ 27,199.7
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Total revenues for 2021 increased$13.61 billion when compared to 2020 primarily due to a$12.99 billion increase in marketing revenues. Revenues from the marketing of NGLs, natural gas, petrochemicals and refined products increased a combined net$8.88 billion year-to-year primarily due to higher average sales prices, which accounted for an$11.4 billion increase, partially offset by lower sales volumes, which accounted for a$2.52 billion decrease. Revenues from the marketing of crude oil increased$4.11 billion year-to-year primarily due to higher average sales prices, which accounted for a$2.84 billion increase, and higher sales volumes, which accounted for an additional$1.27 billion increase. Revenues from midstream services for 2021 increased$617.9 million when compared to 2020. Revenues from our natural gas processing facilities increased$263.0 million year-to-year primarily due to higher average market values for the equity NGLs we receive as non-cash consideration for processing services. Revenues from our terminal facilities increased$190.0 million year-to-year primarily due to higher deficiency fee revenue. Revenues from our crude oil pipeline assets increased$124.5 million year-to-year primarily due to higher demand for crude oil transportation services. Lastly, revenues from our propylene production facilities increased$74.1 million year-to-year primarily due to higher propylene 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 2021 increased
Cost of Sales Cost of sales for 2021 increased$13.16 billion when compared to 2020. The cost of sales associated with our marketing of NGLs, natural gas, petrochemicals and refined products increased a combined net$8.55 billion year-to-year primarily due to higher average purchase prices, which accounted for a$10.65 billion increase, partially offset by lower sales volumes, which accounted for a$2.1 billion decrease. The cost of sales associated with our marketing of crude oil increased$4.61 billion year-to-year primarily due to higher average purchase prices, which accounted for a$3.45 billion increase, and higher sales volumes, which accounted for an additional$1.16 billion increase. Other operating costs and expenses Other operating costs and expenses for 2021 increased$113.9 million year-to-year primarily due to higher maintenance and employee compensation costs and ad valorem taxes. Depreciation, amortization and accretion expenses Depreciation, amortization and accretion expense increased$76.0 million year-to-year primarily due to assets placed into full or limited service since the first quarter of 2020 (e.g., Chambers County Frac X and XI, and theMidland -to-ECHO 3 pipeline) and major maintenance activities accounted for under the deferral method. We adopted the deferral method for our reaction-based plants inNovember 2020 . Under the deferral method, major maintenance costs are capitalized and amortized over the period until the next major overhaul project. Asset impairment charges Non-cash asset impairment charges decreased$658.0 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 2021 decreased
Equity in income of unconsolidated affiliates
Equity income from our unconsolidated affiliates for 2021 increased
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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,
2021 2020
Interest charged on debt principal outstanding $ 1,298.9
38.3 39.3
Interest costs capitalized in connection with construction projects (1) (79.6 ) (115.0 ) Other (2) 25.4 32.5 Total$ 1,283.0 $ 1,287.4
(1) 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.
(2) Primarily reflects facility commitment fees charged in connection with our
revolving credit facilities and amortization of debt issuance costs.
Interest charged on debt principal outstanding, which is a key driver of interest expense, decreased$31.7 million year-to-year primarily due to lower debt principal amounts outstanding during 2021, which accounted for a$25.3 million decrease, and the effects of lower overall interest rates during 2021, which accounted for an additional$6.4 million decrease. Our weighted-average debt principal balance for 2021 was$29.48 billion compared to$29.91 billion for 2020. 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. 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,
2021 2020
Deferred tax benefit (expense) attributable to OTA $ (27.6 ) $ 155.3
Revised Texas Franchise Tax ("Texas Margin Tax") (41.9 ) (32.1 )
Other (0.5 ) 1.1
Benefit from (provision for) income taxes$ (70.0 ) $
124.3
OnFebruary 25, 2020 , we received notice fromMarquard & Bahls AG ("M&B") of its election to exercise its rights 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 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 . 66
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AtMarch 5, 2020 , the Partnership's liability recognized in connection with the Liquidity Option Agreement was$511.9 million (referred to as the "Liquidity Option liability"). Upon settlement of the Liquidity Option Agreement, the Liquidity Option liability was effectively replaced by the deferred tax liability of OTA calculated in accordance with ASC 740, Income Taxes. Since the book value of the Liquidity Option liability exceeded OTA's estimated deferred tax liability of$439.7 million on that date, we recognized a non-cash benefit in earnings of$72.2 million , which is reflected in the "Benefit from (provision for) income taxes" 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 which reflected a decrease in the outside basis difference of its investment in the Partnership caused by a decline in the market price of the Partnership's common units subsequent 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. Income tax expense attributable to the Texas Margin Tax increased$9.8 million year-to-year primarily due to an increase in theTexas apportionment factor and higher Partnership earnings.
For information regarding our income taxes, see Note 15 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
Business Segment Highlights Our operations are reported under four business segments: (i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services and (iv) Petrochemical & Refined Products Services. Our business segments are generally organized and managed according to the types of services rendered (or technologies employed) and products produced and/or sold.
The following information summarizes the assets and operations of each business segment:
• Our NGL Pipelines & Services business segment includes our natural gas
processing and related NGL marketing activities, NGL pipelines, NGL
fractionation facilities, NGL and related product storage facilities, and NGL
marine terminals.
• Our Crude Oil Pipelines & Services business segment includes our crude oil
pipelines, crude oil storage and marine terminals, and related crude oil marketing activities.
• Our Natural Gas Pipelines & Services business segment includes our natural gas
pipeline systems that provide for the gathering, treating and transportation of
natural gas. This segment also includes our natural gas marketing activities.
• Our Petrochemical & Refined Products Services business segment includes our (i)
propylene production facilities, which include propylene fractionation units
and a PDH facility, and related pipelines and marketing activities, (ii) butane
isomerization complex and related deisobutanizer ("DIB") operations, (iii)
octane enhancement, iBDH and HPIB production facilities, (iv) refined products
pipelines, terminals and related marketing activities, (v) an ethylene export
terminal and related operations; and (vi) marine transportation business.
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 total gross
operating margin, a non-generally accepted accounting principle ("non-GAAP")
financial measure, for the years indicated (dollars in millions):
For the Year Ended
December 31,
2021 2020
Gross operating margin by segment:
NGL Pipelines & Services$ 4,315.9 $ 4,182.4 Crude Oil Pipelines & Services 1,679.9 1,997.3 Natural Gas Pipelines & Services 1,155.5 926.6 Petrochemical & Refined Products Services 1,357.2 1,081.8 Total segment gross operating margin (1) 8,508.5 8,188.1 Net adjustment for shipper make-up rights 53.8 (85.7 ) Total gross operating margin (non-GAAP)$ 8,562.3 $ 8,102.4
(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,
2021 2020
Operating income $ 6,103.7 $ 5,035.1
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)
2,010.6 1,961.5
Asset impairment charges in operating costs and expenses 232.6
890.6
Net losses (gains) attributable to asset sales and related matters in operating costs and expenses
6.1 (4.4 )
General and administrative costs 209.3
219.6
Total gross operating margin (non-GAAP)$ 8,562.3
(1) Excludes amortization of major maintenance costs for reaction-based plants,
which are a component of gross operating margin.
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.
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Two major winter storms, Uri and Viola, impactedTexas and the southernU.S. inmid-February 2021 (the "February 2021 winter storms"). The storms had a major impact on the electric power grid inTexas , which resulted in widespread power outages. Voluntarily and in accordance with our agreements with theElectric Reliability Council of Texas, Inc. ("ERCOT"), we temporarily shut down our non-essential plants and other operations inTexas to support residential power consumption. ThoseTexas assets that remained operational (e.g., our natural gas processing plants, storage facilities and Texas Intrastate System) were impacted by rolling blackouts. The economic impacts of these disruptions, higher power and natural gas costs, as well as losses on natural gas hedges, were mitigated by sales of natural gas to electricity generators, natural gas utilities and industrial customers to assist them in meeting their requirements. During and following the storms, many of our customers also experienced downtime due to freeze-related damage and repairs that impacted our volumes.
Estimated Impact of Hurricane Ida on Results for 2021
In lateAugust 2021 , southernLouisiana andMississippi , including its critical energy infrastructure, were impacted by the cumulative effects of Hurricane Ida. Impacts on the energy industry included, but were not limited to, severe flooding and limited access to facilities, disruptions to offshore production in theGulf of Mexico , and reduced energy demand from area refineries and petrochemical facilities. Our plant, pipeline and storage assets in southernLouisiana andMississippi did not experience significant property damage, and the majority have returned to normal operations. We expect our volumes impacted by the remaining third-party facility disruptions to return to normal levels as repairs are completed and production is fully restored. We estimate that Hurricane Ida reduced our gross operating margin for the third and fourth quarters of 2021 by approximately$34 million , almost all of which is related to ourLouisiana andMississippi processing, transportation and fractionation assets and related marketing activities, which are a component of our NGL Pipelines & Services segment. Of this amount, approximately$29 million represents the combined net impact of lower than anticipated volumes and lost business opportunities. The remaining$5 million represents expenses, net of property damage insurance reimbursements, which we incurred during the year in connection with hurricane-related repair and recovery costs.
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,
2021 2020
Segment gross operating margin:
Natural gas processing and related NGL marketing activities $ 1,134.8 $ 997.5
NGL pipelines, storage and terminals 2,323.7 2,524.1
NGL fractionation 857.4 660.8
Total $ 4,315.9 $ 4,182.4
Selected volumetric data:
NGL pipeline transportation volumes (MBPD) 3,412 3,589
NGL marine terminal volumes (MBPD) 658
722
NGL fractionation volumes (MBPD) 1,253
1,359
Equity NGL production volumes (MBPD) (1) 167
151
Fee-based natural gas processing volumes (MMcf/d) (2, 3) 4,057
4,285
(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.
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Natural gas processing and related NGL marketing activities Gross operating margin from natural gas processing and related NGL marketing activities for the year endedDecember 31, 2021 increased$137.3 million when compared to the year endedDecember 31, 2020 . Gross operating margin from ourPermian Basin natural gas processing facilities increased$93.9 million year-to-year primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a$67.9 million increase, and higher processing volumes, which accounted for an additional$28.9 million increase. On a combined basis, fee-based natural gas processing and equity NGL production volumes at ourPermian Basin plants increased 158 MMcf/d and 27 MBPD, respectively, year-to-year. Gross operating margin from our natural gas processing facilities located in theRocky Mountains (Meeker, Pioneer and Chaco plants) increased a combined$73.6 million year-to-year primarily due to higher average processing margins (including the impact of hedging activities). On a combined basis, fee-based natural gas processing and equity NGL production volumes at these plants decreased 245 MMcf/d and 3 MBPD, respectively, year-to-year. Gross operating margin from ourLouisiana andMississippi natural gas processing facilities increased$44.5 million year-to-year primarily due to higher average processing margins (including the impact of hedging activities). Net to our interest, combined fee-based natural gas processing and equity NGL production volumes at these plants decreased 50 MMcf/d and increased 3 MBPD, respectively, year-to-year (net to our interest). Gross operating margin from our NGL marketing activities decreased$72.9 million year-to-year primarily due to lower average sales margins, which accounted for a$44.4 million decrease, and lower sales volumes, which accounted for an additional$18.0 million decrease. The year-to-year decrease in gross operating margin can be attributed to results from marketing strategies that seek to optimize our export, storage and plant assets, which accounted for a combined$154.6 million decrease, partially offset by higher earnings from strategies that seek to optimize our transportation assets, which accounted for a$91.3 million increase. In addition, gross operating margin from our NGL marketing activities attributable to non-cash, mark-to-market earnings decreased$9.6 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, 2021 decreased$200.4 million when compared to the year endedDecember 31, 2020 . A number of our pipelines, including the Mid-America Pipeline System,Seminole NGL Pipeline, Chaparral NGL Pipeline, and Shin Oak NGL Pipeline, servePermian Basin and/orRocky Mountain producers. On a combined basis, gross operating margin from these pipelines decreased$109.2 million year-to-year primarily due to lower transportation volumes of 49 MBPD (net to our interest), which accounted for an$57.3 million decrease, and a$44.0 million decrease due to lower average transportation and deficiency fees, which was primarily due to certain contracts associated with theRocky Mountain segment of our Mid-America Pipeline System reaching their termination date inSeptember 2021 . Gross operating margin from LPG-related activities at ourEnterprise Hydrocarbons Terminal ("EHT") decreased$53.9 million year-to-year primarily due to lower export volumes of 87 MBPD. Gross operating margin from our related Houston Ship Channel Pipeline decreased$11.9 million year-to-year primarily due to an 81 MBPD decrease in transportation volumes. Gross operating margin at our Morgan'sPoint Ethane Export Terminal increased$12.8 million year-to-year primarily due to higher export volumes of 23 MBPD. Gross operating margin from our Dixie Pipeline and related terminals decreased a combined$23.1 million year-to-year primarily due to higher maintenance and other operating costs, which accounted for a$12.0 million decrease, and lower transportation volumes of 20 MBPD, which accounted for an additional$10.9 million decrease. Gross operating margin from ourChambers County storage complex decreased a net$14.5 million year-to-year primarily due to higher operating costs, which accounted for a$16.8 million decrease, and lower throughput fee revenues, which accounted for an additional$10.7 million decrease, partially offset by higher storage fee revenues, which accounted for a$13.0 million increase.
Gross operating margin from our ATEX Pipeline decreased
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Gross operating margin from our South Texas NGL Pipeline System increased$13.6 million year-to-year primarily due to higher pipeline capacity fee revenues. Transportation volumes on our South Texas NGL Pipeline System decreased 7 MBPD year-to-year. NGL fractionation Gross operating margin from NGL fractionation during the year endedDecember 31, 2021 increased$196.6 million when compared to the year endedDecember 31, 2020 . Gross operating margin from our Chambers County NGL fractionation complex increased a net$196.3 million year-to-year. This increase was primarily due to higher fractionation volumes, which accounted for a$151.1 million increase, and higher ancillary service revenues, which accounted for an additional$59.4 million increase, partially offset by higher operating costs, which accounted for a$136.8 million decrease. NGL fractionation volumes at ourChambers County NGL fractionation complex, which includes the average daily operating rates for newly constructed assets from the time the asset was placed into service, decreased 55 MBPD year-to-year (net to our interest). While the average daily operating rate for our Chambers County NGL fractionation complex decreased year-to-year, total NGL fractionation volumes increased primarily due to a full period of contributions from Frac X and Frac XI, which entered service in lateMarch 2020 andSeptember 2020 , respectively. In addition, gross operating margin at our Chambers County NGL fractionation complex increased due to$63.2 million in margins on the optimization of our power supply arrangements and$40.5 million of payments received in connection with our participation in the Texas Load Resources Demand Response Program ("LaaR") during theFebruary 2021 winter storms. The amounts earned from optimization activities were based on the settlement ofERCOT prices, which were finalized by theState of Texas during the second quarter of 2021. The amounts earned from the LaaR program partially compensate us for higher electricity expenses incurred during the storms and for lost revenues resulting from voluntary fractionation plant outages during the storms.
The natural gasoline hydrotreater at our
Gross operating margin from our Norco NGL fractionator decreased$13.5 million year-to-year primarily due to higher maintenance costs and lower fractionation volumes as a result of downtime for major maintenance activities during the second quarter of 2021 and Hurricane Ida during the third quarter of 2021. NGL fractionation volumes at our Norco NGL fractionator decreased 16 MBPD year-to-year.
Crude Oil Pipelines & Services
The following table presents segment gross operating margin and selected volumetric data for the Crude Oil Pipelines & Services segment for the years indicated (dollars in millions, volumes as noted):
For the Year Ended
December 31,
2021 2020Segment gross operating margin:
Other crude oil pipelines, terminals and related marketing results 1,298.5 1,638.1 Total$ 1,679.9 $ 1,997.3 Selected volumetric data:
Crude oil pipeline transportation volumes (MBPD) 2,088 2,166 Crude oil marine terminal volumes (MBPD) 645 724 Gross operating margin from our Crude Oil Pipelines & Services segment for the year endedDecember 31, 2021 decreased$317.4 million when compared to the year endedDecember 31, 2020 . Gross operating margin from our crude oil marketing activities (excluding those attributable to theMidland -to-ECHO System) decreased$264.1 million year-to-year primarily due to lower average sales margins, which accounted for a$231.8 million decrease, and lower non-cash, mark-to-market earnings, which accounted for an additional decrease of$22.9 million . Results from crude oil marketing strategies that optimize our storage and transportation assets decreased$177.5 million and$45.0 million , respectively, year-to-year. 71
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Gross operating margin from our South Texas Crude Oil Pipeline System decreased$42.6 million year-to-year primarily due to lower transportation volumes of 17 MBPD, which accounted for a$26.5 million decrease, and lower average transportation fees, which accounted for an additional$20.6 million decrease. Gross operating margin from our equity investment in the Eagle Ford Crude Oil Pipeline decreased$12.2 million year-to-year primarily due to lower transportation volumes of 42 MBPD (net to our interest).
Gross operating margin from our West Texas Pipeline System decreased
Gross operating margin from crude oil activities at EHT decreased$20.4 million year-to-year primarily due to lower storage revenues and other fees. Crude oil terminal volumes at EHT decreased 112 MBPD year-to-year. Gross operating margin from our equity investment in the Seaway Pipeline increased$35.5 million year-to-year primarily due to LaaR payments from power service providers in connection with theFebruary 2021 winter storms. Transportation volumes on our Seaway Pipeline decreased 30 MBPD year-to-year (net to our interest). Gross operating margin from ourMidland -to-ECHO System and related business activities increased a net$22.2 million year-to-year primarily due to higher transportation volumes, which accounted for a$95.6 million increase, partially offset by lower average sales margins from marketing activities, which accounted for a$77.5 million decrease.
Natural Gas Pipelines & Services
The following table presents segment gross operating margin and selected volumetric data for the Natural Gas Pipelines & Services segment for the years indicated (dollars in millions, volumes as noted):
For the Year Ended
December 31,
2021 2020
Segment gross operating margin $ 1,155.5 $ 926.6
Selected volumetric data:
Natural gas pipeline transportation volumes (BBtus/d) 14,249 13,421
Gross operating margin from our Natural Gas Pipelines & Services segment for the year endedDecember 31, 2021 increased$228.9 million when compared to the year endedDecember 31, 2020 . As noted previously, two major winter storms impactedTexas and the southernU.S. inmid-February 2021 . Given the higher demand for natural gas during theFebruary 2021 winter storms, we sold natural gas to assist electricity generators, natural gas utilities and industrial customers in meeting their requirements. Gross operating margin from our natural gas marketing activities increased$267.6 million year-to-year primarily due to higher average sales margins in connection with these unusual storm events. Gross operating margin from our Permian Basin Gathering System increased$15.5 million year-to-year primarily due to higher condensate sales, which accounted for a$10.8 million increase, and higher natural gas gathering volumes of 200 BBtus/d, which accounted for an additional$8.5 million increase. The year-to-year increase in gathering volumes is attributable to deliveries at our Orla facility. Gross operating margin from our Texas Intrastate System decreased a net$58.9 million year-to-year primarily due to lower capacity reservation revenues, which accounted for a$118.2 million decrease, partially offset by higher storage and other fees, which accounted for a$32.8 million increase, and higher transportation volumes of 591 BBtus/d, which accounted for an additional$18.6 million increase. 72
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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,
2021 2020Segment gross operating margin:
Propylene production and related activities $
798.2
Butane isomerization and related operations
75.0 67.6
Octane enhancement and related plant operations
106.9 161.7
Refined products pipelines and related activities
289.6 318.6
Ethylene exports and related activities
73.8 25.6
Marine transportation and other services 13.7 37.3 Total$ 1,357.2 $ 1,081.8 Selected volumetric data: Propylene production volumes (MBPD) 99 89 Butane isomerization volumes (MBPD) 85 96 Standalone DIB processing volumes (MBPD) 154 127 Octane enhancement and related plant sales volumes (MBPD) (1) 33 35
Pipeline transportation volumes, primarily refined products and
petrochemicals (MBPD) 890 802
Marine terminal volumes, primarily refined products and
petrochemicals (MBPD) 234 262
(1) Reflects aggregate sales volumes for our octane additive and iBDH facilities
located at our Chambers County complex and our HPIB facility located
adjacent to the Houston Ship Channel.
Propylene production and related activities
Gross operating margin from propylene production and related activities for the
year ended December 31, 2021 increased $327.2 million when compared to the year
ended December 31, 2020 . Gross operating margin from our Chambers County
propylene production facilities increased a combined net $324.7 million
year-to-year primarily due to higher average sales margins, which accounted for
a $220.5 million increase, higher propylene fractionation fees, which accounted
for a $119.6 million increase, and higher propylene sales volumes, which
accounted for an additional $31.6 million increase, partially offset by higher
operating costs, which accounted for a $52.6 million decrease. Propylene and
associated by-product production volumes at these facilities increased a
combined 9 MBPD year-to-year (net to our interest).
Butane isomerization and related operations
Gross operating margin from isomerization and related operations increased a net
$7.4 million year-to-year primarily due to higher average by-product sales
prices, which accounted for a $22.1 million increase, partially offset by higher
operating costs, which accounted for a $14.7 million decrease.
Octane enhancement and related plant operations
Gross operating margin from our octane enhancement and related plant operations
decreased $54.8 million year-to-year primarily due to higher operating costs,
which accounted for a $29.4 million decrease, and lower sales volumes, which
accounted for an additional $25.9 million decrease. Volumes at these facilities
for 2021 were lower when compared to 2020 primarily due to planned major
maintenance activities, which were completed in the last week of January 2021
for our HPIB plant and the beginning of May 2021 for our octane enhancement
plant.
Refined products pipelines and related activities
Gross operating margin from refined products pipelines and related activities
for the year ended December 31, 2021 decreased $29.0 million when compared to
the year ended December 31, 2020 .
Gross operating margin from our refined products marketing activities decreased
Gross operating margin from our TE Products Pipeline System and associated
terminals increased a combined
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Ethylene exports and related activities Gross operating margin from ethylene exports and related activities for the year endedDecember 31, 2021 increased$48.2 million when compared to the year endedDecember 31, 2020 . Gross operating margin from our ethylene export terminal increased$23.3 million year-to-year primarily due to higher export volumes of 4 MBPD (net to our interest). Gross operating margin from our other ethylene activities increased$24.9 million year-to-year primarily due to higher storage fees, which accounted for an$11.5 million increase, higher sales volumes, which accounted for a$4.7 million increase, and higher average sales margins, which accounted for an additional$4.6 million increase. Marine transportation and other services Gross operating margin from marine transportation and other services decreased$23.6 million year-to-year primarily due to lower average fees and lower average fleet utilization rates in 2021.
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, 2021 , we had$7.32 billion of consolidated liquidity, which was comprised of$4.5 billion of available borrowing capacity under EPO's revolving credit facilities and$2.82 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 "2021 Shelf") on file with theSEC which allows the Partnership and EPO to issue an unlimited amount of equity and debt securities, respectively. The 2021 Shelf replaced our prior universal shelf registration statement, which is set to expire inMarch 2022 .
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,
2021 2020
Net cash flows provided by operating activities
2,134.6 3,120.7
Cash used in financing activities 4,571.3 2,022.7
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.
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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, 2021 increased$2.62 billion when compared to the year endedDecember 31, 2020 primarily due to:
• a
capital employed in our marketing activities primarily related to storage
optimization strategies;
• a
receipts and payments related to operations;
• a
earnings in 2021 when compared to 2020 (determined by adjusting our
million year-to-year increase in net income for changes in the non-cash items
identified on our Statements of Consolidated Cash Flows); and
• a
earnings from unconsolidated affiliates primarily attributable to our investments in crude oil pipelines. 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, 2021 decreased a net$986.1 million when compared to the year endedDecember 31, 2020 primarily due to:
• a
equipment (see "Capital Investments" within this Part II, Item 7 for additional
information); and
• a
due to the sale of a coal bed natural gas gathering system and related Val
Verde treating facility in
• a
from unconsolidated affiliates primarily attributable to our investments in
crude oil pipelines. Financing activities Cash used in financing activities for the year endedDecember 31, 2021 increased$2.55 billion when compared to the year endedDecember 31, 2020 . The year-to-year increase was primarily due to a net cash outflow of$273.7 million related to debt transactions that occurred during the year endedDecember 31, 2021 compared to a net cash inflow of$2.19 billion during the year endedDecember 31, 2020 . In 2021, we repaid$1.33 billion aggregate principal amount of senior notes, partially offset by the issuance of$1.0 billion principal amount of senior notes. In 2020, we issued$4.25 billion aggregate principal amount of senior notes, partially offset by the repayment of$1.5 billion aggregate principal amount of senior notes. In addition, net repayments of short-term notes under EPO's commercial paper program were$481.8 million in 2020. Non-GAAP Cash Flow Measures Distributable Cash Flow Our partnership agreement requires us to make quarterly distributions to our common unitholders of all available cash, after any cash reserves established by Enterprise GP in its sole discretion. Cash reserves include those for the proper conduct of our business, including those for capital investments, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other amounts. The retention of cash allows us to reinvest in our growth and reduce our future reliance on the equity and debt capital markets. 75
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We measure available cash by reference to distributable cash flow ("DCF"), which
is a non-GAAP cash flow measure. DCF is an important financial measure for our
common unitholders since it serves as an indicator of our success in providing a
cash return on investment. Specifically, this financial measure indicates to
investors whether or not we are generating cash flows at a level that can
sustain our declared quarterly cash distributions. DCF is also a quantitative
standard used by the investment community with respect to publicly traded
partnerships since the value of a partnership unit is, in part, measured by its
yield, which is based on the amount of cash distributions a partnership can pay
to a unitholder. Our management compares the DCF we generate to the cash
distributions we expect to pay our common unitholders. Using this metric,
management computes our distribution coverage ratio. Our calculation of DCF may
or may not be comparable to similarly titled measures used by other companies.
Based on the level of available cash each quarter, management proposes a
quarterly cash distribution rate to the Board, which has sole authority in
approving such matters. Enterprise GP has a non-economic ownership interest in
the Partnership and is not entitled to receive any cash distributions from it
based on incentive distribution rights or other equity interests.
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 to DCF. 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 Ended
December 31,
2021 2020
Net income attributable to common unitholders (GAAP) (1)
derive DCF (addition or subtraction indicated by sign): Depreciation, amortization and accretion expenses
2,139.8 2,071.9
Cash distributions received from unconsolidated affiliates (2)
590.1 614.1
Equity in income of unconsolidated affiliates (583.4 ) (426.1 ) Asset impairment charges 232.8
890.6
Change in fair market value of derivative instruments (27.4 ) (79.3 ) Deferred income tax expense (benefit) 39.8 (147.6 ) Sustaining capital expenditures (3) (430.1 ) (293.6 ) Other, net (4) (126.8 ) 22.5 Operational DCF (5)$ 6,468.9 $ 6,427.2 Proceeds from asset sales 64.3 12.8 Monetization of interest rate derivative instruments accounted for as cash flow hedges 75.2 (33.3 ) DCF (non-GAAP)$ 6,608.4 $ 6,406.7
Cash distributions paid to common unitholders with respect to period,
including distribution equivalent rights on phantom unit awards
$ 3,992.6
Cash distribution per common unit declared by Enterprise GP with respect to period (6)
$ 1.8150
Total DCF retained by the Partnership with respect to period (7)
$ 2,615.8
Distribution coverage ratio (8) 1.66 x
1.63 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 aggregate distributions received from unconsolidated affiliates
attributable to both earnings and the return of capital. (3) Sustaining capital expenditures include cash payments and accruals
applicable to the period.
(4) The year ended
receivable that we do not expect to collect in the normal billing cycle. (5) Represents DCF before proceeds from asset sales and the monetization of
interest rate derivative instruments accounted for as cash flow hedges. (6) 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. (7) Cash retained by the Partnership may be used for capital investments, debt
service, working capital, operating expenses, common unit repurchases,
commitments and contingencies and other amounts. The retention of cash
reduces our reliance on the capital markets.
(8) 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,
2021 2020
Net cash flows provided by operating activities (GAAP)
DCF (addition or subtraction indicated by sign): Net effect of changes in operating accounts (1,366.7 ) 767.5 Sustaining capital expenditures (430.1 ) (293.6 )
Distributions received from unconsolidated affiliates attributable
to the return of capital 46.3 187.5
Proceeds from asset sales 64.3 12.8
Net income attributable to noncontrolling interests (117.6 ) (110.1 )
Monetization of interest rate derivative instruments
accounted
for as cash flow hedges 75.2 (33.3 )
Other, net (175.5 ) (15.6 )
DCF (non-GAAP) $ 6,608.4 $ 6,406.7
Free Cash Flow
Free Cash Flow ("FCF"), a non-GAAP cash flow measure that is widely used by
investors and other participants in the financial community, reflects how much
cash flow a business generates during a period after accounting for all capital
investments, including those 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 to FCF.
FCF fluctuates year-to-year based on a number of factors including earnings, the
level of investing activities, the timing of operating cash receipts and
payments, and contributions from noncontrolling interests. The following table
summarizes our calculation of FCF for the years indicated (dollars in millions):
For the Year Ended
December 31,
2021 2020
Net cash flows provided by operating activities (GAAP) $ 8,512.5 $ 5,891.5
Adjustments to net cash flows provided by operating activities to
derive FCF (addition or subtraction indicated by sign):
Cash used in investing activities
(2,134.6 ) (3,120.7 )
Cash contributions from noncontrolling interests 72.4 30.9 Cash distributions paid to noncontrolling interests (153.7 ) (131.3 ) FCF (non-GAAP)$ 6,296.6 $ 2,670.4 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. 77
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Capital Investments
The following table summarizes our capital investments for the years indicated
(dollars in millions):
For the Year Ended
December 31,
2021 2020Capital investments for property, plant and equipment: (1) Growth capital projects (2)
$ 1,807.4 $ 2,985.8 Sustaining capital projects (3) 415.8
302.1
Total$ 2,223.2
Investments in unconsolidated affiliates$ 2.1
(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 projects are capital expenditures (as defined by GAAP)
resulting from improvements to existing assets. Such expenditures serve to
maintain existing operations but do not generate additional revenues or
result in significant cost savings. Sustaining capital expenditures include
the costs of major maintenance activities at our reaction-based plants, which
are accounted for using the deferral method.
We placed a number of growth capital projects into commercial service during 2021 including:
• a natural gasoline hydrotreater at our
• the Baymark ethylene pipeline in
• the Gillis Lateral natural gas pipeline and its related infrastructure in
December 2021 .
We currently have
Based on information currently available, we expect our total capital investments for 2022, net of contributions from noncontrolling interests, to approximate$1.9 billion , which reflects growth capital investments of$1.5 billion and sustaining capital expenditures of$350 million . These amounts do not include capital investments associated with SPOT, our proposed deep-water offshore crude oil terminal, which remains subject to governmental approvals. We currently anticipate receiving approval for SPOT as early as mid-2022; however, we can give no assurance as to whether the project will ultimately be approved or the timing of such decision. InJanuary 2022 , we announced that an affiliate of Enterprise entered into a definitive agreement to acquireNavitas Midstream Partners, LLC ("Navitas Midstream") from an affiliate of Warburg Pincus LLC for$3.25 billion . The purchase price was paid in cash at closing onFebruary 17, 2022 . We funded the cash consideration for this acquisition using proceeds from the issuance of short-term notes under our commercial paper program and cash on hand. Our forecast of capital investments is dependent upon our ability to generate the required funds from either operating cash flows or other means, including borrowings under debt agreements, the issuance of additional equity and debt securities, and potential divestitures. We may revise our forecast of capital investments due to factors beyond our control, such as adverse economic conditions, weather-related issues and changes in supplier prices. 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. 78
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Comparison of Year Ended
In total, investments in growth capital projects decreased
• completion of projects associated with crude oil pipelines (e.g., expansion
projects involving the
infrastructure supportingPermian Basin producers), which accounted for a combined$479.4 million decrease;
• completion of projects at our
Frac X and Frac XI) during 2020, which accounted for a
• lower investments in
related infrastructure during 2021, which accounted for a$65.3 million decrease; and
• lower investments in projects related to our ethylene business during 2021,
which accounted for a
Investments attributable to sustaining capital projects increased$113.7 million year-to-year primarily due to the cost of major maintenance activities performed during the year endedDecember 31, 2021 at certain of our reaction-based plants (PDH 1, octane enhancement and HPIB facilities). These costs accounted for$106.3 million of the year-to-year increase in sustaining capital investments. For reaction-based plants, we use the deferral method when accounting for major maintenance activities. Under the deferral method, major maintenance costs are capitalized and amortized over the period until the next major overhaul project. We adopted the deferral method for our reaction-based plants inNovember 2020 . Historically, the costs of major maintenance activities attributable to our reaction-based facilities, principally our octane enhancement assets, were not material to our consolidated financial statements.
Consolidated Debt
AtDecember 31, 2021 , the average maturity of EPO's consolidated debt obligations was approximately 20.7 years. The following table presents the scheduled maturities of principal amounts of EPO's consolidated debt obligations and associated estimated cash payments for interest atDecember 31, 2021 for the years indicated (dollars in millions): Total 2022 2023 2024 2025 2026 Thereafter Principal amount of senior and junior debt obligations$ 29,821.4 $ 1,400.0 $ 1,250.0 $ 850.0 $ 1,150.0 $ 875.0 $ 24,296.4 Estimated cash payments for interest (1) 28,488.2 1,272.4 1,232.2 1,194.0 1,152.6 1,118.4 22,518.6
(1) 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 2021, as
applicable, for each note through the respective maturity date.
In February 2021 , EPO repaid all of the $750.0 million in principal amount of
its Senior Notes TT using remaining cash on hand attributable to its August 2020
senior notes offering and proceeds from the issuance of short-term notes under
its commercial paper program.
In March 2021 , EPO redeemed all of the $575.0 million outstanding principal
amount of its Senior Notes RR one month prior to their scheduled maturity in
April 2021 . These notes were redeemed at par (i.e., at a redemption price equal
to the outstanding principal amount of such notes to be redeemed, plus accrued
and unpaid interest thereon) using proceeds from the issuance of short-term
notes under its commercial paper program.
In September 2021 , EPO entered into a new 364-Day Revolving Credit Agreement
(the "September 2021 364-Day Revolving Credit Agreement") that replaced its
September 2020 364-Day Revolving Credit Agreement. The September 2021 364-Day
Revolving Credit Agreement matures in September 2022 . EPO's borrowing capacity
was unchanged from the prior 364-Day Revolving Credit Agreement. As of December
31, 2021 , there are no principal amounts outstanding under this new revolving
credit agreement.
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InSeptember 2021 , EPO entered into a new multi-year revolving credit agreement that matures inSeptember 2026 (the "September 2021 Multi-Year Revolving Credit Agreement"). TheSeptember 2021 Multi-Year Revolving Credit Agreement replaced EPO's prior multi-year revolving credit agreement that was scheduled to mature inSeptember 2024 . EPO's borrowing capacity under theSeptember 2021 Multi-Year Revolving Credit Agreement is$3.0 billion (which may be increased by up to$500.0 million to$3.5 billion at EPO's election, provided certain conditions are met) under theSeptember 2021 Multi-Year Revolving Credit Agreement. As ofDecember 31, 2021 , there are no principal amounts outstanding under this new revolving credit agreement. InSeptember 2021 , EPO issued$1.0 billion in principal amount of senior notes dueFebruary 2053 ("Senior Notes EEE"). Senior Notes EEE were issued at 99.170% of their principal amount and have a fixed rate of interest of 3.30% per year. Net proceeds from the issuance of these senior notes were used for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of a portion of our$750.0 million in principal amount of 3.50% Senior Notes VV and a portion of our$650.0 million in principal amount of 4.05% Senior Notes CC, in each case at their maturity inFebruary 2022 ). 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 ofFebruary 28, 2022 , 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.
Product Purchase Commitments
The following table presents our unconditional product purchase commitments at
Total 2022 2023 2024 2025 2026 Thereafter
Product
purchase
commitments $ 18,805.1 $ 3,420.7 $ 3,070.9 $ 2,807.7 $ 2,348.6 $ 1,988.6 $ 5,168.6
We have long-term product purchase commitments for natural gas, NGLs, crude oil,
and petrochemicals and refined products with third party suppliers. The prices
that we are obligated to pay under these contracts approximate market prices at
the time we take delivery of the volumes. The preceding table presents our
estimated future payment obligations under these contracts based on the
contractual price in each agreement at December 31, 2021 applied to all future
volume commitments. Actual future payment obligations may vary depending on
prices at the time of delivery.
For additional information regarding our product purchase commitments, see Note
16 of the Notes to Consolidated Financial Statements included under Part II,
Item 8 of this annual report.
Enterprise Declares Cash Distribution for Fourth Quarter of 2021
OnJanuary 6, 2022 , we announced that the Board declared a quarterly cash distribution of$0.465 per common unit, or$1.86 per unit on an annualized basis, to be paid to the Partnership's common unitholders with respect to the fourth quarter of 2021. The quarterly distribution was paid onFebruary 11, 2022 to unitholders of record as of the close of business onJanuary 31, 2022 . The total amount paid was$1.02 billion , which includes$8.0 million for distribution equivalent rights on phantom unit awards. 80
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The payment of quarterly cash distributions is subject to management's evaluation of our financial condition, results of operations and cash flows in connection with such payments and Board approval. In light of current economic conditions, management will evaluate any future increases in cash distributions on a quarterly basis.
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 the Partnership 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. The Partnership repurchased an aggregate 9,891,956 common units under the 2019 Buyback Program through open market purchases during the year endedDecember 31, 2021 . The total cost of these repurchases, including commissions and fees, was$213.9 million . Common units repurchased under the 2019 Buyback Program are immediately cancelled upon acquisition. As ofDecember 31, 2021 , the remaining available capacity under the 2019 Buyback Program was$1.52 billion .
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. AtDecember 31, 2021 and 2020, the net carrying value of our property, plant and equipment was$42.09 billion and$41.91 billion , respectively. We recorded$1.71 billion and$1.68 billion of depreciation expense during the years endedDecember 31, 2021 and 2020, 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. 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.
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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 2021 and 2020, we recognized non-cash asset impairment charges attributable to assets other than goodwill totaling$232.6 million and$594.3 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.
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.
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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, 2021 and 2020, the carrying value of our customer relationship and contract-based intangible asset portfolio was$3.15 billion and$3.31 billion , respectively. We recorded$150.9 million and$143.2 million of amortization expense attributable to intangible assets during the years endedDecember 31, 2021 and 2020, 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 atDecember 31, 2021 and 2020.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. 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. We did not record any goodwill impairment charges during the year endedDecember 31, 2021 . Based on our most recent goodwill impairment test atDecember 31, 2021 , the estimated fair value of each of our reporting units was substantially in excess of its carrying value (i.e., by at least 10%).
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.
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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.
Other Matters
Parent-Subsidiary Guarantor Relationship
The Partnership (the "Parent Guarantor") has guaranteed the payment of principal and interest on the consolidated debt obligations of EPO (the "Subsidiary Issuer"), with the exception of the remaining debt obligations 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, 2021 , the total amount of Guaranteed Debt was$30.26 billion , which was comprised of$27.17 billion of EPO's senior notes,$2.63 billion of EPO's junior subordinated notes and$452.7 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$45.92 billion atDecember 31, 2021 .The Obligor Group's equity in the earnings of the Non-Obligor Subsidiaries for the year endedDecember 31, 2021 was$4.49 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's financial information presented below. 84
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The following table presents summarized balance sheet information for the
combined
Selected asset information:
Current receivables from Non-Obligor Subsidiaries $
358.4
Other current assets
7,993.7
Long-term receivables from Non-Obligor Subsidiaries
187.3
Other noncurrent assets, excluding investments in Non-Obligor
Subsidiaries of
8,790.8
Selected liability information:
Current portion of Guaranteed Debt, including interest of
$ 1,852.5
Current payables to Non-Obligor Subsidiaries
1,829.1
Other current liabilities
4,743.2
Noncurrent portion of Guaranteed Debt, principal only
28,406.8
Noncurrent payables to Non-Obligor Subsidiaries 27.0 Other noncurrent liabilities 48.7
Mezzanine equity of
Preferred units$ 49.3
The following table presents summarized income statement information for the
combined
Revenues from Non-Obligor Subsidiaries $
13,113.8
Revenues from other sources
16,676.5
Operating income ofObligor Group
1,489.8
Net income of
144.9
Related Party Transactions
For information regarding our related party transactions, see Note 14 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.
Income Taxes
OnSeptember 29, 2021 , the Internal Revenue Service ("IRS") issued a Notice of Selection for Examination to EPO, stating that theIRS has selected its 2019 and 2020 partnership tax returns for examination. OnJanuary 6, 2022 , theIRS issued a Notice of Selection for Examination to the Partnership stating that theIRS has selected our 2019 and 2020 partnership tax returns for examination. These are routine compliance examinations of various items of income, gain, deductions, losses and credits of EPO and the Partnership, respectively, during the years under examination. The examinations have commenced but are in a preliminary stage, and it is currently not known whether theIRS will propose any adjustments to the 2019 or 2020 partnership tax returns or whether such adjustments, if any, will be material.
Insurance
For information regarding insurance matters, see Note 17 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
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