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. AGenerally, a petroleum products or crude oil pipeline ~~must, as a general rule,~~will utilize the FERC’s indexing methodology to ~~change~~adjust its ~~rates.~~rates, as indexing serves as the default rate-adjustment mechanism. Cost-of-service ~~ratemaking,~~based rates, market-based rates and settlement rates are alternatives to the default indexing ~~approach~~mechanism 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’~~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 ~~West Coast Refined Products~~refined products operations’ business. Tariff rates with respect to intrastate pipeline service in California are subject to challenge by ~~complaint~~protest 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.

~~Mexico - Energy Regulatory Commission~~

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

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

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

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

~~Safety Regulation~~

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

During September 2019, PHMSA finalized rules to be effective July 1, 2020 to expand integrity management program requirements to hazardous liquids pipelines outside of HCAs (with some exceptions) and to make certain other changes to those program requirements, including data integration and emphasis on the use of in-line inspection technology. During October 2019, PHMSA finalized rules to require operators of natural gas pipelines to (i) expand integrity management program requirements outside of HCAs (with some exceptions), and (ii) reconfirm maximum allowable operating pressure (MAOP) on certain pipelines in populated areas including HCAs. The MAOP reconfirmations must be completed by 2035. Changes in technology such as advances of in-line inspection tools, identification of additional integrity threats and changes to PHMSA regulations can have a significant impact on costs to perform integrity assessments, testing and repairs. We will continue our pipeline integrity management programs to assess and maintain the integrity of our existing and future pipelines as required by PHMSA regulations. The costs to comply with integrity management program requirements are difficult to predict. Assessments performed as part of our program could result in significant capital and operating expenditures for upgrades and/or repairs deemed necessary to continue the safe and reliable operation of our pipelines. We expect to increase expenditures in the future to comply with these PHMSA regulations.

The Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 or “PIPES Act of 2016” requires PHMSA, among other regulators, to set minimum safety standards for underground natural gas storage facilities and allows states to set more stringent standards for intrastate pipelines. In compliance with the PIPES Act of 2016, we have implemented procedures for underground natural gas storage facilities.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which was signed into law in 2012, increased penalties for violations of safety laws and rules and may result in the imposition of more stringent regulations in the future. Regulations, changes to regulations or an increase in public expectations for pipeline safety may require additional reporting, the replacement of some of our pipeline segments, addition of monitoring equipment and more frequent inspection or testing of our pipeline facilities. Repair, remediation, and preventative or mitigating actions may require significant capital and operating expenditures.

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

~~We are also subject to the requirements of the Occupational Safety and Health Administration (OSHA) and other federal and state agencies that address employee health, including from infectious diseases such as COVID-19,~~ ~~and safety. In general,~~

we believe we are fulfilling the OSHA requirements and protecting the health and safety of our employees. Based on new or revised regulatory developments, we may be required to increase expenditures in the future to comply with higher industry and regulatory safety standards. However, there are no known new or revised regulations which will require a material increase in our expenditures.

State and Local Regulation

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

Marine Operations

The operation of tankers and marine equipment ~~create~~is subject to maritime obligations involving property, personnel and cargo under General Maritime ~~Law. These obligations create~~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. ~~Furthermore, from~~From time to time, legislation has been introduced unsuccessfully in the U.S. Congress to amend the Jones Act to ease or remove the requirement that vessels operating between U.S. ports be built and registered in the U.S. and owned and crewed by U.S. citizens. If the Jones Act were amended in such fashion, we could face competition from foreign-flagged vessels.

In addition, the U.S. Coast Guard and the American Bureau of Shipping maintain the most stringent regime of vessel inspection in the world, which tends to result in higher regulatory compliance costs for ~~U.S.-flag~~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.

~~Canadian Regulation~~

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

Derivatives Regulation

We use energy commodity derivative contracts as part of our strategy to hedge our exposure to energy commodity market risk and other external risks in the ordinary course of business. The derivative contracts that we use include exchange-traded and OTC commodity financial instruments such as futures and options contracts, fixed price swaps and basis swaps. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires the U.S. Commodity Futures Trading Commission ~~(CFTC)~~ and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the OTC derivatives market and entities that participate in that ~~market. In October 2020, the CFTC finalized one of the last remaining new rules pursuant to the Dodd-Frank Act that institutes~~market including broad ~~new~~ aggregate position limits for OTC swaps and futures and options traded on regulated exchanges. ~~As finalized, these~~

These rules include exemptions for hedging positions, and while we cannot yet predict the full impact of the rules when they take effect in 2022 and 2023, we do not expect that the rules will have a material adverse effect on our business. We cannot predict how new leadership at the CFTC as a result of the change in the U.S. presidential administration may impact us.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 ~~an accidental~~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 ~~for~~ government penalties, address natural resource damages, compensate for human exposure or property damage, install ~~costly~~ pollution control equipment or a combination of these and other measures. Furthermore, new projects may require permits, approvals and environmental ~~analysis~~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.~~Act, as well as Executive Orders focused on environmental justice considerations. The resulting costs and liabilities could ~~materially~~be material to us, and ~~negatively affect our business, financial condition, results of operations and cash flows. In addition, emission controls required~~increasing compliance costs under federal and state environmental laws for both new and existing facilities could require us to make significant capital ~~expenditures at our facilities.~~expenditures. In general, the cost ofto comply with environmental ~~control at facilities~~regulations is ~~increasing and limiting~~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. “

~~Environmental and human health and safety laws and regulations are subject~~Risk Factors—Risks Related to change. The long term trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, wildlife, natural resources and human health. There can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows.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. This policy applies to assets or businesses currently owned or previously disposed. We have accrued liabilities for estimable and probable environmental remediation obligations at various sites, including multi-party sites where the EPA or a similar state agency has identified us as one of the potentially responsible parties. The involvement of other financially responsible companies at these multi-party sites could increase or mitigate our actual joint and several liability exposures.

We believe that the ultimate resolution of these environmental matters will not have a material adverse effect on our business, financial position, results of operations or cash flows. However, it is possible that our ultimate liability with respect to these environmental matters could exceed the amounts accrued in an amount that could be material to our business, financial position, results of operations or cash flows in any particular reporting period. We have accrued an environmental reserve in the amount of $250 million as of December 31, 2020. For ~~additional~~ information related to pending environmental matters, including our accruals of environmental reserves, see Note 18 “~~Litigation~~“Litigation and ~~Environmental~~”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. ~~From time to time, the EPA, as well as other U.S. federal and state regulators, consider the adoption of stricter disposal~~RCRA establishes standards for ~~non‑hazardous waste. Furthermore, it is possible that some~~the generation, treatment, storage, transport, and disposal of solid wastes, that are currently classified as non-hazardous, which could include wastes currently generated during our pipeline or liquids or bulk terminal operations or wastes from oil and gas facilities that are currently exempt as exploration and production waste, may in the future be designated asincluding hazardous wastes. Hazardous wastes are subject to more rigorous and costly handling and disposal requirements than non-hazardous wastes. Such changes in the regulations may result in additional capital expenditures or operating expenses for us.

Superfund

the costs they incur, ~~in addition to~~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~~“hazardous substance,” in the course of our ordinary operations, we have and will generate materials that may fall within ~~the definition of “hazardous substance.” By operation of law, if~~such definition. If we are determined to be a potentially responsible person by operation of law under CERCLA, we may be responsible ~~under CERCLA~~ for all or part of the costs required to ~~clean up~~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 ~~Ozone~~ National Ambient Air Quality ~~Standard (NAAQS)~~Standards

As required by the Clean Air Act, the EPA establishes National Ambient Air Quality Standards (NAAQS) ~~for how much pollution is permissible,~~setting acceptable levels of common pollutants such as ozone, particulate matter and ~~the states~~sulfur dioxide. States then ~~have~~are required to adopt ~~rules so~~State Implementation Plans (SIPs) ensuring their air quality meets the applicable NAAQS. ~~In October 2015,~~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 ~~lowering the ground level ozone~~in October 2015 that lowered NAAQS from 75 ~~ppb~~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 ~~new~~2015 standards. In December 2020, the EPA completed a review of the ozone NAAQS ~~standard. Now, certain states will have to adopt more stringent air quality regulations to meet~~and published a rule retaining the ~~new~~2015 standards.

State rules implementing the NAAQS, ~~standard. These new state rules, which are expected~~including those existing or proposed in ~~2020 or 2021, will likely~~Colorado and New Mexico, require the installation of more stringent air pollution controls on ~~newly-installed~~newly installed equipment and possibly require the retrofitting of existing KMI facilities with air pollution controls. ~~Given the nationwide implications of the new rule, it is expected that it~~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 ~~each of our~~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 CO2, which is naturally occurring and also a byproduct of ~~the~~ burning of natural gas, are examples of GHGs. Various laws and regulations exist or are under development to regulate the emission of such GHGs, including the EPA programs ~~to report~~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. Climate-related laws and regulation could lead to reduced demand for hydrocarbon products that are deemed to contribute to GHGs, which in turn could adversely affect demand for our products and services.

Beginning in ~~December~~ 2009, the EPA published several findings and rulemakings under the Clean Air Act requiring the permitting and reporting of certain GHGs, including CO2 and methane. ~~Our~~Certain of our facilities are subject to these requirements. Operational ~~and/~~or ~~regulatory~~physical changes to existing facilities could require ~~additional~~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 ~~for reducing, reporting~~applicable to natural gas facilities. See Item 1A. “Risk Factors—Risks Related to Regulation—New laws, policies, regulations, rulemaking and ~~permitting GHG emissions.~~oversight, as well as changes to those currently in effect, could adversely impact our earnings, cash flows and operations.

” and “

~~On October 23, 2015,~~—Increased regulatory requirements relating to the ~~EPA published as a final rule the Clean Power Plan, which sets interim~~safety and ~~final CO~~2 ~~emission performance rates for power generating units that are fueled by coal, oil or natural gas. The rule has been the focus~~integrity of ~~legislative discussion in the U.S. Congress~~our pipelines may require us to incur significant capital and ~~litigation in federal court. On February 10, 2016, the U.S. Supreme Court stayed the final rule, effectively suspending the duty~~operating expense outlays to comply with the rule until certain legal challenges are resolved. In October 2017, the EPA proposed to repeal the Clean Power Plan. In June 2019, the EPA replaced the Clean Power Plan with the Affordable Clean Energy rule. In January 2021, the U.S. Court of Appeals for the District of Columbia Circuit vacated the Affordable Clean Energy rule and remanded the question to the EPA to consider a new regulatory framework to replace the Affordable Clean Energy rule thereby allowing the incoming administration to implement standards for emissions from the power sector. While we do not operate power plants, it remains unclear what effect new standards might have on the anticipated demand for natural gas, including natural gas that we gather, process, store and transport.

.”

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, ~~primarily~~such as through ~~the planned development~~establishment of ~~emission inventories~~GHG reduction targets or regional GHG ~~“cap and trade”~~“cap-and-trade” programs. ~~Although many of the state-level initiatives have to date been focused on large sources of GHG emissions, such as electric power plants, it~~It is possible that sources such as our gas-fueled compressors and processing plants could become subject to ~~related~~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. ~~Some of the states have implemented regulations that~~Compliance with state rules could require additional ~~reductions monitoring~~expenditures, above and ~~reporting of methane emissions. Depending on the state programs pending implementation, we could be required~~beyond those spent to ~~further reduce emissions, conduct additional monitoring, do additional emissions reporting, install additional emission controls and/or purchase~~comply with EPA GHG rules for new and ~~surrender emission allowances.~~existing sources.

Because our operations, including the compressor stations and processing plants, emit various types of GHGs, primarily methane and CO2, such new legislation or regulation could increase the costs related to operating and maintaining ~~the~~our facilities. Depending on the particular law, regulation or program, we or our subsidiaries ~~could~~may be required to incur significant additional operating or capital ~~expenditures for installing~~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. ~~We are not able at this time to estimate such increased costs; however, as is the case with similarly situated companies in our industry, they could be significant to us.~~ While we may be able to include some or all of such increased costs in the rates charged by our or our subsidiaries’ pipelines, recovery of costs is uncertain in all cases and may depend on events beyond ~~their~~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. ~~Any of the foregoing could have an adverse effect on our business, financial position, results of operations and prospects.~~

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

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

~~Department~~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 ~~Homeland~~ 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 ~~required~~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 ~~10,524~~10,891 full-time personnel at December 31, ~~2020,~~2023, including approximately ~~929~~891 full-time hourly personnel at certain terminals and pipelines covered by collective bargaining agreements that expire between ~~2021~~2024 and ~~2024.~~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:~~us (i) provide employees and contractors with a safe work environment; (ii) comply with laws, rules, regulations, policies, and procedures; and (iii) identify opportunities to improve. Although our ultimate target is zero incidents, we also have three non-zero employee safety performance targets. The first is to outperform the annual industry average total recordable incident rate (TRIR). The second is to outperform our own three-year TRIR average. The third is a longer-term target to improve our company-wide employee TRIR from 1.0 in the baseline year 2019 to 0.7 by 2024. 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.

~~Our board~~The Nominating and Governance Committee (Nom/Gov Committee) of ~~directors’ nominating and governance committee~~our Board is responsible for planning for succession in ~~the~~our senior management ranks, ~~of the Company,~~ including ~~the office of~~our chief executive officer. ~~The~~Our chief executive officer ~~shall report~~reports to the Nom/Gov Committee annually, generally at the time of the regularly scheduled ~~third quarter board of directors~~July Board meeting, ~~in each year,~~ 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 ~~current~~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 ~~action~~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 prohibit discrimination or harassment against any employee or applicant on the basis of race/ethnicity, sex, or other protected categories listed within our code of business conduct and ethics.~~ We are committed to a harassment free workplace, supported with online and face-to-face workplace harassment and discrimination prevention training for our employees. ~~In 2019, renewal training on~~Employees and supervisors review our harassment and discrimination prevention policy was provided to our supervisors and employees. This renewal training highlighted supervisor’s and employee’s responsibilities for maintaining a workplace free of harassment. We continued to provide this training to newly hired or promoted supervisors and employees in 2020.

Asevery two years as part of the 2020 annual succession planning efforts, we focused on identifying minority and female candidates for senior positions. Management reviewed its succession plan, including a discussion on development opportunities for potential successors, with the nominating and governance committee of our ~~board of directors at its meeting in July 2020.~~required training.

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

leadership and other development programs. These programs help improve recruitment, development, and ~~retention. We support our employees’ ongoing career goals~~retention and ~~development through several programs. These programs~~ help maximize our employees’ potential ~~and give them the~~by providing an opportunity to gain skills they need to further enhance their careers.

Our compensation program is linked to ~~long~~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.

~~Refer to “COVID-19” included in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for information on actions taken by the Company in response to the COVID-19 pandemic.~~

Properties and ~~Rights of Way~~Rights-of-Way

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

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

~~Financial Information about Geographic Areas~~

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

Item 1A. Risk Factors.

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

Risks Related to ~~Operating~~ our Business

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

The COVID-19 pandemic and the efforts to control it have resulted in a significant decline in global economic activity and significant disruption of global supply chains. Governments around the world have implemented stringent measures to help reduce the spread of the virus, including stay-at-home orders, business and school closures, travel restrictions and other measures. The resulting downturn in economic activity has negatively impacted global demand and prices for crude oil, natural gas, NGL, refined petroleum products, CO2~~, steel, chemicals and other products that we handle in our pipelines, terminals, shipping vessels and other facilities. See Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—General—COVID-19.” Continuing uncertainty regarding the global impact of COVID-19 is likely to result in continued weakness in demand and prices for the products on which our business depends.~~

As the pandemic and responses to it continue, we may experience further disruptions to commodities markets, supply chains and the health, availability and efficiency of our workforce, which could adversely affect our ability to conduct our business and operations and limit our ability to execute on our business plan. In addition, measures taken by regulatory authorities attempting to mitigate the economic consequences of COVID-19 may not be effective or may have unintended harmful consequences. There are still too many variables and uncertainties regarding COVID-19 — including the pace and efficacy of vaccination efforts, the duration and severity of possible resurgences and the duration and extent of travel restrictions and business closures imposed in affected countries — to reasonably predict the potential impact of COVID-19 on our business and operations. COVID-19 may materially adversely affect our business, results of operations, financial condition and cash flows. Even after the COVID-19 pandemic has subsided, we may experience materially adverse impacts to our business due to the global economic recession that is likely to result from the measures taken to combat the virus. Further, adverse impacts from the pandemic may have the effect of heightening many of the other risks we face.

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

Our pipelines, terminals and other assets and facilities, including the availability of expansion opportunities, depend in part on continued production of natural gas, crude oil and other products in the geographic areas that they serve. Without additions to crude oil and gas reserves, production will decline over time as reserves are depleted, and production costs may rise. Producers in areas served by us may not be successful in exploring for and developing additional reserves or their costs of doing so may become uneconomic. Commodity prices and tax incentives may not remain at levels that encourage producers to explore for and develop additional reserves, produce existing marginal reserves or renew transportation contracts as they expire. Our business also depends in part on the levels of demand for natural gas, crude oil, NGL, refined petroleum products, CO2, steel, chemicals and other products in the geographic areas to which our pipelines, terminals, shipping vessels and other facilities deliver or provide service, and the ability and willingness of our shippers and other customers to supply such demand. ~~For example, without additions to~~

Decreases in the supply of or demand for natural gas, crude oil and ~~gas reserves, production will decline over time as reserves are depleted, and production costs may rise. Producers may reduce or shut down production during times~~other products could adversely impact the utilization of ~~lower product prices or higher production costs to the extent they become uneconomic. Producers in areas served by us may not be successful in exploring for and developing additional reserves, and~~ our ~~pipelines and related facilities may not be able to maintain existing volumes of throughput.~~assets.

Commodity prices and tax incentives may not remain at levels that encourage producers to explore for and develop additional reserves, produce existing marginal reserves or renew transportation contractsEconomic disruptions, such as ~~they expire. Additionally, demand for such products can decline due to situations over~~those which ~~we have no control, such as~~occurred during the COVID-19 pandemic, ~~and various measures that federal, state and local authorities have implemented in response to the virus~~ or ~~its economic consequences. See “—The COVID-19 pandemic has adversely affected, and could continue to adversely affect, our business.”~~

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

~~These factors could result in not only increased costs for producers of hydrocarbons but also an overall decrease in the demand for hydrocarbons.~~ Each of the foregoing supply and demand issues could negatively impact our business directly, as well as our shippers and other customers, which in turn could negatively impact our prospects for new contracts for transportation, terminaling or other midstream services, or renewals of existing contracts or the ability of our customers and shippers to honor their contractual commitments. Furthermore, such unfavorable conditions may compound the adverse effects of larger disruptions, such as COVID-19. See “—“—Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the productsor services we provide or otherwise fulfill their obligations to ~~us”~~ us.” below.

We cannot predict the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation and/or tax incentives or technological advances in fuel economy and energy generation devices, all of which could reduce the production of and/or demand for the products we handle. In addition, irrespective of supply of or demand for products we handle, implementation of new regulations or changes to existing regulations affecting the energy industry could have a material adverse effect on us.

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

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

extent that companies pursuing development of carbon capture and sequestration technology are successful, they could compete with us for customers who purchase CO2 for use in enhanced oil recovery operations.

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

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

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

In 2020, the impact of COVID-19, combined with a dispute regarding production levels among OPEC+ countries, caused crude oil prices to reach historic lows. By March 2020, crude oil was priced at less than $25 per barrel, the lowest price since April 1999. Producers in the U.S. and globally did not reduce crude oil production at a rate sufficient to match the dramatic decline in economic activity that accelerated in March and April 2020, resulting in an oversupply of crude oil that caused the per-barrel price to fall below zero in April 2020. While global oil demand has improved from the low levels experienced during these months last year and OPEC+ agreed on production cuts in April 2020, there is no assurance that demand will not decline to these levels again, that the OPEC+ agreement will continue to be observed by its parties or that the agreed production cuts will be sufficient to offset continuing demand weakness. Downward pressure onIf commodity ~~prices could continue for the foreseeable future. If~~ prices fall substantially or remain low for a sustained period and we are not sufficiently protected through hedging arrangements, we may be unable to realize a profit from these businesses and would operate at a loss.

Sharp declines in the prices of crude oil, NGL or natural gas, ~~(such as we experienced in the first half of 2020)~~ or a prolonged unfavorable price environment, may result in a commensurate reduction in our revenues, income and cash flows from our businesses that produce, process, or purchase and sell crude oil, NGL, or natural gas, and could have a material adverse effect on the carrying value (which includes assigned goodwill) of our CO2 business segment’s proved reserves, certain assets in certain midstream businesses within our Natural Gas Pipelines business segment, and certain assets within our Products Pipelines business segment. For example, following the commodity price declines we experienced due to COVID-19 during the first half of 2020, we recorded a combined ~~$1.950~~$1.95 billion of non-cash impairments associated with our Natural Gas Pipelines Non-Regulated and CO2 reporting units, primarily for impairments of goodwill and assets owned in these businesses. ~~See Note 3 “Impairments and Losses and Gains on Divestitures” and Note 8 “Goodwill” to our consolidated financial statements for more information.~~

In recent decades, there have been periods worldwide of both overproduction and underproduction of hydrocarbons, and periods of both increased and relaxed energy conservation efforts. Such conditions have resulted in periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis. These periods have been followed by periods of short supply of, and increased demand for, crude oil and natural gas. The cycles of excess or short supply of crude oil or natural gas have placed pressures on prices and resulted in dramatic price fluctuations even during relatively short periods of seasonal market demand. These fluctuations impact the accuracy of assumptions used in our budgeting process. For more information about our energy and commodity market risk, see Item 7A7A. “Quantitative and Qualitative Disclosures About Market Risk.”

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

terminals and hubs; spills associated with ~~the~~ loading and unloading of harmful substances at rail facilities; adverse sea conditions (including storms and rising sea levels) and releases or spills from our shipping vessels or vessels loaded at our marine terminals; operator error; labor disputes/work stoppages; disputes with interconnected facilities and carriers; operational disruptions or apportionment on third-party systems or refineries on which our assets depend; and catastrophic events or natural disasters such as fires, floods, explosions, earthquakes, acts of terrorists and saboteurs, cyber security breaches, and other similar events, many of which are beyond our control. Additional risks to our vessels include capsizing, grounding and navigation errors.

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

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

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

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

our operating results and cash flow. See ““—The volatility of crude oil, NGL and natural gas prices could adversely affect our CO2 ~~business segment and businesses within our Natural Gas Pipelines and Products Pipelines business segments.~~business.”

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

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

We are exposed to the risk of loss in the event of nonperformance by our customers or other counterparties, such as hedging counterparties, joint venture partners and suppliers. The global economic slowdown caused by COVID-19, and the coinciding extreme drop in crude oil prices, which was exacerbated by the effects of the pandemic, significantly impacted the financial condition of many companies, particularly exploration and production companies, including some of our customers or counterparties. Many of our counterparties finance their activities through cash flow from operations or debt or equity financing, and some of them may be highly leveraged and ~~may not be able~~unable to access additional capital to sustain their operations in the future. Our counterparties are subject to their own operating, market, financial and regulatory risks, and some have experienced, are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. Crude oil, NGL and natural gas prices were all lower on average in 2020 compared to 2019. Further deterioration in crude oil prices, or a continuation of the existing low natural gas or NGL price environment, would likely cause severe financial distress to some of our customers with direct commodity price exposure and may result in additional customer bankruptcies. Further, the security ~~that is permitted~~we are able to ~~be obtained~~obtain from such customers may be limited, including by FERC regulation. While certain of our customers are subsidiaries of an entity that has an investment grade credit rating, in many cases the parent entity has not guaranteed the obligations of the subsidiary and, therefore, the parent’s credit ratings may have no bearing on such customers’ ability to pay us for the services we provide or otherwise fulfill their obligations to us. ~~See Note 2 “Summary of Significant Accounting Policies—Allowance for Credit Losses” in our consolidated financial statements.~~

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

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

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

Our business, operations or financial condition generally may be negatively impacted as a result of negative public ~~opinion.~~opinion towards our industry sector, the products we handle, or us specifically. Public opinion may be influenced by negative portrayals of the industry in which we operate as well as opposition to development projects. In addition, ~~market~~ events specific to us could result in the deterioration of our reputation with key stakeholders. Potential impacts of negative public opinion or reputational issues may include delays or stoppages in expansion projects, legal or regulatory actions or challenges, blockades, increased regulatory oversight, reduced support from regulatory authorities, challenges to regulatory approvals, difficulty securing financing for and cost overruns affecting expansion projects and the degradation of our business generally.

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

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

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

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

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

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

We engage in hedging arrangements to reduce our direct exposure to fluctuations in the prices of crude oil, natural gas and NGL, including differentials between regional markets. These hedging arrangements expose us to risk of financial loss in some circumstances, including when production is less than expected, when the counterparty to the hedging contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the hedging

agreement and the actual price received. In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in prices for crude oil, natural gas and NGL. Furthermore, our hedging arrangements cannot hedge against any decrease in the volumes of products we handle. See “—Our businesses are dependent on the supply of and demand for the products ~~that~~ we handle.”

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

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

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

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

~~While~~In accordance with government mandates, we have implemented and maintain a cybersecurity ~~program~~ program—both internal and incorporating industry expertise—designed to protect our IT, OT and data systems from ~~such~~ attacks, however, we can provide no assurance that our cybersecurity program will be completely effective. In compliance with state and local stay-at-home orders issued in connection with COVID-19, a number of our employees have transitioned to working from home. As a result, more of our employees are working from locations where our cybersecurity program may be less effective and IT security may be less robust. We have experienced ~~an increase~~increases in the number of attempts by external parties to access our networks or our company data without authorization. While we have taken additional steps to secure our networks and systems to specifically respond to new and elevated risks associated with remote work, we may nevertheless be more vulnerable to a successful cyber-attack or information security incident when significant numbers of our employees are working remotely. The risk of a disruption or breach of our operational systems, or the compromise of the data processed in connection with our operations, ~~through an act~~has increased as attempted attacks, including acts of terrorism or cyber sabotage, ~~event has increased as attempted attacks~~ have advanced in sophistication and number around the world.

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

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

The U.S. government has issued public warnings ~~that indicate~~indicating that pipelines and other infrastructure assets might be specific targets of terrorist organizations or “cyber sabotage” events. For example, in ~~2018,~~May 2021, a ~~cyber~~ransomware attack on a ~~shared data network~~major U.S. refined products pipeline forced ~~four U.S. natural gas pipeline operators~~the operator to temporarily shut down ~~computer communications with their customers.~~the pipeline, resulting in disruption of fuel supplies along the East Coast. Potential targets include our pipeline systems, terminals, processing plants, databases or operating systems. The occurrence of an attack could cause a substantial decrease in revenues and cash flows, increased costs to respond

or other financial loss, significant reporting requirements, damage to our reputation, increased regulation or litigation or inaccurate information reported from our operations. In the event of such an incident, we may need to retain cybersecurity experts to assist us in stopping, diagnosing, and recovering from the attack. There is no assurance that adequate cyber sabotage and terrorism insurance will be available at rates we believe are reasonable in the near future. ~~These developments~~The potential for an attack may subject our operations to increased risks ~~as well as increased~~and costs, and, depending on their ultimate magnitude, ~~could~~ have a material adverse effect on our business, results of operations, ~~and~~ financial condition and/or ~~could harm our~~ business reputation.

Development of new technologies could create additional risk, or we may not have sufficient resources to manage our technology.

Custom or new technology (including potential generative artificial intelligence) that is heavily relied upon by us or our counterparties may not be maintained and updated appropriately due to resource restraints, or other factors, which could cause technology failures or give rise to additional operational or security risks. Generative artificial intelligence or other new technology could also create additional regulatory scrutiny and generate uncertainty around intellectual property ownership and/or licensing or use. Technology (including artificial intelligence) is also subject to intentional misuse (by criminals, terrorists or other bad actors). Technology failures or incidents of misuse could result in significant adverse effects on our operations, results of operations, financial condition and cash flows.

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

Some of our pipelines, terminals and other assets are located in, and our shipping vessels operate in, areas that are susceptible to hurricanes, earthquakes, flooding and other natural disasters or could be impacted by subsidence and coastal erosion. These natural disasters ~~and phenomena~~ could potentially damage or destroy our assets and disrupt the supply of the products we transport. Many climate models indicate that global warming is likely to result in rising sea levels, increased ~~intensity~~frequency and severity of weather events such as winter storms, hurricanes and ~~increased frequency of~~tropical storms, extreme precipitation and flooding. These climate-related changes could result in damage to our physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone and rain-susceptible regions. ~~In addition, we may experience increased insurance premiums and deductibles, or a decrease in available coverage, for our assets in areas subject to severe weather.~~ Natural disasters ~~and phenomena~~ can similarly affect the facilities of our customers. ~~In either case, losses could exceed our insurance coverage~~The timing, severity and ~~our business, financial condition~~location of these climate change impacts are not known with certainty, and ~~results of operations could be adversely affected, perhaps materially. See Items 1 and 2 “Business and Properties—Narrative Description of Business—Environmental Matters~~.”these impacts are expected to manifest themselves over varying time horizons.

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

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

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

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

We regularly undertake ~~major~~ construction projects to expand our existing assets and to construct new assets. New growth projects generally will be subject to, among other things, the receipt of regulatory approvals, feasibility and cost analyses, funding availability and industry, market and demand ~~conditions.~~ conditions, and environmental justice considerations. A variety of factors outside of our control, such as difficulties in obtaining rights-of-way and permits or other regulatory approvals, have caused, and may continue to cause, delays in or cancellations of our construction projects. Regulatory authorities may modify their permitting policies in ways that disadvantage our construction projects, such as the FERC’s ongoing evaluation of its process

for reviewing and approving applications for construction of natural gas infrastructure. Federal regulators may also expand existing regulatory requirements, such as PHMSA’s recent expansion of gas gathering pipeline regulation and PHMSA’s consideration of regulating the transportation of gaseous CO2. Such factors can be exacerbated by public opposition to our projects. See “—We are subject to reputational risks and risks relating to public opinion.” Inclement weather, natural disasters and delays in performance by third-party contractors have also resulted in, and may continue to result in, increased costs or delays in construction. In addition, we may experience increasing costs for construction materials. Significant increases in costs of construction materials, cost overruns or delays, or our inability to obtain a required permit or right-of-way, could have a material adverse effect on our return on investment, results of operations and cash flows, and could result in project cancellations or limit our ability to pursue other growth opportunities.

If we pursue joint ventures with third parties, those parties may share approval rights over major decisions, and may act in their own interests. Their views may differ from our own or our views of the interests of the venture which could result in operational delays or impasses, which in turn could affect the

financial expectations of and our expected benefits from the venture. A variety of factors outside of our control, such as difficulties in obtaining permits and rights-of-way or other regulatory approvals, have caused, and may continue to cause, delays in or cancellations of our construction projects. Regulatory authorities may modify their permitting policies in ways that disadvantage our construction projects, such as the FERC’s consideration of changes to its Certificate Policy Statement. Such factors can be exacerbated by public opposition to our projects. See “—~~We are subject to reputational risks and risks relating to public opinion.~~” For example, changing public attitudes toward pipelines bearing fossil fuels may impede our ability to secure rights-of-way or governmental reviews and authorizations on a timely basis or at all. Inclement weather, natural disasters and delays in performance by third-party contractors have also resulted in, and may continue to result in, increased costs or delays in construction. Significant increases in costs of construction materials, cost overruns or delays, or our inability to obtain a required permit or right-of-way, could have a material adverse effect on our return on investment, results of operations and cash flows, and could result in project cancellations or limit our ability to pursue other growth opportunities.

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

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

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

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

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

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

The future success of our oil and gas development and production operations depends in part upon our ability to develop additional oil and gas reserves that are economically recoverable, which involves risks that may result in a total loss of investment.

financing for these activities in the future. Additionally, if we do not realize production volumes greater than, or equal to, our hedged volumes, we may suffer financial losses not offset by physical transactions.

Developing and operating oil and gas properties involves a high degree of business and financial risk that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Acquisition and development decisions related to oil and gas properties include subjective judgments and assumptions that, while they may be reasonable, are by their nature speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, the successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational and market-related factors may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable.

Our business requires the retention and recruitment of a skilled executive team and workforce, and difficulties recruiting and retaining executives and other key personnel could impair our ~~workforce could result in a failure~~ability to develop and implement our business ~~plans.~~strategy.

Our success depends in part on the performance of and our ability to attract, retain and effectively manage the succession of a skilled executive team. We depend on our executive officers to develop and execute our business strategy. If we are not successful in retaining our executive officers, or replacing them, our business, financial condition or results of operations ~~and management require~~could be adversely affected. We do not maintain key personnel insurance.

knowledge transfer; and/or (iii) recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased costs to retain and recruit these professionals.

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

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

Risks Related to Financing Our Business

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

As of December 31, ~~2020,~~2023, we had approximately ~~$33.4~~$31.9 billion of consolidated debt (excluding debt fair value adjustments). Additionally, we and substantially all of our wholly owned U.S. subsidiaries are parties to a cross guarantee agreement under which each party to the agreement unconditionally guarantees the indebtedness of each other party, which means that we are liable for the debt of each of such subsidiaries. This level of consolidated debt and the cross guarantee agreement could have important consequences, such as (i) limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements or potential growth, or for other purposes; (ii) increasing the cost of our future borrowings; (iii) limiting our ability to use operating cash flow in other areas of our business or to pay dividends because we must dedicate a substantial portion of these funds to make payments on our debt; (iv) placing us at a competitive disadvantage compared to competitors with less debt; and (v) increasing our vulnerability to adverse economic and industry conditions.

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

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

We may need to rely on external financing sources, including commercial borrowings and issuances of debt and equity securities, to fund acquisitions, capital projects or refinancing debt maturities. Adverse changes to the availability, terms and cost of capital, interest rates or our credit ratings (which would have a corresponding impact on the credit ratings of our

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

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

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

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

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

As of December 31, ~~2020,~~2023, approximately ~~$5.2~~$8.3 billion of our approximately ~~$33.4~~$31.9 billion of consolidated debt (excluding debt fair value adjustments) was subject to variable interest rates, either as short-term or long-term variable-rate debt obligations, or as long-term fixed-rate debt effectively converted to variable rates through the use of interest rate swaps. ~~Our~~In response to increasing inflation, the U.S. Federal Reserve raised interest ~~rate swaps as of December 31, 2020 include $2.5 billion of variable-to-fixed interest rate swap agreements~~rates in March 2022 for the first time in over three years and ~~$900 million of fixed-to-variable interest rate swap agreements that expire during 2021. Should~~raised rates many more times since. As interest rates increase, the amount of cash required to service variable-rate debt ~~would increase,~~also increases, as ~~would~~do our costs to refinance maturities of existing indebtedness, and our earnings and cash flows could be adversely affected.

For more information about our interest rate risk, see Item 7A7A. “Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”

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

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

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

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

Risks Related to Regulation

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

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

Our existing rates may also be challenged by ~~complaint.~~complaint or protest. Regulators and shippers on our pipelines have rights to challenge, and have challenged, the rates we charge under certain circumstances prescribed by applicable regulations. Some shippers on our pipelines have filed complaints with the regulators ~~that seek~~seeking prospective reductions in the tariff rates and, in the

case of a protest to a rate filing, seeking substantial refunds for alleged overcharges during the years in ~~question and prospective reductions in the tariff rates.~~question. Further, the FERC has initiated and may continue to initiate investigations to determine whether our interstate natural gas ~~pipelines have over-collected on~~pipeline rates ~~charged to shippers. We may face challenges, similar to~~

~~those described in~~are just and reasonable. Please read Note 18 “~~Litigation~~“Litigation and ~~Environmental~~”Environmental” to our consolidated financial statements for a description of material pending challenges to the rates we charge on our pipelines. We are unable to predict the extent to which these proceedings will result in lower transportation rates on our pipelines, and in the case of a protest, refunds for alleged overcharges. Any successful challenge to our rates could materially adversely affect our future earnings, cash flows and financial condition.

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

Our assets and operations are subject to extensive regulation and oversight by federal, state and local regulatory authorities. Legislative changes, as well as regulatory actions taken by these ~~agencies,~~authorities, have the potential to adversely affect our profitability. Additional regulatory burdens and uncertainties will be created if and to the extent that ~~the new U.S. presidential administration succeeds in enacting~~ more stringent energy and environmental ~~policies.~~and pipeline safety policies are enacted. Overall, we have seen an increase in the efforts of regulatory authorities to issue new regulations and guidance and to interpret existing laws and regulations in ways that promote the use of renewable energy sources and further protection of the environment, call upon companies to increase monitoring and emissions reduction efforts, and increase investigations and enforcement actions for potential violations of environmental laws. For example, ~~on January 27, 2021,~~in December 2023, the ~~President issued an executive order directing, among other matters,~~EPA finalized a rule containing standards of performance for GHG emissions, in the ~~reevaluation~~form of ~~the leasing program~~methane limitations, and volatile organic compound emissions for ~~federally managed lands and the “pause” of new~~crude oil and natural gas ~~leases~~sources, including the production, processing, and transmission and storage segments.

These types of rules and others that are currently proposed, if finalized, would affect our assets and operations indirectly, such as by increasing the costs associated with the production of natural gas and liquids that we transport, or directly, such as by increasing significantly our capital and operating costs associated with impacted equipment or subjecting us to the potential for regulatory penalties associated with the inability to comply with the rules in the timeframe allotted.

The EPA’s final rule known as the “Good Neighbor Plan” (the Plan) became effective on ~~public lands pending completion~~August 4, 2023, except in states that were awarded a stay of the ~~review.~~ EPA’s disapproval of their SIPs prior to the Plan’s effective date. Following the Plan’s effective date, several other states have been awarded similar stays. As a precursor to the Plan, the EPA disapproved 21 SIPs and found that two other states had failed to submit SIPs under the interstate transport (good neighbor) provisions of the Clean Air Act for the 2015 Ozone NAAQS. The EPA has since proposed to disapprove five additional state SIPs and apply the Plan or portions of the Plan to sources in those states, including one state that would affect our operations. The Plan imposes prescriptive emission standards for several sectors, including new and existing reciprocating internal combustion engines of a certain size used in pipeline transportation of natural gas. The Plan’s emission standards would require installation of more stringent air pollution controls on hundreds of existing internal combustion engines used by our Natural Gas Pipelines business segment. The Plan requires that all impacted engines meet the stringent emission limits by May 1, 2026 unless compliance schedule extensions are granted by the EPA, which would need to be supported by us and approved by the EPA on an engine-by-engine basis. If the Plan remains in effect in its current form (including full compliance by its May 1, 2026 compliance deadline, and assuming failure of all pending challenges to SIP disapprovals and no successful challenge to the Plan), we currently estimate that the Plan would have a material adverse impact on us. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Expenditures—Impact of Regulation.” Multiple legal challenges have been filed, including by us. See Note 18, “Litigation and Environmental—Environmental Matters—Challenge to Federal “Good Neighbor Plan,” to our consolidated financial statements. We are unable to predict whether any legal challenges will ultimately result in changes to the Plan or how those changes, if any, would impact us.

These and other initiatives of ~~the new presidential administration~~regulatory authorities may affect our assets and operations directly or indirectly, such as by preventing or delaying the exploration for and production of natural gas and liquids that we ~~transport.~~transport or expanding regulation of existing infrastructure or new sources that are not currently regulated.

Regulation affects almost every part of our ~~business~~business. In addition to environmental and ~~extends~~pipeline safety matters, we are subject to regulations extending to such matters as (i) federal, state and local taxation; (ii) rates (which include ~~tax,~~ reservation, commodity, surcharges, fuel and gas lost and unaccounted for), operating terms and conditions of service; (iii) the types of services we may offer to our customers; (iv) the contracts for service entered into with our customers; (v) the certification and construction of new facilities; (vi) the ~~costs of raw materials, such as steel, which may be affected by tariffs or otherwise; (vii) the~~ integrity, safety and security (including against cyber-attacks) of facilities and operations; ~~(viii) acquisitions or dispositions~~(vii) the acquisition of ~~assets or~~other businesses; ~~(ix)~~(viii) the acquisition, extension, disposition or abandonment of services or facilities; ~~(x)~~(ix) reporting and information posting requirements; ~~(xi)~~(x) the maintenance of accounts and records; and ~~(xii)~~(xi) relationships with affiliated companies involved in various aspects of the natural gas and energy businesses.

Should we fail to comply with any applicable statutes, rules, regulations, and orders of such regulatory authorities, we could be subject to substantial penalties and fines and potential loss of government contracts. ~~Furthermore, new laws, regulations or policy changes sometimes arise from unexpected sources.~~ New laws or regulations, ~~unexpected policy changes~~ or different interpretations of existing laws or regulations, including unexpected policy changes, applicable to our income, operations, assets or another aspect of our business could have a material adverse impact on our earnings, cash flow, financial condition and results of operations. For more information, see Items 1 and 22. “Business and Properties—Narrative Description of Business—Industry ~~Regulation~~Regulation..”

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

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

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

We own and/or operate numerous properties and equipment that have been used for many years in connection with our business ~~activities.~~activities and contain hydrocarbons or other hazardous substances. While we believe we have utilized operating, handling and disposal practices that were consistent with industry practices at the time, hydrocarbons or other hazardous substances may have been released at or from properties and equipment owned, operated or used by us or our predecessors, or at or from properties where our or our predecessors’ wastes

have been taken for disposal. In addition, many of these properties have been owned and/or operated by third parties whose management, handling and disposal of hydrocarbons or other hazardous substances were not under our control. These properties and ~~the~~any hazardous substances released and wastes disposed onat or from them may be subject to U.S. laws ~~in the U.S.~~ such as CERCLA, which impose joint and several liability without regard to fault or the legality of the original conduct. Under such laws, ~~and implementing regulations,~~ we could be required to remove ~~or remediate~~ previously disposed wastes, orremediate property contamination or both, including contamination caused by prior owners or operators. ~~Imposition of such liability schemes~~Furthermore, it is possible that some wastes that are currently classified as non-hazardous, which could ~~have a material adverse impact on~~include wastes currently generated during our pipeline or liquids or bulk terminal operations or wastes from oil and ~~financial position.~~gas facilities that are currently exempt as being exploration and production waste, may in the future be designated as hazardous wastes. Hazardous wastes are subject to more rigorous and costly handling and disposal requirements than non-hazardous wastes. Such changes in the regulations may result in additional capital expenditures or operating expenses for us.

~~Further, we cannot ensure that such existing~~Environmental and health and safety laws and regulations ~~will not~~are subject to change. The long-term trend in environmental regulation has been to place more restrictions and limitations on activities that may be ~~revised or that new laws or regulations will not be adopted or become applicable~~perceived to ~~us.~~affect the environment, wildlife, natural resources and human health, including without limitation, the exploration, development, storage and transportation of oil and gas. For example, the Federal Clean Air Act and other similar federal and state laws and regulations are subject to periodic review and amendment, which could result in more stringent emission control requirements obligating us to make significant capital expenditures at our facilities. Several state and federal agencies have also increased their daily and maximum penalty amounts in recent years. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. ~~Revised~~

New or ~~additional~~revised regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, as well as increased penalty amounts for inadvertent non-compliance, such as a pipeline leak, could have a material adverse effect on our business, financial position, results of operations and prospects. For more information, see Items 1 and 22. “Business and Properties—Narrative Description of Business—Environmental Matters.”

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.~~expenses.

We are subject to extensive laws and regulations related to pipeline safety and integrity at the federal and state ~~level.~~levels. There are, for example, ~~federal guidelines~~regulations issued by ~~the U.S. Department of Transportation (DOT)~~PHMSA for pipeline ~~companies~~operators in the areas of design, operations, ~~testing, education,~~maintenance, integrity management, qualification and training, emergency response, control room management, and ~~communication. The ultimate~~public awareness. We expect the costs of compliance with ~~the~~these regulations, including integrity management rules, ~~are difficult~~will continue to ~~predict.~~be substantial. The majority of compliance costs relate to pipeline integrity ~~testing~~management regulations, which include assessment and ~~repairs.~~repair requirements. Technological advances in in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipeline determined to be located in ~~“High Consequence Areas”~~HCAs or MCAs can have a significant impact on integrity testing and repair costs. We plan to continue our integrity ~~testing programs~~management program to assess and maintain the integrity of our existing and future pipelines as required by ~~the DOT~~PHMSA rules. ~~The~~Repairs or upgrades deemed necessary to address results of ~~these tests~~integrity assessments and other testing and/or ensure the continued safe and reliable operation of our pipelines and pipeline facilities could cause us to incur significant and unanticipated capital and operating expenditures. Such expenditures will vary depending on the number of repairs determined to be necessary as a result of integrity assessments and other testing. We also anticipate incurring substantial costs associated with PHMSA’s requirements for ~~repairs or upgrades deemed necessary~~reconfirming the maximum allowable operating pressure of certain gas pipelines. We expect to ~~ensure~~increase expenditures in the ~~continued safe and reliable operation of our pipelines.~~future to comply with PHMSA regulations.

Further, additional laws and regulations that may be enacted in the future or a new interpretation of existing laws and regulations could significantly increase our compliance expenditures. Pipeline safety regulations or changes to such regulations may require additional leak detection, reporting, the ~~amount~~replacement of ~~these~~certain pipeline segments, addition of monitoring equipment and more frequent monitoring, inspection or testing of our pipeline facilities. Repair, remediation, and preventative or mitigating actions may require significant capital and operating expenditures. Pipeline safety regulation has increased over time, including recent revised gas and hazardous liquid regulations that we must timely implement, and existing obligations may increase with new proposed rules that are currently under consideration. For example, PHMSA has issued a proposed rulemaking with expansive pipeline leak detection and repair requirements that is proposed to be applicable to gas pipelines, LNG facilities, and underground natural gas storage facilities. In addition, PHMSA is working on a number of proposed rulemakings that are now projected for publication in 2024, including those related to (i) updating regulations for LNG facilities; (ii) requirements for idled gas and liquid pipelines; (iii) revising requirements for transportation of CO2 in the liquid phase as well as establishing regulation of the transportation of gaseous CO2; and (iv) requirements for responding to changes in class location for gas pipelines. Congress is working on the reauthorization of the Pipeline Safety Act, which is expected to be enacted during 2024 and to further expand PHMSA’s current rulemaking agenda and/or statutory authority in certain areas. There can be no assurance as to the amount or timing of future expenditures for pipeline safety and integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not deemed by regulators to be fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects.

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

Various laws and regulations exist or are under development that seek to regulate the emission of GHGs such as methane and CO2, including the EPA programs to control GHG emissions, PHMSA’s existing and anticipated leak detection and repair requirements, and state actions to develop statewide or regional programs. Existing EPA regulations require us to report GHG emissions in the U.S. from sources such as our larger natural gas compressor stations, fractionated NGL, and production of naturally occurring CO2 (for example, from our McElmo Dome CO2 field), even when such production is not emitted to the atmosphere. Proposed approaches to further address GHG emissions include establishing GHG ~~“cap~~“cap-and-trade” programs, a fee on methane emissions from petroleum and ~~trade” programs,~~natural gas systems, increased efficiency standards, participation in international climate agreements, issuance of executive orders by the U.S. presidential administration and incentives or mandates for pollution reduction, use of renewable energy sources, or use of alternative fuels with lower carbon content. For more information about climate change regulation, see Items 1 and 22. “Business and Properties—Narrative Description of Business—Environmental Matters—Climate Change.”

Adoption of any such laws or regulations could increase our costs to operate and maintain our facilities, ~~and~~expand existing facilities or construct new facilities. We could ~~require us~~be required to install new emission controls on our facilities, acquire allowances for our GHG emissions, pay taxes related to our GHG emissions and administer and manage a GHG emissions program, and such increased costs could be significant. Recovery of such increased costs from our customers is uncertain in all cases and may depend on events beyond our control, including the outcome of future rate proceedings before the FERC. Such laws or regulations could also lead to reduced demand for

hydrocarbon products that are deemed to contribute to emissions of GHGs, or restrictions on their use, which in turn could adversely affect demand for our products and services. See also “—Business Risks—We are subject to reputational risks and risks relating to public opinion.” and “—Business Risks—Hurricanes, earthquakes, flooding and other natural disasters, as well as subsidence and coastal erosion and climate-related physical risks, could have an adverse effect on our business, financial condition and results of operations.”

~~Finally, many climate models indicate that global warming is likely to result~~In March 2022, the SEC proposed new climate-related disclosure rules, which if adopted as proposed, would require significant new climate-related disclosure in ~~rising sea levels~~SEC filings, including certain climate-related metrics and ~~increased frequency~~GHG emissions data, and ~~severity~~third-party attestation requirements. At this time, we cannot predict the costs of ~~weather events, which may lead to higher insurance costs,~~compliance with, or a decrease in available coverage, for our assets in areas subject to severe weather. These climate-related changes could result in damage to our physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone and rain-susceptible regions.any potential adverse impacts resulting from, the new rules if adopted as proposed.

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

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

We gather, process or transport crude oil, natural gas or NGL from several areas, including lands that are federally managed. Policy and regulatory initiatives ~~of the new presidential administration~~ or legislation by Congress may decrease access to federally managed lands ~~and~~or increase the regulatory burdens associated with using these lands to produce crude oil or natural ~~gas. For example, on January 20,~~gas, or both. Since 2021, the ~~Secretary~~federal government has deprioritized onshore leasing and its review of applications for permits to drill. Third-party interest groups and members of the ~~Department of the Interior issued an order temporarily restricting the authorization of new leases~~oil and gas industry have initiated litigation challenging decisions to approve or permits to drill without the approval of a senior Department official. On January 27, 2021, the President issued an executive order directing, among other matters, the reevaluation of the leasing program forprohibit oil and gas activities on federally managed ~~lands and the “pause” of new oil and natural gas leases on public lands pending completion of the review.~~lands.

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

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

Adoption of legislation or regulations restricting these activities in our areas of operations could impose operational delays, increased operating costs and additional regulatory burdens on exploration and production operators, which could reduce their production of crude oil, natural gas or NGL and, in turn, adversely affect our revenues, cash flows and results of operations by decreasing the volumes of these commodities that we handle. These laws and regulations may also adversely affect our own oil and gas development and production activities.

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

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

3335

~~Risks Related~~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.

KM Pipelines NG Outlook Assets 01.31.jpg

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 ~~Ownership~~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 ~~Capital Stock~~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 ~~guidance~~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.

Products Segment Outlook Slide 12 10K.jpg

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.

CO2

Our CO2 business segment produces, transports and markets CO2 for use in enhanced oil recovery projects as a flooding medium for recovering crude oil from mature oil fields. We also own and operate oil and gas producing fields, and RNG, LNG and landfill GTE facilities. Our CO2 pipelines and related assets allow us to market a complete package of CO2 supply and transportation services to our customers.

KM CO2 Facilities AND ETV Map 10K 01.04.jpg

Source and Transportation Activities

CO2 Resource Interests

Our ownership of CO2 resources as of December 31, 2023 includes:


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

(a)We do not operate this unit.

CO2 and Crude Oil Pipelines

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

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

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.

CO2 Segment Contracts

Our CO2 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 CO2 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 CO2 business segment can be impacted by the demand for CO2. In the CO2 business segment’s oil and gas producing activities, we monitor the amount of capital we expend in relation to the amount of production that we expect to add. The revenues we receive from our ~~anticipated dividends~~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.

CO2 Segment Competition

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

Major Customers

Our revenue is derived from a wide customer base.For each of the years ended December 31, 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 ~~estimates. Circumstances~~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

State and Local Regulation

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 ~~arise~~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 ~~lead~~restrict maritime transportation (between U.S. departure and destination points) to ~~conflicts~~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 ~~using funds~~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.

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 ~~anticipated dividends~~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

Clean Water Act

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 CO2, 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 CO2 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 CO2, such new legislation or regulation could increase the costs related to operating and maintaining our facilities. Depending on the particular law, regulation or program, we or our subsidiaries 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 CO2 business segment. However, these potential positive effects on our markets may be offset if these same regulations also cause the cost of natural gas to increase relative to competing non-fossil fuels. Although we currently cannot predict the magnitude and direction of these impacts, GHG regulations could have material adverse effects on our business, financial position, results of operations or cash flows.

Pipeline Safety Regulation

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

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

Human Capital

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.


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 ~~invest~~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

Item 1A. Risk Factors.

Risks Related to our Business

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

Decreases in the supply of or demand for natural gas, crude oil and other products could adversely impact the utilization of our assets.

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

Each of the foregoing supply and demand issues could negatively impact our business directly, as well as our shippers and other customers, which in turn could negatively impact our prospects for new contracts for transportation, terminaling or other midstream services, or renewals of existing contracts or the ability of our customers and shippers to honor their contractual commitments. Furthermore, such unfavorable conditions may compound the adverse effects of larger disruptions, such as COVID-19. See “—Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.” below.

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

The volatility of crude oil, NGL and natural gas prices could adversely affect our business.

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

If commodity prices fall substantially or remain low for a sustained period and ~~elsewhere the expected cash dividends on our common stock. These reflect our current judgment, but as with any estimate, they~~we are not sufficiently protected through hedging arrangements, we may be ~~affected~~unable to realize a profit from these businesses and would operate at a loss.

Sharp declines in the prices of crude oil, NGL or natural gas, or a prolonged unfavorable price environment, may result in a commensurate reduction in our revenues, income and cash flows from our businesses that produce, process, or purchase and sell crude oil, NGL, or natural gas, and could have a material adverse effect on the carrying value (which includes assigned goodwill) of our CO2 business segment’s proved reserves, certain assets in certain midstream businesses within our Natural Gas Pipelines business segment, and certain assets within our Products Pipelines business segment. For example, following the commodity price declines we experienced due to COVID-19 during the first half of 2020, we recorded a combined $1.95 billion of non-cash impairments associated with our Natural Gas Pipelines Non-Regulated and CO2 reporting units, primarily for impairments of goodwill and assets owned in these businesses.

For more information about our energy and commodity market risk, see Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.”

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

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

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

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

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

our operating results and cash flow. See “~~Information Regarding Forward-Looking Statements~~—The volatility of crude oil, NGL and natural gas prices could adversely affect our business.”

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

We are exposed to the risk of loss in the event of nonperformance by our customers or other counterparties, such as hedging counterparties, joint venture partners and suppliers. Many of our counterparties finance their activities through cash flow from operations or debt or equity financing, and some of them may be highly leveraged and unable to access additional capital to sustain their operations in the future. Our counterparties are subject to their own operating, market, financial and regulatory risks, and some have experienced, are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. Further, the security we are able to obtain from such customers may be limited, including by FERC regulation. While certain of our customers are subsidiaries of an entity that has an investment grade credit rating, in many cases the parent entity has not guaranteed the obligations of the subsidiary and, therefore, the parent’s credit ratings may have no bearing on such customers’ ability to pay us for the services we provide or otherwise fulfill their obligations to us.

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

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

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

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

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

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

When we engage in hedging transactions (for example, to mitigate our exposure to fluctuations in commodity prices or currency exchange rates or to balance our exposure to fixed and variable interest rates) that we believe are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect volatility due to these hedges, even when there is no underlying economic impact at the dates of those consolidated financial statements. In addition, it may not be possible for us to engage in hedging transactions that completely eliminate our exposure to commodity prices; therefore, our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge. For more information about our hedging activities, see Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” and Note 14 “Risk Management” to our consolidated financial statements.

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

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

In accordance with government mandates, we have implemented and maintain a cybersecurity program—both internal and incorporating industry expertise—designed to protect our IT, OT and data systems from attacks, however, we can provide no assurance that our cybersecurity program will be completely effective. We have experienced increases in the number of attempts by external parties to access our networks or our company data without authorization. While we have taken additional steps to secure our networks and systems to specifically respond to new and elevated risks associated with remote work, we may nevertheless be more vulnerable to a successful cyber-attack or information security incident when significant numbers of our employees are working remotely. The risk of a disruption or breach of our operational systems, or the compromise of the data processed in connection with our operations, has increased as attempted attacks, including acts of terrorism or cyber sabotage, have advanced in sophistication and number around the world.

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

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

The U.S. government has issued public warnings indicating that pipelines and other infrastructure assets might be specific targets of terrorist organizations or “cyber sabotage” events. For example, in May 2021, a ransomware attack on a major U.S. refined products pipeline forced the operator to temporarily shut down the pipeline, resulting in disruption of fuel supplies along the East Coast. Potential targets include our pipeline systems, terminals, processing plants, databases or operating systems. The occurrence of an attack could cause a substantial decrease in revenues and cash flows, increased costs to respond

or other financial loss, significant reporting requirements, damage to our reputation, increased regulation or litigation or inaccurate information reported from our operations. In the event of such an incident, we may need to retain cybersecurity experts to assist us in stopping, diagnosing, and recovering from the attack. There is no assurance that adequate cyber sabotage and terrorism insurance will be available at rates we believe are reasonable in the beginning of this report. If our board of directors elects to pay dividends at the anticipated level and that action would leave us with insufficient cash to take timely advantage of growth opportunities (including through acquisitions), to meet any large unanticipated liquidity requirements, to fundnear future. The potential for an attack may subject our operations to increased risks and costs, and, depending on their ultimate magnitude, have a material adverse effect on our business, results of operations, financial condition and/or business reputation.

Development of new technologies could create additional risk, or we may not have sufficient resources to manage our technology.

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

Changes in the insurance markets subsequent to certain hurricanes and other natural disasters have made it more difficult and more expensive to obtain certain types of coverage. The occurrence of an event that is not fully covered by insurance, or failure by one or more of our insurers to honor its coverage commitments for an insured event, could cause us to incur significant losses. Insurance companies may reduce or eliminate the insurance capacity they are willing to offer or may demand significantly higher premiums or deductibles to cover our assets. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, we may be unable to obtain and maintain adequate insurance at a reasonable cost. The unavailability of adequate insurance coverage to cover events in which we suffer significant losses could have a material adverse effect on our business, financial condition and results of operations.

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

We regularly undertake construction projects to expand our existing assets and to construct new assets. New growth projects generally will be subject to, among other things, the receipt of regulatory approvals, feasibility and cost analyses, funding availability and industry, market and demand conditions, and environmental justice considerations. A variety of factors outside of our control, such as difficulties in obtaining rights-of-way and permits or other regulatory approvals, have caused, and may continue to cause, delays in or cancellations of our construction projects. Regulatory authorities may modify their permitting policies in ways that disadvantage our construction projects, such as the FERC’s ongoing evaluation of its process

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

Part of our business strategy includes acquiring additional businesses and assets. We cannot provide any assurance that we will be able to find complementary acquisition targets or complete such acquisitions, or achieve the desired results from any acquisitions we do complete. Any acquired businesses or assets will be subject to many of the same risks as our existing businesses and may not achieve the levels of performance that we anticipate.

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

Difficulties in integration may be magnified if we make multiple acquisitions over a relatively short period of time. Because of difficulties in combining and expanding operations, we may not be able to achieve the cost savings and other size-related benefits that we hoped to achieve after these acquisitions, which would harm our financial condition and results of operations.

Our business requires the retention and recruitment of a skilled executive team and workforce, and difficulties recruiting and retaining executives and other key personnel could impair our ability to ~~address properly~~develop and implement our business ~~prospects,~~strategy.

Our success depends in part on the performance of and our ability to attract, retain and effectively manage the succession of a skilled executive team. We depend on our executive officers to develop and execute our business strategy. If we are not successful in retaining our executive officers, or replacing them, our business, financial condition or results of operations could be adversely affected. We do not maintain key personnel insurance.

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

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

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

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

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

~~Item 1B.~~ ~~Unresolved Staff Comments.~~

~~None.~~

~~Item 3.~~ ~~Legal Proceedings.~~

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

~~Item 4.~~ ~~Mine Safety Disclosures.~~

We no longer own or operate mines for which reporting requirements apply under the mine safety disclosure requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank), except for one terminal that is in temporary idle status with the Mine Safety and Health Administration. We have not received any specified health and safety violations, orders or citations, related assessments or legal actions, mining-related fatalities, or similar events requiring disclosure pursuant to the mine safety disclosure requirements of Dodd-Frank for the year ended December 31, 2020.

~~PART II~~

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

As of ~~February 4, 2021,~~December 31, 2023, we had ~~10,594 holders~~approximately $31.9 billion of consolidated debt (excluding debt fair value adjustments). Additionally, we and substantially all of our ~~Class P common stock,~~wholly owned U.S. subsidiaries are parties to a cross guarantee agreement under which ~~does not include beneficial owners whose shares~~each party to the agreement unconditionally guarantees the indebtedness of each other party, which means that we are ~~held by a nominee,~~liable for the debt of each of such subsidiaries. This level of consolidated debt and the cross guarantee agreement could have important consequences, such as (i) limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements or potential growth, or for other purposes; (ii) increasing the cost of our future borrowings; (iii) limiting our ability to use operating cash flow in other areas of our business or to pay dividends because we must dedicate a ~~broker or bank.~~substantial portion of these funds to make payments on our debt; (iv) placing us at a competitive disadvantage compared to competitors with less debt; and (v) increasing our vulnerability to adverse economic and industry conditions.

Our ability to service our consolidated debt, and our ability to meet our consolidated leverage targets, will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond our control. If our consolidated cash flow is not sufficient to service our consolidated debt, and any future indebtedness that we incur, we will be forced to take actions such as reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may also take such actions to reduce our indebtedness if we determine that our earnings (or consolidated EBITDA, as calculated in accordance with our revolving credit facility) may not be sufficient to meet our consolidated leverage targets or to comply with consolidated leverage ratios required under certain of our debt agreements. We may not be able to effect any of these actions on satisfactory terms or at all. For more information onabout our ~~equity compensation plans,~~debt, see Note ~~10 “Share-based Compensation and Employee Benefits—Share-based Compensation~~”9 “Debt” to our consolidated financial statements.

~~Item 6.~~ ~~Selected Financial Data.~~Our business, financial condition and operating results may be affected adversely by adverse changes in the availability, terms and cost of capital or a reduction in the availability of credit.

~~The following table sets forth, for the periods~~We may need to rely on external financing sources, including commercial borrowings and ~~at the dates indicated, our summary historical financial data. The table is derived from our consolidated financial statements~~issuances of debt and ~~notes thereto, and should be read in conjunction with those audited financial statements. See also Item 7~~ ~~“Management’s Discussion and Analysis of Financial Condition and Results of Operations”~~ ~~in this report for more information.~~

~~Five-Year Review~~

~~Kinder Morgan, Inc. and Subsidiaries~~

As of or for the Year Ended December 31,
2020 2019 2018 2017 2016
(In millions, except per share amounts)
Income and Cash Flow Data:
Revenues $ 11,700 $ 13,209 $ 14,144 $ 13,705 $ 13,058
Operating income 1,560 4,873 3,794 3,529 3,538
Earnings (losses) from equity investments 780 101 617 428 (113)
Net income 180 2,239 1,919 223 721
Net income attributable to Kinder Morgan, Inc. 119 2,190 1,609 183 708
Net income available to common stockholders 119 2,190 1,481 27 552
Class P Shares
Basic Earnings Per Common Share From Continuing Operations $ 0.05 $ 0.96 $ 0.66 $ 0.01 $ 0.25
Basic Weighted Average Common Shares Outstanding 2,263 2,264 2,216 2,230 2,230
Dividends per common share declared for the period(a) $ 1.05 $ 1.00 $ 0.80 $ 0.50 $ 0.50
Dividends per common share paid in the period(a) 1.0375 0.95 0.725 0.50 0.50
Balance Sheet Data (at end of period):
Property, plant and equipment, net $ 35,836 $ 36,419 $ 37,897 $ 40,155 $ 38,705
Total assets 71,973 74,157 78,866 79,055 80,305
Current portion of debt 2,558 2,477 3,388 2,828 2,696
Long-term debt(b) 30,838 30,883 33,205 34,088 36,205

~~(a)Dividends for the fourth quarter of each year are declared and paid during the first quarter of the following year.~~

~~(b)Excludes~~equity securities, to fund acquisitions, capital projects or refinancing debt ~~fair value adjustments.~~

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

The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto. We prepared our consolidated financial statements in accordance with GAAP. Additional sections in this report which should be helpfulmaturities. Adverse changes to the ~~reading~~availability, terms and cost of capital, interest rates or our ~~discussion and analysis include~~credit ratings (which would have a corresponding impact on the ~~following: (i) a description~~credit ratings of our ~~business strategy found in Items 1 and 2 “Business and Properties—Narrative Description of Business—Business Strategy;” (ii) a description of developments during 2020, found in Items 1 and 2 “Business and Properties—General Development of Business—Recent Developments;” (iii) a description of risk factors affecting us and our business, found in Item 1A~~“~~Risk Factors;” and (iv) a discussion of forward-looking statements, found in “Information Regarding Forward-Looking Statements” at the beginning of this report.~~

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

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

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

As of December 31, 2023, approximately $8.3 billion of our approximately $31.9 billion of consolidated debt (excluding debt fair value adjustments) was subject to variable interest rates, either as short-term or long-term variable-rate debt obligations, or as long-term fixed-rate debt effectively converted to variable rates through the use of interest rate swaps. In response to increasing inflation, the U.S. Federal Reserve raised interest rates in March 2022 for the first time in over three years and raised rates many more times since. As interest rates increase, the amount of cash required to service variable-rate debt also increases, as do our costs to refinance maturities of existing indebtedness, and our earnings and cash flows could be adversely affected.

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

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

Risks Related to Regulation

The profitability of our ~~2019~~regulated pipelines is influenced by fluctuations in costs and our ability to ~~2018~~recover any increases in our costs in the rates charged to our shippers. To the extent that our costs increase in an amount greater than what we are permitted by the FERC or state public utility commissions to recover in our rates, or to the extent that there is a lag before we can file for and obtain rate increases, such events can have a negative impact on our operating ~~results can~~results.

Our existing rates may also be challenged by complaint or protest. Regulators and shippers on our pipelines have rights to challenge, and have challenged, the rates we charge under certain circumstances prescribed by applicable regulations. Some shippers on our pipelines have filed complaints with the regulators seeking prospective reductions in the tariff rates and, in the

case of a protest to a rate filing, seeking substantial refunds for alleged overcharges during the years in question. Further, the FERC has initiated and may continue to initiate investigations to determine whether our interstate natural gas pipeline rates are just and reasonable. Please read Note 18 “Litigation and Environmental” to our consolidated financial statements for a description of material pending challenges to the rates we charge on our pipelines. We are unable to predict the extent to which these proceedings will result in lower transportation rates on our pipelines, and in the case of a protest, refunds for alleged overcharges. Any successful challenge to our rates could materially adversely affect our future earnings, cash flows and financial condition.

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

Our assets and operations are subject to extensive regulation and oversight by federal, state and local regulatory authorities. Legislative changes, as well as regulatory actions taken by these authorities, have the potential to adversely affect our profitability. Additional regulatory burdens and uncertainties will be created if and to the extent that more stringent energy and environmental and pipeline safety policies are enacted. Overall, we have seen an increase in the efforts of regulatory authorities to issue new regulations and guidance and to interpret existing laws and regulations in ways that promote the use of renewable energy sources and further protection of the environment, call upon companies to increase monitoring and emissions reduction efforts, and increase investigations and enforcement actions for potential violations of environmental laws. For example, in December 2023, the EPA finalized a rule containing standards of performance for GHG emissions, in the form of methane limitations, and volatile organic compound emissions for crude oil and natural gas sources, including the production, processing, and transmission and storage segments.

The EPA’s final rule known as the “Good Neighbor Plan” (the Plan) became effective on August 4, 2023, except in states that were awarded a stay of the EPA’s disapproval of their SIPs prior to the Plan’s effective date. Following the Plan’s effective date, several other states have been awarded similar stays. As a precursor to the Plan, the EPA disapproved 21 SIPs and found that two other states had failed to submit SIPs under the interstate transport (good neighbor) provisions of the Clean Air Act for the 2015 Ozone NAAQS. The EPA has since proposed to disapprove five additional state SIPs and apply the Plan or portions of the Plan to sources in those states, including one state that would affect our operations. The Plan imposes prescriptive emission standards for several sectors, including new and existing reciprocating internal combustion engines of a certain size used in pipeline transportation of natural gas. The Plan’s emission standards would require installation of more stringent air pollution controls on hundreds of existing internal combustion engines used by our Natural Gas Pipelines business segment. The Plan requires that all impacted engines meet the stringent emission limits by May 1, 2026 unless compliance schedule extensions are granted by the EPA, which would need to be supported by us and approved by the EPA on an engine-by-engine basis. If the Plan remains in effect in its current form (including full compliance by its May 1, 2026 compliance deadline, and assuming failure of all pending challenges to SIP disapprovals and no successful challenge to the Plan), we currently estimate that the Plan would have a material adverse impact on us. See Item 77. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—~~Results~~Liquidity and Capital Resources—Capital Expenditures—Impact of ~~Operations~~Regulation.” ~~included~~Multiple legal challenges have been filed, including by us. See Note 18, “Litigation and Environmental—Environmental Matters—Challenge to Federal “Good Neighbor Plan,” to our consolidated financial statements. We are unable to predict whether any legal challenges will ultimately result in ~~our Annual Report on Form 10-K for~~changes to the ~~year ended December 31, 2019 filed with the SEC on February 7, 2020.~~Plan or how those changes, if any, would impact us.

~~General~~These and other initiatives of regulatory authorities may affect our assets and operations directly or indirectly, such as by preventing or delaying the exploration for and production of natural gas and liquids that we transport or expanding regulation of existing infrastructure or new sources that are not currently regulated.

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

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

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

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

We own and/or operate numerous properties and equipment that have been used for many years in connection with our business activities and contain hydrocarbons or other hazardous substances. While we believe we have utilized operating, handling and disposal practices that were consistent with industry practices at the time, hydrocarbons or other hazardous substances may have been released at or from properties and equipment owned, operated or used by us or our predecessors, or at or from properties where our or our predecessors’ wastes have been taken for disposal. In addition, many of these properties have been owned and/or operated by third parties whose management, handling and disposal of hydrocarbons or other hazardous substances were not under our control. These properties and any hazardous substances released and wastes disposed at or from them may be subject to U.S. ~~energy industries~~laws such as CERCLA, which impose joint and ~~markets,~~several liability without regard to fault or the legality of the original conduct. Under such laws, we ~~examine~~could be required to remove previously disposed wastes, remediate property contamination or both, including contamination caused by prior owners or operators. Furthermore, it is possible that some wastes that are currently classified as non-hazardous, which could include wastes currently generated during our pipeline or liquids or bulk terminal operations or wastes from oil and gas facilities that are currently exempt as being exploration and production waste, may in the future be designated as hazardous wastes. Hazardous wastes are subject to more rigorous and costly handling and disposal requirements than non-hazardous wastes. Such changes in the regulations may result in additional capital expenditures or operating expenses for us.

Environmental and health and safety laws and regulations are subject to change. The long-term trend in environmental regulation has been to place more restrictions and limitations on activities that may be perceived to affect the environment, wildlife, natural resources and human health, including without limitation, the exploration, development, storage and transportation of oil and gas. For example, the Federal Clean Air Act and other similar federal and state laws and regulations are subject to periodic review and amendment, which could result in more stringent emission control requirements obligating us to make significant capital expenditures at our facilities. Several state and federal agencies have also increased their daily and maximum penalty amounts in recent years. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate.

New or revised regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, as well as increased penalty amounts for inadvertent non-compliance, such as a pipeline leak, could have a material adverse effect on our business, financial position, results of operations and prospects. For more information, see Items 1 and 2. “Business and Properties—Narrative Description of Business—Environmental Matters.”

Increased regulatory requirements relating to the safety and integrity of our pipelines may require us to incur significant capital and operating expenses.

We are subject to extensive laws and regulations related to pipeline safety and integrity at the federal and state levels. There are, for example, regulations issued by PHMSA for pipeline operators in the areas of design, operations, maintenance, integrity management, qualification and training, emergency response, control room management, and public awareness. We expect the costs of compliance with these regulations, including integrity management rules, will continue to be substantial. The majority of compliance costs relate to pipeline integrity management regulations, which include assessment and repair requirements. Technological advances in in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipeline determined to be located in HCAs or MCAs can have a significant impact on integrity testing and repair costs. We plan to continue our integrity management program to assess and maintain the integrity of our existing and future pipelines as required by PHMSA rules. Repairs or upgrades deemed necessary to address results of integrity assessments and other testing and/or ensure the continued safe and reliable operation of our pipelines and pipeline facilities could cause us to incur significant and unanticipated capital and operating expenditures. Such expenditures will vary depending on the number of repairs determined to be necessary as a result of integrity assessments and other testing. We also anticipate incurring substantial costs associated with PHMSA’s requirements for reconfirming the maximum allowable operating pressure of certain gas pipelines. We expect to increase expenditures in the future to comply with PHMSA regulations.

Further, additional laws and regulations that may be enacted in the future or a new interpretation of existing laws and regulations could significantly increase our compliance expenditures. Pipeline safety regulations or changes to such regulations may require additional leak detection, reporting, the replacement of certain pipeline segments, addition of monitoring equipment and more frequent monitoring, inspection or testing of our pipeline facilities. Repair, remediation, and preventative or mitigating actions may require significant capital and operating expenditures. Pipeline safety regulation has increased over time, including recent revised gas and hazardous liquid regulations that we must timely implement, and existing obligations may increase with new proposed rules that are currently under consideration. For example, PHMSA has issued a proposed rulemaking with expansive pipeline leak detection and repair requirements that is proposed to be applicable to gas pipelines, LNG facilities, and underground natural gas storage facilities. In addition, PHMSA is working on a number of ~~variables~~proposed rulemakings that are now projected for publication in 2024, including those related to (i) updating regulations for LNG facilities; (ii) requirements for idled gas and ~~factors~~liquid pipelines; (iii) revising requirements for transportation of CO2 in the liquid phase as well as establishing regulation of the transportation of gaseous CO2; and (iv) requirements for responding to changes in class location for gas pipelines. Congress is working on the reauthorization of the Pipeline Safety Act, which is expected to be enacted during 2024 and to further expand PHMSA’s current rulemaking agenda and/or statutory authority in certain areas. There can be no assurance as to the amount or timing of future expenditures for pipeline safety and integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not deemed by regulators to be fully recoverable from our customers, could have a ~~routine basis to evaluate~~material adverse effect on our ~~current performance~~business, financial position, results of operations and ~~our prospects for the future. We have four business segments as further described below.~~prospects.

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

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

Adoption of any such laws or regulations could increase our costs to operate and maintain our facilities, expand existing facilities or construct new facilities. We could be required to install new emission controls on our facilities, acquire allowances for our GHG emissions, pay taxes related to our GHG emissions and administer and manage a GHG emissions program, and such increased costs could be significant. Recovery of such increased costs from our customers is uncertain in all cases and may depend on events beyond our control, including the outcome of future rate proceedings before the FERC. Such laws or regulations could also lead to reduced demand for hydrocarbon products that are deemed to contribute to emissions of GHGs, or restrictions on their use, which in turn could adversely affect demand for our products and services. See also “—Business Risks—We are subject to reputational risks and risks relating to public opinion.” and “—Business Risks—Hurricanes, earthquakes, flooding and other natural disasters, as well as subsidence and coastal erosion and climate-related physical risks, could have an adverse effect on our business, financial condition and results of operations.”

In March 2022, the SEC proposed new climate-related disclosure rules, which if adopted as proposed, would require significant new climate-related disclosure in SEC filings, including certain climate-related metrics and GHG emissions data, and third-party attestation requirements. At this time, we cannot predict the costs of compliance with, or any potential adverse impacts resulting from, the new rules if adopted as proposed.

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

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

We gather, process or transport crude oil, natural gas or NGL from several areas, including lands that are federally managed. Policy and regulatory initiatives or legislation by Congress may decrease access to federally managed lands or increase the regulatory burdens associated with using these lands to produce crude oil or natural gas, or both. Since 2021, the federal government has deprioritized onshore leasing and its review of applications for permits to drill. Third-party interest groups and members of the oil and gas industry have initiated litigation challenging decisions to approve or prohibit oil and gas activities on federally managed lands.

In addition, oil and gas development and production activities are subject to increasing regulation at the federal, state and local levels. For example, there have been initiatives at the federal and state levels to regulate or otherwise restrict the use of certain hydraulic fracturing activities, and many states are promulgating stricter requirements related not only to well development but also to compressor stations and other facilities in the oil and gas industry. These activities are subject to laws and regulations regarding the acquisition of permits before drilling, restrictions on drilling activities and location, emissions into the environment, water discharges, transportation of hazardous materials, and storage and disposition of wastes. In addition, legislation has been enacted that requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities.

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

Natural Gas Pipelines

~~This~~Our Natural Gas Pipelines business segment ~~owns~~includes interstate and ~~operates~~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 ~~interstate~~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 systems; (ii) natural gas gathering systems and processing and treating facilities; (iii) NGL fractionation facilities and transportation systems; and (iv) LNG regasification, liquefaction and storage facilities.capacity of 60 MBbl.

Natural Gas Pipelines Segment Contracts

~~With respect to~~

Revenues from our interstate natural gas pipelines, related storage facilities and LNG terminals ~~the revenues from these assets~~ are primarily received under long-term fixed contracts. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate risk of reduced volumes and prices by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. These long-term contracts are typically structured with a fixed fee reserving the right to transport or store natural gas and specify that we receive the majority of our fee for making the capacity available, whether or not the customer actually chooses to utilize ~~the~~that capacity. Similarly, our Texas Intrastate natural gas pipeline operations currently ~~derives~~derive approximately ~~83%~~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, ~~2020,~~2023, the remaining weighted average contract life of our natural gas transportation contracts held by assets we own ~~and~~or have equity interests in (including intrastate pipelines’ sales portfolio) was approximatelysix ~~years. Our~~years and our LNG regasification and liquefaction and associated storage contracts ~~are~~were subscribed under long-term agreements with a weighted average remaining contract life of approximately 1311 years.

Our ~~midstream~~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.

Products Pipelines

~~This~~Our Products Pipelines business segment ~~owns and operates~~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 ~~primarily deliver, among other products, gasoline, diesel~~we owned and ~~jet fuel, crude oil~~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 ~~condensate~~ethanol blending.

(b)Collectively referred to ~~various markets. This segment also owns and/or operates associated product terminals and petroleum pipeline transmix facilities.~~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. ~~We also have 49~~Included in the number of terminals above are refined products liquids terminals ~~in this business segment~~ that store fuels and offer blending services for ethanol and biodiesel. The transportation and storage volume levels are primarily driven by the demand for the refined petroleum products being shipped or stored. Demand for refined petroleum products tends to ~~track~~follow trends in ~~large measure demographic~~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 ~~and~~(which do not require contractual commitments) or (ii) long-term contracts that normally contain minimum volume commitments. ~~As a result of these~~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 ~~level~~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

Terminals

~~This~~Our Terminals business segment ~~owns~~includes the operations of our refined petroleum product, chemical, renewable fuel and ~~operates (i) liquids and bulk~~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 ~~throughout~~primarily near large U.S. urban centers. We believe the ~~U.S. that store~~location of our facilities and ~~handle various commodities including gasoline, diesel fuel, chemicals, ethanol, metals~~our ability to provide flexibility to customers help attract new and ~~petroleum coke;~~retain existing customers at our terminals and ~~(ii)~~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 ~~tankers.~~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, and in the case of a bulk terminal, the type of product being handled or stored.~~terminals. Our liquids terminals business generally ~~has~~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 ~~these variables~~supply and demand affect our terminals business in the near term is a function of the remaining length of the underlying service contracts~~(which~~ (which on a weighted average isbasis was approximately ~~three years)~~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.

~~In addition to liquid and bulk terminals, we also own~~Our Jones Act-qualified tankers in our Terminals business segment. As of December 31, 2020, we have sixteen Jones Act-qualified tankers that operate in the marine transportation of crude oil, condensate and refined products in the U.S. and are primarily operating pursuant to ~~multi-year~~ fixed price term charters with major integrated oil companies, major refiners and the U.S. Military Sealift Command.

Terminals Segment Competition

CO2

~~This segment (i) manages the production, transportation and marketing of~~Our CO2 ~~to oil fields that use~~business segment produces, transports and markets CO2 for use in enhanced oil recovery projects as a flooding medium ~~to increase recovery and production of~~for recovering crude oil from mature oil ~~fields; (ii) owns interests in and/or operates~~fields. We also own and operate oil and gas producing fields, and ~~gasoline processing plants in West Texas;~~RNG, LNG and ~~(iii) owns~~landfill GTE facilities. Our CO2 pipelines and ~~operates~~related assets allow us to market a ~~crude oil pipeline system in West Texas.~~complete package of CO2 supply and transportation services to our customers.

Source and Transportation Activities

CO2 Resource Interests

Our ownership of CO2 resources as of December 31, 2023 includes:


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

(a)We do not operate this unit.

CO2 and Crude Oil Pipelines

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

Our ownership of CO2 and crude oil pipelines as of December 31, 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.

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

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.

CO2 Segment Contracts

Our CO2 source and transportation business primarily has third-party contracts with minimum volume requirements, which as of December 31, ~~2020,~~2023 had a remaining average contract life of approximately ~~eight~~ seven years. Our CO2 sales contracts vary from customer to customer and ~~have evolved over time as supply and demand conditions have changed. Our recent contracts have~~ generally ~~provided~~provide for a delivered price tied to the price of crude oil, ~~but with a floor price. On a volume-weighted basis, for third-party contracts making deliveries~~ in ~~2020, and utilizing the average oil price per barrel contained in our 2021 budget, approximately 100% of our revenue is~~ some casesbased on a fixed fee or floor price. Our success in this portion of the CO2 business segment can be impacted by the demand for CO2. In the CO2 business segment’s oil and gas producing activities, we monitor the amount of capital we expend in relation to the amount of production that we expect to add. The revenues we receive from our crude oil and NGL sales are affected by the prices we realize from the sale of these products. Over the long-term, we ~~will~~ tend to receive prices that are ~~dictated~~driven by the demand and overall market price for these products. In the shorter term, however, market prices generally are ~~likely~~ not indicative of the revenues we will receive due to our ~~risk management, or~~ hedging program, in which the prices to be realized for certain of our future sales quantities are fixed ~~capped~~ or bracketed through the use of financial derivative contracts, particularly for crude oil. ~~The realized weighted average~~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 ~~price per barrel,~~sales prices.

CO2 Segment Competition

Major Customers

Industry Regulation

Interstate Natural Gas Transportation and Storage Regulation

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 ~~hedges allocated~~FERC or included in summary form in the pipeline’s tariff.

Interstate Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation

Some of our U.S. refined petroleum products and crude oil ~~was $53.78 per barrel~~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 ~~2020~~effect and ~~$49.49 per barrel in 2019. Had we not used energy derivative~~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.

3717

~~contracts to transfer commodity price risk, our~~

Petroleum products and crude oil ~~sales prices would have averaged $38.32 per barrel~~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 ~~2020~~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 ~~$55.12 per barrel~~settlement rates are alternatives to the default indexing mechanism and may be used in ~~2019.~~certain specified circumstances to change rates.

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

~~Sale of U.S. Portion of Cochin Pipeline System and KML~~

On December 16, 2019, we closed on two cross-conditional transactions resulting in the sale of the U.S. portion of the Cochin Pipeline system and all the outstanding equity of KML, including our 70% interest, to Pembina Pipeline Corporation (Pembina) (together, the “KML and U.S. Cochin Sale”). We received approximately 25 million shares of Pembina common equity for our interest in KML. On January 9, 2020, we sold our shares of Pembina and received proceeds of approximately $907 million ($764 million after tax) which were used to repay maturing debt. The assets sold were part of our Natural Gas Pipelines and Terminals business segments.

~~COVID-19~~CPUC Rate Regulation

The ~~COVID-19 pandemic-related reduction~~intrastate common carrier operations of our refined products pipelines in ~~energy demand~~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

State and Local Regulation

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 ~~dramatic decline in commodity prices that began to impact us~~American Bureau of Shipping maintain the most stringent regime of vessel inspection in the ~~first quarter~~world, which tends to result in higher regulatory compliance costs for U.S.-flagged operators than for owners of ~~2020 continued~~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 ~~cause~~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 ~~volatility. Sharp declines~~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.”

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 ~~crude~~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

Clean Water Act

EPA Revisions to National Ambient Air Quality Standards

Climate Change

Due to concern over climate change, numerous proposals to monitor and limit emissions of GHGs have been made and are likely to continue to be made at the federal, state and local levels of government. Methane, a primary component of natural gas, and CO2, which is naturally occurring and also a byproduct of 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 CO2 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 ~~production along~~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 ~~reduced~~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 CO2, such new legislation or regulation could increase the costs related to operating and maintaining our facilities. Depending on the particular law, regulation or program, we or our subsidiaries 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

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 ~~refined products due~~natural gas by increasing the relative cost of competing fuels such as coal and oil. In addition, we anticipate that GHG regulations will increase demand for carbon sequestration technologies, such as the techniques we have successfully demonstrated in our enhanced oil recovery operations within our CO2 business segment. However, these potential positive effects on our markets may be offset if these same regulations also cause the cost of natural gas to increase relative to competing non-fossil fuels. Although we currently cannot predict the magnitude and direction of these impacts, GHG regulations could have material adverse effects on our business, financial position, results of operations or cash flows.

Pipeline Safety Regulation

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 ~~economic~~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

Human Capital


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.

Properties and Rights-of-Way

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 ~~pandemic affected~~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

Item 1A. Risk Factors.

Risks Related to ~~do so. While we have seen some meaningful recovery during the second half of the year in demand for refined products that we move through~~ our ~~terminals, significant uncertainty remains regarding the duration and extent of the impact of the pandemic~~Business

Our businesses are dependent on the ~~energy industry, including~~supply of and demand ~~and prices~~ for the products ~~handled~~we handle.

Our pipelines, terminals and other assets and facilities, including the availability of expansion opportunities, depend in part on continued production of natural gas, crude oil and other products in the geographic areas that they serve. Without additions to crude oil and gas reserves, production will decline over time as reserves are depleted, and production costs may rise. Producers in areas served by us may not be successful in exploring for and developing additional reserves or their costs of doing so may become uneconomic. Commodity prices and tax incentives may not remain at levels that encourage producers to explore for and develop additional reserves, produce existing marginal reserves or renew transportation contracts as they expire. Our business also depends in part on the levels of demand for natural gas, crude oil, NGL, refined petroleum products, CO2, steel, chemicals and other products in the geographic areas to which our pipelines, terminals, shipping vessels and other facilities ~~although we expect~~deliver or provide service, and the ability and willingness of our shippers and other customers to supply such demand.

Decreases in the supply of or demand for natural gas, crude oil and other products could adversely impact the utilization of our assets.

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

The volatility of crude oil, NGL and natural gas prices could adversely affect our business.

Prices for crude oil, NGL and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for crude oil, NGL and natural gas, uncertainties within the market and a variety of other factors beyond our control. These factors include, among other things (i) weather conditions and events such as ~~described above resulted~~hurricanes in ~~decreases~~the U.S.; (ii) domestic and global economic conditions; (iii) the activities of ~~current~~the OPEC and ~~estimated long-term~~other countries that are significant producers of crude oil (OPEC+); (iv) governmental regulation; (v) armed conflict or political instability in crude oil and ~~NGL sale~~natural gas producing countries; (vi) the foreign supply of and demand for crude oil and natural gas; (vii) the price of foreign imports; (viii) the proximity and availability of storage and transportation infrastructure and processing and treating facilities; and (ix) the availability and prices of alternative fuel sources. We use hedging arrangements to partially mitigate our exposure to commodity prices, but these arrangements also are subject to inherent risks. Please read “—Our use of hedging arrangements does not eliminate our exposure to commodity price risks and ~~volumes~~could result in financial losses or volatility in our income.” In addition, wide fluctuations in commodity prices can impact the accuracy of assumptions used in our budgeting process.

If commodity prices fall substantially or remain low for a sustained period and we ~~expect~~are not sufficiently protected through hedging arrangements, we may be unable to realize a profit from these businesses and would operate at a loss.

Sharp declines in ~~significant reductions to~~ the ~~market capitalization~~prices of ~~many midstream~~crude oil, NGL or natural gas, or a prolonged unfavorable price environment, may result in a commensurate reduction in our revenues, income and cash flows from our businesses that produce, process, or purchase and sell crude oil, NGL, or natural gas, and ~~gas producing companies. These events triggered us to review~~could have a material adverse effect on the carrying value (which includes assigned goodwill) of our long-lived assets and recoverability of goodwill for interim periods in addition to our annual testing. Our evaluations resulted in the recognition during the first six months of 2020 of a $350 million impairment for long-lived assets in our CO2 business segment’s proved reserves, certain assets in certain midstream businesses within our Natural Gas Pipelines business segment, and ~~goodwill~~certain assets within our Products Pipelines business segment. For example, following the commodity price declines we experienced due to COVID-19 during the first half of 2020, we recorded a combined $1.95 billion of non-cash impairments ~~of $1,000 million and $600 million to~~associated with our Natural Gas Pipelines Non-Regulated and CO2 reporting units, ~~respectively.~~ primarily for impairments of goodwill and assets owned in these businesses.

For ~~a further discussion of these impairments~~more information about our energy and ~~our~~commodity market risk, ~~for future impairments,~~ see ~~Note 3,~~Item 7A. “~~Impairments~~Quantitative and ~~Losses and Gains on Divestitures~~Qualitative Disclosures About Market Risk.”

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

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

The occurrence of any of these risks could result in ~~our~~serious injury and loss of human life, significant damage to property and natural resources, environmental pollution, significant reputational damage, impairment or suspension of operations, ~~and have taken a cautious enterprise-wide approach with a phased return to workplace process for our employees who are currently working remotely. During 2020, our incremental employee safety~~fines or other regulatory penalties, costs associated with ~~COVID-19 mitigation were approximately $15 million, primarily for personal protective equipment, enhanced cleaning protocols, temperature screening~~allegations of criminal liability, costs associated with responding to an investigation or enforcement action brought by a governmental agency, and revocation of regulatory approvals or imposition of new requirements, any of which also could result in substantial financial losses, including lost revenue and cash flow to the extent that an incident causes an interruption of service. For pipeline and storage assets located near populated areas, including residential areas, commercial business centers, industrial sites and other ~~measures~~public gathering areas, the level of damage resulting from these risks may be greater. In addition, the consequences of any operational incident (including as a result of adverse sea conditions) at one of our marine terminals may be even more significant as a result of the complexities involved in addressing leaks and releases occurring in the ocean or along coastlines and/or the repair of marine terminals.

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

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

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

our operating results and cash flow. See “—The volatility of crude oil, NGL and natural gas prices could adversely affect our business.”

We are exposed to the risk of loss in the event of nonperformance by our customers or other counterparties, such as hedging counterparties, joint venture partners and suppliers. Many of our counterparties finance their activities through cash flow from operations or debt or equity financing, and some of them may be highly leveraged and unable to access additional capital to sustain their operations in the future. Our counterparties are subject to their own operating, market, financial and regulatory risks, and some have experienced, are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. Further, the security we are able to obtain from such customers may be limited, including by FERC regulation. While certain of our customers are subsidiaries of an entity that has an investment grade credit rating, in many cases the parent entity has not guaranteed the obligations of the subsidiary and, therefore, the parent’s credit ratings may have no bearing on such customers’ ability to pay us for the services we provide or otherwise fulfill their obligations to us.

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

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

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

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

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

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

or other financial loss, significant reporting requirements, damage to our reputation, increased regulation or litigation or inaccurate information reported from our operations. In the event of such an incident, we may need to retain cybersecurity experts to assist us in stopping, diagnosing, and recovering from the attack. There is no assurance that adequate cyber sabotage and terrorism insurance will be available at rates we believe are reasonable in the near future. The potential for an attack may subject our operations to increased risks and costs, and, depending on their ultimate magnitude, have a material adverse effect on our business, results of operations, financial condition and/or business reputation.

Development of new technologies could create additional risk, or we may not have sufficient resources to manage our technology.

Changes in the insurance markets subsequent to certain hurricanes and other natural disasters have made it more difficult and more expensive to obtain certain types of coverage. The occurrence of an event that is not fully covered by insurance, or failure by one or more of our insurers to honor its coverage commitments for an insured event, could cause us to incur significant losses. Insurance companies may reduce or eliminate the insurance capacity they are willing to offer or may demand significantly higher premiums or deductibles to cover our assets. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, we may be unable to obtain and maintain adequate insurance at a reasonable cost. The unavailability of adequate insurance coverage to cover events in which we suffer significant losses could have a material adverse effect on our business, financial condition and results of operations.

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

Our business requires the retention and recruitment of a skilled executive team and workforce, and difficulties recruiting and retaining executives and other key personnel could impair our ability to develop and implement our business strategy.

Our success depends in part on the performance of and our ability to attract, retain and effectively manage the succession of a skilled executive team. We depend on our executive officers to develop and execute our business strategy. If we are not successful in retaining our executive officers, or replacing them, our business, financial condition or results of operations could be adversely affected. We do not maintain key personnel insurance.

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

Risks Related to Financing Our Business

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

As of December 31, 2023, we had approximately $31.9 billion of consolidated debt (excluding debt fair value adjustments). Additionally, we and substantially all of our wholly owned U.S. subsidiaries are parties to a cross guarantee agreement under which each party to the agreement unconditionally guarantees the indebtedness of each other party, which means that we are liable for the debt of each of such subsidiaries. This level of consolidated debt and the cross guarantee agreement could have important consequences, such as (i) limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements or potential growth, or for other purposes; (ii) increasing the cost of our future borrowings; (iii) limiting our ability to use operating cash flow in other areas of our business or to pay dividends because we must dedicate a substantial portion of these funds to make payments on our debt; (iv) placing us at a competitive disadvantage compared to competitors with less debt; and (v) increasing our vulnerability to adverse economic and industry conditions.

Our business, financial condition and operating results may be affected adversely by adverse changes in the availability, terms and cost of capital or a reduction in the availability of credit.

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

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

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

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

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.

Our assets and operations are subject to extensive regulation and oversight by federal, state and local regulatory authorities. Legislative changes, as well as regulatory actions taken by these authorities, have the potential to adversely affect our profitability. Additional regulatory burdens and uncertainties will be created if and to the extent that more stringent energy and environmental and pipeline safety policies are enacted. Overall, we have seen an increase in the efforts of regulatory authorities to issue new regulations and guidance and to interpret existing laws and regulations in ways that promote the use of renewable energy sources and further protection of the environment, call upon companies to increase monitoring and emissions reduction efforts, and increase investigations and enforcement actions for potential violations of environmental laws. For example, in December 2023, the EPA finalized a rule containing standards of performance for GHG emissions, in the form of methane limitations, and volatile organic compound emissions for crude oil and natural gas sources, including the production, processing, and transmission and storage segments.

The EPA’s final rule known as the “Good Neighbor Plan” (the Plan) became effective on August 4, 2023, except in states that were awarded a stay of the EPA’s disapproval of their SIPs prior to the Plan’s effective date. Following the Plan’s effective date, several other states have been awarded similar stays. As a precursor to the Plan, the EPA disapproved 21 SIPs and found that two other states had failed to submit SIPs under the interstate transport (good neighbor) provisions of the Clean Air Act for the 2015 Ozone NAAQS. The EPA has since proposed to disapprove five additional state SIPs and apply the Plan or portions of the Plan to sources in those states, including one state that would affect our operations. The Plan imposes prescriptive emission standards for several sectors, including new and existing reciprocating internal combustion engines of a certain size used in pipeline transportation of natural gas. The Plan’s emission standards would require installation of more stringent air pollution controls on hundreds of existing internal combustion engines used by our Natural Gas Pipelines business segment. The Plan requires that all impacted engines meet the stringent emission limits by May 1, 2026 unless compliance schedule extensions are granted by the EPA, which would need to be supported by us and approved by the EPA on an engine-by-engine basis. If the Plan remains in effect in its current form (including full compliance by its May 1, 2026 compliance deadline, and assuming failure of all pending challenges to SIP disapprovals and no successful challenge to the Plan), we currently estimate that the Plan would have a material adverse impact on us. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Expenditures—Impact of Regulation.” Multiple legal challenges have been filed, including by us. See Note 18, “Litigation and Environmental—Environmental Matters—Challenge to Federal “Good Neighbor Plan,” to our consolidated financial statements. We are unable to predict whether any legal challenges will ultimately result in changes to the Plan or how those changes, if any, would impact us.

These and other initiatives of regulatory authorities may affect our assets and operations directly or indirectly, such as by preventing or delaying the exploration for and production of natural gas and liquids that we transport or expanding regulation of existing infrastructure or new sources that are not currently regulated.

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

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

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

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

We own and/or operate numerous properties and equipment that have been used for many years in connection with our business activities and contain hydrocarbons or other hazardous substances. While we believe we have utilized operating, handling and disposal practices that were consistent with industry practices at the time, hydrocarbons or other hazardous substances may have been released at or from properties and equipment owned, operated or used by us or our predecessors, or at or from properties where our or our predecessors’ wastes have been taken for disposal. In addition, many of these properties have been owned and/or operated by third parties whose management, handling and disposal of hydrocarbons or other hazardous substances were not under our control. These properties and any hazardous substances released and wastes disposed at or from them may be subject to U.S. laws such as CERCLA, which impose joint and several liability without regard to fault or the legality of the original conduct. Under such laws, we could be required to remove previously disposed wastes, remediate property contamination or both, including contamination caused by prior owners or operators. Furthermore, it is possible that some wastes that are currently classified as non-hazardous, which could include wastes currently generated during our pipeline or liquids or bulk terminal operations or wastes from oil and gas facilities that are currently exempt as being exploration and production waste, may in the future be designated as hazardous wastes. Hazardous wastes are subject to more rigorous and costly handling and disposal requirements than non-hazardous wastes. Such changes in the regulations may result in additional capital expenditures or operating expenses for us.

Increased regulatory requirements relating to the safety and integrity of our pipelines may require us to incur significant capital and operating expenses.

Further, additional laws and regulations that may be enacted in the future or a new interpretation of existing laws and regulations could significantly increase our compliance expenditures. Pipeline safety regulations or changes to such regulations may require additional leak detection, reporting, the replacement of certain pipeline segments, addition of monitoring equipment and more frequent monitoring, inspection or testing of our pipeline facilities. Repair, remediation, and preventative or mitigating actions may require significant capital and operating expenditures. Pipeline safety regulation has increased over time, including recent revised gas and hazardous liquid regulations that we must timely implement, and existing obligations may increase with new proposed rules that are currently under consideration. For example, PHMSA has issued a proposed rulemaking with expansive pipeline leak detection and repair requirements that is proposed to be applicable to gas pipelines, LNG facilities, and underground natural gas storage facilities. In addition, PHMSA is working on a number of proposed rulemakings that are now projected for publication in 2024, including those related to (i) updating regulations for LNG facilities; (ii) requirements for idled gas and liquid pipelines; (iii) revising requirements for transportation of CO2 in the liquid phase as well as establishing regulation of the transportation of gaseous CO2; and (iv) requirements for responding to changes in class location for gas pipelines. Congress is working on the reauthorization of the Pipeline Safety Act, which is expected to be enacted during 2024 and to further expand PHMSA’s current rulemaking agenda and/or statutory authority in certain areas. There can be no assurance as to the amount or timing of future expenditures for pipeline safety and integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not deemed by regulators to be fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects.

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

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

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

Risks Related to Ownership of Our Capital Stock

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

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

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

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

Item 1B. Unresolved Staff Comments.

None.

Item 1C. Cybersecurity.

Cybersecurity Risk Management and Strategy

We employ a comprehensive strategy for identifying and addressing cybersecurity risks that is aligned with the U.S. Department of Commerce’s National Institute of Standards and Technology Framework for Improving Critical Infrastructure Cybersecurity. This framework outlines standards and practices to promote the protection of critical infrastructure. We utilize a risk-based approach that focuses on critical systems where failure or exploitation could potentially impact the safety or reliability of our key assets or operations. Cybersecurity risks are integrated into our overall risk management processes, including, for example, quarterly security briefings with senior management, tabletop exercises with operations, finance and other company personnel, and by employing a continuous improvement model for our cyber protection strategy that is aligned with the DHS’s National Infrastructure Protection Plan risk management framework.

Our management team has engaged third-party experts to provide guidance related to management of supply chain cybersecurity risks. Our strategy includes both short- and long-term initiatives to increase the security surrounding our assets and is supplemented using third-party threat monitoring, rigorous security protocols, and government partnerships. We perform cybersecurity assessments with respect to third parties who provide critical services or who have access to or store critical confidential data.

We have not identified any cybersecurity threats that have materially impaired or are reasonably likely to materially impair our operations or financial standing. Please read Item 1A. “Risk Factors—Risks Related to Our Business—A breach of information security or the failure of one or more key information technology (IT) or operational (OT) systems, or those of third parties, may adversely affect our business, results of operations or business reputation.” and “ Attacks, including acts of terrorism or cyber sabotage, or the threat of such attacks, may adversely affect our business or reputation.” for discussions of risks from cybersecurity threats we face.

Measures We Take to Monitor and our Procedures for Responding to Data Breaches or Cyberattacks

We have made investments to address data and cybersecurity risks. These investments include our use of continuous third-party security monitoring of our network perimeters, advanced persistent threat group monitoring to keep us informed of emerging serious threats, standardization of our network security architecture which separates business and supervisory control and data acquisition (SCADA) networks, and security information and event management software systems.

Our critical business systems are fully redundant and backed up at separate locations. Separate business and SCADA networks allow for isolation of potential threats and enhances the security of these systems. Our security systems correlate security events and aggregate security-related incident data, such as malware activity and other possible malicious activities. This system sends alerts if the data analysis shows that an activity could be a potential security issue. Security functionality is continuously monitored by our network operations center, and our network traffic is analyzed for signs of malicious activity through the CyberSentry program, which is managed by DHS’s Cybersecurity and Infrastructure Security Agency and a third-party security operations center, which operates continuously. We maintain a dedicated SCADA group within our IT department to evaluate and respond to significant events and incidents that may impact our operations. Anti-virus solutions are deployed on the SCADA systems and workstations in our data centers and control centers.

Our processes and cybersecurity plans are part of our overall emergency response plans, and we conduct simulated exercise drills, including with multiple U.S. government agencies and peer companies, to enhance our preparedness and provide for continual process improvement.

If data and network defenses are bypassed, processes detailed in our Cyber Incident Response Plan would help identify, contain and eradicate threats and bring our systems back online if needed. Additionally, the plan requires that the appropriate level of our management be made aware of incidents and be updated as the situation warrants.

Vulnerability Assessments and Penetration Testing

We hire an independent third-party cybersecurity firm to perform penetration testing annually. The third-party checks for vulnerabilities on our external and internal network perimeters. If vulnerabilities are found, corrective actions are implemented to remediate any issues.

Government and Industry Group Engagement

We engage with a wide variety of government agencies and industry groups to enable cross-sharing of information and to identify opportunities to improve our security, including active participation in IT Sector Coordinating Councils and attendance at classified briefings and security architecture reviews hosted by the U.S. Department of Energy, the U.S. Federal Bureau of Investigation and DHS. Partnership with these agencies provides us with intelligence on a wide range of critical infrastructure protection and cybersecurity issues as well as an opportunity to exchange best practices.

Employee Training

Our employees are required to take annual cyber and physical security training designed to help employees guard our cyber and physical data. Employees are tested on this training and cybersecurity performance is considered in annual employee performance reviews.

Cybersecurity Governance Structures

Management’s Role in Managing Cybersecurity Risk

We are committed to protecting sensitive information and have a dedicated cybersecurity group within our IT department that is overseen by our Chief Information Officer. This group provides a quarterly cybersecurity report to our senior management, including the Chief Executive Officer, President, Chief Financial Officer, Chief Operating Officer, Chief

Administrative Officer, Chief Information Officer, General Counsel, business segment Presidents and the Vice President—Corporate Security. This senior management team is involved in all significant cybersecurity decisions, including efforts undertaken to comply with the security directives issued by the TSA. Our Chief Executive Officer, General Counsel and our Chief Information Officer have attended classified briefings on cybersecurity in Washington, D.C. In addition to the quarterly reports to senior management, the cybersecurity team prepares broader management briefings that include updates regarding company-wide cybersecurity matters and initiatives and provide a forum for discussing data security risk solutions and formulating action plans.

Management of our cybersecurity team has extensive experience and training related to cybersecurity matters. These leaders hold top-secret clearance from the U.S. federal government and have attended classified briefings from relevant federal agencies. Our cybersecurity team has in excess of 120 years of combined cybersecurity experience as of year-end 2023, and members of the team hold various specialized certifications related to cybersecurity, including training related to penetration testing and information system auditing.

The Board’s Role in Cybersecurity Risk Oversight

The Audit Committee of our Board has oversight responsibility related to cybersecurity risk and is briefed quarterly by our Chief Information Officer on cybersecurity risk, our cybersecurity management program and initiatives, and, if applicable, notable cybersecurity events. In the event of a significant cybersecurity incident, our Chief Executive Officer will notify the Chairman of the Board or, in that person’s absence, the lead independent director of the Board.

Item 3. Legal Proceedings.

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

Item 4. Mine Safety Disclosures.

Except for one terminal facility that is in temporary idle status with the Mine Safety and Health Administration, we do not own or operate mines for which reporting requirements apply under the mine safety disclosure requirements of the Dodd-Frank Act. We have not received any specified health and safety violations, orders or citations, related assessments or legal actions, mining-related fatalities, or similar events requiring disclosure pursuant to the mine safety disclosure requirements of the Dodd-Frank Act for the year ended December 31, 2023.

PART II

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

Our Class P common stock is listed for trading on the NYSE under the symbol “KMI.”

As of February 15, 2024, we had 9,540 holders of record of our Class P common stock, which does not include beneficial owners whose shares are held by a nominee, such as a broker or bank.

For information on our equity compensation plans, see Note 10 “Share-based Compensation and Employee Benefits—Share-based Compensation” to our consolidated financial statements. For information about our expectations regarding dividends, please see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—General—2024 Dividends and Discretionary Capital.”

Our Purchases of Our Class P Stock

(During the quarter ended December 31, 2023)


Settlement Period	Total number of securities purchased(a)	Average price paid per security(b)		Total number of securities purchased as part of publicly announced plans(a)	Approximate dollar value of securities that may yet be purchased under the plans or programs(a)
October 1 to October 31, 2023	5,706,428	$	16.41	5,706,428	$	1,574,253,794
November 1 to November 30, 2023	2,386,705	16.26		2,386,705	1,535,434,677
December 1 to December 31, 2023	—	—		—	1,535,434,677

Total	8,093,133	$	16.37	8,093,133	$	1,535,434,677

(a)On July 19, 2017, our Board approved a $2 billion common share buy-back program. On January 18, 2023, our Board approved an increase in our share repurchase authorization to $3 billion from $2 billion. After repurchase, the shares are canceled and no longer outstanding.

(b)Amount includes any commission or other costs to repurchase shares.

Subsequent to December 31, 2023 and through February 16, 2024, we repurchased less than 1 million shares at an average price of $16.50 for $7 million.

Item 6. [Reserved]

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

“Business and Properties—Narrative Description of Business—Business Segments;” (iv) a description of risk factors affecting us and our business, found in Item 1A.“Risk Factors;” and (v) a discussion of forward-looking statements, found in “Information Regarding Forward-Looking Statements” at the beginning of this report.

A comparative discussion of our 2022 to 2021 operating results can be found in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2022 filed with the SEC on February 7, 2022.

General

Acquisitions

Following are acquisitions we made during the reporting period. See Note 3. “Acquisitions and Divestitures” to our consolidated financial statements for further information on these transactions.


Event	Description	Business Segment
STX Midstream acquisition $1,831 million (December 2023)	We acquired the STX Midstream pipeline system consisting of a set of integrated, large diameter high pressure natural gas pipelines in the Eagle Ford basin, including the Eagle Ford Transmission system, a 90% interest in NET Mexico Pipeline LLC and a 50% interest in Dos Caminos, LLC. Approximately 75% of the business is supported by take-or-pay contracts.	Natural Gas Pipelines (Midstream activities)
Diamond M Field acquisition $13 million (June 2023)	We acquired the Diamond M Field asset which is located directly adjacent to our existing SACROC field. The field is currently under waterflood but is expected to be very receptive to CO2 flooding given its proximity to SACROC. We expect to begin implementation of enhanced oil recovery in 2024.	CO2 (Oil and Gas Producing activities)

2024 Dividends and Discretionary Capital

We expect to declare dividends of ~~$1.08~~$1.15 per share for ~~2021,~~2024, a 3%2% increase from the ~~2020~~2023 declared dividends of ~~$1.05~~$1.13 per share. We also expect to invest ~~$0.8~~$2.3 billion in expansion projects and contributions to joint ventures, or discretionary capital expenditures, during ~~2021.~~2024.

The expectations for ~~2021~~2024 discussed above involve risks, uncertainties and assumptions, and are not guarantees of performance. Many of the factors that will determine these expectations are beyond our ability to control or predict, and because of these uncertainties, it is advisable not to put undue reliance on any forward-looking statement. Please read ~~our Item 1A “Risk Factors” below and~~ “Information Regarding Forward-Looking Statements” at the beginning of this report and Item 1A. “Risk Factors” for more information. ~~Furthermore, we plan to provide updates to these 2021 expectations when we believe previously disclosed expectations no longer have a reasonable basis.~~

Critical Accounting ~~Policies and~~ Estimates

~~Accounting standards require information in financial statements about the risks and uncertainties inherent in significant~~Critical accounting estimates and ~~the application~~assumptions involve material levels of ~~GAAP involves the exercise~~subjectivity and complex judgement to account for highly uncertain matters or matters with a high susceptibility to change, and could result in a material impact to our financial statements. Examples of ~~varying degrees of judgment. Certain amounts included in or~~

~~affecting~~certain areas that require more judgment relative to others when preparing our consolidated financial statements and related disclosures ~~must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at~~include our use of estimates in determining (i) revenue recognition; (ii) income taxes; (iii) the ~~time our financial statements are prepared. These estimates and assumptions affect the amounts we report for~~economic useful lives of our assets and ~~liabilities, our revenues~~related depletion rates; (iv) the fair values used in (a) assignment of the purchase price for a business acquisition, (b) calculations of possible asset and ~~expenses during~~equity investment impairment charges, (c) calculation for the ~~reporting period,~~annual goodwill impairment test (or interim tests if triggered), and ~~our disclosure of contingent~~(d) recording derivative contract assets and ~~liabilities at the date of our financial statements.~~liabilities; (v) reserves for environmental claims, legal fees, transportation rate cases and other litigation liabilities; (vi) provisions for credit losses; and (vii) exposures under contractual indemnifications. We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates, and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

In preparing our consolidated financial statements and related disclosures, examples of certain areas that require more judgment relative to others include our use of estimates in determining: (i) revenue recognition; (ii) income taxes; (iii) the economic useful lives of our assets and related depletion rates; (iv) the fair values used in (a) calculations of possible asset and equity investment impairment charges, and (b) calculation for the annual goodwill impairment test (or interim tests if triggered); (v) reserves for environmental claims, legal fees, transportation rate cases and other litigation liabilities; (vi) provisions for credit losses; (vii) computation of the gain or loss, if any, on assets sold in whole or in part; and (viii) exposures under contractual indemnifications.

For a summary of our significant accounting policies, see Note 2 “Summary of Significant Accounting Policies” to our consolidated financial statements and the following discussion for further information regarding critical accounting estimates and assumptions used in the preparation of our financial statements. ~~We believe that certain accounting policies are of more significance in~~For discussion on our hedging activities and related sensitivities to our estimates, see Note 14 “Risk Management”to our consolidated financial ~~statement preparation process than others, which policies are discussed~~statements and Item 7A. “Quantitative and Qualitative Disclosures About Market Risk,” respectively.

Impairments

In addition to our annual testing of impairment for goodwill, we evaluate impairment of our long-lived assets when a triggering event occurs. Management applies judgment in determining whether there is an impairment indicator. Fair value calculated for the purpose of testing our long-lived assets, including intangible assets, goodwill and equity method investments,

for impairment involves the use of significant estimates and assumptions regarding the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The estimates and assumptions can be affected by a variety of factors, including external factors such as ~~follows.~~industry and economic trends, and internal factors such as changes in our business strategy and our internal forecasts. An estimate of the sensitivity to changes in underlying assumptions of a fair value calculation is not practicable, given the numerous assumptions that can materially affect our estimates.

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

Environmental Matters

With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. We expense or capitalize, as appropriate, environmental expenditures that relate to current operations, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, we do not discount environmental liabilities to a net present value, and we recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We record at fair value, where appropriate, environmental liabilities assumed in a business combination.

Our accrual of environmental liabilities often coincides either with our completion of a feasibility study or our commitment to a formal plan of action, but generally, we recognize and/or adjust our probable environmental liabilities, if necessary or appropriate, following quarterly reviews of potential environmental issues and claims that could impact our assets or operations. In recording and adjusting environmental liabilities, we consider the effect of environmental compliance, pending legal actions against us, and potential ~~third party~~third-party liability claims. For more information on environmental matters, see Part I, Items 1 and 22. “Business and Properties—Narrative Description of Business—Environmental Matters.” For more information on our environmental disclosures, see Note 18 “Litigation and Environmental” to our consolidated financial statements.

Legal and Regulatory Matters

Many of our operations are regulated by various U.S. regulatory bodies, and we are subject to legal and regulatory matters as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. In general, we expense legal costs as incurred. When we identify contingent liabilities that are probable, we identify a range of possible costs expected to be required to resolve the matter. Generally, if no amount within this range is a better estimate than any other amount, we record a liability equal to the low end of the range. Any such liability recorded is revised as better information becomes available. Accordingly, to the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. For more information on regulatory matters, see Part I, Items 1 and 2. “Business and Properties—Narrative Description of Business—Industry Regulation.” For more information on legal proceedings, see Note 18 “Litigation and Environmental” ~~to our consolidated financial statements.~~

~~Long-lived Asset and Equity Investment Impairments~~

We evaluate long-lived assets including leases and investments for impairment whenever events or changes in circumstances indicate that our carrying amount of an asset or investment may not be recoverable. We recognize impairment losses when estimated future cash flows expected to result from our use of the asset and its eventual disposition is less than its carrying amount. Because the impairment test for long-lived assets held in use is based on undiscounted cash flows, there may be instances where an asset or asset group is not considered impaired, even when its fair value may be less than its carrying value, because the asset or asset group is recoverable based on the cash flows to be generated over the estimated life of the asset

or asset group. If the carrying value of a long-lived asset or asset group is in excess of undiscounted cash flows, we typically use discounted cash flow analyses to determine if an impairment is required.

~~For more information on our long-lived asset impairments and significant estimates and assumptions used in our evaluations, see Note 3~~ ~~“Impairments and Losses and Gains on Divestitures.”~~

~~Intangible Assets~~

Intangible assets are those assets which provide future economic benefit but have no physical substance. Identifiable intangible assets having indefinite useful economic lives, including goodwill, are not subject to regular periodic amortization, and such assets are not to be amortized until their lives are determined to be finite. Instead, the carrying amount of a recognized intangible asset with an indefinite useful life must be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We evaluate goodwill for impairment on May 31 of each year. At year end and during other interim periods we evaluate our reporting units for events and changes that could indicate that it is more likely than not that the fair value of a reporting unit could be less than its carrying amount.

Excluding goodwill, our other intangible assets include customer contracts and relationships and agreements. These intangible assets have definite lives, are being amortized in a systematic and rational manner over their estimated useful lives, and are reported separately as “Other intangibles, net” in our accompanying consolidated balance sheets.

~~For more information on our 2020 goodwill impairment evaluations and amortizable intangibles, see Note 3~~ ~~“Impairments and Losses and Gains on Divestitures”~~ ~~and Note 8~~ ~~“Goodwill”~~ ~~to our consolidated financial statements.~~

~~Hedging Activities~~

We engage in a hedging program that utilizes derivative contracts to mitigate (offset) our exposure to fluctuations in energy commodity prices, foreign currency exposure on Euro-denominated debt, and until our recent divestitures of our Canadian assets, net investments in foreign operations, and to balance our exposure to fixed and variable interest rates, and we believe that these derivative contracts are, or were in respect to our Canadian operations, generally effective in realizing these objectives. According to the provisions of GAAP, to be considered effective, changes in the value of a derivative contract or its resulting cash flows must substantially offset changes in the value or cash flows of the hedged risk, and any component excluded from the computation of the effectiveness of the derivative contract must be recognized in earnings over the life of the hedging instrument by using a systematic and rational method.

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

Employee Benefit Plans

We reflect an asset or liability for our pension and other postretirement benefit (OPEB) plans based on their overfunded or underfunded status. As of December 31, 2020, our pension plans were underfunded by~~$645 million, and our OPEB plans were overfunded by $62 million.~~ Our pension and OPEB obligations and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the rate at which we expect the compensation of our employees to increase over the plan term, the estimated cost of health care when benefits are provided under our plan and other factors. A significant assumption we utilize is the discount rate used in calculating our benefit obligations. ~~We utilize a full yield curve approach~~The selection of assumptions used in the ~~estimation~~actuarial calculations of ~~the service and interest cost components of net periodic benefit cost (credit) for~~ our pension and OPEB plans ~~which applies the specific spot rates along the yield curve used in the determination of the benefit obligation to their underlying projected cash flows. The selection of these assumptions~~ is further discussed in Note 10 ~~“Share-based~~“Share-based Compensation and Employee ~~Benefits~~”Benefits” to our consolidated financial statements.

Actual results may differ from the assumptions included in these calculations, and as a result, our estimates associated with our pension and OPEB obligations can be, and have been revised in subsequent periods. The income statement impact of the changes in the assumptions on our related benefit obligations are deferred and amortized into income over either the period of expected

future service of active participants, or over the expected future lives of inactive plan participants. ~~As of December 31, 2020, we had deferred net losses of approximately $521 million in pre-tax accumulated other comprehensive loss related to our pension and OPEB plans.~~

The following sensitivity analysis shows the estimated impact of a 1% change in the primary assumptions used in our actuarial calculations associated with our pension and OPEB plans for the year ended December 31, ~~2020:~~2023:


			Pension Benefits				OPEB
			Net benefit cost (income)		Change in funded status(a)		Net benefit cost (income)		Change in funded status(a)
			(In millions)
		Pension Benefits										Pension Benefits			OPEB
		Net benefit cost (credit)									Net benefit cost (credit)		Funded status	Net benefit cost (credit)		Funded status(a)
		(In millions)												(In millions)
One percent increase in:	One percent increase in:
Discount rates
Discount rates
Discount rates	Discount rates		$	(11)	$	215	$	—	$	21
Expected return on plan assets	Expected return on plan assets		(20)		—		(3)		—
Rate of compensation increase	Rate of compensation increase		3		(12)		—		—

One percent decrease in:	One percent decrease in:

One percent decrease in:

One percent decrease in:
Discount rates
Discount rates
Discount rates	Discount rates		12		(253)		—		(24)
Expected return on plan assets	Expected return on plan assets		20		—		3		—
Rate of compensation increase	Rate of compensation increase		(2)		11		—		—

(a)Includes amounts deferred as either accumulated other comprehensive income (loss) or as a regulatory asset or liability for certain of our regulated operations.

Income Taxes

~~Income~~We make significant judgments and estimates in determining our provision for income taxes, including our assessment of our income tax ~~expense is recorded based on an estimate of~~positions given the ~~effective tax rate in effect or to be in effect during the relevant periods. Changes in tax legislation are included~~uncertainties involved in the ~~relevant computations~~interpretation and application of complex tax laws and regulations in various taxing jurisdictions. Numerous and complex judgments and assumptions are inherent in the ~~period in which such changes are enacted. We do business in a number~~estimation of ~~states with differing laws concerning how~~future taxable income subject to each state’s tax structure is measured and at what effective rate such income is taxed. Therefore, we must make estimates of how our income will be apportioned among the various states in order to arrive at an overall effective tax rate. Changes in our effective rate, including any effect on previously recorded deferred taxes, are recorded in the period in which the need for such change is identified.

Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Deferred tax assets are reduced bywhen determining a valuation allowance, ~~for~~including factors such as future operating conditions and the ~~amount that is~~apportionment of income by state. For more likely than not to not be realized. While we have considered estimated future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance, any change in the amount that we expect to ultimately realize will be included in income in the period in which such a determination is reached.

~~In determining the deferred income tax asset and liability balances attributable~~information, see Note 5 “Income Taxes” to our investments, we apply an accounting policy that looks through our investments. The application of this policy resulted in no deferred income taxes being provided on the difference between the book and tax basis on the non-tax-deductible goodwill portion of our investments, including KMI’s investment in its wholly-owned subsidiary, KMP.consolidated financial statements.

Results of Operations

Overview

As described in further detail below, our management evaluates our performance primarily using ~~the GAAP financial measures~~Net income attributable to Kinder Morgan, Inc. and Segment earnings before DD&A expenses, including amortization of ~~Segment EBDA~~excess cost of equity investments, (EBDA) (as presented in Note 16 “~~Reportable Segments~~”“Reportable Segments”)~~, net income and net income attributable to Kinder Morgan, Inc.,~~ along with the non-GAAP financial measures of Adjusted ~~Earnings~~Net income attributable to Common Stock, and ~~DCF,~~distributable cash flow (DCF), both in the aggregate and per share for each, Adjusted Segment EBDA, Adjusted ~~EBITDA,~~ Net ~~Debt~~income attributable to Kinder Morgan, Inc., Adjusted earnings before interest, income taxes, DD&A expenses, including amortization of excess cost of equity investments, (EBITDA) and Net ~~Debt to Adjusted EBITDA.~~Debt.

GAAP Financial Measures

The Consolidated Earnings Results for the years ended December 31, ~~2020~~2023 and ~~2019~~2022 present ~~Segment EBDA, net income and net~~Net income attributable to Kinder Morgan, Inc. ~~which are~~, as prepared and presented in accordance with ~~GAAP.~~GAAP, and Segment EBDA, which is disclosed in Note 16 “Reportable Segments” pursuant to FASB ASC 280. The composition of Segment EBDA is not addressed nor prescribed by generally accepted accounting principles. Segment EBDA is a useful measure of our operating performance because it measures the operating results of our segments before DD&A and certain expenses that are generally not controllable by our business segment operating managers, such as general and administrative expenses and corporate charges, interest expense, net, and income taxes. Our general and administrative expenses and corporate charges include such items as unallocated employee benefits, insurance, rentals, unallocated litigation and environmental expenses, and shared corporate services including accounting, information technology, human resources and legal services.

Non-GAAP Financial Measures

Our non-GAAP financial measures described below should not be considered alternatives to GAAP ~~net~~Net income attributable to Kinder Morgan, Inc. or other GAAP measures and have important limitations as analytical tools. Our computations of these non-GAAP financial measures may differ from similarly titled measures used by others. You should not consider these non-GAAP financial measures in isolation or as substitutes for an analysis of our results as reported under GAAP. Management compensates for the limitations of ~~these~~our consolidated non-GAAP financial measures by reviewing our

comparable GAAP measures identified in the descriptions of consolidated non-GAAP measures below, understanding the differences between the measures and taking this information into account in its analysis and its ~~decision making~~decision-making processes.

Certain Items

Certain Items, as adjustments used to calculate our non-GAAP financial measures, are items that are required by GAAP to be reflected in ~~net~~Net income attributable to Kinder Morgan, Inc., but typically either (i) do not have a cash impact (for example, unsettled commodity hedges and asset impairments), or (ii) by their nature are separately identifiable from our normal business operations and in ~~our view~~most cases are likely to occur only sporadically (for example, certain legal settlements, enactment of new tax legislation and casualty losses). (See the tables included in “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Kinder Morgan, Inc.,” “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA” below). We also include adjustments related to joint ventures (see “Amounts from Joint Ventures” ~~below and the tables included in~~ ~~“—Consolidated Earnings Results (GAAP)—~~below). The following table summarizes our Certain Items ~~Affecting Consolidated Earnings Results,”“—Non-GAAP Financial Measures—Reconciliation of Net Income (GAAP) to Adjusted EBITDA”~~for the years ended December 31, 2023 and ~~“—Non-GAAP Financial Measures—Supplemental Information”~~ ~~below). In addition, Certain Items~~2022, which are also described in more detail in the footnotes to tables included in “—Segment Earnings Results” below.


	Year Ended December 31,
	2023		2022

Certain Items
Fair value amortization	$	—	$	(15)
Legal, environmental and other reserves	—		51
Change in fair value of derivative contracts(a)	(126)		57
Loss on impairment	67		—

Income tax Certain Items(b)	33		(37)
Other(c)	45		32
Total Certain Items(d)(e)	$	19	$	88

(a)Gains or losses are reflected when realized.

(b)Represents the income tax provision on Certain Items plus discrete income tax items. Includes the impact of KMI’s income tax provision on Certain Items affecting earnings from equity investments and is separate from the related tax provision recognized at the ~~“—DD&A, General~~investees by the joint ventures which are also taxable entities.

(d)2023 and ~~Administrative~~2022 amounts include the following amounts reported within “Earnings from equity investments” on the accompanying consolidated statements of income: (i) none and ~~Corporate Charges, Interest, net~~$1 million, respectively, included within “Change in fair value of derivative contracts” and ~~Noncontrolling Interests”~~(ii) $67 million, for the 2023 period only, included within “Loss on impairment” for a non-cash impairment related to our investment in Double Eagle Pipeline LLC in our Products Pipelines business segment (see Note 4 “Losses and Gains on Divestitures, Impairments and Other Write-downs ~~below.~~—Impairments—Investments”).

(e)2023 and 2022 amounts include, in the aggregate, $(7) million and $(11) million, respectively, included within “Interest, net” on the accompanying consolidated statements of income which consist of none and $(15) million, respectively, of “Fair value amortization” and $(7) million and $4 million, respectively, of “Change in fair value of derivative contracts.”

Adjusted ~~Earnings~~Net Income Attributable to Kinder Morgan, Inc.

Adjusted ~~Earnings~~Net Income Attributable to Kinder Morgan, Inc. (previously referred to as “Adjusted Earnings”) is calculated by adjusting ~~net~~Net income attributable to Kinder Morgan, Inc. for Certain Items. Adjusted ~~Earnings~~Net Income Attributable to Kinder Morgan, Inc. is used by us, investors and ~~certain~~other external users of our financial statements ~~to assess the earnings of~~as a supplemental measure that provides decision-useful information regarding our ~~business excluding Certain Items as another reflection of our~~period-over-period performance and ability to generate ~~earnings.~~earnings that are core to our ongoing operations. We believe the GAAP measure most directly comparable to Adjusted ~~Earnings~~Net Income Attributable to Kinder Morgan, Inc. is ~~net~~Net income attributable to Kinder Morgan, Inc. ~~Adjusted Earnings per share uses Adjusted Earnings and applies the same two-class method used in arriving at basic earnings per common share.~~ See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. ~~(GAAP)~~ to Adjusted ~~Earnings~~Net Income Attributable to ~~DCF”~~Kinder Morgan, Inc.”

Adjusted Net Income Attributable to Common Stock and Adjusted EPS

Adjusted Net Income Attributable to Common Stock is calculated by adjusting Net income attributable to Kinder Morgan, Inc., the most comparable GAAP measure, for Certain Items, and further for net income allocated to participating securities and adjusted net income in excess of distributions for participating securities. We are adopting Adjusted Net Income Attributable to

Common Stock because we believe it allows for calculation of adjusted earnings per share (Adjusted EPS) on the most comparable basis with earnings per share, the most comparable GAAP measure to Adjusted EPS. Adjusted EPS is calculated as Adjusted Net Income Attributable to Common Stock divided by our weighted average shares outstanding. Adjusted EPS applies the same two-class method used in arriving at basic earnings per share. Adjusted EPS is used by us, investors and other external users of our financial statements as a per-share supplemental measure that provides decision-useful information regarding our period-over-period performance and ability to generate earnings that are core to our ongoing operations. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Common Stock” below.

DCF

DCF is calculated by adjusting ~~net~~Net income attributable to Kinder Morgan, Inc. for Certain Items, ~~(Adjusted Earnings),~~ and further byfor DD&A and amortization of excess cost of equity investments, income tax expense, cash taxes, sustaining capital expenditures and other items. We also ~~include~~adjust amounts from joint ventures for income taxes, DD&A, cash taxes and sustaining capital expenditures (see “Amounts from Joint Ventures” below). DCF is a significant performance measure ~~useful to management~~used by us, investors and other external users of our financial statements ~~in evaluating~~to evaluate our performance and ~~in measuring~~to measure and ~~estimating~~estimate the ability of our assets to generate ~~cash~~economic earnings after ~~servicing our debt,~~paying interest expense, paying cash taxes and expending sustaining ~~capital, that could be~~capital. DCF provides additional insight into the specific costs associated with our assets in the current period and facilitates period-to-period comparisons of our performance from ongoing business activities. DCF is also used by us, investors, and other external users to compare the performance of companies across our industry. DCF per share serves as the primary financial performance target for ~~discretionary~~ purposes ~~such as common stock dividends, stock repurchases, retirement~~ of ~~debt, or expansion capital expenditures.~~annual bonuses under our annual incentive compensation program and for performance-based vesting of equity compensation grants under our long-term incentive compensation program. DCF should not be used as an alternative to net cash provided by operating activities computed under GAAP. We believe the GAAP measure most directly comparable to DCF is ~~net~~Net income attributable to Kinder Morgan, Inc. DCF per ~~common~~ share is DCF divided by average outstanding ~~common~~ shares, including restricted stock awards that participate in ~~common share~~ dividends. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. ~~(GAAP) to Adjusted Earnings to DCF”~~ ~~and~~ ~~“—Adjusted Segment EBDA to Adjusted EBITDA~~ to DCF” below.

Adjusted Segment EBDA

Adjusted Segment EBDA is calculated by adjusting Segment EBDA for Certain Items attributable to the segment. Adjusted Segment EBDA is used by management in its analysis of segment performance and management of our business. We believe Adjusted Segment EBDA is a useful performance metric because it provides management, investors and other external users of our financial statements additional insight into performance trends across our business segments, our segments’ relative contributions to our consolidated performance and the ability of our segments to generate ~~cash~~ earnings on an ongoing basis. Adjusted Segment EBDA is also used as a factor in determining compensation under our annual incentive compensation program for our business segment presidents and other business segment employees. We believe it is useful to investors because it is a measure that management uses to allocate resources to our segments and assess each segment’s performance. ~~We believe the GAAP measure most directly comparable to Adjusted Segment EBDA is Segment EBDA.~~ See “—~~Consolidated Earnings Results (GAAP)—Certain Items Affecting Consolidated Earnings Results”~~ ~~for a reconciliation~~Non-GAAP Financial Measures—Reconciliation of Segment EBDA to Adjusted Segment ~~EBDA by business segment.~~EBDA” below.

Adjusted EBITDA

Adjusted EBITDA is calculated by adjusting ~~EBITDA~~Net income attributable to Kinder Morgan, Inc. for Certain ~~Items.~~Items and further for DD&A and amortization of excess cost of equity investments, income tax expense and interest. We also include amounts from joint ventures for income taxes and DD&A (see “Amounts from Joint Ventures” below). Adjusted EBITDA is used by management, investors and other external users, in conjunction with our Net Debt (as described further below), to evaluate ~~certain leverage metrics. Therefore, we believe~~our leverage. Management and external users also use Adjusted EBITDA as an important metric to compare the valuations of companies across our industry. Our ratio of Net Debt-to-Adjusted EBITDA is ~~useful to investors.~~used as a supplemental performance target for purposes of our annual incentive compensation program. We believe the GAAP measure most directly comparable to Adjusted EBITDA is ~~net income.~~Net income attributable to Kinder Morgan, Inc. See “—~~Adjusted Segment EBDA to Adjusted EBITDA to DCF”~~ ~~and~~ “—Non-GAAP Financial Measures—Reconciliation of Net Income ~~(GAAP)~~Attributable to Kinder Morgan, Inc. to Adjusted EBITDA” below.

Amounts from Joint Ventures

Certain Items, DCF and Adjusted EBITDA reflect amounts from unconsolidated joint ventures and consolidated joint ventures utilizing the same recognition and measurement methods used to record “Earnings from equity investments” and “Noncontrolling interests,” respectively. The calculations of DCF and Adjusted EBITDA related to our unconsolidated and consolidated joint ventures include the same ~~adjustments~~items (DD&A and income tax expense, and for DCF only, also cash taxes and sustaining capital expenditures) with respect to the joint ventures as those included in the calculations of DCF and Adjusted EBITDA for our wholly-owned consolidated ~~subsidiaries.~~subsidiaries; further, we remove the portion of these adjustments attributable to

non-controlling interests. (See “—Non-GAAP Financial Measures—~~Supplemental Information”~~Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA” below.) Although these amounts related to our unconsolidated joint ventures are included in the calculations of DCF and Adjusted EBITDA, such inclusion should not be understood to imply that we have control over the operations and resulting revenues, expenses or cash flows of such unconsolidated joint ventures. ~~DCF and Adjusted EBITDA are further adjusted for certain KML activities attributable to our noncontrolling interests in KML for the periods presented through KML’s sale on December 16, 2019, see~~ ~~“—Non-GAAP Financial Measures—Supplemental Information—KML Activities Prior to December 16, 2019”~~ ~~below.~~

~~Net Debt~~Non-GAAP Financial Measures

Net Debt is calculated, based on amounts as of December 31, 2020, by subtracting the following amounts from our debt balance of $34,689 million: (i) cash and cash equivalents of $1,184 million; (ii) debt fair value adjustments of $1,293 million; and (iii) the foreign exchange impact on Euro-denominated bonds of $170 million for which we have entered into currency swaps. Net Debt is aOur non-GAAP financial ~~measure that is useful~~measures described below should not be considered alternatives to investors and other users of our financial information in evaluating our leverage. We believe the most comparable measure to Net Debt is debt net of cash and cash equivalents. Our Net Debt-to-Adjusted EBITDA ratio was 4.6 as of December 31, 2020.

~~Consolidated Earnings Results (GAAP)~~

~~The following tables summarize the key components of our consolidated earnings results.~~

Year Ended December 31,
2020 2019 Earnings
increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines $ 3,483 $ 4,661 $ (1,178) (25) %
Products Pipelines 977 1,225 (248) (20) %
Terminals 1,045 1,506 (461) (31) %
CO2
(292) 681 (973) (143) %
Kinder Morgan Canada — (2) 2 100 %
Total segment EBDA 5,213 8,071 (2,858) (35) %
DD&A (2,164) (2,411) 247 10 %
Amortization of excess cost of equity investments (140) (83) (57) (69) %
General and administrative and corporate charges (653) (611) (42) (7) %
Interest, net (1,595) (1,801) 206 11 %
Income before income taxes 661 3,165 (2,504) (79) %
Income tax expense (481) (926) 445 48 %
Net income 180 2,239 (2,059) (92) %
Net income attributable to noncontrolling interests (61) (49) (12) (24) %
Net income attributable to Kinder Morgan, Inc. $ 119 $ 2,190 $ (2,071) (95) %

~~(a)~~Includes revenues, earnings from equity investments, and other, net, less operating expenses, loss (gain) on impairments and divestitures, net, and other income, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.

~~Year Ended December 31, 2020 vs. 2019~~

GAAP Net income attributable to Kinder Morgan, Inc. ~~decreased $2,071 million~~or other GAAP measures and have important limitations as analytical tools. Our computations of these non-GAAP financial measures may differ from similarly titled measures used by others. You should not consider these non-GAAP financial measures in ~~2020 compared to 2019. The decrease was due primarily to $1,950 million of non-cash impairments of goodwill associated with our Natural Gas Pipelines Non-Regulated and CO~~2 ~~reporting units and non-cash impairments of certain oil and gas producing assets in our CO~~2 ~~business segment. The decrease in results was further impacted by lower earnings from all~~isolation or as substitutes for an analysis of our ~~business segments primarily attributable to COVID-19-related reduced energy demand and commodity price impacts and~~results as reported under GAAP. Management compensates for the ~~impact~~limitations of ~~the KML and U.S. Cochin Sale in the fourth quarter of 2019 on~~ our ~~Natural Gas Pipelines and Terminals business segments, partially offset~~consolidated non-GAAP financial measures by ~~the benefit of completed expansion projects in~~reviewing our ~~Natural Gas Pipelines business segment, by lower interest expense and DD&A expense, and by lower income tax expense due to 2019 income taxes related to the KML and U.S. Cochin Sale.~~

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Certain Items ~~Affecting Consolidated Earnings Results~~

Year Ended December 31,
2020 2019
GAAP Certain Items Adjusted GAAP Certain Items Adjusted Adjusted amounts
increase/(decrease) to earnings
(In millions)
Segment EBDA
Natural Gas Pipelines $ 3,483 $ 983 $ 4,466 $ 4,661 $ (51) $ 4,610 $ (144)
Products Pipelines 977 50 1,027 1,225 33 1,258 (231)
Terminals 1,045 (55) 990 1,506 (332) 1,174 (184)
CO2
(292) 944 652 681 26 707 (55)
Kinder Morgan Canada — — — (2) 2 — —
Total Segment EBDA(a) 5,213 1,922 7,135 8,071 (322) 7,749 (614)
DD&A and amortization of excess cost of equity investments (2,304) — (2,304) (2,494) — (2,494) 190
General and administrative and corporate charges(a) (653) 92 (561) (611) 13 (598) 37
Interest, net(a) (1,595) (15) (1,610) (1,801) (15) (1,816) 206
Income before income taxes 661 1,999 2,660 3,165 (324) 2,841 (181)
Income tax expense(b) (481) (107) (588) (926) 299 (627) 39
Net income 180 1,892 2,072 2,239 (25) 2,214 (142)
Net income attributable to noncontrolling interests(a) (61) — (61) (49) (4) (53) (8)
Net income attributable to Kinder Morgan, Inc. $ 119 $ 1,892 $ 2,011 $ 2,190 $ (29) $ 2,161 $ (150)

~~(a)~~

~~For a more detailed discussion of these~~ Certain Items, ~~see~~as adjustments used to calculate our non-GAAP financial measures, are items that are required by GAAP to be reflected in Net income attributable to Kinder Morgan, Inc., but typically either (i) do not have a cash impact (for example, unsettled commodity hedges and asset impairments), or (ii) by their nature are separately identifiable from our normal business operations and in most cases are likely to occur only sporadically (for example, certain legal settlements, enactment of new tax legislation and casualty losses). (See the tables included in “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Kinder Morgan, Inc.,” “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA” below). We also include adjustments related to joint ventures (see “Amounts from Joint Ventures” below). The following table summarizes our Certain Items for the years ended December 31, 2023 and 2022, which are also described in more detail in the footnotes to ~~the~~ tables ~~within~~included in “—Segment Earnings Results” ~~and “—DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests”~~ below.


	Year Ended December 31,
	2023		2022

Certain Items
Fair value amortization	$	—	$	(15)
Legal, environmental and other reserves	—		51
Change in fair value of derivative contracts(a)	(126)		57
Loss on impairment	67		—

Income tax Certain Items(b)	33		(37)
Other(c)	45		32
Total Certain Items(d)(e)	$	19	$	88

(a)Gains or losses are reflected when realized.

(b)~~The combined net effect of the Certain Items represents~~Represents the income tax provision on Certain Items plus discrete income tax items. Includes the impact of KMI’s income tax provision on Certain Items affecting earnings from equity investments and is separate from the related tax provision recognized at the investees by the joint ventures which are also taxable entities.

(d)2023 and 2022 amounts include the following amounts reported within “Earnings from equity investments” on the accompanying consolidated statements of income: (i) none and $1 million, respectively, included within “Change in fair value of derivative contracts” and (ii) $67 million, for the 2023 period only, included within “Loss on impairment” for a non-cash impairment related to our investment in Double Eagle Pipeline LLC in our Products Pipelines business segment (see Note 4 “Losses and Gains on Divestitures, Impairments and Other Write-downs—Impairments—Investments”).

Adjusted Net Income Attributable to Kinder Morgan, Inc.

Adjusted Net Income Attributable to Kinder Morgan, Inc. (previously referred to as “Adjusted Earnings”) is calculated by adjusting Net income attributable to Kinder Morgan, Inc. ~~adjusted~~for Certain Items. Adjusted Net Income Attributable to Kinder Morgan, Inc. is used by us, investors and other external users of our financial statements as a supplemental measure that provides decision-useful information regarding our period-over-period performance and ability to generate earnings that are core to our ongoing operations. We believe the GAAP measure most directly comparable to Adjusted Net Income Attributable to Kinder Morgan, Inc. is Net income attributable to Kinder Morgan, Inc. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Kinder Morgan, Inc.”

Adjusted Net Income Attributable to Common Stock and Adjusted EPS

Adjusted Net Income Attributable to Common Stock is calculated by adjusting Net income attributable to Kinder Morgan, Inc., the most comparable GAAP measure, for Certain Items, ~~(Adjusted Earnings) decreased by $150 million from the prior year~~ and ~~was primarily due~~further for net income allocated to ~~lower earnings from all~~participating securities and adjusted net income in excess of ~~our business segments primarily attributable~~distributions for participating securities. We are adopting Adjusted Net Income Attributable to COVID-19-related reduced energy demand and commodity price impacts and the impact of the KML and U.S. Cochin Sale in the fourth quarter of 2019 on our Natural Gas Pipelines and Terminals business segments, partially offset by the benefit of completed expansion projects in our Natural Gas Pipelines business segment and by lower interest expense and DD&A expense.

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DCF

DCF is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items, and further for DD&A and amortization of excess cost of equity investments, income tax expense, cash taxes, sustaining capital expenditures and other items. We also adjust amounts from joint ventures for income taxes, DD&A, cash taxes and sustaining capital expenditures (see “Amounts from Joint Ventures” below). DCF is a significant performance measure used by us, investors and other external users of our financial statements to evaluate our performance and to measure and estimate the ability of our assets to generate economic earnings after paying interest expense, paying cash taxes and expending sustaining capital. DCF provides additional insight into the specific costs associated with our assets in the current period and facilitates period-to-period comparisons of our performance from ongoing business activities. DCF is also used by us, investors, and other external users to compare the performance of companies across our industry. DCF per share serves as the primary financial performance target for purposes of annual bonuses under our annual incentive compensation program and for performance-based vesting of equity compensation grants under our long-term incentive compensation program. DCF should not be used as an alternative to net cash provided by operating activities computed under GAAP. We believe the GAAP measure most directly comparable to DCF is Net income attributable to Kinder Morgan, Inc. DCF per share is DCF divided by average outstanding shares, including restricted stock awards that participate in dividends. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF” below.

Adjusted Segment EBDA

Adjusted Segment EBDA is calculated by adjusting Segment EBDA for Certain Items attributable to the segment. Adjusted Segment EBDA is used by management in its analysis of segment performance and management of our business. We believe Adjusted Segment EBDA is a useful performance metric because it provides management, investors and other external users of our financial statements additional insight into performance trends across our business segments, our segments’ relative contributions to our consolidated performance and the ability of our segments to generate earnings on an ongoing basis. Adjusted Segment EBDA is also used as a factor in determining compensation under our annual incentive compensation program for our business segment presidents and other business segment employees. We believe it is useful to investors because it is a measure that management uses to allocate resources to our segments and assess each segment’s performance. See “—Non-GAAP Financial Measures—Reconciliation of Segment EBDA to Adjusted Segment EBDA” below.

Adjusted EBITDA

Adjusted EBITDA is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items and further for DD&A and amortization of excess cost of equity investments, income tax expense and interest. We also include amounts from joint ventures for income taxes and DD&A (see “Amounts from Joint Ventures” below). Adjusted EBITDA is used by management, investors and other external users, in conjunction with our Net Debt (as described further below), to evaluate our leverage. Management and external users also use Adjusted EBITDA as an important metric to compare the valuations of companies across our industry. Our ratio of Net Debt-to-Adjusted EBITDA is used as a supplemental performance target for purposes of our annual incentive compensation program. We believe the GAAP measure most directly comparable to Adjusted EBITDA is Net income attributable to Kinder Morgan, Inc. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA” below.

Amounts from Joint Ventures

Certain Items, DCF and Adjusted EBITDA reflect amounts from unconsolidated joint ventures and consolidated joint ventures utilizing the same recognition and measurement methods used to record “Earnings from equity investments” and “Noncontrolling interests,” respectively. The calculations of DCF and Adjusted EBITDA related to our unconsolidated and consolidated joint ventures include the same items (DD&A and income tax expense, and for DCF only, also cash taxes and sustaining capital expenditures) with respect to the joint ventures as those included in the calculations of DCF and Adjusted EBITDA for our wholly-owned consolidated subsidiaries; further, we remove the portion of these adjustments attributable to

non-controlling interests. (See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA” below.) Although these amounts related to our unconsolidated joint ventures are included in the calculations of DCF and Adjusted EBITDA, such inclusion should not be understood to imply that we have control over the operations and resulting revenues, expenses or cash flows of such unconsolidated joint ventures.

Non-GAAP Financial Measures

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

Certain Items

Certain Items, as adjustments used to calculate our non-GAAP financial measures, are items that are required by GAAP to be reflected in Net income attributable to Kinder Morgan, Inc., but typically either (i) do not have a cash impact (for example, unsettled commodity hedges and asset impairments), or (ii) by their nature are separately identifiable from our normal business operations and in most cases are likely to occur only sporadically (for example, certain legal settlements, enactment of new tax legislation and casualty losses). (See the tables included in “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Kinder Morgan, Inc.,” “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA” below). We also include adjustments related to joint ventures (see “Amounts from Joint Ventures” below). The following table summarizes our Certain Items for the years ended December 31, 2023 and 2022, which are also described in more detail in the footnotes to tables included in “—Segment Earnings Results” below.


	Year Ended December 31,
	2023		2022

Certain Items
Fair value amortization	$	—	$	(15)
Legal, environmental and other reserves	—		51
Change in fair value of derivative contracts(a)	(126)		57
Loss on impairment	67		—

Income tax Certain Items(b)	33		(37)
Other(c)	45		32
Total Certain Items(d)(e)	$	19	$	88

(a)Gains or losses are reflected when realized.

(b)Represents the income tax provision on Certain Items plus discrete income tax items. Includes the impact of KMI’s income tax provision on Certain Items affecting earnings from equity investments and is separate from the related tax provision recognized at the investees by the joint ventures which are also taxable entities.

Adjusted Net Income Attributable to Kinder Morgan, Inc.

Adjusted Net Income Attributable to Kinder Morgan, Inc. (previously referred to as “Adjusted Earnings”) is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items. Adjusted Net Income Attributable to Kinder Morgan, Inc. is used by us, investors and other external users of our financial statements as a supplemental measure that provides decision-useful information regarding our period-over-period performance and ability to generate earnings that are core to our ongoing operations. We believe the GAAP measure most directly comparable to Adjusted Net Income Attributable to Kinder Morgan, Inc. is Net income attributable to Kinder Morgan, Inc. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Kinder Morgan, Inc.”

Adjusted Net Income Attributable to Common Stock and Adjusted EPS

Adjusted Net Income Attributable to Common Stock is calculated by adjusting Net income attributable to Kinder Morgan, Inc., the most comparable GAAP measure, for Certain Items, and further for net income allocated to participating securities and adjusted net income in excess of distributions for participating securities. We are adopting Adjusted Net Income Attributable to

DCF

Adjusted Segment EBDA

Adjusted Segment EBDA is calculated by adjusting Segment EBDA for Certain Items attributable to the segment. Adjusted Segment EBDA is used by management in its analysis of segment performance and management of our business. We believe Adjusted Segment EBDA is a useful performance metric because it provides management, investors and other external users of our financial statements additional insight into performance trends across our business segments, our segments’ relative contributions to our consolidated performance and the ability of our segments to generate earnings on an ongoing basis. Adjusted Segment EBDA is also used as a factor in determining compensation under our annual incentive compensation program for our business segment presidents and other business segment employees. We believe it is useful to investors because it is a measure that management uses to allocate resources to our segments and assess each segment’s performance. See “—Non-GAAP Financial Measures—Reconciliation of Segment EBDA to Adjusted Segment EBDA” below.

Adjusted EBITDA

Amounts from Joint Ventures

Certain Items, DCF and Adjusted EBITDA reflect amounts from unconsolidated joint ventures and consolidated joint ventures utilizing the same recognition and measurement methods used to record “Earnings from equity investments” and “Noncontrolling interests,” respectively. The calculations of DCF and Adjusted EBITDA related to our unconsolidated and consolidated joint ventures include the same items (DD&A and income tax expense, and for DCF only, also cash taxes and sustaining capital expenditures) with respect to the joint ventures as those included in the calculations of DCF and Adjusted EBITDA for our wholly-owned consolidated subsidiaries; further, we remove the portion of these adjustments attributable to

Net Debt

Net Debt is calculated, based on amounts as of December 31, 2023, by subtracting the following amounts from our debt balance of $32,116 million: (i) cash and cash equivalents of $83 million; (ii) debt fair value adjustments of $187 million; and (iii) the foreign exchange impact on Euro-denominated bonds of $9 million for which we have entered into currency swaps to convert that debt to U.S. dollars. Net Debt, on its own and in conjunction with our Adjusted EBITDA as part of a ratio of Net Debt-to-Adjusted EBITDA, is a non-GAAP financial measure that is used by management, investors and other external users of our financial information to evaluate our leverage. Our ratio of Net Debt-to-Adjusted EBITDA is also used as a supplemental performance target for purposes of our annual incentive compensation program. We believe the most comparable measure to Net Debt is total debt.

Consolidated Earnings Results

The following tables summarize the key components of our consolidated earnings results.


	Year Ended December 31,
	2023		2022		Earnings increase/(decrease)
	(In millions, except percentages)
Revenues	$	15,334	$	19,200	$	(3,866)	(20)	%
Operating Costs, Expenses and Other
Costs of sales (exclusive of items shown separately below)	(4,938)		(9,255)		4,317		47	%
Operations and maintenance	(2,807)		(2,655)		(152)		(6)	%
DD&A	(2,250)		(2,186)		(64)		(3)	%
General and administrative	(668)		(637)		(31)		(5)	%
Taxes, other than income taxes	(421)		(441)		20		5	%
Gain on divestitures and impairments, net	15		32		(17)		(53)	%
Other (expense) income, net	(2)		7		(9)		(129)	%
Total Operating Costs, Expenses and Other	(11,071)		(15,135)		4,064		27	%
Operating Income	4,263		4,065		198		5	%
Other Income (Expense)
Earnings from equity investments	838		803		35		4	%
Amortization of excess cost of equity investments	(66)		(75)		9		12	%
Interest, net	(1,797)		(1,513)		(284)		(19)	%
Other, net	(37)		55		(92)		(167)	%
Total Other Expense	(1,062)		(730)		(332)		(45)	%
Income Before Income Taxes	3,201		3,335		(134)		(4)	%
Income Tax Expense	(715)		(710)		(5)		(1)	%
Net Income	2,486		2,625		(139)		(5)	%
Net Income Attributable to Noncontrolling Interests	(95)		(77)		(18)		(23)	%
Net Income Attributable to Kinder Morgan, Inc.	$	2,391	$	2,548	$	(157)	(6)	%
Basic and diluted earnings per share	$	1.06	$	1.12	$	(0.06)	(5)	%
Basic and diluted weighted average shares outstanding	2,234		2,258		(24)		(1)	%
Declared dividends per share	$	1.13	$	1.11	$	0.02	2	%

Our consolidated revenues include fees for transportation and other midstream services that we perform. Fluctuations in our consolidated services revenue largely reflect changes in volumes and/or in the rates we charge. Our consolidated costs of sales and sales revenues also include purchases and sales of natural gas and products (which means, collectively, NGL, crude oil, CO2 and transmix) and related derivative activity. Our consolidated sales revenue will fluctuate with commodity prices and volumes, and the associated costs of sales will usually have a commensurate and offsetting impact, except for the CO2 segment, which produces, instead of purchases, the crude oil and CO2 it sells. Additionally, fluctuations in revenues and costs of sales may be further impacted by gains or losses from derivative contracts that we use to manage our commodity price risk.

Below is a discussion of significant changes in our Consolidated Earnings Results for the comparable years ended 2023 and 2022:

Revenues

Revenues decreased $3,866 million in 2023 compared to 2022. The decrease was primarily due to lower natural gas sales of $3,616 million and lower product sales of $1,029 million driven primarily by lower commodity prices partially offset by the impact of derivative contracts used to hedge commodity sales of $532 million, which includes both realized and unrealized gains and losses from derivatives. These decreases in revenues were offset by corresponding decreases in our costs of sales as described below under “Operating Costs, Expenses and Other—Costs of sales.”

Operating Costs, Expenses and Other

Costs of Sales

Costs of sales decreased $4,317 million in 2023 compared to 2022. The decrease was primarily due to lower costs of sales for natural gas of $3,587 million and for products of $622 million driven primarily by lower commodity prices. Costs of sales was further reduced by $73 million for the impacts of derivative contracts used to hedge commodity purchases which includes both realized and unrealized gains and losses from derivatives.

Operations and Maintenance

Operations and maintenance increased $152 million in 2023 compared to 2022. The increase was primarily driven by higher labor and other expenses, including integrity costs and services, fuel costs and materials and supplies, related to greater activity levels and inflation, partially offset by lower legal costs due to a legal reserve established in the 2022 period associated with the EPNG pipeline rupture.

Other Income (Expense)

Interest, net

In the table above, we report our interest expense as “net,” meaning that we have subtracted interest income and capitalized interest from our total interest expense to arrive at one interest amount. Our interest expense, net increased $284 million in 2023 compared to 2022. The increase was primarily due to higher interest rates associated with fixed-to-floating interest rate swaps.

Other, net

Other, net changed $92 million in 2023 compared to 2022. The unfavorable change was primarily due to increased pension costs resulting from higher interest rates, declining pension asset performance and adjustments related to settlements made by our pension plans partially offset by a payment made in the 2022 period associated with the bankruptcy settlement involving our former equity investee, Ruby.

Non-GAAP Financial Measures

Reconciliation of Net Income Attributable to Kinder Morgan, Inc. ~~(GAAP)~~ to Adjusted ~~Earnings~~Net Income Attributable to ~~DCF~~Kinder Morgan, Inc.

Year Ended December 31,
2020 2019
(In millions)
Net income attributable to Kinder Morgan Inc. (GAAP) $ 119 $ 2,190
Total Certain Items 1,892 (29)
Adjusted Earnings(a) 2,011 2,161
DD&A and amortization of excess cost of equity investments for DCF(b) 2,671 2,867
Income tax expense for DCF(a)(b) 670 714
Cash taxes(c) (68) (90)
Sustaining capital expenditures(c) (658) (688)
Other items(d) (29) 29
DCF $ 4,597 $ 4,993

~~Adjusted Segment EBDA to Adjusted EBITDA to DCF~~

Year Ended December 31,
2020 2019
(In millions, except per share amounts)
Natural Gas Pipelines $ 4,466 $ 4,610
Products Pipelines 1,027 1,258
Terminals 990 1,174
CO2
652 707
Adjusted Segment EBDA(a) 7,135 7,749
General and administrative and corporate charges(a) (561) (598)
Joint venture DD&A and income tax expense(a)(e) 449 487
Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)(a) (61) (20)
Adjusted EBITDA 6,962 7,618
Interest, net(a) (1,610) (1,816)
Cash taxes(c) (68) (90)
Sustaining capital expenditures(c) (658) (688)
KML noncontrolling interests DCF adjustments(f) — (60)
Other items(d) (29) 29
DCF $ 4,597 $ 4,993
Adjusted Earnings per common share $ 0.88 $ 0.95
Weighted average common shares outstanding for dividends(g) 2,276 2,276
DCF per common share $ 2.02 $ 2.19
Declared dividends per common share $ 1.05 $ 1.00


	Year Ended December 31,
	2023		2022
	(In millions, except per share amounts)
Net income attributable to Kinder Morgan, Inc.	$	2,391	$	2,548
Certain Items(a)
Fair value amortization	—		(15)
Legal, environmental and other reserves	—		51
Change in fair value of derivative contracts	(126)		57
Loss on impairment	67		—

Income tax Certain Items	33		(37)
Other	45		32
Total Certain Items	19		88
Adjusted Net Income Attributable to Kinder Morgan, Inc.	$	2,410	$	2,636

Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Common Stock
Net income attributable to Kinder Morgan, Inc.	$	2,391	$	2,548
Total Certain Items(b)	19		88
Net income allocated to participating securities(c)	(14)		(13)
Other(d)	—		(1)
Adjusted Net Income Attributable to Common Stock	$	2,396	$	2,622

Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF
Net income attributable to Kinder Morgan, Inc.	$	2,391	$	2,548








Total Certain Items(b)	19		88
DD&A	2,250		2,186
Amortization of excess cost of equity investments	66		75
Income tax expense(e)	682		747
Cash taxes	(11)		(13)
Sustaining capital expenditures	(868)		(761)
Amounts from joint ventures
Unconsolidated joint venture DD&A	323		323
Remove consolidated joint venture partners’ DD&A	(63)		(50)
Unconsolidated joint venture income tax expense(f)(g)	89		75
Unconsolidated joint venture cash taxes(f)	(76)		(70)
Unconsolidated joint venture sustaining capital expenditures	(163)		(148)
Remove consolidated joint venture partners’ sustaining capital expenditures	9		8
Other items(h)	67		(38)
DCF	$	4,715	$	4,970

Adjusted EPS	$	1.07	$	1.16
Weighted average shares outstanding for dividends(i)	2,247		2,271
DCF per share	$	2.10	$	2.19
Declared dividends per share	$	1.13	$	1.11

(a)~~Amounts are adjusted for Certain Items.~~ See ~~tables~~table included in ““—Overview—Non-GAAP Financial Measures—Certain Items” above.

(b)See “—Non-GAAP Financial Measures—Reconciliation of Net Income ~~(GAAP)~~Attributable to Kinder Morgan, Inc. to Adjusted ~~EBITDA”~~ ~~and~~ ~~“—Supplemental Information”~~ ~~below.~~Net Income Attributable to Common Stock” for a detailed listing.

~~(b)~~(c)~~Includes DD&A~~Net income allocated to common stock and participating securities is based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings, as applicable.

(d)Adjusted net income in excess of distributions for participating securities.

(e)To avoid duplication, adjustments for income tax expense ~~as applicable, from joint ventures. 2019~~ for 2023 and 2022 exclude $33 million and $(37) million, which amounts are ~~also net~~already included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.

(f)Associated with our Citrus, NGPL Holdings and Products (SE) Pipe Line equity investments.

(g)Includes the tax provision on Certain Items recognized by the investees that are taxable entities. The impact of ~~DD&A or~~KMI’s income tax ~~expense attributable to KML noncontrolling interests.~~provision on Certain Items affecting earnings from equity investments is included within “Certain Items.” See ~~tables~~table included in ““—~~Supplemental Information”~~ Overview—Non-GAAP Financial Measures—~~below.~~Certain Items” above.

~~(c)~~(h)Includes ~~cash taxes or sustaining capital expenditures, as applicable, from joint ventures. See tables included in~~ ~~“—Supplemental Information”~~ ~~below.~~

~~(d)Includes pension contributions and~~ non-cash pension expense, ~~and~~ non-cash compensation associated with our restricted stock ~~program.~~

~~(e)Represents joint venture DD&A~~program and ~~income tax expense. See tables included in~~ ~~“—Supplemental Information”~~ ~~below.~~pension contributions.

~~(f)2019 amount represents the combined net income, DD&A and income tax expense adjusted for Certain Items, as applicable, attributable to KML noncontrolling interests. See table included in~~ ~~“—Supplemental Information”~~ ~~below.~~

~~(g)~~(i)Includes restricted stock awards that participate in ~~common share~~ dividends.

Reconciliation of Net Income ~~(GAAP)~~Attributable to Kinder Morgan, Inc. to Adjusted EBITDA

Year Ended December 31,
2020 2019
(In millions)
Net income (GAAP) $ 180 $ 2,239
Certain Items:
Fair value amortization (21) (29)
Legal, environmental and taxes other than income tax reserves 26 46
Change in fair value of derivative contracts(a) (5) (24)
Loss (gain) on impairments and divestitures, net(b) 327 (280)
Loss on impairment of goodwill(c) 1,600 —
Restricted stock accelerated vesting and severance 52 —
COVID-19 costs 15 —
Income tax Certain Items (107) 299
Noncontrolling interests associated with Certain Items — (4)
Other 5 (37)
Total Certain Items(d) 1,892 (29)
DD&A and amortization of excess cost of equity investments 2,304 2,494
Income tax expense(e) 588 627
Joint venture DD&A and income tax expense(e)(f) 449 487
Interest, net(e) 1,610 1,816
Net income attributable to noncontrolling interests (net of KML noncontrolling interests(e)) (61) (16)
Adjusted EBITDA $ 6,962 $ 7,618


	Year Ended December 31,
	2023		2022
	(In millions)
Net income attributable to Kinder Morgan, Inc.	$	2,391	$	2,548
Certain Items(a)
Fair value amortization	—		(15)
Legal, environmental and other reserves	—		51
Change in fair value of derivative contracts	(126)		57
Loss on impairment	67		—




Income tax Certain Items	33		(37)


Other	45		32
Total Certain Items	19		88
DD&A	2,250		2,186
Amortization of excess cost of equity investments	66		75
Income tax expense(b)	682		747
Interest, net(c)	1,804		1,524
Amounts from joint ventures
Unconsolidated joint venture DD&A	323		323
Remove consolidated joint venture partners’ DD&A	(63)		(50)
Unconsolidated joint venture income tax expense(d)	89		75
Adjusted EBITDA	$	7,561	$	7,516

(a)~~Gains or losses are reflected in our DCF when realized.~~

~~(b)2020 amount includes: (i) a pre-tax non-cash impairment loss of $350 million related to oil and gas producing assets in our CO~~2 business segment driven by low oil prices and (ii) $21 million for asset impairments in our Products Pipelines business segment, which are reported within “Loss (gain) on impairments and divestitures, net” on the accompanying consolidated statement of income. 2019 amount primarily includes: (i) a $1,296 million pre-tax gain on the KML and U.S. Cochin Sale and a pre-tax loss of $364 million for asset impairments, related to gathering and processing assets in Oklahoma and northern Texas in our Natural Gas Pipelines business segment and oil and gas producing assets in our CO2 business segment, which are reported within “Loss (gain) on impairments and divestitures, net” on the accompanying consolidated statement of income and (ii) a pre-tax $650 million loss for an impairment of our investment in Ruby Pipeline which is reported within “Earnings from equity investments” on the accompanying consolidated statement of income.

~~(d)2020 and 2019 amounts include $(4) million and $634 million, respectively, reported within “Earnings from equity investments” on our accompanying consolidated statements of income.~~

~~(e)Amounts are adjusted for Certain Items. See tables included in~~ ~~“—Supplemental Information”~~ ~~and~~ ~~“—DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests”~~ ~~below.~~

~~(f)Represents joint venture DD&A and income tax expense.~~ See table included in ““—~~Supplemental Information”~~ Overview—Non-GAAP Financial Measures—~~below.~~Certain Items” above.

(b)To avoid duplication, adjustments for income tax expense for 2023 and 2022 exclude $33 million and $(37) million, which amounts are already included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.

(c)To avoid duplication, adjustments for interest, net for 2023 and 2022 exclude $(7) million and $(11) million, respectively, which amounts are already included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items,” above.

(d)Includes that tax provision on Certain Items recognized by the investees that are taxable entities associated with our Citrus, NGPL Holdings and Products (SE) Pipe Line equity investments. The impact of KMI’s income tax provision on Certain Items affecting earnings from equity investments is included within “Certain Items” above.

4749

~~Supplemental Information~~Below is a discussion of significant changes in our Adjusted Net Income Attributable to Kinder Morgan, Inc., DCF and Adjusted EBITDA:

Year Ended December 31,
2020 2019
(In millions)
DD&A (GAAP) $ 2,164 $ 2,411
Amortization of excess cost of equity investments (GAAP) 140 83
DD&A and amortization of excess cost of equity investments 2,304 2,494
Joint venture DD&A 367 392
DD&A attributable to KML noncontrolling interests — (19)
DD&A and amortization of excess cost of equity investments for DCF $ 2,671 $ 2,867
Income tax expense (GAAP) $ 481 $ 926
Certain Items 107 (299)
Income tax expense(a) 588 627
Unconsolidated joint venture income tax expense(a)(b) 82 95
Income tax expense attributable to KML noncontrolling interests(a) — (8)
Income tax expense for DCF(a) $ 670 $ 714
KML activities prior to December 16, 2019
Net income attributable to KML noncontrolling interests $ — $ 29
KML noncontrolling interests associated with Certain Items — 4
KML noncontrolling interests(a) — 33
DD&A attributable to KML noncontrolling interests — 19
Income tax expense attributable to KML noncontrolling interests(a) — 8
KML noncontrolling interests DCF adjustments(a) $ — $ 60
Net income attributable to noncontrolling interests (GAAP) $ 61 $ 49
Less: KML noncontrolling interests(a) — 33
Net income attributable to noncontrolling interests (net of KML noncontrolling interests(a)) 61 16
Noncontrolling interests associated with Certain Items — 4
Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items) $ 61 $ 20
Additional joint venture information
Unconsolidated joint venture DD&A $ 407 $ 411
Less: Consolidated joint venture partners’ DD&A 40 19
Joint venture DD&A 367 392
Unconsolidated joint venture income tax expense(a)(b) 82 95
Joint venture DD&A and income tax expense(a) $ 449 $ 487
Unconsolidated joint venture cash taxes(b) $ (62) $ (61)
Unconsolidated joint venture sustaining capital expenditures $ (120) $ (114)
Less: Consolidated joint venture partners’ sustaining capital expenditures (6) (6)
Joint venture sustaining capital expenditures $ (114) $ (108)


	Year Ended December 31,
	2023		2022
	(In millions)
Adjusted Net Income Attributable to Kinder Morgan, Inc.	$	2,410	$	2,636
DCF	4,715		4,970
Adjusted EBITDA	7,561		7,516

Change from prior period	Increase/(Decrease)
Adjusted Net Income Attributable to Kinder Morgan, Inc.	$	(226)
DCF	$	(255)
Adjusted EBITDA	$	45

~~(a)Amounts are adjusted for Certain Items.~~

~~(b)~~Adjusted Net Income Attributable to Kinder Morgan, Inc. decreased ~~Amounts are~~$226 million in 2023 compared to 2022. The decrease was primarily driven by higher interest expense. Higher interest expense also affected DCF. The$255 million decrease in DCF in 2023 compared to 2022 was further impacted by an increase in sustaining capital expenditures. Adjusted EBITDA increased $45 million in 2023 compared to 2022. The increase was due to favorable margins from settled derivatives on our Natural Gas Pipeline business segment partially offset by overall lower commodity prices across our business segments.

General and Administrative and Corporate Charges


	Year Ended December 31,
	2023		2022
	(In millions)
General and administrative	$	(668)	$	(637)
Corporate (charges) benefit, net	(91)		44
Certain Items	45		6
General and administrative and corporate charges	$	(714)	$	(587)

Change from prior period	Earnings increase/(decrease)
General and administrative	$	(31)
Corporate (charges) benefit, net	(135)
Total	$	(166)

General and administrative expenses increased $31 million and corporate (charges) benefit increased $135 million in 2023 compared to 2022. The combined changes were primarily due to higher pension costs of $95 million resulting from higher interest rates and declining pension asset performance, and higher labor and benefit-related costs of $39 million. In addition, the combined changes include the impact of increased pension costs of $45 million in 2023 related to settlements made by our pension plans and increased costs of $6 million in 2022 associated with ~~our Citrus, NGPL and PPL pipeline equity investments.~~the Ruby bankruptcy, which we treated as Certain Items.

4850

Reconciliation of Segment EBDA to Adjusted Segment EBDA


	Year Ended December 31,
	2023		2022
	(In millions)
Segment EBDA(a)
Natural Gas Pipelines Segment EBDA	$	5,282	$	4,801
Certain Items(b)
Legal, environmental and other reserves	—		51
Change in fair value of derivative contracts	(122)		64

Other	—		26

Natural Gas Pipelines Adjusted Segment EBDA	$	5,160	$	4,942

Products Pipelines Segment EBDA	$	1,062	$	1,107
Certain Items(b)
Change in fair value of derivative contracts	(1)		—
Loss on impairment	67		—

Products Pipelines Adjusted Segment EBDA	$	1,128	$	1,107

Terminals Segment EBDA	$	1,040	$	975






CO2 Segment EBDA	$	689	$	819
Certain Items(b)
Change in fair value of derivative contracts	4		(11)


CO2 Adjusted Segment EBDA	$	693	$	808

(a)Includes revenues, earnings from equity investments, operating expenses, gain on divestitures and impairments, net, other (expense) income, net, and other, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes. See “—Overview—GAAP Financial Measures” above.

(b)See “—Overview—Non-GAAP Financial Measures—Certain Items” above.

Segment Earnings Results

Natural Gas Pipelines

Year Ended December 31,
2020 2019
(In millions, except operating statistics)
Revenues $ 7,259 $ 8,170
Operating expenses (3,457) (4,213)
(Loss) gain on impairments and divestitures, net (1,010) 677
Other income 1 3
Earnings (losses) from equity investments 679 (29)
Other, net 11 53
Segment EBDA 3,483 4,661
Certain Items(a) 983 (51)
Adjusted Segment EBDA $ 4,466 $ 4,610
Change from prior period Increase/(Decrease)
Adjusted Segment EBDA $ (144)
Volumetric data(b)
Transport volumes (BBtu/d) 37,487 36,793
Sales volumes (BBtu/d) 2,353 2,420
Gathering volumes (BBtu/d) 3,039 3,382
NGLs (MBbl/d) 27 32

~~Certain Items affecting Segment EBDA~~


	Year Ended December 31,
	2023		2022
	(In millions, except operating statistics)
Revenues	$	9,168	$	12,686
Costs of sales	(3,258)		(7,171)
Other operating expenses	(1,442)		(1,391)

Gain on divestitures and impairments, net	10		10

Other income	2		3
Earnings from equity investments	776		683

Other, net	26		(19)

Segment EBDA	5,282		4,801
Certain Items:
Legal, environmental and other reserves	—		51
Change in fair value of derivative contracts	(122)		64
Other	—		26
Certain Items(a)	(122)		141
Adjusted Segment EBDA	$	5,160	$	4,942

Change from prior period	Increase/(Decrease)
Segment EBDA	$	481
Adjusted Segment EBDA	$	218

Volumetric data(b)
Transport volumes (BBtu/d)	40,282		38,657
Sales volumes (BBtu/d)	2,346		2,482
Gathering volumes (BBtu/d)	3,562		2,994
NGLs (MBbl/d)	34		30

(a)~~Includes~~ See table included in “—Overview—Non-GAAP Financial Measures—Certain ~~Item amounts~~Items” above. 2023 and 2022 Certain Items of ~~$983~~(i) $(122) million and ~~$(51)~~$63 million, ~~for 2020~~respectively, are associated with our Midstream business; (ii) none and ~~2019, respectively. 2020 amount includes~~ ~~(i) a $1,000~~$1 million, ~~non-cash goodwill impairment on~~respectively, are associated with our Natural Gas Pipelines Non-Regulated reporting unit; (ii) an increase in revenues of $19 million resulting from amortization of regulatory liabilities including amounts recognized through earnings from equity investments;East business; and (iii) ~~a decrease~~none and $77 million, respectively, are associated with our West business. For more detail of significant Certain Items, see the discussion of changes in ~~revenues of $15 million related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales. 2~~Segment EBDA below.019 amount includes (i) a $957 million gain on the sale of Cochin Pipeline system; (ii) a $650 million non-cash impairment loss related to our investment in Ruby; (iii) $157 million and $133 million non-cash losses on impairments of certain gathering and processing assets in North Texas and Oklahoma, respectively; (iv) an increase in earnings of $23 million for a gain on an ownership rights contract with a joint venture partner; (v) a $16 million increase in earnings related to amortization of regulatory liabilities recognized through earnings of equity investments; and (vi) a $12 million decrease in revenues related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales.

~~Other~~

(b)Joint venture throughput is reported at our ownership share. Volumes for assets sold are excluded for all periods presented.

~~Below are the changes in Adjusted Segment EBDA between 2020 and 2019:~~

~~Year Ended December 31, 2020 versus Year Ended December 31, 2019~~

Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)
Midstream $ (254) (18)%
West Region (47) (4)%
East Region 157 7%
Total Natural Gas Pipelines $ (144) (3)%

4952

Below are the changes in Natural Gas Pipelines Segment EBDA:


	Year Ended December 31,
	2023		2022		increase/(decrease)
	(In millions)
Midstream	$	1,697	$	1,441	$	256
East	2,637		2,502		135
West	948		858		90



Total Natural Gas Pipelines	$	5,282	$	4,801	$	481

The changes in ~~Segment EBDA for our~~ Natural Gas Pipelines ~~business segment are further explained by the following discussion of the significant factors driving Adjusted~~ Segment EBDA in the comparable years of ~~2020~~2023 and ~~2019:~~2022 are explained by the following discussion:

•~~Midstream’s decrease of $254~~The $256 million (18%) increase in Midstream was affected by decreases in revenues and costs of sales related to the mark-to-market impacts of non-cash unrealized derivative contracts used to hedge forecasted commodity sales and purchases, which we treated as Certain Items.

In addition, Midstream was favorably impacted by (i) higher earnings on our Texas intrastate natural gas pipeline operations resulting from increased sales margins, which were largely driven by realized gains on sales hedges but reduced by lower commodity prices and sales volumes, and from lower pipeline integrity costs; (ii) higher earnings from our Hiland Midstream systems primarily due to ~~(i) a decrease of $142 million related to the sale of the Cochin Pipeline system on December 16, 2019 to Pembina; (ii) lower commodity prices on, a decrease in~~higher services fees resulting from higher volumes and ~~two customer bankruptcies associated with~~rates; and (iii) higher earnings on our KinderHawk assets driven by increased volumes partly reduced by higher operating expenses. These were partially offset by (i) lower service fee revenues as a result of renegotiated contracts at lower rates on our South Texas assets; ~~(iii)~~and (ii) lower commodity sales margin driven primarily by lower volumes on ~~KinderHawk; and (iv) lower contract rates on~~ our ~~North Texas~~Oklahoma assets. ~~These decreases were~~

Overall, Midstream’s revenue changes are partially offset by higher equity earnings due to the Gulf Coast Express Pipeline being placed in service in September 2019. Overall Midstream’s revenues decreased primarily due to lower commodity prices which was largely offset by corresponding ~~decreases~~changes in costs of ~~sales;~~sales.

•~~West Region’s decrease of $47~~The $135 million ~~(4%~~(5%) increase in East was primarily ~~due~~due to ~~decreases in~~(i) higher equity earnings from ~~(i) Ruby~~Midcontinent Express Pipeline Company, L.L.C. due principally to credit losses and lost revenues resulting from two of its customers’ bankruptcies; (ii) CPGPL as a result of the expiration of one shipper’s contract; and (iii) EPNGLLC, driven by ~~higher operating expenses; and~~

•~~East Region’s increase of $157 million (7%) was primarily due to increases in earnings from ELC and SLNG resulting from the liquefaction units of the Elba Liquefaction project gradually being placed~~favorable pricing on new customer contracts entered into ~~service~~ in the later part of ~~2019~~2022; (ii) higher revenues on our Stagecoach assets as a result of increased demand for its services and ~~through the first eight months of 2020, and increased equity earnings from NGPL primarily~~favorable pricing; (iii) higher revenues on TGP due to ~~higher revenues. These increases were~~increased rates on capacity sales, increased demand for its services, favorable pricing on services and an expansion project that went into service in November 2023 partially offset by ~~reduced contributions~~higher pipeline maintenance costs.

•The $90 million (10%) increase in West was primarily due to higher earnings from ~~TGP~~EPNG due to ~~the impact of the FERC 501-G rate settlement~~(i) increased revenues from favorable pricing on its ~~revenues.~~services and the return of a pipeline segment to service in February 2023 and (ii) an increase in gas sales margin, partially offset by (i) increased pipeline integrity costs on EPNG and (ii) lower revenues from Cheyenne Plains Gas Pipeline Company, L.L.C. and Wyoming Interstate Company, L.L.C., principally resulting from contract expirations in December 2022.

In addition, the West was affected by costs associated with the EPNG pipeline rupture and related litigation reserve and a payment associated with the bankruptcy settlement involving our former equity investee, Ruby, for the 2022 period only, which we treated as Certain Items.

5053

Products Pipelines

Year Ended December 31,
2020 2019
(In millions, except operating statistics)
Revenues $ 1,721 $ 1,831
Operating expenses (779) (684)
Loss on impairments and divestitures, net (21) —
Earnings from equity investments 55 72
Other, net 1 6
Segment EBDA 977 1,225
Certain Items(a) 50 33
Adjusted Segment EBDA $ 1,027 $ 1,258
Change from prior period Increase/(Decrease)
Adjusted Segment EBDA $ (231)
Volumetric data(b)
Gasoline(c) 897 1,041
Diesel fuel 375 368
Jet fuel 179 306
Total refined product volumes 1,451 1,715
Crude and condensate 552 651
Total delivery volumes (MBbl/d) 2,003 2,366

~~Certain Items affecting Segment EBDA~~


	Year Ended December 31,
	2023		2022
	(In millions, except operating statistics)
Revenues	$	3,066	$	3,418
Costs of sales	(1,588)		(1,972)
Other operating expenses	(436)		(419)
Gain on divestitures and impairments, net	—		12
Other expense	(4)		—
Earnings from equity investments	23		68

Other, net	1		—

Segment EBDA	1,062		1,107
Certain Items:
Change in fair value of derivative contracts	(1)		—
Loss on impairment	67		—
Certain Items(a)	66		—
Adjusted Segment EBDA	$	1,128	$	1,107

Change from prior period	Increase/(Decrease)
Segment EBDA	$	(45)
Adjusted Segment EBDA	$	21

Volumetric data(b)
Gasoline(c)	980		978
Diesel fuel	351		367
Jet fuel	285		264
Total refined product volumes	1,616		1,609
Crude and condensate	483		471
Total delivery volumes (MBbl/d)	2,099		2,080

(a)~~Includes~~ See table included in “—Overview—Non-GAAP Financial Measures—Certain ~~Item amounts~~Items” above. 2023 and 2022 Certain Items of ~~$50~~(i) $(1) million and none, respectively, are associated with our Southeast Refined Products business and (ii) $67 million and ~~$33 million~~ none, respectively, are associated with our Crude and Condensate business. For more detail of significant Certain Items, see the discussion of changes in the 2020 and 2019 periods, respectively. 2020 amount includes a $46 million unfavorable rate case reserve adjustment, a non-cash loss on impairment of our Belton Terminal of $21 million and a $17 million favorable adjustment for tax reserves, other than income taxes. 2019 amount primarily related to unfavorable adjustments of an environmental reserve and of tax reserves, other than income taxes.

~~Other~~Segment EBDA below.

(b)Joint venture throughput is reported at our ownership share.

(c)Volumes include ethanol pipeline volumes.

~~Below are the changes in Adjusted Segment EBDA between 2020 and 2019:~~

~~Year Ended December 31, 2020 versus Year Ended December 31, 2019~~

Adjusted Segment EBDA increase/(decrease)
(In millions, except percentages)
Crude and Condensate $ (119) (25)%
West Coast Refined Products (63) (12)%
Southeast Refined Products (49) (18)%
Total Products Pipelines $ (231) (18)%

The changes in Segment EBDA for our Products Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable years of 2020 and 2019:

•Crude and Condensate’s decrease of $119 million (25%) was primarily due to decreased earnings from Kinder Morgan Crude & Condensate Pipeline (KMCC) and the Bakken Crude assets. KMCC’s decreased earnings were primarily due to lower volumes. The Bakken Crude assets decreased earnings were primarily driven by lower volumes and reduced

re-contracted rates on Double H pipeline. KMCC and Bakken Crude assets decreases were also impacted by unfavorable inventory valuation adjustments driven by declines in commodity prices during the first quarter 2020;

•West Coast Refined Products’ decrease of $63 million (12%) was due to decreased earnings on Pacific (SFPP) operations, Calnev Pipe Line LLC and West Coast terminals driven by lower service revenues as a result of a reduction in volumes due to COVID-19; and

•Southeast Refined Products’ decrease of $49 million (18%) was primarily due to decreased earnings from our South East Terminals and a decrease in equity earnings from PPL pipeline as a result of decreased services revenues driven by lower volumes and prices due to COVID-19, and lower earnings from our Transmix processing operations driven by unfavorable inventory adjustments resulting from commodity price declines during the first quarter 2020.

~~Terminals~~

Year Ended December 31,
2020 2019
(In millions, except operating statistics)
Revenues $ 1,722 $ 2,034
Operating expenses (762) (888)
Gain on divestitures and impairments, net 49 342
Other income 1 —
Earnings from equity investments 22 23
Other, net 13 (5)
Segment EBDA 1,045 1,506
Certain Items(a) (55) (332)
Adjusted Segment EBDA $ 990 $ 1,174
Change from prior period Increase/(Decrease)
Adjusted Segment EBDA $ (184)
Volumetric data(b)
Liquids leasable capacity (MMBbl) 79.7 79.7
Liquids utilization %(c) 95.3 % 93.2 %
Bulk transload tonnage (MMtons) 48.0 55.3

~~Certain Items affecting Segment EBDA~~

~~(a)~~Includes Certain Item amounts of $(55) million and $(332) million for 2020 and 2019, respectively. 2020 amount related to a gain on sale of our Staten Island terminal and 2019 amount primarily related to a gain of $339 million on the sale of KML.

~~Other~~

~~(b)Volumes for assets sold are excluded for all periods presented.~~

~~(c)The ratio of our tankage capacity in service to tankage capacity available for service.~~

5254

Below are the changes in ~~Adjusted~~Products Pipelines Segment ~~EBDA between 2020 and 2019:~~ EBDA:

~~Year Ended December 31, 2020 versus Year Ended December 31, 2019~~

Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)
Alberta Canada $ (124) (100)%
Gulf Liquids (23) (7)%
West Coast (22) (100)%
Mid Atlantic (10) (15)%
Gulf Bulk (8) (12)%
All others (including intrasegment eliminations) 3 1%
Total Terminals $ (184) (16)%


	Year Ended December 31,
	2023		2022		increase/(decrease)
	(In millions)
Crude and Condensate	$	265	$	331	$	(66)
Southeast Refined Products	278		265		13
West Coast Refined Products	519		511		8
Total Products Pipelines	$	1,062	$	1,107	$	(45)

The changes in ~~Segment EBDA for our Terminals business segment are further explained by the following discussion of the significant factors driving Adjusted~~Products Pipelines Segment EBDA in the comparable years of ~~2020~~2023 and ~~2019:~~2022 are explained by the following discussion:

•The $66 million (20%) decrease in Crude and Condensate was affected by a decrease of $67 million to equity earnings for a non-cash impairment related to our investment in Double Eagle Pipeline LLC, which we treated as a Certain Item.

In addition, Crude and Condensate was impacted by (i) higher earnings from our Bakken assets due primarily to higher volumes and gathering rates and lower operating costs driven by favorable net changes in product gains and losses partially offset by unfavorable product pricing and (ii) an increase in equity earnings, excluding the ~~Sale~~impairment discussed above, from Double Eagle Pipeline LLC due to an increase in volumes and deficiency revenues, offset by lower earnings from Kinder Morgan Crude & Condensate pipeline driven primarily by a decrease in revenues as a result of ~~KML assets to Pembina on December 16, 2019, which accounted for the decreases on our Alberta Canada terminals~~re-contracting at lower rates and ~~our West Coast terminals;~~lower deficiency revenues. Our Crude and Condensate business also had lower revenues with a corresponding decrease in costs of sales, resulting primarily from decreased commodity pricing and volumes.

•~~decrease of $23~~The $13 million ~~(7%~~(5%) ~~from our Gulf Liquids terminals primarily~~increase in Southeast Refined Products was driven by ~~lower~~(i) an increase in equity earnings from Products (SE) Pipe Line primarily due to increased revenues driven by higher rates, volumes and ~~associated ancillary fees related~~blending activities partially offset by unfavorable net changes in product gains and losses and (ii) higher revenues on Central Florida Pipeline LLC due to ~~demand reduction attributable~~higher volumes and rates partially offset by lower earnings at our Transmix processing operations primarily due to ~~COVID-19 as well as tanks being temporarily off-lease as they are transitioned to new customers following the termination of a major customer contract;~~unfavorable product pricing.

•~~decrease of $10~~The $8 million ~~(15%~~(2%) increase in West Coast Refined Products was impacted by increased revenues from our ~~Mid Atlantic terminals primarily due to lower coal volumes at our Pier IX facility~~Pacific operations as a result of renewable diesel growth projects and higher rates partially offset by higher operating costs driven by ~~coal market weakness largely attributable to demand reduction associated with COVID-19;~~unfavorable net changes in product gains and losses, higher fuel rates, and increased labor costs and increased revenues from Calnev Pipe Line LLC driven by higher rates partially offset by a gain on sale of land in the 2022 period.

•~~decrease of $8 million (12%) from our Gulf Bulk terminals primarily due to decreased coal volumes and the impact of an expired contract in January 2020.~~

5355

Terminals


	Year Ended December 31,
	2023			2022
	(In millions, except operating statistics)
Revenues	$	1,917		$	1,792
Costs of sales	(33)			(26)
Other operating expenses	(863)			(827)
Gain on divestitures and impairments, net	1			9
Other income	1			5
Earnings from equity investments	9			14

Other, net	8			8

Segment EBDA	$	1,040		$	975



Change from prior period	Increase/(Decrease)
Segment EBDA	$	65


Volumetric data(a)
Liquids leasable capacity (MMBbl)	78.7			78.2
Liquids utilization %(b)	93.6		%	91.3		%
Bulk transload tonnage (MMtons)	53.3			53.2

(a)Volumes for facilities divested, idled, and/or held for sale are excluded for all periods presented.

(b)The ratio of our tankage capacity in service to liquids leasable capacity.

The groupings for our Terminals business segment have been updated from previous periods to reflect a more condensed presentation of Terminals Segment EBDA. For purposes of the following tables and related discussions, the results of operations of our terminals are reclassified for all periods presented from the historical business grouping. Terminals held for sale or divested, including any associated gain or loss on sale, are included within the Other group.

Below are the changes in Terminals Segment EBDA:


	Year Ended December 31,
	2023		2022		increase/(decrease)
	(In millions)
Jones Act tankers	$	177	$	146	$	31
Liquids	601		573		28
Bulk	256		243		13
Other	6		13		(7)
Total Terminals	$	1,040	$	975	$	65

The changes in Terminals Segment EBDA in the comparable years of 2023 and 2022 are explained by the following discussion:

•The $31 million (21%) increase in Jones Act tankers was primarily due to higher average charter rates.

•The $28 million (5%) increase in Liquids was primarily due to increased revenues associated with contributions from expansion projects, contractual rate escalations, re-contracting at higher rates and increased utilization partially offset by higher labor and maintenance expense.

•The $13 million (5%) increase in Bulk was primarily due to higher revenues associated with contributions from expansion projects, contractual rate escalations, higher volumes for petroleum coke and higher volumes and ancillaries for steel handling activities partially offset by reduced revenues from coal handling activities and higher labor and other operating expenses.

CO2

Year Ended December 31,
2020 2019
(In millions, except operating statistics)
Revenues $ 1,038 $ 1,219
Operating expenses (404) (496)
Loss on impairments and divestitures, net (950) (76)
Other expense — (1)
Earnings from equity investments 24 35
Segment EBDA (292) 681
Certain Items(a) 944 26
Adjusted Segment EBDA $ 652 $ 707
Change from prior period Increase/(Decrease)
Adjusted Segment EBDA $ (55)
Volumetric data
SACROC oil production 21.8 23.9
Yates oil production 6.6 7.2
Katz and Goldsmith oil production 2.8 3.8
Tall Cotton oil production 1.7 2.3
Total oil production, net (MBbl/d)(b) 32.9 37.2
NGL sales volumes, net (MBbl/d)(b) 9.5 10.1
CO2 sales volumes, net (Bcf/d)
0.4 0.6
Realized weighted average oil price ($ per Bbl) $ 53.78 $ 49.49
Realized weighted average NGL price ($ per Bbl) $ 17.95 $ 23.49

~~Certain Items affecting Segment EBDA~~


	Year Ended December 31,
	2023		2022
	(In millions, except operating statistics)
Revenues	$	1,209	$	1,334
Costs of sales	(77)		(109)
Other operating expenses	(473)		(445)
Gain on divestitures and impairments, net	1		1
Other expense	(1)		—
Earnings from equity investments	30		38


Segment EBDA	689		819
Certain Items:
Change in fair value of derivative contracts	4		(11)
Certain Items(a)	4		(11)
Adjusted Segment EBDA	$	693	$	808

Change from prior period	Increase/(Decrease)
Segment EBDA	$	(130)
Adjusted Segment EBDA	$	(115)

Volumetric data(b)
SACROC oil production(c)	20.22		20.29
Yates oil production	6.63		6.52
Other	2.32		2.75
Total oil production, net (MBbl/d)(d)	29.17		29.56
NGL sales volumes, net (MBbl/d)(d)	8.97		9.40
CO2 sales volumes, net (Bcf/d)	0.336		0.358
RNG sales volumes (BBtu/d)	6		3
Realized weighted average oil price ($ per Bbl)	$	67.42	$	66.78
Realized weighted average NGL price ($ per Bbl)	$	30.84	$	39.59

(a)~~Includes~~ See table included in “—Overview—Non-GAAP Financial Measures—Certain ~~Item amounts of $944 million~~Items” above. 2023 and ~~$26 million for 2020 and 2019, respectively. 2020 amount includes (i) a $600 million goodwill impairment on our CO~~2 reporting unit and (ii) non-cash impairments of $350 million on our oil and gas producing assets. 2019 amount includes non-cash impairments of $75 million on our oil and gas producing assets and an increase in revenues of $49 million related to mark-to-market gains2022 Certain Items are associated with ~~derivative contracts used to hedge forecasted commodity sales.~~our Oil and Gas Producing activities. For m

~~Other~~ore detail of significant Certain Items, see the discussion of changes in Segment EBDA below.

(b)Volumes for acquired assets are included for all periods presented, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition.

(c)Includes volumetric data for Diamond M.

(d)Net of royalties and outside working interests.

~~Below are the changes in Adjusted Segment EBDA between 2020 and 2019:~~

~~Year Ended December 31, 2020 versus Year Ended December 31, 2019~~

Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)
Source and Transportation activities $ (82) (28)%
Oil and Gas Producing activities 27 6%
Total CO2
$ (55) (8)%

5457

Below are the changes in CO2 Segment EBDA:


	Year Ended December 31,
	2023		2022		increase/(decrease)
	(In millions)
Oil and Gas Producing activities	$	473	$	553	$	(80)
Source and Transportation activities	187		247		(60)

Subtotal	660		800		(140)
Energy Transition Ventures activities	29		19		10
Total CO2	$	689	$	819	$	(130)

The changes in ~~Segment EBDA for our~~ CO2 ~~business segment are further explained by the following discussion of the significant factors driving Adjusted~~ Segment EBDA in the comparable years of ~~2020~~2023 and ~~2019:~~2022 are explained by the following discussion:

•The $80 million (14%) decrease in Oil and Gas Producing activities was impacted by decreases in revenues related to lower realized NGL prices and lower volumes, lower crude oil volumes and higher operating expenses partially offset by higher realized crude oil prices.

In addition, Oil and Gas Producing activities was affected by unfavorable changes in revenues related to the mark-to-market impacts of ~~$82~~non-cash unrealized derivative hedge contracts, which we treated as Certain Items.

•The $60 million ~~(28%~~(24%) ~~from our~~decrease in Source and Transportation activities was primarily due to ~~a decrease of $103 million~~lower revenues related to lower CO2 sales prices and volumes.

•The $10 million (53%) increase in Energy Transition Ventures activities was primarily driven by three additional plants placed into service during 2023 leading to higher RNG margins as a result of higher volumes, partially offset by ~~lower~~higher operating ~~expenses of $28 million; and~~

•increase of $27 million (6%) from our Oil and Gas Producing activities primarily due to (i) lower operating expenses of $69 million; and (ii) higher realized crude oil prices which increased revenues by $62 million, offset by (i) lower volumes which decreased revenues by $92 million; and (ii) lower NGL prices which decreased revenues by $24 million.expenses.

We believe that our existing hedge contracts in place within our CO2 ~~business~~business segment substantially mitigate commodity price sensitivities in the near-term and to lesser extent over the following few years from price exposure. Below is a summary of our CO2 business segment hedges outstanding as of December 31, ~~2020.~~2023.


		2021		2022		2023		2024
	2024									2024	2025	2026	2027	2028
Crude Oil(a)	Crude Oil(a)
Price ($ per Bbl)
Price ($ per Bbl)
Price ($ per Bbl)	Price ($ per Bbl)	$	50.37	$	50.98	$	49.78	$	43.50
Volume (MBbl/d)	Volume (MBbl/d)	25.70		10.80		5.45		1.55
NGLs	NGLs
Price ($ per Bbl)	Price ($ per Bbl)	$	29.26
Volume (MBbl/d)		4.24
Midland-to-Cushing Basis Spread
Price ($ per Bbl)
Price ($ per Bbl)	Price ($ per Bbl)	$	0.26
Volume (MBbl/d)	Volume (MBbl/d)	24.55
Volume (MBbl/d)
Volume (MBbl/d)


Delaware						80-0682103
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)


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


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

		Page Number
	~~Short-term Liquidity~~	57
	Long-term Financing	5860
	~~Counterparty Creditworthiness~~	58
	Capital Expenditures	5960
	Off Balance Sheet Arrangements	5963
	Contractual Obligations and Commercial Commitments	6063
	Cash Flows	6064
	Dividends and Stock Buy-back Program	6165
	Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries	6266
	Recent Accounting Pronouncements	6367
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	6367
	Energy Commodity Market Risk	6367
	Interest Rate Risk	6468
	Foreign Currency Risk	6569
Item 8.	Financial Statements and Supplementary Data	6570
	Index to Financial Statements	70
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	65131
Item 9A.	Controls and Procedures	66132
Item 9B.	Other Information	66132
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	132

	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	66133
Item 11.	Executive Compensation	66133
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	66133
Item 13.	Certain Relationships and Related Transactions, and Director Independence	67133
Item 14.	Principal Accounting Fees and Services	67133

	PART IV
Item 15.	Exhibits, Financial Statement Schedules	68
	~~Index to Financial Statements and Supplementary Quarterly Data~~	72134
Item 16.	Form 10-K Summary	~~136~~137
Signatures		~~137~~138


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


☑			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


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	54
	Recent Developments	54

	Narrative Description of Business	6
	Business Strategy	6
	Business Segments	6
	Natural Gas Pipelines	67
	Products Pipelines	10
	Terminals	1012
	CCOO2	1114
	Major Customers	1316
	Industry Regulation	1317
	Environmental Matters and Safety Regulation	1719
	S ec u r ity Regulations	21
	Human Capital	1922
	Properties and ~~Rights of Way~~Rights-of-Way	20
	~~Financial Information about Geographic Areas~~	2123
	Available Information	2123
Item 1A.	Risk Factors	2123
Item 1B.	Unresolved Staff Comments	3436
Item 1C.	Cybersecurity	36
Item 3.	Legal Proceedings	3438
Item 4.	Mine Safety Disclosures	3438

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	3539
Item 6.	~~Selected Financial Data~~[Reserved]	3539
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3539
	General	3640
	Critical Accounting ~~Policies and~~ Estimates	3840
	Results of Operations	4142
	Overview	4142
	Consolidated Earnings Results ~~(GAAP)~~	4446
	Non-GAAP Financial Measures	4648
	Segment Earnings Results	49
	~~DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests~~	55
	~~Income Taxes~~	5652
	Liquidity and Capital Resources	5658
	General	5658
	Short-term Liquidity	59


					KMI Gross
		Working			Developed
		Interest			Acres
			Working Interest						Working Interest		KMI Gross Developed Acres
SACROC	SACROC	97		%	49,156
Yates	Yates	50		%	9,576
Goldsmith Landreth San Andres	Goldsmith Landreth San Andres	99		%	6,166
Katz Strawn	Katz Strawn	99		%	7,194
Diamond M
Reinecke	Reinecke	70		%	3,793
Sharon Ridge(a)	Sharon Ridge(a)	14		%	2,619
Tall Cotton	Tall Cotton	100		%	641	Tall Cotton	100	%		641

MidCross(a)	MidCross(a)	13		%	320
MidCross(a)
MidCross(a)							13	%		320


	As of or for the Year Ended December 31,
	2020		2019		2018		2017		2016
	(In millions, except per share amounts)
Income and Cash Flow Data:
Revenues	$	11,700	$	13,209	$	14,144	$	13,705	$	13,058
Operating income	1,560		4,873		3,794		3,529		3,538
Earnings (losses) from equity investments	780		101		617		428		(113)


Net income	180		2,239		1,919		223		721
Net income attributable to Kinder Morgan, Inc.	119		2,190		1,609		183		708
Net income available to common stockholders	119		2,190		1,481		27		552
Class P Shares
Basic Earnings Per Common Share From Continuing Operations	$	0.05	$	0.96	$	0.66	$	0.01	$	0.25







Basic Weighted Average Common Shares Outstanding	2,263		2,264		2,216		2,230		2,230



Dividends per common share declared for the period(a)	$	1.05	$	1.00	$	0.80	$	0.50	$	0.50
Dividends per common share paid in the period(a)	1.0375		0.95		0.725		0.50		0.50

Balance Sheet Data (at end of period):
Property, plant and equipment, net	$	35,836	$	36,419	$	37,897	$	40,155	$	38,705
Total assets	71,973		74,157		78,866		79,055		80,305
Current portion of debt	2,558		2,477		3,388		2,828		2,696
Long-term debt(b)	30,838		30,883		33,205		34,088		36,205


	Adjusted Segment EBDA increase/(decrease)
	(In millions, except percentages)
Alberta Canada	$	(124)	(100)%
Gulf Liquids	(23)		(7)%
West Coast	(22)		(100)%
Mid Atlantic	(10)		(15)%
Gulf Bulk	(8)		(12)%
All others (including intrasegment eliminations)	3		1%
Total Terminals	$	(184)	(16)%


Type of Expenditure						Physical Determination of Expenditure
Sustaining capital expenditures						•Investments to maintain the operational integrity and extend the useful life of our assets
Expansion capital expenditures (discretionary capital expenditures)						•Investments to expand throughput or capacity from that which existed immediately prior to the making or acquisition of additions or improvements


	2023		Expected 2024
	(In millions)
Sustaining capital investments
Capital expenditures for property, plant and equipment	$	868	$	990
Sustaining capital expenditures of unconsolidated joint ventures(a)	163		192
Less: Consolidated joint venture partners’ sustaining capital expenditures	(9)		(11)
Total sustaining capital investments	1,022		1,171

Expansion capital investments
Capital expenditures for property, plant and equipment	1,594		2,086
Investments in unconsolidated joint ventures(b)	238		214
Less: Consolidated joint venture partners’ expansion capital expenditures	(20)		(24)
Acquisitions	1,843		—
Total expansion capital investments	3,655		2,276
Total capital investments	$	4,677	$	3,447


	Payments due by period
	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
	(In millions)
Contractual obligations:
Debt borrowings-principal payments(a)	$	33,396	$	2,558	$	5,825	$	3,491	$	21,522
Interest payments(b)	21,693		1,684		3,077		2,631		14,301
Lease obligations(c)	412		53		84		64		211
Pension and OPEB plans(d)	852		63		36		32		721
Transportation, volume and storage agreements(e)	631		163		223		143		102
Other obligations(f)	435		91		132		68		144
Total	$	57,419	$	4,612	$	9,377	$	6,429	$	37,001
Other commercial commitments:
Standby letters of credit(g)	$	147	$	74	$	73	$	—	$	—
Capital expenditures(h)	$	141	$	141	$	—	$	—	$	—


	Payments due by period
	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
	(In millions)
Contractual obligations:
Debt borrowings-principal payments(a)	$	31,929	$	4,049	$	2,668	$	2,773	$	22,439
Interest payments(b)	20,362		1,573		2,933		2,717		13,139
Lease obligations(c)	366		67		96		58		145
Pension and OPEB plans(d)	457		64		28		25		340
Transportation, volume and storage agreements(e)	660		158		266		116		120
Other obligations(f)	297		84		81		31		101
Total	$	54,071	$	5,995	$	6,072	$	5,720	$	36,284
Other commercial commitments:
Standby letters of credit(g)	$	157	$	85	$	72
Capital expenditures(h)	$	469	$	469


	December 31,
Summarized Combined Balance Sheet Information	2020		2019
	(In millions)

Current assets	$	2,957	$	1,918
Current assets - affiliates	1,151		1,146
Noncurrent assets	61,783		63,298
Noncurrent assets - affiliates	616		441
Total Assets	$	66,507	$	66,803


Current liabilities	$	4,528	$	4,569
Current liabilities - affiliates	1,209		1,139
Noncurrent liabilities	33,907		33,612
Noncurrent liabilities - affiliates	1,078		1,325
Total Liabilities	40,722		40,645
Redeemable noncontrolling interest	728		803
Kinder Morgan, Inc.’s stockholders’ equity	25,057		25,355
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	66,507	$	66,803


			~~Credit Rating~~
~~ING~~			A+
~~Citibank~~			A+
~~JP Morgan~~			A+
~~Bank of Nova Scotia~~			A+
~~Bank of America~~			A-


			As of December 31,
		As of December 31,								As of December 31,
Commodity derivative	Commodity derivative		2020		2019		Commodity derivative	2023	2022
			(In millions)
		(In millions)								(In millions)
Crude oil	Crude oil		$	81	$	113
Natural gas	Natural gas		12		8
NGL	NGL		7		7
Total	Total		$	100	$	128


	December 31, 2020				December 31, 2019
	Carrying value		Estimated fair value(e)		Carrying value		Estimated fair value(e)
	(In millions)
Fixed rate debt(a)	$	34,376	$	39,306	$	33,943	$	37,588

Variable rate debt	$	313	$	316	$	449	$	428
Notional principal amount of variable-to-fixed interest rate swap agreements(b)	(2,750)				(250)
Notional principal amount of fixed-to-variable interest rate swap agreements(c)	7,625				8,725
Debt balances subject to variable interest rates(d)	$	5,188			$	8,924


	December 31, 2023				December 31, 2022
	Carrying value		Estimated fair value(a)		Carrying value		Estimated fair value(a)
	(In millions)
Fixed rate debt(b)	$	30,063	$	29,317	$	31,474	$	29,756

Variable rate debt	$	2,053	$	2,053	$	314	$	314
Notional principal amount of variable-to-fixed interest rate swap agreements(c)	—				(1,500)
Notional principal amount of fixed-to-variable interest rate swap agreements	6,200				7,500
Debt balances subject to variable interest rates(d)	$	8,253			$	6,314


~~See “Index to Financial Statements” set forth on Page~~72.


~~3.1~~	*	~~Amended and Restated Certificate of Incorporation of KMI (filed as Exhibit 3.1 to KMI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015 (File No. 001-35081))~~

~~3.2~~	*	~~Amended and Restated Bylaws of KMI (filed as Exhibit 3.1 to KMI’s Current Report on Form 8-K, filed October 20, 2017 (File No. 001-35081))~~

~~4.1~~	*	~~Form of certificate representing Class P common shares of KMI (filed as Exhibit 4.1 to KMI’s Registration Statement on Form S-1 filed on January 18, 2011 (File No. 333-170773))~~

~~4.2~~	*	~~Shareholders Agreement among KMI and certain holders of common stock (filed as Exhibit 4.2 to KMI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 001-35081))~~

~~4.3~~	*	~~Amendment No. 1 to the Shareholders Agreement among KMI and certain holders of common stock (filed as Exhibit 4.3 to KMI’s Current Report on Form 8-K filed on May 30, 2012 (File No. 001-35081))~~

~~4.4~~	*	~~Amendment No. 2 to the Shareholders Agreement among KMI and certain holders of common stock (filed as Exhibit 4.1 to KMI’s Current Report on Form 8-K filed on December 3, 2014 (File No. 001-35081))~~

~~4.5~~	*	Indenture dated as of December 9, 2005, among Kinder Morgan Finance Company LLC (formerly Kinder Morgan Finance Company, ULC), Kinder Morgan Kansas, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 15, 2005 (File No. 1-06446))

~~4.6~~	*	Forms of Kinder Morgan Finance Company LLC Notes (included in the Indenture filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 15, 2005 (File No. 1-06446))

~~4.7~~	*	Indenture dated January 2, 2001 between Kinder Morgan Energy Partners, L.P. and First Union National Bank, as trustee, relating to Senior Debt Securities (including form of Senior Debt Securities) (filed as Exhibit 4.11 to Kinder Morgan Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2000 (File No. 1-11234))

~~4.8~~	*	Certificate of the Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 7.40% Notes due March 15, 2031 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Current Report on Form 8-K filed on March 14, 2001 (File No. 1-11234))

~~4.9~~	*	~~Specimen of 7.40% Notes due March 15, 2031 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P.’s Current Report on Form 8-K filed on March 14, 2001(File No. 1-11234))~~

~~4.10~~	*	Certificate of the Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 7.750% Notes due March 15, 2032 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002 (File No. 1-11234))

~~4.11~~	*	Specimen of 7.750% Notes due March 15, 2032 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002 (File No. 1-11234))

~~4.12~~	*	Indenture dated August 19, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346))

~~4.13~~	*	First Supplemental Indenture to Indenture dated August 19, 2002, dated August 23, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346))

~~4.14~~	*	Form of 7.30% Notes due 2033 (included in the Indenture filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346))


~~4.15~~	*	Senior Indenture dated January 31, 2003 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102961))

~~4.16~~	*	Form of Senior Note of Kinder Morgan Energy Partners, L.P. (included in the Form of Senior Indenture filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102961))

~~4.17~~	*	Certificate of the Vice President, Treasurer and Chief Financial Officer and the Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 5.80% Notes due March 15, 2035 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 (File No. 1-11234))

~~4.18~~	*	Certificate of the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 6.00% Senior Notes due 2017 and 6.50% Senior Notes due 2037 (filed as Exhibit 4.28 to Kinder Morgan Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2006 (File No. 1-11234))

~~4.19~~	*	Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 6.95% Senior Notes due 2038 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 1-11234))

~~4.20~~	*	Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.80% Senior Notes due 2021, and the 6.50% Senior Notes due 2039 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009 (File No. 1-11234))

~~4.21~~	*	Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.30% Senior Notes due 2020, and the 6.55% Senior Notes due 2040 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 (File No. 1-11234))

~~4.22~~	*	Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 6.375% Senior Notes due 2041 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 1-11234))

~~4.23~~	*	Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 4.150% Senior Notes due 2022, and the 5.625% Senior Notes due 2041 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011 (File No. 1-11234))

~~4.24~~	*	Certificate of the Vice President, Finance and Investor Relations and the Vice President and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 3.500% Senior Notes due 2021 and the 5.500% Senior Notes due 2044 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014 (File No. 1-11234))

~~4.25~~	*	Certificate of the Vice President and Treasurer and the Vice President and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 4.250% Senior Notes due 2024 and the 5.400% Senior Notes due 2044 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014 (File No. 1-11234))

~~4.26~~	*	Indenture, dated March 1, 2012, between KMI and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to KMI’s Registration Statement on Form S-3 filed on March 1, 2012 (File No. 001-35081))

~~4.27~~	*	Certificate of the Vice President and Treasurer and the Vice President and Secretary of KMI establishing the terms of the 2.000% Senior Notes due 2017, the 3.050% Senior Notes due 2019, the 4.300% Senior Notes due 2025, the 5.300% Senior Notes due 2034 and the 5.550% Senior Notes due 2045 (filed as Exhibit 10.53 to KMI’s Annual Report on Form 10-K for the year ended December 31, 2014 (File No. 001-35081))

~~4.28~~	*	Certificate of the Vice President and Treasurer and Vice President and Secretary of KMI establishing the terms of the 5.050% Senior Notes due 2046 (filed as Exhibit 4.1 to KMI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015 (File No. 001-35081))


~~4.29~~	*	Certificate of the Vice President and Treasurer and Vice President and Secretary of KMI establishing the terms of the 1.500% Senior Notes due 2022 and 2.250% Senior Notes due 2027 (filed as Exhibit 4.2 to KMI’s Form 8-A, filed March 16, 2015 (File No. 001-35081))

~~4.30~~	*	Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of KMI establishing the terms of the 3.150% Senior Notes due January 15, 2023 (filed as Exhibit 4.1 to KMI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2017 (File No. 001-35081))

~~4.31~~	*	Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of KMI establishing the terms of the Floating Rate Senior Notes due January 15, 2023 (filed as Exhibit 4.2 to KMI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2017 (File No. 001-35081))

~~4.32~~	*	Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of KMI establishing the terms of the 4.300% Senior Notes due 2028 and the 5.200% Senior Notes due 2048 (filed as Exhibit 4.1 to KMI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2018 (File No. 001-35081))

~~4.33~~	*	Certificate of the Vice President and Chief Financial Officer, and Vice President, Investor Relations and Treasurer of Kinder Morgan, Inc. establishing the terms of the 2.00% Notes due February 15, 2031 and the 3.25% Notes due August 1, 2050 (filed as Exhibit 4.1 to KMI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2020 (File No. 001-35081))

~~4.34~~		Certain instruments with respect to long-term debt of KMI and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of KMI and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. sec. #229.601. KMI hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request.

~~4.35~~	*	~~Description of Capital Stock of Kinder Morgan, Inc. Registered Pursuant to Section 12 of the Securities Exchange Act of 1934~~

~~4.36~~	*	~~Description of Debt Securities of Kinder Morgan, Inc. Registered Pursuant to Section 12 of the Securities Exchange Act of 1934~~

~~10.1~~	*	~~KMI 2015 Amended and Restated Stock Incentive Plan (filed as Exhibit 4.5 to KMI’s Registration Statement on Form S-8, filed on July 1, 2015 (File No. 333-205430))~~

~~10.2~~	*	~~Amendment No. 1 to KMI 2015 Amended and Restated Stock Incentive Plan (filed as Exhibit 10.2 to KMI’s Current Report on Form 8-K filed on January 24, 2017 (File No. 001-35081))~~

~~10.3~~	*	~~Amendment No. 2 to KMI 2015 Amended and Restated Stock Incentive Plan (filed as Exhibit 10.2 to KMI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018 (File No. 001-35081))~~

~~10.4~~	*	~~Amendment No. 3 to KMI 2015 Amended and Restated Stock Incentive Plan (filed as Exhibit 10.1 to KMI’s Current Report on Form 8-K filed on January 22, 2019 (File No. 001-35081))~~

~~10.5~~	*	~~2015 Form of Employee Restricted Stock Unit Agreement (filed as Exhibit 4.6 to KMI’s Registration Statement on Form S-8, filed on July 1, 2015 (File No. 333-205430))~~

~~10.6~~	*	~~2016 Form of Employee Restricted Stock Unit Agreement (filed as Exhibit 10.2 to KMI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016 (File No. 001-35081))~~

~~10.7~~	*	~~2018 Form of Employee Restricted Stock Unit Agreement (filed as Exhibit 10.3 to KMI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018 (File No. 001-35081))~~

~~10.8~~	*	~~Amended and Restated Stock Compensation Plan for Non-Employee Directors (filed as Exhibit 10.5 to KMI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015 (File No. 001-35081))~~

~~10.9~~	*	~~2015 Form of Non-Employee Director Stock Compensation Agreement (filed as Exhibit 10.6 to KMI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015 (File No. 001-35081))~~

~~10.10~~	*	~~2011 Form of Non-Employee Director Stock Compensation Agreement (filed as Exhibit 10.3 to KMI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 001-35081))~~

~~10.11~~	*	~~KMI Employees Stock Purchase Plan (filed as Exhibit 10.5 to KMI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 001-35081))~~

~~10.12~~	*	~~Amended and Restated Annual Incentive Plan of KMI (filed as Exhibit 10.1 to KMI’s Current Report on Form 8-K filed January 26, 2021 (File No. 001-35081))~~

~~10.13~~	*	Revolving Credit Agreement, dated November 16, 2018 among KMI, as borrower, Barclays Bank PLC, as administrative agent, and the lenders and issuing banks party thereto (filed as Exhibit 10.15 to KMI’s Annual Report on Form 10-K for the year ended December 31, 2018 (File No. 001-35081))

~~10.14~~		~~Cross Guarantee Agreement, dated as of November 26, 2014 among KMI and certain of its subsidiaries with schedules updated as of December 31, 20~~20


~~21.1~~						~~Subsidiaries of KMI~~

~~22.1~~						~~Subsidiary guarantors and issuers of guaranteed securities~~

~~23.1~~						~~Consent of PricewaterhouseCoopers LLP~~



~~31.1~~						~~Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002~~

~~31.2~~						~~Certification~~ ~~of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002~~

~~32.1~~						~~Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002~~

~~32.2~~						~~Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002~~



~~101~~						Interactive data files pursuant to Rule 405 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language): (i) our Consolidated Statements of Income for the years ended December 31, 2020, 2019, and 2018; (ii) our Consolidated Statements of Comprehensive Income for the years ended December 31, 2020, 2019, and 2018; (iii) our Consolidated Balance Sheets as of December 31, 2020 and 2019; (iv) our Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019, and 2018; (v) our Consolidated Statements of Stockholders’ Equity as of and for the years ended December 31, 2020, 2019, and 2018; and (vi) the notes to our Consolidated Financial Statements

~~104~~						~~Cover Page Interactive Data File pursuant to Rule 406 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language) and contained in Exhibit 101.~~


			Page Number

Report of Independent Registered Public Accounting Firm		(PCAOB ID: 238)	7371

Consolidated Statements of Income for the years ended December 31, 20202 203 , ~~201~~202 92 and 20202181			7674

Consolidated Statements of Comprehensive Income for the years ended December 31, 20202 203 , ~~201~~202 92 and 201821			7775

Consolidated Balance Sheets as of December 31, 20202 203 and ~~201~~20292			7876

Consolidated Statements of Cash Flows for the years ended December 31, 2 0202 203 , ~~201~~202 92 and 201821			7977

Consolidated Statements of Stockholders’ Equity as of and for the years ended December 31,202 3 , 202 20 20 ~~, 201~~92 and 201821			8179

Notes to Consolidated Financial Statements			8280
Note 1.	General		8280
Note 2.	Summary of Significant Accounting Policies		8280
Note 3.	~~Impairments~~Acquisitions and ~~Losses and Gains on~~ Divestitures		9190
Note 4.	Losses and Gains on Divestitures, Impairments and Other Write-downs		9593
Note 5.	Income Taxes		9694
Note 6.	Property, Plant and Equipment, net		9897
Note 7.	Investments		9998
Note 8.	Goodwill		~~100~~99
Note 9.	Debt		~~101~~100
Note 10.	Share-based Compensation and Employee Benefits		~~105~~104
Note 11.	Stockholders’ Equity		~~111~~110
Note 12.	Related Party Transactions		~~114~~112
Note 13.	Commitments and Contingent Liabilities		~~115~~112
Note 14.	Risk Management		~~116~~113
Note 15.	Revenue Recognition		~~121~~118
Note 16.	Reportable Segments		~~125~~121
Note 17.	Leases		~~129~~125
Note 18.	Litigation and Environmental		~~130~~126
Note 19.	Recent Accounting Pronouncements		~~135~~130


~~Supplemental Quarterly Financial Data (Unaudited)~~		~~136~~


KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
	Year Ended December 31,
	2023		2022		2021
Cash Flows From Operating Activities
Net income	$	2,486	$	2,625	$	1,850
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	2,250		2,186		2,135
Deferred income taxes	710		692		355
Amortization of excess cost of equity investments	66		75		78
Change in fair market value of derivative contracts	(126)		56		20

(Gain) loss on divestitures and impairments, net (Note 4)	(15)		(32)		1,624
Gain on sale of interest in equity investment (Note 3)	—		—		(206)
Earnings from equity investments	(838)		(803)		(591)
Distributions of equity investment earnings	755		725		720
Pension contributions net of noncash pension benefit expenses	77		(50)		(39)
Changes in components of working capital, net of the effects of acquisitions and dispositions
Accounts receivable	301		(220)		(265)

Inventories	188		(183)		(202)
Other current assets	108		(51)		(109)
Accounts payable	(201)		161		387
Accrued interest, net of interest rate swaps	(13)		50		(17)

Other current liabilities	(58)		6		165
Change in deferred revenues (Note 15)	870		(24)		(28)
Rate reparations, refunds and other litigation reserve adjustments	(19)		(190)		(57)
Other, net	(50)		(56)		(112)
Net Cash Provided by Operating Activities	6,491		4,967		5,708

Cash Flows From Investing Activities
Acquisitions of assets and investments, net of cash acquired (Note 3)	(1,842)		(487)		(1,547)
Capital expenditures	(2,317)		(1,621)		(1,281)

Sales of property, plant and equipment, investments, and other net assets, net of removal costs	(28)		6		406


Contributions to investments	(212)		(229)		(38)
Distributions from equity investments in excess of cumulative earnings	228		156		163

Other, net	(4)		—		(8)
Net Cash Used in Investing Activities	(4,175)		(2,175)		(2,305)

Cash Flows From Financing Activities
Issuances of debt	7,590		9,058		5,959
Payments of debt	(7,356)		(9,735)		(6,831)
Debt issue costs	(20)		(25)		(27)
Dividends (Note 11)	(2,529)		(2,504)		(2,443)

Repurchases of shares (Note 11)	(522)		(368)		—
Proceeds from sale of noncontrolling interests (Note 3)	—		557		—
Contributions from noncontrolling interests	3		2		4

Distributions to investment partner	—		—		(82)

Distributions to noncontrolling interests	(151)		(116)		(20)
Other, net	(29)		(14)		(25)
Net Cash Used in Financing Activities	(3,014)		(3,145)		(3,465)


Net Decrease in Cash, Cash Equivalents and Restricted Deposits	(698)		(353)		(62)
Cash, Cash Equivalents and Restricted Deposits, beginning of period	794		1,147		1,209
Cash, Cash Equivalents and Restricted Deposits, end of period	$	96	$	794	$	1,147


	Common stock		Additional paid-in capital			Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non-controlling interests		Total
		Issued shares			Par value
Balance at December 31, 2020		2,264	$	23		$	41,756	$	(9,936)	$	(407)	$	31,436	$	402	$	31,838

Restricted shares		3				50						50				50
Net income								1,784				1,784		66		1,850
Dividends								(2,443)				(2,443)				(2,443)
Distributions												—		(20)		(20)
Contributions												—		4		4
Reclassification of redeemable noncontrolling interest												—		646		646

Other comprehensive loss										(4)		(4)				(4)
Balance at December 31, 2021		2,267	23			41,806		(10,595)		(411)		30,823		1,098		31,921
Impact of adoption of ASU 2020-06 (Note 11)						(11)						(11)				(11)
Balance at January 1, 2022		2,267	23			41,795		(10,595)		(411)		30,812		1,098		31,910
Repurchases of shares		(21)	(1)			(367)						(368)				(368)
EP Trust I Preferred security conversions						1						1				1
Restricted shares		2				54						54				54
Net income								2,548				2,548		77		2,625
Dividends								(2,504)				(2,504)				(2,504)
Distributions												—		(116)		(116)
Contributions												—		2		2
Impact of change in ownership interest in subsidiary						190						190		311		501

Other comprehensive income										9		9				9
Balance at December 31, 2022		2,248	22			41,673		(10,551)		(402)		30,742		1,372		32,114


Repurchases of shares		(32)				(522)						(522)				(522)

Restricted shares		4				44						44				44
Net income								2,391				2,391		95		2,486
Dividends								(2,529)				(2,529)				(2,529)
Distributions												—		(151)		(151)
Contributions												—		3		3
Acquisition (Note 3)												—		104		104
Other						(5)						(5)				(5)
Other comprehensive income										185		185				185
Balance at December 31, 2023		2,220	$	22		$	41,190	$	(10,689)	$	(217)	$	30,306	$	1,423	$	31,729


	Preferred stock			Common stock
	Issued shares	Par value		Issued shares	Par value		Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non-controlling interests		Total
Balance at December 31, 2017	2	$	0	2,217	$	22	$	41,909	$	(7,754)	$	(541)	$	33,636	$	1,488	$	35,124
Impact of adoption of ASU (Note 11)									175		(109)		66				66
Balance at January 1, 2018	2	0		2,217	22		41,909		(7,579)		(650)		33,702		1,488		35,190
Repurchases of shares				(15)			(273)						(273)				(273)
Mandatory conversion of preferred shares	(2)			58	1		(1)						0				0
Restricted shares				2			65						65				65
Net income									1,609				1,609		310		1,919
Distributions													0		(997)		(997)
Contributions													0		33		33
Preferred stock dividends									(128)				(128)				(128)
Common stock dividends									(1,618)				(1,618)				(1,618)
Other							1						1		1		2
Other comprehensive income											320		320		18		338
Balance at December 31, 2018	0	0		2,262	23		41,701		(7,716)		(330)		33,678		853		34,531
Impact of adoption of ASU									(4)				(4)				(4)
Balance at January 1, 2019	0	0		2,262	23		41,701		(7,720)		(330)		33,674		853		34,527
Repurchases of shares							(2)						(2)				(2)
Restricted shares				3			46						46				46
Net income									2,190				2,190		49		2,239
Distributions													0		(55)		(55)
Contributions													0		3		3
Common stock dividends									(2,163)				(2,163)				(2,163)
Sale of interest in KML											68		68		(503)		(435)
Other													0		1		1
Other comprehensive loss											(71)		(71)		(4)		(75)
Balance at December 31, 2019	0	0		2,265	23		41,745		(7,693)		(333)		33,742		344		34,086
Repurchases of shares				(4)			(50)						(50)				(50)
Restricted shares				3			61						61				61
Net income									119				119		61		180
Distributions													0		(15)		(15)
Contributions													0		11		11
Common stock dividends									(2,362)				(2,362)				(2,362)
Other													0		1		1
Other comprehensive loss											(74)		(74)				(74)
Balance at December 31, 2020	0	$	0	2,264	$	23	$	41,756	$	(9,936)	$	(407)	$	31,436	$	402	$	31,838


	Weighted Average Amortization Period	December 31,
		2023		2022
	(Years)	(In millions)
Gross	11.3	$	3,543	$	3,382
Accumulated amortization		(1,586)		(1,573)
Net carrying amount		$	1,957	$	1,809


				Assignment of Purchase Price
Ref	Acquisition	Purchase price		Current assets		Property, plant & equipment		Other long-term assets		Current liabilities		Long-term liabilities		Non-controlling interest		Resulting goodwill
		(In millions)
(1)	STX Midstream(a)	$	1,831	$	41	$	1,199	$	552	$	(11)	$	(2)	$	(104)	$	156
(2)	Diamond M	13		—		25		—		—		(12)		—		—
(3)	North American Natural Resources	132		2		5		64		—		—		—		61
(4)	Mas Ranger, LLC	358		9		31		320		(2)		—		—		—
(5)	Kinetrex Energy	318		18		49		272		(6)		(68)		—		53
(6)	Stagecoach	1,258		53		1,187		24		(6)		—		—		—


	Year Ended December 31, 2023
	(In millions)
Balance at beginning of period	$	79
Statute expirations for state NOL and foreign tax credits	(5)
Currency fluctuation	3

Balance at end of period	$	77


	Unused Amount		Deferred Tax Asset		Valuation Allowance		Expiration Period
	(In millions)
Net Operating Loss
U.S. federal net operating loss	$	6,565	$	1,379	$	—	Indefinite
U.S. federal net operating loss	1,716		360		—		2035 - 2037
State losses	5,293		254		(46)		2024 - 2043
Foreign losses	90		31		(31)		Indefinite
Tax Credits
General business credits	300		300		—		2036 - 2042


Jurisdiction						Open Tax Year
U.S.						2019 - 2023
Various states						2012 - 2023
Foreign						2008 - 2023


	Straight-Line Estimated Useful Life	Composite Depreciation Rates	December 31,
			2023		2022
	(Years)	(%)	(In millions)
Interstate Natural Gas FERC-Regulated
Pipelines (Natural gas)		0.80-6.67	$	12,019	$	11,793
Equipment (Natural gas)		0.80-6.67	9,190		8,839
Other(a)		0.00-25	823		833
Accumulated depreciation, depletion and amortization			(10,301)		(9,883)
Depreciable assets			11,731		11,582
Land and land rights-of-way(b)			399		388
Construction work in process			394		258
Total interstate natural gas FERC-regulated			12,524		12,228

Other
Pipelines (Natural gas, liquids, crude oil and CO2)	5-40	0.09-33.33	9,631		8,329
Equipment (Natural gas, liquids, crude oil, CO2 and terminals)	5-40	0.09-33.33	19,974		18,645
Other(a)	3-10	0.00-33.33	4,773		4,791
Accumulated depreciation, depletion and amortization			(11,774)		(10,529)
Depreciable assets			22,604		21,236
Land and land rights-of-way(c)			1,518		1,350
Construction work in process			651		785
Total other			24,773		23,371

Property, plant and equipment, net			$	37,297	$	35,599