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KINDER MORGAN, INC. - Annual Report: 2021 (Form 10-K)


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_____________
Form 10-K
☑ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2021
or
☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____
Commission file number: 001-35081
kmi-20211231_g1.gif
Kinder Morgan, Inc.
(Exact name of registrant as specified in its charter) 
Delaware80-0682103
(State or other jurisdiction of
incorporation or organization)		(I.R.S. Employer
Identification No.)
1001 Louisiana Street, Suite 1000, Houston, Texas 77002
(Address of principal executive offices) (zip code)

Registrant’s telephone number, including area code: 713-369-9000
____________
 
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Class P Common StockKMINew York Stock Exchange
1.500% Senior Notes due 2022KMI 22New York Stock Exchange
2.250% Senior Notes due 2027KMI 27 ANew York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes ☑ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes ☐  No ☑
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes ☑  No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes ☑  No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “non-accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☑  Accelerated filer ☐  Non-accelerated filer ☐  Smaller reporting company ☐  Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report.  ☑
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes ☐  No ☑
Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on closing prices in the daily composite list for transactions on the New York Stock Exchange on June 30, 2021 was approximately $36,152,128,132.  As of February 4, 2022, the registrant had 2,267,484,557 shares of Class P common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 2022 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2022, are incorporated into PART III, as specifically set forth in PART III.


KINDER MORGAN, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
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KINDER MORGAN, INC. AND SUBSIDIARIES (continued)
TABLE OF CONTENTS
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KINDER MORGAN, INC. AND SUBSIDIARIES
GLOSSARY
Company Abbreviations
Calnev=Calnev Pipe Line LLCKMP=Kinder Morgan Energy Partners, L.P. and its majority-owned and/or controlled subsidiaries
CIG=Colorado Interstate Gas Company, L.L.C.
CPGPL=
Cheyenne Plains Gas Pipeline Company, L.L.C.
KMTP=
Kinder Morgan Texas Pipeline LLC
EagleHawk=EagleHawk Field Services LLCMEP=
Midcontinent Express Pipeline LLC
Elba Express=Elba Express Company, L.L.C.NGPL=Natural Gas Pipeline Company of America LLC and certain affiliates
EIG=EIG Global Energy Partners
ELC=Elba Liquefaction Company, L.L.C.PHP=Permian Highway Pipeline LLC
EPNG=El Paso Natural Gas Company, L.L.C.Ruby=Ruby Pipeline Holding Company, L.L.C.
FEP=Fayetteville Express Pipeline LLCSFPP=SFPP, L.P.
Hiland=Hiland Partners, LPSLNG=Southern LNG Company, L.L.C.
KinderHawk=KinderHawk Field Services LLCSNG=Southern Natural Gas Company, L.L.C.
Kinetrex=Kinetrex EnergyTGP=Tennessee Gas Pipeline Company, L.L.C.
KMBT=Kinder Morgan Bulk Terminals, Inc.TMEP=Trans Mountain Expansion Project
KMI=Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiariesTMPL=Trans Mountain Pipeline System
Trans Mountain=Trans Mountain Pipeline ULC
KML=Kinder Morgan Canada Limited and its majority-owned and/or controlled subsidiaries
WIC=
Wyoming Interstate Company, L.L.C.
KMLP=Kinder Morgan Louisiana Pipeline LLCWYCO=WYCO Development L.L.C.
KMLT=Kinder Morgan Liquid Terminals, LLC
Unless the context otherwise requires, references to “we,” “us,” “our,” or “the Company” are intended to mean Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries.
Common Industry and Other Terms
/d=per dayGAAP=United States Generally Accepted Accounting Principles
AFUDC=allowance for funds used during construction
Bbl=barrelsLIBOR=London Interbank Offered Rate
BBtu=billion British Thermal UnitsLLC=limited liability company
Bcf=billion cubic feetLNG=liquefied natural gas
CERCLA=Comprehensive Environmental Response, Compensation and Liability ActMBbl=thousand barrels
MMBbl=million barrels
C$=Canadian dollarsMMtons=million tons
CO2
=
carbon dioxide or our CO2 business segment
NEB=Canadian National Energy Board
COVID-19=Coronavirus Disease 2019, a widespread contagious disease, or the related pandemic declared and resulting worldwide economic downturnNGL=natural gas liquids
NYMEX=New York Mercantile Exchange
CPUC=California Public Utilities CommissionNYSE=New York Stock Exchange
DCF=distributable cash flowOTC=over-the-counter
DD&A=depreciation, depletion and amortization PHMSA=United States Department of Transportation Pipeline and Hazardous Materials Safety Administration
Dth=dekatherms
EBDA=earnings before depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments
ROU=Right-of-Use
RNG=renewable natural gas
EBITDA=earnings before interest, income taxes, depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments
SEC=United States Securities and Exchange Commission
U.S.=United States of America
EPA=United States Environmental Protection AgencyWTI=West Texas Intermediate
FASB=Financial Accounting Standards Board
FERC=Federal Energy Regulatory Commission
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Information Regarding Forward-Looking Statements

This report includes forward-looking statements.  These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts.  They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “outlook,” “continue,” “estimate,” “expect,” “may,” “will,” “shall,” or the negative of those terms or other variations of them or comparable terminology.  In particular, expressed or implied statements concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow, service debt or pay dividends, are forward-looking statements.  Forward-looking statements in this report include, among others, express or implied statements pertaining to: the long-term demand for our assets and services, and our anticipated dividends and capital projects, including expected completion timing and benefits of those projects.

Forward-looking statements are not guarantees of performance.  They involve risks, uncertainties and assumptions.  Future actions, conditions or events and future results may differ materially from those expressed in our forward-looking statements.  Many of the factors that will determine these results are beyond our ability to control or accurately predict.  Specific factors that could cause actual results to differ from those in our forward-looking statements include:

•changes in supply of and demand for natural gas, NGL, refined petroleum products, oil, renewable fuels, CO2, electricity, petroleum coke, steel and other bulk materials and chemicals and certain agricultural products in North America;

•economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand;

•competition from other pipelines, terminals or other forms of transportation, or from emerging technologies such as CO2 capture and sequestration;

•changes in our tariff rates required by the FERC, the CPUC or another regulatory agency;

•the timing and success of our business development efforts, including our ability to renew long-term customer contracts at economically attractive rates;

•our ability to safely operate and maintain our existing assets and to access or construct new assets including pipelines, terminals, gas processing, gas storage and NGL fractionation capacity;

•our ability to attract and retain key management and operations personnel;

•difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from our terminals or pipelines;

•shut-downs or cutbacks at major refineries, petrochemical or chemical plants, natural gas processing plants, ports, utilities, military bases or other businesses that use our services or provide services or products to us;

•changes in crude oil and natural gas production (and the NGL content of natural gas production) from exploration and production areas that we serve, such as the Permian Basin area of West Texas, the shale plays in North Dakota, Ohio, Oklahoma, Pennsylvania and Texas, and the U.S. Rocky Mountains;

•changes in laws or regulations, third-party relations and approvals, and decisions of courts, regulators and governmental bodies that may increase our compliance costs, restrict our ability to provide or reduce demand for our services, or otherwise adversely affect our business;

•interruptions of operations at our facilities due to natural disasters, damage by third parties, power shortages, strikes, riots, terrorism (including cyber attacks), war or other causes;

•compromise of our IT systems, operational systems or sensitive data as a result of errors, malfunctions, hacking events or coordinated cyber attacks;

•the uncertainty inherent in estimating future oil, natural gas, and CO2 production or reserves;

•issues, delays or stoppage associated with new construction or expansion projects;
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•regulatory, environmental, political, grass roots opposition, legal, operational and geological uncertainties that could affect our ability to complete our expansion projects on time and on budget or at all;

•our ability to acquire new businesses and assets and integrate those operations into our existing operations, and make cost-saving changes in operations, particularly if we undertake multiple acquisitions in a relatively short period of time, as well as our ability to expand our facilities;

•the ability of our customers and other counterparties to perform under their contracts with us including as a result of our customers’ financial distress or bankruptcy;

•changes in accounting pronouncements that impact the measurement of our results of operations, the timing of when such measurements are to be made and recorded, and the disclosures surrounding these activities;

•changes in tax laws;

•our ability to access external sources of financing in sufficient amounts and on acceptable terms to the extent needed to fund acquisitions of operating businesses and assets and expansions of our facilities;

•our indebtedness, which could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, place us at a competitive disadvantage compared to our competitors that have less debt, or have other adverse consequences;

•our ability to obtain insurance coverage without significant levels of self-retention of risk;

•natural disasters, sabotage, terrorism (including cyber attacks) or other similar acts or accidents causing damage to our properties greater than our insurance coverage limits;

•possible changes in our and our subsidiaries’ credit ratings;

•conditions in the capital and credit markets, inflation and fluctuations in interest rates;

•political and economic instability of the oil producing nations of the world;

•national, international, regional and local economic, competitive and regulatory conditions and developments, including the effects of any enactment of import or export duties, tariffs or similar measures;

•our ability to achieve cost savings and revenue growth;

•the extent of our success in developing and producing CO2 and oil and gas reserves, including the risks inherent in development drilling, well completion and other development activities;

•engineering and mechanical or technological difficulties that we may experience with operational equipment, in well completions and work-overs, and in drilling new wells;

•unfavorable results of litigation and the outcome of contingencies referred to in Note 18 “Litigation and Environmental” to our consolidated financial statements; and

•the long-term demand for our assets and services and the future impact on our business of the global economic consequences of the COVID-19 pandemic.

The foregoing list should not be construed to be exhaustive.  We believe the forward-looking statements in this report are reasonable.  However, there is no assurance that any of the actions, events or results expressed in forward-looking statements will occur, or if any of them do, of their timing or what impact they will have on our results of operations or financial condition.  Because of these uncertainties, you should not put undue reliance on any forward-looking statements.

Additional discussion of factors that may affect our forward-looking statements appear elsewhere in this report, including in Item 1A “Risk Factors,” Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Energy Commodity Market Risk.” When
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considering forward-looking statements, you should keep in mind the factors described in this section and the other sections referenced above. We disclaim any obligation, other than as required by applicable law, to publicly update or revise any of our forward-looking statements to reflect future events or developments.

PART I

Items 1 and 2. Business and Properties.
We are one of the largest energy infrastructure companies in North America. We own an interest in or operate approximately 83,000 miles of pipelines and 143 terminals. Our pipelines transport natural gas, renewable fuels, refined petroleum products, crude oil, condensate, CO2 and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, chemicals, biodiesel, renewable fuels, metals and petroleum coke.

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General Development of Business

Recent Developments

The following is a listing of significant developments and updates related to our major projects and financing transactions. “Capital Scope” is estimated for our share of the described project which may include portions not yet completed.
Asset or projectDescriptionActivityApprox. Capital Scope (KMI Share)
Placed in service, acquisitions or divestitures
NGPLWe and Brookfield Infrastructure Partners L.P. (Brookfield) sold a combined 25% interest in NGPL to ArcLight Capital Partners, LLC and we and Brookfield each now own a 37.5% interest.Completed in March 2021.n/a
Stagecoach assetsAcquired Stagecoach Gas Services LLC and its subsidiaries, a natural gas pipeline and storage joint venture between Consolidated Edison, Inc. and Crestwood Equity Partners, LP. Assets include 4 natural gas storage facilities and a network of natural gas transportation pipelines in the northeast region of the U.S.Acquired in July and November 2021.$1,258 million
KinetrexAcquired Kinetrex from an affiliate of Parallel49 Equity. Kinetrex is a supplier of LNG in the Midwest and a producer and supplier of RNG.Acquired in August 2021.$318 million
KMLP Acadiana ExpansionExpansion project provides 945,000 Dth/d of capacity to serve Train 6 at Cheniere’s Sabine pass LNG terminal. Project supported by long-term contracts.Placed in service October 2021.$127 million
NGPL Gulf Coast Southbound Expansion (second phase)Expansion project increases southbound capacity on NGPL’s Gulf Coast System by approximately 300,000 Dth/d serving Corpus Christi Liquefaction. Subscribed under a long-term firm transportation contract.Full project placed in service March 2021.$101 million
Other Announcements
Natural Gas Pipelines
TGP East 300 UpgradeExpansion project involves upgrading compression facilities upstream on TGP’s system in order to provide 115,000 Dth/d of capacity to Con Edison’s distribution system in Westchester County, New York. Supported by a long-term contract with Con Edison.Expected in-service date is November 2023, pending receipt of all required permits. $246 million
CO2 - Energy Transition Ventures
RNG facilitiesConstruction of three additional landfill-based RNG facilities for Kinetrex in order to provide approximately 3.5 Bcf of RNG a year. Supported by a long-term contract.First facility expected to be in service by September 2022 and final facility by January 2023.$146 million

Financings

During 2021, we issued $1,550 million of new senior notes and repaid $2.4 billion of maturing senior notes. In addition, we entered into a new $3.5 billion revolving credit facility, maturing August 2026, which may be used for working capital and other general corporate purposes and amended our existing revolving credit facility, maturing November 2023, to reduce the capacity to $500 million.

Narrative Description of Business

Business Strategy

Our business strategy is to:

•focus on stable, fee-based energy transportation and storage assets that are central to the energy infrastructure and energy transition of growing markets within North America or served by U.S. exports;
•increase utilization of our existing assets while controlling costs, operating safely, and employing environmentally sound operating practices;
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•exercise discipline in capital allocation and in evaluating expansion projects and acquisition opportunities;
•leverage economies of scale from acquisitions and asset expansions that fit within our strategy; and
•maintain a strong financial profile and enhance and return value to our stockholders.

It is our intention to carry out the above business strategy, modified as necessary to reflect changing economic conditions and other circumstances. However, as discussed under Item 1A. “Risk Factors” below and at the beginning of this report in “Information Regarding Forward-Looking Statements,” there are factors that could affect our ability to carry out our strategy or affect its level of success even if carried out.

We regularly consider and enter into discussions regarding potential acquisitions and divestitures, and we are currently contemplating potential transactions. Any such transaction would be subject to negotiation of mutually agreeable terms and conditions, and, as applicable, receipt of fairness opinions, and approval of our board of directors. While there are currently no unannounced purchase or sale agreements for the acquisition or sale of any material business or assets, such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations.

Business Segments

For financial information on our reportable business segments, see Note 16 “Reportable Segments” to our consolidated financial statements.

Natural Gas Pipelines

Our Natural Gas Pipelines business segment includes interstate and intrastate pipelines, underground storage facilities and our LNG liquefaction and terminal facilities, and includes both FERC regulated and non-FERC regulated assets.

Our primary businesses in this segment consist of natural gas transportation, storage, sales, gathering, processing and treating, and various LNG services.  Within this segment are: (i) approximately 45,000 miles of wholly owned natural gas pipelines and (ii) our equity interests in entities that have approximately 27,000 miles of natural gas pipelines, along with associated storage and supply lines for these transportation networks, which are strategically located throughout the North American natural gas pipeline grid.  Our transportation network provides access to the major natural gas supply areas and consumers in the western U.S., Louisiana, Texas, Northeast, Rocky Mountain, Midwest and Southeastern regions. Our LNG terminal facilities also serve natural gas market areas in the southeast. The following tables summarize our significant Natural Gas Pipelines business segment assets, as of December 31, 2021. The design capacity represents transmission, gathering, regasification or liquefaction capacity, depending on the nature of the asset.

Asset (KMI ownership shown if not 100%) Miles of Pipeline Design (Bcf/d) [(MBbl/d)] CapacityStorage (Bcf) [Processing (Bcf/d)] CapacitySupply and Market Region
East Region
TGP(a)11,755 12.23 76 Marcellus, Utica, Gulf Coast, Haynesville and Eagle Ford shale supply basins; Northeast, Southeast, Gulf Coast and U.S.-Mexico border markets
NGPL (37.5%)9,105 7.84 288 Chicago and other Midwest markets and all central U.S. supply basins; north to south deliveries, including deliveries to LNG facilities and to the U.S.-Mexico border markets
KMLP140 3.89 — Columbia Gulf, ANR Pipeline Company and various other pipeline interconnects; Cheniere Sabine Pass LNG and industrial markets
Stagecoach Gas Services LLC185 3.22 41 Marcellus, Appalachia; Northeast markets
SNG (50%)(a)6,925 4.44 66 Basins in Texas, Oklahoma, Louisiana, Mississippi and Alabama; Southeast markets
Florida Gas Transmission (Citrus) (50%)5,365 4.04 — Texas to Florida; basins along Louisiana and Texas Gulf Coast, Mobile Bay and offshore Gulf of Mexico
MEP (50%)515 1.81 — Oklahoma and north Texas supply with interconnects to Transco, Columbia Gulf, SNG and various other pipelines
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Asset (KMI ownership shown if not 100%) Miles of Pipeline Design (Bcf/d) [(MBbl/d)] CapacityStorage (Bcf) [Processing (Bcf/d)] CapacitySupply and Market Region
Elba Express190 1.10 — South Carolina to Georgia; connects to SNG, Transco, SLNG, ELC and Dominion Energy Carolina Gas Transmission
FEP (50%)185 2.00 — Arkansas to Mississippi; connects to NGPL, Trunkline Gas Company, Texas Gas Transmission and ANR Pipeline Company
Gulf LNG Holdings (50%)5 1.50 7 Near Pascagoula, Mississippi; connects to four interstate pipelines and a natural gas processing plant
SLNG— 1.76 12 Located on Elba Island in Georgia; connects to Elba Express, SNG, ELC and Dominion Energy Carolina Gas Transmission
ELC (51%)— 0.35 — Located on Elba Island; connects to Elba Express delivering to SLNG for LNG storage and ship loading.
West Region
EPNG/Mojave10,715 6.39 44 Permian, San Juan and Anadarko Basins; interconnects and demand locations in California, Arizona, New Mexico, Texas, Oklahoma and Mexico
CIG(b)4,295 6.00 38 Rocky Mountain and Anadarko Basins; interconnects and demand locations in Colorado, Wyoming, Utah, Montana, Kansas, Oklahoma and Texas
WIC850 3.61 — Rocky Mountain Basins; interconnects and demand locations in Colorado, Utah and Wyoming
Ruby (50%)(c)685 1.53 — Rocky Mountain Basins; interconnects and demand locations in Utah, Nevada, Oregon and California
CPGPL415 1.20 — Rocky Mountain Basins; interconnects and demand locations in Colorado and Kansas
TransColorado310 0.80 — San Juan, Permian, Paradox and Piceance Basins; interconnects and demand locations in Colorado and New Mexico
Sierrita (35%)60 0.52 — Connects with EPNG near Tucson, Arizona, to the U.S.-Mexico international border crossing near Sasabe, Arizona to supply a third-party natural gas pipeline in Mexico
Young Gas Storage (47.5%)15 — 6 
Located in Morgan County, Colorado in the Denver Julesburg Basin; capacity is committed to CIG and Colorado Springs Utilities
Keystone Gas Storage15 — 6 Located in the Permian Basin near the Waha natural gas trading hub in West Texas
Midstream
KM Texas and Tejas pipelines(d)5,9258.30  136
[0.52] 		Texas Gulf Coast supply and markets
Mier-Monterrey pipeline(d)900.65 — Starr County, Texas to Monterrey, Mexico; connects to CENEGAS national system and multiple power plants in Monterrey
KM North Texas pipeline(d)800.33 — Interconnect from NGPL; connects to a 1,750-megawatt Forney, Texas, power plant and a 1,000-megawatt Paris, Texas, power plant
Gulf Coast Express pipeline (34%)5302.00 — Permian Basin to the Agua Dulce, Texas area
PHP (27%)4302.10 — 
Permian Basin to the Texas Gulf Coast and Mexico markets
Oklahoma
Oklahoma system3,4300.73  [0.09]Hunton Dewatering, Woodford Shale, Anadarko Basin and Mississippi Lime, Arkoma Basin
Cedar Cove (70%)1150.03 — Oklahoma STACK, capacity excludes third-party offloads
South Texas
South Texas system1,1601.93  [1.02]Eagle Ford shale, Woodbine and Eaglebine formations
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Asset (KMI ownership shown if not 100%) Miles of Pipeline Design (Bcf/d) [(MBbl/d)] CapacityStorage (Bcf) [Processing (Bcf/d)] CapacitySupply and Market Region
Webb/Duval gas gathering system (91%)1450.15 — South Texas
Camino Real 750.15 — South Texas, Eagle Ford shale formation
EagleHawk (25%)5301.20 — South Texas, Eagle Ford shale formation
KM Altamont1,5450.10  [0.1] Utah, Uinta Basin
Red Cedar (49%)9000.33 — La Plata County, Colorado, Ignacio Blanco Field
Rocky Mountain
Fort Union (50%)315 1.25 — Powder River Basin (Wyoming)
Bighorn (51%)265 0.60 — Powder River Basin (Wyoming)
KinderHawk535 2.35 — Northwest Louisiana, Haynesville and Bossier shale formations
North Texas545 0.14 — North Barnett Shale Combo
KM Treating— — — Odessa, Texas, other locations in Tyler and Victoria, Texas
Hiland - Williston - gas 2,175 0.62  [0.33]Bakken/Three Forks shale formations - natural gas gathering and processing
Liberty pipeline (50%)85 
[140]
— Y-grade pipeline from Houston Central complex to the Texas Gulf Coast
South Texas NGL pipelines(e)340 
[115]
— Ethane and propane pipelines from Houston Central complex to the Texas Gulf Coast
Utopia pipeline (50%)265 
[50]
— Harrison County, Ohio extending to Windsor, Ontario
Cypress pipeline (50%)105 
[56]
— Mont Belvieu, Texas to Lake Charles, Louisiana
EagleHawk - Condensate (25%)(f)400 
[220]
— South Texas, Eagle Ford shale formation
(a)Includes proportionate share of storage capacity from our Bear Creek Storage joint venture.
(b)Includes leased pipeline miles and proportionate share of design and storage capacity from our WYCO joint venture.
(c)We operate Ruby and own the common interest in Ruby. Pembina owns the remaining interest in Ruby in the form of a convertible preferred interest and has 50% voting rights. If Pembina converted its preferred interest into common interest, we and Pembina would each own a 50% common interest in Ruby.
(d)Collectively referred to as Texas intrastate natural gas pipeline operations.
(e)Includes proportionate share of design capacity from our Liberty pipeline joint venture.
(f)Asset also has storage capacity of 60 MBbl.

Segment Competition

The market for natural gas infrastructure is highly competitive, and new pipelines, storage facilities, treating facilities, and facilities for related services are currently being built to serve demand for natural gas in the markets served by the pipelines in our Natural Gas Pipelines business segment.  We compete with interstate and intrastate pipelines for connections to new markets and supplies and for transportation, processing, storage and treating services.  We believe the principal elements of competition in our various markets are location, rates, terms of service, flexibility, availability of alternative forms of energy and reliability of service.  From time to time, projects are proposed that compete with our existing assets. Whether or when any such projects would be built, or the extent of their impact on our operations or profitability is typically not known.

Shippers on our natural gas pipelines compete with other forms of energy available to their natural gas customers and end users, including oil, coal, nuclear and renewables such as hydro, wind and solar power, along with other evolving forms of renewable energy.  Several factors influence the demand for natural gas, including price changes, the availability of supply, other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the ability to convert to alternative fuels and weather.

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Products Pipelines

Our Products Pipelines business segment consists of our refined petroleum products, crude oil and condensate pipelines, and associated terminals, our Southeast terminals, our condensate processing facility and our transmix processing facilities. The following summarizes the significant Products Pipelines business segment assets that we own and operate as of December 31, 2021:
Asset (KMI ownership shown if not 100%)Miles of PipelineNumber of Terminals (a) or locationsTerminal Capacity
(MMBbl)		Supply and Market Region
Crude & Condensate
KM Crude & Condensate pipeline266 5 2.6 Eagle Ford shale field in South Texas (Dewitt, Karnes and Gonzales Counties) to the Houston ship channel refining complex
Camino Real Gathering68 1 0.1 South Texas, Eagle Ford shale formation
Hiland - Williston Basin - oil(b)1,617 7 0.9 Bakken/Three Forks shale formations - crude oil gathering and transporting
Double H pipeline(b)512 — — Bakken shale in Montana and North Dakota to Guernsey, Wyoming
Double Eagle pipeline (50%)204 2 0.6 Live Oak County, Texas; Corpus Christi, Texas; Karnes County, Texas; and LaSalle County
KM Condensate Processing Facility (Splitter)— 1 2.0 Houston Ship Channel, Galena Park, Texas
Southeast Refined Products
Products (SE) pipeline (51%)3,186 — — Louisiana to Washington D.C.
Central Florida pipeline206 2 2.5 Tampa to Orlando
Southeast Terminals— 25 8.9 From Mississippi to Virginia, including Tennessee
Transmix Operations— 5 0.6 Colton, California; Richmond, Virginia; Dorsey Junction, Maryland; St. Louis, Missouri; and Greensboro, North Carolina
West Coast Refined Products
Pacific (SFPP) (99.5%)2,804 13 15.2 Six western states
Calnev566 2 2.0 Colton, California to Las Vegas, Nevada; Mojave region
West Coast Terminals44 8 9.9 Seattle, Portland, San Francisco and Los Angeles areas
(a)The terminals provide services including short-term product storage, truck loading, vapor handling, additive injection, dye injection and ethanol blending.
(b)Collectively referred to as Bakken Crude assets.

Segment Competition

Our Products Pipelines’ pipeline and terminal operations compete against proprietary pipelines and terminals owned and operated by major oil companies, other independent products pipelines and terminals, trucking and marine transportation firms (for short-haul movements of products). Our transmix operations compete with refineries owned by major oil companies and independent transmix facilities.

Terminals

Our Terminals business segment includes the operations of our refined petroleum product, chemical, renewable fuel and other liquid terminal facilities (other than those included in the Products Pipelines business segment) and all of our petroleum coke, metal and ores facilities.  Our terminals are located primarily near large U.S. urban centers.  We believe the location of our facilities and our ability to provide flexibility to customers help attract new and retain existing customers at our terminals and provide expansion opportunities. We often classify our terminal operations based on the handling of either liquids or dry-bulk material products. In addition, our Terminals’ marine operations include Jones Act-qualified product tankers that provide
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marine transportation of crude oil, condensate and refined petroleum products between U.S. ports. The following summarizes our Terminals business segment assets, as of December 31, 2021:
NumberCapacity
(MMBbl)
Liquids terminals5079.9
Bulk terminals28— 
Jones Act-qualified tankers165.3

Segment Competition

We are one of the largest independent operators of liquids terminals in the U.S., based on barrels of liquids terminaling capacity.  Our liquids terminals compete with other publicly or privately held independent liquids terminals and terminals owned by oil, chemical, pipeline and refining companies.  Our bulk terminals compete with numerous independent terminal operators, terminals owned by producers and distributors of bulk commodities, stevedoring companies and other industrial companies opting not to outsource terminaling services.  In some locations, competitors are smaller, independent operators with lower cost structures.  Our Jones Act-qualified product tankers compete with other Jones Act-qualified vessel fleets.

CO2

Our CO2 business segment produces, transports and markets CO2 for use in enhanced oil recovery projects as a flooding medium for recovering crude oil from mature oil fields.  Our CO2 pipelines and related assets allow us to market a complete package of CO2 supply and transportation services to our customers. We hold ownership interests in several oil-producing fields and own a crude oil pipeline, all located in the Permian Basin region of West Texas. We also own and operate RNG and LNG facilities in Indiana associated with our acquisition of Kinetrex.

Source and Transportation Activities

CO2 Resource Interests

Our principal market for CO2 is for injection into mature oil fields in the Permian Basin. Our ownership of CO2 resources as of December 31, 2021 includes:
Ownership
Interest		Compression
Capacity (Bcf/d)		Location
McElmo Dome unit45 %1.5 Colorado
Doe Canyon Deep unit87 %0.2 Colorado
Bravo Dome unit(a)11 %0.3 New Mexico
(a)We do not operate this unit.

CO2 and Crude Oil Pipelines

The principal market for transportation on our CO2 pipelines is to customers, including ourselves, using CO2 for enhanced recovery operations in mature oil fields in the Permian Basin, where industry demand is expected to remain stable in the foreseeable future. The tariffs charged on (i) the Wink crude oil pipeline system are regulated by both the FERC and the Texas Railroad Commission; (ii) the Pecos Carbon Dioxide Pipeline are regulated by the Texas Railroad Commission; and (iii) the Cortez pipeline are based on a consent decree. Rates on our other CO2 pipelines are established by other means, including by contract.

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Our ownership of CO2 and crude oil pipelines as of December 31, 2021 includes:
Asset (KMI ownership shown if not 100%)Miles of PipelineTransport Capacity (Bcf/d)Supply and Market Region
CO2 pipelines
Cortez pipeline (53%)5691.5McElmo Dome and Doe Canyon source fields to the Denver City, Texas hub
Central Basin pipeline3370.7Cortez, Bravo, Sheep Mountain, Canyon Reef Carriers and Pecos pipelines
Bravo pipeline (13%)(a)2180.4Bravo Dome to the Denver City, Texas hub
Canyon Reef Carriers pipeline (98%)1630.3McCamey, Texas, to the SACROC, Sharon Ridge, Cogdell and Reinecke units
Centerline CO2 pipeline
1130.3between Denver City, Texas and Snyder, Texas
Eastern Shelf CO2 pipeline
980.1between Snyder, Texas and Knox City, Texas
Pecos pipeline (95%)250.1McCamey, Texas, to Iraan, Texas, delivers to the Yates unit
(Bbls/d)
Crude oil pipeline
Wink pipeline434145,000West Texas to Marathon’s refinery in El Paso, Texas
(a)We do not operate Bravo pipeline.

Oil, Gas, and RNG Producing Activities

Oil and Gas Producing Interests

Our ownership interests in oil and gas producing fields located in the Permian Basin of West Texas as of December 31, 2021 include the following:
Working InterestKMI Gross Developed Acres
SACROC97 %49,156 
Yates50 %9,576 
Goldsmith Landreth San Andres99 %6,166 
Katz Strawn99 %7,194 
Reinecke70 %3,793 
Sharon Ridge(a)14 %2,619 
Tall Cotton100 %641
MidCross(a)13 %320
(a)We do not operate these fields.

Our oil and gas producing activities are not significant to KMI as a whole; therefore, we do not include the supplemental information on oil and gas producing activities under Accounting Standards Codification Topic 932, Extractive Activities - Oil and Gas.

Gas and Gasoline Plant Interests

Owned and operated gas plants in the Permian Basin of West Texas as of December 31, 2021 include:
Ownership InterestSource
Snyder gas plant(a)22 %
The SACROC unit and neighboring CO2 projects, specifically the Sharon Ridge and Cogdell units
Diamond M gas plant51 %Snyder gas plant
North Snyder gas plant100 %Snyder gas plant
(a)This is a working interest, in addition, we have a 28% net profits interest.

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RNG and LNG Facilities

Owned and operated RNG and LNG facilities as of December 31, 2021 include:
Storage (Bcf) [Production (Bcf)] CapacityProductOwnership InterestLocation
LNG Indy2.0 LNG100 %Indiana
Indy High BTU[0.8]RNG50 %Indiana
Segment Competition

Our primary competitors for the sale of CO2 include suppliers that have an ownership interest in McElmo Dome, Bravo Dome and Sheep Mountain CO2 resources.  Our ownership interests in the Central Basin, Cortez and Bravo pipelines are in direct competition with other CO2 pipelines.  We also compete with other interest owners in the McElmo Dome unit and the Bravo Dome unit for transportation of CO2 to the Denver City, Texas market area.

Major Customers

Our revenue is derived from a wide customer base. For each of the years ended December 31, 2021, 2020 and 2019, no revenues from transactions with a single external customer accounted for 10% or more of our total consolidated revenues. We do not believe that a loss of revenues from any single customer would have a material adverse effect on our business, financial position, results of operations or cash flows.

Industry Regulation

Interstate Natural Gas Transportation and Storage Regulation

We operate our interstate natural gas pipeline and storage facilities subject to the jurisdiction of the FERC and the provisions of the Natural Gas Act of 1938 (NGA), the Natural Gas Policy Act of 1978 (NGPA), and the Energy Policy Act of 2005 (the Energy Policy Act). These laws provide the FERC authority over the construction and operation of such facilities, including their modification, extension, enlargement and abandonment. The FERC also has authority over the rates charged and terms and conditions of services offered by interstate natural gas pipeline and storage companies. The FERC’s regulatory authority extends to establishing minimum and maximum rates for services and allows operators to discount or negotiate rates on a non-discriminatory basis. The rates, terms and conditions of service are set forth in posted tariffs approved by the FERC for each of our interstate natural gas pipeline and storage companies. Posted tariff rates are deemed just and reasonable and cannot be changed without FERC authorization following an evidentiary hearing or settlement. The FERC can initiate proceedings, on its own initiative or in response to a shipper complaint, that could result in a rate change or confirm existing rates. Negotiated rates provide certainty to the pipeline and the shipper of agreed-upon rates during the term of the transportation agreement, regardless of changes to the posted tariff rates. Negotiated rate agreements must be filed with FERC or included in the pipeline’s tariff in summary form.

FERC regulations also include a comprehensive framework for market transparency and nondiscrimination, as well as the FERC’s prohibition against market manipulation. Under the Energy Policy Act and related regulations, it is unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, to engage in fraudulent conduct. FERC Standards of Conduct regulate, among other things, the manner in which interstate natural gas pipelines may interact with their marketing affiliates. FERC’s market oversight and transparency regulations require annual reports of purchases or sales of natural gas meeting certain thresholds and criteria and certain public postings of information on scheduled volumes.

FERC has authority to impose civil penalties for violations of these statutes and regulations of more than $1.3 million per day per violation. Should we fail to comply with all applicable statutes, rules, regulations, and orders administered by FERC, we could be subject to substantial civil penalties and fines.

Interstate Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation

Some of our U.S. refined petroleum products and crude oil gathering and transmission pipelines are interstate common carrier pipelines, subject to regulation by the FERC under the Interstate Commerce Act, or ICA. The ICA requires that we
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maintain our tariffs on file with the FERC. Those tariffs set forth the rates we charge for providing gathering or transportation services on our interstate common liquids carrier pipelines as well as the rules and regulations governing these services. The ICA requires, among other things, that such rates on interstate common liquids carrier pipelines be “just and reasonable” and nondiscriminatory. The ICA permits interested persons to challenge newly proposed or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained during the two years prior to the filing of a complaint. Accordingly, certain of the SFPP pipelines’ rates have been subject to challenge with the FERC, as is more fully described in Note 18 “Litigation and Environmental” to our consolidated financial statements.

Petroleum products and crude oil pipelines may change their rates within prescribed ceiling levels that are tied to an inflation index. Shippers may protest rate increases made within the ceiling levels, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs from the previous year. A petroleum products or crude oil pipeline must, as a general rule, utilize the indexing methodology to change its rates. Cost-of-service ratemaking, market-based rates and settlement rates are alternatives to the indexing approach and may be used in certain specified circumstances to change rates.

CPUC Rate Regulation

The intrastate common carrier operations of our West Coast Refined Products operations’ pipelines in California are subject to regulation by the CPUC under a “depreciated book plant” methodology, which is based on an original cost measure of investment. Intrastate tariffs filed by us with the CPUC have been established on the basis of revenues, expenses and investments allocated as applicable to the California intrastate portion of the West Coast Refined Products operations’ business. Tariff rates with respect to intrastate pipeline service in California are subject to challenge by complaint by interested parties or by independent action of the CPUC. A variety of factors can affect the rates of return permitted by the CPUC, and certain other issues similar to those which have arisen with respect to our FERC regulated rates also could arise with respect to its intrastate rates.

Railroad Commission of Texas (RCT) Rate Regulation

The intrastate operations of our crude oil and liquids pipelines and natural gas pipelines and storage facilities in Texas are subject to regulation with respect to such intrastate transportation by the RCT. The RCT has the authority to regulate our rates, though it generally has not investigated the rates or practices of our intrastate pipelines in the absence of shipper complaints.

Mexico - Energy Regulatory Commission

The Mier-Monterrey Pipeline has a natural gas transportation permit granted by the Energy Regulatory Commission of Mexico (the Commission) that defines the conditions for the pipeline to carry out activity and provide natural gas transportation service. This permit expires in 2026, subject to an additional renewal term.

This permit establishes certain restrictive conditions, including without limitation: (i) compliance with the general conditions for the provision of natural gas transportation service; (ii) compliance with certain safety measures, contingency plans, maintenance plans and the official standards of Mexico regarding safety; (iii) compliance with the technical and economic specifications of the natural gas transportation system authorized by the Commission; (iv) compliance with certain technical studies established by the Commission; and (v) compliance with a minimum contributed capital not entitled to withdrawal of at least the equivalent of 10% of the investment proposed in the project.

Mexico - National Agency for Industrial Safety and Environmental Protection (ASEA)

ASEA regulates environmental compliance and industrial and operational safety. The Mier-Monterrey Pipeline must satisfy and maintain ASEA’s requirements, including compliance with certain safety measures, contingency plans, maintenance plans and the official standards of Mexico regarding safety, including a Safety Administration Program.

Safety Regulation

We are also subject to safety regulations issued by PHMSA, including those requiring us to develop and maintain pipeline integrity management programs to evaluate areas along our pipelines and take additional measures to protect pipeline segments
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located in what are referred to as High Consequence Areas (HCAs), and Moderate Consequence Areas (MCAs), where a leak or rupture could potentially do the most harm.

In October 2019, PHMSA published a final rule, effective July 1, 2020, to (i) expand integrity management program requirements outside of HCAs (with some exceptions), and (ii) reconfirm maximum allowable operating pressure (MAOP) on certain pipelines in populated areas including HCAs. The MAOP reconfirmations must be completed by 2035. Changes in technology such as advances of in-line inspection tools, identification of additional integrity threats and changes to PHMSA regulations or interpretations can have a significant impact on costs to perform integrity assessments, testing and repairs. We plan to continue to assess and maintain the integrity of our existing and future pipelines as required by PHMSA regulations. We expect the costs to comply with PHMSA regulations, including integrity management program requirements, will be substantial. Such costs will vary depending on the number of repairs or upgrades determined to be necessary as a result of integrity testing. Assessments performed as part of our program could identify results that require significant and unanticipated capital and operating expenditures to address. We expect to increase expenditures in the future to comply with PHMSA regulations.

Regulations, changes to regulations or an increase in public expectations for pipeline safety may require additional reporting, the replacement of some of our pipeline segments, addition of monitoring equipment and more frequent inspection or testing of our pipeline facilities. Repair, remediation, and preventative or mitigating actions may require significant capital and operating expenditures.

From time to time, our pipelines or facilities may experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.

We are also subject to the requirements of the Occupational Safety and Health Administration (OSHA) and other federal and state agencies that address employee health, including infectious diseases such as COVID-19, and safety.  In general, we believe we are fulfilling the OSHA requirements and protecting the health and safety of our employees.  Based on new or revised regulatory developments, we may be required to increase expenditures in the future to comply with higher industry and regulatory safety standards.  However, there are no known new or revised regulations which will require a material increase in our expenditures.

State and Local Regulation

Certain of our activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies, governing a wide variety of matters, including marketing, production, pricing, pollution, protection of the environment, and human health and safety.

Marine Operations

The operation of tankers and marine equipment create maritime obligations involving property, personnel and cargo under General Maritime Law. These obligations create a variety of risks including, among other things, the risk of collision, which may result in claims for personal injury, cargo, contract, pollution, third-party claims and property damages to vessels and facilities.

We are subject to the Jones Act and other federal laws that restrict maritime transportation (between U.S. departure and destination points) to vessels built and registered in the U.S. and owned and crewed by U.S. citizens. As a result, we monitor the foreign ownership of our common stock and under certain circumstances consistent with our certificate of incorporation, we have the right to redeem shares of our common stock owned by non-U.S. citizens. If we do not comply with such requirements, we would be prohibited from operating our vessels in U.S. coastwise trade, and under certain circumstances we would be deemed to have undertaken an unapproved foreign transfer, resulting in severe penalties, including permanent loss of U.S. coastwise trading rights for our vessels, fines or forfeiture of the vessels. Furthermore, from time to time, legislation has been introduced unsuccessfully in the U.S. Congress to amend the Jones Act to ease or remove the requirement that vessels operating between U.S. ports be built and registered in the U.S. and owned and crewed by U.S. citizens.  If the Jones Act were amended in such fashion, we could face competition from foreign-flagged vessels.

In addition, the U.S. Coast Guard and the American Bureau of Shipping maintain the most stringent regime of vessel inspection in the world, which tends to result in higher regulatory compliance costs for U.S.-flag operators than for owners of
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vessels registered under foreign flags of convenience. The Jones Act and General Maritime Law also provide damage remedies for crew members injured in the service of the vessel arising from employer negligence or vessel unseaworthiness.

The Merchant Marine Act of 1936 is a federal law that provides the U.S. Secretary of Transportation, upon proclamation by the U.S. President of a national emergency or a threat to the national security, the authority to requisition or purchase any vessel or other watercraft owned by U.S. citizens (including us, provided that we are considered a U.S. citizen for this purpose). If one of our vessels were purchased or requisitioned by the U.S. government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, we would not be entitled to compensation for any consequential damages suffered as a result of such purchase or requisition.

Canadian Regulation

The Utopia Pipeline System, owned by a joint venture that we operate and in which we own a 50% interest, originates in Ohio and terminates in Windsor, Ontario, Canada and is therefore subject to U.S. regulation as described in this section and below under the heading “—Environmental Matters,” as well as similar regulations promulgated by Canadian authorities with respect to natural gas liquids pipelines.

Derivatives Regulation

We use energy commodity derivative contracts as part of our strategy to hedge our exposure to energy commodity market risk and other external risks in the ordinary course of business. The derivative contracts that we use include exchange-traded and OTC commodity financial instruments such as, futures and options contracts, fixed price swaps and basis swaps. The Dodd-Frank Act requires the U.S. Commodity Futures Trading Commission (CFTC) and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the OTC derivatives market and entities that participate in that market. In October 2020, the CFTC finalized one of the last remaining new rules pursuant to the Dodd-Frank Act that institutes broad new aggregate position limits for OTC swaps and futures and options traded on regulated exchanges. As finalized, these rules include exemptions for hedging positions, and while we cannot yet predict the full impact of the rules when they take effect in 2022 and 2023, we do not expect that the rules will have a material adverse effect on our business. We cannot predict how new leadership at the CFTC as a result of the change in the U.S. presidential administration may impact us.

Environmental Matters

Our business operations are subject to federal, state and local laws and regulations relating to environmental protection and human health and safety. For example, if an accidental leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines, storage or other facilities, we may experience significant operational disruptions, and we may have to pay a significant amount to clean up the leak, release or spill, pay for government penalties, address natural resource damages, compensate for human exposure or property damage, install costly pollution control equipment or a combination of these and other measures. Furthermore, new projects may require approvals and environmental analyses under federal and state laws, including the Clean Water Act, the National Environmental Policy Act and the Endangered Species Act, as well as Executive Orders focused on environmental justice considerations. The resulting costs and liabilities could materially and negatively affect our business, financial condition, results of operations and cash flows. In addition, emission controls required under federal and state environmental laws for both new and existing facilities could require significant capital expenditures at our facilities. In general, the cost of environmental control at facilities is increasing and limiting the return on capital projects and the number of capital projects that are viable.

Environmental and human health and safety laws and regulations are subject to change. The long-term trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, wildlife, natural resources and human health. There can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Several state and federal agencies have also increased their daily and maximum penalty amounts in recent years. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, as well as increased penalty amounts for inadvertent non-compliance, such as an unexpected pipeline leak, could have a material adverse effect on our business, financial position, results of operations and cash flows.

In accordance with GAAP, we record liabilities for environmental matters when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or
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previously disposed. We have accrued liabilities for reasonably estimable and probable environmental remediation obligations at various sites, including multi-party sites where the EPA or a similar state agency has identified us as one of the potentially responsible parties. The involvement of other financially responsible companies at these multi-party sites could affect our actual joint and several liability exposures for response costs as well as natural resource damages.

We believe that the ultimate resolution of these environmental matters will not have a material adverse effect on our business, financial position, results of operations or cash flows. However, it is possible that our ultimate liability with respect to these environmental matters could exceed the amounts accrued in an amount that could be material to our business, financial position, results of operations or cash flows in any particular reporting period. We have accrued an environmental reserve in the amount of $243 million as of December 31, 2021. For additional information related to environmental matters, see Note 18 “Litigation and Environmental” to our consolidated financial statements.

Hazardous and Non-Hazardous Waste

We generate both hazardous and non-hazardous wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act and comparable state statutes. From time to time, the EPA, as well as other U.S. federal and state regulators, consider the adoption of stricter disposal standards for non‑hazardous waste. Furthermore, it is possible that some wastes that are currently classified as non-hazardous, which could include wastes currently generated during our pipeline or liquids or bulk terminal operations or wastes from oil and gas facilities that are currently exempt as exploration and production waste, may in the future be designated as hazardous wastes. Hazardous wastes are subject to more rigorous and costly handling and disposal requirements than non-hazardous wastes. Such changes in the regulations may result in additional capital expenditures or operating expenses for us.

Superfund

The CERCLA or the Superfund law, and analogous state laws, impose joint and several liability, without regard to fault or the legality of the original conduct, on certain classes of potentially responsible persons for releases of hazardous substances into the environment. These persons include the owner or operator of a site and companies that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA authorizes the EPA and, in some cases, third parties to take actions in response to threats to public health or the environment and to seek to recover from the responsible classes of persons the costs they incur, in addition to compensation for natural resource damages, if any. Although petroleum is excluded from CERCLA’s definition of a hazardous substance, in the course of our ordinary operations, we have and will generate materials that may fall within the definition of “hazardous substance.” By operation of law, if we are determined to be a potentially responsible person, we may be responsible under CERCLA for all or part of the costs required to clean up sites at which such materials are present, in addition to compensation for natural resource damages, if any.

Clean Air Act

Our operations are subject to the Clean Air Act, its implementing regulations, and analogous state statutes and regulations. The EPA regulations under the Clean Air Act contain requirements for the monitoring, reporting, and control of greenhouse gas (GHG) emissions from stationary sources. For further information, see “—Climate Change” below.

Clean Water Act

Our operations can result in the discharge of pollutants. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and controls regarding the discharge of fills and pollutants into waters of the U.S. The discharge of fills and pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by applicable federal or state authorities. The Oil Pollution Act was enacted in 1990 and amends provisions of the Clean Water Act pertaining to prevention of and response to oil spills. Spill prevention, control and countermeasure requirements of the Clean Water Act and some state laws require containment and similar structures to help prevent contamination of navigable waters in the event of an overflow or release of oil.

EPA Revisions to Ozone National Ambient Air Quality Standard (NAAQS)

As required by the Clean Air Act, the EPA establishes National Ambient Air Quality Standards (NAAQS) for how much pollution is permissible, and the states then have to adopt rules so their air quality meets the NAAQS. In October 2015, the EPA published a rule lowering the ground level ozone NAAQS from 75 parts per billion (ppb) to a more stringent 70 ppb standard. This change triggered a process under which the EPA designated the areas of the country in or out of compliance with the 2015 standards. In December 2020, EPA completed a review of the ozone NAAQS and published a rule retaining the
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2015 standards. State rules implementing the NAAQS, including those existing or proposed in Colorado and New Mexico, require the installation of more stringent air pollution controls on newly-installed equipment and possibly require the retrofitting of existing KMI facilities with air pollution controls. These rules will have financial impacts to our Natural Gas Business Unit. Future state rules could have financial impacts on multiple business units.

Climate Change

Due to concern over climate change, numerous proposals to monitor and limit emissions of GHGs have been made and are likely to continue to be made at the federal, state and local levels of government. Methane, a primary component of natural gas, and CO2, which is naturally occurring and also a byproduct of the burning of natural gas, are examples of GHGs. Various laws and regulations exist or are under development to regulate the emission of such GHGs, including the EPA programs to report GHG emissions and state actions to develop statewide or regional programs. The U.S. Congress has in the past considered legislation to reduce emissions of GHGs. Climate-related laws and regulation could lead to reduced demand for hydrocarbon products that are deemed to contribute to GHGs, which in turn could adversely affect demand for our products and services.

Beginning in 2009, EPA published several findings and rulemakings under the Clean Air Act requiring the permitting and reporting of certain GHGs, including CO2 and methane. Our facilities are subject to these requirements. Operational and/or regulatory changes could require additional facilities to comply with requirements for reducing, reporting and permitting GHG emissions. In November 2021, EPA published preamble language for a proposed new rule to regulate GHGs from new and existing sources in the oil and natural gas sector. The proposal would require states to limit methane emissions consistent with the EPA proposed “Emission Guidelines” which are meant be presumptive standards for the states to follow. These standards include increased monitoring requirements and require installation of pollution control equipment on a wide variety of equipment including compressor engines, pneumatic controllers and tanks. The EPA proposal did not include draft rule language so the total cost to comply with the proposed rule is difficult to predict. However, if the rule is finalized in a similar format to what is proposed, we expect significant increases in capital and operating expenditures to comply with this EPA regulation.

At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of GHGs, such as through establishment of GHG reduction targets or regional GHG “cap and trade” programs. It is possible that sources such as our gas-fueled compressors and processing plants could become subject to these state GHG reduction regulations. Various states are also proposing or have implemented stricter regulations for reporting, monitoring or reduction of GHGs that go beyond the requirements of the EPA. Compliance with state rules could require additional expenditures, above and beyond those spent to comply with the November 2021 proposed EPA GHG rules for new and existing sources.

Because our operations, including the compressor stations and processing plants, emit various types of GHGs, primarily methane and CO2, such new legislation or regulation could increase the costs related to operating and maintaining our facilities. Depending on the particular law, regulation or program, we or our subsidiaries could be required to incur capital expenditures for installing new monitoring equipment or emission controls on the facilities, acquire and surrender allowances for the GHG emissions, pay taxes related to the GHG emissions and administer and manage a more comprehensive GHG emissions program. We are not able at this time to estimate such increased costs; however, as is the case with similarly situated companies in our industry, they could be significant to us. While we may be able to include some or all of such increased costs in the rates charged by our or our subsidiaries’ pipelines, recovery of costs is uncertain in all cases and may depend on events beyond their control, including the outcome of future rate proceedings before the FERC or other regulatory bodies, and the provisions of any final legislation or other regulations. Any of the foregoing could have an adverse effect on our business, financial position, results of operations and prospects.

Many climate models indicate that global warming is likely to result in rising sea levels, increased intensity of hurricanes and tropical storms, and increased frequency of extreme precipitation and flooding. We may experience increased insurance premiums and deductibles, or a decrease in available coverage, for our assets in areas subject to severe weather. These climate-related changes could damage our physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone and rain-susceptible regions. However, the timing, severity and location of these climate change impacts are not known with certainty and, these impacts are expected to manifest themselves over varying time horizons.

Because the combustion of natural gas produces lower GHG emissions per unit of energy than competing fossil fuels, cap-and-trade legislation or EPA regulatory initiatives to reduce GHGs could stimulate demand for natural gas by increasing the relative cost of competing fuels such as coal and oil.  In addition, we anticipate that GHG regulations will increase demand for carbon sequestration technologies, such as the techniques we have successfully demonstrated in our enhanced oil recovery
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operations within our CO2 business segment.  However, these potential positive effects on our markets may be offset if these same regulations also cause the cost of natural gas to increase relative to competing non-fossil fuels.  Although we currently cannot predict the magnitude and direction of these impacts, GHG regulations could have material adverse effects on our business, financial position, results of operations or cash flows.

Department of Homeland Security

The Department of Homeland Security, referred to in this report as the DHS, has regulatory authority over security at certain high-risk chemical facilities. The DHS has promulgated the Chemical Facility Anti-Terrorism Standards and required all high-risk chemical and industrial facilities, including oil and gas facilities, to comply with the regulatory requirements of these standards. This process includes completing security vulnerability assessments, developing site security plans, and implementing protective measures necessary to meet DHS-defined, risk-based performance standards. The DHS has not provided final notice to all facilities that it determines to be high risk and subject to the rule; therefore, neither the extent to which our facilities may be subject to coverage by the rules nor the associated costs to comply can currently be determined, but it is possible that such costs could be substantial.

In response to ongoing cybersecurity threats affecting the pipeline industry the DHS’s Transportation Safety Administration issued two new security directives in 2021, which require critical pipeline owners to comply with mandatory reporting measures, designate a cybersecurity coordinator, provide vulnerability assessments, and ensure compliance with certain cybersecurity requirements. Compliance with these directives is consuming significant resources, and we may be required to expend significant additional resources to continue to enhance our information security measures, to comply with regulations, and/or to investigate and remediate information security vulnerabilities.

Human Capital

In managing our human capital resources, we use a strategic approach to building a diverse, inclusive, and respectful workplace. Our human resources department provides expertise and tools to attract, develop, and retain diverse talent and support our employees’ career and development goals. Our leadership teams have plans in place to enhance diversity and equality of opportunity in hiring, development, and promotions. We value our employees’ opinions and encourage them to engage with management and ask questions on topics such as our goals, challenges, and employee concerns.

We employed 10,529 full-time personnel at December 31, 2021, including approximately 910 full-time hourly personnel at certain terminals and pipelines covered by collective bargaining agreements that expire between 2022 and 2024. We consider relations with our employees to be good.

We value the safety of our workforce and integrate a culture of safety, emergency preparedness, and environmental responsibility through our operations management system (OMS). Our OMS conforms to common industry standards and establishes a framework that helps us: (i) provide employees and contractors with a safe work environment; (ii) comply with laws, rules, regulations, policies, and procedures; and (iii) identify opportunities to improve. Although our ultimate target is zero incidents, we also have three non-zero employee safety performance targets. The first is to outperform the annual industry average total recordable incident rate (TRIR). The second is to outperform our own three-year TRIR average. The third is a longer-term target to improve our company-wide employee TRIR from 1.0 in the baseline year 2019 to 0.7 by 2024. Our 2021 company-wide TRIR was 1.8 and 0.7, including and excluding COVID-19 cases, respectively. We seek to constantly improve our contractor TRIR performance through initiatives to address recent incident trends and new best practices.

Our board of directors’ nominating and governance committee is responsible for planning for succession in the senior management ranks of the Company, including the office of chief executive officer. The chief executive officer shall report to the Committee, generally at the time of the regularly scheduled third quarter board of directors meeting in each year, regarding the processes in place to identify talent within and outside the Company to succeed to senior management positions and the information developed during the current calendar year pursuant to those processes. As part of our annual succession planning process, we identify minority and female candidates to include in the plan for senior positions. Management reviews its succession plan, including a discussion on development opportunities for potential successors, with the nominating and governance committee of our board of directors annually.

We consider employee diversity an asset and support equal opportunity employment. We take affirmative steps to employ and advance in employment all persons without regard to their race/ethnicity; sex; sexual orientation; gender, including gender identity and expression; veteran status; disability; or other protected categories, and base employment decisions solely on valid job requirements. We are committed to a harassment free workplace, supported with online and face-to-face workplace
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harassment and discrimination prevention training for our employees. Employees and supervisors review our harassment and discrimination prevention policy every two years as part of our policy renewal training.

Our employees are an integral part of our success, and we value their career development. We encourage and support professional development and learning for our employees by offering workforce training, tuition reimbursement, leadership and other development programs. These programs help improve recruitment, development, and retention. We support our employees’ ongoing career goals and development through several programs. These programs help maximize our employees’ potential and give them the skills they need to further enhance their careers.

Our compensation program is linked to long and short-term strategic financial and operational objectives, including environmental, safety, and compliance targets. Compensation includes competitive base salaries in the markets in which we operate and competitive benefits, including retirement plans, opportunities for annual bonuses, and, for eligible employees, long-term incentives and an employee stock purchase plan.

Properties and Rights-of-Way

We believe that we generally have satisfactory title to the properties we own and use in our businesses, subject to liens for current taxes, liens incident to minor encumbrances, and easements and restrictions, which do not materially detract from the value of such property, the interests in those properties or the use of such properties in our businesses.  Our terminals, storage facilities, treating and processing plants, regulator and compressor stations, oil and gas wells, offices and related facilities are located on real property owned or leased by us.  In some cases, the real property we lease is on federal, state or local government land.

We generally do not own the land on which our pipelines are constructed.  Instead, we obtain and maintain rights to construct and operate the pipelines on other people’s land generally under agreements that are perpetual or provide for renewal rights.  Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of such property.  In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants.  In some cases, not all of the apparent record owners have joined in the right-of-way grants, but in substantially all such cases, signatures of the owners of a majority of the interests have been obtained.  Permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets and state highways, and in some instances, such permits are revocable at the election of the grantor, or, the pipeline may be required to move its facilities at its own expense.  Permits also have been obtained from railroad companies to run along or cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election.  Some such permits require annual or other periodic payments.  In a few minor cases, property for pipeline purposes was purchased by the Company.

Financial Information about Geographic Areas

For geographic information concerning our assets and operations, see Note 16 “Reportable Segments” to our consolidated financial statements.

Available Information

We make available free of charge on or through our internet website, at www.kindermorgan.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The information contained on or connected to our internet website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.

Item 1A.  Risk Factors.

You should carefully consider the risks described below, in addition to the other information contained in this document. Realization of any of the following risks could have a material adverse effect on our business, financial condition, cash flows and results of operations.

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Risks Related to Operating our Business

The COVID-19 pandemic has adversely affected, and could continue to adversely affect, our business.

The COVID-19 pandemic and the efforts to control it resulted in a significant decline in global economic activity and significant disruption of global supply chains in 2020. The resulting downturn in economic activity negatively impacted global demand and prices for crude oil, natural gas, NGL, refined petroleum products, CO2, steel, chemicals and other products that we handle in our pipelines, terminals, shipping vessels and other facilities. The sustainability of the economic recovery observed in 2021 remains unclear as inflationary pressures have increased in the U.S. and globally and efforts to combat the virus have been complicated by new variants.

As the pandemic and responses to it continue, we may experience further disruptions to commodities markets, supply chains and the health, availability and efficiency of our workforce, which could adversely affect our ability to conduct our business and operations and limit our ability to execute on our business plan. There are still too many variables and uncertainties regarding COVID-19 — including the pace and efficacy of vaccination efforts, the duration and severity of possible resurgences or additional variants, the duration and extent of any travel restrictions and business closures imposed in affected countries and market reactions to the announcement of any such restrictions and closures — to reasonably predict the potential impact of COVID-19 on our business and operations. COVID-19 may materially adversely affect our business, results of operations, financial condition and cash flows. Even after the COVID-19 pandemic has subsided, we may experience materially adverse impacts to our business due to residual impacts from measures taken to combat the virus. Further, adverse impacts from the pandemic may have the effect of heightening many of the other risks we face.

Our businesses are dependent on the supply of and demand for the products that we handle.

Our pipelines, terminals and other assets and facilities, including the availability of expansion opportunities, depend in part on continued production of natural gas, crude oil and other products in the geographic areas that they serve. Our business also depends in part on the levels of demand for natural gas, crude oil, NGL, refined petroleum products, CO2, steel, chemicals and other products in the geographic areas to which our pipelines, terminals, shipping vessels and other facilities deliver or provide service, and the ability and willingness of our shippers and other customers to supply such demand. For example, without additions to crude oil and gas reserves, production will decline over time as reserves are depleted, and production costs may rise. Producers may reduce or shut down production during times of lower product prices or higher production costs to the extent they become uneconomic. Producers in areas served by us may not be successful in exploring for and developing additional reserves, and our pipelines and related facilities may not be able to maintain existing volumes of throughput.

Commodity prices and tax incentives may not remain at levels that encourage producers to explore for and develop additional reserves, produce existing marginal reserves or renew transportation contracts as they expire. Additionally, demand for such products can decline due to situations over which we have no control, such as the COVID-19 pandemic and various measures that federal, state and local authorities have implemented in response to the virus or its economic consequences.

In addition to economic disruptions resulting from events such as COVID-19, conditions in the business environment generally, such as declining or sustained low commodity prices, supply disruptions, or higher development or production costs, could result in a slowing of supply to our pipelines, terminals and other assets. Also, sustained lower demand for hydrocarbons, or changes in the regulatory environment or applicable governmental policies, including in relation to climate change or other environmental concerns, may have a negative impact on the supply of crude oil and other products. In recent years, a number of initiatives and regulatory changes relating to reducing GHG emissions have been undertaken by federal, state and municipal governments and crude oil and gas industry participants. In addition, public concern about the potential risks posed by climate change has resulted in increased demand for energy efficiency and a transition to energy provided from renewable energy sources, rather than fossil fuels, fuel-efficient alternatives such as hybrid and electric vehicles, and pursuit of other technologies to reduce GHG emissions, such as carbon capture and sequestration. We may see an intensification of these trends if and to the extent that the Biden presidential administration succeeds in enacting its energy and environmental policies.

These factors could result in not only increased costs for producers of hydrocarbons but also an overall decrease in the demand for hydrocarbons. Each of the foregoing could negatively impact our business directly as well as our shippers and other customers, which in turn could negatively impact our prospects for new contracts for transportation, terminaling or other midstream services, or renewals of existing contracts or the ability of our customers and shippers to honor their contractual commitments. Furthermore, such unfavorable conditions may compound the adverse effects of larger disruptions such as COVID-19. See “—Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us” below.
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We cannot predict the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce the production of and/or demand for the products we handle. In addition, irrespective of supply of or demand for products we handle, implementation of new regulations or changes to existing regulations affecting the energy industry could have a material adverse effect on us.

We face competition from other pipelines and terminals, as well as other forms of transportation and storage.

Competition is a factor affecting our existing businesses and our ability to secure new project opportunities. Any current or future pipeline system or other form of transportation (such as barge, rail or truck) that delivers the products we handle into the areas that our pipelines serve could offer transportation services that are more desirable to shippers than those we provide because of price, location, facilities or other factors. Likewise, competing terminals or other storage options may become more attractive to our customers. To the extent that competitors offer the markets we serve more desirable transportation or storage options, or customers opt to construct their own facilities for services previously provided by us, this could result in unused capacity on our pipelines and in our terminals. We also could experience competition for the supply of the products we handle from both existing and proposed pipeline systems; for example, several pipelines access many of the same areas of supply as our pipeline systems and transport to destinations not served by us. If capacity on our assets remains unused, our ability to re-contract for expiring capacity at favorable rates or otherwise retain existing customers could be impaired. In addition, to the extent that companies pursuing development of carbon capture and sequestration technology are successful, they could compete with us for customers who purchase CO2 for use in enhanced oil recovery operations.

The volatility of crude oil, NGL and natural gas prices could adversely affect our CO2 business segment and businesses within our Natural Gas Pipelines and Products Pipelines business segments.

The revenues, cash flows, profitability and future growth of some of our businesses (and the carrying values of certain of their respective assets, which include related goodwill) depend to a large degree on prevailing crude oil, NGL and natural gas prices.

Prices for crude oil, NGL and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for crude oil, NGL and natural gas, uncertainties within the market and a variety of other factors beyond our control. These factors include, among other things (i) weather conditions and events such as hurricanes in the U.S.; (ii) domestic and global economic conditions; (iii) the activities of the OPEC and other countries that are significant producers of crude oil (OPEC+); (iv) governmental regulation; (v) political instability in crude oil producing countries; (vi) the foreign supply of and demand for crude oil and natural gas; (vii) the price of foreign imports; (viii) the proximity and availability of storage and transportation infrastructure and processing and treating facilities; and (ix) the availability and prices of alternative fuel sources. We use hedging arrangements to partially mitigate our exposure to commodity prices, but these arrangements also are subject to inherent risks. We are also subject, indirectly, to volatility of commodity prices, through many of our customers’ direct exposure to such volatility. Please read “—Our use of hedging arrangements does not eliminate our exposure to commodity price risks and could result in financial losses or volatility in our income.”

In 2020, the impact of COVID-19, combined with a dispute regarding production levels among OPEC+ countries, caused crude oil prices to reach historic lows in April 2020. While global oil demand and prices improved later in 2020 and through 2021 from the low levels experienced in early 2020, the announcement of a newly discovered variant of COVID-19 in late November 2021 resulted in a sharp, unexpected and temporary decline in the price of crude oil. If prices fall substantially or remain low for a sustained period and we are not sufficiently protected through hedging arrangements, we may be unable to realize a profit from these businesses and would operate at a loss.

Sharp declines in the prices of crude oil, NGL or natural gas (such as we experienced in the first half of 2020) or a prolonged unfavorable price environment, may result in a commensurate reduction in our revenues, income and cash flows from our businesses that produce, process, or purchase and sell crude oil, NGL, or natural gas, and could have a material adverse effect on the carrying value (which includes assigned goodwill) of our CO2 business segment’s proved reserves, certain assets in certain midstream businesses within our Natural Gas Pipelines business segment, and certain assets within our Products Pipelines business segment. For example, following the commodity price declines we experienced during the first half of 2020, we recorded a combined $1.950 billion of non-cash impairments associated with our Natural Gas Pipelines Non-Regulated and CO2 reporting units, primarily for impairments of goodwill and assets owned in these businesses. See Note 4 “Losses and Gains on Impairments, Divestitures and Other Write-downs” and Note 8 “Goodwill” to our consolidated financial statements for more information.

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In recent decades, there have been periods worldwide of both overproduction and underproduction of hydrocarbons, and periods of both increased and relaxed energy conservation efforts. Such conditions have resulted in periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis. These periods have been followed by periods of short supply of, and increased demand for, crude oil and natural gas. The cycles of excess or short supply of crude oil or natural gas have placed pressures on prices and resulted in dramatic price fluctuations even during relatively short periods of seasonal market demand. These fluctuations impact the accuracy of assumptions used in our budgeting process. For more information about our energy and commodity market risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk.”

Commodity transportation and storage activities involve numerous risks that may result in accidents or otherwise adversely affect our operations.

There are a variety of hazards and operating risks inherent to the transportation and storage of the products we handle, such as leaks; releases; the breakdown, underperformance or failure of equipment, facilities, information systems or processes; damage to our pipelines caused by third-party construction; the compromise of information and control systems; spills at terminals and hubs; spills associated with the loading and unloading of harmful substances at rail facilities; adverse sea conditions (including storms and rising sea levels) and releases or spills from our shipping vessels or vessels loaded at our marine terminals; operator error; labor disputes/work stoppages; disputes with interconnected facilities and carriers; operational disruptions or apportionment on third-party systems or refineries on which our assets depend; and catastrophic events or natural disasters such as fires, floods, explosions, earthquakes, acts of terrorists and saboteurs, cyber security breaches, and other similar events, many of which are beyond our control. Additional risks to our vessels include capsizing, grounding and navigation errors.

The occurrence of any of these risks could result in serious injury and loss of human life, significant damage to property and natural resources, environmental pollution, significant reputational damage, impairment or suspension of operations, fines or other regulatory penalties, and revocation of regulatory approvals or imposition of new requirements, any of which also could result in substantial financial losses, including lost revenue and cash flow to the extent that an incident causes an interruption of service. For pipeline and storage assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks may be greater. In addition, the consequences of any operational incident (including as a result of adverse sea conditions) at one of our marine terminals may be even more significant as a result of the complexities involved in addressing leaks and releases occurring in the ocean or along coastlines and/or the repair of marine terminals.

Our operating results may be adversely affected by unfavorable economic and market conditions.

Unfavorable conditions such as a general slowdown of the global or U.S. economy, uncertainty and volatility in the financial markets, or inflation and rising interest rates, could materially adversely affect our operating results. For example, as described above, COVID-19 resulted in a global economic downturn in 2020. The slowdown resulting from the pandemic affected numerous industries, including the crude oil and gas industry, the steel industry and in specific segments and markets in which we operate, resulting in reduced demand and increased price competition for our products and services. While global economic activity largely rebounded in 2021, we could experience similar or compounded adverse impacts as a result of other global events affecting economic conditions. Also, economic conditions in the wake of the pandemic have included inflationary pressure, which could result in higher operating expenses and project costs for us, as well as higher interest rates.

In addition, uncertain or changing economic conditions within one or more geographic regions may affect our operating results within the affected regions. Sustained unfavorable commodity prices, volatility in commodity prices or changes in markets for a given commodity might also have a negative impact on many of our customers, which could impair their ability to meet their obligations to us. See “—Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.” In addition, decreases in the prices of crude oil, NGL and natural gas are likely to have a negative impact on our operating results and cash flow. See “—The volatility of crude oil, NGL and natural gas prices could adversely affect our CO2 business segment and businesses within our Natural Gas Pipelines and Products Pipelines business segments.”

If economic and market conditions (including volatility in commodity markets) globally, in the U.S. or in other key markets become more volatile or deteriorate, we may experience material impacts on our business, financial condition and results of operations.

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Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.

We are exposed to the risk of loss in the event of nonperformance by our customers or other counterparties, such as hedging counterparties, joint venture partners and suppliers. Many of our counterparties finance their activities through cash flow from operations or debt or equity financing, and some of them may be highly leveraged and may not be able to access additional capital to sustain their operations in the future. Our counterparties are subject to their own operating, market, financial and regulatory risks, and some have experienced, are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. For example, in 2020, the global economic slowdown caused by COVID-19, and the coinciding extreme drop in crude oil prices, which was exacerbated by the effects of the pandemic, significantly impacted the financial condition of many companies, particularly exploration and production companies, including some of our customers or counterparties. Further, the security that is permitted to be obtained from such customers may be limited, including by FERC regulation. While certain of our customers are subsidiaries of an entity that has an investment grade credit rating, in many cases the parent entity has not guaranteed the obligations of the subsidiary and, therefore, the parent’s credit ratings may have no bearing on such customers’ ability to pay us for the services we provide or otherwise fulfill their obligations to us. See Note 2 “Summary of Significant Accounting Policies—Allowance for Credit Losses” in our consolidated financial statements.

Furthermore, financially distressed customers might be forced to reduce or curtail their future use of our products and services, which also could have a material adverse effect on our results of operations, financial condition, and cash flows.

We cannot provide any assurance that such customers and key counterparties will not become financially distressed or that such financially distressed customers or counterparties will not default on their obligations to us or file for bankruptcy protection. If one of such customers or counterparties files for bankruptcy protection, we likely would be unable to collect all, or even a significant portion of, amounts owed to us. Similarly, our contracts with such customers may be renegotiated at lower rates or terminated altogether. Significant customer and other counterparty defaults and bankruptcy filings could have a material adverse effect on our business, financial position, results of operations or cash flows.

We are subject to reputational risks and risks relating to public opinion.

Our business, operations or financial condition generally may be negatively impacted as a result of negative public opinion. Public opinion may be influenced by negative portrayals of the industry in which we operate as well as opposition to development projects. In addition, market events specific to us could result in the deterioration of our reputation with key stakeholders.

Reputational risk cannot be managed in isolation from other forms of risk. Credit, market, operational, insurance, regulatory and legal risks, among others, must all be managed effectively to safeguard our reputation. Our reputation and public opinion could also be impacted by the actions and activities of other companies operating in the energy industry, particularly other energy infrastructure providers, over which we have no control. In particular, our reputation could be impacted by negative publicity related to pipeline incidents or unpopular expansion projects and due to opposition to development of hydrocarbons and energy infrastructure, particularly projects involving resources that are considered to increase GHG emissions and contribute to climate change. Negative impacts from a compromised reputation or changes in public opinion (including with respect to the production, transportation and use of hydrocarbons generally) could include increased regulatory oversight, delays in obtaining, or challenges to, regulatory approvals with respect to growth projects, blockades, project cancellations, difficulty securing financing, revenue loss, reduction in customer base, and decreased value of our securities and our business.

The future success of our oil and gas development and production operations depends in part upon our ability to develop additional oil and gas reserves that are economically recoverable.

The rate of production from oil and natural gas properties declines as reserves are depleted. Without successful development activities, the reserves, revenues and cash flows of the oil and gas producing assets within our CO2 business segment will decline. We may not be able to develop or acquire additional reserves at an acceptable cost or have necessary financing for these activities in the future. Additionally, if we do not realize production volumes greater than, or equal to, our hedged volumes, we may suffer financial losses not offset by physical transactions.

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The development of crude oil and gas properties involves risks that may result in a total loss of investment.

The business of developing and operating oil and gas properties involves a high degree of business and financial risk that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Acquisition and development decisions generally are based on subjective judgments and assumptions that, while they may be reasonable, are by their nature speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, the successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational and market-related factors, including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions, may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable. A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of oil and/or gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances.

Our use of hedging arrangements does not eliminate our exposure to commodity price risks and could result in financial losses or volatility in our income.

We engage in hedging arrangements to reduce our direct exposure to fluctuations in the prices of crude oil, natural gas and NGL, including differentials between regional markets. These hedging arrangements expose us to risk of financial loss in some circumstances, including when production is less than expected, when the counterparty to the hedging contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the hedging agreement and the actual price received. In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in prices for crude oil, natural gas and NGL. Furthermore, our hedging arrangements cannot hedge against any decrease in the volumes of products we handle. See “—Our businesses are dependent on the supply of and demand for the products that we handle.”

The markets for instruments we use to hedge our commodity price exposure generally reflect then-prevailing conditions in the underlying commodity markets. As our existing hedges expire, we will seek to replace them with new hedging arrangements. To the extent then-existing underlying market conditions are unfavorable, new hedging arrangements available to us will reflect such unfavorable conditions, limiting our ability to hedge our exposure to unfavorable commodity prices.

The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions (for example, to mitigate our exposure to fluctuations in commodity prices or currency exchange rates or to balance our exposure to fixed and variable interest rates) that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at the dates of those consolidated financial statements. In addition, it may not be possible for us to engage in hedging transactions that completely eliminate our exposure to commodity prices; therefore, our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge. For more information about our hedging activities, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates—Hedging Activities” and Note 14 “Risk Management” to our consolidated financial statements.

A breach of information security or failure of one or more key information technology (IT) or operational (OT) systems, or those of third parties, may adversely affect our business, results of operations or business reputation.

Our business is dependent upon our operational systems to process a large amount of data and complex transactions. Some of the operational systems we use are owned or operated by independent third-party vendors. The various uses of these IT systems, networks and services include, but are not limited to, controlling our pipelines and terminals with industrial control systems, collecting and storing information and data, processing transactions, and handling other processing necessary to manage our business.

While we have implemented and maintain a cybersecurity program designed to protect our IT, OT and data systems from attacks, we can provide no assurance that our cybersecurity program will be effective. As a result of the COVID-19 pandemic and our subsequent continuation of hybrid office-and-remote-working arrangements with some of our employees, remote access to our networks and systems has increased substantially. While we have taken additional steps to secure our networks and systems, we may be more vulnerable to a successful cyber-attack or information security incident when significant numbers of our employees are working remotely. We have experienced an increase in the number of attempts by external parties to access our networks or our company data without authorization. The risk of a disruption or breach of our operational systems,
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or the compromise of the data processed in connection with our operations, through an act of terrorism or cyber sabotage event has increased as attempted attacks have advanced in sophistication and number around the world.

If any of our systems are damaged, fail to function properly or otherwise become unavailable, we may incur substantial costs to repair or replace them and may experience loss or corruption of critical data and interruptions or delays in our ability to perform critical functions, which could adversely affect our business and results of operations. A significant failure, compromise, breach or interruption in our systems, which may result from problems such as ransomware, malware, computer viruses, hacking attempts or third-party error or malfeasance, could result in a disruption of our operations, customer dissatisfaction, damage to our reputation and a loss of customers or revenues. Efforts by us and our vendors to develop, implement and maintain security measures, including malware and anti-virus software and controls, may not be successful in preventing these events from occurring, and any network and information systems-related events could require us to expend significant resources to remedy such event. In the future, we may be required to expend significant additional resources to continue to enhance our information security measures, to comply with regulations, and/or to investigate and remediate information security vulnerabilities.

Attacks, including acts of terrorism or cyber sabotage, or the threat of such attacks, may adversely affect our business or reputation.

The U.S. government has issued public warnings that indicate that pipelines and other infrastructure assets might be specific targets of terrorist organizations or “cyber sabotage” events. For example, in May 2021, a ransomware attack on a major U.S. refined products pipeline forced the operator to temporarily shut down the pipeline, resulting in disruption of fuel supplies along the East Coast. Potential targets include our pipeline systems, terminals, processing plants or operating systems. The occurrence of an attack could cause a substantial decrease in revenues and cash flows, increased costs to respond or other financial loss, damage to our reputation, increased regulation or litigation or inaccurate information reported from our operations. There is no assurance that adequate cyber sabotage and terrorism insurance will be available at rates we believe are reasonable in the near future. These developments may subject our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations and financial condition or could harm our business reputation.

Hurricanes, earthquakes, flooding and other natural disasters, as well as subsidence and coastal erosion and climate-related physical risks, could have an adverse effect on our business, financial condition and results of operations.

Some of our pipelines, terminals and other assets are located in, and our shipping vessels operate in, areas that are susceptible to hurricanes, earthquakes, flooding and other natural disasters or could be impacted by subsidence and coastal erosion. These natural disasters and phenomena could potentially damage or destroy our assets and disrupt the supply of the products we transport. Many climate models indicate that global warming is likely to result in rising sea levels, increased intensity of weather, and increased frequency of extreme precipitation and flooding. These climate-related changes could result in damage to physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone and rain-susceptible regions. In addition, we may experience increased insurance premiums and deductibles, or a decrease in available coverage, for our assets in areas subject to severe weather. Natural disasters and phenomena can similarly affect the facilities of our customers. In either case, losses could exceed our insurance coverage and our business, financial condition and results of operations could be adversely affected, perhaps materially. See Items 1 and 2 “Business and Properties—Narrative Description of Business—Environmental Matters.”

Our insurance policies do not cover all losses, costs or liabilities that we may experience, and insurance companies that currently insure companies in the energy industry may cease to do so or substantially increase premiums.

Our insurance program may not cover all operational risks and costs and may not provide sufficient coverage in the event of a claim. We do not maintain insurance coverage against all potential losses and could suffer losses for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Losses in excess of our insurance coverage could have a material adverse effect on our business, financial condition and results of operations.

Changes in the insurance markets subsequent to certain hurricanes and natural disasters have made it more difficult and more expensive to obtain certain types of coverage. The occurrence of an event that is not fully covered by insurance, or failure by one or more of our insurers to honor its coverage commitments for an insured event, could have a material adverse effect on our business, financial condition and results of operations. Insurance companies may reduce the insurance capacity they are willing to offer or may demand significantly higher premiums or deductibles to cover our assets. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, we may be unable to obtain and maintain adequate insurance at a reasonable cost. There is no assurance that our insurers will renew their insurance coverage on
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acceptable terms, if at all, or that we will be able to arrange for adequate alternative coverage in the event of non-renewal. The unavailability of full insurance coverage to cover events in which we suffer significant losses could have a material adverse effect on our business, financial condition and results of operations.

Expanding our existing assets and constructing new assets is part of our growth strategy. Our ability to begin and complete construction on expansion and new-build projects may be inhibited by difficulties in obtaining, or our inability to obtain, permits and rights-of-way, as well as public opposition, increases in costs of construction materials, cost overruns, inclement weather and other delays. Should we pursue expansion of or construction of new projects through joint ventures with others, we will share control of and any benefits from those projects.

We regularly undertake major construction projects to expand our existing assets and to construct new assets. New growth projects generally will be subject to, among other things, the receipt of regulatory approvals, feasibility and cost analyses, funding availability and industry, market and demand conditions. If we pursue joint ventures with third parties, those parties may share approval rights over major decisions, and may act in their own interests. Their views may differ from our own or our views of the interests of the venture which could result in operational delays or impasses, which in turn could affect the financial expectations of and our expected benefits from the venture. A variety of factors outside of our control, such as difficulties in obtaining permits and rights-of-way or other regulatory approvals, have caused, and may continue to cause, delays in or cancellations of our construction projects. Regulatory authorities may modify their permitting policies in ways that disadvantage our construction projects, such as the FERC’s consideration of changes to its Certificate Policy Statement. Such factors can be exacerbated by public opposition to our projects. See “—We are subject to reputational risks and risks relating to public opinion.” For example, changing public attitudes toward pipelines bearing fossil fuels may impede our ability to secure rights-of-way or governmental reviews and authorizations on a timely basis or at all. Inclement weather, natural disasters and delays in performance by third-party contractors have also resulted in, and may continue to result in, increased costs or delays in construction. In addition, inflationary pressure that emerged during the economic recovery following the COVID-19 pandemic is likely to increase our costs for construction materials. Significant increases in costs of construction materials, cost overruns or delays, or our inability to obtain a required permit or right-of-way, could have a material adverse effect on our return on investment, results of operations and cash flows, and could result in project cancellations or limit our ability to pursue other growth opportunities.

Substantially all of the land on which our pipelines are located is owned by third parties. If we are unable to procure and maintain access to land owned by third parties, our revenue and operating costs, and our ability to complete construction projects, could be adversely affected.

We must obtain and maintain the rights to construct and operate pipelines on other owners’ land, including private landowners, railroads, public utilities and others. While our interstate natural gas pipelines in the U.S. have federal eminent domain authority, the availability of eminent domain authority for our other pipelines varies from state to state depending upon the type of pipeline—petroleum liquids, natural gas, CO2, or crude oil—and the laws of the particular state. In any case, we must compensate landowners for the use of their property, and in eminent domain actions, such compensation may be determined by a court. If we are unable to obtain rights-of-way on acceptable terms, our ability to complete construction projects on time, on budget, or at all, could be adversely affected. In addition, we are subject to the possibility of increased costs under our rights-of-way or rental agreements with landowners, primarily through renewals of expiring agreements and rental increases. If we were to lose these rights, our operations could be disrupted or we could be required to relocate the affected pipelines, which could cause a substantial decrease in our revenues and cash flows and a substantial increase in our costs.

The acquisition of additional businesses and assets is part of our growth strategy. We may experience difficulties completing acquisitions or integrating new businesses and properties, and we may be unable to achieve the benefits we expect from any future acquisitions.

Part of our business strategy includes acquiring additional businesses and assets. We evaluate and pursue assets and businesses that we believe will complement or expand our operations in accordance with our growth strategy. We cannot provide any assurance that we will be able to complete acquisitions in the future or achieve the desired results from any acquisitions we do complete. Any acquired business or assets will be subject to many of the same risks as our existing businesses and may not achieve the levels of performance that we anticipate.

If we do not successfully integrate acquisitions, we may not realize anticipated operating advantages and cost savings. Integration of acquired companies or assets involves a number of risks, including (i) the loss of key customers of the acquired business; (ii) demands on management related to the increase in our size; (iii) the diversion of management’s attention from the
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management of daily operations; (iv) difficulties in implementing or unanticipated costs of accounting, budgeting, reporting, internal controls and other systems; and (v) difficulties in the retention and assimilation of necessary employees.

We may not be able to maintain the levels of operating efficiency that acquired companies have achieved or might achieve separately. Successful integration of each acquisition will depend upon our ability to manage those operations and to eliminate redundant and excess costs. Difficulties in integration may be magnified if we make multiple acquisitions over a relatively short period of time. Because of difficulties in combining and expanding operations, we may not be able to achieve the cost savings and other size-related benefits that we hoped to achieve after these acquisitions, which would harm our financial condition and results of operations.

Our business requires the retention and recruitment of a skilled workforce, and difficulties recruiting and retaining our workforce could result in a failure to implement our business plans.

Our operations and management require the retention and recruitment of a skilled workforce, including engineers, technical personnel and other professionals. We and our affiliates compete with other companies in the energy industry for this skilled workforce. In addition, many of our current employees are retirement eligible and have significant institutional knowledge that must be transferred to other employees. If we are unable to (i) retain current employees; (ii) successfully complete the knowledge transfer; and/or (iii) recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased costs to retain and recruit these professionals.

If we are unable to retain our executive officers, our ability to execute our business strategy, including our growth strategy, may be hindered.

Our success depends in part on the performance of and our ability to retain our executive officers, particularly Richard D. Kinder, our Executive Chairman and one of our founders, Steve Kean, our Chief Executive Officer, and Kim Dang, our President. Along with the other members of our senior management, Messrs. Kinder and Kean and Ms. Dang have been responsible for developing and executing our growth strategy. If we are not successful in retaining Mr. Kinder, Mr. Kean, Ms. Dang or our other executive officers, or replacing them, our business, financial condition or results of operations could be adversely affected. We do not maintain key personnel insurance.

Risks Related to Financing Our Business

Our substantial debt could adversely affect our financial health and make us more vulnerable to adverse economic conditions.

As of December 31, 2021, we had approximately $32.4 billion of consolidated debt (excluding debt fair value adjustments). Additionally, we and substantially all of our wholly owned U.S. subsidiaries are parties to a cross guarantee agreement under which each party to the agreement unconditionally guarantees the indebtedness of each other party, which means that we are liable for the debt of each of such subsidiaries. This level of consolidated debt and the cross guarantee agreement could have important consequences, such as (i) limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements or potential growth, or for other purposes; (ii) increasing the cost of our future borrowings; (iii) limiting our ability to use operating cash flow in other areas of our business or to pay dividends because we must dedicate a substantial portion of these funds to make payments on our debt; (iv) placing us at a competitive disadvantage compared to competitors with less debt; and (v) increasing our vulnerability to adverse economic and industry conditions.

Our ability to service our consolidated debt, and our ability to meet our consolidated leverage targets, will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond our control. If our consolidated cash flow is not sufficient to service our consolidated debt, and any future indebtedness that we incur, we will be forced to take actions such as reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may also take such actions to reduce our indebtedness if we determine that our earnings (or consolidated EBITDA, as calculated in accordance with our revolving credit facility) may not be sufficient to meet our consolidated leverage targets or to comply with consolidated leverage ratios required under certain of our debt agreements. We may not be able to effect any of these actions on satisfactory terms or at all. For more information about our debt, see Note 9 “Debt” to our consolidated financial statements.

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Our business, financial condition and operating results may be affected adversely by increased costs of capital or a reduction in the availability of credit.

Adverse changes to the availability, terms and cost of capital, interest rates or our credit ratings (which would have a corresponding impact on the credit ratings of our subsidiaries that are party to the cross guarantee agreement) could cause our cost of doing business to increase by limiting our access to capital, including our ability to refinance maturities of existing indebtedness on similar terms, which could in turn reduce our cash flows and limit our ability to pursue acquisition or expansion opportunities. Our credit ratings may be impacted by our leverage, liquidity, credit profile and potential transactions. Although the ratings from credit agencies are not recommendations to buy, sell or hold our securities, our credit ratings will generally affect the market value of our and our subsidiaries’ debt securities and the terms available to us for future issuances of debt securities.

Also, disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability, impacting our ability to finance our operations on favorable terms. A significant reduction in the availability of credit could materially and adversely affect our business, financial condition and results of operations.

Our and our customers’ access to capital could be affected by evolving financial institutions’ policies concerning businesses linked to fossil fuels.

Our and our customers’ access to capital could be affected by financial institutions’ evolving policies concerning businesses linked to fossil fuels. Public opinion toward industries linked to fossil fuels continues to evolve. Concerns about the potential effects of climate change have caused some to direct their attention towards sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in such companies. Ultimately, this could make it more difficult for our customers to secure funding for exploration and production activities or for us to secure funding for growth projects, and consequently could both indirectly affect demand for our services and directly affect our ability to fund construction or other capital projects.

Our large amount of variable rate debt makes us vulnerable to increases in interest rates.

As of January 4, 2022, approximately $2.1 billion of our approximately $32.4 billion of consolidated debt (excluding debt fair value adjustments) was subject to variable interest rates, either as short-term or long-term variable-rate debt obligations, or as long-term fixed-rate debt effectively converted to variable rates through the use of interest rate swaps. Variable-to-fixed interest rate swap agreements covering an additional $5.1 billion of our consolidated debt will expire at the end of 2022. Should interest rates increase, the amount of cash required to service variable-rate debt would increase, as would our costs to refinance maturities of existing indebtedness, and our earnings and cash flows could be adversely affected.

For more information about our interest rate risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”

Acquisitions and growth capital expenditures may require access to external capital. Limitations on our access to external financing sources could impair our ability to grow.

We have limited amounts of internally generated cash flows to fund acquisitions and growth capital expenditures. If our internally generated cash flows are not sufficient to fund one or more capital projects or acquisitions, we may have to rely on external financing sources, including commercial borrowings and issuances of debt and equity securities, to fund our acquisitions and growth capital expenditures. Limitations on our access to external financing sources, whether due to tightened capital markets, more expensive capital or otherwise, could impair our ability to execute our growth strategy.

Our debt instruments may limit our financial flexibility and increase our financing costs.

The instruments governing our debt contain restrictive covenants that may prevent us from engaging in certain transactions that may be beneficial to us. Some of the agreements governing our debt generally require us to comply with various affirmative and negative covenants, including the maintenance of certain financial ratios and restrictions on (i) incurring additional debt; (ii) entering into mergers, consolidations and sales of assets; (iii) granting liens; and (iv) entering into sale-leaseback transactions. The instruments governing any future debt may contain similar or more limiting restrictions. Our ability to respond to changes in business and economic conditions and to obtain additional financing, if needed, may be restricted.

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Risks Related to Regulation

The FERC or state public utility commissions, such as the CPUC, may establish pipeline tariff rates that have a negative impact on us. In addition, the FERC, state public utility commissions or our customers could initiate proceedings or file complaints challenging the tariff rates charged by our pipelines, which could have an adverse impact on us.

The profitability of our regulated pipelines is influenced by fluctuations in costs and our ability to recover any increases in our costs in the rates charged to our shippers. To the extent that our costs increase in an amount greater than what we are permitted by the FERC or state public utility commissions to recover in our rates, or to the extent that there is a lag before we can file for and obtain rate increases, such events can have a negative impact on our operating results.

Our existing rates may also be challenged by complaint. Regulators and shippers on our pipelines have rights to challenge, and have challenged, the rates we charge under certain circumstances prescribed by applicable regulations. Some shippers on our pipelines have filed complaints with the regulators that seek substantial refunds for alleged overcharges during the years in question and prospective reductions in the tariff rates. Further, the FERC may continue to initiate investigations to determine whether interstate natural gas pipelines have over-collected on rates charged to shippers. We may face challenges, similar to those described in Note 18 “Litigation and Environmental” to our consolidated financial statements, to the rates we charge on our pipelines. Any successful challenge to our rates could materially adversely affect our future earnings, cash flows and financial condition.

New laws, policies, regulations, rulemaking and oversight, as well as changes to those currently in effect, could adversely impact our earnings, cash flows and operations.

Our assets and operations are subject to regulation and oversight by federal, state and local regulatory authorities. Legislative changes, as well as regulatory actions taken by these authorities, have the potential to adversely affect our profitability. Additional regulatory burdens and uncertainties will be created if and to the extent that more stringent energy and environmental policies are enacted. For example, on November 15, 2021, the EPA published a proposed rule containing standards of performance for GHG emissions, in the form of methane limitations, and volatile organic compound emissions for new, modified, and reconstructed crude oil and natural gas sources, including the production, processing, transmission and storage segments. This proposal, if finalized, and other regulatory initiatives may affect our assets and operations directly or indirectly, such as by increasing the costs associated with the production of natural gas and liquids that we transport. In addition, on January 27, 2021, the President issued an executive order directing, among other matters, the reevaluation of the leasing program for federally managed lands and the “pause” of new oil and natural gas leases on public lands pending completion of the review. In July 2021, a federal district court granted a nationwide preliminary injunction against enforcement of the “pause.” The Biden Administration has appealed the injunction. On November 26, 2021, the Department of the Interior issued a report in response to the President’s executive order calling for an increase in royalty payments for new oil and gas leases on federal lands. These and other initiatives of the presidential administration may affect our assets and operations directly or indirectly, such as by preventing or delaying the exploration for and production of natural gas and liquids that we transport.

Regulation affects almost every part of our business and extends to such matters as (i) federal, state and local taxation; (ii) rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for), operating terms and conditions of service; (iii) the types of services we may offer to our customers; (iv) the contracts for service entered into with our customers; (v) the certification and construction of new facilities; (vi) the integrity, safety and security of facilities and operations; (vii) the acquisition of other businesses; (viii) the acquisition, extension, disposition or abandonment of services or facilities; (ix) reporting and information posting requirements; (x) the maintenance of accounts and records; and (xi) relationships with affiliated companies involved in various aspects of the natural gas and energy businesses.

Should we fail to comply with any applicable statutes, rules, regulations, and orders of such regulatory authorities, we could be subject to substantial penalties and fines and potential loss of government contracts. Furthermore, new laws or regulations or policy changes sometimes arise from unexpected sources. New laws or regulations, or different interpretations of existing laws or regulations, including unexpected policy changes, applicable to our income, operations, assets or another aspect of our business could have a material adverse impact on our earnings, cash flow, financial condition and results of operations. For more information, see Items 1 and 2 “Business and Properties—Narrative Description of Business—Industry Regulation.”

Environmental, health and safety laws and regulations could expose us to significant costs and liabilities.

Our operations are subject to federal, state and local laws, regulations and potential liabilities arising under or relating to the protection or preservation of the environment, natural resources and human health and safety. Such laws and regulations
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affect many aspects of our past, present and future operations, and generally require us to obtain and comply with various environmental registrations, licenses, permits, inspections and other approvals. Liability under such laws and regulations may be incurred without regard to fault under CERCLA, the Resource Conservation and Recovery Act, the Federal Clean Water Act, the Oil Pollution Act or analogous state laws as a result of the presence or release of hydrocarbons and other hazardous substances into or through the environment, and these laws may require response actions and remediation and may impose liability for natural resource and other damages. Private parties, including the owners of properties through which our pipelines pass, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with such laws and regulations or for personal injury or property damage. Our insurance may not cover all environmental risks and costs and/or may not provide sufficient coverage in the event an environmental claim is made against us.

Failure to comply with these laws and regulations including required permits and other approvals also may expose us to civil, criminal and administrative fines, penalties and/or interruptions in our operations that could harm our business, financial position, results of operations and prospects. For example, if a leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines, shipping vessels or storage or other facilities, we may experience significant operational disruptions and we may have to pay a significant amount to clean up or otherwise respond to the leak, release or spill, pay government penalties, address natural resource damage, compensate for human exposure or property damage, install costly pollution control equipment or undertake a combination of these and other measures. The resulting costs and liabilities could materially and negatively affect our earnings and cash flows.

We own and/or operate numerous properties and equipment that have been used for many years in connection with our business activities. While we believe we have utilized operating, handling and disposal practices that were consistent with industry practices at the time, hydrocarbons or other hazardous substances may have been released at or from properties and equipment owned, operated or used by us or our predecessors, or at or from properties where our or our predecessors’ wastes have been taken for disposal. In addition, many of these properties have been owned and/or operated by third parties whose management, handling and disposal of hydrocarbons or other hazardous substances were not under our control. These properties and the hazardous substances released and wastes disposed on them may be subject to laws in the U.S. such as CERCLA, which impose joint and several liability without regard to fault or the legality of the original conduct. Under such laws and implementing regulations, we could be required to remove or remediate previously disposed wastes or property contamination, including contamination caused by prior owners or operators. Imposition of such liability schemes could have a material adverse impact on our operations and financial position.

Further, we cannot ensure that such existing laws and regulations will not be revised or that new laws or regulations will not be adopted or become applicable to us. For example, the Federal Clean Air Act and other similar federal and state laws are subject to periodic review and amendment, which could result in more stringent emission control requirements obligating us to make significant capital expenditures at our facilities. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects. For more information, see Items 1 and 2 “Business and Properties—Narrative Description of Business—Environmental Matters.”

Increased regulatory requirements relating to the integrity of our pipelines may require us to incur significant capital and operating expense outlays to comply.

We are subject to extensive laws and regulations related to pipeline safety and integrity at the federal and state levels. There are, for example, regulations issued by the U.S. Department of Transportation (U.S. DOT) for pipeline companies in the areas of operations, testing, education, training and communication. We expect the costs of compliance with these regulations, including integrity management rules, will be substantial. The majority of compliance costs relate to pipeline integrity testing and repairs. Technological advances in in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipeline determined to be located in HCAs or MCAs can have a significant impact on integrity testing and repair costs. We plan to continue our integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by the U.S. DOT rules. Repairs or upgrades deemed necessary to address results of these tests and/or ensure the continued safe and reliable operation of our pipeline could cause us to incur significant and unanticipated capital and operating expenditures.

Further, additional laws and regulations that may be enacted in the future or a new interpretation of existing laws and regulations could significantly increase the amount of these expenditures. There can be no assurance as to the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating
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restrictions, particularly if those costs are not deemed by regulators to be fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects.

Climate-related risk and related regulation could result in significantly increased operating and capital costs for us and could reduce demand for our products and services.

Various laws and regulations exist or are under development that seek to regulate the emission of GHGs such as methane and CO2, including the EPA programs to control GHG emissions and state actions to develop statewide or regional programs. Existing EPA regulations require us to report GHG emissions in the U.S. from sources such as our larger natural gas compressor stations, fractionated NGL, and production of naturally occurring CO2 (for example, from our McElmo Dome CO2 field), even when such production is not emitted to the atmosphere. Proposed approaches to further address GHG emissions include establishing GHG “cap and trade” programs, a fee on methane emissions from petroleum and natural gas systems, increased efficiency standards, participation in international climate agreements, issuance of executive orders by the U.S. presidential administration and incentives or mandates for pollution reduction, use of renewable energy sources, or use of alternative fuels with lower carbon content. For more information about climate change regulation, see Items 1 and 2 “Business and Properties—Narrative Description of Business—Environmental Matters—Climate Change.”

Adoption of any such laws or regulations could increase our costs to operate and maintain our facilities and could require us to install new emission controls on our facilities, acquire allowances for our GHG emissions, pay taxes related to our GHG emissions and administer and manage a GHG emissions program, and such increased costs could be significant. Recovery of such increased costs from our customers is uncertain in all cases and may depend on events beyond our control, including the outcome of future rate proceedings before the FERC. Such laws or regulations could also lead to reduced demand for hydrocarbon products that are deemed to contribute to GHGs, or restrictions on their use, which in turn could adversely affect demand for our products and services.

Finally, many climate models indicate that global warming is likely to result in rising sea levels and increased frequency and severity of weather events, which may lead to higher insurance costs, or a decrease in available coverage, for our assets in areas subject to severe weather. These climate-related changes could result in damage to our physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone and rain-susceptible regions.

Any of the foregoing could have adverse effects on our business, financial position, results of operations or cash flows.

Increased regulation of exploration and production activities, including activity on public lands and hydraulic fracturing, could result in reductions or delays in drilling and completing new oil and natural gas wells, as well as reductions in production from existing wells, which could adversely impact the volumes of natural gas transported on our natural gas pipelines and our own oil and gas development and production activities.

We gather, process or transport crude oil, natural gas or NGL from several areas, including lands that are federally managed. Policy and regulatory initiatives or legislation by Congress may decrease access to federally managed lands and increase the regulatory burdens associated with using these lands to produce crude oil or natural gas.

The use of hydraulic fracturing is prevalent in areas where we have operations. Oil and gas development and production activities are subject to numerous federal, state and local laws and regulations relating to environmental quality and pollution control. The oil and gas industry is increasingly relying on supplies of hydrocarbons from unconventional sources, such as shale, tight sands and coal bed methane. The extraction of hydrocarbons from these sources frequently requires hydraulic fracturing. Hydraulic fracturing involves the pressurized injection of water, sand, and chemicals into the geologic formation to stimulate gas production and is a commonly used stimulation process employed by oil and gas exploration and production operators in the completion of certain oil and gas wells. There have been initiatives at the federal and state levels to regulate or otherwise restrict the use of certain hydraulic fracturing activities. Adoption of legislation or regulations placing restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on exploration and production operators, which could reduce their production of crude oil, natural gas or NGL and, in turn, adversely affect our revenues, cash flows and results of operations by decreasing the volumes of these commodities that we handle.

In addition, many states are promulgating stricter requirements related not only to well development but also to compressor stations and other facilities in the oil and gas industry sector. These laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation. Specifically, these activities are subject to laws and regulations regarding the acquisition of permits before drilling, restrictions on drilling activities and location,
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emissions into the environment, water discharges, transportation of hazardous materials, and storage and disposition of wastes. In addition, legislation has been enacted that requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities. These laws and regulations may adversely affect our oil and gas development and production activities.

The Jones Act includes restrictions on ownership by non-U.S. citizens of our U.S. point to point maritime shipping vessels, and failure to comply with the Jones Act, or changes to or a repeal of the Jones Act, could limit our ability to operate our vessels in the U.S. coastwise trade, result in the forfeiture of our vessels or otherwise adversely impact our earnings, cash flows and operations.

We are subject to the Jones Act, which generally restricts U.S. point-to-point maritime shipping to vessels operating under the U.S. flag, built in the U.S., owned and operated by U.S.-organized companies that are controlled and at least 75% owned by U.S. citizens and crewed by predominately U.S. citizens. Our business would be adversely affected if we fail to comply with the Jones Act provisions on coastwise trade. If we do not comply with any of these requirements, we would be prohibited from operating our vessels in the U.S. coastwise trade and, under certain circumstances, we could be deemed to have undertaken an unapproved transfer to non-U.S. citizens that could result in severe penalties, including permanent loss of U.S. coastwise trading rights for our vessels, fines or forfeiture of vessels. Our business could be adversely affected if the Jones Act were to be modified or repealed so as to permit foreign competition that is not subject to the same U.S. government imposed burdens.

Proposed changes to U.S. federal, state, and local tax laws, if enacted, could have a material adverse effect on our business and profitability.

New or revised U.S. federal, state, or local tax legislation may be enacted in the future, and such legislation could materially impact our current or future tax planning and effective tax rates. For example, President Biden and Congress have set forth proposals that would, if enacted, make significant changes to U.S. federal income tax laws applicable to domestic corporations. Such proposals include, but are not limited to, (i) an increase in the U.S. federal income tax rate applicable to corporations and (ii) a minimum book income tax applicable to certain large corporations. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals and other similar changes in U.S. federal income or other tax laws could materially and adversely affect our business, cash flows, and future profitability.

Risks Related to Ownership of Our Capital Stock

The guidance we provide for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.

We disclose in this report and elsewhere the expected cash dividends on our common stock. These reflect our current judgment, but as with any estimate, they may be affected by inaccurate assumptions and other risks and uncertainties, many of which are beyond our control. See “Information Regarding Forward-Looking Statements” at the beginning of this report. If our board of directors elects to pay dividends at the anticipated level and that action would leave us with insufficient cash to take timely advantage of growth opportunities (including through acquisitions), to meet any large unanticipated liquidity requirements, to fund our operations, to maintain our leverage metrics or otherwise to address properly our business prospects, our business could be harmed.

Conversely, a decision to address such needs might lead to the payment of dividends below the anticipated levels. As events present themselves or become reasonably foreseeable, our board of directors, which determines our business strategy and our dividends, may decide to address those matters by reducing our anticipated dividends. Alternatively, because nothing in our governing documents or credit agreements prohibits us from borrowing to pay dividends, we could choose to incur debt to enable us to pay our anticipated dividends. This would add to our substantial debt discussed above under “—Risks Related to Financing Our Business—Our substantial debt could adversely affect our financial health and make us more vulnerable to adverse economic conditions.”

Our certificate of incorporation restricts the ownership of our common stock by non-U.S. citizens within the meaning of the Jones Act. These restrictions may affect the liquidity of our common stock and may result in non-U.S. citizens being required to sell their shares at a loss.

The Jones Act requires, among other things, that at least 75% of our common stock be owned at all times by U.S. citizens, as defined under the Jones Act, in order for us to own and operate vessels in the U.S. coastwise trade. As a safeguard to help us maintain our status as a U.S. citizen, our certificate of incorporation provides that, if the number of shares of our common stock owned by non-U.S. citizens exceeds 22%, we have the ability to redeem shares owned by non-U.S. citizens to reduce the
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percentage of shares owned by non-U.S. citizens to 22%. These redemption provisions may adversely impact the marketability of our common stock, particularly in markets outside of the U.S. Further, those stockholders would not have control over the timing of such redemption, and may be subject to redemption at a time when the market price or timing of the redemption is disadvantageous. In addition, the redemption provisions might have the effect of impeding or discouraging a merger, tender offer or proxy contest by a non-U.S. citizen, even if it were favorable to the interests of some or all of our stockholders.

Item 1B.  Unresolved Staff Comments.

None.

Item 3.  Legal Proceedings.

See Note 18 “Litigation and Environmental” to our consolidated financial statements.

Item 4.  Mine Safety Disclosures.

We no longer own or operate mines for which reporting requirements apply under the mine safety disclosure requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank), except for one terminal that is in temporary idle status with the Mine Safety and Health Administration. We have not received any specified health and safety violations, orders or citations, related assessments or legal actions, mining-related fatalities, or similar events requiring disclosure pursuant to the mine safety disclosure requirements of Dodd-Frank for the year ended December 31, 2021.

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PART II

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

As of February 4, 2022, we had 10,236 holders of our Class P common stock, which does not include beneficial owners whose shares are held by a nominee, such as a broker or bank.

For information on our equity compensation plans, see Note 10 “Share-based Compensation and Employee Benefits—Share-based Compensation” to our consolidated financial statements.

Item 6.  [Reserved] 

Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto.  We prepared our consolidated financial statements in accordance with GAAP. Additional sections in this report which should be helpful to the reading of our discussion and analysis include the following: (i) a description of our business strategy found in Items 1 and 2 “Business and Properties—Narrative Description of Business—Business Strategy;” (ii) a description of developments during 2021, found in Items 1 and 2 “Business and Properties—General Development of Business—Recent Developments;” (iii) a description of risk factors affecting us and our business, found in Item 1A “Risk Factors;” and (iv) a discussion of forward-looking statements, found in “Information Regarding Forward-Looking Statements” at the beginning of this report.

A comparative discussion of our 2020 to 2019 operating results can be found in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2020 filed with the SEC on February 5, 2021.

General

Business Segments

As an energy infrastructure owner and operator in multiple facets of the various U.S. energy industries and markets, we examine a number of variables and factors on a routine basis to evaluate our current performance and our prospects for the future.  We have four business segments as further described below.

Natural Gas Pipelines

This segment owns and operates (i) major interstate and intrastate natural gas pipeline and storage systems; (ii) natural gas gathering systems and processing and treating facilities; (iii) NGL fractionation facilities and transportation systems; and (iv) LNG regasification, liquefaction and storage facilities.

With respect to our interstate natural gas pipelines, related storage facilities and LNG terminals, the revenues from these assets are primarily received under long-term fixed contracts.  To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate risk of reduced volumes and prices by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity.  These long-term contracts are typically structured with a fixed fee reserving the right to transport or store natural gas and specify that we receive the majority of our fee for making the capacity available, whether or not the customer actually chooses to utilize the capacity.  Similarly, our Texas Intrastate natural gas pipeline operations, currently derives approximately 84% of its sales and transport margins from long-term transport and sales contracts.  As contracts expire, we have additional exposure to the longer term trends in supply and demand for natural gas.  As of December 31, 2021, the remaining weighted average contract life of our natural gas transportation contracts held by assets we own and have equity interests in (including intrastate pipelines’ sales portfolio) was approximately six years. Our LNG regasification and liquefaction and associated storage contracts are subscribed under long-term agreements with a weighted average remaining contract life of approximately 12 years.

Our midstream assets provide natural gas gathering and processing services. These assets are mostly fee-based and the revenues and earnings we realize from gathering natural gas, processing natural gas in order to remove NGL from the natural gas stream, and fractionating NGL into its base components, are affected by the volumes of natural gas made available to our systems. Such volumes are impacted by producer rig count and drilling activity. In addition to fee-based arrangements, some of which may include minimum volume commitments, we also provide some services based on percent-of-proceeds, percent-
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of-index and keep-whole contracts. Our service contracts may rely solely on a single type of arrangement, but more often they combine elements of two or more of the above, which helps us and our counterparties manage the extent to which each shares in the potential risks and benefits of changing commodity prices.
Products Pipelines

This segment owns and operates refined petroleum products, crude oil and condensate pipelines that primarily deliver, among other products, gasoline, diesel and jet fuel, crude oil and condensate to various markets. This segment also owns and/or operates associated product terminals and petroleum pipeline transmix facilities.
The profitability of our refined petroleum products pipeline transportation business generally is driven by the volume of refined petroleum products that we transport and the prices we receive for our services. We also have 49 liquids terminals in this business segment that store fuels and offer blending services for ethanol and biodiesel. The transportation and storage volume levels are primarily driven by the demand for the refined petroleum products being shipped or stored.  Demand for refined petroleum products tends to track in large measure demographic and economic growth, and, with the exception of periods of time with very high product prices or recessionary conditions, demand tends to be relatively stable.  Because of that, we seek to own refined petroleum products pipelines and terminals located in, or that transport to, stable or growing markets and population centers.  The prices for shipping are generally based on regulated tariffs that are adjusted annually based on changes in the U.S. Producer Price Index and a FERC index rate.

Our crude, condensate and refined petroleum products transportation services are primarily provided pursuant to (i) either FERC or state tariffs and (ii) long-term contracts that normally contain minimum volume commitments. As a result of these contracts, our settlement volumes are generally not sensitive to changing market conditions in the shorter term; however, the revenues and earnings we realize from our pipelines and terminals are affected by the volumes of crude oil, refined petroleum products and condensate available to our pipeline systems, which are impacted by the level of oil and gas drilling activity and product demand in the respective regions that we serve. Our petroleum condensate processing facility splits condensate into its various components, such as light and heavy naphtha, under a long-term fee-based agreement with a major integrated oil company.

Terminals

This segment owns and operates (i) liquids and bulk terminal facilities located throughout the U.S. that store and handle various commodities including gasoline, diesel fuel, chemicals, renewable fuels, metals and petroleum coke; and (ii) Jones Act-qualified tankers.

The factors impacting our Terminals business segment generally differ between liquid and bulk terminals, and in the case of a bulk terminal, the type of product being handled or stored.  Our liquids terminals business generally has long-term contracts that require the customer to pay regardless of whether they use the capacity.  Thus, similar to our natural gas pipelines business, our liquids terminals business is less sensitive to short-term changes in supply and demand.  Therefore, the extent to which changes in these variables affect our terminals business in the near term is a function of the remaining length of the underlying service contracts (which on a weighted average basis is approximately three years), the extent to which revenues under the contracts are a function of the amount of product stored or transported, and the extent to which such contracts expire during any given period of time. 

As with our refined petroleum products pipelines transportation business, the revenues from our bulk terminals business are generally driven by the volumes we handle and/or store, as well as the prices we receive for our services, which in turn are driven by the demand for the products being shipped or stored.  While we handle and store a large variety of products in our bulk terminals, the primary products are petroleum coke, metals and ores. In addition, the majority of our contracts for this business contain minimum volume guarantees and/or service exclusivity arrangements under which customers are required to utilize our terminals for all or a specified percentage of their handling and storage needs.  The profitability of our minimum volume contracts is generally unaffected by short-term variation in economic conditions; however, to the extent we expect volumes above the minimum and/or have contracts which are volume-based, we can be sensitive to changing market conditions.  To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate the risk of reduced volumes and pricing by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity.  In addition, weather-related events, including hurricanes, may impact our facilities and access to them and, thus, the profitability of certain terminals for limited periods of time or, in relatively rare cases of severe damage to facilities, for longer periods.

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In addition to liquid and bulk terminals, we also own Jones Act-qualified tankers in our Terminals business segment. As of December 31, 2021, we have 16 Jones Act-qualified tankers that operate in the marine transportation of crude oil, condensate and refined products in the U.S. and are primarily operating pursuant to fixed price term charters with major integrated oil companies, major refiners and the U.S. Military Sealift Command.

CO2

This segment (i) manages the production, transportation and marketing of CO2 to oil fields that use CO2 as a flooding medium to increase recovery and production of crude oil from mature oil fields; (ii) owns interests in and/or operates oil fields and gasoline processing plants in West Texas; (iii) owns and operates a crude oil pipeline system in West Texas; and (iv) owns and operates RNG and LNG facilities in Indiana associated with our acquisition of Kinetrex discussed below.

The CO2 source and transportation business primarily has third-party contracts with minimum volume requirements, which as of December 31, 2021, had a remaining average contract life of approximately eight years.  CO2 sales contracts vary from customer to customer and have evolved over time as supply and demand conditions have changed.  Our current sales contracts have generally provided for a delivered price tied to the price of crude oil, but with a floor price.  Beginning in 2022, due to the floor price associated with a significant sales contract no longer being a component of the pricing formula, only a small percentage of our sales contracts will be based on a fixed fee or floor price. Our success in this portion of the CO2 business segment can be impacted by the demand for CO2.  In the CO2 business segment’s oil and gas producing activities, we monitor the amount of capital we expend in relation to the amount of production that we expect to add.  The revenues we receive from our crude oil and NGL sales are affected by the prices we realize from the sale of these products.  Over the long-term, we will tend to receive prices that are dictated by the demand and overall market price for these products.  In the shorter term, however, market prices are likely not indicative of the revenues we will receive due to our risk management, or hedging, program, in which the prices to be realized for certain of our future sales quantities are fixed, capped or bracketed through the use of financial derivative contracts, particularly for crude oil.  The realized weighted average crude oil price per barrel, with the hedges allocated to oil, was $52.71 per barrel in 2021 and $53.78 per barrel in 2020.  Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $68.47 per barrel in 2021 and $38.32 per barrel in 2020.

Also, see Note 15 “Revenue Recognition” to our consolidated financial statements for more information about the types of contracts and revenues recognized for each of our segments.

Stagecoach Acquisition

On July 9, 2021 and November 24, 2021, we completed the acquisitions of Stagecoach Gas Services LLC and its subsidiaries (Stagecoach), a natural gas pipeline and storage joint venture between Consolidated Edison, Inc. and Crestwood Equity Partners, LP, for approximately $1,258 million, including purchase price adjustments for working capital. The Stagecoach assets include 4 natural gas storage facilities with a total FERC-certificated working capacity of 41 Bcf and a network of FERC-regulated natural gas transportation pipelines with multiple interconnects to major interstate natural gas pipelines in the northeast region of the U.S., including TGP. The acquired assets are included in our Natural Gas Pipelines business segment.

Kinetrex Acquisition

On August 20, 2021, we completed the acquisition of Indianapolis-based Kinetrex from an affiliate of Parallel49 Equity for $318 million, including a preliminary purchase price adjustment for working capital. Kinetrex is a supplier of LNG in the Midwest and a producer and supplier of RNG under long-term contracts to transportation service providers. Kinetrex has a 50% interest in the largest RNG facility in Indiana and we commenced construction on three additional landfill-based RNG facilities in September 2021. The acquired assets are included as part of our new Energy Transition Ventures group within our CO2 business segment.

Sale of an Interest in NGPL Holdings LLC

On March 8, 2021, we and Brookfield Infrastructure Partners L.P. (Brookfield) completed the sale of a combined 25% interest in our joint venture, NGPL Holdings LLC (NGPL Holdings), to a fund controlled by ArcLight Capital Partners, LLC (ArcLight). We received net proceeds of $412 million for our proportionate share of the interests sold. We recognized a pre-tax gain of $206 million for our proportionate share, which is included within “Other, net” in our accompanying consolidated statement of operations for the year ended December 31, 2021. We and Brookfield now each hold a 37.5% interest in NGPL Holdings.
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February 2021 Winter Storm

Our earnings for 2021 reflect impacts of the February 2021 winter storm that affected Texas, which are largely nonrecurring. See “—Segment Earnings Results” below.

2022 Dividends and Discretionary Capital

We expect to declare dividends of $1.11 per share for 2022, a 3% increase from the 2021 declared dividends of $1.08 per share. We also expect to invest $1.3 billion in expansion projects and contributions to joint ventures, or discretionary capital expenditures during 2022.

The expectations for 2022 discussed above involve risks, uncertainties and assumptions, and are not guarantees of performance.  Many of the factors that will determine these expectations are beyond our ability to control or predict, and because of these uncertainties, it is advisable not to put undue reliance on any forward-looking statement.  Please read our Item 1A “Risk Factors” below and “Information Regarding Forward-Looking Statements” at the beginning of this report for more information.  Furthermore, we plan to provide updates to these 2022 expectations when we believe previously disclosed expectations no longer have a reasonable basis.

Critical Accounting Estimates

Accounting standards require information in financial statements about the risks and uncertainties inherent in significant estimates, and the application of GAAP involves the exercise of varying degrees of judgment. Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for our assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements. We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates, and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

Critical accounting estimates and assumptions involve material levels of subjectivity and complex judgement to account for highly uncertain matters or matters with a high susceptibility to change, and could result in a material impact to our financial statements. Examples of certain areas that require more judgment relative to others when preparing our consolidated financial statements and related disclosures include our use of estimates in determining: (i) revenue recognition; (ii) income taxes; (iii) the economic useful lives of our assets and related depletion rates; (iv) the fair values used in (a) assigning the purchase price of a business acquisition, (b) calculations of possible asset and equity investment impairment charges, (c) calculation for the annual goodwill impairment test (or interim tests if triggered), and (d) recording derivative contract assets and liabilities; (v) reserves for environmental claims, legal fees, transportation rate cases and other litigation liabilities; (vi) provisions for credit losses; (vii) computation of the gain or loss, if any, on assets sold in whole or in part; and (viii) exposures under contractual indemnifications.

For a summary of our significant accounting policies, see Note 2 “Summary of Significant Accounting Policies” to our consolidated financial statements and the following discussion for further information regarding critical estimates and assumptions used in the preparation of our financial statements.

Acquisition Method of Accounting

For acquired businesses, we recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired is recorded to goodwill. Determining the fair value of these items requires management’s judgment and/or the utilization of independent valuation specialists and involves the use of significant estimates and assumptions. The judgments made in the determination of the estimated fair value assigned to the assets acquired, the liabilities assumed and any noncontrolling interest in the investee, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. For more information on our acquisitions and application of the acquisition method, see Note 3 “Acquisitions and Divestitures” to our consolidated financial statements.

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Impairments

In addition to our annual testing of impairment for goodwill, we evaluate impairment of our long-lived assets when a triggering event occurs. Management applies judgment in determining whether there is an impairment indicator. Fair value calculated for the purpose of testing our long-lived assets, including intangible assets, goodwill and equity method investments for impairment involves the use of significant estimates and assumptions regarding the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The estimates and assumptions can be affected by a variety of factors, including external factors such as industry and economic trends, and internal factors such as changes in our business strategy and our internal forecasts. An estimate of the sensitivity to changes in underlying assumptions of a fair value calculation is not practicable, given the numerous assumptions that can materially affect our estimates.

For more information on our impairments and significant estimates and assumptions used in our impairment evaluations, see Note 4 “Losses and Gains on Impairments, Divestitures and Other Write-downs.”

Hedging Activities

All of our derivative contracts are recorded at estimated fair value. We utilize published prices, broker quotes, and estimates of market prices to estimate the fair value of these contracts; however, actual amounts could vary materially from estimated fair values as a result of changes in market prices. In addition, changes in the methods used to determine the fair value of these contracts could have a material effect on our results of operations. We do not anticipate future changes in the methods used to determine the fair value of these derivative contracts. For more information on our hedging activities, see Note 14 “Risk Management” to our consolidated financial statements.

Environmental Matters

With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. Our accrual of environmental liabilities often coincides either with our completion of a feasibility study or our commitment to a formal plan of action, but generally, we recognize and/or adjust our probable environmental liabilities, if necessary or appropriate, following quarterly reviews of potential environmental issues and claims that could impact our assets or operations. In recording and adjusting environmental liabilities, we consider the effect of environmental compliance, pending legal actions against us, and potential third party liability claims. For more information on environmental matters, see Part I, Items 1 and 2 “Business and Properties—Narrative Description of Business—Environmental Matters.” For more information on our environmental disclosures, see Note 18 “Litigation and Environmental” to our consolidated financial statements.

Legal and Regulatory Matters

Many of our operations are regulated by various U.S. regulatory bodies, and we are subject to legal and regulatory matters as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. Any such liability recorded is revised as better information becomes available. Accordingly, to the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. For more information on legal proceedings, see Note 18 “Litigation and Environmental” to our consolidated financial statements. 

Employee Benefit Plans

We reflect an asset or liability for our pension and other postretirement benefit (OPEB) plans based on their overfunded or underfunded status. As of December 31, 2021, our pension plans were underfunded by $427 million, and our OPEB plans were overfunded by $125 million. Our pension and OPEB obligations and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the rate at which we expect the compensation of our employees to increase over the plan term, the estimated cost of health care when benefits are provided under our plan and other factors. A significant assumption we utilize is the discount rate used in calculating our benefit obligations. We utilize a full yield curve approach to estimate the service and interest cost components of net periodic benefit cost (credit) for our pension and OPEB plans, which applies the specific spot rates along the yield curve used in determining the benefit obligation to the underlying projected cash flows. The selection of these assumptions is further discussed in Note 10 “Share-based Compensation and Employee Benefits” to our consolidated financial statements.

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Actual results may differ from the assumptions included in these calculations, and as a result, our estimates associated with our pension and OPEB can be, and have been revised in subsequent periods. The income statement impact of the changes in the assumptions on our related benefit obligations are deferred and amortized into income over either the period of expected future service of active participants, or over the expected future lives of inactive plan participants. As of December 31, 2021, we had deferred net losses of approximately $319 million in pre-tax accumulated other comprehensive loss related to our pension and OPEB plans.

The following sensitivity analysis shows the estimated impact of a 1% change in the primary assumptions used in our actuarial calculations associated with our pension and OPEB plans for the year ended December 31, 2021:
Pension BenefitsOPEB
Net benefit cost (income)Change in funded status(a)Net benefit cost (income)Change in funded status(a)
(In millions)
One percent increase in:
Discount rates$(11)$223 $1 $18 
Expected return on plan assets(21)— (4)— 
Rate of compensation increase3 (13)— — 
One percent decrease in:
Discount rates13 (266)— (20)
Expected return on plan assets21 — 4 — 
Rate of compensation increase(3)12 — — 
(a)Includes amounts deferred as either accumulated other comprehensive income (loss) or as a regulatory asset or liability for certain of our regulated operations.

Income Taxes

We make significant judgments and estimates in determining our provision for income taxes, including our assessment of our income tax positions given the uncertainties involved in the interpretation and application of complex tax laws and regulations in various taxing jurisdictions. Numerous and complex judgments and assumptions are inherent in the estimation of future taxable income when determining a valuation allowance, including factors such as future operating conditions and the apportionment of income by state. For more information, see Note 5 “Income Taxes” to our consolidated financial statements.

Results of Operations

Overview

As described in further detail below, our management evaluates our performance primarily using the GAAP financial measures of Segment EBDA (as presented in Note 16, “Reportable Segments”) and Net income attributable to Kinder Morgan, Inc., along with the non-GAAP financial measures of Adjusted Earnings and DCF, both in the aggregate and per share for each, Adjusted Segment EBDA, Adjusted EBITDA and Net Debt.

GAAP Financial Measures

The Consolidated Earnings Results for the years ended December 31, 2021 and 2020 present Segment EBDA and Net income attributable to Kinder Morgan, Inc. which are prepared and presented in accordance with GAAP. Segment EBDA is a useful measure of our operating performance because it measures the operating results of our segments before DD&A and certain expenses that are generally not controllable by our business segment operating managers, such as general and administrative expenses and corporate charges, interest expense, net, and income taxes. Our general and administrative expenses and corporate charges include such items as unallocated employee benefits, insurance, rentals, unallocated litigation and environmental expenses, and shared corporate services including accounting, information technology, human resources and legal services.

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Non-GAAP Financial Measures

Our non-GAAP financial measures described below should not be considered alternatives to GAAP Net income attributable to Kinder Morgan, Inc. or other GAAP measures and have important limitations as analytical tools. Our computations of these non-GAAP financial measures may differ from similarly titled measures used by others. You should not consider these non-GAAP financial measures in isolation or as substitutes for an analysis of our results as reported under GAAP. Management compensates for the limitations of these non-GAAP financial measures by reviewing our comparable GAAP measures, understanding the differences between the measures and taking this information into account in its analysis and its decision making processes.

Certain Items

Certain Items, as adjustments used to calculate our non-GAAP financial measures, are items that are required by GAAP to be reflected in Net income attributable to Kinder Morgan, Inc., but typically either (i) do not have a cash impact (for example, asset impairments), or (ii) by their nature are separately identifiable from our normal business operations and in our view are likely to occur only sporadically (for example, certain legal settlements, enactment of new tax legislation and casualty losses). We also include adjustments related to joint ventures (see “Amounts from Joint Ventures” below and the tables included in “—Consolidated Earnings Results (GAAP)—Certain Items Affecting Consolidated Earnings Results,” “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA” and “—Non-GAAP Financial Measures—Supplemental Information” below). In addition, Certain Items are described in more detail in the footnotes to tables included in “—Segment Earnings Results” and “—DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests” below.

Adjusted Earnings

Adjusted Earnings is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items. Adjusted Earnings is used by us and certain external users of our financial statements to assess the earnings of our business excluding Certain Items as another reflection of our ability to generate earnings. We believe the GAAP measure most directly comparable to Adjusted Earnings is Net income attributable to Kinder Morgan, Inc. Adjusted Earnings per share uses Adjusted Earnings and applies the same two-class method used in arriving at basic earnings per share. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF” below.

DCF

DCF is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items (Adjusted Earnings), and further by DD&A and amortization of excess cost of equity investments, income tax expense, cash taxes, sustaining capital expenditures and other items. We also include amounts from joint ventures for income taxes, DD&A and sustaining capital expenditures (see “Amounts from Joint Ventures” below). DCF is a significant performance measure useful to management and external users of our financial statements in evaluating our performance and in measuring and estimating the ability of our assets to generate cash earnings after servicing our debt, paying cash taxes and expending sustaining capital, that could be used for discretionary purposes such as dividends, stock repurchases, retirement of debt, or expansion capital expenditures. DCF should not be used as an alternative to net cash provided by operating activities computed under GAAP. We believe the GAAP measure most directly comparable to DCF is Net income attributable to Kinder Morgan, Inc. DCF per share is DCF divided by average outstanding shares, including restricted stock awards that participate in dividends. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF” and “—Adjusted Segment EBDA to Adjusted EBITDA to DCF” below.

Adjusted Segment EBDA

Adjusted Segment EBDA is calculated by adjusting Segment EBDA for Certain Items attributable to the segment. Adjusted Segment EBDA is used by management in its analysis of segment performance and management of our business. We believe Adjusted Segment EBDA is a useful performance metric because it provides management and external users of our financial statements additional insight into the ability of our segments to generate cash earnings on an ongoing basis. We believe it is useful to investors because it is a measure that management uses to allocate resources to our segments and assess each segment’s performance. We believe the GAAP measure most directly comparable to Adjusted Segment EBDA is Segment EBDA. See “—Consolidated Earnings Results (GAAP)—Certain Items Affecting Consolidated Earnings Results” for a reconciliation of Segment EBDA to Adjusted Segment EBDA by business segment.

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Adjusted EBITDA

Adjusted EBITDA is calculated by adjusting EBITDA for Certain Items. We also include amounts from joint ventures for income taxes and DD&A (see “Amounts from Joint Ventures” below). Adjusted EBITDA is used by management and external users, in conjunction with our Net Debt (as described further below), to evaluate certain leverage metrics. Therefore, we believe Adjusted EBITDA is useful to investors. We believe the GAAP measure most directly comparable to Adjusted EBITDA is Net income attributable to Kinder Morgan, Inc. In prior periods Net income was considered the comparable GAAP measure and has been updated to Net income attributable to Kinder Morgan, Inc. for consistency with our other non-GAAP performance measures. See “—Adjusted Segment EBDA to Adjusted EBITDA to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA” below.

Amounts from Joint Ventures

Certain Items, DCF and Adjusted EBITDA reflect amounts from unconsolidated joint ventures and consolidated joint ventures utilizing the same recognition and measurement methods used to record “Earnings from equity investments” and “Noncontrolling interests,” respectively. The calculations of DCF and Adjusted EBITDA related to our unconsolidated and consolidated joint ventures include the same items (DD&A and income tax expense, and for DCF only, also cash taxes and sustaining capital expenditures) with respect to the joint ventures as those included in the calculations of DCF and Adjusted EBITDA for our wholly-owned consolidated subsidiaries. (See “—Non-GAAP Financial Measures—Supplemental Information” below.) Although these amounts related to our unconsolidated joint ventures are included in the calculations of DCF and Adjusted EBITDA, such inclusion should not be understood to imply that we have control over the operations and resulting revenues, expenses or cash flows of such unconsolidated joint ventures.

Net Debt

Net Debt is calculated, based on amounts as of December 31, 2021, by subtracting the following amounts from our debt balance of $33,320 million: (i) cash and cash equivalents of $1,140 million; (ii) debt fair value adjustments of $902 million; and (iii) the foreign exchange impact on Euro-denominated bonds of $64 million for which we have entered into currency swaps. Net Debt is a non-GAAP financial measure that management believes is useful to investors and other users of our financial information in evaluating our leverage. We believe the most comparable measure to Net Debt is debt net of cash and cash equivalents.

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Consolidated Earnings Results (GAAP)

The following tables summarize the key components of our consolidated earnings results.
Year Ended December 31,
20212020Earnings
increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)  
Natural Gas Pipelines$3,815 $3,483 $332 10 %
Products Pipelines1,064 977 87 9 %
Terminals908 1,045 (137)(13)%
CO2
760 (292)1,052 360 %
Total segment EBDA6,547 5,213 1,334 26 %
DD&A(2,135)(2,164)29 1 %
Amortization of excess cost of equity investments(78)(140)62 44 %
General and administrative and corporate charges(623)(653)30 5 %
Interest, net(1,492)(1,595)103 6 %
Income before income taxes2,219 661 1,558 236 %
Income tax expense(369)(481)112 23 %
Net income1,850 180 1,670 928 %
Net income attributable to noncontrolling interests(66)(61)(5)(8)%
Net income attributable to Kinder Morgan, Inc.$1,784 $119 $1,665 1399 %
(a)Includes revenues, earnings from equity investments, and other, net, less operating expenses, loss on impairments and divestitures, net, and other income, net.  Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.

Year Ended December 31, 2021 vs. 2020

Net income attributable to Kinder Morgan, Inc. increased $1,665 million in 2021 compared to 2020. The increase primarily resulted from (i) $1,092 million of earnings related to the February 2021 winter storm, and therefore largely nonrecurring, mostly impacting the higher earnings from our Natural Gas Pipelines and CO2 business segments; and (ii) a decrease of $342 million in impairments in 2021 as compared to 2020 primarily reflecting the $1,600 million pre-tax non-cash asset impairment loss related to South Texas gathering and processing assets within our Natural Gas Pipeline segment in 2021 compared to the combined $1,950 million of non-cash impairments recognized in 2020 of goodwill associated with our Natural Gas Pipelines Non-Regulated and CO2 reporting units and non-cash asset impairments of certain oil and gas producing assets in our CO2 business segment. The impacts of the long-lived asset impairments were partially offset by associated tax benefits. The increase was also impacted by higher earnings from our Products Pipelines business segment, lower interest expense and amortization of excess cost of equity investments partially offset by lower earnings from our Terminals business segment.
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Certain Items Affecting Consolidated Earnings Results
Year Ended December 31,
20212020
GAAPCertain ItemsAdjustedGAAPCertain ItemsAdjustedAdjusted amounts
increase/(decrease) to earnings
(In millions)
Segment EBDA
Natural Gas Pipelines$3,815 $1,648 $5,463 $3,483 $983 $4,466 $997 
Products Pipelines1,064 53 1,117 977 50 1,027 90 
Terminals908 42 950 1,045 (55)990 (40)
CO2
760 (6)754 (292)944 652 102 
Total Segment EBDA(a)6,547 1,737 8,284 5,213 1,922 7,135 1,149 
DD&A and amortization of excess cost of equity investments(2,213)— (2,213)(2,304)— (2,304)91 
General and administrative and corporate charges(a)(623)— (623)(653)92 (561)(62)
Interest, net(a)(1,492)(26)(1,518)(1,595)(15)(1,610)92 
Income before income taxes2,219 1,711 3,930 661 1,999 2,660 1,270 
Income tax expense(b)(369)(491)(860)(481)(107)(588)(272)
Net income1,850 1,220 3,070 180 1,892 2,072 998 
Net income attributable to noncontrolling interests(a)(66)— (66)(61)— (61)(5)
Net income attributable to Kinder Morgan, Inc.$1,784 $1,220 $3,004 $119 $1,892 $2,011 $993 
(a)For a more detailed discussion of these Certain Items, see the footnotes to the tables within “—Segment Earnings Results” and “—DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests” below.
(b)The combined net effect of the income tax Certain Items represents the income tax provision on Certain Items plus discrete income tax items.

Net income attributable to Kinder Morgan, Inc. adjusted for Certain Items (Adjusted Earnings) increased by $993 million from the prior year resulting from earnings increases of $1,046 million from our Natural Gas Pipelines business segment’s Midstream region and $67 million from our CO2 business segment’s oil and gas producing activities (both primarily related to the February 2021 winter storm, and therefore largely nonrecurring), higher earnings from our Products Pipelines business segment and lower amortization of excess cost of equity investments and interest expense partially offset by higher general and administrative and corporate charges expense and lower earnings from our Terminals business segment. See “—Segment Earnings Results” and “—DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests” below.

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Non-GAAP Financial Measures

Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF
Year Ended December 31,
20212020
(In millions)
Net income attributable to Kinder Morgan Inc. (GAAP)$1,784 $119 
Total Certain Items1,220 1,892 
Adjusted Earnings(a)3,004 2,011 
DD&A and amortization of excess cost of equity investments for DCF(b)2,481 2,671 
Income tax expense for DCF(a)(b)943 670 
Cash taxes(b)(69)(68)
Sustaining capital expenditures(b)(864)(658)
Other items(c)(35)(29)
DCF$5,460 $4,597 

Adjusted Segment EBDA to Adjusted EBITDA to DCF
Year Ended December 31,
20212020
(In millions, except per share amounts)
Natural Gas Pipelines$5,463 $4,466 
Products Pipelines1,117 1,027 
Terminals950 990 
CO2
754 652 
Adjusted Segment EBDA(a)8,284 7,135 
General and administrative and corporate charges(a)(623)(561)
Joint venture DD&A and income tax expense(a)(b)351 449 
Net income attributable to noncontrolling interests(a)(66)(61)
Adjusted EBITDA7,946 6,962 
Interest, net(a)(1,518)(1,610)
Cash taxes(b)(69)(68)
Sustaining capital expenditures(b)(864)(658)
Other items(c)(35)(29)
DCF$5,460 $4,597 
Adjusted Earnings per share$1.32 $0.88 
Weighted average shares outstanding for dividends(d)2,278 2,276 
DCF per share$2.40 $2.02 
Declared dividends per share$1.08 $1.05 
(a)Amounts are adjusted for Certain Items. See tables included in “—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA” and “—Supplemental Information” below.
(b)Includes or represents DD&A, income tax expense, cash taxes and/or sustaining capital expenditures (as applicable for each item) from joint ventures. See tables included in “—Supplemental Information” below.
(c)Includes pension contributions and non-cash pension expense and non-cash compensation associated with our restricted stock program.
(d)Includes restricted stock awards that participate in dividends.

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Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA
Year Ended December 31,
20212020
(In millions)
Net income attributable to Kinder Morgan, Inc. (GAAP)(a)$1,784 $119 
Certain Items:
Fair value amortization(19)(21)
Legal, environmental and taxes other than income tax reserves160 26 
Change in fair value of derivative contracts(b)19 (5)
Loss on impairments, divestitures and other write-downs, net(c)1,535 327 
Loss on impairments of goodwill(d)— 1,600 
Restricted stock accelerated vesting and severance— 52 
COVID-19 costs— 15 
Income tax Certain Items(491)(107)
Other16 5 
Total Certain Items(e)1,220 1,892 
DD&A and amortization of excess cost of equity investments2,213 2,304 
Income tax expense(f)860 588 
Joint venture DD&A and income tax expense(f)(g)351 449 
Interest, net(f)1,518 1,610 
Adjusted EBITDA$7,946 $6,962 
(a)In prior periods, Net income was considered the comparable GAAP measure and has been updated to Net income attributable to Kinder Morgan, Inc. for consistency with our other non-GAAP performance measures.
(b)Gains or losses are reflected in our DCF when realized.
(c)2021 amount includes (i) a pre-tax non-cash impairment loss of $1,600 million related to our South Texas gathering and processing assets within our Natural Gas Pipelines business segment resulting from lower expectations regarding the volumes and rates associated with re-contracting; (ii) a write-down of $117 million, reported within “Earnings from equity investments” on the accompanying consolidated statement of income, on a long-term subordinated note receivable from an equity investee, Ruby; and (iii) a pre-tax non-cash impairment of $20 million related to our Wilmington terminal resulting from certain commercial contract terminations and lower expectations regarding the volumes and rates associated with re-contracting, partially offset by a pre-tax gain of $206 million, reported within “Other, net” on the accompanying consolidated statement of income, associated with the sale of a partial interest in our equity investment in NGPL Holdings. 2020 amount includes a pre-tax non-cash impairment loss of $350 million related to oil and gas producing assets in our CO2 business segment driven by low oil prices and $21 million for asset impairments in our Products Pipelines business segment partially offset by a $55 million pre-tax gain on sale of terminal assets. Except as otherwise noted above, these amounts are reported within “Loss on impairments and divestitures, net” on the accompanying consolidated statement of income.
(d)2020 amount includes non-cash impairments of goodwill of $1,000 million and $600 million associated with our Natural Gas Pipelines Non-Regulated and our CO2 reporting units, respectively.
(e)2021 and 2020 amounts include $124 million and $(4) million, respectively, reported within “Earnings from equity investments” on our accompanying consolidated statements of income.
(f)Amounts are adjusted for Certain Items. See tables included in “—Supplemental Information” and “—DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests” below.
(g)Represents joint venture DD&A and income tax expense. See table included in “—Supplemental Information” below.
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Supplemental Information
Year Ended December 31,
20212020
(In millions)
DD&A (GAAP)$2,135 $2,164 
Amortization of excess cost of equity investments (GAAP)78 140 
DD&A and amortization of excess cost of equity investments2,213 2,304 
Joint venture DD&A268 367 
DD&A and amortization of excess cost of equity investments for DCF$2,481 $2,671 
Income tax expense (GAAP)$369 $481 
Certain Items491 107 
Income tax expense(a)860 588 
Unconsolidated joint venture income tax expense(a)(b)83 82 
Income tax expense for DCF(a)$943 $670 
Additional joint venture information
Unconsolidated joint venture DD&A$312 $407 
Less: Consolidated joint venture partners’ DD&A44 40 
Joint venture DD&A268 367 
Unconsolidated joint venture income tax expense(a)(b)83 82 
Joint venture DD&A and income tax expense(a)$351 $449 
Unconsolidated joint venture cash taxes(b)$(60)$(62)
Unconsolidated joint venture sustaining capital expenditures$(116)$(120)
Less: Consolidated joint venture partners’ sustaining capital expenditures(9)(6)
Joint venture sustaining capital expenditures$(107)$(114)
(a)Amounts are adjusted for Certain Items.
(b)Amounts are associated with our Citrus, NGPL and Products (SE) Pipe Line equity investments.

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Segment Earnings Results

Natural Gas Pipelines 
 Year Ended December 31,
 20212020
 (In millions, except operating statistics)
Revenues$11,709 $7,259 
Operating expenses(7,000)(3,457)
Loss on impairments and divestitures, net(1,599)(1,010)
Other income2 1 
Earnings from equity investments487 679 
Other, net216 11 
Segment EBDA3,815 3,483 
Certain Items(a)1,648 983 
Adjusted Segment EBDA$5,463 $4,466 
Change from prior periodIncrease/(Decrease)
Adjusted Segment EBDA$997 
Volumetric data(b)
Transport volumes (BBtu/d)38,577 38,330 
Sales volumes (BBtu/d)2,473 2,353 
Gathering volumes (BBtu/d)2,749 3,039 
NGLs (MBbl/d)29 27 
Certain Items affecting Segment EBDA
(a)Includes Certain Item amounts of $1,648 million and $983 million for 2021 and 2020, respectively. 2021 amount includes a pre-tax non-cash asset impairment loss of $1,600 million resulting from lower expectations regarding the volumes and rates associated with re-contracting related to our South Texas gathering and processing assets, a write-down of $117 million on a long-term subordinated note receivable from an equity investee, Ruby, and an increase in expense of $99 million related to litigation reserves partially offset by a pre-tax gain of $206 million associated with the sale of a partial interest in our equity investment in NGPL Holdings. 2020 amount includes a $1,000 million non-cash goodwill impairment on our Natural Gas Pipelines Non-Regulated reporting unit and a decrease in revenues of $15 million related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales partially offset by an increase in revenues of $19 million resulting from amortization of regulatory liabilities including amounts recognized through earnings from equity investments.
Other
(b)Joint venture throughput is reported at our ownership share. Volumes for assets sold are excluded for all periods presented. Volumes for acquired pipelines are included for all periods presented, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition.

Below are the changes in Adjusted Segment EBDA between 2021 and 2020:

Year Ended December 31, 2021 versus Year Ended December 31, 2020
 Adjusted Segment EBDA
increase/(decrease)
 (In millions, except percentages)
Midstream$1,046 93 %
East Region 24 1 %
West Region(73)(7)%
Total Natural Gas Pipelines$997 22 %

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The changes in Segment EBDA for our Natural Gas Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable years of 2021 and 2020:
•$1,046 million (93%) increase in Midstream was primarily due to (i) higher commodity prices driving higher sales margins resulting in increases of $882 million on our Texas intrastate natural gas pipeline operations and $90 million on our South Texas assets primarily as a result of the February 2021 winter storm; (ii) $62 million of higher equity earnings due to PHP being placed in service in January 2021; (iii) higher earnings on Kinder Morgan Altamont LLC primarily due to higher commodity prices and volumes; and (iv) higher volumes on our Hiland Midstream assets partially offset by the impacts of lower volumes on KinderHawk and certain purchase contract obligations on our Oklahoma assets. Overall Midstream’s revenues increased primarily due to higher commodity prices which was partially offset by corresponding increases in costs of sales;
•$24 million (1%) increase in the East Region was primarily due to (i) a $61 million increase resulting from our July 2021 acquisition of the Stagecoach assets; (ii) higher earnings from TGP primarily due to weather-driven increases in reservation and park and loan revenues; and (iii) increased earnings from ELC resulting from the liquefaction units of the Elba Liquefaction project being fully operational as of August 2020, partially offset by lower earnings on FEP driven by lower revenues resulting from contract expirations; and
•$73 million (7%) decrease in the West Region was primarily due to lower earnings from WIC and CIG driven by lower revenues due to contract expirations, lower earnings from EPNG driven by lower park and loan revenues and lower equity earnings from Ruby.

Products Pipelines
 Year Ended December 31,
 20212020
 (In millions, except  operating statistics)
Revenues$2,245 $1,721 
Operating expenses(1,239)(779)
Loss on impairments and divestitures, net— (21)
Earnings from equity investments57 55 
Other, net1 1 
Segment EBDA1,064 977 
Certain Items(a)53 50 
Adjusted Segment EBDA$1,117 $1,027 
Change from prior periodIncrease/(Decrease)
Adjusted Segment EBDA$90 
Volumetric data(b)
Gasoline(c)987 897 
Diesel fuel390 375 
Jet fuel223 179 
Total refined product volumes1,600 1,451 
Crude and condensate498 552 
Total delivery volumes (MBbl/d)2,098 2,003 
Certain Items affecting Segment EBDA
(a)Includes Certain Item amounts of $53 million and $50 million in the 2021 and 2020 periods, respectively. 2021 amount includes increases in expense of $30 million and $23 million related to a litigation reserve and an environmental reserve adjustment, respectively. 2020 amount includes a $46 million unfavorable rate case reserve adjustment and a $21 million non-cash loss on impairment of our Belton Terminal partially offset by a $17 million favorable adjustment for tax reserves, other than income taxes.
Other
(b)Joint venture throughput is reported at our ownership share.
(c)Volumes include ethanol pipeline volumes.

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Below are the changes in Adjusted Segment EBDA between 2021 and 2020:

Year Ended December 31, 2021 versus Year Ended December 31, 2020
Adjusted Segment EBDA increase/(decrease)
(In millions, except percentages)
West Coast Refined Products$59 13 %
Southeast Refined Products38 17 %
Crude and Condensate(7)(2)%
Total Products Pipelines$90 9 %

The changes in Segment EBDA for our Products Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable years of 2021 and 2020:
•$59 million (13%) increase in West Coast Refined Products was primarily due to increased revenues on Pacific operations (SFPP), and to a lesser extent, on Calnev and West Coast terminals driven by the continued recovery of volumes in 2021 compared to 2020 which was impacted by COVID-19, partially offset by higher operating expenses primarily as a result of higher integrity management spending;
•$38 million (17%) increase in Southeast Refined Products was primarily due to higher 2021 earnings at our Transmix processing operations primarily due to higher prices and first quarter 2020 unfavorable inventory adjustments, and increased revenues from our South East Terminals resulting from higher volumes driven by continued recovery of volumes from 2020; and
•$7 million (2%) decrease in Crude and Condensate was primarily due to decreased earnings from the Bakken Crude assets and KM Condensate Processing Facility (Splitter) partially offset by increased earnings from Kinder Morgan Crude & Condensate Pipeline (KMCC). The Bakken Crude assets’ decreased earnings was driven by lower volumes, contracts renewed at lower average rates, and contract expirations partially offset by lower field operating expenses. Splitter’s decreased earnings was primarily driven by higher field maintenance expenses. KMCC’s increased earnings was primarily due to higher deficiency revenues and lower field operating expenses partially offset by contract expirations. Bakken Crude assets’ and KMCC’s changes were also impacted by first quarter 2020 unfavorable inventory valuation adjustments. In addition, increased marketing activities within KMCC have resulted in increases in revenues with corresponding increases in cost of sales.

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Terminals
 Year Ended December 31,
 20212020
 (In millions, except 
operating statistics)
Revenues$1,715 $1,722 
Operating expenses(793)(762)
(Loss) gain on impairments and divestitures, net(36)49 
Other income4 1 
Earnings from equity investments15 22 
Other, net3 13 
Segment EBDA908 1,045 
Certain Items(a)42 (55)
Adjusted Segment EBDA$950 $990 
Change from prior periodIncrease/(Decrease)
Adjusted Segment EBDA$(40)
Volumetric data(b)
Liquids leasable capacity (MMBbl)79.9 79.7 
Liquids utilization %(c)93.0 %95.3 %
Bulk transload tonnage (MMtons)51.7 48.0 
Certain Items affecting Segment EBDA
(a)Includes Certain Item amounts of $42 million and $(55) million for 2021 and 2020, respectively. 2021 amount primarily resulted from pre-tax non-cash impairment losses of $20 million related to our Wilmington terminal resulting from certain commercial contract terminations and lower expectations regarding the volumes and rates associated with re-contracting and $14 million related to the reclassification of an asset to held for sale. 2020 amount related to a gain on sale of our Staten Island terminal.
Other
(b)Volumes for assets sold are excluded for all periods presented.
(c)The ratio of our tankage capacity in service to tankage capacity available for service.

Below are the changes in Adjusted Segment EBDA between 2021 and 2020: 

Year Ended December 31, 2021 versus Year Ended December 31, 2020
Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)
Marine operations$(50)(25)%
Northeast10 10 %
Mid Atlantic8 14 %
All others (including intrasegment eliminations)(8)(1)%
Total Terminals$(40)(4)%

The changes in Segment EBDA for our Terminals business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable years of 2021 and 2020:
•$50 million (25%) decrease in Marine operations was primarily due to lower fleet utilization and average charter rates;
•$10 million (10%) increase in the Northeast terminals was primarily driven by increased revenues associated with higher throughput levels and associated ancillary fees; and
•$8 million (14%) increase in the Mid Atlantic terminals was primarily due to higher coal volumes at our Pier IX facility.
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CO2 
 Year Ended December 31,
 20212020
 (In millions, except 
operating statistics)
Revenues$1,009 $1,038 
Operating expenses(289)(404)
Gain (loss) on impairments and divestitures, net8 (950)
Earnings from equity investments32 24 
Segment EBDA760 (292)
Certain Items(a)(6)944 
Adjusted Segment EBDA $754 $652 
Change from prior periodIncrease/(Decrease)
Adjusted Segment EBDA$102 
Volumetric data
SACROC oil production19.9 21.8 
Yates oil production6.6 6.6 
Katz and Goldsmith oil production2.2 2.8 
Tall Cotton oil production1.0 1.7 
Total oil production, net (MBbl/d)(b)29.7 32.9 
NGL sales volumes, net (MBbl/d)(b)9.4 9.5 
CO2 sales volumes, net (Bcf/d)
0.4 0.4 
Realized weighted average oil price ($ per Bbl)$52.71 $53.78 
Realized weighted average NGL price ($ per Bbl)$25.39 $17.95 
Certain Items affecting Segment EBDA
(a)Includes Certain Item amounts of $(6) million and $944 million for 2021 and 2020, respectively. 2020 amount primarily resulted from a $600 million goodwill impairment on our CO2 reporting unit and non-cash impairments of $350 million on our oil and gas producing assets.
Other
(b)Net of royalties and outside working interests.

Below are the changes in Adjusted Segment EBDA between 2021 and 2020:

Year Ended December 31, 2021 versus Year Ended December 31, 2020
Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)
Oil and Gas Producing activities$67 15 %
Source and Transportation activities27 13 %
Subtotal94 14 %
Energy Transition Ventures8 n/a
Total CO2
$102 16 %
n/a - not applicable
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The changes in Segment EBDA for our CO2 business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable years of 2021 and 2020:
•$67 million (15%) increase in Oil and Gas Producing activities was primarily due to lower operating expenses of $143 million driven by a benefit in the 2021 period realized from returning power to the grid by curtailing oil production during the February 2021 winter storm and higher realized NGL prices which increased revenues by $42 million, partially offset by decreased revenues of (i) $50 million resulting from lower crude oil volumes, driven in part, by the curtailed oil production and (ii) $27 million related to lower realized crude oil prices, and increased operating expenses due to the impact of a settlement of $38 million for a terminated affiliate purchase contract with Source and Transportation activities; and
•$27 million (13%) increase in Source and Transportation activities primarily due to a settlement of $38 million for a terminated affiliate sales contract with Oil and Gas Producing activities which resulted in an increase in revenues partially offset by a decrease in revenues of $17 million related to lower CO2 sales volumes.

We believe that our existing hedge contracts in place within our CO2 business segment substantially mitigate commodity price sensitivities in the near-term and to lesser extent over the following few years from price exposure. Below is a summary of our CO2 business segment hedges outstanding as of December 31, 2021.

2022202320242025
Crude Oil(a)
Price ($ per Bbl)$57.92 $55.57 $54.92 $55.28 
Volume (MBbl/d)21.80 15.00 8.90 4.65 
NGLs
Price ($ per Bbl)$48.43 
Volume (MBbl/d)2.94 
Midland-to-Cushing Basis Spread
Price ($ per Bbl)$0.52 
Volume (MBbl/d)21.50 
(a)Includes West Texas Intermediate hedges.

DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests
 Year Ended December 31,
 20212020
 (In millions)
DD&A (GAAP)$(2,135)$(2,164)
General and administrative (GAAP)$(655)$(648)
Corporate benefit (charges)32 (5)
Certain Items(a)— 92 
General and administrative and corporate charges(b)$(623)$(561)
Interest, net (GAAP)$(1,492)$(1,595)
Certain Items(c)(26)(15)
Interest, net(b)$(1,518)$(1,610)
Net income attributable to noncontrolling interests (GAAP)$(66)$(61)
Certain Items— — 
Net income attributable to noncontrolling interests(b)$(66)$(61)
Certain Items
(a)2020 amount includes $52 million for restricted stock accelerated vesting and severance expense, an increase in expense of $23 million associated with a non-cash fair value adjustment and the dividend on the Pembina common stock and $15 million related to costs incurred associated with COVID-19 mitigation.
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(b)Amounts are adjusted for Certain Items.
(c)2021 and 2020 amounts include decreases in interest expense of $19 million and $21 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions and a decrease of $15 million and an increase of $8 million in interest expense, respectively, related to non-cash mismatches between the change in fair value of interest rate swaps and change in fair value of hedged debt.

General and administrative expenses and corporate charges adjusted for Certain Items increased $62 million in 2021 when compared to 2020 primarily due to lower capitalized costs of $48 million reflecting reduced capital spending primarily by our Natural Gas Pipelines business segment, higher benefit-related costs of $34 million and non-recurring cost savings realized in the 2020 period as a result of the global pandemic of $33 million, partially offset by $41 million of cost savings in the 2021 period associated with organizational efficiency efforts, and lower pension costs of $17 million.

In the table above, we report our interest expense as “net,” meaning that we have subtracted interest income and capitalized interest from our total interest expense to arrive at one interest amount.  Our consolidated interest expense, net adjusted for Certain Items decreased $92 million in 2021 when compared to 2020 primarily due to lower long-term debt balances, lower LIBOR rates, and lower long-term interest rates, partially offset by lower capitalized interest.

We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of December 31, 2021 and 2020, approximately 21% and 16%, respectively, of the principal amount of our debt balances were subject to variable interest rates—either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. The percentage at December 31, 2021 excludes $4,860 million of variable-to-fixed interest rate derivative contracts which became effective January 4, 2022 and hedge our exposure through 2022. For more information on our interest rate swaps, see Note 14 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements.

Net income attributable to noncontrolling interests represents the allocation of our consolidated net income attributable to all outstanding ownership interests in our consolidated subsidiaries that are not owned by us. 

Income Taxes

Year Ended December 31, 2021 versus Year Ended December 31, 2020

Our income tax expense for the year ended December 31, 2021 is approximately $369 million, as compared with income tax expense of $481 million for the same period of 2020.  The $112 million decrease in income tax expense is due primarily to (i) the lack of tax benefit on the impairment of non-tax-deductible goodwill in 2020; (ii) higher dividend-received deductions in 2021; (iii) the 2021 Enhanced Oil Recovery Credit; and (iv) the release in 2021 of a valuation allowance related to our investment in NGPL. These decreases are partially offset by (i) higher pretax book income in 2021 as a result of the February 2021 winter storm, the 2020 impairment of certain CO2 assets and the 2020 demand destruction from the COVID-19 pandemic; and (ii) the refund of alternative minimum tax sequestration credits in 2020.

Liquidity and Capital Resources

General

As of December 31, 2021, we had $1,140 million of “Cash and cash equivalents,” a decrease of $44 million from December 31, 2020. Additionally, as of December 31, 2021, we had borrowing capacity of approximately $3.9 billion under our credit facilities (discussed below in “—Short-term Liquidity”). As discussed further below, we believe our cash flows from operating activities, cash position and remaining borrowing capacity on our credit facilities are more than adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.

We have consistently generated substantial cash flow from operations, providing a source of funds of $5,708 million and $4,550 million in 2021 and 2020, respectively. The year-to-year increase is discussed below in “—Cash Flows—Operating Activities.” We primarily rely on cash provided from operations to fund our operations as well as our debt service, sustaining capital expenditures, dividend payments, and our growth capital expenditures; however, we may access the debt capital markets from time to time to refinance our maturing long-term debt.

Our board of directors declared a quarterly dividend of $0.27 per share for the fourth quarter of 2021, consistent with previous quarters in 2021. The total of the dividends declared for 2021 of $1.08 represents a 3% increase over total dividends
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declared for 2020. We expect to fully fund our dividend payments as well as our discretionary spending for 2022 without funding from the capital markets with additional flexibility to engage in share repurchases on an opportunistic basis.

On August 20, 2021, we entered into a new $3.5 billion revolving credit facility (the “New Credit Facility”) due August 2026 and amended our existing facility (the “Existing Facility”) to reduce the borrowing capacity to $500 million and terminate the letter of credit commitments and the swing line capacity thereunder (together, the “Credit Facilities”).

Short-term Liquidity

As of December 31, 2021, our principal sources of short-term liquidity are (i) cash from operations; (ii) our combined $4.0 billion of Credit Facilities and associated commercial paper program; and (iii) cash and cash equivalents. The loan commitments under our revolving Credit Facilities can be used for working capital and other general corporate purposes, and as a backup to our commercial paper program. Commercial paper borrowings reduce borrowings allowed under our Credit Facilities and letters of credit reduce borrowings allowed under our New Credit Facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our Credit Facilities and have consistently generated strong cash flows from operations.

As of December 31, 2021, our $2,646 million of short-term debt consisted primarily of senior notes that mature in the next twelve months. We intend to fund our debt, as it becomes due, primarily through cash on hand, credit facility borrowings, commercial paper borrowings, cash flows from operations, and/or issuing new long-term debt. Our short-term debt balance as of December 31, 2020 was $2,558 million.
 
We had working capital (defined as current assets less current liabilities) deficits of $1,992 million and $1,871 million as of December 31, 2021 and 2020, respectively. From time to time, our current liabilities may include short-term borrowings used to finance our expansion capital expenditures, which we may periodically replace with long-term financing and/or pay down using retained cash from operations. The overall $121 million unfavorable change from year-end 2020 was primarily due to: (i) a $104 million increase in accounts payable, net of change in accounts receivable; (ii) an increase of approximately $88 million in senior notes that mature in the next twelve months; and (iii) a net unfavorable short-term fair value adjustment of $80 million on derivative contract assets and liabilities in 2021, offset partially by a $214 million increase in inventories, primarily storage gas and product inventories, and a decrease of $23 million in accrued contingencies. Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts, and changes in our cash and cash equivalent balances as a result of excess cash from operations after payments for investing and financing activities (discussed below in “—Long-term Financing” and “—Capital Expenditures”).

We employ a centralized cash management program for our U.S.-based bank accounts that concentrates the cash assets of our wholly owned subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing. These programs provide that funds in excess of the daily needs of our wholly owned subsidiaries are concentrated, consolidated or otherwise made available for use by other entities within the consolidated group. We place no material restrictions on the ability to move cash between entities, payment of intercompany balances or the ability to upstream dividends to KMI other than restrictions that may be contained in agreements governing the indebtedness of those entities.

Credit Ratings and Capital Market Liquidity

We believe that our capital structure will continue to allow us to achieve our business objectives. We expect that our short-term liquidity needs will be met primarily through retained cash from operations or short-term borrowings. Generally, we anticipate re-financing maturing long-term debt obligations in the debt capital markets and are therefore subject to certain market conditions which could result in higher costs or negatively affect our and/or our subsidiaries’ credit ratings. A decrease in our credit ratings could negatively impact our borrowing costs and could limit our access to capital.

As of December 31, 2021, our short-term corporate debt ratings were A-2, Prime-2 and F2 at Standard and Poor’s, Moody’s Investor Services and Fitch Ratings, Inc., respectively.

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The following table represents KMI’s and KMP’s senior unsecured debt ratings as of December 31, 2021.
Rating agencySenior debt ratingOutlook
Standard and Poor’sBBB Stable
Moody’s Investor ServicesBaa2Stable
Fitch Ratings, Inc.BBBStable

Long-term Financing

Our equity consists of Class P common stock with a par value of $0.01 per share. We do not expect to need to access the equity capital markets to fund our discretionary capital investments for the foreseeable future. See also “—Dividends and Stock Buy-back Program” below for additional discussion related to our dividends and stock buy-back program.

From time to time, we issue long-term debt securities, often referred to as senior notes.  All of our senior notes issued to date, other than those issued by certain of our subsidiaries, generally have very similar terms, except for interest rates, maturity dates and prepayment premiums. All of our fixed rate senior notes provide that the notes may be redeemed at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date, and, in most cases, plus a make-whole premium.  In addition, from time to time, our subsidiaries issue long-term debt securities. Furthermore, we and almost all of our direct and indirect wholly owned domestic subsidiaries are parties to a cross guaranty wherein we each guarantee each other’s debt. See “—Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries. As of December 31, 2021 and 2020, the aggregate principal amount outstanding of our various long-term debt obligations (excluding current maturities) was $29,772 million and $30,838 million, respectively.

On February 11, 2021, we issued in a registered offering $750 million aggregate principal amount of 3.60% senior notes due 2051 and received net proceeds of $741 million.

On October 26, 2021, we issued in a registered offering two series of senior notes consisting of $500 million aggregate principal amount of 1.75% senior notes due 2026 and $300 million aggregate principal amount of 3.60% senior notes due 2051, as a reopening of the 3.60% series discussed above, and received combined net proceeds of $796 million.

On January 18, 2022, we repaid $260 million of maturing 8.625% notes.

We achieve our variable rate exposure primarily by issuing long-term fixed rate debt and then swapping a portion of the fixed rate interest payments for variable rate interest payments and through the issuance of commercial paper or credit facility borrowings.

For additional information about our outstanding senior notes and debt-related transactions in 2021, see Note 9 “Debt” to our consolidated financial statements.  For information about our interest rate risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”

Counterparty Creditworthiness

Some of our customers or other counterparties may experience severe financial problems that may have a significant impact on their creditworthiness. These financial problems may arise from our current global economic conditions, continued volatility of commodity prices or otherwise. In such situations, we utilize, to the extent allowable under applicable contracts, tariffs and regulations, prepayments and other security requirements, such as letters of credit, to enhance our credit position relating to amounts owed from these counterparties. While we believe we have taken reasonable measures to protect against counterparty credit risk, we cannot provide assurance that one or more of our customers or other counterparties will not become financially distressed and will not default on their obligations to us. The balance of our allowance for credit losses as of December 31, 2021 and 2020, was $1 million and $26 million, respectively, reflected in “Other current assets” on our consolidated balance sheets, which includes reserves for counterparty bankruptcies recorded during the year ended December 31, 2020.

Capital Expenditures

We account for our capital expenditures in accordance with GAAP. We also distinguish between capital expenditures that are maintenance/sustaining capital expenditures and those that are expansion capital expenditures (which we also refer to as
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discretionary capital expenditures). Expansion capital expenditures are those expenditures which increase throughput or capacity from that which existed immediately prior to the addition or improvement and are not deducted in calculating DCF (see “—Results of Operations—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF”). With respect to our oil and gas producing activities, we classify a capital expenditure as an expansion capital expenditure if it is expected to increase capacity or throughput (i.e., production capacity) from the capacity or throughput immediately prior to the making or acquisition of such additions or improvements. Maintenance capital expenditures are those which maintain throughput or capacity. The distinction between maintenance and expansion capital expenditures is a physical determination rather than an economic one, irrespective of the amount by which the throughput or capacity is increased.

Budgeting of maintenance capital expenditures is done annually on a bottom-up basis. For each of our assets, we budget for and make those maintenance capital expenditures that are necessary to maintain safe and efficient operations, meet customer needs and comply with our operating policies and applicable law. We may budget for and make additional maintenance capital expenditures that we expect to produce economic benefits such as increasing efficiency and/or lowering future expenses. Budgeting and approval of expansion capital expenditures are generally made periodically throughout the year on a project-by-project basis in response to specific investment opportunities identified by our business segments from which we generally expect to receive sufficient returns to justify the expenditures.  Generally, the determination of whether a capital expenditure is classified as maintenance/sustaining or as expansion capital expenditures is made on a project level. The classification of our capital expenditures as expansion capital expenditures or as maintenance capital expenditures is made consistent with our accounting policies and is generally a straightforward process, but in certain circumstances can be a matter of management judgment and discretion. The classification has an impact on DCF because capital expenditures that are classified as expansion capital expenditures are not deducted from DCF, while those classified as maintenance capital expenditures are.
 
Our capital expenditures for the year ended December 31, 2021, and the amount we expect to spend for 2022 to sustain our assets and grow our business are as follows:
2021Expected 2022
(In millions)
Sustaining capital expenditures(a)(b)$864 $865 
Discretionary capital investments(b)(c)(d)2,278 1,319 
(a)2021 and Expected 2022 amounts include $107 million and $120 million, respectively, for sustaining capital expenditures from unconsolidated joint ventures, reduced by consolidated joint venture partners’ sustaining capital expenditures. See table included in “Non-GAAP Financial Measures—Supplemental Information.”
(b)2021 combined sustaining and discretionary amounts include $78 million due to increases in accrued capital expenditures and contractor retainage and net changes in other.
(c)2021 amount includes $138 million of our contributions to certain unconsolidated joint ventures for capital investments and $1,538 million for our acquisitions of Stagecoach and Kinetrex.
(d)Amounts include our actual or estimated contributions to certain unconsolidated joint ventures, net of actual or estimated contributions from certain partners in non-wholly owned consolidated subsidiaries for capital investments.

Off Balance Sheet Arrangements
 
We have invested in entities that are not consolidated in our financial statements. For information on our obligations with respect to these investments, as well as our obligations with respect to related letters of credit, see Note 13 “Commitments and Contingent Liabilities” to our consolidated financial statements. Additional information regarding the nature and business purpose of our investments is included in Note 7 “Investments” to our consolidated financial statements.

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Contractual Obligations and Commercial Commitments

The table below provides a summary of our material cash requirements.
 Payments due by period
 TotalLess than 1
year		1-3 years3-5 yearsMore than 5 years
 (In millions)
Contractual obligations:     
Debt borrowings-principal payments(a)$32,418 $2,646 $5,175 $2,669 $21,928 
Interest payments(b)
21,171 1,646 2,932 2,601 13,992 
Lease obligations(c)411 57 94 67 193 
Pension and OPEB plans(d) 604 57 33 30 484 
Transportation, volume and storage agreements(e)629 162 238 152 77 
Other obligations(f) 392 86 122 61 123 
Total$55,625 $4,654 $8,594 $5,580 $36,797 
Other commercial commitments:     
Standby letters of credit(g)$150 $77 $73 $— $— 
Capital expenditures(h)$209 $209 $— $— $— 
(a)See Note 9 “Debt” to our consolidated financial statements.
(b)Interest payment obligations exclude adjustments for interest rate swap agreements and assume no change in variable interest rates from those in effect at December 31, 2021.  
(c)Represents commitments pursuant to the terms of operating lease agreements as of December 31, 2021.
(d)Represents the amount by which the benefit obligations exceeded the fair value of plan assets at year-end for pension and OPEB plans whose accumulated postretirement benefit obligations exceeded the fair value of plan assets. The payments by period include expected contributions in 2022 and estimated benefit payments for underfunded plans in the other years. 
(e)Primarily represents transportation agreements of $289 million, NGL volume agreements of $203 million and storage agreements for capacity of $99 million.
(f)Primarily includes (i) rights-of-way obligations; and (ii) environmental liabilities related to sites that we own or have a contractual or legal obligation with a regulatory agency or property owner upon which we will perform remediation activities. These environmental liabilities are included within “Other current liabilities” and “Other long-term liabilities and deferred credits” in our consolidated balance sheet as of December 31, 2021.
(g)The $150 million in letters of credit outstanding as of December 31, 2021 consisted of the following (i) $50 million under six letters of credit for insurance purposes; (ii) a $46 million letter of credit supporting our International Marine Terminals Partnership Plaquemines Bond; (iii) a $24 million letter of credit supporting our Kinder Morgan Operating LLC “B” tax-exempt bonds; and (iv) a combined $30 million in thirty letters of credit supporting environmental and other obligations of us and our subsidiaries.
(h)Represents commitments for the purchase of plant, property and equipment as of December 31, 2021.

Cash Flows
 
Operating Activities
Cash provided by operating activities increased $1,158 million in 2021 compared to 2020 primarily due to:
•a $1,264 million increase in cash largely related to the February 2021 winter storm. This change in cash is after adjusting the $1,670 million increase in net income by $406 million for the combined effects of the period-to-period net changes in non-cash items including the following: (i) losses from impairments and divestitures, net (see discussion above in “—Results of Operations”); (ii) gain from the sale of a partial interest in our equity investment in NGPL Holdings (see discussion above in “—General”); (iii) DD&A expenses (including amortization of excess cost of equity investments); (iv) deferred income taxes; and (v) earnings from equity investments (including a non-cash write-down of a related party note receivable from Ruby); partially offset by,
•a $106 million decrease in cash associated with net changes in working capital items and other non-current assets and liabilities. The decrease was driven, among other things, primarily by payments for litigation matters in the 2021 period compared with the 2020 period.

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Investing Activities

Cash used in investing activities increased $1,394 million in 2021 compared to 2020 primarily due to:
•a $1,531 million increase in expenditures for the acquisition of assets and investments, net of cash acquired, primarily driven by $1,227 million and $311 million of net cash used for the Stagecoach and the Kinetrex acquisitions, respectively, in the 2021 period. See Note 3 “Acquisitions and Divestitures” to our consolidated financial statements for further information regarding these two acquisitions; and
•a $663 million decrease in cash received from the sales of property, plant and equipment, investments, and other net assets, net of removal costs, primarily due to, among other things, the $412 million of net proceeds received from the sale of a partial interest in our equity investment in NGPL Holdings in the 2021 period, versus the $907 million of proceeds received from the sale of Pembina shares in the 2020 period. See Note 3 “Acquisitions and Divestitures” to our consolidated financial statements for further information regarding these two transactions; partially offset by,
•a $426 million decrease in capital expenditures reflecting an overall reduction of expansion capital projects in the 2021 period over the comparative 2020 period; and
•a $348 million decrease in cash used for contributions to equity investees driven primarily by lower contributions to PHP and SNG in the 2021 period compared with the 2020 period.

Financing Activities

Cash used in financing activities increased $827 million in 2021 compared to 2020 primarily due to:
•a $766 million net increase in cash used related to debt activity as a result of higher net debt payments in the 2021 period compared to the 2020 period. See Note 9 “Debt” to our consolidated financial statements for further information regarding our debt activity; and
•an $81 million increase in dividend payments to our shareholders.

Dividends and Stock Buy-back Program

The table below reflects the declaration of dividends of $1.08 per share for 2021:
Three months endedTotal quarterly dividend per share for the periodDate of declarationDate of recordDate of dividend
March 31, 2021
$0.27April 21, 2021April 30, 2021May 17, 2021
June 30, 2021
0.27July 21, 2021August 2, 2021August 16, 2021
September 30, 2021
0.27October 20, 2021November 1, 2021November 15, 2021
December 31, 2021
0.27January 19, 2022January 31, 2022February 15, 2022

We expect to continue to return additional value to our shareholders in 2022 through our previously announced dividend increase. We plan to increase our dividend by 3% to $1.11 per common share in 2022. Based on our 2022 expectations, we also expect to have up to $750 million available to invest in attractive opportunities, including share repurchases. Any potential repurchases in 2022 would be under our $2 billion stock buy-back program approved by our board of directors in July 2017. Since December 2017, in total, we have repurchased approximately 32 million shares of our Class P common stock under the program at an average price of approximately $17.71 per share for approximately $575 million. For information on our equity buy-back program and our equity distribution agreement, see Note 11 “Stockholders’ Equity” to our consolidated financial statements.

The actual amount of dividends to be paid on our capital stock will depend on many factors, including our financial condition and results of operations, liquidity requirements, business prospects, capital requirements, legal, regulatory and contractual constraints, tax laws, Delaware laws and other factors. See Item 1A “Risk Factors—The guidance we provide for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.” All of these matters will be taken into consideration by our board of directors in declaring dividends.

Our dividends are not cumulative. Consequently, if dividends on our stock are not paid at the intended levels, our stockholders are not entitled to receive those payments in the future. Our dividends generally will be paid on or about the 15th day of each February, May, August and November.

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Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries

KMI and certain subsidiaries (Subsidiary Issuers) are issuers of certain debt securities. KMI and substantially all of KMI’s wholly owned domestic subsidiaries (Subsidiary Guarantors), are parties to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement. Accordingly, with the exception of certain subsidiaries identified as subsidiary non-guarantors (Subsidiary Non-Guarantors), the parent issuer, Subsidiary Issuers and Subsidiary Guarantors (the “Obligated Group”) are all guarantors of each series of our guaranteed debt (Guaranteed Notes). As a result of the cross guarantee agreement, a holder of any of the Guaranteed Notes issued by KMI or Subsidiary Issuers are in the same position with respect to the net assets, and income of KMI and the Subsidiary Issuers and Guarantors. The only amounts that are not available to the holders of each of the Guaranteed Notes to satisfy the repayment of such securities are the net assets, and income of the Subsidiary Non-Guarantors.

In lieu of providing separate financial statements for the Obligated Group, we have presented the accompanying supplemental summarized combined income statement and balance sheet information for the Obligated Group based on Rule 13-01 of the SEC’s Regulation S-X.  Also, see Exhibit 10.12 to this Report “Cross Guarantee Agreement, dated as of November 26, 2014, among KMI and certain of its subsidiaries, with schedules updated as of December 31, 2021.”

All significant intercompany items among the Obligated Group have been eliminated in the supplemental summarized combined financial information. The Obligated Group’s investment balances in Subsidiary Non-Guarantors have been excluded from the supplemental summarized combined financial information. Significant intercompany balances and activity for the Obligated Group with other related parties, including Subsidiary Non-Guarantors (referred to as “affiliates”), are presented separately in the accompanying supplemental summarized combined financial information.

Excluding fair value adjustments, as of December 31, 2021 and 2020, the Obligated Group had $31,608 million and $32,563 million, respectively, of Guaranteed Notes outstanding.  

Summarized combined balance sheet and income statement information for the Obligated Group follows:
December 31,
Summarized Combined Balance Sheet Information20212020
(In millions)
Current assets$3,556 $2,957 
Current assets - affiliates1,233 1,151 
Noncurrent assets61,754 61,783 
Noncurrent assets - affiliates508 616 
Total Assets$67,051 $66,507 
Current liabilities$5,413 $4,528 
Current liabilities - affiliates1,332 1,209 
Noncurrent liabilities32,310 33,907 
Noncurrent liabilities - affiliates1,047 1,078 
Total Liabilities40,102 40,722 
Redeemable noncontrolling interest— 728 
Kinder Morgan, Inc.’s stockholders’ equity26,949 25,057 
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity$67,051 $66,507 
Summarized Combined Income Statement InformationYear Ended December 31, 2021
(In millions)
Revenues$15,307 
Operating income2,541 
Net income1,489 

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Recent Accounting Pronouncements

Please refer to Note 19 “Recent Accounting Pronouncements” to our consolidated financial statements for information concerning recent accounting pronouncements.

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk.

Generally, our market risk sensitive instruments and positions have been determined to be “other than trading.”  Our exposure to market risk as discussed below includes forward-looking statements and represents an estimate of possible changes in fair value or future earnings that would occur assuming hypothetical future movements in energy commodity prices or interest rates.  Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated based on actual fluctuations in energy commodity prices or interest rates and the timing of transactions.

Energy Commodity Market Risk

We are exposed to energy commodity market risk and other external risks in the ordinary course of business.  However, we manage these risks by executing a hedging strategy that seeks to protect us financially against adverse price movements and serves to minimize potential losses.  Our strategy involves the use of certain energy commodity derivative contracts to reduce and minimize the risks associated with unfavorable changes in the market price of crude oil, natural gas and NGL.  The derivative contracts that we use include exchange-traded and OTC commodity financial instruments, including, but not limited to, futures and options contracts, fixed price swaps and basis swaps. We may categorize such use of energy commodity derivative contracts as cash flow hedges because the derivative contract is used to hedge the anticipated future cash flow of a transaction that is expected to occur but which value is uncertain.

Our hedging strategy involves entering into a financial position intended to offset our physical position, or anticipated position, in order to minimize the risk of financial loss from an adverse price change.  For example, as sellers of crude oil, natural gas and NGL, we often enter into fixed price swaps and/or futures contracts to guarantee or lock-in the sale price of our crude oil or the margin from the sale and purchase of our natural gas at the time of market delivery, thereby in whole or in part offsetting any change in prices, either positive or negative.  Using derivative contracts for this purpose helps provide increased certainty with regard to operating cash flows which helps us to undertake further capital improvement projects, attain budget results and meet dividend targets.

Our policies require that derivative contracts are only entered into with carefully selected major financial institutions or similar counterparties based upon their credit ratings and other factors, and we maintain strict dollar and term limits that correspond to our counterparties’ credit ratings.  While it is our policy to enter into derivative transactions principally with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that losses will result from counterparty credit risk in the future.

The credit ratings of the primary parties from whom we transact in energy commodity derivative contracts (based on contract market values) are as follows (credit ratings per Standard & Poor’s Rating Service): 
Credit Rating
INGA+
MacquarieA+
JP MorganA+
Bank of Nova ScotiaA+
Bank of AmericaA-

We measure the risk of price changes in the derivative instrument portfolios utilizing a sensitivity analysis model. The sensitivity analysis applied to each portfolio measures the potential income or loss (i.e., the change in fair value of the derivative instrument portfolio) based upon a hypothetical 10% movement in the underlying quoted market prices. In addition to these variables, the fair value of each portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. Because we enter into derivative contracts largely for the purpose of mitigating the risks that accompany certain of our business activities, both in the sensitivity analysis model and in reality, the change in the market value of the derivative contracts’ portfolio is offset largely by changes in the value of the underlying
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physical transactions. A hypothetical 10% movement in the underlying commodity prices would have the following effect on the associated derivative contracts’ estimated fair value:
As of December 31,
Commodity derivative20212020
(In millions)
Crude oil$135 $81 
Natural gas36 12 
NGL
8 7 
Total$179 $100 

Our sensitivity analysis represents an estimate of the reasonably possible gains and losses that would be recognized on the crude oil, natural gas and NGL portfolios of derivative contracts assuming hypothetical movements in future market rates and is not necessarily indicative of actual results that may occur. It does not represent the maximum possible loss or any expected loss that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ from estimates due to actual fluctuations in market rates, operating exposures and the timing thereof, as well as changes in our portfolio of derivatives during the year.

Interest Rate Risk

In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt.  The market risk inherent in our debt instruments and positions is the potential change arising from increases or decreases in interest rates as discussed below.

For fixed rate debt, changes in interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows.  Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows.  Generally, there is not an obligation to prepay fixed rate debt prior to maturity and, as a result, changes in fair value should not have a significant impact on the fixed rate debt. We are generally subject to interest rate risk upon refinancing maturing debt. Below are our debt balances, including debt fair value adjustments, and sensitivity to interest rates:
 December 31, 2021December 31, 2020
 Carrying
value		Estimated
fair value(a)		Carrying
value		Estimated
fair value(a)
(In millions)
Fixed rate debt(b)$33,006 $37,459 $34,376 $39,306 
Variable rate debt$314 $316 $313 $316 
Notional principal amount of variable-to-fixed interest rate swap agreements(c)(490)(2,750)
Notional principal amount of fixed-to-variable interest rate swap agreements(d)7,100 7,625 
Debt balances subject to variable interest rates(e)$6,924 $5,188 
(a)Fair values were determined using Level 2 inputs.
(b)A hypothetical 10% change in the average interest rates applicable to such debt as of December 31, 2021 and 2020, would result in changes of approximately $749 million and $1,541 million, respectively, in the estimated fair values of these instruments.
(c)December 31, 2021 amount excludes $4.9 billion of variable-to-fixed interest rate swap agreements that became effective January 4, 2022 and expire December 31, 2022. December 31, 2020 amount includes $2.5 billion of variable-to-fixed interest rate swap agreements that expired during 2021.
(d)December 31, 2020 amount includes $900 million of fixed-to-variable interest rate swap agreements that expired during 2021.
(e)A hypothetical 10% change in the weighted average interest rate on all of our borrowings (approximately 47 and 49 basis points, respectively, in 2021 and 2020) when applied to our outstanding balance of variable rate debt as of December 31, 2021 and 2020, including adjustments for the notional swap amounts described in the table above, would result in changes of approximately $32 million (or $10 million with the inclusion of the variable-to-fixed interest rate swap agreements described in note (c) above) and $25 million, respectively, in our 2021 and 2020 annual income before income taxes.

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Fixed-to-variable interest rate swap agreements are entered into for the purpose of converting a portion of the underlying cash flows related to long-term fixed rate debt securities into variable rate debt in order to achieve our desired mix of fixed and variable rate debt.  Since the fair value of fixed rate debt varies with changes in the market rate of interest, swap agreements are entered into to receive a fixed and pay a variable rate of interest.  Such swap agreements result in future cash flows that vary with the market rate of interest, and therefore hedge against changes in the fair value of the fixed rate debt due to market rate changes.

As presented in the table above, we monitor the mix of fixed rate and variable rate debt obligations in light of changing market conditions and from time to time, may alter that mix by, for example, refinancing outstanding balances of variable rate debt with fixed rate debt (or vice versa) or by entering into interest rate swap agreements or other interest rate hedging agreements.  As of December 31, 2021, including debt converted to variable rates through the use of interest rate swaps but excluding our debt fair value adjustments, approximately 21% of our debt balances were subject to variable interest rates. The percentage at December 31, 2021 excludes $4,860 million of variable-to-fixed interest rate derivative contracts which became effective January 4, 2022 and hedge our exposure through 2022.

For more information on our interest rate risk management and on our interest rate swap agreements, see Note 14 “Risk Management” to our consolidated financial statements.

LIBOR Phase Out

Amounts drawn under our revolving credit facility may bear interest rates in relation to U.S. Dollar LIBOR (USD LIBOR), depending on our selection of repayment options, and certain of our outstanding interest rate swap agreements have a floating interest rate in relation to one-month LIBOR or three-month LIBOR. In July 2017, the Financial Conduct Authority in the U.K. announced a desire to phase out LIBOR as a benchmark by the end of 2021. The Alternative Reference Rates Committee, a steering committee consisting of large U.S. financial institutions convened by the U.S. Federal Reserve Board and the Federal Reserve Bank of New York, has recommended replacing LIBOR with the Secured Overnight Financing Rate (SOFR), an index supported by short-term Treasury repurchase agreements. On November 30, 2020, ICE Benchmark Administration (IBA), the administrator of USD LIBOR announced that it does not intend to cease publication of the remaining USD LIBOR tenors until June 30, 2023, providing additional time for existing contracts that are dependent on LIBOR to mature.

The agreements governing our Credit Facilities include customary provisions to provide for replacement of LIBOR with an alternative benchmark rate when LIBOR ceases to be available. The International Swaps and Derivatives Association has developed provisions for SOFR-based fall-back rates to apply upon permanent cessation of LIBOR and has published a protocol to enable market participants to include the new provisions in existing swap agreements. See also Note 19 “Recent Accounting Pronouncements” to our consolidated financial statements for accounting pronouncements related to the LIBOR phase out.

We currently do not expect the transition from LIBOR to have a material impact on us.

Foreign Currency Risk

As of December 31, 2021, we had a notional principal amount of $1,358 million of cross-currency swap agreements that effectively convert all of our fixed-rate Euro denominated debt, including annual interest payments and the payment of principal at maturity, to U.S. dollar denominated debt at fixed rates.  These swaps eliminate the foreign currency risk associated with our foreign currency denominated debt.

Item 8.  Financial Statements and Supplementary Data.

The information required in this Item 8 is in this report as set forth in the “Index to Financial Statements” on page 69.

Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.
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Item 9A. Controls and Procedures.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of December 31, 2021, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934.  There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures.  Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.  Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f).  Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.  Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an assessment of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on this assessment, our management concluded that our internal control over financial reporting was effective as of December 31, 2021.

The effectiveness of our internal control over financial reporting as of December 31, 2021, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their audit report, which appears herein.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the fourth quarter of 2021 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.  Other Information.

None.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.

Not Applicable.

PART III

Item 10.  Directors, Executive Officers and Corporate Governance. 
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2022 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2022.

Item 11. Executive Compensation.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2022 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2022.

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2022 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2022.

Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2022 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2022.  

Item 14.  Principal Accounting Fees and Services.

The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2022 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2022.

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PART IV

Item 15.  Exhibits, Financial Statement Schedules.

(a)(1) Financial Statements and (2) Financial Statement Schedules
See “Index to Financial Statements” set forth on Page 69.

(3)Exhibits
Exhibit NumberDescription
3.1*
3.2*
4.1*
4.2*
4.3*
4.4*
4.5*
4.6*
4.7*
4.8*
4.9*
4.10*
4.11*
4.12*
4.13*
4.14*
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4.15*
4.16*
4.17*