Items 1 and 2. Business and Properties.

We are one of the largest energy infrastructure companies in North America. As of December 31, 2023, we owned an interest in or operated approximately 82,000 miles of pipelines, 139 terminals, 702 Bcf of working natural gas storage capacity and had RNG generation capacity of approximately 6.1 Bcf per year of gross production. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2, renewable fuels and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, jet fuel, chemicals, petroleum coke, metals, and ethanol and other renewable fuels and feedstocks.

General Development of Business

Recent Developments

The following is a listing of significant developments and updates related to our major acquisitions and projects and financing transactions. “Capital Scope” is estimated for our share of the described project and may include portions not yet completed.

Asset or project

Description

Activity

Approx. Capital Scope (KMI Share)

Acquisitions and projects placed in service

STX Midstream pipeline system acquisition

Acquired a set of integrated, large diameter, high pressure natural gas pipeline systems that connect the Eagle Ford basin to growing Mexico and Gulf Coast demand markets with the purchase of the STX Midstream pipeline system from NextEra Energy Partners, LP. These pipeline systems include the Eagle Ford Transmission system, a 90% interest in the NET Mexico Pipeline LLC and a 50% interest in Dos Caminos, LLC.

Acquired in December 2023.

$1,831 million

TGP East 300 Upgrade

Expansion project involved 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.

Placed in service November 2023.

$267 million

Eagle Ford transport project

Expansion project included constructing 67 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 Eagle Ford production to Gulf Coast markets. Supported by long-term contracts.

Placed in service November 2023.

$231 million

PHP expansion

Joint venture project (our ownership interest of 27.74%) that expanded 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.

Placed in service December 2023.

$159 million

RNG facilities

Construction of three additional landfill-based RNG facilities for KMRNG in order to provide approximately 3.5 Bcf of RNG a year.

Twin Bridges placed in service June 2023. Liberty placed in service October 2023. Prairie View placed in service December 2023.

$153 million

Asset or project

Description

Activity

Approx. Capital Scope (KMI Share)

Greenholly pipeline - North Holly expansion

Joint venture project (our ownership interest of 39.25%) that constructed 38 miles of 36-inch pipeline to provide 1.15 Bcf/d of capacity and runs from KinderHawk’s Greenwood system and partner receipt points to KinderHawk’s North Holly system. Supported by long-term contracts.

Placed in service August 2023.

$125 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 third quarter of 2024 and third quarter of 2025 for the second phase, pending receipt of all required permits.

$673 million

TVA Cumberland

Project includes a new 32-mile pipeline to transport approximately 0.245 Bcf/d of natural gas from the existing TGP system to Tennessee Valley Authority’s (TVA) proposed 1,450 megawatt generation facility at an existing site in Cumberland, Tennessee.

Expected in-service date is August 2025, pending receipt of all required permits and clearances.

$181 million

KMTP system expansion

Expansion project includes a new 30-mile, 30-inch pipeline, to deliver up to 0.5 Bcf/d of Eagle Ford natural gas supply to markets along the Texas Gulf Coast and Mexico. Expansion will provide transportation services, including treating, for Kimmeridge Texas Gas and other third parties. Supported by a long-term contract.

Expected in-service date is November 2024.

$180 million

Central Texas pipeline

Project includes installation of 22 miles of 30-inch pipeline from PHP to Sand Hill Lateral, 1.75 miles of 20-inch pipeline from Sand Hill Lateral to Texas Gas Services and three meter stations and one regulator station.

Expected in-service date is fourth quarter of 2024.

$115 million

Tejas South to North expansion

South Texas to Houston Market expansion project to add compression on Tejas’ mainline to increase natural gas deliveries by approximately 0.35 Bcf/d to Houston markets.

Expected in-service date is third quarter of 2024.

$97 million

3Rivers Offload Phase II

Construct 19 miles of 16-inch pipeline and associated compression allowing delivery of 27,000 Dth/d of incremental gathered production for third-party processing.

Expected in-service date is second quarter 2025.

$96 million

CO2

Diamond M expansion

Enhanced oil recovery expansion at our recently acquired Diamond M field that will result in peak oil production of over 5,000 Bbl/d.

Expected in-service date for the first phase is late 2024, second phase is mid 2025, and peak production in 2026.

$180 million

Financings and Share Repurchases

During 2023, we (i) issued $1,500 million of new senior notes to repay short-term borrowings, maturing debt and for general corporate purposes; (ii) utilized commercial paper borrowings under our credit facility to fund the $1,831 million acquisition of the STX Midstream pipeline system (STX Midstream); and (iii) repaid a combined $3,225 million of maturing senior notes. On January 18, 2023, our board of directors (Board) approved an increase in our share repurchase authorization of our share buy-back program from $2 billion to $3 billion. During 2023, we repurchased approximately 32 million shares of Class P common stock for $522 million at an average price of $16.56 per share. We have approximately $1.5 billion of capacity remaining under this program.

On February 1, 2024, we issued $2,250 million of new senior notes to repay short-term borrowings, fund maturing debt and for general corporate purposes.

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 decisions 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, approval of our Board and regulatory approval. 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, 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 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., Rocky Mountain, Midwest, Texas, Louisiana, Southeastern and Northeast regions. Our LNG terminal facilities also serve natural gas market areas in the southeast. The following table summarizes our significant Natural Gas Pipelines business segment assets as of December 31, 2023. 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	12.38	76
NGPL	37.5	%	9,100	7.84	288
KMLP	100	%	140	3.89	—
Stagecoach	100	%	185	3.22	41
SNG(a)	50	%	6,925	4.39	66
Florida Gas Transmission (Citrus)	50	%	5,380	4.39	—
MEP	50	%	515	1.81	—
Elba Express	100	%	190	1.16	—
FEP	50	%	185	2.00	—
Gulf LNG Holdings	50	%	5	1.50	7

Asset	Ownership Interest		Miles of Pipeline	Design (Bcf/d) [(MBbl/d)] Capacity	Storage (Bcf) [Processing (Bcf/d)] Capacity
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	3.39	—
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(c)(d)	100	%	5,980	9.50	138 [0.52]
Mier-Monterrey pipeline(c)	100	%	90	0.65	—
KM North Texas pipeline(c)	100	%	80	0.33	—
Gulf Coast Express pipeline	34	%	530	2.00	—
PHP	27.74	%	435	2.65	—
Oklahoma
Oklahoma system	100	%	3,175	0.73	[0.09]
Cedar Cove	70	%	120	0.03	—
South Texas
South Texas system	100	%	1,130	1.90	[1.02]
Webb/Duval gas gathering system	91	%	140	0.15	—
Camino Real	100	%	75	0.15	—
EagleHawk	25	%	555	1.20	—
KM Altamont	100	%	1,605	0.13	[0.10]
Red Cedar	49	%	860	0.33	—
Rocky Mountain
Fort Union	50	%	315	1.25	—
Bighorn	51	%	290	0.60	—
KinderHawk	100	%	570	2.40	—
Greenholly Gathering	39.25	%	40	1.15	—
KM Treating	100	%	—	—	—
Hiland - Williston - gas	100	%	2,200	0.62	[0.33]
Eagle Ford Transmission system	100	%	160	1.05	—
NET Mexico	90	%	120	2.15	—
Dos Caminos	50	%	75	1.20	—
Mission Natural Gas	100	%	1	—	—
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.

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

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

(d)Includes LaSalle, Mission Valley, Red Gate and South Shore assets associated with our acquisition of STX Midstream.

(e)Includes proportionate share of design capacity from our Liberty pipeline joint venture.

(f)Asset also has storage capacity of 60 MBbl.

Natural Gas Pipelines 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 74% 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, 2023, 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 and our LNG regasification and liquefaction and associated storage contracts were subscribed under long-term agreements with a weighted average remaining contract life of approximately 11 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. Our natural gas marketing activities generate revenues from the sale and delivery of natural gas purchased either directly from producers or from others on the open market.

Natural Gas Pipelines 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.

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

Products Pipelines

Our Products Pipelines business segment consists of our refined petroleum products, crude oil and condensate pipelines, and associated terminals, our condensate processing facility and our transmix processing facilities.

The following summarizes the significant Products Pipelines business segment assets that we owned and operated as of December 31, 2023:

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	%	1,645	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	%	3,187	—	—
Central Florida pipeline	100	%	206	2	2.6
Southeast Terminals	100	%	—	25	9.3
Transmix Operations	100	%	—	5	0.6
West Coast Refined Products
Pacific (SFPP)	99.5	%	2,806	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.

Products Pipelines 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. Included in the number of terminals above are refined products liquids terminals 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 follow trends in population 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.

Products Pipelines 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 movement of products). Our transmix operations compete with refineries owned by major oil companies and independent transmix facilities.

Terminals

Our Terminals business segment includes the operations of our refined petroleum product, chemical, renewable fuel and other liquid terminal facilities (other than those included in the Products Pipelines business segment) and all of our petroleum coke, metal and ores facilities. Our terminals are located primarily near large U.S. urban centers. We believe the location of our facilities and our ability to provide flexibility to customers help attract new and retain existing customers at our terminals and provide expansion opportunities. We often classify our terminal operations based on the handling of either liquids or dry-bulk material products. In addition, our Terminals’ 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, 2023:

	Number	Capacity(MMBbl)
Liquids terminals	47	78.7
Bulk terminals	27	—
Jones Act tankers	16	5.3

Terminals Segment Contracts

The factors impacting our Terminals business segment generally differ between liquid and bulk terminals. Our liquids terminals business generally enters into long-term contracts that require the customer to pay our fee 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 supply and demand 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 was approximately two years as of December 31, 2023), the extent to which revenues under the contracts are a function of the amount of product stored or transported, and the extent to which such contracts expire during any given period of time.

As with our refined petroleum products pipelines transportation business, the revenues from our bulk terminals business are generally driven by the volumes we handle and/or store, as well as the prices we receive for our services, which in turn are

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

Our Jones Act-qualified tankers are primarily operating pursuant to fixed price term charters with major integrated oil companies, major refiners and the U.S. Military Sealift Command.

Terminals 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 tankers compete with other Jones Act-qualified vessel fleets.

CO

Our CO business segment produces, transports and markets CO 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 CO pipelines and related assets allow us to market a complete package of CO supply and transportation services to our customers.

Source and Transportation Activities

CO Resource Interests

Our ownership of CO resources as of December 31, 2023 includes:

	OwnershipInterest		CompressionCapacity (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.

CO and Crude Oil Pipelines

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

Our ownership of CO and crude oil pipelines as of December 31, 2023 includes:

Asset	Ownership Interest		Miles of Pipeline	Transport Capacity (Bcf/d)[(MBbl/d)]
CO2 pipelines
Cortez	53	%	569	1.5
Central Basin	100	%	337	0.7
Bravo(a)	13	%	218	0.4
Canyon Reef Carriers	97	%	163	0.3
Centerline	100	%	113	0.3
Eastern Shelf	100	%	98	0.1
Pecos	95	%	25	0.1
Crude oil pipeline
Wink	100	%	434	[145]

(a)We do not operate Bravo.

Oil, Gas and RNG Producing Activities

Oil and Gas Producing Interests

Our ownership interests in oil and gas producing fields as of December 31, 2023 included the following:

	Working Interest		KMI Gross Developed Acres
SACROC	97	%	50,316
Yates	50	%	9,676
Goldsmith Landreth San Andres	99	%	6,166
Katz Strawn	99	%	7,194
Diamond M	88	%	5,396
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

Our ownership and operation of gas plants as of December 31, 2023 included:

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.

RNG, LNG and GTE Facilities

Our ownership and operation of RNG, LNG and GTE facilities as of December 31, 2023 included:

Asset

Ownership Interest

Production [Storage] Generation Capacity(a)

Product

LNG Indy

100

%

[2 Bcf]

LNG

Indy High BTU

50

%

1.0 Bcf/y

RNG

Twin Bridges

100

%

1.5 Bcf/y

RNG

Liberty

100

%

1.5 Bcf/y

RNG

Prairie View

100

%

0.8 Bcf/y

RNG

Arlington RNG

100

%

1.3 Bcf/y

RNG

Shreveport RNG(b)

—

%

0.7 Bcf/y

Medium BTU

Victoria RNG

100

%

0.4 Bcf/y

Medium BTU

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

Morehead

100

%

1.6 mW/h

GTE

Blue Ridge

100

%

1.6 mW/h

GTE

(a)GTE generation capacity is measured in megawatts per hour (mW/h). RNG and Medium British Thermal Units (BTU) gas capacities are measured in Bcf per year (Bcf/y).

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

CO Segment Contracts

Our CO source and transportation business primarily has third-party contracts with minimum volume requirements, which as of December 31, 2023 had a remaining average contract life of approximately seven years. Our CO sales contracts vary from customer to customer and generally provide for a delivered price tied to the price of crude oil, in some casesbased on a fixed fee or floor price. Our success in this portion of the CO business segment can be impacted by the demand for CO. In the CO 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 driven by the demand and overall market price for these products. In the shorter term, however, market prices generally are not indicative of the revenues we will receive due to our 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.

CO Segment Competition

Our primary competitors for the sale of CO include suppliers that have an ownership interest in McElmo Dome, Bravo Dome and Sheep Mountain CO resources. Our ownership interests in the Central Basin, Cortez and Bravo pipelines are in direct competition with other CO pipelines. We compete with other interest owners in the McElmo Dome unit and the Bravo Dome unit for transportation of CO 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, 2023, 2022 and 2021, 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

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 $1.4 million per day per violation. If 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 natural gas 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 determined by the FERC in periodic rate proceedings.

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 carrier liquids pipelines as well as the rules and regulations governing these services. The ICA requires, among other things, that rates on interstate common carrier liquids 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 to shippers the difference between the revenues collected during the pendency of the investigation and the revenues that would have been collected based on the rate the FERC finds to be just and reasonable. 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.

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. Generally, a petroleum products or crude oil pipeline will utilize the FERC’s indexing methodology to adjust its rates, as indexing serves as the default rate-adjustment mechanism. Cost-of-service based rates, market-based rates and settlement rates are alternatives to the default indexing mechanism and may be used in certain specified circumstances to change rates.

CPUC Rate Regulation

The intrastate common carrier operations of our refined products 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 refined products operations’ business. Tariff rates with respect to intrastate pipeline service in California are subject to challenge by protest by interested parties or by independent action of 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.

State and Local Regulation

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

Marine Operations

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

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

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

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

Derivatives Regulation

We use energy commodity derivative contracts as part of our strategy to hedge our exposure to energy commodity market risk and other external risks in the ordinary course of business. The derivative contracts that we use include exchange-traded and OTC commodity financial instruments such as futures and options contracts, fixed price swaps and basis swaps. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires the U.S. Commodity Futures Trading Commission and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the OTC derivatives market and entities that participate in that market including broad aggregate position limits for OTC swaps and futures and options traded on regulated exchanges. These rules include exemptions for hedging positions.

Environmental Matters and Safety Regulation

Our business operations are subject to extensive federal, state and local laws and regulations relating to environmental protection and human health and safety. For example, if a leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines, storage or other facilities, we may experience significant operational disruptions, and we may have to pay a significant amount to clean up the leak, release or spill, pay government penalties, address natural resource damages, compensate for human exposure or property damage, install pollution control equipment or a combination of these and other measures. Furthermore, new projects may require permits, approvals and environmental analyses under federal and state laws, including the Clean Water Act, the Clean Air Act, the National Environmental Policy Act and the Endangered Species Act, as well as Executive Orders focused on environmental justice considerations. The resulting costs and liabilities could be material to us, and increasing compliance costs under federal and state environmental laws for both new and existing facilities could require us to make significant capital expenditures. In general, the cost to comply with environmental regulations is increasing. These costs have the potential to limit the return on capital projects and the number of capital projects that are economically viable. Please read Item 1A. “Risk Factors—Risks Related to Regulation.”

In accordance with GAAP, we record liabilities for environmental matters when it is probable that obligations have been incurred and the amounts can be reasonably estimated. For information related to pending environmental matters, including our accruals of environmental reserves, see Note 18 “Litigation and Environmental” to our consolidated financial statements.

Hazardous and Non-Hazardous Waste

We generate both hazardous and non-hazardous wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. RCRA establishes standards for the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes.

Superfund

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

Clean Air Act

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

Clean Water Act

Our operations can result in the discharge of pollutants. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and controls regarding the discharge of fills

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

EPA Revisions to National Ambient Air Quality Standards

As required by the Clean Air Act, the EPA establishes National Ambient Air Quality Standards (NAAQS) setting acceptable levels of common pollutants such as ozone, particulate matter and sulfur dioxide. States then are required to adopt State Implementation Plans (SIPs) ensuring their air quality meets the applicable NAAQS. The EPA reviews these SIPs to ensure they comply with the NAAQS and other provisions of the Clean Air Act, including the Good Neighbor provision. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Expenditures—Impact of Regulation,” and Note 18 “Litigation and Environmental—Environmental Matters—Challenge to Federal “Good Neighbor Plan,” to our consolidated financial statements.

For ground level ozone, the EPA published a rule in October 2015 that lowered NAAQS from 75 parts per billion (ppb) to a more stringent 70 ppb standard. This change triggered a process under which the EPA designated the areas of the country in or out of compliance with the 2015 standards. In December 2020, the EPA completed a review of the ozone NAAQS and published a rule retaining the 2015 standards.

State rules implementing the NAAQS, including those existing or proposed in Colorado and New Mexico, require the installation of more stringent air pollution controls on newly installed equipment and possibly require the retrofitting of existing KMI facilities with air pollution controls. These rules will have financial impacts to our Natural Gas Pipelines business segment. Future state or federal rules relating to the EPA’s establishment of NAAQS for ozone or other criteria air pollutants could have financial impacts on multiple business units.

Climate Change

Due to concern over climate change, numerous proposals to monitor and limit emissions of GHGs have been made and are likely to continue to be made at the federal, state and local levels of government. Methane, a primary component of natural gas, and CO, which is naturally occurring and also a byproduct of burning natural gas, are examples of GHGs. Various laws and regulations exist or are under development to regulate the emission of such GHGs, including the EPA programs requiring the reduction, monitoring, and reporting of GHG emissions levels and state actions to develop statewide or regional programs. The U.S. Congress has in the past considered legislation to reduce emissions of GHGs.

Beginning in 2009, the EPA published several findings and rulemakings under the Clean Air Act requiring the permitting and reporting of certain GHGs, including CO and methane. Certain of our facilities are subject to these requirements. Operational or physical changes to existing facilities could require those facilities to comply with these requirements. In addition, recent EPA regulatory changes require many existing oil and natural gas facilities to reduce GHG emissions, and PHMSA has proposed regulations requiring expansive leak detection and repair requirements applicable to natural gas facilities. See Item 1A. “Risk Factors—Risks Related to Regulation—New laws, policies, regulations, rulemaking and oversight, as well as changes to those currently in effect, could adversely impact our earnings, cash flows and operations.” and “ —Increased regulatory requirements relating to the safety and integrity of our pipelines may require us to incur significant capital and operating expense outlays to comply.”

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

Because our operations, including the compressor stations and processing plants, emit various types of GHGs, primarily methane and CO, such new legislation or regulation could increase the costs related to operating and maintaining our facilities. Depending on the particular law, regulation or program, we or our subsidiaries may be required to incur significant additional operating or capital costs to install new monitoring equipment or emission controls on the facilities, acquire and surrender allowances for the GHG emissions, replace certain GHG-emitting devices or technologies, pay taxes related to the GHG

emissions and administer and manage a more comprehensive GHG emissions program. While we may be able to include some or all of such increased costs in the rates charged by our or our subsidiaries’ pipelines, recovery of costs is uncertain in all cases and may depend on events beyond our control, including the outcome of future rate proceedings before the FERC or other regulatory bodies, and the provisions of any final legislation or other regulations.

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

Pipeline Safety Regulation

We are subject to pipeline safety regulations issued by PHMSA as well as any states that are certified by PHMSA to regulate pipeline safety for intrastate pipelines in their respective states. These regulations apply to pipelines and pipeline facilities, including associated underground natural gas storage, terminals and LNG facilities. PHMSA regulations in particular, require us to develop and maintain pipeline integrity management programs to evaluate our pipelines and take additional measures to protect pipeline segments located in what are referred to as High Consequence Areas (HCAs) for both gas and liquid pipelines, where a release could potentially have the most adverse consequences. Additionally, PHMSA recently issued requirements that require us to conduct additional assessments to identify risks in what are referred to as Moderate Consequence Areas (MCAs) for gas pipelines.

Since 2019, PHMSA has implemented several rules that impose additional pipeline safety requirements including without limitation: (i) expanding certain integrity management program requirements outside of HCAs (with some exceptions) for both gas and hazardous liquid pipelines; (ii) expanding the application of integrity management requirements relevant to hazardous liquid pipelines to include additional areas, including certain coastal waters; (iii) requiring reconfirmation of the maximum allowable operating pressure (MAOP) by 2035 and material verification on certain gas pipelines; (iv) requiring installation of remote control or automatic shut-off valves (or alternative equivalent technology) on certain newly constructed or replaced gas and liquid pipelines; (v) increasing requirements for corrosion control for gas pipelines; (vi) providing additional prescriptive requirements that increase conservatism and specificity on the evaluation of discovered anomalies and their associated repair criteria for gas pipelines; and (vi) expanding certain regulations to previously unregulated gas gathering assets.

Employee Health and Safety Regulations

We are subject to the requirements of federal and state agencies, including, where appropriate, the Occupational Safety and Health Administration (OSHA), that address, among other things, employee health and safety.

Security Regulations

High-Risk Facilities

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

Cybersecurity

In response to ongoing cybersecurity threats affecting the pipeline industry, the DHS’s Transportation Security Administration, or TSA, has issued a series of security directives setting forth specific elements that owners and operators of certain “critical” pipelines must include in their cybersecurity planning and their reporting of any incidents. These security directives require, among other things, that identified pipeline owners comply with mandatory reporting measures; designate a

cybersecurity coordinator; provide vulnerability assessments; ensure compliance with certain cybersecurity requirements; establish and implement a TSA-approved Cybersecurity Implementation Plan; develop and maintain a Cybersecurity Incident Response Plan (CIRP), which shall include individuals identified as active participants in CIRP exercises, and annually test at least two CIRP objectives; and establish a Cybersecurity Assessment Plan (CAP), and annually submit an updated CAP to TSA for review and approval, which shall include a schedule for assessing and auditing specific cybersecurity measures for effectiveness.

In addition, PHMSA requires reporting of certain events that involve a release from or the shutdown of a pipeline, including those that may be caused by a cyber-attack. On July 26, 2023, the SEC adopted new disclosure requirements regarding cybersecurity risk management, strategy, governance, and incidents. Please read Item 1C. “Cybersecurity.” Regulations are also under development to implement reporting requirements under the Cyber Incident Reporting for Critical Infrastructure Act of 2022 (CIRCIA), a law concerning the reporting of cyber incidents and ransomware payments that is expected to take effect in 2024.

Human Capital

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

We employed 10,891 full-time personnel at December 31, 2023, including approximately 891 full-time hourly personnel at certain terminals and pipelines covered by collective bargaining agreements that expire between 2024 and 2028. We consider relations with our employees to be good.

We value the safety of our workforce and integrate a culture of safety, emergency preparedness and environmental responsibility through our operations management system (OMS). Our OMS conforms to common industry standards and establishes a framework that helps us (i) provide employees and contractors with a safe work environment; (ii) comply with laws, rules, regulations, policies, and procedures; and (iii) identify opportunities to improve. Although our ultimate target is zero incidents, we also have three non-zero employee safety performance targets as follows:

Non-zero employee safety performance target						2023 Company-wide TRIR
Outperform the annual industry average total recordable incident rate (TRIR)						0.8
Outperform our own three-year TRIR average
Improve our company-wide employee TRIR from 1.0 in the baseline year 2019 to 0.7 by 2024

We seek to constantly improve our contractor TRIR performance through initiatives to address recent incident trends and new best practices.

The Nominating and Governance Committee (Nom/Gov Committee) of our Board is responsible for planning for succession in our senior management ranks, including our chief executive officer. Our chief executive officer reports to the Nom/Gov Committee annually, generally at the time of the regularly scheduled July Board meeting, regarding the succession plan and processes in place to identify talent within and outside the Company to succeed to senior management positions, development opportunities for potential successors, and the information developed during the then-current calendar year pursuant to those processes. As part of our annual succession planning process, we identify minority and female candidates to include in the plan for senior positions.

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

Our employees are an integral part of our success, and we value their career development. We support our employees’ ongoing career goals and development through several programs, including workforce training, tuition reimbursement,

leadership and other development programs. These programs help improve recruitment, development, and retention and help maximize our employees’ potential by providing an opportunity to gain skills they need to further enhance their careers.

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

Properties and Rights-of-Way

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

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

Available Information

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

KMI - Kinder Morgan, Inc.

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