KMI 10-K diff: FY 2023-12-31 → FY 2024-12-31
Paragraph-level diff of Risk Factors (Item 1A) and Management's Discussion & Analysis (Item 7).
Item 1A · Risk Factors
+50 paragraphs −49 paragraphs ~49 changed
FY 2023-12-31 (earlier)
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 our Business
Our businesses are dependent on the supply of and demand for the products 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, CO 2 , 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.23Decreases 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 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.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 CO 2 for use in enhanced oil recovery operations.The volatility of crude oil, NGL and natural gas prices could adversely affect our 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+); (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. 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.24If commodity 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, 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 CO 2 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 CO 2 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 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 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.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 on25our operating results and cash flow. See “ —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.
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. 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.
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 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.
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 hedging26agreement 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 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. 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 respond27or 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.
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 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 frequency and severity of weather events such as winter storms, hurricanes and 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. Natural disasters can similarly affect the facilities of our customers. 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.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 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
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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 CO 2 . 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.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, CO 2 , 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.
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 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.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.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 CO 2 business segment will decline. We may not be able to develop or acquire additional reserves at an acceptable cost or have necessary
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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 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 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” to our consolidated financial statements.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.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
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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. 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.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.
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 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 the31case 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.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 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.32Should 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.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 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.
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.33New 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 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 CO 2 in the liquid phase as well as establishing regulation of the transportation of gaseous CO 2 ; 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 CO 2 , 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 CO 2 (for example, from our McElmo Dome CO 2 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. ”34Adoption 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.
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 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.35Risks 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 .”
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.
FY 2024-12-31 (later)
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 our Business
Our businesses are dependent on the supply of and demand for the products 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, CO 2 , 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. Decreases in the supply of or demand for natural gas, crude oil and other products could adversely impact the utilization of our assets.
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 governmental23policies, including in relation to climate change or other environmental concerns, may have a negative impact on the supply of crude oil and other products. 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. 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. Furthermore, such unfavorable conditions may compound the adverse effects of larger economic disruptions. See “ —Our operating results may be adversely affected by unfavorable economic and market conditions. ”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.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, 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. Federal regulators may also expand existing regulatory requirements, such as PHMSA’s recent expansion of gas gathering pipeline regulation and the Congressional mandate under the Pipeline Safety Act that PHMSA regulate the transportation of gaseous CO 2 . 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, including cost increases associated with increased tariffs (such as those proposed by the new U.S. presidential administration). 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 otherwise limit our ability to pursue 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, which may differ from our interests or our views of the interests of the venture. Such differences in actual or perceived interests could result in operational delays or impasses, which in turn could affect the financial expectations of and our expected benefits from the venture.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 CO 2 for use in enhanced oil recovery operations.24The volatility of crude oil, NGL and natural gas prices could adversely affect our 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+); (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. 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.If commodity 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, 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 CO 2 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 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 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 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.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, the25global economic downturn caused by the coronavirus pandemic in 2020 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. Also, economic conditions in the wake of the pandemic included inflationary pressure, which resulted in higher operating expenses and project costs for us, as well as higher interest rates. More recently, we may see increasing market uncertainty and volatility due to possible shifts in U.S. and foreign trade, economic and other policies following the recent change in U.S. presidential administration.
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.”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.
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. 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.
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 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 energy industry 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 increased26regulatory 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. In the past, 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, and they may do so in the future.
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 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. 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 13 “Risk Management” to our consolidated financial statements.
A breach of information security or the failure of one or more key 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, which may be escalated during periods of heightened geopolitical tensions, 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,27implement 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. Potential targets include our pipeline systems, terminals, processing plants, databases or operating systems. Risk of these attacks may escalate during periods of heightened geopolitical tensions. 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. 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.
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.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 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.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 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 frequency and severity of weather events such as winter storms, hurricanes and tropical storms, extreme precipitation and flooding. These
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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. Natural disasters can similarly affect the facilities of our customers. 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.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 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.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, CO 2 , or crude oil—and the laws of the particular state. In addition, 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.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.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 CO 2 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.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.29Our 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, 2024, we had approximately $31.8 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 8 “Debt” to our consolidated financial statements.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.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.30Our 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 debt makes us vulnerable to increases in interest rates to the extent we have variable-rate debt and maturing fixed-rate debt.
As of December 31, 2024, we had approximately $31.8 billion of consolidated debt (excluding debt fair value adjustments), including $1.5 billion of senior notes maturing within the next 12 months, and approximately $3.6 billion of debt 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 over the period from March 2022 to July 2023 before beginning rate reductions in September 2024 due to slowing inflation. There can be no assurance that the U.S. Federal reserve will continue rate reductions, will not resume rate increases or regarding the pace at which any such reductions or increases could occur. If and to the extent that interest rates increase, our costs to refinance maturities of existing indebtedness may also increase, as will the amount of cash required to service variable-rate debt, and our earnings and cash flows could be adversely affected.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.
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 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 17 “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.31New 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. In recent years, we saw an increase in the efforts of regulatory authorities to issue new regulations and guidance and to interpret existing laws and regulations in ways that promoted the use of renewable energy sources and further protection of the environment, called upon companies to increase monitoring and emissions reduction efforts, and increased 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 methane and volatile organic compound emissions from crude oil and natural gas sources, including the production, processing, and transmission and storage segments. In addition, a certain degree of regulatory uncertainty is created by the recent change in U.S. presidential administrations. It remains unclear specifically what the new administration may do with respect to future policies and regulations that may affect us.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) was predicated on the EPA’s disapproval of numerous state implementation plans, or SIPs, submitted under the interstate transport (Good Neighbor) provisions of the Clean Air Act for the 2015 Ozone NAAQS and became effective on August 4, 2023. 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 by May 1, 2026, except for any compliance schedule extensions granted by the EPA, which would need to be supported by us and approved by the EPA on an engine-by-engine basis. Multiple legal challenges have been filed, including by states seeking review of SIP disapprovals (12 of which have received stays pending review) and by us. On June 27, 2024, the Supreme Court granted a temporary stay of the Plan until a disposition of a review of the Plan by the U.S. Court of Appeals for the D.C. Circuit and any appeal of that decision to the Supreme Court. See Note 17, “Litigation and Environmental— Environmental Matters—Challenge to Federal “Good Neighbor Plan ,” to our consolidated financial statements. On February 6, 2025, the EPA filed a motion asking the U.S. Court of Appeals for the D.C. Circuit to hold the cases in abeyance for 60 days to allow the Trump Administration time to familiarize themselves with the Plan, receive briefing from the EPA about the cases and the Plan, and decide what action on the Plan, if any, is necessary. If the Plan were to remain in effect in its current form (including full compliance by a revised compliance deadline accounting for the stays, 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 .” We are unable to predict whether pending 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, local and foreign 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 costs of raw materials, such as steel, which may be affected by tariffs (such as those proposed by the new U.S. presidential administration) or otherwise; (vii) the integrity, safety and security (including against cyber-attacks) of facilities and operations; (viii) the acquisition of other businesses; (ix) the acquisition, extension, disposition or abandonment of services or facilities; (x) reporting and information posting requirements; (xi) the maintenance of accounts and records; and (xii) relationships with affiliated companies involved in various aspects of the natural gas and energy businesses.
If 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 different32interpretations 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.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 change depending on 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 or 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 a leak, release or spill of liquid petroleum products, chemicals or 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 hazardous substances. While we believe we have utilized operating, handling and disposal practices that were consistent with industry practices at the time, hydrocarbons or 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 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.
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 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, 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. ”33Increased 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 enhanced assessment and repair requirements in HCAs, and compliance with recently issued regulations which impose additional assessment and repair criteria for gas pipelines in MCAs. 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. 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 MAOP of certain gas pipelines.
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 or equipment, 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. PHMSA is also working on a final rulemaking regarding requirements for pipelines located in coastal ecological unusually sensitive areas, as well as a final rule that updates requirements for responding to changes in class location for gas pipelines. In addition, PHMSA is working on a number of proposed rulemakings, including those related to (i) updating regulations for LNG facilities; (ii) requirements for idled gas and liquid pipelines; (iii) revising requirements for transportation of CO 2 in the liquid phase as well as establishing regulation of the transportation of gaseous CO 2 ; (iv) oil spill response plans; and (v) liquid pipeline repair criteria.
Congress is working on the reauthorization of the Pipeline Safety Act, which is expected to be enacted in 2025 and could 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 CO 2 , including the EPA programs to control GHG emissions, PHMSA’s existing leak detection and repair requirements and additional requirements proposed by PHMSA in accordance with its Congressional mandate, state actions to develop statewide or regional programs, and regulations by foreign governments that restrict imports. 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 CO 2 (for example, from our McElmo Dome CO 2 field), even when such production is not emitted to the atmosphere. In addition, the European Union has approved a law to impose limits on methane emissions applicable to imports of natural gas and crude oil beginning in 2030. Proposed approaches to further address GHG emissions include establishing GHG “cap-and-trade” programs, increased efficiency standards, participation in international climate agreements 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 reduction program, and such increased costs could be significant. Recovery of such increased costs from our customers is uncertain in all34cases 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, increases in the costs for such products 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 2024, the SEC finalized rules requiring significant new climate-related disclosure in SEC filings, including certain climate-related metrics and GHG emissions data, and third-party attestation requirements. In April 2024, the SEC voluntarily stayed the effectiveness of the new rules, pending judicial review, and on February 11, 2025, the Acting Chairman of the SEC directed the SEC staff to request that the court not schedule the case for argument to provide time for the SEC to deliberate and determine the appropriate next steps in the cases. The State of California also has enacted legislation requiring climate-related disclosures. Other U.S. states have announced similar proposed regulations. These types of regulations may expose us to significant additional compliance costs. Some customers and other third parties also have begun requesting disclosures from us related to their own reporting obligations. At this time, we cannot predict the costs of compliance with, or other potential adverse impacts resulting from, these or similar future rules that may be adopted.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. From 2021 to 2024, the federal government 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.
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 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. coastwise35trading 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.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 .”
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 7 · Management's Discussion & Analysis
+377 paragraphs −397 paragraphs ~377 changed
FY 2023-12-31 (earlier)
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 helpful to the reading of our discussion and analysis include the following: (i) a description 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 2023, found in Items 1 and 2. “ Business and Properties—General Development of Business—Recent Developments; ” (iii) a description of terms for services and commodities we provide, found in Items 1 and 2.“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.
39GeneralAcquisitions
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 SegmentSTX 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 CO 2 flooding given its proximity to SACROC. We expect to begin implementation of enhanced oil recovery in 2024.CO 2
(Oil and Gas Producing activities)2024 Dividends and Discretionary Capital
We expect to declare dividends of $1.15 per share for 2024, a 2% increase from the 2023 declared dividends of $1.13 per share. We also expect to invest $2.3 billion in expansion projects and contributions to joint ventures, or discretionary capital expenditures, during 2024.
The expectations for 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 “ Information Regarding Forward-Looking Statements ” at the beginning of this report and Item 1A. “ Risk Factors ” for more information.Critical Accounting Estimates
Critical accounting estimates and assumptions involve material levels of 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 certain areas that require more judgment relative to others when preparing our consolidated financial statements and related disclosures 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) assignment of the purchase price for a business acquisition, (b) calculations of possible asset and equity investment impairment charges, (c) calculation for the annual goodwill impairment test (or interim tests if triggered), and (d) recording derivative contract assets and 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.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. For discussion on our hedging activities and related sensitivities to our estimates, see Note 14 “Risk Management” to our consolidated financial statements and Item 7A. “ Quantitative and Qualitative Disclosures About Market Risk ,” respectively.ImpairmentsIn 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,
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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 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 MattersWith 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. 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 liability claims. For more information on environmental matters, see Part I, Items 1 and 2. “ 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 MattersMany 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. 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.Employee Benefit PlansOur pension and OPEB obligations and net benefit costs are primarily based on actuarial calculations. A significant assumption we utilize is the discount rate used in calculating our benefit obligations. The selection of assumptions used in the actuarial calculations of our pension and OPEB plans is further discussed in Note 10 “ Share-based Compensation and Employee 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.41
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, 2023:Pension Benefits OPEB
Net benefit cost (credit) Funded status
Net benefit cost (credit) Funded status(a)
(In millions)
One percent increase in:Discount rates $ (9) $ 133 $ — $ 10
Expected return on plan assets (17) — (3) —
Rate of compensation increase 2 (10) — —One percent decrease in:Discount rates 11 (155) — (11)
Expected return on plan assets 17 — 3 —
Rate of compensation increase (2) 9 — —(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 TaxesWe make significant judgments and estimates in determining our provision for income taxes, including our assessment of our income tax positions given the uncertainties involved in the interpretation and application of complex tax laws and regulations in various taxing jurisdictions. Numerous and complex judgments and assumptions are inherent in the estimation of future taxable income when determining a valuation allowance, including factors such as future operating conditions and the apportionment of income by state. For more information, see Note 5 “Income Taxes” to our consolidated financial statements.Results of Operations
OverviewAs described in further detail below, our management evaluates our performance primarily using Net income attributable to Kinder Morgan, Inc. and Segment earnings before DD&A expenses, including amortization of excess cost of equity investments, (EBDA) (as presented in Note 16 “Reportable Segments”) along with the non-GAAP financial measures of Adjusted Net income attributable to Common Stock, and distributable cash flow (DCF), both in the aggregate and per share for each, Adjusted Segment EBDA, Adjusted Net 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.GAAP Financial MeasuresThe Consolidated Earnings Results for the years ended December 31, 2023 and 2022 present Net income attributable to Kinder Morgan, Inc., as prepared and presented in accordance with 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 MeasuresOur 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
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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 processes.Certain ItemsCertain 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 2022Certain ItemsFair 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.
(c) 2023 amount represents pension cost adjustments related to settlements made by our pension plans.
(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 ”).
(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 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 EPSAdjusted 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
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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 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 EBDAAdjusted 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 EBITDAAdjusted 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 VenturesCertain 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
44
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.Net DebtNet 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 f or 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.
45Consolidated 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 OtherCosts 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, CO 2 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 CO 2 segment, which produces, instead of purchases, the crude oil and CO 2 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:RevenuesRevenue s decreas ed $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 .”
46Operating Costs, Expenses and Other
Costs of SalesCosts of sale s 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 MaintenanceOperations and maintenance increa sed $152 million in 2023 compared to 2022. The increase was primarily driven by higher labor and other expenses, including integrity costs and service s, 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, netIn 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, ne t increa sed $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.
47Non-GAAP Financial MeasuresReconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Kinder Morgan, Inc.Year Ended December 31,2023 2022(In millions, except per share amounts)Net income attributable to Kinder Morgan, Inc. $ 2,391 $ 2,548Certain 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 88Adjusted Net Income Attributable to Kinder Morgan, Inc.$ 2,410 $ 2,636Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Common StockNet income attributable to Kinder Morgan, Inc. $ 2,391 $ 2,548Total 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 $ 4,970Adjusted 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) See table included in “ —Overview—Non-GAAP Financial Measures— Certain Items” above.
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(b) See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Common Stock” for a detailed listing.
(c) 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 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.
(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 KMI’s income tax provision on Certain Items affecting earnings from equity investments is included within “Certain Items.” See table included in “ —Overview—Non-GAAP Financial Measures— Certain Items” above.
(h) Includes non-cash pension expense, non-cash compensation associated with our restricted stock program and pension contributions.
(i) Includes restricted stock awards that participate in dividends.Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDAYear 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 1,524Amounts from joint venturesUnconsolidated 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) See table included in “ —Overview—Non-GAAP Financial Measures— 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— Cer tain Items” above.
(c) To avoid duplication, adjustments for interest, net for 2023 and 2022 exclude $(7) million and $(11) million, respectively, whic h amounts are already included within “Certain Items.” See table included in “ —Overview—Non-GAAP Financial Measures— Certain Items,” above.
(d) Includes that tax provision on Certain Items recognized by the investees that are taxable entities associated with our Citrus, NGPL Holdings and Products (SE) Pipe Line equity investments. The impact of KMI’s income tax provision on Certain Items affecting earnings from equity investments is included within “Certain Items” above.
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Below is a discussion of significant changes in our Adjusted Net Income Attributable to Kinder Morgan, Inc., DCF and Adjusted EBITDA :Year Ended December 31,2023 2022(In millions)
Adjusted Net Income Attributable to Kinder Morgan, Inc.$ 2,410 $ 2,636
DCF 4,715 4,970
Adjusted EBITDA 7,561 7,516Change from prior period Increase/(Decrease)
Adjusted Net Income Attributable to Kinder Morgan, Inc.$ (226)
DCF $ (255)
Adjusted EBITDA $ 45
Adjusted Net Income Attributable to Kinder Morgan, Inc. decreased $226 mill ion in 2023 compared to 2022. The decrease was primarily driven by higher interest expense. Higher interest expense also affected DCF. The $255 mi llion decrease in DCF in 2023 compared to 2022 was further impacted by an increase in sustaining capital expenditures. Adjus ted EBITDA increas ed $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 primaril y 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 the Ruby bankruptcy, which we treated as Certain Items.
50Reconciliation 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 $ 4,801Certain 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 $ 1,107Certain 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 $ 975CO 2 Segment EBDA$ 689 $ 819Certain Items(b)Change in fair value of derivative contracts 4 (11)CO 2 Adjusted Segment EBDA$ 693 $ 808
(a) Includes revenues, earnings from equity investments, operating expense s, 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 incom e taxes. See “ —Overview—GAAP Financial Measures ” above.(b) See “ —Overview—Non-GAAP Financial Measures— Certain Items” above.51Segment Earnings Results
Natural Gas Pipelines
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 4,801Certain 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 $ 4,942Change from prior period Increase/(Decrease)Segment EBDA $ 481
Adjusted Segment EBDA $ 218Volumetric 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) See table included in “ —Overview—Non-GAAP Financial Measures— Certain Items” above. 2023 and 2022 Certain Items of (i) $(122) million and $63 million, respectively, are associated with our Midstream business; (ii) none and $1 million, respectively, are associated with our East business; and (iii) none and $77 million, respectively, are associated with our West business. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.
(b) Joint venture throughput is reported at our ownership share. Volumes for assets sold are excluded for all periods presented.
52Below 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 Natural Gas Pipelines Segment EBDA in the comparable years of 2023 and 2022 are explained by the following discussion:
• 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 higher services fees resulting from higher volumes and 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; and (ii) lower commodity sales margin driven primarily by lower volumes on our Oklahoma assets.Ove rall, Midstream’s revenue changes are partially offset by corresponding changes in costs of sales.• The $135 million (5%) increase in East was primarily d ue to (i) higher equity earnings from Midcontinent Express Pipeline LLC, driven by favorable pricing on new customer contracts entered into in the later part of 2022; (ii) higher revenues on our Stagecoach assets as a result of increased demand for its services and favorable pricing; (iii) higher revenues on TGP due to 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 higher pipeline maintenance costs.
• The $90 million (10%) increase in West was primarily due t o higher earnings from EPNG due to (i) increased revenues from favorable pricing on its 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.
53Products Pipelines
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 1,107Certain Items:Change in fair value of derivative contracts (1) —
Loss on impairment 67 —
Certain Items(a) 66 —
Adjusted Segment EBDA $ 1,128 $ 1,107Change from prior period Increase/(Decrease)Segment EBDA $ (45)
Adjusted Segment EBDA $ 21Volumetric 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) See table included in “ —Overview—Non-GAAP Financial Measures— Certain Items” above. 2023 and 2022 Certain Items of (i) $(1) million an d none, respectively, are associated with our Southeast Refined Products business and (ii) $67 million and none, respectively, are associated with our Crude and Condensate business. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.(b) Joint venture throughput is reported at our ownership share.
(c) Volumes include ethanol pipeline volumes.54Below are the changes in Products Pipelines Segment EBDA:
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 Products Pipelines Segment EBDA in the comparable years of 2023 and 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 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 re-contracting at lower rates and 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.
• The $13 million (5%) increase in Southeast Refined Products was driven by (i) an increase in equity earnings from Products (SE) Pipe Line primarily due to increased revenues driven by higher rates, volumes and blending activities partially offset by unfavorable net changes in product gains and losses and (ii) higher revenues on Central Florida Pipeline LLC due to higher volumes and rates partially offset by lower earnings at our Transmix processing operations primarily due to unfavorable product pricing.
• The $8 million (2%) increase in West Coast Refined Products was impacted by increased revenues from our Pacific operations as a result of renewable diesel growth projects and higher rates partially offset by higher operating costs driven by 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.
55Terminals
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 $ 975Change from prior period Increase/(Decrease)Segment EBDA $ 65Volumetric 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 highe r 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.
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• 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 ste el handling activities partially offset by reduced revenues from coal handling activities and higher labor and other operating expenses.CO 2
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 819Certain Items:Change in fair value of derivative contracts 4 (11)
Certain Items(a) 4 (11)
Adjusted Segment EBDA $ 693 $ 808Change 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 9.40CO 2 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) See table included in “ —Overview—Non-GAAP Financial Measures— Certain Items” above. 2023 and 2022 Certain Items are associated with our Oil and Gas Producing activities. For m 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 presente d, 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.
57Below are the changes in CO 2 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 10Total CO 2$ 689 $ 819 $ (130)
The changes in CO 2 Segment EBDA in the comparable years of 2023 and 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 non-cash unrealized derivative hedge contracts, which we treated as Certain Items.
• The $60 million (24%) decrease in Source and Transportation activities was primarily due to lower revenues related to lower CO 2 sales prices and volumes.
• The $10 million (53%) increase in Energy Transition Ventures activities was primarily driven by three additional plants placed into service during 2023 leading to higher RNG margins as a result of higher volumes, partially offset by higher operating expenses.
We believe that our existing hedge contracts in place within our CO 2 busines s segment substantially mitigate commodity price sensitivities in the near-term and to lesser extent over the following few years from price exposure. Below is a summary of our CO 2 business segment hedges outstanding as of December 31, 2023.
2024 2025 2026 2027 2028Crude Oil(a)Price ($ per Bbl) $ 65.27 $ 63.91 $ 65.16 $ 64.38 $ 61.40
Volume (MBbl/d) 21.00 12.85 8.60 3.60 0.10
NGLs
Price ($ per Bbl) $ 51.58
Volume (MBbl/d) 3.20
(a) Includes West Texas Intermediate hedges.Liquidity and Capital Resources
GeneralAs of December 31, 2023, we had $83 million of “Cash and cash equivalents,” a decrease of $662 million from December 31, 2022. Additionally, as of December 31, 2023, we had borrowing capacity of approximately $1.4 billion under our credit facility (discussed below in “ —Short-term Liquidity ”). As discussed further below, we believe our cash flows from operating activities, cash position and remaining borrowing capacity on our credit facility is more than adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.
We have consistently generated substantial cash flow from operations, providing a source of funds of $6,491 million and $4,967 million in 2023 and 2022, respectively. The year-to-year increase is discussed below in “ —Cash Flows—Operating Activities. ” We primarily rely on cash provided by operations to fund our operations as well as our debt service, sustaining capital expenditures, dividend payments and our growth capital expenditures; however, we may access the debt capital markets from time to time to refinance our maturing long-term debt and finance incremental investments, if any. From time to time,
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short-term borrowings are used to finance our expansion capital expenditures, which we may periodically replace with long-term financing and/or pay down using retained cash from operations.
Our Board declared a quarterly dividend of $0.2825 per share for the fourth quarter of 2023, consistent with previous quarters in 2023. The total of the dividends declared for 2023 of $1.13 represents a 2% increase over total dividends declared for 2022.
We financed our fourth quarter acquisition of STX Midstream using commercial paper borrowings.
On January 31, 2023, we issued in a registered offering, $1,500 million aggregate principal amount of 5.20% senior notes due 2033 for net proceeds of $1,485 million, which were used to repay short-term borrowings, maturing debt and for general corporate purposes.
During the year ended December 31, 2023, upon maturity, we repaid our 3.15% senior notes, our floating rate senior notes, our 3.45% senior notes, our 3.50% senior notes and our 5.625% senior notes.
On February 1, 2024, we issued in a registered offering, two series of senior notes consisting of $1,250 million aggregate principal amount of 5.00% senior notes due 2029 and $1,000 million aggregate principal amount of 5.40% senior notes due 2034 for combined net proceeds of $2,230 million, which were used to repay short-term borrowings, fund maturing debt and for general corporate purposes.Short-term LiquidityAs of December 31, 2023, our principal sources of short-term liquidity are (i) cash from operations; and (ii) our $3.5 billion credit facility with an available capacity of approximately $1.4 billion and an associated $3.5 billion commercial paper program. The loan commitments under our credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Commercial paper borrowings and letters of credit reduce borrowings allowed under our credit facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facility and, as previously discussed, have consistently generated strong cash flows from operations.
As of December 31, 2023, our $4,049 million of short-term debt consisted primarily of commercial paper borrowings and senior notes that mature in the next twelve months. We intend to fund our debt as it becomes due, primarily through credit facility borrowings, commercial paper borrowings, cash flows from operations, and/or issuing new long-term debt. Our short-term debt balance as of December 31, 2022 was $3,385 million.
We had working capital (defined as current assets less current liabilities) deficits of $4,679 million and $3,127 million as of December 31, 2023 and 2022, respectively. The overall $1,552 million unfavorable change from year-end 2022 was primarily due to (i) a $664 million increase in current debt, primarily related to commercial paper borrowings used to fund our acquisition of STX Midstream; (ii) a $662 million decrease in cash and cash equivalents, resulting from using cash on hand as of December 31, 2022 to repay a portion of our senior notes that matured in the first quarter of 2023 partially offset by a decrease in current maturities of senior notes; (iii) a $174 million net unfavorable change in our accounts receivables and payables; (iv) a $109 million decrease in inventories, primarily products inventories; and (v) a $97 million decrease in other current assets, primarily in exchange gas receivables and regulatory assets; partially offset by favorable net short-term fair value adjustments of $155 million on derivative contract assets and liabilities in 2023. Generally, our working capital varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts and changes in our cash and cash equivalent balances as a result of excess cash from operations after payments for investing and financing activities (discussed below in “ —Long-term Financing ” and “ —Capital Expenditures ”).We employ a centralized cash management program for our U.S.-based bank accounts that concentrates the cash assets of our wholly owned subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing. These programs provide that funds in excess of the daily needs of our wholly owned subsidiaries are concentrated, consolidated or otherwise made available for use by other entities within the consolidated group. We place no material restrictions on the ability to move cash between entities, payment of intercompany balances or the ability to upstream dividends to KMI other than restrictions that may be contained in agreements governing the indebtedness of those entities.59Credit Ratings and Capital Market Liquidity
We believe that our capital structure will continue to allow us to achieve our business objectives. We expect that our short-term liquidity needs will be met primarily through retained cash from operations or short-term borrowings. Generally, we anticipate re-financing maturing long-term debt obligations in the debt capital markets and are therefore subject to certain market conditions which could result in higher costs or negatively affect our and/or our subsidiaries’ credit ratings. A decrease in our credit ratings could negatively impact our borrowing costs and could limit our access to capital.The following table represents our debt ratings as of December 31, 2023.Rating agency Short-term rating Long-term rating OutlookStandard and Poor’s A-2 BBB StableMoody’s Investor Services Prime-2 Baa2 Stable
Fitch Ratings, Inc. F2 BBB StableLong-term Financing
Our equity consists of Class P common stock with a par value of $0.01 per share. We do not expect to need to access the equity capital markets to fund our discretionary capital investments for the foreseeable future. See also “— Dividends and Stock Buy-back Program ” below for additional discussion related to our dividends and stock buy-back program.From time to time, we issue long-term debt securities, often referred to as senior notes. Our senior notes issued to date, other than those issued by certain of our subsidiaries, generally have very similar terms, except for interest rates, maturity dates and prepayment premiums. All of our fixed rate senior notes provide that the notes may be redeemed at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date, and, in most cases, plus a make-whole premium. In addition, from time to time, our subsidiaries issue long-term debt securities. Furthermore, we and almost all of our direct and indirect wholly owned domestic subsidiaries are parties to a cross guaranty wherein each party guarantees each other party’s debt. See “ —Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries .” As of December 31, 2023 and 2022, the aggregate principal amount outstanding of our various long-term debt obligations (excluding current maturities) was $27,880 million and $28,288 million, respectively.
We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of December 31, 2023 and 2022, approximately $8,253 million (26%) and $6,314 million (20%), respectively, of the principal amount of our debt balances were subject to variable interest rates—either as short-term or long-term variable-rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. The December 31, 2023 amount includes $1,989 million of commercial paper notes. The percentage at December 31, 2022 includes $1,250 million of variable-to-fixed interest rate derivative contracts which expired in December 2023.
For additional information about our outstanding senior notes and debt-related transactions in 2023, see Note 9 “Debt” to our consolidated financial statements. For information about our interest rate risk, see Note 14 “Risk Management— Interest Rate Risk Management ” to our consolidated financial statem ents and Item 7A. “ Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk. ”Capital Expenditures
We account for our capital expenditures in accordance with GAAP. Additionally, we distinguish between capital expenditures as follows:
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 improvementsBudgeting of maintenance capital expenditures, which we refer to as sustaining capital expenditures, is done annually on a bottom-up basis. For each of our assets, we budget for and make those sustaining capital expenditures that are necessary to
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maintain safe and efficient operations, meet customer needs and comply with our operating policies and applicable law. We may budget for and make additional sustaining capital expenditures that we expect to produce economic benefits such as increasing efficiency and/or lowering future expenses. Budgeting and approval of expansion capital expenditures generally occurs periodically throughout the year on a project-by-project basis in response to specific investment opportunities identified by our business segments from which we generally expect to receive sufficient returns to justify the expenditures. Assets comprising expansion capital projects could result in additional sustaining capital expenditures over time. The need for sustaining capital expenditures in respect of newly constructed assets tends to be minimal but tends to increase over time as such assets age and experience wear and tear. Regardless of whether assets result from sustaining or expansion capital expenditures, once completed, the addition of such assets to our depreciable asset base will impact our calculation of depreciation, depletion and amortization over the remaining useful lives of the impacted or resulting assets.
Generally, the determination of whether a capital expenditure is classified as sustaining or as expansion capital expenditures is made on a project level. The classification of our capital expenditures as expansion capital expenditures or as sustaining capital expenditures is made consistent with our accounting policies and is generally a straightforward process, but in certain circumstances can be a matter of management judgment and discretion. The classification has an impact on DCF because capital expenditures that are classified as expansion capital expenditures are not deducted in calculating DCF, while those classified as sustaining capital expenditures are.
Our capital expenditures for the year ended December 31, 2023, and the amount we expect to spend for 2024 to sustain our assets and expand our business are as follows:
2023 Expected 2024(In millions)
Capital expenditures:Sustaining capital expenditures $ 868 $ 990
Expansion capital expenditures 1,594 2,086
Accrued capital expenditures, contractor retainage and other (145) —
Capital expenditures $ 2,317 $ 3,076Add:Sustaining capital expenditures of unconsolidated joint ventures(a) $ 163 $ 192
Investments in unconsolidated joint ventures(b) 238 214
Less: Consolidated joint venture partners’ sustaining capital expenditures (9) (11)
Less: Consolidated joint venture partners’ expansion capital expenditures (20) (24)
Acquisitions
1,843 —
Accrued capital expenditures, contractor retainage and other 145 —
Total capital investments $ 4,677 $ 3,447(a) Sustaining capital expenditures by our joint ventures generally do not require cash outlays by us.
(b) Reflects cash contributions to unconsolidated joint ventures. Also includes contributions to an unconsolidated joint venture that are netted within the amount the joint venture declares as a distribution to us.61Our capital investments consist of the following:2023 Expected 2024(In millions)
Sustaining capital investmentsCapital 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 1,171Expansion capital investmentsCapital 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(a) Sustaining capital expenditures by our joint ventures generally do not require cash outlays by us.
(b) Reflects cash contributions to unconsolidated joint ventures. Also includes contributions to an unconsolidated joint venture that are netted within the amount the joint venture declares as a distribution to us.
Impact of RegulationThe trend toward increasingly stringent regulations creates uncertainty regarding our capital and operating expenditure requirements over the longer term. For example, on June 5, 2023, the EPA’s final rule known as the “Good Neighbor Plan” (the Plan) was published in the federal register. 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 Plan imposes prescriptive emission standards for several sectors, including new and existing internal combustion engines of a certain size used in pipeline transportation of natural gas. The EPA subsequently 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.
Multiple legal challenges have already been filed, including by us. See Note 18, “Litigation and Environmental— Environmental Matters—Challenge to Federal “Good Neighbor Plan ,” to our consolidated financial statements. While we are unable to predict whether any legal challenges will result in changes to the Plan or how those changes, if any, would impact us, we believe that the EPA’s disapprovals of the SIPs were improper, that the Plan is deeply flawed and that numerous and substantial bases for challenging the Plan exist. Several states in which we have affected assets, including Arkansas, Kentucky, Louisiana, Mississippi, Missouri, Oklahoma and Texas, have appealed the EPA’s disapprovals of SIPs and requested stays pending appeal. The criteria for a stay pending appeal include a requirement that the applicant show likelihood of success on the merits. Stays pending appeal have been granted with respect to the EPA’s disapprovals of SIPs submitted by Alabama, Arkansas, Kentucky, Louisiana, Minnesota, Mississippi, Missouri, Nevada, Oklahoma Texas, Utah and West Virginia meaning that (for as long as the stays remain in place) the EPA no longer has a legal basis to enforce the Plan in these states. In response to those stays, on July 31, 2023, and September 29, 2023, the EPA published interim final rules acknowledging that the Plan requirements in those states were suspended and indicating that the Plan compliance deadlines in those states may be extended. The guidance afforded by the EPA in the interim final rules is uncertain so we have filed petitions seeking review of the interim final rules. If the Plan were fully implemented, its 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 would require 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 were to remain 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 it would have a material impact on us, including estimated costs necessary to comply with the Plan ranging from $1.5 billion to $1.8 billion (including costs for joint ventures that we operate, net to our interests in such joint ventures), potential shortages of equipment resulting in our inability to comply with the Plan, and operational disruptions. However, impacts are difficult to predict, given the extensive pending litigation. The outcomes of these numerous lawsuits may significantly decrease our exposure. For example, our currently estimated costs necessary to comply with the Plan associated with states that have not been granted stays with respect to the EPA’s disapproval of their SIPs range from $200 million to $300
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million. However, successful challenges to the Plan would impact all affected states. In addition, we would seek to mitigate the impacts and to recover expenditures through adjustments to our rates on our regulated assets where available.The cost estimates discussed above are preliminary, based on a number of assumptions and subject to significant variation, including outside of the ranges provided. Costs are assumed based on the average cost incurred historically for a typical retrofit of an average engine. These estimates reflect only the anticipated upgrades that would need to be performed (and in the case of joint ventures, only on assets that we operate) and do not take into account potential complications such as additional maintenance requirements that may be identified during the upgrade process.
Off Balance Sheet ArrangementsWe have invested in entities that are not consolidated in our financial statements. For information on our obligations with respect to these investments, as well as our obligations with respect to related letters of credit, see Note 13 “Commitments and Contingent Liabilities” to our consolidated financial statements. Additional information regarding the nature and business purpose of our investments is included in Note 7 “Investments” to our consolidated financial statements.Contractual Obligations and Commercial Commitments
The table below provides a summary of our material cash requirements.
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 $ 22,439Interest 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 $ 36,284Other commercial commitments:Standby letters of credit(g) $ 157 $ 85 $ 72
Capital expenditures(h) $ 469 $ 469
(a) See Note 9 “Debt” to our consolidated financial statements.
(b) Interest payment obligations exclude adjustments for interest rate swap agreements and assume no change in variable interest rates from those in effect at December 31, 2023.
(c) Represents commitments pursuant to the terms of operating lease agreements as of December 31, 2023.
(d) Represents the amount by which the benefit obligations exceeded the fair value of plan assets at year-end for pension and OPEB plans whose accumulated postretirement benefit obligations exceeded the fair value of plan assets. The payments by period include expected contributions in 2024 and estimated benefit payments for underfunded plans in the other years.
(e) Primarily represents transportation agreements of $310 million, storage agreements for capacity of $189 million and NGL volume agreements of $109 million.
(f) Primarily includes (i) rights-of-way obligations; and (ii) environmental liabilities related to sites that we own or have a contractual or legal obligation with a regulatory agency or property owner upon which we will perform remediation activities. These environmental liabilities are included within “Other current liabilities” and “Other long-term liabilities and deferred credits” in our consolidated balance sheet as of December 31, 2023.
(g) The $157 million in letters of credit outstanding as of December 31, 2023 consisted of the following (i) $51 million under six letters of credit for insurance purposes; (ii) a $46 million letter of credit supporting our International Marine Terminals Partnership Plaquemines Bond; (iii) a $24 million letter of credit supporting our Kinder Morgan Operating LLC “B” tax-exempt bonds; and (iv) a combined $36 million in thirty-four letters of credit supporting environmental and other obligations of us and our subsidiaries.
(h) Represents commitments for the purchase of plant, property and equipment as of December 31, 2023.
63Cash FlowsThe following table summarizes our net cash flows provided by (used in) operating, investing and financing activities between 2023 and 2022.Year Ended December 31,2023 2022 Changes(In millions)
Net Cash Provided by (Used in)Operating activities $ 6,491 $ 4,967 $ 1,524
Investing activities (4,175) (2,175) (2,000)
Financing activities (3,014) (3,145) 131
Net Decrease in Cash, Cash Equivalents and Restricted Deposits $ (698) $ (353) $ (345)Operating Activities$1,524 million more cash provided by operating activities in the comparable years of 2023 and 2022 is explained by the following discussion.
• an $894 million increase in cash related to changes in deferred revenues primarily driven by an $843 million prepayment received for certain fixed reservation charges under long-term transportation and terminaling contracts in the 2023 period. See Note 15 “Revenue Recognition” to our consolidated financial statements for further information regarding this prepayment; and
• an $896 million increase in cash associated with net changes in working capital items and other non-current assets and liabilities, excluding the change in deferred revenues discussed above. The increase was primarily driven by (i) the sale of natural gas inventories and higher settlements associated with commodity hedges in 2023, both related to gas in underground storage; (ii) lower litigation payments in the 2023 period compared with 2022; (iii) net favorable changes related to the timing of accounts receivable collections and trade payable payments, largely in our Natural Gas Pipelines business segment; and (iv) higher pension benefit expenses in 2023, which are netted against contribution payments, resulting from actuarial valuation adjustments and one-time pension cost adjustments related to settlements made by our pension plans.Investing Activities$2,000 million more cash used in investing activities in the comparable years of 2023 and 2022 is explained by the following discussion.
• a $1,355 million increase in expenditures for the acquisition of assets and investments, net of cash acquired, primarily driven by $1,829 million of net cash used for the acquisition of STX Midstream in 2023, compared with a combined $487 million of net cash used for our acquisitions of Mas Ranger, LLC and NANR in 2022; See Note 3 “Acquisitions and Divestitures” to our consolidated financial statements for further information regarding these acquisitions; and
• a $696 million increase in capital expenditures primarily driven by the expansion projects in our Natural Gas Pipelines and Terminals business segments, partially offset by a decrease in expansion projects in our Products Pipelines business segment.Financing Activities$131 million less cash used in financing activities in the comparable years of 2023 and 2022 is explained by the following discussion.
• a $916 million net increase in cash related to debt activity as a result of net issuances in 2023 compared to net debt payments in 2022. Net debt issuances in 2023 were primarily driven by the utilization of borrowings under our credit facility to fund the STX Midstream acquisition; partially offset by,
• a decrease of $557 million in cash due to net proceeds received from the sale of a 25.5% ownership interest in ELC in 2022; and
• a $154 million increase in cash used for share repurchases under our share buy-back program.
64Dividends and Stock Buy-back ProgramThe table below reflects the declaration of dividends of $1.13 per share for 2023:Three months ended Total quarterly dividend per share for the period Date of declaration Date of record Date of dividendMarch 31, 2023
$0.2825 April 19, 2023 May 1, 2023 May 15, 2023
June 30, 2023
0.2825 July 19, 2023 July 31, 2023 August 15, 2023
September 30, 2023
0.2825 October 18, 2023 October 31, 2023 November 15, 2023
December 31, 2023
0.2825 January 17, 2024 January 31, 2024 February 15, 2024
We expect to continue to return additional value to our shareholders in 2024 through our previously announced dividend increase. We plan to increase our divide nd by 2% to $1 .15 per common share in 2024. On January 18, 2023, our Board approved an increase to our stock buy-back program from $2 billion to $3 billion. S ince December 2017, in total, we have repurchased approximately 86 million shares of our Class P common stock under the program at an average price of $17.09 per share for $1,472 million, leaving a remaining capacity of approximately $1.5 billion . For information on our stock buy-back program, see Note 11 “Stockholders’ Equity” to our consolidated financial statements.The actual amount of dividends to be paid on our capital stock will depend on many factors, including our financial condition and results of operations, liquidity requirements, business prospects, capital requirements, legal, regulatory and contractual constraints, tax laws, Delaware laws and other factors. See Item 1A. “ Risk Factors—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. ” All of these matters will be taken into consideration by our Board when declaring dividends.
Our dividends are not cumulative. Consequently, if dividends on our stock are not paid at the intended levels, our stockholders are not entitled to receive those payments in the future. Our dividends generally will be paid on or about the 15th day of each February, May, August and November.65Summarized Combined Financial Information for Guarantee of Securities of SubsidiariesKMI and certain subsidiaries (Subsidiary Issuers) are issuers of certain debt securities. KMI and substantially all of KMI’s wholly owned domestic subsidiaries (Subsidiary Guarantors), are parties to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement. Accordingly, with the exception of certain subsidiaries identified as subsidiary non-guarantors (Subsidiary Non-Guarantors), the parent issuer, Subsidiary Issuers and Subsidiary Guarantors (the “Obligated Group”) are all guarantors of each series of our guaranteed debt (Guaranteed Notes). As a result of the cross guarantee agreement, a holder of any of the Guaranteed Notes issued by KMI or Subsidiary Issuers are in the same position with respect to the net assets, and income of KMI and the Subsidiary Issuers and Guarantors. The only amounts that are not available to the holders of each of the Guaranteed Notes to satisfy the repayment of such securities are the net assets, and income of the Subsidiary Non-Guarantors.
In lieu of providing separate financial statements for the Obligated Group, we have presented the accompanying supplemental summarized combined income statement and balance sheet information for the Obligated Group based on Rule 13-01 of the SEC’s Regulation S-X. Also, see Exhibit 10.11 to this Report “ Cross Guarantee Agreement, dated as of November 26, 2014, among KMI and certain of its subsidiaries, with schedules updated as of December 31, 2023. ”All significant intercompany items among the Obligated Group have been eliminated in the supplemental summarized combined financial information. The Obligated Group’s investment balances in Subsidiary Non-Guarantors have been excluded from the supplemental summarized combined financial information. Significant intercompany balances and activity for the Obligated Group with other related parties, including Subsidiary Non-Guarantors (referred to as “affiliates”), are presented separately in the accompanying supplemental summarized combined financial information.Excluding fair value adjustments, as of December 31, 2023 and 2022, the Obligated Group had $31,167 million and $30,886 million, respectively, of Guaranteed Notes outstanding.Summarized combined balance sheet and income statement information for the Obligated Group follows:
December 31,Summarized Combined Balance Sheet Information 2023 2022(In millions)Current assets $ 2,246 $ 3,514
Current assets - affiliates 760 618
Noncurrent assets 62,877 61,523
Noncurrent assets - affiliates 903 516
Total Assets $ 66,786 $ 66,171
Current liabilities $ 6,907 $ 6,612
Current liabilities - affiliates 734 707
Noncurrent liabilities 31,681 30,668
Noncurrent liabilities - affiliates 1,306 1,096
Total Liabilities 40,628 39,083
Kinder Morgan, Inc.’s stockholders’ equity 26,158 27,088
Total Liabilities and Stockholders’ Equity $ 66,786 $ 66,171
Summarized Combined Income Statement Information Year Ended December 31, 2023(In millions)Revenues $ 14,131
Operating income 3,832
Net income 2,032
66Recent Accounting PronouncementsPlease refer to Note 19 “Recent Accounting Pronouncements” to our consolidated financial statements for information concerning recent accounting pronouncements.
FY 2024-12-31 (later)
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 helpful to the reading of our discussion and analysis include the following: (i) a description 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 2024, found in Items 1 and 2. “ Business and Properties—General Development of Business—Recent Developments; ” (iii) a description of terms for services and commodities we provide, found in Items 1 and 2.“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 2023 to 2022 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, 2023 filed with the SEC on February 20, 2024.GeneralAcquisitions and Divestitures
Following are acquisitions and divestitures we made during the 2024 reporting period. See Note 3 “Acquisitions and Divestitures” to our consolidated financial statements for further information on these transactions.Event Description Business SegmentNorth McElroy Unit acquisition
$61 million
(June 2024)
We acquired AVAD Energy Partners’ interest in the North McElroy Unit (NMU). NMU is an existing waterflood that currently produces approximately 1,250 Bbl/d of crude oil. Our analysis suggests that NMU could be a candidate for CO 2 flooding.CO 2
(Oil and Gas Producing activities)CO 2 assets divestiture
$18 million
(June 2024)
We sold our interests in the Katz Unit, Goldsmith Landreth San Andres Unit, Tall Cotton Field and Reinecke Unit, along with certain shallow interests in the Diamond M Field, all located in the Permian Basin, and received a leasehold interest in an undeveloped leasehold directly adjacent to the SACROC unit.
CO 2
(Oil and Gas Producing activities)
Oklahoma assets divestiture
$43 million
(February 2024)
We sold our Oklahoma midstream assets consisting of our Oklahoma system and Cedar Cove.
Natural Gas Pipelines
(Midstream)
Additionally, on January 13, 2025, we announced that we had entered into an agreement to purchase a natural gas gathering and processing system in North Dakota from Outrigger Energy II LLC for a cash payment of $640 million. The acquisition includes a 0.27 Bcf/d processing facility and a 104-mile, large-diameter, high-pressure rich gas gathering header pipeline with 0.35 Bcf/d of capacity connecting supplies from the Williston Basin area to high-demand markets. With this transaction, we expect to reduce future capital expenditures needed to accommodate the growth of our existing Bakken
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customers. Initially, we plan to fund the transaction with short-term borrowings and cash on hand. Subject to customary closing conditions and regulatory approval, this transaction is expected to close in the first quarter of 2025.
2025 Dividends and Discretionary Capital
We expect to declare dividends of $1.17 per share for 2025, a 2% increase from the 2024 declared dividends of $1.15 per share. We also expect to invest $2.3 billion in expansion projects and contributions to joint ventures, or discretionary capital expenditures, during 2025.
The expectations for 2025 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 “ Information Regarding Forward-Looking Statements ” at the beginning of this report and Item 1A. “ Risk Factors ” for more information.Critical Accounting Estimates
Critical accounting estimates and assumptions involve material levels of 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 certain areas that require more judgment relative to others when preparing our consolidated financial statements and related disclosures 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) assignment of the purchase price for a business acquisition, (b) calculations of possible asset and equity investment impairment charges, (c) calculation for the annual goodwill impairment test (or interim tests if triggered), and (d) recording derivative contract assets and 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.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. For discussion on our hedging activities and related sensitivities to our estimates, see Note 13 “Risk Management” to our consolidated financial statements and Item 7A. “ Quantitative and Qualitative Disclosures About Market Risk ,” respectively.ImpairmentsIn 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 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.Environmental MattersWith 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. 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 liability claims. For more information on environmental matters, see Part I, Items 1 and 2. “ Business and Properties—Narrative Description of Business—Environmental Matters. ” For more information on our environmental disclosures, see Note 17 “Litigation and Environmental” to our consolidated financial statements.
40Legal and Regulatory MattersMany 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. 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 17 “Litigation and Environmental” to our consolidated financial statements.Employee Benefit PlansOur pension and OPEB obligations and net benefit costs are primarily based on actuarial calculations. A significant assumption we utilize is the discount rate used in calculating our benefit obligations. The selection of assumptions used in the actuarial calculations of our pension and OPEB plans is further discussed in Note 9 “ Share-based Compensation and Employee 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.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, 2024:Pension Benefits OPEB
Net benefit cost (credit) Funded status
Net benefit cost (credit) Funded status(a)
(In millions)
One percent increase in:Discount rates $ (9) $ 118 $ — $ 10
Expected return on plan assets (15) — (3) —
Rate of compensation increase 2 (9) 1 (5)One percent decrease in:Discount rates 11 (137) — (11)
Expected return on plan assets 15 — 3 —
Rate of compensation increase (2) 8 (1) 5(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 TaxesWe make significant judgments and estimates in determining our provision for income taxes, including our assessment of our income tax positions given the uncertainties involved in the interpretation and application of complex tax laws and regulations in various taxing jurisdictions. Numerous and complex judgments and assumptions are inherent in the estimation of future taxable income when determining a valuation allowance, including factors such as future operating conditions and the apportionment of income by state. For more information, see Note 4 “Income Taxes” to our consolidated financial statements.Results of Operations
OverviewAs described in further detail below, our management evaluates our performance primarily using Net income attributable to Kinder Morgan, Inc. and Segment earnings before DD&A expenses including amortization of excess cost of equity investments (EBDA) (as presented in Note 15 “Reportable Segments”), along with the non-GAAP financial measures of Adjusted Net
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Income Attributable to Common Stock, in the aggregate and per share, Adjusted Segment EBDA, Adjusted Net 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. Historically, we have disclosed the non-GAAP financial measure of distributable cash flow (DCF), in the aggregate and per share; however, we are not including discussion of DCF in this report due to declining investor interest in DCF as a primary performance measure.GAAP Financial MeasuresThe Consolidated Earnings Results for the years ended December 31, 2024 and 2023 present Net income attributable to Kinder Morgan, Inc., as prepared and presented in accordance with GAAP, and Segment EBDA, which is disclosed in Note 15 “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, IT, human resources and legal services.Non-GAAP Financial MeasuresOur 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 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 processes.Certain ItemsCertain 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 Adjusted Net Income Attributable to Common Stock” 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, 2024 and 2023, which are also described in more detail in the footnotes to tables included in “—Segment Earnings Results” below.Year Ended December 31,2024 2023
(In millions)Certain ItemsChange in fair value of derivative contracts(a) $ 72 $ (126)
(Gain) loss on divestitures and impairment, net(b)
(69) 67
Income tax Certain Items(c)
(52) 33
Other(d)
7 45
Total Certain Items(e)
$ (42) $ 19
(a) Gains or losses are reflected within non-GAAP financial measures when realized.
(b) 2024 amount represents gains of $40 million and $29 million, respectively, on divestitures of CO 2 and Oklahoma midstream assets. 2023 amount represents $67 million included within “Earnings from equity investments” on the accompanying consolidated statement of income for a non-cash impairment related to our investment in Double Eagle Pipeline LLC in our Products Pipelines business segment (see Note 6 “Investments”).
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(c) 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 amount represents pension cost adjustments related to settlements made by our pension plans.
(e) 2024 and 2023 amounts include the following amounts reported within “Interest, net” on the accompanying consolidated statements of income: $(5) million and $(7) million, respectively, of “Change in fair value of derivative contracts.”Adjusted Net Income Attributable to Kinder Morgan, Inc.Adjusted Net Income Attributable to Kinder Morgan, Inc. 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.” below.Adjusted Net Income Attributable to Common Stock and Adjusted EPSAdjusted 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 believe Adjusted Net Income Attributable to Common Stock 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.Adjusted Segment EBDAAdjusted Segment EBDA is calculated by adjusting segment earnings before DD&A and amortization of excess cost of equity investments, general and administrative expenses and corporate charges, interest expense, and income taxes (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 EBITDAAdjusted 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 .
43Amounts from Joint VenturesCertain Items 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 calculation of Adjusted EBITDA related to our unconsolidated and consolidated joint ventures include DD&A and income tax expense) with respect to the joint ventures as those included in the calculation of 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 Adjusted EBITDA” below.) Although these amounts related to our unconsolidated joint ventures are included in the calculation of 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.Net DebtNet Debt is calculated, based on amounts as of December 31, 2024, by subtracting the following amounts from our debt balance of $31,890 million: (i) cash and cash equivalents of $88 million; (ii) debt fair value adjustments of $102 million; and (iii) the foreign exchange impact on Euro-denominated bonds of $(25) million f or 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.
44Consolidated Earnings Results
The following tables summarize the key components of our consolidated earnings results.
Year Ended December 31,2024 2023 Earnings increase/(decrease)
(In millions, except per share amounts and percentages)
Revenues $ 15,100 $ 15,334 $ (234) (2) %Operating Costs, Expenses and OtherCosts of sales (exclusive of items shown separately below) (4,337) (4,938) 601 12 %
Operations and maintenance (2,972) (2,807) (165) (6) %
DD&A (2,354) (2,250) (104) (5) %
General and administrative (712) (668) (44) (7) %
Taxes, other than income taxes (433) (421) (12) (3) %
Other income, net
92 13 79 608 %
Total Operating Costs, Expenses and Other (10,716) (11,071) 355 3 %
Operating Income 4,384 4,263 121 3 %Other Income (Expense)Earnings from equity investments 890 838 52 6 %
Amortization of excess cost of equity investments (50) (66) 16 24 %
Interest, net (1,844) (1,797) (47) (3) %
Other, net 27 (37) 64 173 %
Total Other Expense (977) (1,062) 85 8 %
Income Before Income Taxes 3,407 3,201 206 6 %
Income Tax Expense (687) (715) 28 4 %
Net Income 2,720 2,486 234 9 %
Net Income Attributable to Noncontrolling Interests (107) (95) (12) (13) %
Net Income Attributable to Kinder Morgan, Inc. $ 2,613 $ 2,391 $ 222 9 %
Basic and diluted earnings per share $ 1.17 $ 1.06 $ 0.11 10 %
Basic and diluted weighted average shares outstanding 2,220 2,234 (14) (1) %
Declared dividends per share $ 1.15 $ 1.13 $ 0.02 2 %
Our consolidated revenues primarily consist of services and sales revenue. Our services 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 sales revenues include sales of natural gas (includes natural gas and RNG), products (includes NGL, crude oil, CO 2 and transmix) and other (includes RINs). Our consolidated sales revenue will fluctuate with commodity prices and volumes, and the costs of sales associated with purchases will usually have a commensurate and offsetting impact, except for the CO 2 segment, which produces, instead of purchases, the crude oil, CO 2, and RINs 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 2024 and 2023:RevenuesRevenue s decreas ed $234 million in 2024 compared to 2023. The decrease was primarily due to (i) a $398 million decrease in product sales driven by lower volumes resulting primarily from contractual changes and an asset divestiture and (ii) a $326 million decrease in n atural gas sales due to lower commodity prices partially offset by higher volumes. These decreases in sales revenues were partially offset by a $45 million increase in other sales driven by higher RIN sales. Revenues were
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further reduced by $151 million for the impacts of derivative contracts used to hedge commodity sales which includes both realized and unrealized gains and losses from derivatives. Services revenues increased $ 515 million driven by (i) higher volumes, including from expansion projects; (ii) our late 2023 acquisition of the STX Midstream assets partially offset by a reduction in revenues related to divested assets; and (iii) higher rate escalations. Th e decrease in sales revenues had a corresponding decrease in our costs of sales as described below under “ Operating Costs, Expenses and Other—Costs of sales .”Operating Costs, Expenses and Other
Costs of SalesCosts of sale s decreased $601 million in 2024 compared to 2023. The decrease, which includes the impact of our divested assets, was primarily due to lower costs of sales for (i) natural gas of $447 million primarily due to lower commodity prices partially offset by higher volumes; and (ii) products of $269 million driven primarily by lower volumes partially offset by an increase of $145 million related to derivative contracts used to hedge commodity purchases which includes both realized and unrealized gains and losses from d erivatives.Operations and MaintenanceOperations and maintenance increa sed $165 million in 2024 compared to 2023. I ncreased costs were primarily driven by greater activity levels and inflation, including for service, integrity, labor and fuel costs.
DD&A
DD&A increased $ 104 million in 2024 compared to 2023. The increase was primarily due to our late 2023 acquisition of the STX Midstream assets and an increase in SACROC’s unit of production rate partially offset by the impact of our divested assets.Other Income (Expense)
Interest, netIn the table above, we report our interest expense as “net,” meaning that we have subtracted interest income and capitalized interest from our to tal interest expense to arrive at one interest amount. Our interest expense, net increased $47 million in 2024 compared to 2023. The increase was primarily due to (i) higher average short-term and long-term debt balances driven by funding our STX Midstream acquisition; and (ii) higher interest rates associated with our fixed-to-variable interest rate swap agreements and our long-term debt; partially offset by a reduction in the notional balances associated with our fixed-to-variable interest rate swap agreements.
46Non-GAAP Financial MeasuresReconciliations from Net Income Attributable to Kinder Morgan, Inc.Year Ended December 31,2024 2023(In millions, except per share amounts)Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Kinder Morgan, Inc.
Net income attributable to Kinder Morgan, Inc. $ 2,613 $ 2,391Certain Items(a)Change in fair value of derivative contracts 72 (126)
(Gain) loss on divestitures and impairment, net (69) 67
Income tax Certain Items (52) 33
Other 7 45
Total Certain Items (42) 19Adjusted Net Income Attributable to Kinder Morgan, Inc.$ 2,571 $ 2,410Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Common StockNet income attributable to Kinder Morgan, Inc. $ 2,613 $ 2,391Total Certain Items(b)(42) 19
Net income allocated to participating securities and other(c)
(14) (14)Adjusted Net Income Attributable to Common Stock$ 2,557 $ 2,396Adjusted EPS$ 1.15 $ 1.07Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDANet income attributable to Kinder Morgan, Inc. $ 2,613 $ 2,391
Total Certain Items(b)
(42) 19
DD&A 2,354 2,250
Amortization of excess cost of equity investments 50 66
Income tax expense(d) 739 682
Interest, net(e)
1,849 1,804Amounts from joint venturesUnconsolidated joint venture DD&A 359 323
Remove consolidated joint venture partners’ DD&A (62) (63)
Unconsolidated joint venture income tax expense(f)
78 89
Adjusted EBITDA $ 7,938 $ 7,561(a) See table included in “ —Overview—Non-GAAP Financial Measures— Certain Items” above.(b) See “— Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Kinder Morgan, Inc. ” for a detailed listing.
(c) 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. Other includes Adjusted net income in excess of distributions for participating securities of $1 million and none for 2024 and 2023, respectively.
(d) To avoid duplication, adjustments for income tax expense for 2024 and 2023 exclude $(52) million and $33 million, which amounts are already included within “Certain Items.” See table included in “ —Overview—Non-GAAP Financial Measures— Cer tain Items” above.
(e) To avoid duplication, adjustments for interest, net for 2024 and 2023 exclude $(5) million and $(7) million, respectively, whic h amounts are already included within “Certain Items.” See table included in “ —Overview—Non-GAAP Financial Measures— Certain Items,” above.
(f) Includes the tax provision on Certain Items recognized by the investees that are taxable entities associated with our Citrus, NGPL Holdings and Products (SE) Pipe Line equity investments. The impact of KMI’s income tax provision on Certain Items affecting earnings from equity investments is included within “Certain Items” above.
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Below is a discussion of significant changes in our Adjusted Net Income Attributable to Kinder Morgan, Inc. and Adjusted EBITDA :Year Ended December 31,2024 2023(In millions)
Adjusted Net Income Attributable to Kinder Morgan, Inc.$ 2,571 $ 2,410
Adjusted EBITDA 7,938 7,561Change from prior period Increase/(Decrease)
Adjusted Net Income Attributable to Kinder Morgan, Inc.$ 161
Adjusted EBITDA $ 377
Adjusted Net Income Attributable to Kinder Morgan, Inc. increased $161 mill ion in 2024 compared to 2023. The increase resulted primarily fro m favorable earnings in our Natural Gas Pipelines, Terminals and Products Pipelines business segments, which were also primary drivers of the increase in Adjus ted EBITDA of $377 million, partially offset by an increase in DD&A expenses .General and Administrative and Corporate Charges
Year Ended December 31,2024 2023(In millions)General and administrative $ (712) $ (668)
Corporate charges (24) (91)
Certain Items(a) 7 45
General and administrative and corporate charges $ (729) $ (714)Change from prior period Earnings increase/(decrease)General and administrative $ (44)
Corporate charges 67Total$ 23
(a) See “ —Overview—Non-GAAP Financial Measures— Certain Items” above.
General and administrative expenses increased $44 million and corporate charges decreased $67 million in 2024 compared to 2023. The combined changes include $41 million consisting of higher labor and benefit-related costs, higher legal costs and higher corporate development costs, offset by lower pension costs of $30 million. In addition, the combined changes described above include $7 million of costs in 2024 and the impact of increased pension costs of $45 million in 2023 related to settlements made by our pension plans, which we treated as Certain Items.
48Reconciliation of Segment EBDA to Adjusted Segment EBDA
Year Ended December 31,2024 2023(In millions)
Segment EBDA(a)Natural Gas Pipelines Segment EBDA $ 5,427 $ 5,282Certain Items(b)Change in fair value of derivative contracts 75 (122)
Gain on divestiture (29) —
Natural Gas Pipelines Adjusted Segment EBDA $ 5,473 $ 5,160
Products Pipelines Segment EBDA $ 1,173 $ 1,062Certain Items(b)Change in fair value of derivative contracts — (1)
Loss on impairment — 67
Products Pipelines Adjusted Segment EBDA $ 1,173 $ 1,128
Terminals Segment EBDA $ 1,099 $ 1,040CO 2 Segment EBDA$ 692 $ 689Certain Items(b)Change in fair value of derivative contracts 2 4
Gain on divestitures (40) —CO 2 Adjusted Segment EBDA$ 654 $ 693
(a) Includes revenues, earnings from equity investments, operating expense s, other income, net, and other, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than incom e taxes. See “ —Overview—GAAP Financial Measures ” above.(b) See “ —Overview—Non-GAAP Financial Measures— Certain Items” above.49Segment Earnings Results
Natural Gas Pipelines
Year Ended December 31,2024 2023(In millions, except operating statistics)Revenues $ 8,942 $ 9,168
Costs of sales (2,837) (3,258)
Other operating expenses (1,519) (1,442)
Other income 47 12
Earnings from equity investments 782 776
Other, net 12 26
Segment EBDA 5,427 5,282Certain Items:Change in fair value of derivative contracts 75 (122)
Gain on divestiture (29) —
Certain Items(a) 46 (122)
Adjusted Segment EBDA $ 5,473 $ 5,160Change from prior period Increase/(Decrease)Segment EBDA $ 145
Adjusted Segment EBDA $ 313Volumetric data(b)Transport volumes (BBtu/d) 44,252 44,132
Sales volumes (BBtu/d) 2,576 2,346
Gathering volumes (BBtu/d) 3,922 3,710
NGL (MBbl/d)
38 34
(a) See table included in “ —Overview—Non-GAAP Financial Measures— Certain Items” above. 2024 and 2023 Certain Items of $46 million and $(122) million, respectively, are associated with our Midstream business. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.
(b) Joint venture throughput is reported at our ownership share. 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. Volumes for assets sold are excluded for all periods presented.
50Below are the changes in Natural Gas Pipelines Segment EBDA:
Year Ended December 31,2024 2023 increase/(decrease)(In millions)Midstream $ 1,799 $ 1,697 $ 102
East 2,678 2,637 41
West 950 948 2
Total Natural Gas Pipelines $ 5,427 $ 5,282 $ 145
The changes in Natural Gas Pipelines Segment EBDA in the comparable years of 2024 and 2023 are explained by the following discussion:
• The $102 million (6%) increase in Midstream was favorably impacted by (i) our STX Midstream acquired assets partially offset by our divested assets; (ii) increased demand and rates for our services on our Texas intrastate systems and increased sales margin driven by lower prices on costs of sales and higher volumes, partially offset by higher operating expenses; and (iii) higher equity earnings from PHP driven by an expansion project that went into service in November 2023. These increases were partially offset by (i) lower sales margin on our Altamont assets driven by higher prices on NGL purchases and higher natural gas purchase volumes related to contract re-negotiations ; (ii) lower sales margin on our South Texas assets due to lower volumes partially offset by higher NGL prices; and (ii i) lower natural gas sales margin on our Hiland Midstream assets as a result of lower prices and a reduction in gathering revenues from lower volumes partially offset by higher rates.
In addition, Midstream was affected by (i) non-cash mark-to-market derivative contracts used to hedge forecasted commodity sales and purchases, which increased costs of sales and decreased revenues; and (ii) a gain on sale of assets in 2024, all of which we treated as Certain Items.Ove rall, Midstream’s revenue changes are partially offset by corresponding changes in costs of sales.• The $41 million (2%) increase in East was impacted by (i) expansion projects on TGP that went into service in July 2024 and November 2023 partly offset by its highe r operating costs and an increase in legal reserves ; and (ii) increased demand for services on our Stagecoach assets. These increases were also partially offset by (i) lower equity earnings from MEP driven by lower contracted rates; and (ii) timing of revenue recognition associated with a prepaid customer contract on SLNG.
• The $2 million ( — %) increase in West was primarily due to increased demand for services on CPGPL and WIC, and an insurance settlement received by EPNG in the 2024 period. These increases were largely offset by lower gas sales margin and higher operating and maintenance costs on EPNG.
51Products Pipelines
Year Ended December 31,2024 2023(In millions, except operating statistics)Revenues $ 2,955 $ 3,066
Costs of sales (1,394) (1,588)
Other operating expenses (456) (436)
Other income (expense) 1 (4)
Earnings from equity investments 66 23
Other, net 1 1
Segment EBDA 1,173 1,062Certain Items:Change in fair value of derivative contracts — (1)
Loss on impairment — 67
Certain Items(a) — 66
Adjusted Segment EBDA $ 1,173 $ 1,128Change from prior period Increase/(Decrease)Segment EBDA $ 111
Adjusted Segment EBDA $ 45Volumetric data(b)Gasoline(c) 977 980
Diesel fuel 361 351
Jet fuel 294 285
Total refined product volumes 1,632 1,616
Crude and condensate 471 483
Total delivery volumes (MBbl/d) 2,103 2,099
(a) See table included in “ —Overview—Non-GAAP Financial Measures— Certain Items” above. 2023 Certain Items of (i) $(1) million is associated with our Southeast Refined Products business and (ii) $67 million is associated with our Crude and Condensate business. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.(b) Joint venture throughput is reported at our ownership share.
(c) Volumes include ethanol pipeline volumes.Below are the changes in Products Pipelines Segment EBDA:
Year Ended December 31,2024 2023 increase/(decrease)(In millions)West Coast Refined Products $ 604 $ 519 $ 85
Crude and Condensate 280 265 15
Southeast Refined Products 289 278 11
Total Products Pipelines $ 1,173 $ 1,062 $ 111
The changes in Products Pipelines Segment EBDA in the comparable years of 2024 and 2023 are explained by the following discussion:
• The $85 million (16%) increase in West Coast Refined Products resulted from higher transportation rates and volumes
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and increased renewable diesel terminal activity on our Pacific operations.
• The $15 million (6%) increase in Crude and Condensate was impacted by an increase of $67 million to equity earnings for a non-cash impairment in the 2023 period related to our investment in Double Eagle Pipeline LLC, which we treated as a Certain Item.
In addition, Crude and Condensate was unfavorably impacted by a decrease in equity earnings from Double Eagle Pipeline LLC, excluding the impairment discussed above, due to unfavorable recontracting and, on Bakken Crude assets, lower gathering volumes partially offset by higher transportation rates. Our Crude and Condensate business also had lower revenues with a corresponding decrease in costs of sales, resulting primarily from decreased sales volumes.
• The $11 million (4%) increase in Southeast Refined Products was driven by an increase in equity earnings from Products (SE) Pipe Line primarily due to higher rates and higher butane blending sales volumes at our South East Terminals.
53Terminals
Year Ended December 31,2024 2023(In millions, except operating statistics)Revenues $ 2,022 $ 1,917
Costs of sales (42) (33)
Other operating expenses (904) (863)
Other income 5 2
Earnings from equity investments 8 9
Other, net 10 8
Segment EBDA $ 1,099 $ 1,040Change from prior period Increase/(Decrease)Segment EBDA $ 59Volumetric data(a)Liquids leasable capacity (MMBbl) 78.6 78.7
Liquids utilization %(b) 94.6 % 93.6 %
Bulk transload tonnage (MMtons) 53.7 53.3(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.For purposes of the following tables and related discussions, the results of operations of our terminals held for sale or divested, including any associated gain or loss on sale, are reclassified for all periods presented from the historical business grouping and included within the Other group.Below are the changes in Terminals Segment EBDA:
Year Ended December 31,2024 2023 increase/(decrease)(In millions)Liquids $ 633 $ 601 $ 32
Jones Act tankers 195 177 18
Bulk 267 256 11
Other 4 6 (2)
Total Terminals $ 1,099 $ 1,040 $ 59
The changes in Terminals Segment EBDA in the comparable years of 2024 and 2023 are explained by the following discussion:
• The $32 million (5%) increase in Liquids was primarily driven by (i) contributions from expansion projects; (ii) higher throughput and ancillary fees primarily at our Houston Ship Channel hub facilities; and (iii) higher rates and utilization, primarily at our New York Harbor hub facilities, partially offset by higher labor and maintenance expenses.
• The $18 million (10%) increase in Jones Act tankers was primarily due to hig her average charter rates and lower operating costs.
• The $11 million (4%) increase in Bulk was primarily due to increased volume and related handling and ancillary charges for petroleum coke, coal, soda ash and fertilizer. These increases were partially offset by higher labor and maintenance expenses and demurrage costs incurred at our International Marine Terminal.
54CO 2
Year Ended December 31,2024 2023(In millions, except operating statistics)Revenues $ 1,204 $ 1,209
Costs of sales (82) (77)
Other operating expenses (504) (473)
Other income 40 —
Earnings from equity investments 34 30
Segment EBDA 692 689Certain Items:Change in fair value of derivative contracts 2 4
Gain of divestitures (40) —
Certain Items(a) (38) 4
Adjusted Segment EBDA $ 654 $ 693Change from prior period Increase/(Decrease)Segment EBDA $ 3
Adjusted Segment EBDA $ (39)Volumetric data(b)SACROC oil production 19.01 20.22
Yates oil production 6.13 6.63
Other 1.02 1.08
Total oil production, net (MBbl/d)(c) 26.16 27.93
NGL sales volumes, net (MBbl/d)(c) 8.57 8.97CO 2 sales volumes, net (Bcf/d)0.322 0.336
RNG sales volumes (BBtu/d) 9 6
Realized weighted average oil price ($ per Bbl) $ 68.46 $ 67.42
Realized weighted average NGL price ($ per Bbl) $ 30.83 $ 30.84
(a) See table included in “ —Overview—Non-GAAP Financial Measures— Certain Items” above. 2024 and 2023 Certain Items are associated with our Oil and Gas Producing activities. For m 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 presente d, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition. Volumes for assets sold are excluded for all periods presented.
(c) Net of royalties and outside working interests.
55Below are the changes in CO 2 Segment EBDA:
Year Ended December 31,2024 2023 increase/(decrease)(In millions)Oil and Gas Producing activities $ 447 $ 473 $ (26)
Source and Transportation activities 195 187 8
Subtotal 642 660 (18)
Energy Transition Ventures 50 29 21Total CO 2$ 692 $ 689 $ 3
The changes in CO 2 Segment EBDA in the comparable years of 2024 and 2023 are explained by the following discussion:
• The $26 million (5%) decrease in Oil and Gas Producing activities resulted primarily from (i) lower crude oil volumes; (ii) our divested assets; and (iii) higher power costs. These decreases were partially offset by our acquired assets and higher realized crude oil prices.
In addition, Oil and Gas Producing activities was favorably impacted by (i) a $40 million gain on sale of oil and gas producing fields; and (ii) non-cash mark-to-market derivative hedge contracts, which increased revenues, all of which we treated as Certain Items.
• The $8 million (4%) increase in Source and Transportation activities was primarily due to higher volumes in 2024, resulting from a refinery outage in 2023 on our Wink pipeline, and lower integrity maintenance costs in 2024. These increases were partially offset by lower CO 2 sales volumes and realized prices.
• The $21 million (72%) increase in Energy Transition Ventures activities was primarily due to higher RIN sales margin resulting from increased volumes partially offset by higher operating expenses.
We believe that our existing hedge contracts in place within our CO 2 busines s segment substantially mitigate commodity price sensitivities in the near-term and to lesser extent over the following few years from price exposure. Below is a summary of our CO 2 business segment hedges outstanding as of December 31, 2024.
2025 2026 2027 2028Crude Oil(a)Price ($ per Bbl) $ 66.61 $ 65.94 $ 65.71 $ 64.55
Volume (MBbl/d) 20.90 13.40 8.10 3.70
NGL
Price ($ per Bbl) $ 48.98
Volume (MBbl/d) 3.13
(a) Includes WTI.Liquidity and Capital Resources
GeneralAs of December 31, 2024, we had $88 million of “Cash and cash equivalents,” an increase of $5 million from December 31, 2023. Additionally, as of December 31, 2024, we had borrowing capacity of approximately $3.1 billion under our credit facility (discussed below in “ —Short-term Liquidity ”). As discussed further below, we believe our cash flows from operating activities, cash position and remaining borrowing capacity on our credit facility is more than adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.
We have consistently generated substantial cash flow from operations, providing a source of funds of $5,635 million and $6,491 million in 2024 and 2023, respectively. The year-to-year decrease is discussed below in “ —Cash Flows—Operating Activities. ” We primarily rely on cash provided by operations to fund our operations as well as our debt service, sustaining
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capital expenditures, dividend payments and our growth capital expenditures; however, we may access the debt capital markets from time to time to refinance our maturing long-term debt and finance incremental investments, if any. From time to time, short-term borrowings are used to fund working capital and finance incremental capital investments, if any. Incremental capital investments initially funded through short-term borrowings may periodically be replaced with long-term financing and/or paid down using retained cash from operations.
Our Board declared a quarterly dividend of $0.2875 per share for the fourth quarter of 2024, consistent with previous quarters in 2024. The total of the dividends declared for 2024 of $1.15 represents a 2% increase over total dividends declared for 2023.
We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed-rate debt securities (senior notes) into variable-rate debt in order to achieve our desired mix of fixed and variable rate debt. As of December 31, 2024 and 2023, $3,621 million (11%) and $8,253 million (26%), respectively, of the principal amount of our debt balances were subject to variable interest rates—either as short-term or long-term variable-rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. The amounts at December 31, 2024 and 2023 include $3,250 million and $6,200 million, respectively, of interest rate swap agreements and $331 million and $1,989 million, respectively, of commercial paper notes. The interest rate swap agreements as of December 31, 2024 are net of $1,500 million of variable-to-fixed interest rate swap agreements which expire December 2025.
On February 1, 2024, we issued, in a registered offering, two series of senior notes consisting of $1,250 million aggregate principal amount of 5.00% senior notes due 2029 and $1,000 million aggregate principal amount of 5.40% senior notes due 2034 for combined net proceeds of $2,230 million, which were used to repay short-term borrowings, to fund maturing debt and for general corporate purposes.
On July 31, 2024, we issued, in a registered offering, two series of senior notes consisting of $500 million aggregate principal amount of 5.10% senior notes due 2029 and $750 million aggregate principal amount of 5.95% senior notes due 2054 and received combined net proceeds of $1,235 million, which were used to repay short-term borrowings, to fund maturing debt and for general corporate purposes.
During the year ended December 31, 2024, upon maturity, we repaid our 4.15% senior notes, our 4.30% senior notes and our 4.25% senior notes.
For additional information about our outstanding senior notes and debt-related transactions in 2024, see Note 8 “Debt” to our consolidated financial statements. For information about our interest rate risk, see Note 13 “Risk Management— Interest Rate Risk Management ” to our consolidated financial statements and Item 7A. “ Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk. ”Short-term LiquidityAs of December 31, 2024, our principal sources of short-term liquidity are (i) cash from operations; and (ii) our $3.5 billion credit facility with an available capacity of approximately $3.1 billion and an associated $3.5 billion commercial paper program. The loan commitments under our credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Commercial paper borrowings and letters of credit reduce borrowings allowed under our credit facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facility and, as previously discussed, have consistently generated strong cash flows from operations.
As of December 31, 2024, our $2,009 million of short-term debt consisted primarily of senior notes that mature in the next twelve months and commercial paper borrowings. We intend to fund our debt as it becomes due, primarily through credit facility borrowings, commercial paper borrowings, cash flows from operations, and/or issuing new long-term debt. Our short-term debt balance as of December 31, 2023 was $4,049 million.
We had working capital (defined as current assets less current liabilities) deficits of $2,580 million and $4,679 million as of December 31, 2024 and 2023, respectively. The overall $2,099 million favorable change from year-end 2023 was primarily due to (i) a $1,658 million decrease in commercial paper borrowings resulting from refinancing a portion of our short-term borrowings into long-term debt with the issuance of senior notes in 2024; (ii) a $400 million decrease in long-term debt maturing in the next twelve months; and (iii) a $113 million increase in restricted deposits primarily associated with our derivative collateral requirements, partially offset by a $111 million net unfavorable change in our accounts receivables and payables. Generally, our working capital varies due to factors such as the timing of scheduled debt payments, timing
57
differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts and changes in our cash and cash equivalent balances as a result of excess cash from operations after payments for investing and financing activities (discussed below in “ —Long-term Financing ” and “ —Capital Expenditures ”).We employ a centralized cash management program for our U.S.-based bank accounts that concentrates the cash assets of our wholly owned subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing. These programs provide that funds in excess of the daily needs of our wholly owned subsidiaries are concentrated, consolidated or otherwise made available for use by other entities within the consolidated group. We place no material restrictions on the ability to move cash between entities, payment of intercompany balances or the ability to upstream dividends to KMI other than restrictions that may be contained in agreements governing the indebtedness of those entities.Credit Ratings and Capital Market Liquidity
We believe that our capital structure will continue to allow us to achieve our business objectives. We expect that our short-term liquidity needs will be met primarily through retained cash from operations or short-term borrowings. Generally, we anticipate re-financing maturing long-term debt obligations in the debt capital markets and are therefore subject to certain market conditions which could result in higher costs or negatively affect our and/or our subsidiaries’ credit ratings. A decrease in our credit ratings could negatively impact our borrowing costs and could limit our access to capital.The following table represents our debt ratings as of December 31, 2024.Rating agency Short-term rating Long-term rating OutlookStandard and Poor’s(a)
A-2 BBB StableMoody’s Investor Services Prime-2 Baa2 Stable
Fitch Ratings, Inc. F2 BBB Stable(a) On February 12, 2025, Standard and Poor’s upgraded our outlook to positive.Long-term Financing
Our equity consists of Class P common stock with a par value of $0.01 per share. We do not expect to need to access the equity capital markets to fund our discretionary capital investments for the foreseeable future. See also “— Dividends and Stock Buy-back Program ” below for additional discussion related to our dividends and stock buy-back program.From time to time, we issue long-term debt securities, often referred to as senior notes. Our senior notes issued to date, other than those issued by certain of our subsidiaries, generally have very similar terms, except for interest rates, maturity dates and prepayment premiums. All of our fixed rate senior notes provide that the notes may be redeemed at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date, and, in most cases, plus a make-whole premium. In addition, from time to time, our subsidiaries issue long-term debt securities. We and almost all of our direct and indirect wholly owned domestic subsidiaries are parties to a cross guaranty wherein each party guarantees each other party’s debt. See “ —Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries .” As of December 31, 2024 and 2023, the aggregate principal amount outstanding of our various long-term debt obligations (excluding current maturities) was $29,779 million and $27,880 million, respectively.Capital Expenditures
We account for our capital expenditures in accordance with GAAP. Additionally, we distinguish between capital expenditures as follows:
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 improvementsBudgeting of maintenance capital expenditures, which we refer to as sustaining capital expenditures, is done annually on a bottom-up basis. For each of our assets, we budget for and make those sustaining capital expenditures that are necessary to maintain safe and efficient operations, meet customer needs and comply with our operating policies and applicable law. We
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may budget for and make additional sustaining capital expenditures that we expect to produce economic benefits such as increasing efficiency and/or lowering future expenses. Budgeting and approval of expansion capital expenditures generally occurs periodically throughout the year on a project-by-project basis in response to specific investment opportunities identified by our business segments from which we generally expect to receive sufficient returns to justify the expenditures. Assets comprising expansion capital projects could result in additional sustaining capital expenditures over time. The need for sustaining capital expenditures in respect of newly constructed assets tends to be minimal but tends to increase over time as such assets age and experience wear and tear. Regardless of whether assets result from sustaining or expansion capital expenditures, once completed, the addition of such assets to our depreciable asset base will impact our calculation of depreciation, depletion and amortization over the remaining useful lives of the impacted or resulting assets.
Generally, the determination of whether a capital expenditure is classified as sustaining or as expansion capital expenditures is made on a project level. The classification of our capital expenditures as expansion capital expenditures or as sustaining capital expenditures is made consistent with our accounting policies and is generally a straightforward process, but in certain circumstances can be a matter of management judgment and discretion.
Our capital expenditures for the year ended December 31, 2024, and the amount we expect to spend for 2025 to sustain our assets and expand our business are as follows:
2024 Expected 2025(In millions)
Capital expenditures:Sustaining capital expenditures $ 1,009 $ 938
Expansion capital expenditures 1,708 2,182
Accrued capital expenditures, contractor retainage and other (88) —
Capital expenditures $ 2,629 $ 3,120Add:Sustaining capital expenditures of unconsolidated joint ventures(a) $ 189 $ 184
Investments in unconsolidated joint ventures(b) 178 166
Less: Consolidated joint venture partners’ sustaining capital expenditures (10) (10)
Less: Consolidated joint venture partners’ expansion capital expenditures (24) (8)
Less: Insurance reimbursement related to a sustaining capital expenditure (23) —
Acquisition 60 —
Accrued capital expenditures, contractor retainage and other 88 —
Total capital investments $ 3,087 $ 3,452(a) Sustaining capital expenditures by our joint ventures generally do not require cash outlays by us.
(b) Reflects cash contributions to unconsolidated joint ventures. Also includes contributions to an unconsolidated joint venture that are netted within the amount the joint venture declares as a distribution to us.59Our capital investments consist of the following:2024 Expected 2025(In millions)
Sustaining capital investmentsCapital expenditures for property, plant and equipment $ 1,009 $ 938
Sustaining capital expenditures of unconsolidated joint ventures(a) 189 184
Less: Consolidated joint venture partners’ sustaining capital expenditures (10) (10)
Less: Insurance reimbursement related to a sustaining capital expenditure (23) —
Total sustaining capital investments 1,165 1,112Expansion capital investmentsCapital expenditures for property, plant and equipment 1,708 2,182
Investments in unconsolidated joint ventures(b) 178 166
Less: Consolidated joint venture partners’ expansion capital expenditures (24) (8)
Acquisition 60 —
Total expansion capital investments 1,922 2,340
Total capital investments $ 3,087 $ 3,452(a) Sustaining capital expenditures by our joint ventures generally do not require cash outlays by us.
(b) Reflects cash contributions to unconsolidated joint ventures. Also includes contributions to an unconsolidated joint venture that are netted within the amount the joint venture declares as a distribution to us.
Impact of RegulationThe trend toward increasingly stringent regulations creates uncertainty regarding our capital and operating expenditure requirements over the longer term. For example, the EPA’s final rule known as the “Good Neighbor Plan” (the Plan) became effective on August 4, 2023. As a precursor to the Plan, the EPA disapproved state implementation plans, or SIPs, submitted under the interstate transport (Good Neighbor) provisions of the Clean Air Act for the 2015 Ozone NAAQS. The Plan, which imposes prescriptive emission standards for several sectors, including natural gas pipelines, covers 23 states; however, 12 states were awarded stays pending their respective appeals of the EPA’s disapproval of their SIPs.
Multiple legal challenges to the Plan have been filed, including by us. See Note 17, “Litigation and Environmental— Environmental Matters—Challenge to Federal “Good Neighbor Plan ,” to our consolidated financial statements. We believe that the Plan is deeply flawed and that numerous and substantial bases for challenging the Plan exist, as evidenced by the U.S. Supreme Court ruling on June 27, 2024, staying enforcement of the Plan pending a decision by the U.S. Court of Appeals for the District of Columbia (D.C. Circuit) on its pending review of the Plan and any subsequent appeal to the Supreme Court. In reaching its decision, the Supreme Court found that the parties challenging the Plan are likely to prevail on their argument that the Plan was not reasonably explained, that the EPA failed to supply a satisfactory explanation for its action, and that the EPA ignored an important aspect of the problem it was attempting to solve by promulgating the Plan. The EPA has no legal basis to enforce the Plan in any state while the Supreme Court stay remains in place. In addition, the stays of underlying SIP disapprovals also serve to prevent enforcement of the Plan in those states. The D.C. Circuit returned the consolidated cases to its active docket on January 13, 2025; however, on February 6, 2025, the EPA filed a motion asking the court to hold the cases in abeyance for 60 days to allow the Trump Administration time to familiarize themselves with the Plan, receive briefing from the EPA about the cases and the Plan, and decide what action on the Plan, if any, is necessary.
The Plan would require installation of more stringent air pollution controls on hundreds of existing internal combustion engines used by our Natural Gas Pipelines business segment. If the Plan ultimately were to take effect in its current form (including full compliance by a revised compliance deadline (originally May 1, 2026) accounting for the stays, and assuming failure of all challenges to SIP disapprovals and the Plan), we currently estimate that it would have a material impact on us, including estimated costs necessary to comply with the Plan ranging from $1.5 billion to $1.8 billion (including costs for joint ventures that we operate, net to our interests in such joint ventures), potential shortages of equipment resulting in our inability to comply with the Plan, and operational disruptions. Given the extensive pending litigation, and more recently, the change in U.S. presidential administrations and EPA’s filing with the U.S. Court of Appeals for the District of Columbia Circuit on February 6, 2025, impacts of the Plan are difficult to predict. The outcomes of these numerous lawsuits may significantly decrease or delay our exposure. In addition, we would seek to mitigate the impacts and to recover expenditures through adjustments to our rates on our regulated assets where available.
60The cost estimates discussed above are preliminary, based on a number of assumptions and subject to significant variation, including outside of the ranges provided. Costs are assumed based on the average cost incurred historically for a typical retrofit of an average engine. These estimates reflect only the anticipated upgrades that would need to be performed (and in the case of joint ventures, only on assets that we operate) and do not take into account potential complications such as additional maintenance requirements that may be identified during the upgrade process.
Off Balance Sheet ArrangementsWe have invested in entities that are not consolidated in our financial statements. For information on our obligations with respect to these investments, as well as our obligations with respect to related letters of credit, see Note 12 “Commitments and Contingent Liabilities” to our consolidated financial statements. Additional information regarding the nature and business purpose of our investments is included in Note 6 “Investments” to our consolidated financial statements.Contractual Obligations and Commercial Commitments
The table below provides a summary of our material cash requirements.
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) $ 31,788 $ 2,009 $ 1,974 $ 3,648 $ 24,157Interest payments(b)21,051 1,670 3,219 2,949 13,213
Lease obligations(c) 326 72 84 48 122
Pension and OPEB plans(d) 311 64 29 26 192
Transportation, volume and storage agreements(e) 622 164 224 110 124
Other obligations(f) 254 56 64 32 102
Total $ 54,352 $ 4,035 $ 5,594 $ 6,813 $ 37,910Other commercial commitments:Standby letters of credit(g) $ 132 $ 83 $ 49
Capital expenditures(h) $ 809 $ 691 $ 115 $ 3
(a) See Note 8 “Debt” to our consolidated financial statements.
(b) Interest payment obligations exclude adjustments for interest rate swap agreements and assume no change in variable interest rates from those in effect at December 31, 2024.
(c) Represents commitments pursuant to the terms of operating lease agreements as of December 31, 2024.
(d) Represents the amount by which the benefit obligations exceeded the fair value of plan assets at year-end for pension and OPEB plans whose accumulated postretirement benefit obligations exceeded the fair value of plan assets. The payments by period include expected pension contributions in 2025 and estimated benefit payments for underfunded plans in all years.
(e) Primarily represents transportation agreements of $277 million, storage agreements for capacity of $230 million and NGL volume agreements of $68 million.
(f) Primarily includes (i) rights-of-way obligations; and (ii) environmental liabilities related to sites that we own or have a contractual or legal obligation with a regulatory agency or property owner upon which we will perform remediation activities. These environmental liabilities are included within “Other current liabilities” and “Other long-term liabilities and deferred credits” in our consolidated balance sheet as of December 31, 2024.
(g) The $132 million in letters of credit outstanding as of December 31, 2024 consisted of the following (i) $51 million under six letters of credit for insurance purposes; (ii) a $46 million letter of credit supporting our International Marine Terminals Partnership Plaquemines Bond; and (iii) a combined $35 million in thirty-two letters of credit supporting environmental and other obligations of us and our subsidiaries.
(h) Represents commitments for the purchase of plant, property and equipment as of December 31, 2024.
61Cash FlowsThe following table summarizes our net cash flows provided by (used in) operating, investing and financing activities between 2024 and 2023.Year Ended December 31,2024 2023 Changes(In millions)
Net Cash Provided by (Used in)Operating Activities $ 5,635 $ 6,491 $ (856)
Investing Activities (2,629) (4,175) 1,546
Financing Activities (2,887) (3,014) 127
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits (1) — (1)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Deposits $ 118 $ (698) $ 816Operating Activities$856 million less cash provided by operating activities in the comparable years of 2024 and 2023 is explained by the following discussion.
• an $843 million decrease in cash related to a prepayment received of certain fixed reservation charges under long-term transportation and terminaling contracts in 2023. See Note 14 “Revenue Recognition” to our consolidated financial statements for further information regarding this prepayment; and
• a $359 million decrease in cash associated with net changes in working capital items and other non-current assets and liabilities, excluding the customer prepayment discussed above. The decrease was primarily driven by (i) the decrease in the weighted-average cost of gas in underground storage inventory in 2023; and (ii) a decrease in cash margin deposits posted by our counterparties as collateral; partially offset by
• a $346 million increase in cash after adjusting the $234 million increase in net income by the combined effects of the period-to-period net changes in non-cash items. See “ —Results of Operations ” for a discussion of items impacting net income.Investing Activities$1,546 million less cash used in investing activities in the comparable years of 2024 and 2023 is explained by the following discussion.
• a $1,780 million decrease in expenditures for the acquisition of assets and investments, net of cash acquired, primarily driven by $1,829 million of net cash used for the acquisition of STX Midstream in 2023. See Note 3 “Acquisitions and Divestitures” to our consolidated financial statements for further information regarding this acquisition; and
• a $91 million decrease in cash used for contributions to equity investees driven primarily by lower contributions to PHP and Greenholly Gathering Pipeline LLC, partially offset by higher contributions to SNG in the 2024 period compared to the 2023 period; partially offset by
• a $312 million increase in capital expenditures primarily driven by expansion projects in our Natural Gas Pipelines business segment.Financing Activities$127 million less cash used in financing activities in the comparable years of 2024 and 2023 is explained by the following discussion.
• a $515 million decrease in cash used for share repurchases under our share buy-back program; partially offset by
• a $363 million net increase in cash used related to debt activity as a result of net debt reduction in 2024 compared to net issuances in 2023.
62Dividends and Stock Buy-back ProgramThe table below reflects the declaration of dividends of $1.15 per share for 2024:Three months ended Total quarterly dividend per share for the period Date of declaration Date of record Date of dividendMarch 31, 2024
$0.2875 April 17, 2024 April 30, 2024 May 15, 2024
June 30, 2024
0.2875 July 17, 2024 July 31, 2024 August 15, 2024
September 30, 2024
0.2875 October 16, 2024 October 31, 2024 November 15, 2024
December 31, 2024
0.2875 January 22, 2025 February 3, 2025 February 18, 2025
We expect to continue to return additional value to our shareholders in 2025 through our previously announced dividend increase. We plan to increase our divide nd by 2% to $1 .17 per common share in 2025. We have a board-approved share buy-back program that authorizes share repurchase of up to $3 billion that began in December 2017. S ince December 2017, in total, we have repurchased approximately 86 million shares of our Class P common stock under the program at an average price of $17.09 per share for $1,472 million, leaving a remaining capacity of approximately $1.5 billion . For information on our stock buy-back program, see Note 10 “Stockholders’ Equity” to our consolidated financial statements.The actual amount of dividends to be paid on our capital stock will depend on many factors, including our financial condition and results of operations, liquidity requirements, business prospects, capital requirements, legal, regulatory and contractual constraints, tax laws, Delaware laws and other factors. See Item 1A. “ Risk Factors—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. ” All of these matters will be taken into consideration by our Board when declaring dividends.
Our dividends are not cumulative. Consequently, if dividends on our stock are not paid at the intended levels, our stockholders are not entitled to receive those payments in the future. Our dividends generally will be paid on or about the 15th day of each February, May, August and November.63Summarized Combined Financial Information for Guarantee of Securities of SubsidiariesKMI and certain subsidiaries (Subsidiary Issuers) are issuers of certain debt securities. KMI and substantially all of KMI’s wholly owned domestic subsidiaries (Subsidiary Guarantors), are parties to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement. Accordingly, with the exception of certain subsidiaries identified as subsidiary non-guarantors (Subsidiary Non-Guarantors), the parent issuer, Subsidiary Issuers and Subsidiary Guarantors (the “Obligated Group”) are all guarantors of each series of our guaranteed debt (Guaranteed Notes). As a result of the cross guarantee agreement, a holder of any of the Guaranteed Notes issued by KMI or a Subsidiary Issuer is in the same position with respect to the net assets, and income of KMI and the Subsidiary Issuers and Guarantors. The only amounts that are not available to the holders of each of the Guaranteed Notes to satisfy the repayment of such securities are the net assets, and income of the Subsidiary Non-Guarantors.
In lieu of providing separate financial statements for the Obligated Group, we have presented the accompanying supplemental summarized combined income statement and balance sheet information for the Obligated Group based on Rule 13-01 of the SEC’s Regulation S-X. Also, see Exhibit 10.11 to this report “ Cross Guarantee Agreement, dated as of November 26, 2014, among KMI and certain of its subsidiaries, with schedules updated as of December 31, 2024. ”All significant intercompany items among the Obligated Group have been eliminated in the supplemental summarized combined financial information. The Obligated Group’s investment balances in Subsidiary Non-Guarantors have been excluded from the supplemental summarized combined financial information. Significant intercompany balances and activity for the Obligated Group with other related parties, including Subsidiary Non-Guarantors (referred to as “affiliates”), are presented separately in the accompanying supplemental summarized combined financial information.Excluding fair value adjustments, as of December 31, 2024 and 2023, the Obligated Group had $31,052 million and $31,167 million, respectively, of Guaranteed Notes outstanding.Summarized combined balance sheet and income statement information for the Obligated Group follows:
December 31,Summarized Combined Balance Sheet Information 2024 2023(In millions)Current assets $ 2,216 $ 2,246
Current assets - affiliates 735 760
Noncurrent assets 63,267 62,877
Noncurrent assets - affiliates 813 903
Total Assets $ 67,031 $ 66,786
Current liabilities $ 4,737 $ 6,907
Current liabilities - affiliates 758 734
Noncurrent liabilities 34,052 31,681
Noncurrent liabilities - affiliates 1,561 1,306
Total Liabilities 41,108 40,628
Kinder Morgan, Inc.’s stockholders’ equity 25,923 26,158
Total Liabilities and Stockholders’ Equity $ 67,031 $ 66,786
Summarized Combined Income Statement Information Year Ended December 31, 2024(In millions)Revenues $ 13,678
Operating income 3,827
Net income 2,131
64Recent Accounting PronouncementsPlease refer to Note 18 “Recent Accounting Pronouncements” to our consolidated financial statements for information concerning recent accounting pronouncements.