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, 2022

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

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
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.  ☑

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

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, 2022 was approximately $33,112,481,840.  As of February 7, 2023, the registrant had 2,248,003,224 shares of Class P common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s definitive proxy statement for the 2023 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2023, 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	4
	Recent Developments	4
	Narrative Description of Business	5
	Business Strategy	5
	Business Segments	6
	Natural Gas Pipelines	6
	Products Pipelines	9
	Terminals	11
	CO2	13
	Major Customers	15
	Industry Regulation	16
	Environmental Matters	19
	Human Capital	21
	Properties and Rights-of-Way	22
	Financial Information about Geographic Areas	22
	Available Information	22
Item 1A.	Risk Factors	23
Item 1B.	Unresolved Staff Comments	35
Item 3.	Legal Proceedings	35
Item 4.	Mine Safety Disclosures	35
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	36
Item 6.	[Reserved]	36
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
	General	37
	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	56
	Income Taxes	57
	Liquidity and Capital Resources	57
	General	57

KINDER MORGAN, INC. AND SUBSIDIARIES (continued)
TABLE OF CONTENTS
		Page Number
	Short-term Liquidity	58
	Long-term Financing	59
	Counterparty Creditworthiness	59
	Capital Expenditures	59
	Off Balance Sheet Arrangements	60
	Contractual Obligations and Commercial Commitments	61
	Cash Flows	62
	Dividends and Stock Buy-back Program	63
	Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries	64
	Recent Accounting Pronouncements	65
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	65
	Energy Commodity Market Risk	65
	Interest Rate Risk	66
	Foreign Currency Risk	67
Item 8.	Financial Statements and Supplementary Data	68
	Index to Financial Statements	68
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	129
Item 9A.	Controls and Procedures	129
Item 9B.	Other Information	130
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	130
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	130
Item 11.	Executive Compensation	130
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	130
Item 13.	Certain Relationships and Related Transactions, and Director Independence	130
Item 14.	Principal Accounting Fees and Services	130
	PART IV
Item 15.	Exhibits, Financial Statement Schedules	131
Item 16.	Form 10-K Summary	134
Signatures		135

KINDER MORGAN, INC. AND SUBSIDIARIES

GLOSSARY

Company Abbreviations

Calnev	=	Calnev Pipe Line LLC	KMLT	=	Kinder Morgan Liquid Terminals, LLC
CIG	=	Colorado Interstate Gas Company, L.L.C.	KMP	=	Kinder Morgan Energy Partners, L.P. and its majority-owned and/or controlled subsidiaries
CPGPL	=	Cheyenne Plains Gas Pipeline Company, L.L.C.
EagleHawk	=	EagleHawk Field Services LLC	KMTP	=	Kinder Morgan Texas Pipeline LLC
Elba Express	=	Elba Express Company, L.L.C.	MEP	=	Midcontinent Express Pipeline LLC
EIG	=	EIG Global Energy Partners	NGPL	=	Natural Gas Pipeline Company of America LLC and certain affiliates
ELC	=	Elba Liquefaction Company, L.L.C.
EPNG	=	El Paso Natural Gas Company, L.L.C.	PHP	=	Permian Highway Pipeline LLC
FEP	=	Fayetteville Express Pipeline LLC	Ruby	=	Ruby Pipeline Holding Company, L.L.C.
Hiland	=	Hiland Partners, LP	SFPP	=	SFPP, L.P.
KinderHawk	=	KinderHawk Field Services LLC	SLNG	=	Southern LNG Company, L.L.C.
Kinetrex	=	Kinetrex Energy	SNG	=	Southern Natural Gas Company, L.L.C.
KMBT	=	Kinder Morgan Bulk Terminals, Inc.	Stagecoach	=	Stagecoach Gas Services LLC
KMI	=	Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries	TGP	=	Tennessee Gas Pipeline Company, L.L.C.
			WIC	=	Wyoming Interstate Company, L.L.C.
KMLP	=	Kinder Morgan Louisiana Pipeline LLC	WYCO	=	WYCO Development L.L.C.
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	GTE	=	gas-to-electric
BBtu	=	billion British Thermal Units	LIBOR	=	London Interbank Offered Rate
Bcf	=	billion cubic feet	LLC	=	limited liability company
CERCLA	=	Comprehensive Environmental Response, Compensation and Liability Act	LNG	=	liquefied natural gas
			MBbl	=	thousand barrels
CO2	=	carbon dioxide or our CO2 business segment	MMBbl	=	million barrels
COVID-19	=	Coronavirus Disease 2019, a widespread contagious disease, or the related pandemic declared and resulting worldwide economic downturn	MMtons	=	million tons
			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
			SOFR	=	Secured Overnight Financing Rate
EPA	=	United States Environmental Protection Agency	U.S.	=	United States of America
FASB	=	Financial Accounting Standards Board	WTI	=	West Texas Intermediate
FERC	=	Federal Energy Regulatory Commission

1

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, chemical or petrochemical 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;

2

•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 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 higher interest rates;

•political and economic instability of the oil and natural gas 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; and

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

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 of our 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.

3

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, 140 terminals, 700 Bcf of working natural gas storage capacity and have RNG generation capacity of approximately 2.2 Bcf per year of gross production. 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, renewable fuel feedstocks, chemicals, ethanol, 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
ELC	Sold a 25.5% interest in ELC to an undisclosed financial buyer and now own a 25.5% interest.	Completed in September 2022.	n/a
Mas Ranger	Acquired three landfill assets with the purchase of Mas Ranger, LLC and its subsidiaries from Mas CanAm, LLC. Assets include an RNG facility in Arlington, Texas and Medium British Thermal Units facilities in Shreveport, Louisiana and Victoria, Texas.	Acquired in July 2022.	$358 million
North American Natural Resources	Acquired seven landfill assets with the purchase of North American Natural Resources, Inc. and, its sister companies, North American Biofuels, LLC and North American-Central, LLC (NANR). Assets include GTE facilities in Michigan and Kentucky. A final investment decision was made to convert Autumn Hills, one of the seven landfill assets acquired, to an RNG facility and construction began in January 2023.	Acquired in August 2022.	$132 million
Other Announcements
Natural Gas Pipelines
TGP and SNG Evangeline Pass	Two-phase 2 Bcf/d project to serve Venture Global’s proposed Plaquemines LNG facility (Plaquemines). First phase, TGP will provide approximately 0.9 Bcf/d natural gas transportation capacity to Plaquemines. Second phase, TGP and SNG will jointly provide volumes up to the remaining 1.1 Bcf/d to Plaquemines.	Expected in-service date for first phase is fourth quarter of 2024 and third quarter of 2025 for the second phase, pending receipt of all required permits.	$678 million
Eagleford transport project	Expansion project includes constructing 69 miles of 42-inch pipeline, multiple receipt and delivery meters and upgrades to Kinder Morgan Freer compressor station to transport up to 1.88 Bcf/d of lean Eagleford production to Gulf Coast markets.	Expected in-service date is fourth quarter 2023.	$283 million
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.	$263 million
PHP expansion	Joint venture project that will expand PHP’s capacity by approximately 550,000 Dth/d, increasing natural gas deliveries from the Permian to U.S. Gulf Coast markets. Supported by long-term contracts.	Expected in-service date is November 2023.	$149 million

4

Asset or project	Description	Activity	Approx. Capital Scope (KMI Share)
Greenholly pipeline - North Holly expansion	Joint venture project (our ownership interest of 37.58%) to construct 38 miles of 36-inch pipeline from partner receipt points to KinderHawk wholly owned North Holly gathering system and includes joint venture pipeline receipt interconnects off KinderHawk’s Greenwood system, upgrades to KinderHawk’s North Holly system and 400 gallons per minute treating capacity addition to KinderHawk’s North Holly plant. Supported by long-term contracts.	Expected in-service date is second quarter 2023.	$121 million
3Rivers Offload Phase II	Construct 19 miles of 16-inch pipeline and associated compression allowing delivery of 50,000 Dth/d of incremental gathered production for third-party processing.	Expected in-service date is third quarter 2023.	$96  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.	Expected to be in service throughout 2023.	$150 million

Financings

During 2022, EPNG issued $300 million and KMI issued $1,500 million of new senior notes to repay maturing debt and for general corporate purposes. On January 17, 2023, we repaid $1,250 million of maturing senior notes using cash on hand and short-term borrowings. On January 31, 2023, we issued $1,500 million of new senior notes to repay short-term borrowings, maturing debt and for general corporate purposes. On January 18, 2023, our board of directors approved an increase in our share repurchase authorization of our share buy-back program from $2 billion to $3 billion. Subsequently, we have approximately $2.1 billion of capacity remaining under this program. During 2022, we repurchased approximately 21.7 million shares of Class P common stock for $368 million at an average price of $16.94 per share.

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 asset expansions and acquisitions 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.

5

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, our LNG liquefaction and terminal facilities and NGL fractionation 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., Rocky Mountain, Midwest, Texas, Louisiana, Southeastern and Northeast 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, 2022. The design capacity represents transmission, gathering, regasification or liquefaction capacity, depending on the nature of the asset.

Asset	Ownership Interest		Miles of Pipeline	Design (Bcf/d) [(MBbl/d)] Capacity	Storage (Bcf) [Processing (Bcf/d)] Capacity
East Region
TGP(a)	100	%	11,755	12.23	76
NGPL	37.5	%	9,105	7.84	288
KMLP	100	%	140	3.89	—
Stagecoach	100	%	185	3.22	41
SNG(a)	50	%	6,925	4.47	66

6

Asset	Ownership Interest		Miles of Pipeline	Design (Bcf/d) [(MBbl/d)] Capacity	Storage (Bcf) [Processing (Bcf/d)] Capacity
Florida Gas Transmission (Citrus)	50	%	5,380	4.31	—
MEP	50	%	515	1.81	—
Elba Express	100	%	190	1.10	—
FEP	50	%	185	2.00	—
Gulf LNG Holdings	50	%	5	1.50	7
SLNG	100	%	—	1.76	12
ELC	25.5	%	—	0.35	—
West Region
EPNG/Mojave	100	%	10,720	6.39	44
CIG(b)	100	%	4,300	6.00	38
WIC	100	%	850	3.61	—
Ruby(c)	50	%	685	1.53	—
CPGPL	100	%	415	1.20	—
TransColorado	100	%	310	0.80	—
Sierrita	35	%	60	0.52	—
Young Gas Storage	47.5	%	15	—	6
Keystone Gas Storage	100	%	15	—	6
Midstream
KM Texas and Tejas pipelines(d)	100	%	5,915	8.30	136 [0.52]
Mier-Monterrey pipeline(d)	100	%	90	0.65	—
KM North Texas pipeline(d)	100	%	80	0.33	—
Gulf Coast Express pipeline	34	%	530	2.00	—
PHP	26.67	%	435	2.10	—
Oklahoma
Oklahoma system	100	%	3,225	0.73	[0.09]
Cedar Cove	70	%	120	0.03	—
South Texas
South Texas system	100	%	1,155	1.93	[1.02]
Webb/Duval gas gathering system	91	%	145	0.15	—
Camino Real	100	%	75	0.15	—
EagleHawk	25	%	550	1.20	—
KM Altamont	100	%	1,535	0.13	[0.1]
Red Cedar	49	%	865	0.33	—
Rocky Mountain
Fort Union	50	%	315	1.25	—
Bighorn	51	%	265	0.60	—
KinderHawk	100	%	535	2.35	—
North Texas	100	%	530	0.14	—
KM Treating	100	%	—	—	—
Hiland - Williston - gas	100	%	2,190	0.62	[0.33]
Liberty pipeline	50	%	85	[140]	—
South Texas NGL pipelines(e)	100	%	340	[115]	—
Utopia pipeline	50	%	265	[50]	—
Cypress pipeline	50	%	105	[56]	—
EagleHawk - Condensate(f)	25	%	410	[220]	—

(a)Includes proportionate share of storage capacity from our Bear Creek Storage joint venture.

7

(b)Includes leased pipeline miles and proportionate share of design and storage capacity from our WYCO joint venture.

(c)As of December 31, 2022, we operated Ruby and owned an effective 50% interest. Ruby is not included on the map above. On January 13, 2023, a bankruptcy court confirmed a plan of reorganization satisfactory to all interested parties regarding Ruby which involved the sale of Ruby, and subsequently we no longer hold an interest in Ruby. For further information regarding Ruby’s bankruptcy filing, see Note 4 “Gains and Losses on Divestitures, Impairments and Other Write-downs—Ruby Chapter 11 Bankruptcy Filing.”

(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 Contracts

Revenues from our interstate natural gas pipelines, related storage facilities and LNG terminals 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 that capacity. Similarly, our Texas Intrastate natural gas pipeline operations currently derive approximately 77% 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, 2022, the remaining weighted average contract life of our natural gas transportation contracts held by assets we own or 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-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.

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 domestic and export 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.

8

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, 2022:

Asset	Ownership Interest		Miles of Pipeline	Number of Terminals (a) or locations	Terminal Capacity (MMBbl)
Crude & Condensate
KM Crude & Condensate pipeline	100	%	266	5	2.6
Camino Real Gathering	100	%	68	1	0.1
Hiland - Williston Basin - oil(b)	100	%	1,617	7	0.8
Double H pipeline(b)	100	%	512	—	—
Double Eagle pipeline	50	%	204	2	0.6
KM Condensate Processing Facility (Splitter)	100	%	—	1	2.1
Southeast Refined Products
Products (SE) pipeline	51	%	3,186	—	—
Central Florida pipeline	100	%	206	2	2.6
Southeast Terminals	100	%	—	25	9.3
Transmix Operations	100	%	—	5	0.7
West Coast Refined Products
Pacific (SFPP)	99.5	%	2,804	13	15.9
Calnev	100	%	566	2	2.1
West Coast Terminals	100	%	44	8	10.1

(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.

9

Segment Contracts

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 (which do not require contractual commitments) or (ii) long-term contracts that normally contain minimum volume commitments. Where we have long-term 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 levels 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. Our crude oil marketing activities generate revenues from the sale and delivery of crude oil and condensate purchased either directly from producers or from others on the open market. In general, sales prices referenced in underlying purchase and sales contracts are market-based and include pricing differentials for factors such as delivery location or crude oil quality.

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.

10

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, refined petroleum products and renewable fuel between U.S. ports.

The following summarizes our Terminals business segment assets, as of December 31, 2022:

	Number	Capacity (MMBbl)
Liquids terminals	47	77.8
Bulk terminals	28	—
Jones Act-qualified tankers	16	5.3

Segment Contracts

The factors impacting our Terminals business segment generally differ between liquid and bulk terminals.  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

11

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.

Our Jones Act-qualified tankers provide marine transportation of crude oil, condensate, refined products and renewable fuel 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.

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.

12

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. We also own and operate oil and gas producing fields, and RNG, LNG and landfill GTE facilities.  Our CO2 pipelines and related assets allow us to market a complete package of CO2 supply and transportation services to our customers.

Source and Transportation Activities

CO2 Resource Interests

Our ownership of CO2 resources as of December 31, 2022 includes:

	Ownership Interest		Compression Capacity (Bcf/d)
McElmo Dome unit	45	%	1.5
Doe Canyon Deep unit	87	%	0.2
Bravo Dome unit(a)	11	%	0.3

(a)We do not operate this unit.

13

CO2 and Crude Oil Pipelines

Industry demand for transportation on our CO2 pipelines is expected to remain stable for the foreseeable future.

Our ownership of CO2 and crude oil pipelines as of December 31, 2022 includes:

Asset	Ownership Interest		Miles of Pipeline	Transport Capacity (Bcf/d) [(MBbl/d)]
CO2 pipelines
Cortez pipeline	53	%	569	1.5
Central Basin pipeline	100	%	337	0.7
Bravo pipeline(a)	13	%	218	0.4
Canyon Reef Carriers pipeline	98	%	163	0.3
Centerline CO2 pipeline	100	%	113	0.3
Eastern Shelf CO2 pipeline	100	%	98	0.1
Pecos pipeline	95	%	25	0.1
Crude oil pipeline
Wink pipeline	100	%	434	[145]

(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 as of December 31, 2022 include the following:

	Working Interest		KMI Gross Developed Acres
SACROC	97	%	50,316
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 Plant Interests

Owned and operated gas plants as of December 31, 2022 include:

Asset	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.

14

RNG, LNG and GTE Facilities

Owned and operated RNG, LNG and GTE facilities as of December 31, 2022 include:

Asset	Ownership Interest		Storage [Production] Generation Capacity(a)	Product
LNG Indy	100	%	2 Bcf	LNG
Indy High BTU	50	%	[0.8 Bcf]	RNG
Southeast Berrien	100	%	4.8 mW/h	GTE
Autumn Hills	100	%	4.0 mW/h	GTE
Central	100	%	4.0 mW/h	GTE
Venice Park	100	%	6.4 mW/h	GTE
Peoples	100	%	4.8 mW/h	GTE
Morehead	100	%	1.6 mW/h	GTE
Blue Ridge	100	%	1.6 mW/h	GTE
Arlington RNG	100	%	7.3 mcf/d	RNG
Shreveport RNG(b)	—	%	3.8 mcf/d	Medium BTU
Victoria RNG	100	%	1.4 mcf/d	Medium BTU

(a)GTE generation capacity is measured in megawatts per hour (mW/h). RNG and Medium British Thermal Units (BTU) gas capacities are measured in thousands of cubic feet per day (mcf/d).

(b)We operate Shreveport for a fee and receive royalties on RNG sales.

Segment Contracts

The CO2 source and transportation business primarily has third-party contracts with minimum volume requirements, which as of December 31, 2022 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 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 or bracketed through the use of financial derivative contracts, particularly for crude oil.  See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Segment Earnings Results” for more information on crude oil sales prices.

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 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, 2022, 2021 and 2020, 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.

15

Industry Regulation

Our business operations are subject to extensive federal, state and local laws and regulations. Please read Item 1A. “Risk Factors—Risks Related to Regulation” for discussions of the risks we face related to regulation. For information related to pending regulatory proceedings, see Note 18 “Litigation and Environmental” to our consolidated financial statements.

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 give the FERC authority over the construction and operation of such facilities, including their modification, extension, enlargement and abandonment.

Pursuant to the NGA, 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 the FERC or included in summary form in the pipeline’s tariff.

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 the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the 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. The 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.

The FERC has authority to impose civil penalties 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 the FERC, we could be subject to substantial civil penalties and fines.

In addition to having jurisdiction over interstate natural gas pipelines and storage companies, the FERC also has jurisdiction over the interstate transportation and storage services that are provided by intrastate pipelines and storage companies under Section 311 of the NGPA. We have numerous intrastate pipelines and storage companies that provide interstate services pursuant to Section 311 of the NGPA. Under Section 311, along with the FERC’s implementing regulations, an intrastate pipeline may transport gas “on behalf of” an interstate pipeline company or any local distribution company served by an interstate pipeline, without becoming subject to the FERC’s broader regulatory authority under the NGA. These services must be provided on an open and nondiscriminatory basis, and the rates charged for these services may not exceed a “fair and equitable” level as dete