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, 2022 and 2021, 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, 2020 and year-to-year comparisons between the years endedDecember 31, 2021 and 2020 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, 2021 that was filed onFebruary 28, 2022 .
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 32.4% of the Partnership's common units outstanding atDecember 31, 2022 .
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, 2022 (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," "pending," "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 in theU.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 ("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 "Regulatory
Matters - Environmental, Safety and Conservation" within 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 2023 Short-Term Energy Outlook ("February 2023 STEO"), which was published onFebruary 7, 2023 . 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 most 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. Beginning in late 2020 and throughout 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 programs worldwide, helped bolster an economic recovery in most industrial economies. According to the EIA,U.S. gross domestic product ("GDP") increased 5.9% in 2021 compared to a decrease of 2.8% in 2020. InChina , however, strategies for responding to the COVID-19 virus evolved through various stages that ultimately resulted in longer-lasting mobility restrictions than in most other industrialized nations.China adopted a strategy of "zero-COVID" which was based on a strict testing regime intended to pinpoint and then isolate localized clusters of the population infected with the virus. The large-scale lockdowns dramatically slowed Chinese economic output between late 2021 and 2022 and ended up constricting the global supply chain due to the significant reductions in intermediate and finished goods manufactured inChina . These reductions occurred just as the rest of the world was demanding increases in goods upon emerging from the pandemic. To make matters worse,Russia invaded the independent country ofUkraine inFebruary 2022 in a major escalation of the conflict that began whenRussia annexedCrimea fromUkraine in 2014. To counterRussia's aggression and to prevent a larger regional conflict, members of theNorth Atlantic Treaty Organization ("NATO"), among other countries, imposed sanctions onRussia including limits on exports of crude oil, refined products and natural gas, which sent global Brent crude oil prices soaring from$90 per barrel in earlyFebruary 2022 to$123 per barrel by earlyJune 2022 . Natural gas prices inEurope (based on the Dutch Title Transfer Facility, a virtual trading hub for gas inthe Netherlands and primary gas pricing hub for the European gas market) increased even more dramatically from$26 per MMBtu inJanuary 2022 to nearly$100 per MMBtu inAugust 2022 . The higher cost of energy led to government subsidies and the rationing of natural gas, electricity and commodities inEurope , which further reduced global economic output. 59
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Several factors, including massive fiscal stimulus from theU.S. and other global governments, increases in energy prices due to higher demand for energy and commodities following the pandemic, the significant global supply chain disruptions caused in large part by lockdowns inChina and the reduction in energy supplies due to sanctions onRussia contributed to inflation rates not seen in theU.S. in over four decades. BetweenJune 2021 andJune 2022 , the inflation rate, as measured by theU.S. Consumer Price Index ("CPI"), increased from 5.4% to a peak of 9.1%. To counteract these pressures, theU.S. Federal Reserve Bank ("the Fed") increased interest rates by 25 basis points inMarch 2022 and 50 basis points inMay 2022 . As inflation continued to rise, the Fed further increased rates by 75 basis points in each of its June, July, September and November meetings during 2022. Under the weight of these pressures, including higher interest rates, theU.S. economy began to experience a slowdown in growth as evidenced byU.S. GDP decreasing 1.6% and 0.6% in the first and second quarters of 2022, respectively. Some economists labeled this period a recession based on the general indicator of two consecutive quarters of negative growth. After peaking inJune 2022 at 9.1%, the inflation rate slowly began to moderate in each of the subsequent months, declining to a rate of 6.5% inDecember 2022 . In response to the decline in inflation, the Fed slowed the pace of interest rate increases to 50 basis points inDecember 2022 . Despite these increases,U.S. GDP turned positive again with a growth rate of 3.2% in the third quarter of 2022 and 2.9% in the fourth quarter of 2022. During the latter half of 2022, energy prices began falling to levels consistent with the start of the year as countries braced for recession, lockdowns inChina persisted, theU.S. andInternational Energy Agency member countries released an aggregate 240 million barrels from their respective strategic petroleum reserves and theU.S. and other non-OPEC countries increased petroleum and other liquids production volumes by approximately 2.0 MMBPD during the second half of 2022 (as reported by the EIA). Energy prices inEurope fell to pre-war levels as a relatively warm winter and alternatives to Russian natural gas from theU.S. ,Qatar and other exporting nations led to a healthy buildup of storage inventories. Despite sanctions and price caps, Russian crude oil continued to find its way to refineries, albeit with redirected trade flows toChina ,India and other nations encouraged by the ability to purchase crude oil fromRussia at steep discounts. The EIA provided expectations of continued growth inU.S. petroleum and liquid fuels production by nearly 1.0 MMBPD to reach a total of 21.1 MMBPD in 2023. Global production of petroleum and liquid fuels is expected to reach an average of 102.6 MMBPD in 2024, up from 100.0 MMBPD in 2022, driven mostly by growth inU.S. and other non-OPEC production. With respect to demand, the EIA forecasts that global liquids fuel consumption will increase from 99.4 MMBPD in 2022 to 102.3 MMBPD in 2024, driven primarily by growth fromChina and other non-OECD countries. However, the EIA qualified that this forecast is subject to significant uncertainty overRussia's oil supply, ongoing concerns about global economic conditions and the easing of COVID-19 restrictions inChina . We acknowledge that these uncertainties exist, however, the upside from the recently more upbeat economic news and the continued reopening of the Chinese economy helps us remain constructive on crude oil prices. We are not as constructive on natural gas prices considering we see domestic production rising, consumption declining and liquefied natural gas ("LNG") exports remaining relatively flat until 2025 when additional capacity will be available from new facilities that are expected to be placed in service. A wider crude oil-to-natural gas price spread, however, makesU.S. petrochemicals more cost-advantaged due to locally produced feedstocks more closely aligning with natural gas prices, whereas feedstocks derived from naphtha are more closely aligned with crude oil prices. We believe that these coming additions to petroleum production and consumption levels, along with favorable pricing trends, 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 innovative 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.
feedstock advantages position our assets well to compete globally for
incremental production and processing volumes. To the extent a rising
operating cost environment impacts our results, there are typically offsetting
benefits either inherent in our business or that result from other steps we
take proactively to reduce the impact of inflation on our operating results.
These steps include revenue rate escalations based on inflation factors, fuel
and electricity surcharges and additional volumetric throughputs often achieved
during periods of higher prices.
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• Our Customers - We have contracted with a large number of quality customers in
order to achieve revenue diversification. In 2022, our top 200 largest
customers represented 95.3% of consolidated revenues. Based on their
respective year-end 2022 debt ratings, 89.6% of revenues from our top 200
customers were either investment grade rated or backed by letters of credit.
Additionally, less than 4% of our top 200 customer revenues were attributable
to sub-investment grade or non-rated upstream producers.
• Our Balance Sheet and Liquidity - We currently maintain 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. Based on current market
conditions, we believe that we have sufficient consolidated liquidity as of
capacity under EPO's revolving credit facilities and
unrestricted cash on hand. As of
our debt portfolio is fixed rate debt at a weighted average cost of 4.5% and
weighted-average maturity of 20 years.
• Our Access to Capital Markets - EPO successfully issued
principal amount of senior notes in
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 2023 and beyond.
Recent Developments
Enterprise's SPOT Project Receives Record of Decision
InNovember 2022 , we announced that ourSea Port Oil Terminal ("SPOT") project received a favorable Record of Decision ("ROD") from theU.S. Department of Transportation's Maritime Administration in accordance with the provisions of the Deepwater Port Act of 1974. The proposed SPOT project consists of onshore and offshore facilities, including a fixed platform located approximately 30 nautical miles off theTexas coast in approximately 115 feet of water. SPOT is designed to load VLCCs and other crude oil tankers at rates of approximately 85,000 barrels per hour. The platform will be connected to an onshore storage facility with approximately 4.8 MMBbls of capacity inBrazoria County, Texas , by two 36-inch, bi-directional pipelines. Additionally, the SPOT project includes state-of-the-art pipeline control, vapor recovery and leak detection systems that are designed to minimize emissions. The receipt of the ROD is a significant milestone in the process to obtain a license for SPOT under the Deepwater Port Act. Remaining conditions that we must address and satisfy to obtain approval for the license issuance include routine construction, operating and decommissioning guarantees, submission of public outreach, wetland restoration and volatile organic compound ("VOC") monitoring plans, and other state approvals. We expect to satisfy these remaining conditions in 2023; however, we can give no assurance as to when or whether the project will ultimately be authorized to begin construction or operation.
Enterprise Announces Three Expansions in the
InAugust 2022 , we announced the following three new projects to support ongoing production growth in thePermian Basin (including their respective scheduled completion dates):
• our Leonidas natural gas processing plant, which was previously referred to as
Plant 7, in the
• our Mentone III natural gas processing plant in the
quarter of 2024); and
• a 275 MBPD expansion of our Shin Oak NGL Pipeline (first half of 2025).
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Enterprise and OLCV Sign Letter of Intent for
InApril 2022 ,Enterprise andOxy Low Carbon Ventures, LLC ("OLCV"), a subsidiary of Occidental Petroleum Corporation, announced that we have executed a letter of intent to work toward a potentialcarbon dioxide ("CO2") transportation and sequestration solution for theTexas Gulf Coast . The joint project would initially be focused on providing services to emitters in the industrial corridors from the greaterHouston toBeaumont /Port Arthur areas. The initiative would combine Enterprise's leadership position in the midstream energy sector with OLCV's extensive experience in subsurface characterization and CO2 sequestration. Enterprise would develop the CO2 aggregation and transportation network utilizing a combination of new and existing pipelines along its expansiveGulf Coast footprint. OLCV, through its 1PointFive business unit, is developing sequestration hubs on theGulf Coast and across theU.S. , some of which are expected to be anchored by direct air capture facilities. The hubs will provide access to high quality pore space and efficient transportation infrastructure, bringing more options to emitters looking to explore viablecarbon management strategies. Enterprise and OLCV have begun exploring the commercialization of the potential joint service offering with customers.
Enterprise Announces Seven New Projects During Analyst and Investor Day
On
• a 400 MMcf/d expansion of our Acadian Gas System (second quarter of 2023);
• our Poseidon natural gas processing plant, which was previously referred to as
Plant 6, in the
• a twelfth NGL fractionator ("Frac XII") in
quarter of 2023);
• our Mentone II natural gas processing plant in the
quarter of 2023);
• our Texas Western Products System, created by repurposing a portion of our
Mid-America Pipeline System's
service to our Chaparral Pipeline business to transport refined products from
the
(fourth quarter of 2023);
• an
• an expansion of our Morgan's Point terminal to increase ethylene export
capacity (2024 and 2025).
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 (subject to adjustment in accordance with the agreement).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 EPO's commercial paper program and cash on hand. See Note 12 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for additional information regarding this acquisition. 62
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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)
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 2022 by quarter: 1st Quarter$4.96 $0.40 $1.30 $1.59 $1.60 $2.21 $0.63 $0.39 $0.55 2nd Quarter$7.17 $0.59 $1.24 $1.50 $1.68 $2.17 $0.61 $0.40 $0.46 3rd Quarter$8.20 $0.55 $1.08 $1.19 $1.44 $1.72 $0.47 $0.28 $0.26 4th Quarter$6.26 $0.39 $0.79 $0.97 $1.03 $1.54 $0.32 $0.18 $0.17 2022 Averages$6.65 $0.48 $1.10 $1.31 $1.44 $1.91
(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
Markit ("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
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)
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
2022 by quarter:
1st Quarter $94.29 $96.43 $96.77 $96.77
2nd Quarter $108.41 $109.66 $109.96 $110.17
3rd Quarter $91.56 $93.41 $93.77 $94.17
4th Quarter $82.64 $83.97 $84.33 $85.50
2022 Averages $94.23 $95.87 $96.21 $96.65 (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.
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Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices. An increase in our consolidated marketing revenues due to higher energy commodity sales prices may not result in an increase in gross operating margin or cash available for distribution, since our consolidated cost of sales amounts would also 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 14 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.
Impact of Inflation
After being relatively moderate in recent years, inflation inthe United States increased significantly in late 2021 into 2022. This rise in inflation, coupled with supply chain disruptions, labor shortages and increased commodity prices, has generally resulted in higher costs in 2022. However, to the extent that a rising cost environment impacts our results, there are typically offsetting benefits either inherent in our business or that result from other steps we take proactively to reduce the impact of inflation on our net operating results. These benefits include: (1) provisions included in our long-term fee-based revenue contracts that offset cost increases in the form of rate escalations based on positive changes in theU.S. Consumer Price Index, Producer Price Index for Finished Goods or other factors; (2) provisions in other revenue contracts that enable us to pass through higher energy costs to customers in the form of gas, electricity and fuel rebills or surcharges; and (3) higher commodity prices, which generally enhance our results in the form of increased volumetric throughput and demand for our services. Additionally, we take measures to mitigate the impact of cost increases in certain commodities, including a portion of our electricity needs, using fixed-price, term purchase agreements. For these reasons, the increased cost environment, caused in part by inflation, has not had a material impact on our historical results of operations for the periods presented in this report. However, a significant or prolonged period of high inflation could adversely impact our results if costs were to increase at a rate greater than the increase in the revenues we receive. See "Capital Investments" within this Part II, Item 7 for a discussion of the impact of inflation on our capital investment decisions. Additionally, see Part I, Item 1A "Risk Factors - Changes in price levels could negatively impact our revenue, our expenses, or both, which could adversely affect our business." 64
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Table of Contents Income Statement Highlights
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,
2022 2021
Revenues $ 58,186 $ 40,807
Costs and expenses:
Operating costs and expenses:
Cost of sales 45,836 29,887
Other operating costs and expenses 3,454 2,915
Depreciation, amortization and accretion expenses 2,158
2,038
Asset impairment charges 53
233
Net losses attributable to asset sales and related matters 1
5
Total operating costs and expenses 51,502
35,078
General and administrative costs 241
209
Total costs and expenses 51,743
35,287
Equity in income of unconsolidated affiliates 464 583 Operating income 6,907 6,103 Other income (expense): Interest expense (1,244 ) (1,283 ) Other, net 34 5 Total other expense, net (1,210 ) (1,278 ) Income before income taxes 5,697 4,825 Provision for income taxes (82 ) (70 ) Net income 5,615 4,755 Net income attributable to noncontrolling interests (125 ) (117 ) Net income attributable to preferred units (3 ) (4 ) Net income attributable to common unitholders$ 5,487 $ 4,634 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,
2022 2021
NGL Pipelines & Services:
Sales of NGLs and related products $ 21,307 $ 13,716
Midstream services 2,952 2,586
Total 24,259 16,302
Crude Oil Pipelines & Services:
Sales of crude oil 17,301 9,519
Midstream services 1,260 1,383
Total 18,561 10,902
Natural Gas Pipelines & Services:
Sales of natural gas 5,019 3,413
Midstream services 1,241 987
Total 6,260 4,400
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products 8,003 8,196
Midstream services 1,103 1,007
Total 9,106 9,203
Total consolidated revenues $ 58,186 $ 40,807
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Total revenues for 2022 increased
Revenues from the marketing of NGLs, crude oil and natural gas increased a
combined
Revenues from midstream services for 2022 increased$593 million when compared to 2021. Revenues from our natural gas processing facilities increased$343 million year-to-year primarily due to higher market values for the equity NGL-equivalent production volumes we receive as non-cash consideration for processing services. Revenues from our natural gas pipeline assets increased$251 million year-to-year primarily due to the addition of theMidland Basin Gathering System from theNavitas Midstream acquisition and higher demand for natural gas transportation and gathering services inTexas andNew Mexico . Revenues from our NGL fractionators increased$51 million year-to-year primarily due to higher fractionation fee revenues at our Chambers County NGL fractionation complex. Revenues from our ethylene export terminal increased$34 million year-to-year primarily due to higher loading fee revenues. Lastly, revenues from our crude oil pipeline assets decreased$122 million year-to-year primarily due to lower deficiency revenues as a result of the expiration of minimum volume commitments under certain long-term gathering agreements on our EFS Midstream System. 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 2022 increased
Cost of sales Cost of sales for 2022 increased$15.9 billion when compared to 2021. The cost of sales associated with our marketing of NGLs, crude oil and natural gas increased a combined$16.5 billion year-to-year primarily due to higher average purchase prices, which accounted for a$12.1 billion increase, and higher sales volumes, which accounted for an additional$4.4 billion increase. Other operating costs and expenses Other operating costs and expenses increased$539 million year-to-year primarily due to higher utility, employee compensation and rental costs. Depreciation, amortization and accretion expenses Depreciation, amortization and accretion expense increased$120 million year-to-year. The addition of assets attributable to theNavitas Midstream acquisition accounted for$86 million of the year-to-year increase. The remainder of the year-to-year increase is due to assets placed into full or limited service since the first quarter of 2021 (e.g., the Gillis Lateral natural gas pipeline and the Baymark ethylene pipeline) and major maintenance activities accounted for under the deferral method. Asset impairment charges Non-cash asset impairment charges decreased$180 million year-to-year primarily due to the partial impairment of our marine transportation business inDecember 2021 , which accounted for$114 million of expense, and the sale of a coal bed natural gas gathering system and relatedVal Verde treating facility inMarch 2021 , both of which were components of our San Juan Gathering System, which accounted for an additional$44 million of expense. For information regarding these charges, see Note 4 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 2022 increased$32 million when compared to 2021 primarily due to higher employee compensation and professional services costs.
Equity in income of unconsolidated affiliates
Equity income from our unconsolidated affiliates for 2022 decreased$119 million when compared to 2021 primarily due to lower earnings from investments in crude oil pipelines. 66
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Table of Contents Operating income
Operating income for the year ended
Interest expense
The following table presents the components of our consolidated interest expense for the years indicated (dollars in millions):
For the Year Ended
December 31,
2022 2021
Interest charged on debt principal outstanding (1) $ 1,288
19 38
Interest costs capitalized in connection with construction projects (2) (90 ) (80 ) Other (3) 27 26 Total$ 1,244 $ 1,283
(1) The weighted-average interest rates on debt principal outstanding were 4.33%
and 4.35% during the years ended
plant and equipment while the asset is in its construction phase.
Capitalized interest amounts become part of the historical cost of an asset
and are charged to earnings (as a component of depreciation expense) on a
straight-line basis over the estimated useful life of the asset once the
asset enters its intended service. When capitalized interest is recorded, it
reduces interest expense from what it would be otherwise. Capitalized
interest amounts fluctuate based on the timing of when projects are placed
into service, our capital investment levels and the interest rates charged on
borrowings.
(3) Primarily reflects facility commitment fees charged in connection with our
revolving credit facilities and amortization of debt issuance costs.
Interest charged on debt principal outstanding, which is a key driver of interest expense, decreased$11 million year-to-year primarily due to the retirement of$1.4 billion of fixed-rate senior notes inFebruary 2022 and the redemption of$350 million of variable-rate junior subordinated notes inAugust 2022 using a combination of available cash, commercial paper and proceeds from a senior notes issuance inSeptember 2021 with a lower interest rate. These actions resulted in lower weighted-average interest rates on outstanding debt obligations during the comparative years. 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.
Other, net
Other non-operating income for 2022 includes
Income taxes
Our provision for income taxes for 2022 increased
For information regarding our income taxes, see Note 16 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
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Table of Contents 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.
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,
2022 2021
Gross operating margin by segment:
NGL Pipelines & Services$ 5,142 $ 4,316 Crude Oil Pipelines & Services 1,655 1,680 Natural Gas Pipelines & Services 1,042 1,155 Petrochemical & Refined Products Services 1,517 1,357 Total segment gross operating margin (1) 9,356 8,508 Net adjustment for shipper make-up rights (47 ) 53 Total gross operating margin (non-GAAP)$ 9,309 $ 8,561
(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.
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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,
2022 2021
Operating income $ 6,907 $ 6,103
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)
2,107 2,011
Asset impairment charges in operating costs and expenses 53
233
Net losses attributable to asset sales and related matters in operating costs and expenses
1 5
General and administrative costs 241 209
Total gross operating margin (non-GAAP)$ 9,309
(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.
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. During and following the storms, many of our customers also experienced downtime due to freeze-related damage and repairs that impacted our volumes. The economic impacts of these disruptions, higher power and natural gas costs, as well as losses on natural gas hedges and lower volumes, were mitigated by sales of natural gas to electricity generators, natural gas utilities and industrial customers to assist them in meeting their requirements.
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 all assets have since returned to normal operations. Our volumes impacted by third-party facility disruptions also returned to normal levels as repairs were completed and production was 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 was 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$5 million represents expenses, net of property damage insurance reimbursements, which we incurred during the year in connection with hurricane-related repair and recovery costs. 69
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Table of Contents NGL Pipelines & Services
The following table presents segment gross operating margin and selected volumetric data for the NGL Pipelines & Services segment for the years indicated (dollars in millions, volumes as noted):
For the Year Ended
December 31,
2022 2021Segment gross operating margin:
Natural gas processing and related NGL marketing activities$ 1,946 $ 1,135 NGL pipelines, storage and terminals 2,362 2,324 NGL fractionation 834 857 Total$ 5,142 $ 4,316
Selected volumetric data:
NGL pipeline transportation volumes (MBPD) 3,703 3,412 NGL marine terminal volumes (MBPD) 723 658 NGL fractionation volumes (MBPD) 1,339 1,253 Equity NGL-equivalent production volumes (MBPD) (1) 182 167 Fee-based natural gas processing volumes (MMcf/d) (2, 3) 5,182 4,057
(1) Primarily represents the NGL and condensate volumes we earn and take title
to in connection with our processing activities. The total equity
NGL-equivalent production volumes also include residue natural gas volumes
from our natural gas processing business. (2) Volumes reported correspond to the revenue streams earned by our natural gas
processing plants. (3) Fee-based natural gas processing volumes are measured at either the wellhead
or plant inlet in MMcf/d.
Natural gas processing and related NGL marketing activities
Gross operating margin from natural gas processing and related NGL marketing
activities for the year ended
OurMidland Basin natural gas processing facilities, which represent the natural gas processing facilities we acquired inFebruary 2022 as part of our acquisition ofNavitas Midstream , generated gross operating margin of$385 million . Fee-based natural gas processing volumes and equity NGL-equivalent production volumes at these facilities were 940 MMcf/d and 53 MBPD, respectively, following the acquisition date. OurMidland Basin natural gas gathering activities are discussed under the Natural Gas Pipelines & Services segment. Gross operating margin from ourDelaware Basin natural gas processing facilities, which represent our legacyPermian Basin processing facilities, increased$182 million year-to-year primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a$152 million increase, and a 180 MMcf/d increase in fee-based natural gas processing volumes, which accounted for an additional$29 million increase. Equity NGL-equivalent production volumes at these facilities decreased 27 MBPD year-to-year. Gross operating margin from ourSouth Texas natural gas processing facilities increased$86 million year-to-year primarily due to higher average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes increased 96 MMcf/d and equity NGL-equivalent production volumes decreased 1 MBPD year-to-year. Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) increased a net$86 million year-to-year primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a$71 million increase, and higher average processing fees, which accounted for an additional$20 million increase, partially offset by an 8 MBPD combined decrease in equity NGL-equivalent production volumes, which accounted for a$10 million decrease. On a combined basis, fee-based natural gas processing volumes decreased 47 MMcf/d year-to-year. Gross operating margin from our NGL marketing activities increased a net$71 million year-to-year primarily due to higher average sales margins, which accounted for a$135 million increase, and an increase in sales volumes, which accounted for an additional$29 million increase, partially offset by lower non-cash, mark-to-market earnings, which accounted for a$98 million decrease. The year-to-year increase in gross operating margin can be primarily attributed to results from marketing strategies that seek to optimize our storage, plant and transportation assets. 70
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NGL pipelines, storage and terminals Gross operating margin from our NGL pipelines, storage and terminal assets for the year endedDecember 31, 2022 increased$38 million when compared to the year endedDecember 31, 2021 . Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased a combined$106 million year-to-year primarily due to a 21 MBPD increase in transportation volumes on the ATEX Pipeline, which accounted for a$60 million increase, and higher deficiency fees, which accounted for an additional$39 million increase. Gross operating margin at our Morgan'sPoint Ethane Export Terminal increased$53 million year-to-year primarily due to higher average loading fees, which accounted for a$44 million increase, and an 11 MBPD increase in export volumes, which accounted for an additional$11 million increase.
Gross operating margin from our
Gross operating margin from our Dixie Pipeline and related terminals increased a
combined
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 a net$79 million year-to-year primarily due to lower deficiency fees as a result of certain contracts associated with theRocky Mountain segment of our Mid-America Pipeline System reaching their termination date inSeptember 2021 , which accounted for a$71 million decrease, lower average transportation fees, which accounted for a$58 million decrease, and higher utility and other operating costs, which accounted for an additional$31 million decrease, partially offset by a 120 MBPD (net to our interest) increase in transportation volumes, which accounted for an$88 million increase. Gross operating margin from LPG-related activities at ourEnterprise Hydrocarbons Terminal ("EHT") decreased a net$67 million year-to-year primarily due to lower average loading fees, which accounted for an$84 million decrease, and higher utility and other operating costs, which accounted for an additional$9 million decrease, partially offset by a 54 MBPD increase in LPG export volumes, which accounted for a$25 million increase. NGL fractionation Gross operating margin from NGL fractionation during the year endedDecember 31, 2022 decreased$23 million when compared to the year endedDecember 31, 2021 . Gross operating margin from our Chambers County NGL fractionation complex decreased a net$95 million year-to-year primarily due to$63 million in margins earned on the optimization of our power supply arrangements and$40 million of payments received in connection with our participation in the Texas Load Resources Demand Response Program ("LaaR") during the second quarter of 2021 in connection with theFebruary 2021 winter storms. Gross operating margin from our Chambers County NGL fractionation complex was further impacted by higher utility and other operating costs, which accounted for an additional$50 million decrease, partially offset by a 53 MBPD (net to our interest) increase in fractionation volumes, which accounted for a$54 million increase, and higher average fractionation fees, which accounted for an additional$10 million increase. Gross operating margin from our Norco NGL fractionator increased$24 million year-to-year primarily due to a 12 MBPD increase in fractionation volumes, which accounted for a$10 million increase, higher average fractionation fees, which accounted for an$8 million increase, and higher ancillary service revenues, which accounted for an additional$6 million increase. Gross operating margin from our natural gasoline hydrotreater at ourChambers County complex, which was placed into service inOctober 2021 , increased$22 million year-to-year.
Gross operating margin from our Hobbs NGL fractionator increased
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Crude Oil Pipelines & Services
The following table presents segment gross operating margin and selected volumetric data for the Crude Oil Pipelines & Services segment for the years indicated (dollars in millions, volumes as noted):
For the Year Ended
December 31,
2022 2021Segment gross operating margin:
Other crude oil pipelines, terminals and related marketing results 1,242 1,273 Total$ 1,655 $ 1,680 Selected volumetric data:
Crude oil pipeline transportation volumes (MBPD) 2,222 2,088 Crude oil marine terminal volumes (MBPD) 788 645 Gross operating margin from our Crude Oil Pipelines & Services segment for the year endedDecember 31, 2022 decreased$25 million when compared to the year endedDecember 31, 2021 . Gross operating margin from our EFS Midstream System decreased a net$108 million year-to-year primarily due to lower deficiency revenues as a result of the expiration of minimum volume commitments under certain long-term gathering agreements, which accounted for a$133 million decrease, partially offset by higher average transportation fees, which accounted for an$8 million increase. Our EFS Midstream System will continue to transport volumes produced on dedicated acreage through the remaining term of these agreements, most of which have a life-of-lease duration. Gross operating margin from our equity investment in the Seaway Pipeline decreased$70 million year-to-year primarily due to lower average transportation fees, which accounted for a$39 million decrease, a$16 million decrease due to LaaR payments from power service providers in connection with theFebruary 2021 winter storms, and higher utility and other operating costs, which accounted for an additional$7 million decrease. Transportation volumes on our Seaway Pipeline increased 40 MBPD year-to-year (net to our interest). Gross operating margin from crude oil activities at EHT decreased$20 million year-to-year primarily due to lower storage and other revenues, which accounted for a$12 million decrease, and higher operating costs, which accounted for an additional$5 million decrease. Crude oil terminal volumes at EHT increased 162 MBPD year-to-year. Gross operating margin from our West Texas Pipeline System increased a net$87 million year-to-year primarily due to higher ancillary service and other revenues, which accounted for a$86 million increase, and a 47 MBPD increase in transportation volumes, which accounted for an additional$14 million increase, partially offset by lower average transportation fees, which accounted for a$9 million decrease. Gross operating margin from our crude oil marketing activities (excluding those attributable to theMidland -to-ECHO System) increased$43 million year-to-year primarily due to higher average sales margins, which accounted for a$50 million increase, lower operating costs, which accounted for a$12 million increase, and higher earnings from trucking activities, which accounted for an additional$10 million increase, partially offset by lower non-cash, mark-to-market earnings, which accounted for a$29 million decrease.
Gross operating margin from our
Gross operating margin from our South Texas Crude Oil Pipeline System increased a net$8 million year-to-year primarily due to higher ancillary service and other revenues, which accounted for a$60 million increase, partially offset by lower average transportation fees, which accounted for a$24 million decrease, and lower deficiency revenues as a result of the expiration of minimum volume commitments under certain long-term agreements, which accounted for an additional$23 million decrease. Gross operating margin from ourMidland -to-ECHO System and related business activities increased a net$6 million year-to-year primarily due to a 51 MBPD (net to our interest) increase in transportation volumes, which accounted for a$33 million increase, higher other revenues, which accounted for an additional$17 million increase, partially offset by lower average sales margins, which accounted for a$40 million decrease. 72
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Natural Gas Pipelines & Services
The following table presents segment gross operating margin and selected volumetric data for the Natural Gas Pipelines & Services segment for the years indicated (dollars in millions, volumes as noted):
For the Year Ended
December 31,
2022 2021
Segment gross operating margin $ 1,042 $ 1,155
Selected volumetric data:
Natural gas pipeline transportation volumes (BBtus/d) 17,107 14,249
Gross operating margin from our Natural Gas Pipelines & Services segment for the year endedDecember 31, 2022 decreased$113 million when compared to the year endedDecember 31, 2021 . Gross operating margin from our natural gas marketing activities decreased$272 million year-to-year primarily due to lower average sales margins. As noted previously, the year endedDecember 31, 2021 reflects increased natural gas sales as a result of our efforts to meet the needs of electricity generators, natural gas utilities and industrial customers during theFebruary 2021 winter storms.
Gross operating margin from our
Gross operating margin from our Texas Intrastate System increased$87 million year-to-year primarily due to higher average transportation fees, which accounted for a$61 million increase, and higher ancillary and other revenues, which accounted for an additional$31 million increase. Transportation volumes on our Texas Intrastate System increased 449 BBtus/d year-to-year. OurMidland Basin Gathering System, which represents the natural gas gathering system we acquired inFebruary 2022 as part of our acquisition ofNavitas Midstream , generated gross operating margin of$52 million on gathering volumes of 1,273 BBtus/d following the acquisition date. OurMidland Basin natural gas processing activities are discussed under the NGL Pipelines & Services segment. On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System and San Juan Gathering System in theRocky Mountains increased a net$50 million year-to-year primarily due to higher average gathering fees, which accounted for a$48 million increase, and higher condensate sales, which accounted for an additional$15 million increase, partially offset by a 169 BBtus/d combined decrease in gathering volumes, which accounted for a$10 million decrease. Gross operating margin from our Acadian Gas System and Haynesville Gathering System increased a combined$20 million year-to-year primarily due to an 885 BBtus/d combined increase in transportation volumes. The year-to-year increase in transportation volumes is primarily due to the Gillis Lateral pipeline, which was placed into service inDecember 2021 . 73
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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,
2022 2021Segment gross operating margin:
Propylene production and related activities $
564
Butane isomerization and related operations 114 75 Octane enhancement and related plant operations 394 107 Refined products pipelines and related activities 277 290 Ethylene exports and related activities 123 73 Marine transportation and other services 45 14 Total$ 1,517 $ 1,357 Selected volumetric data: Propylene production volumes (MBPD) 101 99 Butane isomerization volumes (MBPD) 108 85 Standalone DIB processing volumes (MBPD) 159 154 Octane enhancement and related plant sales volumes (MBPD) (1) 39 33
Pipeline transportation volumes, primarily refined products and
petrochemicals (MBPD) 747 890
Marine terminal volumes, primarily refined products and
petrochemicals (MBPD) 202 234
(1) Reflects aggregate sales volumes for our octane enhancement 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, 2022 decreased $234 million when compared to the year
ended December 31, 2021 . Gross operating margin from our Chambers County
propylene production facilities decreased a combined net $218 million
year-to-year primarily due to lower average propylene sales margins, which
accounted for a $150 million decrease, lower average processing fees, which
accounted for a $90 million decrease, and higher utility, amortization expense
from major maintenance activities accounted for under the deferral method and
other operating costs, which accounted for an additional $67 million decrease,
partially offset by an increase in propylene sales volumes, which accounted for
a $70 million increase, and higher by-product sales and other revenues, which
accounted for an additional $19 million increase. Propylene and associated
by-product production volumes at these facilities increased a combined 3 MBPD
year-to-year (net to our interest).
Butane isomerization and related operations
Gross operating margin from butane isomerization and related operations
increased $39 million year-to-year primarily due to an increase in isomerization
volumes, which accounted for a $22 million increase, and higher average
isomerization fees, which accounted for an additional $15 million increase.
Octane enhancement and related plant operations
Gross operating margin from our octane enhancement and related plant operations
increased a net $287 million year-to-year primarily due to higher average sales
margins, which accounted for a $180 million increase, and an increase in sales
volumes, which accounted for an additional $151 million increase, partially
offset by higher utility costs, amortization expense from major maintenance
activities accounted for under the deferral method and other operating costs,
which accounted for a $41 million decrease. The year-to-year increase in sales
volumes at these facilities is primarily due to planned major maintenance
activities during 2021, 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.
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Refined products pipelines and related activities Gross operating margin from refined products pipelines and related activities for the year endedDecember 31, 2022 decreased$13 million when compared to the year endedDecember 31, 2021 . Gross operating margin from our TE Products Pipeline System decreased a net$18 million year-to-year primarily due to higher operating costs, which accounted for a$29 million decrease, partially offset by higher ancillary service revenues, which accounted for a$15 million increase. Overall, transportation volumes on our TE Products Pipeline System decreased a net 183 MBPD year-to-year.
Gross operating margin at our refined products terminal in
Gross operating margin from our refined products marketing activities increased
Ethylene exports and related activities Gross operating margin from ethylene exports and related activities for the year endedDecember 31, 2022 increased$50 million when compared to the year endedDecember 31, 2021 . Gross operating margin from our ethylene export terminal increased$30 million year-to-year primarily due to a 9 MBPD (net to our interest) increase in export volumes. Gross operating margin from our other ethylene activities increased$20 million year-to-year primarily due to a 26 MBPD increase in transportation volumes, which accounted for a$13 million increase, and higher storage revenues, which accounted for an additional$8 million increase. Marine transportation and other services Gross operating margin from marine transportation and other services increased$31 million year-to-year primarily due to higher average fees and fleet utilization rates.
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, 2022 , we had$4.1 billion of consolidated liquidity. This amount was comprised of$4.0 billion of available borrowing capacity under EPO's revolving credit facilities, which is the net of$4.5 billion of total borrowing capacity under EPO's revolving credit facilities and$495 million outstanding under EPO's commercial paper program, and$76 million of unrestricted cash on hand.
We may issue debt and equity securities to assist us in meeting our future
funding and liquidity requirements, including those related to capital
investments. We have a universal shelf registration statement (the "2021
Shelf") on file with the
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Cash Flow Statement Highlights
The following table summarizes our consolidated cash flows from operating,
investing and financing activities for the years indicated (dollars in
millions).
For the Year Ended
December 31,
2022 2021
Net cash flows provided by operating activities
4,954 2,135
Cash used in financing activities 5,844 4,571
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, petrochemicals
and refined products, which could impact sales of our products and the demand
for our midstream services. Changes in demand for our products and services may
be caused by other factors, including prevailing economic conditions, reduced
demand by consumers for the end products made with hydrocarbon products,
increased competition, public health emergencies, adverse weather conditions and
government regulations affecting prices and production levels. We may also
incur credit and price risk to the extent customers do not fulfill their
contractual obligations to us in connection with our marketing activities and
long-term take-or-pay agreements. For a more complete discussion of these and
other risk factors pertinent to our business, see Part I, Item 1A of this annual
report.
For additional information regarding our cash flow amounts, please refer to the
Statements of Consolidated Cash Flows included under Part II, Item 8 of this
annual report.
The following information highlights significant year-to-year fluctuations in our consolidated cash flow amounts:
Operating activities Net cash flows provided by operating activities for the year endedDecember 31, 2022 decreased a net$474 million when compared to the year endedDecember 31, 2021 primarily due to:
• a
primarily due to the use of working capital employed in our marketing
activities, which includes the impact of (i) fluctuations in commodity prices,
(ii) timing of our inventory purchase and sale strategies, and (iii) changes in
margin deposit requirements associated with our commodity derivative instruments; partially offset by
• a
(determined by adjusting our
for changes in the non-cash items identified on our Statements of Consolidated
Cash Flows). 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, 2022 increased a net$2.8 billion when compared to the year endedDecember 31, 2021 primarily due to:
• a net
acquisition of
• a
equipment (see "Capital Investments" within this Part II, Item 7 for additional
information).
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Financing activities Cash used in financing activities for the year endedDecember 31, 2022 increased$1.3 billion when compared to the year endedDecember 31, 2021 primarily due to:
• a net cash outflow of
during the year ended
million related to debt transactions that occurred during the year ended
of senior and junior subordinated notes, partially offset by net issuances of
billion aggregate principal amount of senior notes, partially offset by the
issuance of
• a
unitholders primarily attributable to increases in the quarterly cash
distribution rate per unit.
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.
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.
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The following table summarizes our calculation of DCF for the years indicated
(dollars in millions):
For the Year Ended
December 31,
2022 2021
Net income attributable to common unitholders (GAAP) (1)
derive DCF (addition or subtraction indicated by sign): Depreciation, amortization and accretion expenses
2,245 2,140
Cash distributions received from unconsolidated affiliates (2)
544 590
Equity in income of unconsolidated affiliates (464 ) (583 ) Asset impairment charges 53
233
Change in fair market value of derivative instruments 78 (27 ) Deferred income tax expense 60
40
Sustaining capital expenditures (3) (372 ) (430 ) Other, net (4) (2 ) (128 ) Operational DCF (5)$ 7,629 $ 6,469 Proceeds from asset sales and other matters 122
64
Monetization of interest rate derivative instruments accounted for as cash flow hedges - 75 DCF (non-GAAP)$ 7,751 $ 6,608
Cash distributions paid to common unitholders with respect to period,
including distribution equivalent rights on phantom unit awards
$ 4,181
Cash distribution per common unit declared by Enterprise GP with respect to period (6)
$ 1.9050
Total DCF retained by the Partnership with respect to period (7)
$ 3,570
Distribution coverage ratio (8) 1.85 x
1.66 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.
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,
2022 2021
Net cash flows provided by operating activities (GAAP)
DCF (addition or subtraction indicated by sign): Net effect of changes in operating accounts 54 (1,366 ) Sustaining capital expenditures (372 ) (430 )
Distributions received from unconsolidated affiliates attributable
to the return of capital 98 46
Proceeds from asset sales and other matters 122 64
Net income attributable to noncontrolling interests (125 ) (117 )
Monetization of interest rate derivative instruments
accounted
for as cash flow hedges - 75
Other, net (65 ) (177 )
DCF (non-GAAP) $ 7,751 $ 6,608
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Table of Contents Capital Investments We have approximately$5.8 billion of growth capital projects scheduled to be completed by the end of 2025 including the following projects (including their respective scheduled completion dates):
• natural gas gathering expansion projects in the
(2023);
• our PDH 2 facility (second quarter of 2023);
• a 400 MMcf/d expansion of our Acadian Gas System (second quarter of 2023);
• our Poseidon natural gas processing plant in the
of 2023);
• a twelfth NGL fractionator ("Frac XII") in
quarter of 2023);
• our Mentone II natural gas processing plant in the
quarter of 2023);
• our Texas Western Products System, created by repurposing a portion of our
Mid-America Pipeline System's
service to our Chaparral Pipeline business to transport refined products from
the
(fourth quarter of 2023);
• our Mentone III natural gas processing plant in the
quarter of 2024);
• our Leonidas natural gas processing plant in the
of 2024);
• the expansion of our Shin Oak NGL Pipeline (first half of 2025);
• an
• an expansion of our Morgan's Point terminal to increase ethylene export
capacity (2024 and 2025).
InFebruary 2022 , we acquiredNavitas Midstream from an affiliate of Warburg Pincus LLC for$3.2 billion in net cash consideration, which was funded using proceeds from the issuance of short-term notes under EPO's commercial paper program and cash on hand. Shortly after closing on this transaction, we completed construction of the Leiker Plant and placed it into service inMarch 2022 . Based on information currently available, we expect our total capital investments for 2023, net of contributions from noncontrolling interests, to approximate$2.7 billion to$2.9 billion , which reflects growth capital investments of$2.3 billion to$2.5 billion and sustaining capital expenditures of$400 million . These amounts do not include capital investments associated with SPOT, our proposed deep-water offshore crude oil terminal, which remains subject to state and federal permitting, mitigation and related requirements. We received a favorable ROD from theDepartment of Transportation's Maritime Administration for SPOT during the fourth quarter of 2022 and expect to satisfy the remaining conditions to obtain the deep-water port license in 2023; however, we can give no assurance as to when or whether the project will ultimately be authorized to begin construction or operation. 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 resulting from raw material or labor shortages, supply chain disruptions or inflation. Furthermore, our forecast of capital investments may change over time based on future decisions by management, which may include changing the scope or timing of projects or cancelling projects altogether. Our success in raising capital, having the ability to increase revenues commensurate with cost increases and our ability to partner with other companies to share project costs and risks, continue to be significant factors 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 currently expect to make the forecast capital investments noted above, we may revise our plans in response to changes in economic and capital market conditions. 79
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The following table summarizes our capital investments for the years indicated
(dollars in millions):
For the Year Ended
December 31,
2022 2021Capital investments for property, plant and equipment: (1) Growth capital projects (2)
$ 1,606 $ 1,807 Sustaining capital projects (3) 358
416
Total$ 1,964
Cash used for business combinations, net (4)$ 3,204
$ -
Investments in unconsolidated affiliates$ 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.
(4) Amount for the year ended
acquisition of
Comparison of Year Ended
In total, investments in growth capital projects decreased a net
• lower investments at our
natural gasoline hydrotreater in
spending on our PDH 2 facility, partially offset by a year-to-year increase in
spending on Frac XII), which accounted for a net
• completion of our Gillis Lateral natural gas pipeline in
accounted for a
• completion of pipeline projects connecting our
• lower investments in projects attributable to our ethylene business (e.g.,
completion of our Baymark ethylene pipeline in
for a
• higher investments in natural gas processing and gathering projects in the
related gathering systems), which accounted for a
• the purchase of approximately 580 miles of pipelines and related assets for
allow us to optimize and expand our NGL and petrochemical systems on the Gulf
Coast. Investments attributable to sustaining capital projects decreased$58 million year-to-year primarily due to lower major maintenance activities performed at certain of our reaction-based plants (PDH 1, octane enhancement and HPIB facilities) and fluctuations in timing and costs of pipeline integrity and similar projects. 80
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Table of Contents Consolidated Debt AtDecember 31, 2022 , the average maturity of EPO's consolidated debt obligations was approximately 20.0 years. The following table presents the scheduled maturities of principal amounts of EPO's consolidated debt obligations and associated estimated cash payments for interest atDecember 31, 2022 for the years indicated (dollars in millions): Total 2023 2024 2025 2026 2027 Thereafter Principal amount of debt obligations$ 28,566 $ 1,745 $ 850 $ 1,150 $ 875 $ 575 $ 23,371 Estimated cash payments for interest (1) 27,324 1,239 1,200 1,158 1,124 1,100 21,503
(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 2022, as
applicable, for each note through the respective maturity date.
In
InAugust 2022 , EPO redeemed$350 million of the$700 million outstanding principal amount of its Junior Subordinated Notes D at a redemption price equal to 100% of the principal amount of the notes being redeemed plus accrued and unpaid interest thereon to, but not including, the redemption date. The redemption was funded using cash on hand and proceeds from issuances under EPO's commercial paper program. InSeptember 2022 , EPO entered into a new$1.5 billion 364-Day Revolving Credit Agreement (the "September 2022 $1.5 Billion 364-Day Revolving Credit Agreement") that replaced itsSeptember 2021 364-Day Revolving Credit Agreement. TheSeptember 2022 $1.5 Billion 364-Day Revolving Credit Agreement matures inSeptember 2023 . EPO's borrowing capacity was unchanged from the prior 364-day revolving credit agreement. As ofDecember 31, 2022 , there are no principal amounts outstanding under this new revolving credit agreement. InJanuary 2023 , EPO issued$1.75 billion aggregate principal amount of senior notes comprised of (i)$750 million principal amount of senior notes dueJanuary 2026 ("Senior Notes FFF") and (ii)$1.0 billion principal amount of senior notes dueJanuary 2033 ("Senior Notes GGG"). Senior Notes FFF were issued at 99.893% of their principal amount and have a fixed-rate interest rate of 5.05% per year. Senior Notes GGG were issued at 99.803% of their principal amount and have a fixed-rate interest rate of 5.35% per year. Net proceeds from this offering will be used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of all or a portion of our$1.25 billion principal amount of 3.35% Senior Notes HH at their maturity inMarch 2023 and amounts outstanding under our commercial paper program). For additional information regarding our consolidated debt obligations, see Note 7 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. Credit Ratings As ofFebruary 28, 2023 , 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. 81
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Table of Contents Product Purchase Commitments
The following table presents our unconditional product purchase commitments at
Total 2023 2024 2025 2026 2027 Thereafter
Product
purchase
commitments $ 17,644 $ 3,401 $ 3,338 $ 2,960 $ 2,318 $ 2,205 $ 3,422
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, 2022 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
17 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 2022
OnJanuary 5, 2023 , we announced that the Board declared a quarterly cash distribution of$0.49 per common unit, or$1.96 per common unit on an annualized basis, to be paid to the Partnership's common unitholders with respect to the fourth quarter of 2022. The quarterly distribution was paid onFebruary 14, 2023 to unitholders of record as of the close of business onJanuary 31, 2023 . The total amount paid was$1.07 billion , which includes$9 million for distribution equivalent rights on phantom unit awards. 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. 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 2.75 to 3.25 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 10,166,923 common units under the 2019 Buyback Program through open market purchases during the year endedDecember 31, 2022 . The total cost of these repurchases, including commissions and fees, was$250 million . Common units repurchased under the 2019 Buyback Program are immediately cancelled upon acquisition. As ofDecember 31, 2022 , the remaining available capacity under the 2019 Buyback Program was$1.3 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:
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Valuation of Assets and Liabilities Acquired in a Business Combination
For acquisitions accounted for as business combinations, we allocate the purchase price of an acquired business to its identifiable assets and liabilities based on estimated fair values. The excess of the purchase price over the amount allocated to the acquired identifiable assets and liabilities, if any, is recorded as goodwill. Our purchase price allocation methodology contains uncertainties because it requires management to make assumptions and to apply judgment to estimate the fair value of acquired assets and liabilities. Management estimates the fair value of assets and liabilities based upon quoted market prices, the carrying value of certain acquired assets and widely accepted valuation techniques, including discounted cash flows. Our estimates of fair value are based upon assumptions we believe to be reasonable, but which are inherently uncertain and unpredictable. When appropriate, we engage third-party valuation specialists to assist in the fair value determination of acquired tangible and intangible assets. The purchase price allocation recorded in a business combination may change during the measurement period, which is a period not to exceed one year from the date of acquisition, as additional information about conditions existing at the acquisition date becomes available. InFebruary 2022 , we acquired all of the member interests inNavitas Midstream Partners, LLC for$3.2 billion in net cash consideration. For information regarding this business combination, see Note 12 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
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, 2022 and 2021, the net carrying value of our property, plant and equipment was$44.4 billion and$42.1 billion , respectively. We recorded$1.8 billion and$1.7 billion of depreciation expense during the years endedDecember 31, 2022 and 2021, 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.
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 discounted 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.
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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 2022 and 2021, we recognized non-cash asset impairment charges attributable to assets other than goodwill totaling$53 million and$233 million , respectively, which are a component of operating costs and expenses. For information regarding impairment charges involving property, plant and equipment see Note 4 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. We did not recognize any impairment charges in connection with our equity-method investments during the years endedDecember 31, 2022 andDecember 31, 2021 .
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.
Customer relationship intangible assets represent the estimated economic value
assigned to commercial relationships acquired in connection with business
combinations. In certain instances, the acquisition of these intangible assets
provides us with access to customers in a defined resource basin and is
analogous to having a franchise in a particular area. Efficient operation of the
acquired assets (e.g., a natural gas gathering system) helps to support the
commercial relationships with existing producers and provides us with
opportunities to establish new ones within our existing asset footprint. The
duration of this type of customer relationship is limited by the estimated
economic life of the associated resource basin that supports the customer
group. When estimating the economic life of a resource basin, we consider a
number of factors, including reserve estimates and the economic viability of
production and exploration activities.
In other situations, the acquisition of a customer relationship intangible asset
provides us with access to customers whose hydrocarbon volumes are not
attributable to specific resource basins. As with basin-specific customer
relationships, efficient operation of the associated assets (e.g., a marine
terminal that handles volumes originating from multiple sources) helps to
support the commercial relationships with existing customers and provides us
with opportunities to establish new ones. The duration of this type of customer
relationship is typically limited to the term of the underlying service
contracts, including assumed renewals.
The value we assign to customer relationships is amortized to earnings using
methods that closely resemble the pattern in which the estimated economic
benefits will be consumed (i.e., the manner in which the intangible asset is
expected to contribute directly or indirectly to our cash flows). For example,
the amortization period for a basin-specific customer relationship asset is
limited by the estimated finite economic life of the associated hydrocarbon
resource basin.
Contract-based intangible assets represent specific commercial rights we own
arising from discrete contractual agreements. A contract-based intangible asset
with a finite life is amortized over its estimated economic life, which is the
period over which the contract is expected to contribute directly or indirectly
to our cash flows. Our estimates of the economic life of contract-based
intangible assets are based on a number of factors, including (i) the expected
useful life of the related tangible assets (e.g., a marine terminal, pipeline or
other asset), (ii) any legal or regulatory developments that would impact such
contractual rights and (iii) any contractual provisions that enable us to renew
or extend such arrangements.
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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. AtDecember 31, 2022 and 2021, the carrying value of our customer relationship and contract-based intangible asset portfolio was$4.0 billion and$3.2 billion , respectively. We recorded$177 million and$151 million of amortization expense attributable to intangible assets during the years endedDecember 31, 2022 and 2021, 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$5.6 billion and$5.4 billion atDecember 31, 2022 and 2021, respectively.Goodwill , which represents the cost of an acquired business in excess of the fair value of its net assets at the acquisition date, is subject to annual impairment testing in the fourth quarter of each year or when events or changes in circumstances indicate that the carrying amount of the goodwill may not be recoverable.Goodwill impairment charges represent the amount by which a reporting unit's carrying value (including its respective goodwill) exceeds its fair value, not to exceed the carrying amount of the reporting unit's goodwill. 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, 2022 . Based on our most recent goodwill impairment test atDecember 31, 2022 , 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.
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.
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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, 2022 , the total amount of Guaranteed Debt was$29.0 billion , which was comprised of$25.8 billion of EPO's senior notes,$2.3 billion of EPO's junior subordinated notes,$495 million of short-term commercial paper notes and$426 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$47.5 billion atDecember 31, 2022 .The Obligor Group's equity in the earnings of the Non-Obligor Subsidiaries for the year endedDecember 31, 2022 was$5.9 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. 86
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The following table presents summarized balance sheet information for the
combined
Selected asset information:
Current receivables from Non-Obligor Subsidiaries $
1,012
Other current assets
4,949
Long-term receivables from Non-Obligor Subsidiaries
187
Other noncurrent assets, excluding investments in Non-Obligor
Subsidiaries of
9,130
Selected liability information:
Current portion of Guaranteed Debt, including interest of
$ 2,171
Current payables to Non-Obligor Subsidiaries
1,899
Other current liabilities
4,121
Noncurrent portion of Guaranteed Debt, principal only
26,807
Noncurrent payables to Non-Obligor Subsidiaries 38 Other noncurrent liabilities 98
Mezzanine equity of
Preferred units$ 49
The following table presents summarized income statement information for the
combined
Revenues from Non-Obligor Subsidiaries $
14,145
Revenues from other sources
27,312
Operating income ofObligor Group
836
Net loss of
(450 ) Related Party Transactions For information regarding our related party transactions, see Note 15 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report as well as Part III, Item 13 of this annual report.
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. Insurance
For information regarding insurance matters, see Note 18 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
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