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Cover and table of contents

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


☐			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

Kinder Morgan, Inc.

(Exact name of registrant as specified in its charter)


Delaware						80-0682103
(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 class	Trading Symbol(s)	Name of each exchange on which registered
Class P Common Stock	KMI	New York Stock Exchange
1.500% Senior Notes due 2022	KMI 22	New York Stock Exchange
2.250% Senior Notes due 2027	KMI 27 A	New 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

		Page Number
	Glossary	1
	Information Regarding Forward-Looking Statements	2

	PART I
Items 1. and 2.	Business and Properties	4
	General Development of Business	5
	Recent Developments	5
	Narrative Description of Business	5
	Business Strategy	5
	Business Segments	6
	Natural Gas Pipelines	6
	Products Pipelines	9
	Terminals	9
	CO2	10
	Major Customers	12
	Industry Regulation	12
	Environmental Matters	15
	Human Capital	18
	Properties and Rights of Way	19
	Financial Information about Geographic Areas	19
	Available Information	19
Item 1A.	Risk Factors	19
Item 1B.	Unresolved Staff Comments	33
Item 3.	Legal Proceedings	33
Item 4.	Mine Safety Disclosures	33

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	34
Item 6.	[Reserved]	34
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
	General	34
	Critical Accounting Estimates	37
	Results of Operations	39
	Overview	39
	Consolidated Earnings Results (GAAP)	42
	Non-GAAP Financial Measures	44
	Segment Earnings Results	47
	DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests	52
	Income Taxes	53
	Liquidity and Capital Resources	53
	General	53


KINDER MORGAN, INC. AND SUBSIDIARIES (continued)
TABLE OF CONTENTS

		Page Number
	Short-term Liquidity	54
	Long-term Financing	55
	Counterparty Creditworthiness	55
	Capital Expenditures	55
	Off Balance Sheet Arrangements	56
	Contractual Obligations and Commercial Commitments	57
	Cash Flows	57
	Dividends and Stock Buy-back Program	58
	Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries	59
	Recent Accounting Pronouncements	60
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	60
	Energy Commodity Market Risk	60
	Interest Rate Risk	61
	Foreign Currency Risk	62
Item 8.	Financial Statements and Supplementary Data	62
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	62
Item 9A.	Controls and Procedures	63
Item 9B.	Other Information	63
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	63

	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	63
Item 11.	Executive Compensation	63
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	64
Item 13.	Certain Relationships and Related Transactions, and Director Independence	64
Item 14.	Principal Accounting Fees and Services	64

	PART IV
Item 15.	Exhibits, Financial Statement Schedules	65
	Index to Financial Statements	69
Item 16.	Form 10-K Summary	132
Signatures		133

KINDER MORGAN, INC. AND SUBSIDIARIES

GLOSSARY

Company Abbreviations


Calnev	=	Calnev Pipe Line LLC	KMP	=	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 LLC	MEP	=	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 LLC	SFPP	=	SFPP, L.P.
Hiland	=	Hiland Partners, LP	SLNG	=	Southern LNG Company, L.L.C.
KinderHawk	=	KinderHawk Field Services LLC	SNG	=	Southern Natural Gas Company, L.L.C.
Kinetrex	=	Kinetrex Energy	TGP	=	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 subsidiaries	TMPL	=	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 LLC	WYCO	=	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 day	GAAP	=	United States Generally Accepted Accounting Principles
AFUDC	=	allowance for funds used during construction
Bbl	=	barrels	LIBOR	=	London Interbank Offered Rate
BBtu	=	billion British Thermal Units	LLC	=	limited liability company
Bcf	=	billion cubic feet	LNG	=	liquefied natural gas
CERCLA	=	Comprehensive Environmental Response, Compensation and Liability Act	MBbl	=	thousand barrels
MMBbl	=	million barrels
C$	=	Canadian dollars	MMtons	=	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 downturn	NGL	=	natural gas liquids
NYMEX	=	New York Mercantile Exchange
CPUC	=	California Public Utilities Commission	NYSE	=	New York Stock Exchange
DCF	=	distributable cash flow	OTC	=	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 Agency	WTI	=	West Texas Intermediate
FASB	=	Financial Accounting Standards Board
FERC	=	Federal Energy Regulatory Commission

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;
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

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.

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 project	Description	Activity	Approx. Capital Scope (KMI Share)
Placed in service, acquisitions or divestitures
NGPL	We 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 assets	Acquired 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
Kinetrex	Acquired 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 Expansion	Expansion 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 Upgrade	Expansion 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 facilities	Construction 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;
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)] Capacity	Storage (Bcf) [Processing (Bcf/d)] Capacity	Supply 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
KMLP	140	3.89	—	Columbia Gulf, ANR Pipeline Company and various other pipeline interconnects; Cheniere Sabine Pass LNG and industrial markets
Stagecoach Gas Services LLC	185	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


Asset (KMI ownership shown if not 100%)	Miles of Pipeline	Design (Bcf/d) [(MBbl/d)] Capacity	Storage (Bcf) [Processing (Bcf/d)] Capacity	Supply and Market Region
Elba Express	190	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/Mojave	10,715	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
WIC	850	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
CPGPL	415	1.20	—	Rocky Mountain Basins; interconnects and demand locations in Colorado and Kansas
TransColorado	310	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 Storage	15	—	6	Located in the Permian Basin near the Waha natural gas trading hub in West Texas

Midstream
KM Texas and Tejas pipelines(d)	5,925	8.30	136 [0.52]	Texas Gulf Coast supply and markets
Mier-Monterrey pipeline(d)	90	0.65	—	Starr County, Texas to Monterrey, Mexico; connects to CENEGAS national system and multiple power plants in Monterrey
KM North Texas pipeline(d)	80	0.33	—	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%)	530	2.00	—	Permian Basin to the Agua Dulce, Texas area
PHP (27%)	430	2.10	—	Permian Basin to the Texas Gulf Coast and Mexico markets
Oklahoma
Oklahoma system	3,430	0.73	[0.09]	Hunton Dewatering, Woodford Shale, Anadarko Basin and Mississippi Lime, Arkoma Basin
Cedar Cove (70%)	115	0.03	—	Oklahoma STACK, capacity excludes third-party offloads
South Texas
South Texas system	1,160	1.93	[1.02]	Eagle Ford shale, Woodbine and Eaglebine formations


Asset (KMI ownership shown if not 100%)	Miles of Pipeline	Design (Bcf/d) [(MBbl/d)] Capacity	Storage (Bcf) [Processing (Bcf/d)] Capacity	Supply and Market Region
Webb/Duval gas gathering system (91%)	145	0.15	—	South Texas
Camino Real	75	0.15	—	South Texas, Eagle Ford shale formation
EagleHawk (25%)	530	1.20	—	South Texas, Eagle Ford shale formation
KM Altamont	1,545	0.10	[0.1]	Utah, Uinta Basin
Red Cedar (49%)	900	0.33	—	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)
KinderHawk	535	2.35	—	Northwest Louisiana, Haynesville and Bossier shale formations
North Texas	545	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.

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 Pipeline	Number of Terminals (a) or locations	Terminal Capacity (MMBbl)	Supply and Market Region

Crude & Condensate
KM Crude & Condensate pipeline	266	5	2.6	Eagle Ford shale field in South Texas (Dewitt, Karnes and Gonzales Counties) to the Houston ship channel refining complex
Camino Real Gathering	68	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 pipeline	206	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
Calnev	566	2	2.0	Colton, California to Las Vegas, Nevada; Mojave region
West Coast Terminals	44	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

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:


	Number	Capacity (MMBbl)
Liquids terminals	50	79.9
Bulk terminals	28	—
Jones Act-qualified tankers	16	5.3

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.

CO**2

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 unit	45	%	1.5	Colorado
Doe Canyon Deep unit	87	%	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.

Our ownership of CO2 and crude oil pipelines as of December 31, 2021 includes:


Asset (KMI ownership shown if not 100%)	Miles of Pipeline	Transport Capacity (Bcf/d)	Supply and Market Region
CO2 pipelines
Cortez pipeline (53%)	569	1.5	McElmo Dome and Doe Canyon source fields to the Denver City, Texas hub
Central Basin pipeline	337	0.7	Cortez, Bravo, Sheep Mountain, Canyon Reef Carriers and Pecos pipelines
Bravo pipeline (13%)(a)	218	0.4	Bravo Dome to the Denver City, Texas hub
Canyon Reef Carriers pipeline (98%)	163	0.3	McCamey, Texas, to the SACROC, Sharon Ridge, Cogdell and Reinecke units
Centerline CO2 pipeline	113	0.3	between Denver City, Texas and Snyder, Texas
Eastern Shelf CO2 pipeline	98	0.1	between Snyder, Texas and Knox City, Texas
Pecos pipeline (95%)	25	0.1	McCamey, Texas, to Iraan, Texas, delivers to the Yates unit
		(Bbls/d)
Crude oil pipeline
Wink pipeline	434	145,000	West 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 Interest		KMI Gross Developed Acres
SACROC	97	%	49,156
Yates	50	%	9,576
Goldsmith Landreth San Andres	99	%	6,166
Katz Strawn	99	%	7,194
Reinecke	70	%	3,793
Sharon Ridge(a)	14	%	2,619
Tall Cotton	100	%	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 Interest		Source
Snyder gas plant(a)	22	%	The SACROC unit and neighboring CO2 projects, specifically the Sharon Ridge and Cogdell units
Diamond M gas plant	51	%	Snyder gas plant
North Snyder gas plant	100	%	Snyder gas plant

(a)This is a working interest, in addition, we have a 28% net profits interest.

RNG and LNG Facilities

Owned and operated RNG and LNG facilities as of December 31, 2021 include:


	Storage (Bcf) [Production (Bcf)] Capacity	Product	Ownership Interest		Location
LNG Indy	2.0	LNG	100	%	Indiana
Indy High BTU	[0.8]	RNG	50	%	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

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

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

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

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

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

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

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.

Next: Item 1A. Risk Factors.