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, 2020

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
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,” “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, 2020 was approximately $29,459,747,400.  As of February 4, 2021, the registrant had 2,264,450,220 Class P shares outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s definitive proxy statement for the 2021 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2021, 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	6
	Business Strategy	6
	Business Segments	6
	Natural Gas Pipelines	6
	Products Pipelines	10
	Terminals	10
	CO2	11
	Major Customers	13
	Industry Regulation	13
	Environmental Matters	17
	Human Capital	19
	Properties and Rights of Way	20
	Financial Information about Geographic Areas	21
	Available Information	21
Item 1A.	Risk Factors	21
Item 1B.	Unresolved Staff Comments	34
Item 3.	Legal Proceedings	34
Item 4.	Mine Safety Disclosures	34
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	35
Item 6.	Selected Financial Data	35
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
	General	36
	Critical Accounting Policies and Estimates	38
	Results of Operations	41
	Overview	41
	Consolidated Earnings Results (GAAP)	44
	Non-GAAP Financial Measures	46
	Segment Earnings Results	49
	DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests	55
	Income Taxes	56
	Liquidity and Capital Resources	56
	General	56

KINDER MORGAN, INC. AND SUBSIDIARIES (continued)
TABLE OF CONTENTS
		Page Number
	Short-term Liquidity	57
	Long-term Financing	58
	Counterparty Creditworthiness	58
	Capital Expenditures	59
	Off Balance Sheet Arrangements	59
	Contractual Obligations and Commercial Commitments	60
	Cash Flows	60
	Dividends and Stock Buy-back Program	61
	Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries	62
	Recent Accounting Pronouncements	63
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	63
	Energy Commodity Market Risk	63
	Interest Rate Risk	64
	Foreign Currency Risk	65
Item 8.	Financial Statements and Supplementary Data	65
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	65
Item 9A.	Controls and Procedures	66
Item 9B.	Other Information	66
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	66
Item 11.	Executive Compensation	66
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	66
Item 13.	Certain Relationships and Related Transactions, and Director Independence	67
Item 14.	Principal Accounting Fees and Services	67
	PART IV
Item 15.	Exhibits, Financial Statement Schedules	68
	Index to Financial Statements and Supplementary Quarterly Data	72
Item 16.	Form 10-K Summary	136
Signatures		137

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.	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.
KMBT	=	Kinder Morgan Bulk Terminals, Inc.	TGP	=	Tennessee Gas Pipeline Company, L.L.C.
KMGP	=	Kinder Morgan G.P., 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.
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
2017 Tax Reform	=	The Tax Cuts & Jobs Act of 2017	GAAP	=	United States Generally Accepted Accounting Principles
/d	=	per day	IPO	=	Initial Public Offering
AFUDC	=	allowance for funds used during construction	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
			SEC	=	United States Securities and Exchange Commission
EBITDA	=	earnings before interest, income taxes, depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments	U.S.	=	United States of America
			WTI	=	West Texas Intermediate
EPA	=	United States Environmental Protection Agency
FASB	=	Financial Accounting Standards Board
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, the future impact on our business of the global economic consequences of the COVID-19 pandemic, including the timing and extent of any economic recovery, 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, 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, Oklahoma, Ohio, Pennsylvania and Texas, and the U.S. Rocky Mountains;

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

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

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

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

•issues, delays or stoppage associated with new construction or expansion projects;

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

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

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

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

•changes in tax laws;

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

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

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

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

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

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

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

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

•our ability to achieve cost savings and revenue growth;

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

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

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

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

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

The impacts of COVID-19 and decreases in commodity prices resulting from oversupply and demand weakness are discussed in further detail in Note 2 “Summary of Significant Accounting Policies—COVID-19” to our consolidated financial statements. Additional discussion of factors that may affect our forward-looking statements, including those associated with

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COVID-19, 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 144 terminals. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2 and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, chemicals, biodiesel, ethanol, metals and petroleum coke.

4

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
ELC and SLNG Expansion	Building of new natural gas liquefaction and export facilities at our SLNG natural gas terminal on Elba Island, near Savannah, Georgia, with a total capacity of 2.5 MMtons per year of LNG, equivalent to approximately 357,000 Dth/d of natural gas. Supported by a long-term firm contract with Shell.	SLNG facilities and three of 10 liquefaction units were placed in service in the later part of 2019. The remaining seven units were placed in service during January through August 2020.	$1.2 billion
Permian Highway Pipeline (PHP) Project	Joint venture pipeline project (KMTP 26.67%, BCP PHP, LLC (BCP) 26.67%, Altus Midstream Processing LP 26.67% and an affiliate of an anchor shipper has a 20% ownership interest) is designed to transport up to 2.1 Bcf/d of natural gas through approximately 430 miles of 42-inch pipeline from the Waha, Texas area to the U.S. Gulf Coast and Mexico markets. Subscribed under long-term firm transportation contracts.	Initial commissioning in-service date November 2020. Placed in full commercial service on January 1, 2021.	$652 million
KMI’s Crossover II Project	Expansion project that increases the delivery capacity on the Texas intrastate system by 1.4 Bcf/d. This expansion capacity serves LNG, industrial, electric generation and local distribution company expansions along the Texas Gulf Coast.	Placed in service November 2020	$257 million
EPNG South Mainline Expansion	Expansion project that provides 471,000 Dth/d of firm transportation capacity with a first phase of system improvements to deliver volumes to the Sierrita pipeline and the second phase for incremental deliveries of natural gas to Arizona and California. Subscribed under long-term firm transportation contracts.	Phase 1 is already in service. Phase 2 was placed in service July 2020.	$134 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 2022, pending regulatory approvals.	$246 million
KMLP Acadiana Expansion	Expansion project that will provide 945,000 Dth/d of capacity to serve Train 6 at Cheniere’s Sabine pass LNG terminal. Project supported by long-term contracts.	Expected to be placed in service as early as the second quarter 2022, regulatory approvals have been received.	$145 million
NGPL Gulf Coast Southbound Expansion (second phase)	Expansion project to increase southbound capacity on NGPL’s Gulf Coast System by approximately 300,000 Dth/d to serve Corpus Christi Liquefaction. Subscribed under a long-term firm transportation contract.	In mid-December 2020, compressor stations 300 and 301 were placed into service. Full project expected in-service date is the first half of 2021.	$101 million

Financings

During 2020, we and our subsidiaries issued approximately $2.25 billion of new senior notes and repaid approximately $2.2 billion of maturing senior notes. We utilized after-tax proceeds from the sale of Pembina stock received from the sale of KML to partially pay down debt that matured in February 2020, and in early January 2021, utilized a portion of proceeds from our August 2020 offerings to repay $750 million of senior notes that were scheduled to mature in March 2021.

5

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 expansions of assets 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.

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 44,000 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, 2020. 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	11,760	12.14	80	Marcellus, Utica, Gulf Coast, Haynesville, and Eagle Ford shale supply basins; Northeast, Southeast, Gulf Coast and U.S.-Mexico border markets
NGPL (50%)	9,100	7.60	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

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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
KMLP	140	3.00	—	Columbia Gulf, ANR Pipeline Company and various other pipeline interconnects; Cheniere Sabine Pass LNG and industrial markets
SNG (50%)	6,930	4.40	66	Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee markets; basins in Texas, Oklahoma, Louisiana, Mississippi and Alabama
Florida Gas Transmission (Citrus) (50%)	5,360	3.90	—	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
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
Bear Creek Storage (75%)	—	—	59	Located in Louisiana; provides storage capacity to SNG and TGP
SLNG	—	1.76	12	Located on Elba Island in Georgia; connects to Elba Express, SNG 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	10,685	6.39	44	Permian, San Juan and Anadarko Basins; interconnects and demand locations in California, Arizona, New Mexico, Texas, Oklahoma and Mexico
CIG	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%)(a)	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
WYCO (50%)	235	1.20	7	Denver Julesburg Basin; interconnects with CIG, WIC, Rockies Express Pipeline, Young Gas Storage and PSCo’s pipeline systems
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 (48%)	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(b)	5,920	8.30	132 [0.52]	Texas Gulf Coast supply and markets

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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
Mier-Monterrey pipeline(b)	90	0.65	—	Starr County, Texas to Monterrey, Mexico; connects to CENEGAS national system and multiple power plants in Monterrey
KM North Texas pipeline(b)	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%)(c)	430	2.10	—	Permian Basin to the Texas Gulf Coast and Mexico markets
Oklahoma
Oklahoma system	3,580	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
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	1,515	0.10	[0.1]	Utah, Uinta Basin
Red Cedar (49%)	900	0.33	—	La Plata County, Colorado, Ignacio Blanco Field
Rocky Mountain
Fort Union (42.595%)	315	1.25	—	Powder River Basin (Wyoming)
Bighorn (51%)	265	0.60	—	Powder River Basin (Wyoming)
KinderHawk	525	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	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%)(d)	400	[220]	—	South Texas, Eagle Ford shale formation

(a)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.

(b)Collectively referred to as Texas intrastate natural gas pipeline operations.

(c)Initial commissioning during November 2020.

(d)Asset also has storage capacity 60 MBbl.

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Competition

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

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

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Products Pipelines

Our Products Pipelines business segment consists of our refined petroleum products, crude oil and condensate pipelines, and associated terminals, 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, 2020:

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	66	1	0.1	South Texas, Eagle Ford shale formation
Hiland - Williston Basin - oil(b)	1,595	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 (KMCC - Splitter)	—	1	2.0	Houston Ship Channel, Galena Park, Texas
Southeast Refined Products
PPL pipeline (51%)(c)	3,183	—	—	Louisiana to Washington D.C.
Central Florida pipeline	206	2	2.5	Tampa to Orlando
Southeast Terminals	—	25	8.9	From Mississippi through 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%)	2,845	13	15.2	Six western states
Calnev	566	2	2.0	Colton, California to Las Vegas, Nevada; Mojave region
West Coast Terminals	38	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.

(c)Previously known as Plantation pipeline.

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 railcars and 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, ethanol and other liquid terminal facilities (other than those included in the Products Pipelines business segment) and all of our petroleum coke, metal and ores facilities.  Our terminals are located primarily near large U.S. urban centers.  We believe the location of our facilities and our ability to provide flexibility to customers help attract new and retain existing customers at our terminals and provide expansion opportunities. We often classify our terminal operations based on the handling of either liquids or dry-bulk material products. In addition, our Terminals’ marine operations include Jones Act-qualified product tankers that provide

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marine transportation of crude oil, condensate and refined petroleum products between U.S. ports. The following summarizes our Terminals business segment assets, as of December 31, 2020:

	Number	Capacity (MMBbl)
Liquids terminals	50	79.7
Bulk terminals	29	—
Jones Act-qualified tankers	16	5.3

Competition

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

CO2

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

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, 2020 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. Our other CO2 pipelines are not regulated.

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Our ownership of CO2 and crude oil pipelines as of December 31, 2020 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 Western Refining’s refinery in El Paso, Texas

(a)We do not operate Bravo pipeline.

Oil and Gas 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, 2020 include the following:

			KMI Gross
	Working		Developed
	Interest		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.

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Gas and Gasoline Plant Interests

Owned and operated gas plants in the Permian Basin of West Texas as of December 31, 2020 include:

	Ownership
	Interest		Source
Snyder gasoline plant(a)	22	%	The SACROC unit and neighboring CO2 projects, specifically the Sharon Ridge and Cogdell units
Diamond M gas plant	51	%	Snyder gasoline plant
North Snyder plant	100	%	Snyder gasoline plant

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

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, 2020, 2019 and 2018, 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

As an owner and operator of natural gas companies subject to the Natural Gas Act of 1938, we are required to provide service to shippers on our interstate natural gas pipelines and storage facilities at regulated rates that have been determined by the FERC to be just and reasonable. Recourse rates and general terms and conditions for service are set forth in posted tariffs approved by the FERC for each pipeline (including storage facilities or companies as used herein). Generally, recourse rates are based on our cost of service, including recovery of, and a return on, our investment. 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.

Posted tariff rates set the general range of maximum and minimum rates we charge shippers on our interstate natural gas pipelines. Within that range, each pipeline is permitted to charge discounted rates, so long as such discounts are offered to all similarly situated shippers and granted without undue discrimination. Apart from discounted rates, upon mutual agreement, the pipeline is permitted to charge negotiated rates that are not bound by and are irrespective of changes that may occur to the range of tariff-based maximum and minimum rate levels. 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. The actual negotiated rate agreement or a summary of such agreement must be posted as part of the pipelines’ tariffs. While pipelines and their shippers may agree to a variety of negotiated rate structures depending on the shipper and circumstance, pipelines generally must use for all shippers the form of service agreement that is contained within their FERC-approved tariff. Any deviation from the pro forma service agreements must be filed with the FERC and only certain types of deviations in the terms and conditions of service are acceptable to the FERC.

The FERC regulates the rates, terms and conditions of service, construction and abandonment of facilities by companies performing interstate natural gas transportation services, including storage services, under the Natural Gas Act of 1938. To a lesser extent, the FERC regulates interstate transportation rates, terms and conditions of service under the Natural Gas Policy Act of 1978. Beginning in the mid-1980s, the FERC adopted a number of regulatory changes to ensure that interstate natural gas pipelines operated on a not unduly discriminatory basis and to create a more competitive and transparent environment in the natural gas marketplace. Examples include FERC regulations requiring interstate natural gas pipelines to separate their traditional merchant sales services from their transportation and storage services and provide comparable transportation and

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storage services with respect to all natural gas customers. Also, natural gas pipelines must separately state the applicable rates for each unbundled service they provide (i.e., for transportation services and storage services for natural gas). To ensure a competitive transportation market, these pipelines must adhere to certain scheduling procedures, accept capacity segmentation in certain circumstances and abide by FERC-established standards of conduct when communicating with marketing affiliates.

In addition to regulatory changes initiated by the FERC, the U.S. Congress passed the Energy Policy Act of 2005. Among other things, the Energy Policy Act amended the Natural Gas Act to: (i) prohibit market manipulation by any entity; (ii) direct the FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce; and (iii) significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations or orders thereunder.

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.

The Energy Policy Act of 1992 deemed petroleum products pipeline tariff rates that were in effect for the 365-day period ending on the date of enactment or that were in effect on the 365th day preceding enactment and had not been subject to complaint, protest or investigation during the 365-day period to be just and reasonable or “grandfathered” under the ICA. The Energy Policy Act also limited the circumstances under which a complaint can be made against such grandfathered rates. Certain rates on our SFPP operations’ pipeline system were subject to protest during the 365-day period established by the Energy Policy Act. Accordingly, certain of the SFPP pipelines’ rates have been, and continue to be, the subject of complaints 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. The intrastate rates for movements in California on our SFPP and Calnev systems have been, and may in the future be, subject to complaints before the CPUC.

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.