UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_____________
Form 10-K
☑
[X]
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20172023
or
☐
[   ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____
Commission file number: 001-35081
kminc4a03a02.gif
Kinder Morgan, Inc.
(Exact name of registrant as specified in its charter)
Delaware80-0682103
Delaware80-0682103
(State or other jurisdiction of

incorporation or organization)
(I.R.S. Employer

Identification No.)
1001 Louisiana Street, Suite 1000, Houston, Texas 77002
(Address of principal executive offices) (zip code)


Registrant’s telephone number, including area code: 713-369-9000
____________
 
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Class P Common StockKMINew York Stock Exchange
Depositary Shares, each representing a 1/20th interest in a
share of 9.75% Series A Mandatory Convertible Preferred Stock
New York Stock Exchange
1.500% Senior Notes due 2022New York Stock Exchange
2.250% Senior Notes due 2027KMI 27 ANew York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933.Act.  Yes þ☑ No o☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.Act.  Yes o☐  No þ☑
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ☑  No o☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes þ☑  No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K(§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as definedor an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “non-accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Securities Exchange Act of 1934).Act.
Large accelerated filer þ☑  Accelerated filer o☐  Non-accelerated filer o☐  Smaller reporting company o☐  Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report.  ☑
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes o☐  No þ☑
Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on closing prices in the daily composite list for transactions on the New York Stock Exchange on June 30, 20172023 was approximately $36,830,209,065.$33,533,173,723.  As of February 8, 2018,16, 2024, the registrant had 2,206,066,6842,219,369,970 shares of Class P sharescommon stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 20182024 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2018,2024, are incorporated into PART III, as specifically set forth in PART III.



KINDER MORGAN, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
Page
Number

1
Page
Number
Glossary
1
Information Regarding Forward-Looking Statements
2
4
General Development of Business
4
Organizational StructureRecent Developments
4
Recent Developments
5
Financial Information about Segments
8
Narrative Description of Business
86
Business Strategy
86
Business Segments
96
Natural Gas Pipelines
97
CProducts PipelinesO2
1110
Terminals
1412
Products PipelinesCO2
1514
Kinder Morgan CanadaMajor Customers
1516
Major CustomersIndustry Regulation
17
Environmental Matters and Safety Regulation
1719
Environmental MattersSecurity Regulations
21
OtherHuman Capital
2322
Financial Information about Geographic AreasProperties and Rights-of-Way
2423
Available Information
2423
2423
3536
3536
38
3538
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
3639
3739
3839
General
3840
Critical Accounting Policies and Estimates
4240
Results of Operations
4542
Income TaxesOverview
6042
Consolidated Earnings Results
46
Non-GAAP Financial Measures
48
Segment Earnings Results
52
Liquidity and Capital Resources
6058
Recent Accounting PronouncementsGeneral
6758
Short-term Liquidity
59



KINDER MORGAN, INC. AND SUBSIDIARIES
(continued)
TABLE OF CONTENTS (continued)
Page
Number
Long-term Financing

60
Capital Expenditures
60
Off Balance Sheet Arrangements
63
Contractual Obligations and Commercial Commitments
63
Cash Flows
64
Dividends and Stock Buy-back Program
65
Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries
66
Recent Accounting Pronouncements
67
67
Energy Commodity Market Risk
6867
Interest Rate Risk
68
Foreign Currency Risk
69
70
Index to Financial Statements
70
70131
70132
70132
132
71133
71133
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
71133
71133
71133
71134
Index to Financial Statements
76
153137
154138




KINDER MORGAN, INC. AND SUBSIDIARIES
GLOSSARY
Company Abbreviations

Calnev=
Calnev=Calnev Pipe Line LLCKMGPKMP=Kinder Morgan G.P., Inc.Energy Partners, L.P. and its majority-owned and/or controlled subsidiaries
CIG=Colorado Interstate Gas Company, L.L.C.KMI=Kinder Morgan, Inc. and its majority-owned and/or
CopanoCPGPL=Copano Energy, L.L.C.controlled subsidiaries
CPGPL=Cheyenne Plains Gas Pipeline Company, L.L.C.KMLKMTP=Kinder Morgan Canada Limited and its majority-Texas Pipeline LLC
EagleHawk=EagleHawk Field Services LLCMEPowned and/or controlled subsidiaries
Elba Express=Elba Express Company, L.L.C.KMLP=Kinder Morgan Louisiana Pipeline LLC
ELC=Elba Liquefaction Company, L.L.C.KMP=Kinder Morgan Energy Partners, L.P. and its
EP=El Paso Corporation and its majority-owned andmajority-owned and controlled subsidiaries
controlled subsidiariesKMR=Kinder Morgan Management, LLC
EPB=El Paso Pipeline Partners, L.P. and its majority-MEP=Midcontinent Express Pipeline LLC
Elba Express=owned and controlled subsidiariesElba Express Company, L.L.C.NGPL=Natural Gas Pipeline Company of America LLC and certain affiliates
EPNGELC=Elba Liquefaction Company, L.L.C.
EPNG=El Paso Natural Gas Company, L.L.C.RubyPHP=Permian Highway Pipeline LLC
FEP=Fayetteville Express Pipeline LLCRuby=Ruby Pipeline Holding Company, L.L.C.
EPPOCHiland=El Paso PipelineHiland Partners, Operating Company,LPSFPP=SFPP, L.P.
KinderHawk=L.L.C.KinderHawk Field Services LLCSLNG=Southern LNG Company, L.L.C.
FEPKMRNG=Fayetteville Express PipelineKinder Morgan RNG Holdco LLCSNG=Southern Natural Gas Company, L.L.C.
HilandKMBT=Hiland Partners, LPKinder Morgan Bulk Terminals, Inc.TGPStagecoach=Stagecoach Gas Services LLC
KMI=Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiariesTGP=Tennessee Gas Pipeline Company, L.L.C.
KinderHawkWIC=KinderHawk Field Services LLCTMEP=Trans Mountain Expansion Project
KMCO2
=
Kinder Morgan CO2 Company, L.P.
WIC=Wyoming Interstate Company, L.L.C.
KMEPKMLP=Kinder Morgan Energy Partners, L.P.Louisiana Pipeline LLCWYCO=WYCO Development L.L.C.
KMLT=Kinder Morgan Liquid Terminals, LLC
Unless the context otherwise requires, references to “we,” “us,” “our,” or “the Company” are intended to mean Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries.
Common Industry and Other Terms
2017 Tax/d=per dayIPOLIBOR=Initial Public Offering
Reform=The Tax Cuts & Jobs Act of 2017LIBOR=London Interbank Offered Rate
/dAFUDC=per dayLLC=limited liability company
AFUDC=allowance for funds used during constructionLNGLLC=limited liability company
Bbl=barrelsLNG=liquefied natural gas
BBtu=billion British Thermal UnitsMBbl=thousand barrels
Bcf=billion cubic feetMDthMMBbl=thousand dekathermsmillion barrels
CERCLA=Comprehensive Environmental Response,MLP=master limited partnership
Compensation and Liability ActMMBblMMtons=million barrelstons
C$NGL=Canadian dollarsMMcf=million cubic feetnatural gas liquids
CO2
=
carbon dioxide or our CO2 business segment
NEBNYMEX=National Energy Board
CPUC=California Public Utilities CommissionNGL=natural gas liquids
DCF=distributable cash flowNYMEX=New York Mercantile Exchange
DD&ACOVID-19=depreciation, depletionCoronavirus Disease 2019, a widespread contagious disease, or the related pandemic declared and amortizationresulting worldwide economic downturnNYSE=New York Stock Exchange
DGCLOTC=General Corporation Law of the state of DelawareOTC=over-the-counter
DthPHMSA=dekathermsPHMSA=United States Department of Transportation
EBDA=earnings before depreciation, depletion andPipeline and Hazardous Materials Safety Administration
CPUC=amortization expenses, including amortization ofAdministrationCalifornia Public Utilities Commission
DD&A=excess cost of equity investmentsU.S.=United States of Americadepreciation, depletion and amortization
EPADth=dekathermsROU=Right-of-Use
EPA=United States Environmental Protection AgencySECRNG=renewable natural gas
FASB=Financial Accounting Standards BoardSEC=United States Securities and Exchange Commission
FASBFERC=Financial Accounting Standards BoardCommission
FERC=Federal Energy Regulatory CommissionTBtu=trillion British Thermal Units
FTCGAAP=Federal Trade CommissionWTI=West Texas Intermediate
GAAP=United States Generally Accepted Accounting PrinciplesSOFR=Secured Overnight Financing Rate
U.S.=PrinciplesUnited States of America
When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.GTE=gas-to-electricWTI=West Texas Intermediate

1

Information Regarding Forward-Looking Statements

This report includes forward-looking statements.  These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts.  They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “outlook,” “continue,” “estimate,” “expect,” “may,” “will,” “shall,” or the negative of those terms or other variations of them or comparable terminology.  In particular, expressed or implied statements concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow, service debt or pay dividends, are forward-looking statements.  Forward-looking statements in this report include, among others, express or implied statements pertaining to: long term demand for our assets and services, our business strategy, including energy transition related opportunities, expected financial results, dividends, sustaining and discretionary capital expenditures, our cash requirements and our financing and capital allocation strategy, anticipated impacts of litigation and legal or regulatory developments, and our capital projects, including expected completion timing and benefits of those projects.

Forward-looking statements are not guarantees of performance.  They involve risks, uncertainties and assumptions.  Future actions, conditions or events and future results may differ materially from those expressed in our forward-looking statements.  Many of the factors that will determine these results are beyond our ability to control or accurately predict.  Specific factors that could cause actual results to differ from those in our forward-looking statements include:

•
the extent of volatility in prices for and resulting changes in supply of and demand for NGL, refined petroleum products, oil, CO2, natural gas, electricity, coal, steel and other bulk materials and chemicals and certain agricultural products in North America;


•changes in supply of and demand for natural gas, NGL, refined petroleum products, oil, renewable fuels, CO2, electricity, petroleum coke, steel and other bulk materials and chemicals and certain agricultural products;
•economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand;

•competition from other pipelines, terminals or other forms of transportation, or from emerging technologies such as CO2 capture and sequestration;
•changes in our tariff rates required by the FERC, the CPUC Canada’s NEB or another regulatory agency;

•the timing and success of our commercial and business development efforts, including our ability to renew long-term customer contracts at economically attractive rates;
•our ability to safely operate and maintain our existing assets and to access or construct new assets including pipelines, terminals, gas processing, gas storage and NGL fractionation capacity;
•our ability to attract and retain key management and operations personnel;
•difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from our terminals or pipelines;
•shut-downs or cutbacks at major refineries, chemical or petrochemical plants, natural gas processing plants, LNG export facilities, ports, utilities, military bases or other businesses that use our services or provide services or products to us;
•changes in crude oil and natural gas production (and the NGL content of natural gas production) from exploration and production areas that we serve, such as the Permian Basin area of West Texas, the shale plays in North Dakota, Ohio, Oklahoma, Pennsylvania and Texas, and the U.S. Rocky Mountains;
•changes in laws or regulations, third-party relations and approvals, and decisions of courts, regulators and governmental bodies that may increase our compliance costs, restrict our ability to provide or reduce demand for our services, or otherwise adversely affect our business;
•interruptions of operations at our facilities due to natural disasters, damage by third parties, power shortages, strikes, riots, terrorism (including cyber-attacks), war or other causes;
•compromise of our IT systems, operational systems or sensitive data as a result of errors, malfunctions, hacking events or coordinated cyber-attacks;
2

•changes in technologies, possibly introducing new cybersecurity risks and other new risks inherent in the use, either by us or our counterparties, of new technologies in the developmental stage including, without limitation, generative artificial intelligence;
•the uncertainty inherent in estimating future oil, natural gas, and CO2 production or reserves;
•issues, delays or stoppage associated with new construction or expansion projects;
•regulatory, environmental, political, grass roots opposition, legal, operational and geological uncertainties that could affect our ability to complete our expansion projects on time and on budget or at all;
•our ability to acquire new businesses and assets and integrate those operations into our existing operations, and make cost-saving changes in operations, particularly if we undertake multiple acquisitions in a relatively short period of time, as well as our ability to expand our facilities;

our ability to safely operate and maintain our existing assets and to access or construct new pipeline, gas processing, gas storage and NGL fractionation capacity;

our ability to attract and retain key management and operations personnel;

difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from our terminals or pipelines;

shut-downs or cutbacks at major refineries, petrochemical or chemical plants, natural gas processing plants, ports, utilities, military bases or other businesses that use our services or provide services or products to us;

changes in crude oil and natural gas production (and the NGL content of natural gas production) from exploration and production areas that we serve, such as the Permian Basin area of West Texas, the shale plays in North Dakota, Oklahoma, Ohio, Pennsylvania and Texas, and the U.S. Rocky Mountains and the Alberta, Canada oil sands;

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

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

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

issues, delays or stoppage associated with major expansion projects, including TMEP;

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

the timing and success of our business development efforts, including our ability to renew long-term customer contracts at economically attractive rates;

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

competition from other pipelines or other forms of transportation;

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

•changes in tax laws;

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

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

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

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

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

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

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

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

•our ability to achieve cost savings and revenue growth;

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

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

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

•unfavorable results of litigation and the outcome of contingencies referred to in Note 1718 “Litigation Environmental and Other Contingencies”Environmental” to our consolidated financial statements.
The foregoing list should not be construed to be exhaustive.  We believe the forward-looking statements in this report are reasonable.  However, there is no assurance that any of the actions, events or results expressed in forward-looking statements will occur, or if any of them do, of their timing or what impact they will have on our results of operations or financial condition.  Because of these uncertainties, you should not put undue reliance on any of our forward-looking statements.
3


Additional discussion of factors that may affect our forward-looking statements appearsappear elsewhere in this report, including in Item 1A 1A. “Risk Factors,” Item 7 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 7A 7A. “Quantitative and Qualitative Disclosures About Market Risk-EnergyRisk—Energy Commodity Market Risk.”  In addition, there is a general level of uncertainty regarding the extent to which potential positive or negative changes to fiscal, tax and trade policies may impact us and those with whom we do business. It is not possible at this time to predict the extent of any such impact. When considering forward-looking statements, you should keep in mind the factors described in this section and the other sections referenced above. These factors could cause our actual results to differ materially from those contained in any forward-looking statement.  We disclaim any obligation, other than as required by applicable law, and described below under Items 1 and 2 “Business and Properties­—(a) General Development of Business—Recent Developments—2018 Outlook,”to publicly update the above list or to announce publicly the result of any revisions torevise any of our forward-looking statements to reflect future events or developments.



PART I


Items 1 and 2. Business and Properties.
We are one of the largest energy infrastructure companies in North America. We ownAs of December 31, 2023, we owned an interest in or operateoperated approximately 85,000 82,000 miles of pipelines, 139 terminals, 702 Bcf of working natural gas storage capacity and 152 terminals.had RNG generation capacity of approximately 6.1 Bcf per year of gross production. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2,renewable fuels and other products, and our terminals transloadstore and store liquidhandle various commodities including gasoline, diesel fuel, jet fuel, chemicals, petroleum products,coke, metals, and ethanol and chemicals,other renewable fuels and bulk products, including petroleum coke, steel and coal. We are also a leading producer of CO2, which we and others utilize for enhanced oil recovery projects primarily in the Permian basin. Our common stock trades on the NYSE under the symbol “KMI.”feedstocks.


(a) General Development of Business

Organizational Structure
We are a Delaware corporation and our common stock has been publicly traded since February 2011.

Sale of Approximate 30% Interest in our Canadian Business

On May 30, 2017, our indirectly owned subsidiary, KML, completed an IPO of 102,942,000 restricted voting shares listed on the Toronto Stock Exchange (TSX) at a price to the public of C$17.00 per restricted voting share for total gross proceeds of approximately C$1,750 million. The net proceeds of C$1,677 million (U.S.$1,245 million) from the IPO were used by KML to indirectly acquire from us an approximate 30% interest in a limited partnership that holds our Canadian business, while we retained the remaining 70% interest. We used the proceeds from KML to pay down debt.

Subsequent to the IPO, we retained control of KML and the limited partnership, and as a result, they remain consolidated in our consolidated financial statements. The public ownership of the KML restricted voting shares is reflected within “Noncontrolling interests” in our consolidated statements of stockholders’ equity and consolidated balance sheets. Earnings attributable to the public ownership of KML are presented in “Net income attributable to noncontrolling interests” in our consolidated statements of income for the periods presented after May 30, 2017.

The portion of the Canadian business operations that we sold to the public on May 30, 2017 represented Canadian assets that are included in our Kinder Morgan Canada, Terminals and Products Pipelines business segments and included the Trans Mountain pipeline system (including related terminaling assets), TMEP, the Puget Sound and Jet Fuel pipeline systems, the Canadian portion of the Cochin pipeline system, the Vancouver Wharves Terminal and the North 40 Terminal; as well as three jointly controlled investments: the Edmonton Rail Terminal, the Alberta Crude Terminal and the Base Line Terminal.

Subsequent to its IPO, KML has obtained a credit facility and completed two preferred share offerings. KMI expects KML to be a self-funding entity and does not anticipate making contributions to fund its growth or specifically to fund the TMEP.

You should read the following in conjunction with our audited consolidated financial statements and the notes thereto. We have prepared our accompanying consolidated financial statements under GAAP and the rules and regulations of the SEC. Our accounting records are maintained in U.S. dollars and all references to dollars in this report are to U.S. dollars, except where stated otherwise. Our consolidated financial statements include our accounts and those of our majority-owned and/or controlled subsidiaries, and all significant intercompany items have been eliminated in consolidation. The address of our principal executive offices is 1001 Louisiana Street, Suite 1000, Houston, Texas 77002, and our telephone number at this address is (713) 369-9000.


Recent Developments


The following is a brief listing of significant developments and updates related to our major acquisitions and projects and otherfinancing transactions. Additional information regarding most of these items may be found elsewhere in this report. “Capital Scope” is estimated for our share of the described project whichand may include portions not yet completed.
Asset or projectDescriptionDescriptionActivityActivityApprox. Capital Scope (KMI Share)
PlacedAcquisitions and projects placed in service acquisitions or divestitures
STX Midstream pipeline system acquisitionAcquired a set of integrated, large diameter, high pressure natural gas pipeline systems that connect the Eagle Ford basin to growing Mexico and Gulf Coast demand markets with the purchase of the STX Midstream pipeline system from NextEra Energy Partners, LP. These pipeline systems include the Eagle Ford Transmission system, a 90% interest in the NET Mexico Pipeline LLC and a 50% interest in Dos Caminos, LLC.Acquired in December 2023.$1,831 million
ELCTGP East 300 UpgradeSold 49% interest in ELC to investment funds of EIG Global Energy Partners and formed a joint venture, which includes our remaining 51% interest in ELC.Completed in February 2017.n/a
Jones Act TankersPurchase of nine new-build, medium-range Jones Act tankers constructed by General Dynamics NASSCO Shipyard (five) and Philly Shipyard, Inc. (four). Each of the 50,000-deadweight-ton, LNG conversion-ready product tankers has a capacity of approximately 330,000 barrels and is contracted under a term charter agreement.First tanker delivery took place in December 2015. Four additional tankers were delivered during 2016. The final four tankers were delivered during 2017.
$1.4
billion
Elba Express and SNG ExpansionExpansion project that provides 854,000involved upgrading compression facilities upstream on TGP’s system in order to provide 115,000 Dth/d of incremental natural gas transportation service supporting the needs of customerscapacity to Con Edison’s distribution system in Georgia, South Carolina and northern Florida, and also serving ELC. Supported by long-term firm contracts.Initial service began in December 2016. As of December 31, 2017, more than 70% of capacity has been placed in service. The remaining work is expected to be completed by November 2018.$284 million
KM Export TerminalBrownfield expansion along Houston Ship Channel that adds 12 storage tanks with 1.5 MMBbl of liquids storage capacity, one ship dock, one barge dock and cross-channel pipelines to connect with the KM Galena Park terminal.Westchester County, New York. Supported by a long-term contract with Con Edison.Placed in service November 2023.$267 million
Eagle Ford transport projectExpansion project included constructing 67 miles of 42-inch pipeline, multiple receipt and delivery meters and upgrades to Kinder Morgan Freer compressor station to transport up to 1.88 Bcf/d of lean Eagle Ford production to Gulf Coast markets. Supported by long-term contracts.Placed in service November 2023.$231 million
PHP expansionJoint venture project (our ownership interest of 27.74%) that expanded PHP’s capacity by approximately 550,000 Dth/d, increasing natural gas deliveries from the Permian to U.S. Gulf Coast markets. Supported by long-term contracts.Placed in service December 2023.$159 million
RNG facilitiesConstruction of three additional landfill-based RNG facilities for KMRNG in order to provide approximately 3.5 Bcf of RNG a major ship channel refiner.year.Storage tanksTwin Bridges placed in service June 2023. Liberty placed in January 2017 followed by the terminal’s full marine capabilities, which were commissionedservice October 2023. Prairie View placed in March 2017.service December 2023.$246153 million
4

Pit 11 Expansion
Asset or projectDescriptionProject adds 2 MMBblActivityApprox. Capital Scope (KMI Share)
Greenholly pipeline - North Holly expansionJoint venture project (our ownership interest of refined products storage at Pasadena terminal along the Houston Ship Channel.39.25%) that constructed 38 miles of 36-inch pipeline to provide 1.15 Bcf/d of capacity and runs from KinderHawk’s Greenwood system and partner receipt points to KinderHawk’s North Holly system. Supported by long-term commitments from existing customers.contracts.Placed in service throughout fourth quarter 2017.August 2023.$186125 million
Other Announcements
Natural Gas Pipelines
TGP Susquehanna Westand SNG Evangeline PassExpansionTwo-phase 2 Bcf/d project that provides 145,000 Dth/to serve Venture Global’s proposed Plaquemines LNG facility (Plaquemines). First phase, TGP will provide approximately 0.9 Bcf/d of incremental natural gas transportation capacity to Plaquemines. Second phase, TGP and SNG will jointly provide volumes up to the remaining 1.1 Bcf/d to Plaquemines.Expected in-service date for first phase is third quarter of 2024 and third quarter of 2025 for the second phase, pending receipt of all required permits.$673 million
TVA CumberlandProject includes a new 32-mile pipeline to transport approximately 0.245 Bcf/d of natural gas from the northeast Marcellus supply basinexisting TGP system to pointsTennessee Valley Authority’s (TVA) proposed 1,450 megawatt generation facility at an existing site in Cumberland, Tennessee.Expected in-service date is August 2025, pending receipt of liquidity. Subscribed under long-term firm transportation contracts.all required permits and clearances.Placed in service September 2017.$126181 million
TGP OrionKMTP system expansionExpansion project that provides 135,000includes a new 30-mile, 30-inch pipeline, to deliver up to 0.5 Bcf/d of Eagle Ford natural gas supply to markets along the Texas Gulf Coast and Mexico. Expansion will provide transportation services, including treating, for Kimmeridge Texas Gas and other third parties. Supported by a long-term contract.Expected in-service date is November 2024.$180 million
Central Texas pipelineProject includes installation of 22 miles of 30-inch pipeline from PHP to Sand Hill Lateral, 1.75 miles of 20-inch pipeline from Sand Hill Lateral to Texas Gas Services and three meter stations and one regulator station.Expected in-service date is fourth quarter of 2024.$115 million
Tejas South to North expansionSouth Texas to Houston Market expansion project to add compression on Tejas’ mainline to increase natural gas deliveries by approximately 0.35 Bcf/d to Houston markets.Expected in-service date is third quarter of 2024.$97
 million
3Rivers Offload Phase IIConstruct 19 miles of 16-inch pipeline and associated compression allowing delivery of 27,000 Dth/d of incremental firm transportation capacity from the Marcellus supply basin to TGP’s interconnection with Columbia Gas Transmission in Pike County, Pennsylvania. Subscribed under long-term firm transportation contracts.gathered production for third-party processing.Expected in-service date is second quarter 2025.Placed in service November 2017.$10496
 million
TGP Connecticut Expansion
CO2
Expansion project that provides 72,100 Dth/d of incremental firm transportation capacity from Wright, New York to three local distribution companies in Connecticut. Subscribed under long-term firm transportation contracts.Placed in service November 2017.$104 million
TGP Triad ExpansionDiamond M expansionExpansion project that provides 180,000 Dth/d of incremental firm transportation capacity from the Marcellus supply basin to Invenergy’s Lackawanna Energy Center in Lackawanna County, Pennsylvania. Subscribed under long-term firm transportation contracts.Project facilities placed in service November 2017 (customer contracts to begin June 2018).
$57
million
Other Announcements
Natural Gas Pipelines
ELC and SLNG ExpansionBuilding of new natural gas liquefaction and export facilitiesEnhanced oil recovery expansion at our SLNG natural gas terminal on Elba Island, near Savannah, Ga., with a total capacity of 2.5 million tonnes per year of LNG, equivalent to 357,000 Dth/d of natural gas. Supported by a long-term firm contract with Shell.First of 10 liquefaction units expected to be placed in service in mid-2018 with the remainder expected by mid-2019.$1.2 billion
KMTP Gulf Coast Express Pipeline Project (GCX Project)(a)
New infrastructure joint venture project (KMTP 50%, DCP Midstream, LP 25% and Targa Resources Corp. 25% ownership interest) to provide up to 1.98 Bcf/d of transportation capacity from the Permian Basin to the Agua Dulce, Texas area with 1.76 Bcf/d under long-term contracts. A binding open season for the remaining 220,000 Dth/d of project capacity ends on March 1, 2018.

Pending regulatory approvals, the project is expected to be placed in service October 2019.$638 million

Asset or projectDescriptionActivityApprox. Capital Scope
TGP Broad Run ExpansionSecond of two projects to create a total of 790,000 Dth/d of incremental firm transportation capacity from the southwest Marcellus and Utica supply basins to delivery points in Mississippi and Louisiana. Subscribed under long-term firm transportation contracts.Broad Run Expansion (200,000 Dth/d) expected to be placed in service June 2018. Broad Run Flexibility facilities (590,000 Dth/d) were placed in service November 2015.$453 million
Texas Intrastate Crossover ExpansionExpansion project that provides over 1,000,000 Dth/d of transportation capacity from the Katy Hub, the company’s Houston Central processing plant, and other third party receipt points to serve customers in Texas and Mexico. Phase I is supported by long-term firm transportation contracts of nearly 700,000 Dth/d, including a contract with Comisión Federal de Electricidad. Phase 2, which is supported by long-term firm transportation contracts with Cheniere Energy, Inc. at its Corpus Christi LNG facility and SK E&S LNG, LLC,recently acquired Diamond M field that will provide service to the Freeport LNG export facility and other domestic markets.result in peak oil production of over 5,000 Bbl/d.Phase 1 was placed in service in September 2016. Phase 2 is expected to be placed in service by third quarter 2019.$307 million
TGP Southwest Louisiana SupplyExpansion project to provide 900,000 Dth/d of incremental firm transportation capacity from multiple supply basins to the Cameron LNG export facility in Cameron Parish, Louisiana. Subscribed under long-term firm transportation contracts.Expected in-service date March 2018.$178 million
TGP Lone StarExpansion project to provide 300,000 Dth/d of incremental firm transportation capacity from Louisiana receipt points to Cheniere’s Corpus Christi LNG export facility in Jackson County, Texas. Subscribed under long-term firm transportation contracts.Expected in-service date July 2019.$150 million
EPNG South Mainline Expansion (formerly upstream Sierrita)Expansion project that provides 471,000 Dth/d of firm transportation capacity with afor the first phase of system improvements to deliver volumes to the Sierrita pipeline and theis late 2024, second phase for incremental deliveries of natural gas to Arizonais mid 2025, and California. Subscribed under long-term firm transportation contracts.peak production in 2026.Phase one placed in service October 2014, phase two expected to be in service July 2020.$134180 million
KMLP Magnolia LNG Liquefaction TransportExpansion project to provide 700,000 Dth/d of incremental firm transportation capacity from various receipt points to the proposed Magnolia LNG export facility in Lake Charles, Louisiana. Subscribed under long-term firm agreements, subject to shipper’s final investment decision.In-service date subject to timing of shipper’s final investment decision.$127 million
KMLP Sabine Pass ExpansionExpansion project to provide 600,000 Dth/d of incremental firm transportation capacity from various receipt points to Cheniere’s Sabine Pass Liquefaction Terminal in Cameron Parish, Louisiana. Subscribed under long-term firm transportation contracts.Expected in-service date as early as the first quarter 2019.$122 million
SNG Fairburn ExpansionExpansion project in Georgia to provide 347,000 Dth/d of incremental long-term firm transportation capacity into the Southeast market, and includes the construction of a new compressor station, 6.5 miles of new pipeline and new meter stations.Expected in-service date October 2018.$119 million
NGPL Gulf Coast Southbound ExpansionExpansion project to provide 460,000 Dth/d of incremental firm transportation capacity from various interstate pipeline interconnects in Illinois, Arkansas and Texas, to points south on NGPL’s pipeline system to serve growing demand in the Gulf Coast area. Subscribed under long-term firm transportation contracts.Partially in service April 2017 (75,000 Dth/d). Remaining (385,000 Dth/d) expected to be in service fourth quarter of 2018.$106 million
Terminals
KM Base Line Terminal development(b)A 4.8 MMBbl new-build merchant crude oil storage facility in Edmonton, Alberta. Developed as part of a 50-50 joint venture with Keyera Corp. Capital figure includes costs associated with the construction of a pipeline segment funded solely by Kinder Morgan. Subscribed under long-term contracts with an average initial term of 7.5 years.Commissioning began in the first quarter of 2018. First four tanks placed in-service in January 2018 with balance expected to be phased into service throughout 2018.C$398 million
Products Pipelines
Utopia PipelineBuilding of new 267 mile pipeline, supported by a long-term customer contract, to transport ethane and ethane-propane mixtures from the prolific Utica Shale, with an initial design capacity of 50 MBbl/d, expandable to more than 75 MBbl/d.Placed in-service January 2018.$275 million


Financings and Share Repurchases
Asset or projectDescriptionActivityApprox. Capital Scope
Kinder Morgan Canada
TMEP(b)An increase of capacity on our Trans Mountain pipeline system from approximately 300 to 890 MBbl/d, underpinned by long-term take-or-pay contracts.Received federal government approval in December 2016. In the process of getting permits and other regulatory approval.
C$7.4
billion

_______
n/a - not applicable
(a)Our share of capital scope is adjusted to reflect the potential exercise of Apache Corp.’s option to purchase 15% equity in the project.
(b)As of May 31, 2017, these assets are now included in KML and are partially owned by KML’s Restricted Voting Stockholders.

KMI Financings

On August 10, 2017,During 2023, we (i) issued $1 billion$1,500 million of unsecurednew senior notes with a fixed rate of 3.15% and $250 million of unsecured senior notes with a floating rate, both due January 2023. The net proceeds from the notes were primarily used to repay allshort-term borrowings, maturing debt and for general corporate purposes; (ii) utilized commercial paper borrowings under our credit facility to fund the $1,831 million acquisition of the $225 million principal amount outstanding of Hiland’s 5.50% senior notes due 2022, plus accrued interest, and to repay the $1 billion term loan facility due 2019.

KML Financings

In addition to proceeds received from KML’s IPO discussed above, on June 16, 2017, KML entered into a definitive credit agreement establishing (i) a C$4.0 billion revolving construction facility for the purposes of funding the development, construction and completion of the TMEP; (ii) a C$1.0 billion revolving contingent credit facility for the purpose of funding, if necessary, additional TMEP costs (and, subject to the need to fund such additional costs and regulatory approval, meeting the Canadian NEB-mandated liquidity requirements)STX Midstream pipeline system (STX Midstream); and (iii) repaid a C$500combined $3,225 million revolving working capital facility, to be used for working capital and other general corporate purposes (collectively, the “KML Credit Facility”). The KML Credit Facility has a five year term and is with a syndicate of financial institutions with Royal Bank of Canada as the administrative agent.maturing senior notes. On January 23, 2018, KML entered into an agreement amending certain terms of the KML Credit Facility to, among other things, provide additional funding certainty with respect to the construction, contingent and working capital facilities. As of December 31, 2017, KML had no amounts outstanding under the KML Credit Facility and C$53 million (U.S.$42 million) in letters of credit.

On August 15, 2017, KML completed an offering of 12,000,000 cumulative redeemable minimum rate reset preferred shares, Series 1 (Series 1 Preferred Shares) on the TSX at a price to the public of $25.00 per Series 1 Preferred Share for total net proceeds of C$293 million (U.S.$230 million) and on December 8, 2017, KML completed an offering of 10,000,000 cumulative redeemable minimum rate reset preferred shares, Series 3 (Series 3 Preferred Shares) on the TSX at a price to the public of $25.00 per Series 3 Preferred Share for total net proceeds of C$243 million (U.S.$189 million).

2018 Outlook

We expect to declare dividends of $0.80 per share for 2018, a 60% increase from the 2017 declared dividends of $0.50 per share, and generate approximately $4.57 billion of DCF. We also expect to invest $2.2 billion on expansion projects and other discretionary spending in 2018, excluding growth capital and discretionary spending by KML, which we expect to continue to be a self-funding entity. As in recent years, our discretionary spending will be funded with excess, internally generated cash flow, with no need to access equity markets during 2018. In addition,18, 2023, our board of directors authorized a $2 billion(Board) approved an increase in our share repurchase authorization of our share buy-back program and in December 2017 and January 2018from $2 billion to $3 billion. During 2023, we bought back 27repurchased approximately 32 million shares of Class P sharescommon stock for $500 million.

We are unable to provide budgeted net income attributable to common stockholders (the GAAP financial measure most directly comparable to DCF) due to the inherent difficulty and impracticality of predicting certain amounts required by GAAP, such as ineffectiveness on commodity, interest rate and foreign currency hedges, unrealized gains and losses on derivatives marked to market, and potential changes in estimates for certain contingent liabilities.

These expectations assume average annual prices for WTI crude oil and Henry Hub natural gas of $56.50 per barrel and $3.00 per MMBtu, respectively, consistent with forward pricing during our 2018 budget process. The vast majority of cash we generate is supported by multi-year fee-based customer arrangements and therefore is not directly exposed to commodity

prices. The primary area where we have direct commodity price sensitivity is in our CO2 segment, in which we hedge the majority of the next 12 months of oil and NGL production to minimize this sensitivity. For 2018, we estimate that every $1 change in the average WTI crude oil price from our budget of $56.50 per barrel would impact our DCF by approximately $7$522 million and each $0.10 per MMBtu change in theat an average price of natural gas from our budget$16.56 per share. We have approximately $1.5 billion of $3.00 per MMBtu would impact DCF by approximately $1 million.capacity remaining under this program.


In addition, our expectationsOn February 1, 2024, we issued $2,250 million of new senior notes to repay short-term borrowings, fund maturing debt and for 2018 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 to not put undue reliance on any forward-looking statement.  Please read our Item 1A “Risk Factors” below for more information.  Furthermore, we plan to provide updates to our 2018 expectations when we believe previously disclosed expectations no longer have a reasonable basis.general corporate purposes.


2017 Tax Reform
5


While the recently enacted 2017 Tax Reform will ultimately be moderately positive for us, the reduced corporate income tax rate caused certain of our deferred-tax assets to be revalued at 21 percent versus 35 percent at the end of 2017.  Although there is no impact to the underlying related deductions, which can continue to be used to offset future taxable income, we took an estimated approximately $1.4 billion non-cash accounting charge in the fourth quarter of 2017.  This charge is our initial estimate and may be refined in the future as permitted by recent guidance from the SEC and FASB. The positive impacts of the law include the reduced corporate income tax rate and the fact that several of our U.S. business units (essentially all but our interstate natural gas pipelines) will be able to deduct 100 percent of their capital expenditures through 2022.  The net impact results in postponing the date when we become a significant federal cash taxpayer by approximately one year, to beyond 2024.

(b) Financial Information about Segments

For financial information on our five reportable business segments, see Note 16 “Reportable Segments” to our consolidated financial statements.

(c) Narrative Description of Business


Business Strategy


Our business strategy is to:


•focus on stable, fee-based energy transportation and storage assets that are central to the energy infrastructure and energy transition of growing markets within North America;America or served by U.S. exports;
•increase utilization of our existing assets while controlling costs, operating safely, and employing environmentally sound operating practices;
•exercise discipline in capital allocation decisions and in evaluating expansion projects and acquisition opportunities;
•leverage economies of scale from incrementalasset expansions and acquisitions and expansions of assets that fit within our strategystrategy; and are accretive to cash flow; and
•maintain a strong balance sheetfinancial profile and enhance and return value to our stockholders.


It is our intention to carry out the above business strategy, modified as necessary to reflect changing economic conditions and other circumstances. However, as discussed under Item 1A. “Risk Factors”Factors” below and at the beginning of this report in “Information Regarding Forward-Looking Statements,” there are factors that could affect our ability to carry out our strategy or affect its level of success even if carried out.


We regularly consider and enter into discussions regarding potential acquisitions and full and partial divestitures, and we are currently contemplating potential transactions. Any such transaction would be subject to negotiation of mutually agreeable terms and conditions, and, as applicable, receipt of fairness opinions, and approval of our board of directors, if applicable.Board and regulatory approval. While there are currently no unannounced purchase or sale agreements for the acquisition or sale of any material business or assets, such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations.


Business Segments
We operate the following
For financial information on our reportable business segments. These segments, and their principal sources of revenues are as follows:see Note 16 “Reportable Segments” to our consolidated financial statements.
Natural Gas Pipelines—the ownership and operation of (i) major interstate and intrastate natural gas pipeline and storage systems; (ii) natural gas and crude oil gathering systems and natural gas processing and treating facilities; (iii) NGL fractionation facilities and transportation systems; and (iv) LNG facilities;
•
CO2—(i) the production, transportation and marketing of CO2 to oil fields that use CO2 as a flooding medium for recovering crude oil from mature oil fields to increase production; (ii) ownership interests in and/or operation of oil fields and gas processing plants in West Texas; and (iii) the ownership and operation of a crude oil pipeline system in West Texas;
Terminals—the ownership and/or operation of (i) liquids and bulk terminal facilities located throughout the U.S. and portions of Canada that transload and store refined petroleum products, crude oil, chemicals, and ethanol and bulk products, including petroleum coke, steel and coal; and (ii) Jones Act tankers;
Products Pipelines—the ownership and operation of refined petroleum products, NGL and crude oil and condensate pipelines that primarily deliver, among other products, gasoline, diesel and jet fuel, propane, ethane, crude oil and condensate to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities; and
6
Kinder Morgan Canada—the ownership and operation of the Trans Mountain pipeline system that transports crude oil and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia, Canada and the state of Washington, plus the Jet Fuel aviation turbine fuel pipeline that serves the Vancouver (Canada) International Airport.


Natural Gas Pipelines


Our Natural Gas Pipelines business segment includes interstate and intrastate pipelines, andunderground storage facilities, our LNG terminals,liquefaction and terminal facilities and NGL fractionation facilities, and includes both FERC regulated and non-FERC regulated assets.

KM Pipelines NG Outlook Assets 01.31.jpg

Our primary businesses in this segment consist of natural gas transportation, storage, natural gas sales, gathering, processing and treating, and the terminaling of LNG.various LNG services.  Within this segment are: (i) approximately 46,00044,000 miles of wholly owned natural gas pipelines and (ii) our equity interests in entities that have approximately 26,00027,000 miles of natural gas pipelines, along with associated storage and supply lines for these transportation networks, which are strategically located throughout the North American natural gas pipeline grid.  Our transportation network provides access to the major natural gas supply areas and consumers in the western U.S., Louisiana, Texas, the Midwest, Northeast, Rocky Mountain, Midwest, Texas, Louisiana, Southeastern and SoutheasternNortheast regions. Our LNG storage and regasification terminalsterminal facilities also serve natural gas supplymarket areas in the southeast. The following tables summarizetable summarizes our significant Natural Gas Pipelines business segment assets as of December 31, 2017.2023. The Design Capacitydesign capacity represents either transmission, gathering, regasification or liquefaction capacity, depending on the nature of the asset.

AssetOwnership Interest Miles of PipelineDesign (Bcf/d) [(MBbl/d)] CapacityStorage (Bcf) [Processing (Bcf/d)] Capacity
East Region
TGP(a)100 %11,755 12.38 76 
NGPL37.5 %9,100 7.84 288 
KMLP100 %140 3.89 — 
Stagecoach100 %185 3.22 41 
SNG(a)50 %6,925 4.39 66 
Florida Gas Transmission (Citrus)50 %5,380 4.39 — 
MEP50 %515 1.81 — 
Elba Express100 %190 1.16 — 
FEP50 %185 2.00 — 
Gulf LNG Holdings50 %5 1.50 7 
7

Asset (KMI ownership shown if not 100%) 
 Miles
of
Pipeline
 Design (Bcf/d) Capacity Storage (Bcf) [Processing (Bcf/d)] Capacity Supply and Market Region
Natural Gas Pipelines
TGP 11,750
 12.00 106 North to south to Gulf Coast and U.S.-Mexico border, southeast U.S.; Haynesville, Marcellus, Utica, and Eagle Ford shale formations
EPNG/Mojave pipeline system 10,600
 
5.65

 44 Northern New Mexico, Texas, Oklahoma, to California, connects to San Juan, Permian and Anadarko basins
NGPL (50%) 9,100
 7.60 288 Chicago and other Midwest markets and all central U.S. supply basins; north to south for LNG and to U.S.-Mexico border
SNG (50%) 6,900
 4.16 68 Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee; basins in Texas, Louisiana, Mississippi and Alabama
Florida Gas Transmission (Citrus) (50%) 5,300
 3.60 — Texas to Florida; basins along Louisiana and Texas Gulf Coast, Mobile Bay and offshore Gulf of Mexico
CIG 4,350
 5.15 37 Colorado and Wyoming; Rocky Mountains and the Anadarko Basin
AssetOwnership Interest Miles of PipelineDesign (Bcf/d) [(MBbl/d)] CapacityStorage (Bcf) [Processing (Bcf/d)] Capacity
SLNG100 %— 1.76 12 
ELC25.5 %— 0.35 — 
West Region
EPNG/Mojave100 %10,720 6.39 44 
CIG(b)100 %4,300 6.00 38 
WIC100 %850 3.39 — 
CPGPL100 %415 1.20 — 
TransColorado100 %310 0.80 — 
Sierrita35 %60 0.52 — 
Young Gas Storage47.5 %15 — 6 
Keystone Gas Storage100 %15 — 6 
Midstream
KM Texas and Tejas pipelines(c)(d)100 %5,9809.50  138
[0.52]
Mier-Monterrey pipeline(c)100 %900.65 — 
KM North Texas pipeline(c)100 %800.33 — 
Gulf Coast Express pipeline34 %5302.00 — 
PHP27.74 %4352.65 — 
Oklahoma
Oklahoma system100 %3,1750.73  [0.09]
Cedar Cove70 %1200.03 — 
South Texas
South Texas system100 %1,1301.90  [1.02]
Webb/Duval gas gathering system91 %1400.15 — 
Camino Real100 %750.15 — 
EagleHawk25 %5551.20 — 
KM Altamont100 %1,6050.13  [0.10]
Red Cedar49 %8600.33 — 
Rocky Mountain
Fort Union50 %315 1.25 — 
Bighorn51 %290 0.60 — 
KinderHawk100 %570 2.40 — 
Greenholly Gathering39.25 %40 1.15 — 
KM Treating100 %— — — 
Hiland - Williston - gas100 %2,200 0.62  [0.33]
Eagle Ford Transmission system100 %160 1.05 — 
NET Mexico90 %120 2.15 — 
Dos Caminos50 %75 1.20 — 
Mission Natural Gas100 %1 — — 
Liberty pipeline50 %85 [140]— 
South Texas NGL pipelines(e)100 %340 [115]— 
Utopia pipeline50 %265 [50]— 
Cypress pipeline50 %105 [56]— 
EagleHawk - Condensate(f)25 %410 [220]— 

(a)Includes proportionate share of storage capacity from our Bear Creek Storage joint venture.
(b)Includes leased pipeline miles and proportionate share of design and storage capacity from our WYCO joint venture.
(c)Collectively referred to as Texas intrastate natural gas pipeline operations.
(d)Includes LaSalle, Mission Valley, Red Gate and South Shore assets associated with our acquisition of STX Midstream.
8

Asset (KMI ownership shown if not 100%) 
 Miles
of
Pipeline
 Design (Bcf/d) Capacity Storage (Bcf) [Processing (Bcf/d)] Capacity Supply and Market Region
WIC 850
 3.88 — Wyoming, Colorado and Utah; Overthrust, Piceance, Uinta, Powder River and Green River Basins
Ruby (50%)(a) 680
 1.53 — Wyoming to Oregon with interconnects supplying California and the Pacific Northwest; Rocky Mountain basins
MEP (50%) 510
 1.80 — Oklahoma and north Texas supply basins to interconnects with deliveries to interconnects with Transco, Columbia Gulf and various other pipelines
CPGPL 410
 1.20 — Colorado and Kansas, natural gas basins in the Central Rocky Mountain area
TransColorado Gas 310
 0.98 — Colorado and New Mexico; connects to San Juan, Paradox and Piceance basins
WYCO (50%) 224
 
1.20

 7 Northeast Colorado; interconnects with CIG, WIC, Rockies Express Pipeline, Young Gas Storage and PSCo’s pipeline system
Elba Express 200
 0.95 — Georgia; connects to SNG (Georgia), Transco (Georgia/South Carolina), SLNG (Georgia) and Dominion Energy Carolina Gas Transmission (Georgia)
FEP (50%) 185
 2.00 — Arkansas to Mississippi; connects to NGPL, Trunkline Gas Company, Texas Gas Transmission and ANR Pipeline Company
KMLP 135
 2.20 — sources gas from Cheniere Sabine Pass LNG terminal to interconnects with Columbia Gulf, ANR and various other pipelines
Sierrita Gas Pipeline LLC (35%) 61
 0.20 — near Tucson, Arizona, to the U.S.-Mexico border near Sasabe, Arizona; connects to EPNG and via an international border crossing with a third-party natural gas pipeline in Mexico
Young Gas Storage (48%) 16
 — 5.8 Morgan County, Colorado, capacity is committed to CIG and Colorado Springs Utilities
Keystone Gas Storage 15
 — 6.4 located in the Permian Basin and near the WAHA natural gas trading hub in West Texas
Gulf LNG Holdings (50%) 5
 — 6.6 near Pascagoula, Mississippi; connects to four interstate pipelines and a natural gas processing plant
Bear Creek Storage (75%) —
 — 59 located in Louisiana; provides storage capacity to SNG and TGP
SLNG —
 — 11.5 Georgia; connects to Elba Express, SNG and Dominion Energy Carolina Gas Transmission
ELC (51%) —
 0.35 — Georgia; expect phased in-service from mid-2018 to mid-2019
         
Midstream Natural Gas Assets
KM Texas and Tejas pipelines 5,660
 7.00 132 [0.54] Texas Gulf Coast
Mier-Monterrey pipeline 90
 0.65 — Starr County, Texas to Monterrey, Mexico; connect to CENEGAS national system and multiple power plants in Monterrey
KM North Texas pipeline 80
 0.33 — interconnect from NGPL; connects to 1,750-megawatt Forney, Texas, power plant and a 1,000-megawatt Paris, Texas, power plant
Oklahoma      
Oklahoma System 3,500
 .50 [0.14] Hunton Dewatering, Woodford Shale and Mississippi Lime
Hiland - Midcontinent 620
 .22 — Woodford Shale, Anadarko Basin and Arkoma Basin
Cedar Cove (70%) 85
 0.03 — Oklahoma STACK, capacity excludes third-party offloads
South Texas      
South Texas System 1,300
 1.74 [1.02] Eagle Ford shale, Woodbine and Eaglebine formations
Webb/Duval gas gathering system (63%) 145
 0.15 — South Texas
(e)Includes proportionate share of design capacity from our Liberty pipeline joint venture.

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

Asset (KMI ownership shown if not 100%) 
 Miles
of
Pipeline
 Design (Bcf/d) Capacity Storage (Bcf) [Processing (Bcf/d)] Capacity Supply and Market Region
EagleHawk (25%) 530
 1.20 — South Texas, Eagle Ford shale formation
KM Altamont 1,380
 0.08 [0.08] Utah, Uinta Basin
Red Cedar (49%) 900
 0.70 — La Plata County, Colorado, Ignacio Blanco Field
Rocky Mountain        
Fort Union (37%) 310
 1.25 — Powder River Basin (Wyoming)
Bighorn (51%) 290
 0.60 — Powder River Basin (Wyoming)
KinderHawk 510
 2.00 — Northwest Louisiana, Haynesville and Bossier shale formations
North Texas 550
 0.14 [0.10] North Barnett Shale Combo
Endeavor (40%) 101
 0.15 — East Texas, Cotton Valley Sands and Haynesville/ Bossier Shale
Camino Real 70
 0.15 — South Texas, Eagle Ford shale formation
KM Treating —
 — — Odessa, Texas, other locations in Tyler and Victoria, Texas
Hiland - Williston 2,030
 .32 [0.20] Bakken/Three Forks shale formations (North Dakota/Montana)
         
Midstream Liquids/Oil/Condensate Pipelines
    (MBbl/d) (MBbl)  
Liberty Pipeline (50%) 87
 140 — Y-grade pipeline from Houston Central complex to the Texas Gulf Coast
South Texas NGL Pipelines 340
 115 — Ethane and propane pipelines from Houston Central complex to the Texas Gulf Coast
Camino Real - Condensate 69
 110 60 South Texas, Eagle Ford shale formation
Hiland - Williston - Oil 1,500
 282 — Bakken/Three Forks shale formations (North Dakota/Montana)
EagleHawk - Condensate (25%) 400
 220 60 South Texas, Eagle Ford shale formation
Natural Gas Pipelines Segment Contracts
_______
(a)We operate Ruby and own the common interest in Ruby. Pembina Pipeline Corporation (Pembina) owns the remaining interest in Ruby in the form of a convertible preferred interest. If Pembina converted its preferred interest into common interest, we and Pembina would each own a 50% common interest in Ruby.


Revenues from our interstate natural gas pipelines, related storage facilities and LNG terminals are primarily received under long-term fixed contracts.  To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate risk of reduced volumes and prices by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity.  These long-term contracts are typically structured with a fixed fee reserving the right to transport or store natural gas and specify that we receive the majority of our fee for making the capacity available, whether or not the customer actually chooses to utilize that capacity. Similarly, our Texas Intrastate natural gas pipeline operations currently derive approximately 74% of its sales and transport margins from long-term transport and sales contracts. As contracts expire, we have additional exposure to the longer term trends in supply and demand for natural gas. As of December 31, 2023, the remaining weighted average contract life of our natural gas transportation contracts held by assets we own or have equity interests in (including intrastate pipelines’ sales portfolio) was approximately six years and our LNG regasification and liquefaction and associated storage contracts were subscribed under long-term agreements with a weighted average remaining contract life of approximately 11 years.

Our Midstream assets provide natural gas gathering and processing services. These assets are mostly fee-based, and the revenues and earnings we realize from gathering natural gas, processing natural gas in order to remove NGL from the natural gas stream, and fractionating NGL into its base components, are affected by the volumes of natural gas made available to our systems. Such volumes are impacted by producer rig count and drilling activity. In addition to fee-based arrangements, some of which may include minimum volume commitments, we also provide some services based on percent-of-proceeds, percent-of-index and keep-whole contracts. Our service contracts may rely solely on a single type of arrangement, but more often they combine elements of two or more of the above, which helps us and our counterparties manage the extent to which each shares in the potential risks and benefits of changing commodity prices. Our natural gas marketing activities generate revenues from the sale and delivery of natural gas purchased either directly from producers or from others on the open market.

Natural Gas Pipelines Segment Competition


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


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


9
CO2


Products Pipelines

Our CO2Products Pipelines business segment produces, transports, and markets CO2 for use in enhanced oil recovery projects as a flooding medium for recoveringconsists of our refined petroleum products, crude oil from mature oil fields.  Our CO2and condensate pipelines, and relatedassociated terminals, our condensate processing facility and our transmix processing facilities.
Products Segment Outlook Slide 12 10K.jpg

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The following summarizes the significant Products Pipelines business segment assets allow us to market a complete

package of CO2 supply, transportationthat we owned and technical expertise to our customers. We also hold ownership interests in several oil-producing fields and own a crude oil pipeline, all located in the Permian Basin region of West Texas.

Sales and Transportation Activities

Our principal market for CO2 is for injection into mature oil fields in the Permian Basin. Our ownership of CO2 resourcesoperated as of December 31, 2017 includes:2023:

AssetOwnership InterestMiles of PipelineNumber of Terminals (a) or locationsTerminal Capacity
(MMBbl)
Crude & Condensate
KM Crude & Condensate pipeline100 %266 5 2.6 
Camino Real Gathering100 %68 1 0.1 
Hiland - Williston Basin - oil(b)100 %1,645 7 0.8 
Double H pipeline(b)100 %512 — — 
Double Eagle pipeline50 %204 2 0.6 
KM Condensate Processing Facility (Splitter)100 %— 1 2.1 
Southeast Refined Products
Products (SE) pipeline51 %3,187 — — 
Central Florida pipeline100 %206 2 2.6 
Southeast Terminals100 %— 25 9.3 
Transmix Operations100 %— 5 0.6 
West Coast Refined Products
Pacific (SFPP)99.5 %2,806 13 15.9 
Calnev100 %566 2 2.1 
West Coast Terminals100 %44 8 10.1 
(a)The terminals provide services including short-term product storage, truck loading, vapor handling, additive injection, dye injection and ethanol blending.
 
Ownership
Interest %
 
Recoverable
CO2 (Bcf)
 
Compression
Capacity (Bcf/d)
 Location
Recoverable CO2
       
McElmo Dome unit45 4,159
 1.5
 Colorado
Doe Canyon Deep unit87 382
 0.2
 Colorado
Bravo Dome unit(a)11 285
 0.3
 New Mexico
(b)Collectively referred to as Bakken Crude assets.
_______
(a)We do not operate this unit.


CO2Products Pipelines Segment PipelinesContracts


The principal marketprofitability of our refined petroleum products pipeline transportation business generally is driven by the volume of refined petroleum products that we transport and the prices we receive for transportation on our CO2 pipelines is to customers, including ourselves, using CO2 for enhanced recovery operations in mature oil fieldsservices.  Included in the Permian Basin, where industrynumber of terminals above are refined products liquids terminals that store fuels and offer blending services for ethanol and biodiesel. The transportation and storage volume levels are primarily driven by the demand is expected to remain stable for the next several years.refined petroleum products being shipped or stored.  Demand for refined petroleum products tends to follow trends in population and economic growth, and, with the exception of periods of time with very high product prices or recessionary conditions, demand tends to be relatively stable.  Because of that, we seek to own refined petroleum products pipelines and terminals located in, or that transport to, stable or growing markets and population centers.  The prices for shipping are generally based on regulated tariffs chargedthat are adjusted annually based on changes in the WinkU.S. Producer Price Index and a FERC index rate.

Our crude, condensate and refined petroleum products transportation services are primarily provided pursuant to (i) either FERC or state tariffs (which do not require contractual commitments) or (ii) long-term contracts that normally contain minimum volume commitments. Where we have long-term contracts, our settlement volumes are generally not sensitive to changing market conditions in the shorter term; however, the revenues and earnings we realize from our pipelines and terminals are affected by the volumes of crude oil, refined petroleum products and condensate available to our pipeline systemsystems, which are regulated by both the FERC and the Texas Railroad Commission and the Pecos Carbon Dioxide Pipeline’s tariffs are regulatedimpacted by the Texas Railroad Commission. The tariff charged on the Cortez pipeline is based on a consent decree and the tariffs charged by our other CO2 pipelines are not regulated.

Our ownershiplevels of CO2 and crude oil pipelines as of December 31, 2017 includes:

Asset (KMI ownership shown if not 100%) Miles of Pipeline Transport Capacity (Bcf/d) Supply and Market Region
CO2 pipelines
      
Cortez pipeline (53%) 569
 1.5
 McElmo Dome and Doe Canyon source fields to the Denver City, Texas hub
Central Basin pipeline 334
 0.7
 Cortez, Bravo, Sheep Mountain, Canyon Reef Carriers, and Pecos pipelines
Bravo pipeline (13%)(a) 218
 0.4
 Bravo Dome to the Denver City, Texas hub
Canyon Reef Carriers pipeline (98%) 163
 0.3
 McCamey, Texas, to the SACROC, Sharon Ridge, Cogdell and Reinecke units
Centerline CO2 pipeline
 113
 0.3
 between Denver City, Texas and Snyder, Texas
Eastern Shelf CO2 pipeline
 98
 0.1
 between Snyder, Texas and Knox City, Texas
Pecos pipeline (95%) 25
 0.1
 McCamey, Texas, to Iraan, Texas, delivers to the Yates unit
Goldsmith Landreth (99%) 3
 0.2
 Goldsmith Landreth San Andres field in the Permian Basin of West Texas
    (Bbls/d)  
Crude oil pipeline      
Wink pipeline 457
 145,000
 West Texas to Western Refining’s refinery in El Paso, Texas
_______
(a)We do not operate Bravo pipeline.


Oil and Gas Producing Activities

Oil Producing Interests

Our ownership interests in oil-producing fields located in the Permian Basin of West Texas include the following:

   KMI Gross
 Working Developed
 Interest % Acres
SACROC97
 49,156
Yates50
 9,576
Goldsmith Landreth San Andres99
 6,166
Katz Strawn99
 7,194
Sharon Ridge14
 2,619
Tall Cotton (ROZ)100
 641
MidCross13
 320
Reinecke(a)—
 80
_______
(a)Working interest less than 1 percent.

The following table sets forth productive wells, service wells and drilling wells in the oil and gas fieldsdrilling activity and product demand in whichthe respective regions that we owned interestsserve. Our petroleum condensate processing facility splits condensate into its various components, such as light and heavy naphtha, under a long-term fee-based agreement with a major integrated oil company. Our crude oil marketing activities generate revenues from the sale and delivery of December 31, 2017.  Thecrude oil and gas producing fieldscondensate purchased either directly from producers or from others on the open market. In general, sales prices referenced in which we own interestsunderlying purchase and sales contracts are located in the Permian Basin areamarket-based and include pricing differentials for factors such as delivery location or crude oil quality.

Products Pipelines Segment Competition

Our Products Pipelines’ pipeline and terminal operations compete against proprietary pipelines and terminals owned and operated by major oil companies, other independent products pipelines and terminals, trucking and marine transportation firms (for short-haul movement of West Texas.  When usedproducts). Our transmix operations compete with respect to acres or wells, “gross” refers to the total acres or wells in which we have a working interest, and “net” refers to gross acres or wells multiplied, in each case, by the percentage working interestrefineries owned by us:

major oil companies and independent transmix facilities.
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 Productive Wells(a) Service Wells(b) Drilling Wells(c)
 Gross Net Gross Net Gross Net
Crude Oil2,327
 1,518
 1,412
 1,088
 27
 26
Natural Gas5
 2
 —
 —
 —
 —
Total Wells2,332
 1,520
 1,412
 1,088
 27
 26
_______
(a)Includes active wells and wells temporarily shut-in.  As of December 31, 2017, we did not operate any productive wells with multiple completions.
(b)Consists of injection, water supply, disposal wells and service wells temporarily shut-in.  A disposal well is used for disposal of salt water into an underground formation; and an injection well is a well drilled in a known oil field in order to inject liquids and/or gases that enhance recovery.
(c)Consists of development wells in the process of being drilled as of December 31, 2017. A development well is a well drilled in an already discovered oil field.

The following table reflects our wells that were completed in each of the years ended December 31, 2017, 2016 and 2015:


 Year Ended December 31,
 2017 2016 2015
Productive     
Development                                  108
 40
 87
Exploratory                                    3
 20
Total Productive108
 43
 107
Dry Exploratory—
 —
 —
Total Wells108
 43
 107
_______
Note: The above table includes wells that were completed during each year regardless of the year in which drilling was initiated, and does not include any wells where drilling and completion operations were not finalized as of the end of the applicable year.  A completed well refers to the installation of permanent equipment for the production of oil and gas. A development well is a well drilled in an already discovered oil field. A dry hole is reflected once the well has been abandoned and reported to the appropriate governmental agency.

The following table reflects the developed and undeveloped oil and gas acreage that we held as of December 31, 2017:
 Gross Net
Developed Acres75,752
 72,562
Undeveloped Acres17,282
 15,351
Total93,034
 87,913

Our oil and gas producing activities are not significant and therefore, we do not include the supplemental information on oil and gas producing activities under Accounting Standards Codification Topic 932, Extractive Activities - Oil and Gas.

Gas and Gasoline Plant Interests

Operated gas plants in the Permian Basin of West Texas:
Ownership
Interest %Source
Snyder gasoline plant(a)22
The SACROC unit and neighboring CO2 projects, specifically the Sharon Ridge and Cogdell units
Diamond M gas plant51
Snyder gasoline plant
North Snyder plant100
Snyder gasoline plant
_______
(a)This is a working interest, in addition, we have a 28% net profits interest.

Competition

Our primary competitors for the sale of CO2 include suppliers that have an ownership interest in McElmo Dome, Bravo Dome and Sheep Mountain CO2 resources, and Oxy U.S.A., Inc., which controls waste CO2 extracted from natural gas production in the Val Verde Basin of West Texas.  Our ownership interests in the Central Basin, Cortez and Bravo pipelines are in direct competition with other CO2 pipelines.  We also compete with other interest owners in the McElmo Dome unit and the Bravo Dome unit for transportation of CO2 to the Denver City, Texas market area.

Terminals


Our Terminals business segment includes the operations of our refined petroleum product, crude oil, chemical, ethanolrenewable fuel and other liquid terminal facilities (other than those included in the Products Pipelines business segment) and all of our petroleum coke, steelmetal and coalores facilities.  Our terminals are located throughout theprimarily near large U.S. and in portions of Canada.urban centers.  We believe the location of our facilities and our ability to provide flexibility to customers help attract new and retain existing customers at our terminals and provide expansion opportunities. We often classify our terminal operations based on the handling of either liquids or dry-bulk material products. In addition, our Terminals’ marine operations include Jones Act qualifiedAct-qualified product tankers that provide marine transportation of crude oil, condensate, and refined petroleum products and renewable fuel between U.S. ports.

KM Terminals Slide 16.jpg


The following summarizes our Terminals business segment assets, as of December 31, 2017:2023:

NumberCapacity
(MMBbl)
Liquids terminals4778.7
Bulk terminals27— 
Jones Act tankers165.3

Terminals Segment Contracts

The factors impacting our Terminals business segment generally differ between liquid and bulk terminals.  Our liquids terminals business generally enters into long-term contracts that require the customer to pay our fee regardless of whether they use the capacity.  Thus, similar to our natural gas pipelines business, our liquids terminals business is less sensitive to short-term changes in supply and demand.  Therefore, the extent to which changes in supply and demand affect our terminals business in the near term is a function of the remaining length of the underlying service contracts (which on a weighted average basis was approximately two years as of December 31, 2023), the extent to which revenues under the contracts are a function of the amount of product stored or transported, and the extent to which such contracts expire during any given period of time.

As with our refined petroleum products pipelines transportation business, the revenues from our bulk terminals business are generally driven by the volumes we handle and/or store, as well as the prices we receive for our services, which in turn are
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 Number 
Capacity
(MMBbl)
Liquids terminals51
 87.4
Bulk terminals35
 —
Jones Act tankers16
 5.3
driven by the demand for the products being shipped or stored.  While we handle and store a large variety of products in our bulk terminals, the primary products are petroleum coke, metals and ores.  In addition, the majority of our contracts for this business contain minimum volume guarantees and/or service exclusivity arrangements under which customers are required to utilize our terminals for all or a specified percentage of their handling and storage needs.  The profitability of our minimum volume contracts is generally unaffected by short-term variation in economic conditions; however, to the extent we expect volumes above the minimum and/or have contracts which are volume-based, we can be sensitive to changing market conditions.  To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate the risk of reduced volumes and pricing by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity.  In addition, weather-related events, including hurricanes, may impact our facilities and access to them and, thus, the profitability of certain terminals for limited periods of time or, in relatively rare cases of severe damage to facilities, for longer periods.


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

Terminals Segment Competition


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

operators with lower cost structures.  Our Jones Act qualified productAct-qualified tankers compete with other Jones Act qualifiedAct-qualified vessel fleets.


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Products Pipelines


CO2

Our Products PipelinesCO2 business segment consists of our refined petroleum products,produces, transports and markets CO2 for use in enhanced oil recovery projects as a flooding medium for recovering crude oil and condensate, and NGL pipelines and associated terminals, Southeast terminals, our condensate processing facility and our transmix processing facilities. The following summarizes our significant Products Pipelines segment assets we own and operate as of December 31, 2017:

Asset (KMI ownership shown if not 100%) Miles of Pipeline Number of Terminals (a) or locations Terminal Capacity(MMBbl) Supply and Market Region
Plantation pipeline (51%) 3,182
 — — Louisiana to Washington D.C.
West Coast Products Pipelines(b)        
Pacific (SFPP) 2,845
 13
 15.2
 six western states
Calnev 566
 2
 2.0
 Colton, CA to Las Vegas, NV; Mojave region
West Coast Terminals 38
 7
 10.3
 Seattle, Portland, San Francisco and Los Angeles areas
Cochin pipeline 1,810
 3
 1.1
 three provinces in Canada and seven states in the U.S.
KM Crude & Condensate pipeline 264
 5
 2.6
 Eagle Ford shale field in South Texas (Dewitt, Karnes, and Gonzales Counties) to the Houston ship channel refining complex
Double H Pipeline 511
 — — Bakken shale in Montana and North Dakota to Guernsey, Wyoming
Central Florida pipeline 206
 2
 2.4
 Tampa to Orlando
Double Eagle pipeline (50%) 204
 2
 0.6
 Live Oak County, Texas; Corpus Christi, Texas; Karnes County, Texas; and LaSalle County
Cypress pipeline (50%) 104
 — — Mont Belvieu, Texas to Lake Charles, Louisiana
Southeast Terminals — 32
 10.7
 from Mississippi through Virginia, including Tennessee
KM Condensate Processing Facility — 1
 1.9
 Houston Ship Channel, Galena Park, Texas
Transmix Operations — 5
 0.6
 Colton, California; Richmond, Virginia; Dorsey Junction, Maryland; St. Louis, Missouri; and Greensboro, North Carolina
_______
(a)The terminals provide services including short-term product storage, truck loading, vapor handling, additive injection, dye injection and ethanol blending.
(b)Our West Coast Products Pipelines assets include interstate common carrier pipelines rate-regulated by the FERC, intrastate pipelines in the state of California rate-regulated by the CPUC, and certain non rate-regulated operations and terminal facilities.

Competition

Our Products Pipelines’ pipeline operations compete against proprietary pipelines owned and operated by majorfrom mature oil companies, other independent products pipelines, trucking and marine transportation firms (for short-haul movements of products) and railcars. Our Products Pipelines’ terminal operations compete with proprietary terminals owned and operated by major oil companies and other independent terminal operators, and our transmix operations compete with refineries owned by major oil companies and independent transmix facilities.

Kinder Morgan Canada

Our Kinder Morgan Canada business segment includes the Trans Mountain pipeline system and a 25-mile Jet Fuel pipeline system. Effective with KML’s May 2017 IPO, the operating assets in our Kinder Morgan Canada segment are included in KML. Operating assets in our Terminals and Products Pipelines segments are also included in KML, in which we retain a controlling interest, and KML and these operating assets are included in our consolidated financial statements.


Trans Mountain Pipeline System

The Trans Mountain pipeline system (TMPL) originates at Edmonton, Alberta and transports crude oil and refined petroleum products to destinations in the interior and on the west coast of British Columbia. The TMPL is 713 miles in length. The capacity of the line at Edmonton ranges from 300 MBbl/d when heavy crude oil represents 20% of the total throughput (which is a historically normal heavy crude oil percentage), to 400 MBbl/d with no heavy crude oil. The TMPL mainline is a common carrier pipeline, providing transportation services under a cost of service model that is negotiated with shippers and regulated by the NEB. Although Trans Mountain takes custody of its shippers’ products, it does not own any of the product it ships. The TMPL system has posted tariff rates that are available to all shippers based on a monthly contract which varies according to the type of product being shipped as well as receipt and delivery points. As such, it provides service to producers, marketers, refineries and terminals who sell or resell products to domestic markets, oil marketers and international shippers moving oil to such places as California, Washington State and Asia.

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

KM CO2 Facilities AND ETV Map 10K 01.04.jpg

Source and Transportation Activities

CO2 Resource Interests

Our ownership of CO2 resources as of December 31, 2023 includes:
Ownership
Interest		Compression
Capacity (Bcf/d)
McElmo Dome unit45 %1.5 
Doe Canyon Deep unit87 %0.2 
Bravo Dome unit(a)11 %0.3 
(a)We do not operate this unit.

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CO2 and Crude Oil Pipelines

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

Our ownership of CO2 and crude oil pipelines as of December 31, 2023 includes:
AssetOwnership InterestMiles of PipelineTransport Capacity (Bcf/d)
[(MBbl/d)]
CO2 pipelines
Cortez53 %5691.5
Central Basin100 %3370.7
Bravo(a)13 %2180.4
Canyon Reef Carriers97 %1630.3
Centerline100 %1130.3
Eastern Shelf100 %980.1
Pecos95 %250.1
Crude oil pipeline
Wink100 %434[145]
(a)We do not operate Bravo.

Oil, Gas and RNG Producing Activities

Oil and Gas Producing Interests

Our ownership interests in oil and gas producing fields as of December 31, 2023 included the following:
Working InterestKMI Gross Developed Acres
SACROC97 %50,316 
Yates50 %9,676 
Goldsmith Landreth San Andres99 %6,166 
Katz Strawn99 %7,194 
Diamond M88 %5,396 
Reinecke70 %3,793 
Sharon Ridge(a)14 %2,619 
Tall Cotton100 %641
MidCross(a)13 %320
(a)We do not operate these fields.

Our oil and gas producing activities are not significant to refineriesKMI as a whole; therefore, we do not include the supplemental information on oil and gas producing activities under Accounting Standards Codification Topic 932, Extractive Activities – Oil and Gas.

Gas Plant Interests

Our ownership and operation of gas plants as of December 31, 2023 included:
AssetOwnership InterestSource
Snyder gas plant(a)22 %
The SACROC unit and neighboring CO2 projects, specifically the Sharon Ridge and Cogdell units
Diamond M gas plant51 %Snyder gas plant
North Snyder gas plant100 %Snyder gas plant
(a)This is a working interest; in addition, we have a 28% net profits interest.

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RNG, LNG and GTE Facilities

Our ownership and operation of RNG, LNG and GTE facilities as of December 31, 2023 included:
AssetOwnership InterestProduction [Storage] Generation Capacity(a)Product
LNG Indy100 %[2 Bcf]LNG
Indy High BTU50 %1.0 Bcf/yRNG
Twin Bridges100 %1.5 Bcf/yRNG
Liberty100 %1.5 Bcf/yRNG
Prairie View100 %0.8 Bcf/yRNG
Arlington RNG100 %1.3 Bcf/yRNG
Shreveport RNG(b)— %0.7 Bcf/yMedium BTU
Victoria RNG100 %0.4 Bcf/yMedium BTU
Southeast Berrien100 %4.8 mW/hGTE
Autumn Hills100 %4.0 mW/hGTE
Central100 %4.0 mW/hGTE
Venice Park100 %6.4 mW/hGTE
Morehead100 %1.6 mW/hGTE
Blue Ridge100 %1.6 mW/hGTE
(a)GTE generation capacity is measured in megawatts per hour (mW/h). RNG and Medium British Thermal Units (BTU) gas capacities are measured in Bcf per year (Bcf/y).
(b)We operate Shreveport for a fee and receive royalties on RNG sales.

CO2 Segment Contracts

Our CO2 source and transportation business primarily has third-party contracts with minimum volume requirements, which as of December 31, 2023 had a remaining average contract life of approximately seven years.  Our CO2 sales contracts vary from customer to customer and generally provide for a delivered price tied to the stateprice of Washington referred to as the Puget Sound Pipeline System which is regulated by the FERC for tariffs and the U.S. Department of Transportation for safety and integrity.

TMEP

KML continues to move forward with its C$7.4 billion TMEP that upon completion would provide western Canadian crude oil, producers with an additional 590 MBbl/d of shipping capacity and tidewater access to the western U.S. (most notably states of Washington, California and Hawaii) and global markets (most notably Asia). TMEP has firm transportation services agreements with 13 companies for a total of 707.5 MBbl/din some casesbased on a capacityfixed fee or floor price. Our success in this portion of 890 MBbl/d (the maximumthe CO2 business segment can be impacted by the demand for CO2.  In the CO2 business segment’s oil and gas producing activities, we monitor the amount of capital we expend in relation to the amount of production that Trans Mountain anticipatedwe expect to add.  The revenues we receive from our crude oil and NGL sales are affected by the NEB would authorize).

prices we realize from the sale of these products.  Over the long-term, we tend to receive prices that are driven by the demand and overall market price for these products.  In the shorter term, however, market prices generally are not indicative of the revenues we will receive due to our hedging program, in which the prices to be realized for certain of our future sales quantities are fixed or bracketed through the use of financial derivative contracts, particularly for crude oil.  See “Item 7—Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—General—KML—TMEP Construction Progress.”

Jet Fuel Pipeline System

We also own and operate the approximate 25-mile aviation fuel pipeline that serves the Vancouver International Airport, located in Vancouver, British Columbia, Canada. The turbine fuel pipeline is referred to in this report as the Jet Fuel pipeline system. In addition to its receiving and storage facilities located at the Westridge Marine terminal, located in Port Metro Vancouver, the Jet Fuel pipeline system’s operations include a terminal at the Vancouver airport that consistsResults of five jet fuel storage tanks with an overall capacity of 15 MBbl.

Competition

Although Trans Mountain is the only pipeline carryingOperations—Segment Earnings Results” for more information on crude oil sales prices.

CO2 Segment Competition

Our primary competitors for the sale of CO2 include suppliers that have an ownership interest in McElmo Dome, Bravo Dome and refined petroleum products from AlbertaSheep Mountain CO2 resources.  Our ownership interests in the Central Basin, Cortez and Bravo pipelines are in direct competition with other CO2 pipelines.  We compete with other interest owners in the McElmo Dome unit and the Bravo Dome unit for transportation of CO2 to the west coast, it is subject to competition resulting from the shipment of oil from the Western Canadian Sedimentary Basis (WCSB) to markets other than the Canadian and U.S. West Coast, including shipments to refineries in Ontario, the U.S. Midwest and the U.S. Gulf Coast. In addition, refineries in Washington State and California, which comprise an important point of sale on the U.S. West Coast, have, in the past, been supplied primarily by crude oil from the Alaska North Slope. As such, there has historically been some competitive pressure on supply originating from the WCSB for sale in the states of Washington and California refinery markets. A further source of competition exists from the transportation of oil to the Canadian West Coast by rail. We expect that such supply and demand conditions in the oil markets served from the Canadian West Coast will continue to impact the long-term value and economics of the TMPL system.Denver City, Texas market area.


Historically, the Jet Fuel pipeline has transported a significant proportion of the jet fuel used at the Vancouver International Airport. However, the airport also receives jet fuel through other means including trucks and an airport approved, and yet to be constructed, jet fuel barge-receiving terminal near the airport. The Jet Fuel pipeline systems’ supplying refinery was sold in 2017. As a result of that sale, we are unable to predict whether, and to what extent, that refinery will continue to supply jet fuel to the Jet Fuel pipeline. These developments have made it unclear how much jet fuel will continue to be available for shipment to the Vancouver International Airport by way of the Jet Fuel pipeline in the future. We continue to assess our options relating to our Jet Fuel pipeline assets.


Major Customers


Our revenue is derived from a wide customer base.For each of the years ended December 31, 2017, 20162023, 2022 and 2015,2021, no revenues from transactions with a single external customer accounted for 10% or more of our total consolidated revenues. We do not believe that a loss of revenues from any single customer would have a material adverse effect on our business, financial position, results of operations or cash flows.


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Industry Regulation

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

Interstate Natural Gas Pipeline operations (includesTransportation and Storage Regulation

We operate our interstate natural gas pipeline and storage facilities subject to the operationsjurisdiction of Kinder Morgan Tejas Pipeline LLC, Kinder Morgan Border Pipeline LLC, Kinder Morgan Texas Pipeline LLC, Kinder Morgan North Texas Pipeline LLCthe FERC and the Mier-Monterrey Mexicoprovisions of the Natural Gas Act of 1938 (NGA), the Natural Gas Policy Act of 1978 (NGPA), and the Energy Policy Act of 2005 (the Energy Policy Act). These laws give the FERC authority over the construction and operation of such facilities, including their modification, extension, enlargement and abandonment.

Pursuant to the NGA, the FERC also has authority over the rates charged and terms and conditions of services offered by interstate natural gas pipeline system) buys and sells significant volumesstorage companies. The FERC’s regulatory authority extends to establishing minimum and maximum rates for services and allows operators to discount or negotiate rates on a non-discriminatory basis. The rates, terms and conditions of service are set forth in posted tariffs approved by the FERC for each of our interstate natural gas pipeline and storage companies. Posted tariff rates are deemed just and reasonable and cannot be changed without FERC authorization following an evidentiary hearing or settlement. The FERC can initiate proceedings, on its own initiative or in response to a shipper complaint, that could result in a rate change or confirm existing rates. Negotiated rates provide certainty to the pipeline and the shipper of agreed-upon rates during the term of the transportation agreement, regardless of changes to the posted tariff rates. Negotiated rate agreements must be filed with the FERC or included in summary form in the pipeline’s tariff.

FERC regulations also include a comprehensive framework for market transparency and nondiscrimination, as well as the FERC’s prohibition against market manipulation. Under the Energy Policy Act and related regulations, it is unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas withinsubject to the statejurisdiction of Texas,the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, to engage in fraudulent conduct. FERC Standards of Conduct regulate, among other things, the manner in which interstate natural gas pipelines may interact with their marketing affiliates. The FERC’s market oversight and to a far lesser extent, the CO2 business segment also sells natural gas. Combined, total revenues from thetransparency regulations require annual reports of purchases or sales of natural gas frommeeting certain thresholds and criteria and certain public postings of information on scheduled volumes.

The FERC has authority to impose civil penalties of more than $1.4 million per day per violation. If we fail to comply with all applicable statutes, rules, regulations, and orders administered by the Natural Gas PipelinesFERC, we could be subject to substantial civil penalties and CO2 business segments in 2017, 2016 and 2015 accounted for 22%, 19% and 20%, respectively, of our total consolidated revenues. To the extent possible, we attemptfines.

In addition to balance the pricing and timing of ourhaving jurisdiction over interstate natural gas purchases to ourpipelines and storage companies, the FERC also has jurisdiction over the interstate transportation and storage services that are provided by intrastate natural gas sales,pipelines and storage companies under Section 311 of the NGPA. We have numerous intrastate pipelines and storage companies that provide interstate services pursuant to Section 311 of the NGPA. Under Section 311, along with the FERC’s implementing regulations, an intrastate pipeline may transport gas “on behalf of” an interstate pipeline company or any local distribution company served by an interstate pipeline, without becoming subject to the FERC’s broader regulatory authority under the NGA. These services must be provided on an open and nondiscriminatory basis, and the rates charged for these contracts are often settledservices may not exceed a “fair and equitable” level as determined by the FERC in terms of an index price for both purchases and sales.periodic rate proceedings.

Regulation


Interstate Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation - U.S. Operations


Some of our U.S. refined petroleum products and crude oil gathering and transmission pipelines are interstate common carrier pipelines, subject to regulation by the FERC under the Interstate Commerce Act, or ICA. The ICA requires that we maintain our tariffs on file with the FERC. Those tariffs set forth the rates we charge for providing gathering or transportation services on our interstate common carrier liquids pipelines as well as the rules and regulations governing these services. The ICA requires, among other things, that such rates on interstate common carrier liquids pipelines be “just and reasonable” and nondiscriminatory. The ICA permits interested persons to challenge newly proposed or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund to shippers the difference between the revenues in excess of the prior tariff collected during the pendency of the investigation.investigation and the revenues that would have been collected based on the rate the FERC finds to be just and reasonable. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained during the two years prior to the filing of a complaint.

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The Energy Policy Act of 1992 deemed petroleum products pipeline tariff rates that were in effect for the 365-day period ending on the date of enactment or that were in effect on the 365th day preceding enactment and had not been subject to complaint, protest or investigation during the 365-day period to be just and reasonable or “grandfathered” under the ICA. The Energy Policy Act also limited the circumstances under which a complaint can be made against such grandfathered rates. Certain rates on our Pacific operations’ pipeline system were subject to protest during the 365-day period established by the Energy Policy Act. Accordingly, certain of the Pacific pipelines’ rates have been, and continue to be, the subject of complaints with the FERC, as is more fully described in Note 17 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements.


Petroleum products and crude oil pipelines may change their rates within prescribed ceiling levels that are tied to an inflation index. Shippers may protest rate increases made within the ceiling levels, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs from the previous year. AGenerally, a petroleum products or crude oil pipeline must, as a general rule,will utilize the FERC’s indexing methodology to changeadjust its rates.rates, as indexing serves as the default rate-adjustment mechanism. Cost-of-service ratemaking,based rates, market-based rates and settlement rates are alternatives to the default indexing approachmechanism and may be used in certain specified circumstances to change rates.


Common Carrier Pipeline Rate Regulation - Canadian Operations

The Canadian portion of our crude oil and refined petroleum products pipeline systems is under the regulatory jurisdiction of the NEB. The National Energy Board Act gives the NEB power to authorize pipeline construction and to establish tolls and conditions of service.

The toll charged for the portion of Trans Mountain’s pipeline system located in the U.S. falls under the jurisdiction of the FERC. For further information, see “—Interstate Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation - U.S. Operations” above.


Interstate Natural Gas Transportation and Storage Regulation

Posted tariff rates set the general range of maximum and minimum rates we charge shippers on our interstate natural gas pipelines. Within that range, each pipeline is permitted to charge discounted rates, so long as such discounts are offered to all similarly situated shippers and granted without undue discrimination. Apart from discounted rates offered within the range of tariff maximums and minimums, the pipeline is permitted to charge negotiated rates where the pipeline and shippers want rate certainty, irrespective of changes that may occur to the range of tariff-based maximum and minimum rate levels. Negotiated rates provide certainty to the pipeline and the shipper of agreed upon rates during the term of the transportation agreement, regardless of changes to the posted tariff rates. There are a variety of rates that different shippers may pay, but while the rates may vary by shipper and circumstance, pipelines must generally use the form of service agreement that is contained within their FERC approved tariff. Any deviation from the pro forma service agreements must be filed with the FERC and only certain types of deviations are acceptable to the FERC.

The FERC regulates the rates, terms and conditions of service, construction and abandonment of facilities by companies performing interstate natural gas transportation services, including storage services, under the Natural Gas Act of 1938. To a lesser extent, the FERC regulates interstate transportation rates, terms and conditions of service under the Natural Gas Policy Act of 1978. Beginning in the mid-1980’s, the FERC initiated a number of regulatory changes intended to ensure that interstate natural gas pipelines operated on a not unduly discriminatory basis and to create a more competitive and transparent environment in the natural gas marketplace. Among the most important of these changes were:

Order No. 436 (1985) which required open-access, nondiscriminatory transportation of natural gas;
Order No. 497 (1988) which set forth new standards and guidelines imposing certain constraints on the interaction between interstate natural gas pipelines and their marketing affiliates and imposing certain disclosure requirements regarding that interaction;
Order Nos. 587, et seq., Order No. 809 (1996-2015) which adopt regulations to standardize the business practices and communication methodologies of interstate natural gas pipelines to create a more integrated and efficient pipeline grid and wherein the FERC has incorporated by reference in its regulations standards for interstate natural gas pipeline business practices and electronic communications that were developed and adopted by the North American Energy Standards Board (NAESB). Interstate natural gas pipelines are required to incorporate by reference or verbatim in their respective tariffs the applicable version of the NAESB standards;
Order No. 636 (1992) which required interstate natural gas pipelines that perform open-access transportation under blanket certificates to “unbundle” or separate their traditional merchant sales services from their transportation and storage services and to provide comparable transportation and storage services with respect to all natural gas supplies. Natural gas pipelines must now separately state the applicable rates for each unbundled service they provide (i.e., for transportation services and storage services for natural gas);
Order No. 637 (2000) which revised, among other things, FERC regulations relating to scheduling procedures, capacity segmentation, and pipeline penalties in order to improve the competitiveness and efficiency of the interstate pipeline grid; and
Order No. 717 (2008) amending the Standards of Conduct for Transmission Providers (the Standards of Conduct or the Standards) to make them clearer and to refocus the marketing affiliate rules on the areas where there is the greatest potential for abuse. The FERC standards of conduct address and clarify multiple issues with respect to the actions and operations of interstate natural gas pipelines and public utilities using a functional approach to ensure that natural gas transmission is provided on a nondiscriminatory basis, including (i) the definition of transmission function and transmission function employees; (ii) the definition of marketing function and marketing function employees; (iii) the definition of transmission function information and non-disclosure requirements regarding non-public information; (iv) independent functioning and no conduit requirements; (v) transparency requirements; and (vi) the interaction of FERC standards with the NAESB business practice standards. The Standards of Conduct rules also require that a transmission provider provide annual training on the standards of conduct to all transmission function employees, marketing function employees, officers, directors, supervisory employees, and any other employees likely to become privy to transmission function information.

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


CPUC Rate Regulation


The intrastate common carrier operations of our Pacific operations’refined products pipelines in California are subject to regulation by the CPUC under a “depreciated book plant” methodology, which is based on an original cost measure of investment. Intrastate tariffs filed by us with the CPUC have been established on the basis of revenues, expenses and investments allocated as applicable to the California intrastate portion of the Pacificrefined products operations’ business. Tariff rates with respect to intrastate pipeline service in California are subject to challenge by complaintprotest by interested parties or by independent action of the CPUC. A variety of factors can affect the rates of return permitted by the CPUC, and certain other issues similar to those which have arisen with respect to our FERC regulated rates also could arise with respect to its intrastate rates. The  intrastate rates for movements in California on our SFPP and Calnev systems have been, and may in the future be, subject to complaints before the CPUC, as is more fully described in Note 17 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements.


Railroad Commission of Texas (RCT) Rate Regulation


The intrastate operations of our crude oil and liquids pipelines and natural gas pipelines and storage facilities in Texas are subject to regulation with respect to such intrastate transportation by the RCT. The RCT has the authority to regulate our rates, though it generally has not investigated the rates or practices of our intrastate pipelines in the absence of shipper complaints.

Mexico - Energy Regulatory Commission

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

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

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

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

Safety Regulation

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

The ultimate costs of compliance with pipeline Integrity Management rules are difficult to predict. Changes such as advances of in-line inspection tools, identification of additional integrity threats and changes to the amount of pipe determined to be located in HCAs can have a significant impact on costs to perform integrity testing and repairs. We plan to continue our pipeline integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by PHMSA regulations. These tests could result in significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

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

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which was signed into law in 2012, increased penalties for violations of safety laws and rules and may result in the imposition of more stringent regulations in the next few

years. In 2012, PHMSA issued an Advisory Bulletin which, among other things, advises pipeline operators that if they are relying on design, construction, inspection, testing, or other data to determine maximum pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities to meet the Advisory Bulletin requirements, could significantly increase our costs. Additionally, failure to locate such records to verify maximum pressures could result in reductions of allowable operating pressures, which would reduce available capacity on our pipelines. There can be no assurance as to the amount or timing of future expenditures for pipeline Integrity Management regulation, and actual expenditures may be different from the amounts we currently anticipate. Regulations, changes to regulations or an increase in public expectations for pipeline safety may require additional reporting, the replacement of some of our pipeline segments, addition of monitoring equipment and more frequent inspection or testing of our pipeline facilities. Repair, remediation, and preventative or mitigating actions may require significant capital and operating expenditures.

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

We are also subject to the requirements of the Occupational Safety and Health Administration (OSHA) and other federal and state agencies that address employee health and safety.  In general, we believe current expenditures are addressing the OSHA requirements and protecting the health and safety of our employees.  Based on new regulatory developments, we may increase expenditures in the future to comply with higher industry and regulatory safety standards.  However, such increases in our expenditures, and the extent to which they might be offset, cannot be estimated at this time.


State and Local Regulation


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


Marine Operations


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


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


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


The Merchant Marine Act of 1936 is a federal law that provides the U.S. Secretary of Transportation, upon proclamation by the U.S. President of a national emergency or a threat to the national security, the U.S. Secretary of Transportation the authority to requisition or purchase any vessel or other watercraft owned by U.S. citizens (including us, provided that we are considered a U.S. citizen for this purpose). If one of our vessels were purchased or requisitioned by the U.S. government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire.

However, we would not be entitled to compensation for any consequential damages suffered as a result of such purchase or requisition.


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Derivatives Regulation

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

Environmental Matters and Safety Regulation


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

Environmental and human health and safety laws and regulations are subject to change. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, wildlife, natural resources and human health. There can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows.


In accordance with GAAP, we accruerecord liabilities for environmental matters when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or previously disposed. We have accrued liabilities for estimable and probable environmental remediation obligations at various sites, including multi-party sites where the EPA, or similar state or Canadian agency has identified us as one of the potentially responsible parties. The involvement of other financially responsible companies at these multi-party sites could increase or mitigate our actual joint and several liability exposures.

We believe that the ultimate resolution of these environmental matters will not have a material adverse effect on our business, financial position, results of operations or cash flows. However, it is possible that our ultimate liability with respect to these environmental matters could exceed the amounts accrued in an amount that could be material to our business, financial position, results of operations or cash flows in any particular reporting period. We have accrued an environmental reserve in the amount of $279 million as of December 31, 2017. Our aggregate reserve estimate ranges in value from approximately $279 millionto approximately $443 million, and we recorded our liability equal to the low end of the range, as we did not identify any amounts within the range as a better estimate of the liability. For additional information related to pending environmental matters, including our accruals of environmental reserves, see Note 1718 “Litigation Environmental and Other Contingencies”Environmental” to our consolidated financial statements.


Hazardous and Non-Hazardous Waste


We generate both hazardous and non-hazardous wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act (RCRA) and comparable state and Canadian statutes. From time to time, the EPA and state and Canadian regulators consider the adoption of stricter disposalRCRA establishes standards for non‑hazardous waste. Furthermore, it is possible that somethe generation, treatment, storage, transport, and disposal of solid wastes, that are currently classified as non-hazardous, which could include wastes currently generated during our pipeline or liquids or bulk terminal operations, may in the future be designated asincluding hazardous wastes. Hazardous wastes are subject to more rigorous and costly handling and disposal requirements than non-hazardous wastes. Such changes in the regulations may result in additional capital expenditures or operating expenses for us.


Superfund


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

materials that may fall within the definition of hazardous substance. By operation of law, ifsuch definition. If we are determined to be a potentially responsible person by operation of law under CERCLA, we may be responsible under CERCLA for all or part of the costs required to clean upevaluate and remediate sites at which such materials are present, in addition to compensation for natural resource damages, if any.


Clean Air Act


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


Clean Water Act


Our operations can result in the discharge of pollutants. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and controls regarding the discharge of fills
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and pollutants into waters of the U.S. The discharge of fills and pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by applicable federal state or Canadianstate authorities. The Oil Pollution Act was enacted in 1990 and amends provisions of the Clean Water Act pertaining to prevention of and response to oil spills. Spill prevention, control and countermeasure requirements of the Clean Water Act and some state and Canadian laws require containment and similar structures to help prevent contamination of navigable waters in the event of an overflow or release of oil.


EPA Revisions to Ozone National Ambient Air Quality Standard (NAAQS)Standards


As required by the Clean Air Act, the EPA establishes National Ambient Air Quality Standards (NAAQS) for how much pollution is permissiblesetting acceptable levels of common pollutants such as ozone, particulate matter and sulfur dioxide. States then the states haveare required to adopt rules soState Implementation Plans (SIPs) ensuring their air quality meets the applicable NAAQS. In October 2015,The EPA reviews these SIPs to ensure they comply with the NAAQS and other provisions of the Clean Air Act, including the Good Neighbor provision. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Expenditures—Impact of Regulation,” and Note 18 “Litigation and Environmental—Environmental Matters—Challenge to Federal “Good Neighbor Plan,” to our consolidated financial statements.
For ground level ozone, the EPA published a rule lowering the ground level ozonein October 2015 that lowered NAAQS from 75 ppbparts per billion (ppb) to a more stringent 70 ppb standard. This change triggerstriggered a process under which the EPA will designatedesignated the areas of the country that are in or out of attainmentcompliance with the new2015 standards. In December 2020, the EPA completed a review of the ozone NAAQS standard.  Then, certain states will have to adopt more stringent air quality regulations to meetand published a rule retaining the 2015 standards.

State rules implementing the NAAQS, standard.  These new state rules, which are expectedincluding those existing or proposed in 2020 or 2021, will likelyColorado and New Mexico, require the installation of more stringent air pollution controls on newly installed equipment and possibly require the retrofitting of existing KMI facilities with air pollution controls. Given the nationwide implications of the new rule, it is expected that itThese rules will have financial impacts to our Natural Gas Pipelines business segment. Future state or federal rules relating to the EPA’s establishment of NAAQS for each of ourozone or other criteria air pollutants could have financial impacts on multiple business units.


Climate Change


Studies have suggested thatDue to concern over climate change, numerous proposals to monitor and limit emissions of certain gases, commonly referredGHGs have been made and are likely to as greenhouse gases, maycontinue to be contributing to warmingmade at the federal, state and local levels of the Earth’s atmosphere.government. Methane, a primary component of natural gas, and CO2, which is naturally occurring and also a byproduct of the burning of natural gas, are examples of greenhouse gases.GHGs. Various laws and regulations exist or are under development that seek to regulate the emission of such greenhouse gases,GHGs, including the EPA programs to control greenhouse gasrequiring the reduction, monitoring, and reporting of GHG emissions levels and state actions to develop statewide or regional programs. The U.S. Congress has in the past considered legislation to reduce emissions of greenhouse gases.GHGs.


Beginning in December 2009, the EPA published several findings and rulemakings under the Clean Air Act requiring the permitting and reporting of certain greenhouse gasesGHGs, including CO2 and methane. OurCertain of our facilities are subject to these requirements. Operational and/or regulatoryphysical changes to existing facilities could require additionalthose facilities to comply with greenhousethese requirements. In addition, recent EPA regulatory changes require many existing oil and natural gas facilities to reduce GHG emissions, reporting and permitting requirements. For example,PHMSA has proposed regulations requiring expansive leak detection and repair requirements applicable to natural gas facilities. See Item 1A. “Risk Factors—Risks Related to Regulation—New laws, policies, regulations, rulemaking and oversight, as well as changes to those currently in August 2016, the EPA rule regarding the “Oileffect, could adversely impact our earnings, cash flows and Natural Gas Sector: Emission Standards for Newoperations.” and Modified Sources,” otherwise known as the Proposed New Source Performance Standard (NSPS) Part OOOOa Rule, became effective. This rule is the first federal rule under the Clean Air Act to regulate methane as a pollutant and impose additional pollution control and work practice“ —Increased regulatory requirements on applicable KMI facilities.

On October 23, 2015, the EPA published as a final rule the Clean Power Plan, which sets interim and final CO2 emission performance rates for power generating units that fire coal, oil or natural gas. The final rule is the focus of legislative discussion in the U.S. Congress and litigation in federal court. On February 10, 2016, the U.S. Supreme Court stayed the final rule, effectively suspending the duty to comply with the rule until certain legal challenges are resolved.  In October 2017, EPA proposed to repeal the Clean Power Plan. The ultimate resolution of the final rule’s validity remains uncertain.  While we do not operate power plants that would be subjectrelating to the Clean Power Plan final rule, it remains unclear what effect the final rule, if it comes into force, might have on the anticipated demand for natural gas, including natural gas that we gather, process, storesafety and transport.integrity of our pipelines may require us to incur significant capital and operating expense outlays to comply.”



At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already
have begun implementing legal measures to reduce emissions of greenhouse gases, primarilyGHGs, such as through the planned developmentestablishment of emission inventoriesGHG reduction targets or regional greenhouse gas “cap and trade”GHG “cap-and-trade” programs. Although many of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions, such as electric power plants, itIt is possible that sources such as our gas-firedgas-fueled compressors and processing plants could become subject to relatedthese state GHG reduction regulations. Various states are also proposing or have implemented more strictstricter regulations for greenhouse gasesreporting, monitoring or reducing GHGs that go beyond the requirements of the EPA. Depending on the particular program, weCompliance with state rules could be requiredrequire additional expenditures, above and beyond those spent to conduct monitoring, do additional emissions reporting and/or purchasecomply with EPA GHG rules for new and surrender emission allowances.existing sources.


Because our operations, including the compressor stations and processing plants, emit various types of greenhouse gases,GHGs, primarily methane and CO2, such new legislation or regulation could increase the costs related to operating and maintaining theour facilities. Depending on the particular law, regulation or program, we or our subsidiaries couldmay be required to incur significant additional operating or capital expenditures for installingcosts to install new monitoring equipment ofor emission controls on the facilities, acquire and surrender allowances for the greenhouse gasGHG emissions, replace certain GHG-emitting devices or technologies, pay taxes related to the greenhouse gas GHG
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emissions and administer and manage a greenhouse gasmore comprehensive GHG emissions program. We are not able at this time to estimate such increased costs; however, as is the case with similarly situated entities in the industry, they could be significant to us. While we may be able to include some or all of such increased costs in the rates charged by our or our subsidiaries’ pipelines, such recovery of costs is uncertain in all cases is uncertain and may depend on events beyond theirour control, including the outcome of future rate proceedings before the FERC or other regulatory bodies, and the provisions of any final legislation or other regulations. Any

Because the combustion of the foregoing could have an adverse effect on our business, financial position, results of operations and prospects.

Some climatic models indicate that global warming is likely to result in rising sea levels, increased intensity of hurricanes and tropical storms, and increased frequency of extreme precipitation and flooding. We may experience increased insurance premiums and deductibles, or a decrease in available coverage, for our assets in areas subject to severe weather. To the extent these phenomena occur, they could damage our physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone regions. However, the timing and location of these climate change impacts is not known with any certainty and, in any event, these impacts are expected to manifest themselves over a long time horizon. Thus, we are not in a position to say whether the physical impacts of climate change pose a material risk to our business, financial position, results of operations or cash flows.

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


DepartmentPipeline Safety Regulation

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

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


Employee Health and Safety Regulations

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

Security Regulations

High-Risk Facilities

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


Cybersecurity
Other

In response to ongoing cybersecurity threats affecting the pipeline industry, the DHS’s Transportation Security Administration, or TSA, has issued a series of security directives setting forth specific elements that owners and operators of certain “critical” pipelines must include in their cybersecurity planning and their reporting of any incidents. These security directives require, among other things, that identified pipeline owners comply with mandatory reporting measures; designate a
Employees
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cybersecurity coordinator; provide vulnerability assessments; ensure compliance with certain cybersecurity requirements; establish and implement a TSA-approved Cybersecurity Implementation Plan; develop and maintain a Cybersecurity Incident Response Plan (CIRP), which shall include individuals identified as active participants in CIRP exercises, and annually test at least two CIRP objectives; and establish a Cybersecurity Assessment Plan (CAP), and annually submit an updated CAP to TSA for review and approval, which shall include a schedule for assessing and auditing specific cybersecurity measures for effectiveness.

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

Human Capital

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

We employed 10,89710,891 full-time peoplepersonnel at December 31, 2017,2023, including approximately 801891 full-time hourly personnel at certain terminals and pipelines covered by collective bargaining agreements that expire between 20182024 and 2022.2028. We consider relations with our employees to be good.



MostWe value the safety of our workforce and integrate a culture of safety, emergency preparedness and environmental responsibility through our operations management system (OMS). Our OMS conforms to common industry standards and establishes a framework that helps us (i) provide employees and contractors with a safe work environment; (ii) comply with laws, rules, regulations, policies, and procedures; and (iii) identify opportunities to improve. Although our ultimate target is zero incidents, we also have three non-zero employee safety performance targets as follows:
Non-zero employee safety performance target2023 Company-wide TRIR
Outperform the annual industry average total recordable incident rate (TRIR)0.8
Outperform our own three-year TRIR average
Improve our company-wide employee TRIR from 1.0 in the baseline year 2019 to 0.7 by 2024

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

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

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

Our employees are employed by us and a limited numberan integral part of our subsidiariessuccess, and provide services to one or more ofwe value their career development. We support our business units. The direct costs of compensation, benefits expenses, employer taxesemployees’ ongoing career goals and development through several programs, including workforce training, tuition reimbursement,
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leadership and other employer expensesdevelopment programs. These programs help improve recruitment, development, and retention and help maximize our employees’ potential by providing an opportunity to gain skills they need to further enhance their careers.

Our compensation program is linked to long- and short-term strategic financial and operational objectives, including environmental, safety, and compliance targets. Compensation includes competitive base salaries in the markets in which we operate and competitive benefits, including retirement plans, opportunities for theseannual bonuses, and, for eligible employees, are allocated to our subsidiaries. Our human resources department provides the administrative support necessary to implement these payrolllong-term incentives and benefits services,an employee stock purchase plan.

Properties and the related administrative costs are allocated to our subsidiaries pursuant to our board-approved expense allocation policy. The effect of these arrangements is that each business unit bears the direct compensation and employee benefits costs of its assigned or partially assigned employees, as the case may be, while also bearing its allocable share of administrative costs.Rights-of-Way

Properties


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


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


(d) Financial Information about Geographic Areas

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

(e) Available Information


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

Item 1A.  Risk Factors.


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


Risks Related to Operating our Business


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


Our pipelines, terminals and other assets and facilities, including the availability of expansion opportunities, depend in part on continued production of natural gas, crude oil and other products in the geographic areas that they serve. Without additions to crude oil and gas reserves, production will decline over time as reserves are depleted, and production costs may rise. Producers in areas served by us may not be successful in exploring for and developing additional reserves or their costs of doing so may become uneconomic. Commodity prices and tax incentives may not remain at levels that encourage producers to explore for and develop additional reserves, produce existing marginal reserves or renew transportation contracts as they expire. Our business also depends in part on the levels of demand for oil, natural gas, crude oil, NGL, refined petroleum products, CO2, coal, 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. Without additions to
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Decreases in the supply of or demand for natural gas, crude oil and gas reserves, production will decline over time as reserves are depleted, and production costs may rise. Producers may shut down production at lower product prices or higherother products could adversely impact the utilization of our assets.


production costs, especially where the existing cost of production exceeds other extraction methodologies,Economic disruptions, such as inthose which occurred during the Alberta oil sands. Producers in areas served by us may not be successful in exploring for and developing additional reserves, and our pipelines and related facilities may not be able to maintain existing volumes of throughput. Commodity prices and tax incentives may not remain at levels that encourage producers to explore for and develop additional reserves, produce existing marginal reservesCOVID-19 pandemic, or renew transportation contracts as they expire.

Trendsconditions in the business environment generally, such as declining or sustained low commodity prices, supply disruptions, or higher development costs, or high feedstock prices that adversely impact demand,production costs, could result in a slowing of supply to our pipelines, terminals and other assets. In addition,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 ana 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 products we handle. 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 these factors impactsthe foregoing supply and demand issues could negatively impact our customers shipping throughbusiness directly, as well as our pipelines or using our terminals,shippers and other customers, which in turn could negatively impact theour prospects offor new contracts for transportation, terminaling or other midstream services, or renewals of existing contracts.

Implementationcontracts or the ability of new regulationsour 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 changesother counterparties could have an adverse impact on us in the event they are unable to existing regulations affecting the energy industry could reduce production of and/or demandpay us for the products or services we handle, increase our costs and have a material adverse effect on our results of operations and financial condition. 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 CO2 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.
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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 CO2 business segment’s proved reserves, certain assets in certain midstream businesses within our Natural Gas Pipelines business segment, and certain assets within our Products Pipelines business segment. For example, following the commodity price declines we experienced due to COVID-19 during the first half of 2020, we recorded a combined $1.95 billion of non-cash impairments associated with our Natural Gas Pipelines Non-Regulated and CO2 reporting units, primarily for impairments of goodwill and assets owned in these businesses.

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

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

There are a variety of hazards and operating risks inherent to the transportation and storage of the products we handle, such as leaks; releases; the breakdown, underperformance or failure of equipment, facilities, information systems or processes; damage to our pipelines caused by 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 on
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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 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 hedging
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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 14 “Risk Management” to our consolidated financial statements.

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

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

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

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

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

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

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 construction on expansion and new-build projects may be inhibited by difficulties in obtaining or our inability to obtain, permits and rights-of-way, as well as public opposition, increases in costs of construction materials, cost overruns, inclement weather and other delays. If we pursue projects through joint ventures with others, we will share control of and any benefits from those projects.


We regularly undertake major construction projects to expand our existing assets and to construct new assets. New growth projects generally will be subject to, among other things, the receipt of regulatory approvals, feasibility and cost analyses, funding availability and industry, market and demand conditions, and environmental justice considerations. A variety of factors outside of our control, such as difficulties in obtaining permitsrights-of-way and rights-of-waypermits or other regulatory approvals, have caused, and may continue to cause, delays in or cancellations of our construction projects. TheseRegulatory 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 CO2. Such factors can be exacerbated by public opposition to our projects. See “—We are subject to reputational risks and risks relating to public opinion.” Inclement weather, natural disasters and delays in performance by third-party contractors have also resulted in, and may continue to result in, increased costs or delays in construction. In addition, we may experience increasing costs for construction materials. Significant increases in costs of construction materials, cost overruns or delays, or our inability to obtain a required permit or right-of-way, could have a material adverse effect on our return on investment, results of operations and cash flows, and could result in project cancellations or limit our ability to pursue other growth opportunities.


For example,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 ability to continue and complete construction onown or our views of the TMEP may be inhibited, delayed or stopped by a varietyinterests of factors (some ofthe venture which may be outside of our control), including without limitation, inabilities to overcome challenges posed by or related to regulatory approvals by federal, provincial or municipal governments, difficulty in obtaining, or inability to obtain, permits (including those that are required prior to construction such as the permits required under the Species at Risk Act), land agreements, public opposition, blockades, legal and regulatory proceedings (including judicial reviews, injunctions, detailed route hearings and land acquisition processes), delays to ancillary projects that are required for the TMEP (including, with respect to power lines and power supply), increased costs and/or cost overruns and inclement weather or significant weather-related events.

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

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 with new
transportation or storage options, this could result in unused capacity on our pipelines and in our terminals. If pipeline capacity
remains unsubscribed, our ability to re-contract for expiring capacity at favorable ratesoperational delays or otherwise retain existing customers
could be impaired. 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.

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

Economic conditions worldwide have from time to time contributed to slowdowns in several industries, including the oil
and gas industry, the steel industry, the coal industry and in specific segments and markets in which we operate, resulting in
reduced demand and increased price competition for our products and services. Our operating results in one or more
geographic regions also may be affected by uncertain or changing economic conditions within that region. Volatility in
commodity prices or changes in markets for a given commodity might also have a negative impact on many of our customers,

impasses, which in turn could have a negative impact on their ability to meet their obligations to us. See “—Financial distress
experienced byaffect the financial expectations of and 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 will have a negative impact on our operating results and cash flow. See “—The volatility of oil and natural gas prices could have a material adverse effect on our CO2 business segment and businesses within our Natural Gas Pipeline and Products Pipelines business segments.”

If global economic and market conditions (including volatility in commodity markets), or economic conditions in the U.S.
or 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. Some of these counterparties may be highly leveraged and subject
to their own operating, market and regulatory risks, and some are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness.

In 2015 and 2016, several of our counterparties defaulted on their obligations to us, and some have filed for bankruptcy
protection. For more information regarding the impact to our operating results from customer bankruptcies, see Item 7
“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Segment Earnings Results—Terminals.” We cannot provide any assurance that other financially distressed counterparties will not also
default on their obligations to us or file for bankruptcy protection. If a counterparty files for bankruptcy protection, we likely
would be unable to collect all, or even a significant portion, of amounts that they owe to us. Additional counterparty defaults
and bankruptcy filings could have a material adverse effect on our business, financial position, results of operations or cash
flows. Furthermore, in the case of financially distressed customers, such events might force such customers to reduce or curtail
their future use of our products and services, which could have a material adverse effect on our 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
integrating new businesses and properties, and we may be unable to achieve theexpected benefits we expect from any future
acquisitions.

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

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

We do not own substantiallySubstantially all of the land on which our pipelines are located.located is owned by third parties. If we are unable to procure and maintain access to land owned by third parties, our revenue and operating costs, and our ability to complete construction projects, could be adversely affected.


We must obtain and maintain the rights to construct and operate pipelines on other owners’ land, including private landowners, railroads, public utilities and others. While our interstate natural gas pipelines in the U.S. have federal eminent domain authority, the availability of eminent domain authority for our other pipelines varies from state to state depending upon the type of pipeline—petroleum liquids, natural gas, CO2, or crude oil—and the laws of the particular state. We likewise must obtain approval from various governmental entities to construct and operate our pipelines in Canada, particularly for the TMEP. In any case, we must compensate landowners for the use of their property, and in eminent domain actions, such compensation may be determined by a court. If we are unable to obtain rights-of-way on acceptable terms, our ability to complete

construction projects on time, on budget, or at all, could be adversely affected. In addition, we are subject to the possibility of increased costs under our right-of-wayrights-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 ana substantial increase in our costs.


Commodity transportationThe acquisition of additional businesses and storage activities involve numerous risksassets 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 may result in accidentswe will be able to find complementary acquisition targets or otherwise adversely affect our operations.

There are a variety of hazards and operating risks inherentcomplete such acquisitions, or achieve the desired results from any acquisitions we do complete. Any acquired businesses or assets will be subject to transportation and storagemany of the productssame risks as our existing businesses and may not achieve the levels of performance that we handle, such as leaks, releases, explosions, mechanical problemsanticipate.

We may not realize anticipated operating advantages and damage caused by third parties. Additionalcost savings. Integration of acquired businesses or assets involves a number of risks, to vessels include adverse sea conditions, capsizing, grounding and navigation errors. These risks could result in serious injury andincluding (i) the loss of human life, significant damagekey customers of the acquired business; (ii) demands on management related to property and natural resources, environmental pollution and impairmentthe increase in our size; (iii) the diversion of operations, anymanagement’s attention from the management of which also could resultdaily operations; (iv) difficulties in substantial financial losses, negatively impact our reputation and increase public opposition to our expansionimplementing or new build projects. For pipeline and storage assets located near populated areas, including residential areas, commercial business centers, industrial sitesunanticipated costs of accounting, budgeting, reporting, internal controls and other public gathering areas,systems; and (v) difficulties in the levelretention and assimilation of damage resulting from these risksnecessary employees.

Difficulties in integration may be greater. Incidentsmagnified 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 cause an interruption of service, such as when unrelated third party construction damages a pipeline or a newly completed expansion experiences a weld failure, may negatively impactwe hoped to achieve after these acquisitions, which would harm our revenues and cash flows while the affected asset is temporarily out of service. In addition, losses in excess of our insurance coverage could have a material adverse effect on our business, financial condition and results of operations.

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

The revenues, cash flows, profitability and future growth of some of our businesses depend to a large degree on prevailing oil, NGL and natural gas prices. Our CO2 business segment (and the carrying value of its oil, NGL and natural gas producing properties) and certain midstream businesses within our Natural Gas Pipelines segment depend to a large degree, and certain businesses within our Product Pipelines segment depend to a lesser degree, on prevailing oil, NGL and natural gas prices. For 2018, we estimate that every $1 change in the average WTI crude oil price per barrel would impact our DCF by approximately $7 million and each $0.10 per MMBtu change in the average price of natural gas would impact DCF by approximately $1 million.

Prices for oil, NGL and natural gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for 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) the condition of the U.S. economy; (iii) the activities of the Organization of Petroleum Exporting Countries; (iv) governmental regulation; (v) political instability in the Middle East and elsewhere; (vi) the foreign supply of and demand for oil and natural gas; (vii) the price of foreign imports; and (viii) the availability 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.”

A sharp decline in the prices of oil, NGL or natural gas, or a prolonged unfavorable price environment, would result in a commensurate reduction in our revenues, income and cash flows from our businesses that produce, process, or purchase and sell oil, NGL, or natural gas, and could have a material adverse effect on the carrying value of our CO2 business segment’s proved reserves. If prices fall substantially or remain low for a sustained period and we are not sufficiently protected through hedging arrangements, we may be unable to realize a profit from these businesses and would operate at a loss.

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



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.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 CO2 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.


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

The business of developingDeveloping and operating oil and gas properties involves a high degree of business and financial risk that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Acquisition and development decisions generally are based onrelated 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 including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions, may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable. A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of oil and/or gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances.

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

We engage in hedging arrangements to reduce our exposure to fluctuations in the prices of oil, NGL and natural gas. 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 oil and natural gas.

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

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

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

Our business is dependent upon our operational systems to process a large amount of data and complex transactions. The
various uses of these IT systems, networks and services include, but are not limited to, controlling our pipelines and terminals
with industrial control systems, collecting and storing information and data, processing transactions, and handling other
processing necessary to manage our business.

If any of our systems are damaged, fail to function properly or otherwise become unavailable, we may incur substantial
costs to repair or replace them and may 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 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 may not be successful in preventing these events from occurring, and any network and information
systems-related events could require us to expend significant resources to remedy such event. Although we believe that we have robust information security procedures and other safeguards in place, we may be required to expend additional resources to continue to enhance our information security measures and/or to investigate and remediate information security vulnerabilities.

Terrorist attacks, including cyber sabotage, or the threat of such attacks, may adversely affect our business or harm our business reputation.

The U.S. government has issued public warnings that indicate that pipelines and other infrastructure assets might be specific targets of terrorist organizations or “cyber sabotage” events. These potential targets might include our pipeline systems, terminals, processing plants or operating systems. The occurrence of a terrorist attack could cause a substantial decrease in revenues and cash flows, increased costs to respond or other financial loss, damage to our reputation, increased regulation or litigation or inaccurate information reported from our operations. There is no assurance that adequate cyber sabotage and terrorism insurance will be available at rates we believe are reasonable in the near future. These developments may subject our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations and financial condition or harm our business reputation.

Hurricanes, earthquakes and other natural disasters 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 and other natural disasters. These natural disasters could potentially damage or destroy our assets and disrupt the supply of the products we transport. In the third quarter of 2017, Hurricane Harvey caused
disruptions in our operations and, as of December 31, 2017, we had incurred $27 million in repair costs to our assets near the Texas Gulf Coast. For more information regarding the impact of Hurricane Harvey on our assets and operating results, see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Natural disasters can similarly affect the facilities of our customers. In either case, losses could exceed our insurance coverage and our business, financial condition and results of operations could be adversely affected, perhaps materially.


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


Our success depends in part on the performance of and our ability to attract, retain and effectively manage the succession of a skilled executive team. We depend on our executive officers to develop and execute our business strategy. If we are not successful in retaining our executive officers, or replacing them, our business, financial condition or results of operations and management requirecould 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 allocated costs to retain and recruit these professionals.


The increased financial reporting and other obligations of management resulting from KML’s obligations as a public company may divert management’s attention away from other business operations.

KML, in which we own an approximate 70% interest, completed its IPO in Canada in May of 2017. Certain of our officers and directors also serve as officers and directors of KML, and we provide financial reporting support and other services as requested by KML and its controlled affiliates pursuant to a Services Agreement. The increased obligations associated with providing support to KML as a public company may divert our management’s attention from other business concerns and may adversely affect our business, financial condition and results of operations. We are subject to financial reporting and other obligations that place significant demands on our management, administrative, operational, legal, internal audit and accounting resources. The demands on our personnel will be intensified as they comply with the additional obligations applicable to KML.


If we are unable to retain our executive chairman, chief executive officer or other executive officers, our ability to execute our business strategy, including our growth strategy, may be hindered.

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

Our Kinder Morgan Canada and Terminals segments are subject to U.S. dollar/Canadian dollar exchange rate fluctuations.

We are a U.S. dollar reporting company. As a result of the operations of our Kinder Morgan Canada and Terminals
business segments, a portion of our consolidated assets, liabilities, revenues, cash flows and expenses are denominated in Canadian dollars. Fluctuations in the exchange rate between U.S. and Canadian dollars could expose us to reductions in the U.S. dollar value of our earnings and cash flows and a reduction in our stockholders’ equity under applicable accounting rules.

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, 2017,2023, we had approximately $36.9$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 earnings before interest, taxes, depreciation and amortization, or 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 increased costsadverse 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)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 and reduce our cash flows.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.


KMLOur and its subsidiaries are not part of the cross guarantee and are rated separately by credit rating agencies. However, because of our approximate 70% ownership interest in KML, wecustomers’ access to capital could be indirectly affected if KML experiences material adverse changes in its credit ratings orby evolving financial institutions’ policies concerning businesses linked to fossil fuels.

Our and our customers’ access to capital.

Acquisitionscapital 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 capital expenditures may require access to external capital. Limitations onprojects, and consequently could both indirectly affect demand for our access to external financing sources could impairservices and directly affect our ability to grow.fund construction or other capital projects.

We have limited amounts of internally generated cash flows to fund acquisitions and growth capital expenditures. We may have to rely on external financing sources, including commercial borrowings and issuances of debt and equity securities, to fund our acquisitions and growth capital expenditures. Limitations on our access to external financing sources, whether due to tightened capital markets, more expensive capital or otherwise, could impair our ability to execute our growth strategy.


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


As of December 31, 2017,2023, approximately $10.4$8.3 billion of our approximately $36.9$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. ShouldIn 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 thisvariable-rate debt would increase,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 “Quantitative7A. “Quantitative and Qualitative Disclosures About Market Risk-InterestRisk—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 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 expected cash dividends on our common stock and on our preferred stock (or depositary shares). 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 we elect 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 address properly our business prospects, our business could be harmed.

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

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

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


Our assets and operations are subject to extensive regulation and oversight by federal, state provincial and local regulatory authorities. Legislative changes, as well as regulatory actions taken by these agencies,authorities, have the potential to adversely affect our profitability. In addition,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 degreesize 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 uncertainty is created by the current U.S. presidential administration because it remains unclear specifically what the current administration may do with respect to future policies and regulations thatauthorities may affect us. 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 businessbusiness. In addition to environmental and extendspipeline safety matters, we are subject to regulations extending to such matters as (i) federal, state provincial and local taxation; (ii) rates (which include tax, reservation, commodity, surcharges, fuel and gas lost and unaccounted for), operating terms and conditions of service; (iii) the types of services we may offer to our customers; (iv) the contracts for service entered into with our customers; (v) the certification and construction of new facilities; (vi) the 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.

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Should we fail to comply with any applicable statutes, rules, regulations, and orders of such regulatory authorities, we could be subject to substantial penalties and fines and potential loss of government contracts. Furthermore, new laws, regulations or policy changes sometimes arise from unexpected sources. New laws or regulations, unexpected policy changes or different interpretations of existing laws or regulations, including the 2017 Tax Reform,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 “Business2. “Business and Properties—(c) Narrative Description of Business—Industry Regulation.”

The FERC, the CPUC, or the NEB may establish pipeline tariff rates that have a negative impact on us. In addition, the FERC, the CPUC, the NEB, 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, the CPUC, or the NEB 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. Regulators and shippers on our pipelines have rights to challenge, and have challenged, the rates we charge under certain circumstances prescribed by applicable regulations. Some shippers on our pipelines have filed complaints with the regulators that seek substantial refunds for alleged overcharges during the years in question and prospective reductions in the tariff rates. Further, the FERC may continue to initiate investigations to determine whether interstate natural gas pipelines have over-collected on rates charged to shippers. We may face challenges, similar to those described in Note 17 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements, to the rates we charge on our pipelines. In addition, following the 2017 Tax Reform, which reduced the corporate tax rate from 35% to 21%, various industry groups have petitioned the FERC to consider action with respect to tax recovery in existing jurisdictional rates. Any successful challenge to our rates could materially adversely affect our future earnings, cash flows and financial condition.



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


Our operations are subject to extensive federal, state provincial 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 or provincial 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 influenceharm our business, financial position, results of operations and prospects. For example, if an accidentala leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines, shipping vessels or storage or other facilities, we may experience significant operational disruptions, and we may have to pay a significant amount to clean up or otherwise respond to the leak, release or spill, pay government penalties, address natural resource damage, compensate for human exposure or property damage, install costly pollution control equipment or undertake a combination of these and other measures. The resulting costs and liabilities could materially and negatively affect our earnings and cash flows. In addition, emission controls required under the Federal Clean Air Act and other similar federal, state and provincial laws could require significant capital expenditures at our facilities.


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


Further, we cannot ensure that such existingEnvironmental and health and safety laws and regulations will notare subject to change. The long-term trend in environmental regulation has been to place more restrictions and limitations on activities that may be revised or that newperceived 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 orand regulations will not be adopted or become applicableare subject to us.periodic review and amendment, which could result in more stringent emission control requirements obligating us to make significant capital expenditures at our facilities. Several state and federal agencies have also increased their daily and maximum penalty amounts in recent years. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised

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


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


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



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


Climate changeClimate-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 greenhouse gasesGHGs such as methane and CO2, including the EPA programs to control greenhouse gasGHG 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 greenhouse gasGHG emissions in the U.S. from sources such as our larger natural gas compressor stations, fractionated NGL, and production of naturally occurring CO2 (for example, from our McElmo Dome CO2 field), even when such production is not emitted to the atmosphere. Proposed approaches to further regulate greenhouse gasaddress GHG emissions include establishing greenhouseGHG “cap-and-trade” programs, a fee on methane emissions from petroleum and natural gas “cap and trade” programs,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 “Business2. “Business and Properties—(c) Narrative Description of Business-EnvironmentalBusiness—Environmental Matters—Climate Change.”


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Adoption of any such laws or regulations could increase our costs to operate and maintain our facilities, andexpand existing facilities or construct new facilities. We could require usbe required to install new emission controls on our facilities, acquire allowances for our greenhouse gasGHG emissions, pay taxes related to our greenhouse gasGHG emissions and administer and manage a greenhouse gasGHG 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 greenhouse gases,emissions of GHGs, or restrictions on their use, which in turn could adversely affect demand for our products and services.

Finally, some climatic models indicate that global warming is likely to result in rising sea levels and increased frequency and severity of weather events, which may lead to higher insurance costs, or a decrease in available coverage, for our assets in areas See also “—Business Risks—We are subject to severe weather. Toreputational 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 extent these phenomena occur, they could damage our physical assets, especially operations locatedSEC proposed new climate-related disclosure rules, which if adopted as proposed, would require significant new climate-related disclosure in low-lying areas near coastsSEC filings, including certain climate-related metrics and river banks,GHG emissions data, and facilities situated in hurricane-prone regions.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 hydraulic fracturing,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, in whichincluding lands that are federally managed. Policy and regulatory initiatives or legislation by Congress may decrease access to federally managed lands or increase the useregulatory 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 hydraulic fracturing is prevalent. Oilapplications 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 numerousincreasing regulation at the federal, state provincial and local laws and regulations relating to environmental quality and pollution control. The oil and gas industry is increasingly relying on supplies of hydrocarbons from unconventional sources, such as shale, tight sands and coal bed methane. The extraction of hydrocarbons from these sources frequently requires hydraulic fracturing. Hydraulic fracturing involves the pressurized injection of water, sand, and chemicals into the geologic formation to stimulate gas production and is a commonly used stimulation process employed by oil and gas exploration and production operators in the completion of certain oil and gas wells. Therelevels. For example, there have been initiatives at the federal and state levels to regulate or otherwise restrict the use of certain hydraulic fracturing. 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 placing restrictions on hydraulic fracturingrestricting 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.

In addition, many states are promulgating stricter requirements not only for wells but also compressor stations and other facilities in the oil and gas industry sector. These laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation. Specifically, these activities are subject to laws and regulations regarding the acquisition of permits before drilling, restrictions on drilling activities and location, emissions into the environment, water discharges, transportation of hazardous materials, and storage and disposition of wastes. In addition,

legislation has been enacted that requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities. These laws and regulations may also adversely affect our own oil and gas development and production activities.

Derivatives regulation could have an adverse effect on our ability to hedge risks associated with our business.

The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the OTC derivatives market and entities that participate in that market. In December 2016, the CFTC re-proposed new rules pursuant to the Dodd-Frank Act that would institute broad new aggregate position limits for OTC swaps and futures and options traded on regulated exchanges. As the law favors exchange trading and clearing, the Dodd-Frank Act also may require us to move certain derivatives transactions to exchanges where no trade credit is provided. The Dodd-Frank Act, related regulations and the reduction in competition due to derivatives industry consolidation have (i) increased the cost of derivative contracts (including those requirements to post collateral, which could adversely affect our available liquidity); (ii) reduced the availability of derivatives to protect against risks we encounter; and (iii) reduced the liquidity of energy related derivatives.

If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Any of these consequences could have a material adverse effect on our financial condition and results of operations.


The Jones Act includes restrictions on ownership by non-U.S. citizens of our U.S. point to pointpoint-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 mannedcrewed by predominately U.S. crews.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.


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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 1B.  Unresolved Staff Comments.

None.

Item 1C.  Cybersecurity.

Cybersecurity Risk Management and Strategy

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

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

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

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

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

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

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

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

Vulnerability Assessments and Penetration Testing

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

Government and Industry Group Engagement

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

Employee Training

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

Cybersecurity Governance Structures

Management’s Role in Managing Cybersecurity Risk

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

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

The Board’s Role in Cybersecurity Risk Oversight

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

Item 3.  Legal Proceedings.

See Note 1718 “Litigation Environmental and Other Contingencies”Environmental” to our consolidated financial statements.


Item 4.  Mine Safety Disclosures.

We no longerExcept for one terminal facility that is in temporary idle status with the Mine Safety and Health Administration, we do not own or operate mines for which reporting requirements apply under the mine safety disclosure requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank), except for one terminal that is in temporary idle status with the Mine Safety and Health Administration.Act. We have not received any specified health and safety violations, orders or citations, related assessments or legal actions, mining-related fatalities, or similar events requiring disclosure pursuant to the mine safety disclosure requirements of the Dodd-Frank Act for the year ended December 31, 2017.2023.



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PART II


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

Our Class P common stock is listed for trading on the NYSE under the symbol “KMI.” The high and low sale prices per Class P share as reported on the NYSE and the dividends declared per share by period for 2017, 2016 and 2015, are provided below. 
 Price Range 
Declared Cash
Dividends(a)
 Low High 
2017     
First Quarter$20.71
 $23.01
 $0.125
Second Quarter18.31
 21.92
 0.125
Third Quarter18.23
 21.25
 0.125
Fourth Quarter16.68
 19.17
 0.125
2016     
First Quarter$11.20
 $19.32
 $0.125
Second Quarter16.63
 19.40
 0.125
Third Quarter17.95
 23.20
 0.125
Fourth Quarter19.43
 23.36
 0.125
2015     
First Quarter$39.45
 $42.93
 $0.48
Second Quarter38.33
 44.71
 0.49
Third Quarter25.81
 38.58
 0.51
Fourth Quarter14.22
 32.89
 0.125
_______
(a)Dividend information is for dividends declared with respect to that quarter.  Generally, our declared dividends for our Class P common stock are paid on or about the 15th day of each February, May, August and November. 


As of February 8, 2018,15, 2024, we had 11,8679,540 holders of record of our Class P common stock, which does not include beneficial owners whose shares are held by a nominee, such as a broker or bank.


For information on our equity compensation plans, see Note 10 “Share-based Compensation and Employee Benefits—Benefits—Share-based Compensation” to our consolidated financial statements.

The warrant repurchase program, dated June 12, 2015, which authorized us to repurchase up to $100 million of warrants, expired along with the warrants on May 25, 2017.
Our Purchases of Our Class P Shares
Period Total number of securities purchased(a) Average price paid per security Total number of securities purchased as part of publicly announced plans(a) Maximum number (or approximate dollar value) of securities that may yet be purchased under the plans or programs
December 1 to December 31, 2017 14,038,121
 $17.80
 14,038,121
 $1,750,009,426
         
        $1,750,009,426
_______
(a)On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. After repurchase, the shares are cancelled and no longer outstanding.



For information about our expectations regarding dividends, please see Item 6.  Selected Financial Data.
The following table sets forth, for the periods and at the dates indicated, our summary historical financial data.  The table is derived from our consolidated financial statements and notes thereto, and should be read in conjunction with those audited financial statements.  See also Item 7 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations”Operations—General—2024 Dividends and Discretionary Capital.”

Our Purchases of Our Class P Stock
(During the quarter ended December 31, 2023)
Settlement PeriodTotal number of securities purchased(a)Average price paid per security(b)Total number of securities purchased as part of publicly announced plans(a)Approximate dollar value of securities that may yet be purchased under the plans or programs(a)
October 1 to October 31, 20235,706,428 $16.41 5,706,428 $1,574,253,794 
November 1 to November 30, 20232,386,705 16.26 2,386,705 1,535,434,677 
December 1 to December 31, 2023— — — 1,535,434,677 
Total8,093,133 $16.37 8,093,133 $1,535,434,677 
(a)On July 19, 2017, our Board approved a $2 billion common share buy-back program. On January 18, 2023, our Board approved an increase in this reportour share repurchase authorization to $3 billion from $2 billion. After repurchase, the shares are canceled and no longer outstanding.
(b)Amount includes any commission or other costs to repurchase shares.
Subsequent to December 31, 2023 and through February 16, 2024, we repurchased less than 1 million shares at an average price of $16.50 for more information.$7 million.
Item 6.  [Reserved]

Five-Year Review
Kinder Morgan, Inc. and Subsidiaries
 As of or for the Year Ended December 31,
 2017 2016 2015 2014 2013
 (In millions, except per share amounts)
Income and Cash Flow Data:         
Revenues$13,705
 $13,058
 $14,403
 $16,226
 $14,070
Operating income3,544
 3,572
 2,447
 4,448
 3,990
Earnings from equity investments578
 497
 414
 406
 327
Income from continuing operations223
 721
 208
 2,443
 2,696
Loss from discontinued operations, net of tax—
 —
 —
 —
 (4)
Net income223
 721
 208
 2,443
 2,692
Net income attributable to Kinder Morgan, Inc.183
 708
 253
 1,026
 1,193
Net income available to common stockholders27
 552
 227
 1,026
 1,193
Class P Shares         
Basic and Diluted Earnings Per Common Share From Continuing Operations$0.01
 $0.25
 $0.10
 $0.89
 $1.15
Basic Weighted Average Common Shares Outstanding2,230
 2,230
 2,187
 1,137
 1,036
Diluted Weighted Average Common Shares Outstanding2,230
 2,230
 2,193
 1,137
 1,036
          
Dividends per common share declared for the period(a)$0.50
 $0.50
 $1.605
 $1.74
 $1.60
Dividends per common share paid in the period(a)0.50
 0.50
 1.93
 1.70
 1.56
          
Balance Sheet Data (at end of period):         
Property, plant and equipment, net$40,155
 $38,705
 $40,547
 $38,564
 $35,847
Total assets79,055
 80,305
 84,104
 83,049
 75,071
Long-term debt(b)34,088
 36,205
 40,732
 38,312
 31,910
_______
(a)Dividends for the fourth quarter of each year are declared and paid during the first quarter of the following year.
(b)Excludes debt fair value adjustments.  Increases to long-term debt for debt fair value adjustments totaled $927 million, $1,149 million, $1,674 million, $1,785 million and $1,863 million as of December 31, 2017, 2016, 2015, 2014 and 2013, respectively.  

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 2. “Business and Properties—(c) Narrative Description of Business—Business Strategy;” (ii) a description of developments during 2017,2023, found in Items 1 and 2 2. “Business and Properties—(a) General Development of Business—Recent Developments;” (iii) a description of terms for services and (iii)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.1A.“Risk Factors;”

Inasmuch as the and (v) a discussion below and the other sections to which we have referred you pertain to management’s comments on financial resources, capital spending, our business strategy and the outlook for our business, such discussions contain forward-looking statements.  Theseof forward-looking statements, reflectfound 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.

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General

Acquisitions

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

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

2024 Dividends and Discretionary Capital

We expect to declare dividends of $1.15 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 beliefs, plans and objectives of management about future financial performancefor 2024 discussed above involve risks, uncertainties and assumptions, underlying management’s judgment concerning the matters discussed, and accordingly, involve estimates, assumptions, judgments and uncertainties.  Our actual results could differ materially from those discussed in the forward-looking statements.  Factors that could cause or contribute to any differences include, but are not limitedguarantees of performance.  Many of the factors that will determine these expectations are beyond our ability to those discussed belowcontrol or predict, and elsewhere in this report, particularly in Item 1A because of these uncertainties, it is advisable not to put undue reliance on any forward-looking statement.  Please read “Risk Factors” andInformation Regarding Forward-Looking Statements” at the beginning of this report in “Information Regarding Forward-Looking Statements.and Item 1A. “Risk Factors” for more information. 


GeneralCritical Accounting Estimates

Our business model, through our ownershipCritical accounting estimates and operationassumptions involve material levels of energy related assets, is builtsubjectivity and complex judgement to support two principal objectives:

helping customers by providing safe and reliable natural gas, liquids products and bulk commodity transportation, storage and distribution; and

creating long-term valueaccount for our shareholders.
To achieve these objectives, we focus on providing fee-based services to customers from a business portfolio consisting of energy-related pipelines, natural gas storage, processing and treating facilities, and bulk and liquids terminal facilities. We also produce and sell crude oil. Our reportable business segments are based on the way our management organizes our enterprise, and each of our business segments represents a component of our enterprise that engages in a separate business activity and for which discrete financial information is available.

Our reportable business segments are:

Natural Gas Pipelines—the ownership and operation of (i) major interstate and intrastate natural gas pipeline and storage systems; (ii) natural gas and crude oil gathering systems and natural gas processing and treating facilities; (iii) NGL fractionation facilities and transportation systems; and (iv) LNG facilities;

•
CO2—(i) the production, transportation and marketing of CO2 to oil fields that use CO2 as a flooding medium for recovering crude oil from mature oil fields to increase production; (ii) ownership interests in and/or operation of oil fields and gas processing plants in West Texas; and (iii) the ownership and operation of a crude oil pipeline system in West Texas;

Terminals—the ownership and/highly uncertain matters or operation of (i) liquids and bulk terminal facilities located throughout the U.S. and portions of Canada that transload and store refined petroleum products, crude oil, chemicals, and ethanol and bulk products, including petroleum coke, steel and coal; and (ii) Jones Act tankers;

Products Pipelines—the ownership and operation of refined petroleum products, NGL and crude oil and condensate pipelines that primarily deliver, among other products, gasoline, diesel and jet fuel, propane, ethane, crude oil and condensate to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities; and

Kinder Morgan Canada—the ownership and operation of the Trans Mountain pipeline system that transports crude oil and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia, Canada and the state of Washington, plus the Jet Fuel aviation turbine fuel pipeline that serves the Vancouver (Canada) International Airport.

As an energy infrastructure owner and operator in multiple facets of the various U.S. and Canadian energy industries and markets, we examine a number of variables and factors on a routine basis to evaluate our current performance and our prospects for the future. 
With respect to our interstate natural gas pipelines, related storage facilities and LNG terminals, the revenues from these assets are primarily received under contracts with terms that are fixed for various and extended periods of time.  To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate risk of reduced volumes and prices by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity.  These long-term contracts are typically structuredmatters with a fixed-fee reserving the right to transport or store natural gas and specify that we receive the majority of our fee for making the capacity available, whether or not the customer actually chooses to utilize the capacity.  Similarly, the Texas Intrastate Natural Gas Pipeline operations, currently derives approximately 76% of its sales and transport margins from long-term transport and sales contracts.  As contracts expire, we have additional exposure to the longer term trends in supply and demand for natural gas.  As of December 31, 2017, the remaining weighted average contract life of our natural gas transportation contracts (including intrastate pipelines’ terminal sales portfolio) was approximatelysix years.

Our midstream assets provide gathering and processing services for natural gas and gathering services for crude oil. These assets are mostly fee-based and the revenues and earnings we realize from gathering natural gas, processing natural gas in order to remove NGL from the natural gas stream, and fractionating NGL into their base components, are affected by the volumes of natural gas made available to our systems. Such volumes are impacted by producer rig count and drilling activity. In addition to fee based arrangements, some of which may include minimum volume commitments, we also provide some services based on percent-of-proceeds, percent-of-index and keep-whole contracts. Our service contracts may rely solely on a single type of arrangement, but more often they combine elements of two or more of the above, which helps us and our counterparties manage the extent to which each shares in the potential risks and benefits of changing commodity prices. 
The CO2 source and transportation business primarily has third-party contracts with minimum volume requirements, which as of December 31, 2017, had a remaining average contract life of approximately eight years.  CO2 sales contracts vary from customer to customer and have evolved over time as supply and demand conditions have changed.  Our recent contracts have generally provided for a delivered price tied to the price of crude oil, but with a floor price.  On a volume-weighted basis, for third-party contracts making deliveries in 2018, and utilizing the average oil price per barrel contained in our 2018 budget, approximately 97% of our revenue is based on a fixed fee or floor price, and 3% fluctuates with the price of oil. In the long-term, our success in this portion of the CO2 business segment is driven by the demand for CO2. However, short-term changes in the demand for CO2 typically do not have a significant impact on us due to the required minimum sales volumes under many of our contracts.  In the CO2 business segment’s oil and gas producing activities, we monitor the amount of capital we expend in relation to the amount of production that we expect to add.  In that regard, our production during any period is an important measure.  In addition, the revenues we receive from our crude oil, NGL and CO2 sales are affected by the prices we realize from the sale of these products.  Over the long-term, we will tend to receive prices that are dictated by the demand and overall market price for these products.  In the shorter term, however, market prices are likely not indicative of the revenues we will receive due to our risk management, or hedging, program, in which the prices to be realized for certain of our future sales quantities are fixed, capped or bracketed through the use of financial derivative contracts, particularly for crude oil.  The realized weighted average crude oil price per barrel, with the hedges allocated to oil, was $58.40 per barrel in 2017, $61.52 per barrel in 2016 and $73.11 per barrel in 2015.  Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $49.61 per barrel in 2017, $41.36 per barrel in 2016 and $47.56 per barrel in 2015.

 The factors impacting our Terminals business segment generally differ between terminals and tankers and depending on whether the terminal is a liquids or bulk terminal, and in the case of a bulk terminal, the type of product being handled or stored.  Our liquids terminals business generally has long-term contracts that require the customer to pay regardless of whether they use the capacity.  Thus, similar to our natural gas pipeline business, our liquids terminals business is less sensitive to short-term changes in supply and demand.  Therefore, the extent to which changes in these variables affect our terminals business in the near term is a function of the length of the underlying service contracts(which on average is approximately three years), the extent to which revenues under the contracts are a function of the amount of product stored or transported, and the extent to which such contracts expire during any given period of time.  As with our refined petroleum products pipeline transportation business, the revenues from our bulk terminals business are generally driven by the volumes we handle and/or store, as well as the prices we receive for our services, which in turn are driven by the demand for the products being shipped or stored.  While we handle and store a large variety of products in our bulk terminals, the primary products are steel, coal and petroleum coke. For the most part, we have contracts for this business that contain minimum volume guarantees and/or service exclusivity arrangements under which customers are required to utilize our terminals for all or a specified percentage of their handling and storage needs.  The profitability of our minimum volume contracts is generally unaffected by short-term variation in economic

conditions; however, to the extent we expect volumes above the minimum and/or have contracts which are volume-based we can be sensitive to changing market conditions.  To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate the risk of reduced volumes and pricing by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity.  In addition, weather-related factors such as hurricanes, floods and droughts may impact our facilities and access to them and, thus, the profitability of certain terminals for limited periods of time or, in relatively rare cases of severe damage to facilities, for longer periods. In addition to liquid and bulk terminals, we also own Jones Act tankers. As of December 31, 2017, we have sixteen Jones Act qualified tankers that operate in the marine transportation of crude oil, condensate and refined products in the U.S. and are currently operating pursuant to multi-year fixed price charters with major integrated oil companies, major refiners and the U.S. Military Sealift Command.

The profitability of our refined petroleum products pipeline transportation and storage business is generally driven by the volume of refined petroleum products that we transport and the prices we receive for our services. We also have approximately 51 liquids terminals in this business segment that store fuels and offer blending services for ethanol and biofuels. The transportation and storage volume levels are primarily driven by the demand for the refined petroleum products being shipped or stored.  Demand for refined petroleum products tends to track in large measure demographic and economic growth, and with the exception of periods of time with very high product prices or recessionary conditions, demand tends to be relatively stable.  Because of that, we seek to own refined petroleum products pipelines located in, or that transport to, stable or growing markets and population centers.  The prices for shipping are generally based on regulated tariffs that are adjusted annually based on changes in the U.S. Producer Price Index.

Our crude and condensate transportation services are primarily provided either pursuant to (i) long-term contracts that normally contain minimum volume commitments or (ii) through terms prescribed by the toll settlements with shippers and approved by regulatory authorities. As a result of these contracts, our settlement volumes are generally not sensitive to changing market conditions in the shorter term, however, in the longer term the revenues and earnings we realize from our crude and condensate pipelines in the U.S. and Canada are affected by the volumes of crude and condensate available to our pipeline systems, which are impacted by the level of oil and gas drilling activity in the respective producing regions that we serve. Our petroleum condensate processing facility splits condensate into its various components, such as light and heavy naphtha, under a long-term fee-based agreement with a major integrated oil company.

KML

The interest in the Canadian business operations that we sold to the public on May 30, 2017 in KML’s IPO represented an interest in all our operating assets in our Kinder Morgan Canada business segment and our operating Canadian assets in our Terminals and Products Pipelines business segments. These Canadian assets include the Trans Mountain pipeline system (including related terminaling assets), the TMEP, the Puget Sound and Jet Fuel pipeline systems, the Canadian portion of the Cochin pipeline system, the Vancouver Wharves Terminal and the North 40 Terminal; as well as three jointly controlled investments: the Edmonton Rail Terminal, the Alberta Crude Terminal and the Base Line Terminal.

Subsequent to the IPO, we retained control of KML, and as a result, it remains consolidated in our consolidated financial statements. The public ownership of the KML restricted voting shares is reflected within “Noncontrolling interests” in our consolidated statements of stockholders’ equity and consolidated balance sheets. Earnings attributable to the public ownership of KML are presented in “Net income attributable to noncontrolling interests” in our consolidated statements of income for the periods presented after May 30, 2017. KML transacts in and/or uses the Canadian dollar as the functional currency, which affects segment results due to the variability in U.S. - Canadian dollar exchange rates. 

Subsequent to its IPO, KML has obtained a credit facility and completed two preferred share offerings. KMI expects KML to be a self-funding entity and does not anticipate making contributions to fund its growth or specifically to fund the TMEP.

TMEP Permitting and Construction Progress

TMEP was approved by Order in Council on December 1, 2016, with 157 conditions. The Province of British Columbia (BC) stated its approval of the TMEP on January 11, 2017, with 37 conditions. Trans Mountain has made filings with the NEB and BC Environment with respect to all of the federal and provincial conditions required prior to general construction. The BC Environmental Assessment Office (EAO) has now released all condition filings required prior to general construction. The NEB has released sufficient approvals for proceeding with the Westridge Terminal and Temporary Infrastructure work phase. Trans Mountain is now in receipt of a number of priority permits from regulatory authorities in Alberta and BC, including access to BC northern interior Crown lands. KML continues to make progress on approvals from the NEB, government of BC and government of Alberta. However, as of the end of 2017, even with this progress, TMEP has

yet to obtain numerous provincial and municipal permits and federal condition approvals necessary for construction.

On December 4, 2017, KML announced that, while TMEP had made incremental progress during 2017 on permitting, regulatory condition satisfaction and land access, the scope and pace of the permits and approvals received to date did not allow for significant additional construction to begin at that time. KML also stated that it must have a clear line of sight on the timely conclusion of the permitting and approvals processes before it would commit to full construction spending. Consistent with its primarily permitting strategy and to mitigate risk, KML set its 2018 budget assuming TMEP spend in the first part of 2018 would be focused primarily on advancing the permitting process, rather than spending at full construction levels, until KML has greater clarity on key permits, approvals and judicial reviews. In its January 17, 2018 earnings press release, KML announced a potential unmitigated delay to project completion of one year (to December 2020) primarily due to the time required to file for, process and obtain necessary permits and regulatory approvals. As stated in Trans Mountain's November 14, 2017 motion to the NEB discussed below, "it is critical for Trans Mountain to have certainty that once started, the TMEP can confidently be completed on schedule." The TMEP projected in service date remains subjectsusceptibility to change, due to risks and uncertainties described in “Information Regarding Forward-Looking Statements,” “Item 1A, Risk Factors,” elsewhere in this Item 7, and in Note 17 to our consolidated financial statements under the heading “TMEP Litigation.” Further, as stated in KML’s January 17, 2018 earnings press release, if TMEP continues to be "faced with unreasonable regulatory risks due to a lack of clear processes to secure necessary permits . . . it may become untenable for Trans Mountain's shareholders . . . to proceed." Trans Mountain continues to proceed in water work at the Westridge Terminal.

On October 26 and November 14, 2017, KML filed motions with the NEB to resolve delays as they relate to the City of Burnaby and to establish a fair, transparent and expedited backstop process for resolving any similar delays in other provincial and municipal permitting processes. On December 7, 2017, the NEB granted KML’s motion in respect to the City of Burnaby and indicated that Trans Mountain is not required to comply with two sections of the city’s bylaws, thereby allowing Trans Mountain to start work at its pipeline terminals subject to other permits or authorizations that may be required. The NEB indicated that it would release its reasons for decision at a later date. On January 18, 2018, the NEB issued its reasons for decision on the Burnaby motion and granted in part Trans Mountain’s motion for a backstop process, establishing a generic process to hear any future motions as they relate to provincial and municipal permitting issues.

Hearings were held in October and November 2017 related to two judicial reviews underway in the BC Supreme Court with respect to the environmental certificate granted to TMEP by the province of BC. Separate judicial reviews pending in the Federal Court of Appeal challenging the process leading to the federal government’s approval of TMEP were heard by the court from October 2 to October 13, 2017. Decisions from the courts are expected in the coming months. KMI is confident that the NEB, the Federal Government, and the BC Government properly assessed and weighed the various scientific and technical evidence through a comprehensive review process, while taking into consideration varying interests on the TMEP. The approvals granted followed many years of engagement and consultation with communities, Aboriginal groups and individuals.

As of the end of the fourth quarter 2017, a cumulative C$930 million has been spent on the TMEP. KML’s estimated total cost for the TMEP is C$7.4 billion (C$6.7 billion excluding capitalized equity financing costs). Construction related delays could result in increases to the estimated total costs; however, because the extent of the delay remains uncertain, KML has not updated its cost estimate at this time.

2017 Tax Reform

While the recently enacted 2017 Tax Reform will ultimately be moderately positive for us, the reduced corporate income tax rate caused certain of our deferred-tax assets to be revalued at 21 percent versus 35 percent at the end of 2017.  Although there is noa material impact to the underlying related deductions, which can continueour financial statements. Examples of certain areas that require more judgment relative to be used to offset future taxable income, we took an estimated approximately $1.4 billion non-cash accounting charge in the fourth quarter of 2017.  This charge is our initial estimate and may be refined in the future as permitted by recent guidance from the SEC and FASB. The positive impacts of the law include the reduced corporate income tax rate and the fact that several of our U.S. business units (essentially all but our interstate natural gas pipelines) will be able to deduct 100 percent of their capital expenditures through 2022.  The net impact results in postponing the dateothers when we become a significant federal cash taxpayer by approximately one year, to beyond 2024.

We continue to assess the impact of the 2017 Tax Reform on our business in order to complete our analysis. Any adjustment to our provisional amount recorded during the year ended December 31, 2017 will be reported in the reporting period in which any such adjustments are determined and may be material in the period in which the adjustments are made. See Note 5 “Income Taxes” to our consolidated financial statements.


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

In preparing our consolidated financial statements and related disclosures, examples of certain areas that require more judgment relative to others include our use of estimates in determining: (i) revenue recognition and income taxes, (ii) the economic useful lives of our assets and related depletion rates; (iii) the fair values used to (a) assign purchase price from business combinations, (b) determine possible asset and equity investment impairment charges, and (c) calculate the annual goodwill impairment test; (iv) reserves for environmental claims, legal fees, transportation rate cases and other litigation liabilities; (v) provisions for uncollectible accounts receivables; and (vi) exposures under contractual indemnifications.

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


Acquisition MethodImpairments

In addition to our annual testing of Accountingimpairment 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,

40

For acquired businesses, we generally recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition. Determining the fair value of these items requires management’s judgment, the utilization of independent valuation experts andfor impairment involves the use of significant estimates and assumptions with respect toregarding the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The judgments madeestimates 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 the determinationour business strategy and our internal forecasts. An estimate of the estimatedsensitivity to changes in underlying assumptions of a fair value assigned tocalculation is not practicable, given the assets acquired, the liabilities assumed and any noncontrolling interest in the investee, as well as the estimated useful life of each asset and the duration of each liability,numerous assumptions that can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. affect our estimates.

For more information on our acquisitionsimpairments and application of the acquisition method,significant estimates and assumptions used in our impairment evaluations, see Note 3“Acquisitions4 “Losses and Divestitures”to our consolidated financial statements.Gains on Divestitures, Impairments and Other Write-downs.”


Environmental Matters

With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. We expense or capitalize, as appropriate, environmental expenditures that relate to current operations, and we recordOur accrual of environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs.  Generally, we do not discount environmental liabilities to a net present value, and we recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We record at fair value, where appropriate, environmental liabilities assumed in a business combination.
Our recording of our environmental accruals 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 routinequarterly reviews of potential environmental issues and claims that could impact our assets or operations. These adjustments may result in increases inIn recording and adjusting environmental expenses and are primarily related to quarterly reviews of potential environmental issues and resulting environmental liability estimates.  In making these liability estimations,liabilities, we consider the effect of environmental compliance, pending legal actions against us, and potential third partythird-party liability claims. For more information on environmental matters, see PARTPart I, Items 1 and 2 “Business2. “Business and Properties—(c) Narrative Description of Business—Environmental Matters.” For more information on our environmental disclosures, see Note 1718 “Litigation Environmental and Other Contingencies”Environmental” to our consolidated financial statements.


Legal and Regulatory Matters

Many of our operations are regulated by various U.S. and Canadian regulatory bodies, and we are subject to legal and regulatory matters as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements.  In general, we expense legal costs as incurred.  When we identify contingent liabilities, we identify a range of possible costs expected to be required to resolve the matter.  Generally, if no amount within this range is a better estimate than any other amount, we record a liability equal to the low end of the range. Any such liability recorded is revised as better information becomes available. Accordingly, to the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. For more information on regulatory matters, see Part I, Items 1 and 2. “Business and Properties—Narrative Description of Business—Industry Regulation.” For more information on legal proceedings, see Note 1718 “Litigation Environmental and Other Contingencies”Environmental” to our consolidated financial statements.

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

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

Hedging Activities

We engage in a hedging program that utilizes derivative contracts to mitigate (offset) our exposure to fluctuations in energy commodity prices, foreign currency exposure on Euro denominated debt, and to balance our exposure to fixed and variable interest rates, and we believe that these hedges are generally effective in realizing these objectives.  According to the provisions of GAAP, to be considered effective, changes in the value of a derivative contract or its resulting cash flows must substantially offset changes in the value or cash flows of the item being hedged, and any ineffective portion of the hedge gain or loss and any component excluded from the computation of the effectiveness of the derivative contract must be reported in earnings immediately.

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

Employee Benefit Plans

We reflect an asset or liability for our pension and other postretirement benefit plans based on their overfunded or underfunded status. As of December 31, 2017, our pension plans were underfunded by$686 million and our other postretirement benefits plans were underfunded by$90 million. Our pension and other postretirement benefitOPEB obligations and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the rate at which we expect the compensation of our employees to increase over the plan term, the estimated cost of health care when benefits are provided under our plan and other factors. A significant assumption we utilize is the discount rate used in calculating our benefit obligations. We utilize a full yield curve approachThe selection of assumptions used in the estimationactuarial calculations of the service and interest cost components of net periodic benefit cost (credit) for our pension and other postretirement benefitOPEB plans which applies the specific spot rates along the yield curve used in the determination of the benefit obligation to their underlying projected cash flows. The selection of these assumptions is further discussed in Note 10“Share-based 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 other postretirement benefitsOPEB obligations can be, and often are,have been revised in the future.subsequent periods. The income statement impact of the changes in the assumptions on our related benefit obligations are deferred and amortized into income over either the period of expected future service of active participants, or over the expected future lives of inactive plan participants. As of December 31, 2017, we had deferred net losses of approximately $547 million in pretax accumulated other comprehensive loss and noncontrolling interests related to our pension and other postretirement benefits.

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The following tablesensitivity analysis shows the estimated impact of a 1% change in the primary assumptions used in our actuarial calculations associated with our pension and other postretirement benefitsOPEB plans for the year ended December 31, 2017:
2023:
 Pension Benefits Other Postretirement Benefits
 Net benefit cost (income) Change in funded status(a) Net benefit cost (income) Change in funded status(a)
 (In millions)
Pension BenefitsPension BenefitsOPEB
Net benefit cost (credit)Net benefit cost (credit)Funded statusNet benefit cost (credit)Funded status(a)
(In millions)(In millions)
One percent increase in:        
Discount rates
Discount rates
Discount rates $(13) $252
 $(1) $33
Expected return on plan assets (21) —
 (3) —
Rate of compensation increase 4
 (13) —
 —
Health care cost trends —
 —
 3
 (24)
One percent decrease in:
One percent decrease in:
        
One percent decrease in:        
Discount rates 15
 (299) 1
 (38)
Discount rates
Discount rates
Expected return on plan assets 21
 —
 3
 —
Rate of compensation increase (3) 13
 —
 —
Health care cost trends —
 —
 (3) 21
_______(a)Includes amounts deferred as either accumulated other comprehensive income (loss) or as a regulatory asset or liability for certain of our regulated operations.
(a)Includes amounts deferred as either accumulated other comprehensive income (loss) or as a regulatory asset or liability for certain of our regulated operations.


Income Taxes

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

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

In determining the deferred income tax asset and liability balances attributableinformation, see Note 5 “Income Taxes” to our investments, we apply an accounting policy that looks through our investments. The application of this policy resulted in no deferred income taxes being provided on the difference between the book and tax basis on the non-tax-deductible goodwill portion of our investments.consolidated financial statements.


Results of Operations


Overview


OurAs 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 Measures

The 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 and, as discussed below under “—Non-GAAP Measures,” DCF, and Segment EBDA before certain items.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.


In our discussions of the operating results of individual businesses that follow, we generally identify the important fluctuations between periods that are attributable to acquisitions and dispositions separately from those that are attributable to businesses owned in both periods.
Consolidated Earnings Results

 Year Ended December 31,
 2017 2016 2015
 (In millions)
Segment EBDA(a)     
Natural Gas Pipelines$3,487
 $3,211
 $3,067
CO2
847
 827
 658
Terminals1,224
 1,078
 878
Products Pipelines1,231
 1,067
 1,106
Kinder Morgan Canada186
 181
 182
Total segment EBDA(b)6,975
 6,364
 5,891
DD&A(2,261) (2,209) (2,309)
Amortization of excess cost of equity investments(61) (59) (51)
General and administrative and corporate charges(c)(660) (652) (708)
Interest, net(d)(1,832) (1,806) (2,051)
Income before income taxes2,161
 1,638
 772
Income tax expense(e)(1,938) (917) (564)
Net income223
 721
 208
Net (income) loss attributable to noncontrolling interests(40) (13) 45
Net income attributable to Kinder Morgan, Inc.183
 708
 253
Preferred Stock Dividends(156) (156) (26)
Net Income Available to Common Stockholders$27
 $552
 $227
_______
(a)Includes revenues, earnings from equity investments, and other, net, less operating expenses, other expense (income), net, losses on impairments of goodwill, losses on impairments and divestitures, net and losses on impairments and divestitures of equity investments, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
Certain items affecting Total Segment EBDA (see “—Non-GAAP Measures” below)
(b)2017, 2016 and 2015 amounts include decreases in earnings of $384 million, $1,121 million and $1,748 million, respectively, related to the combined net effect of the certain items impacting Total Segment EBDA. The extent to which these items affect each of our business segments is discussed below in the footnotes to the tables within “—Segment Earnings Results.”
(c)
2017, 2016 and 2015 amounts include an increase to expense of $15 million, a decrease to expense of $13 million and an increase to expense of $60 million, respectively, related to the combined net effect of the certain items related to general and administrative and corporate charges disclosed below in “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests.”
(d)
2017, 2016 and 2015 amounts include decreases in expense of $39 million, $193 million and $27 million, respectively, related to the combined net effect of the certain items related to interest expense, net disclosed below in “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests.”

(e)2017, 2016 and 2015 amounts include increases in expense of $1,085 million and $18 million and a decrease in expense of $340 million, respectively, related to the combined net effect of the certain items related to income tax expense representing the income tax provision on certain items plus discrete income tax items.

Year Ended December 31, 2017 vs. 2016

The certain item totals reflected in footnotes (b), (c) and (d) to the table above accounted for $555 million of the increase in income before income taxes in 2017 as compared to 2016 (representing the difference between decreases of $360 million and $915 million in income before income taxes for 2017 and 2016, respectively). After giving effect to these certain items, which are discussed in more detail in the discussion that follows, the remaining decrease of $32 million (1%) from the prior year in income before income taxes is primarily attributable to decreased performance from our Natural Gas Pipelines business segment, largely associated with our sale of a 50% interest in SNG to The Southern Company (Southern Company) on September 1, 2016, and increased DD&A expense partially offset by decreased general and administrative expense and decreased interest expense.

Year Ended December 31, 2016 vs. 2015

The certain item totals reflected in footnotes (b), (c) and (d) to the table above accounted for $866 million of the increase in income before income taxes in 2016 as compared to 2015 (representing the difference between decreases of $915 million and $1,781 million in income before income taxes for 2016 and 2015, respectively). After giving effect to these certain items, which are discussed in more detail in the discussion that follows, income before income taxes for 2016 when compared to the prior year was flat. Increased results in our Products Pipelines and Terminals business segments and decreased DD&A expense and interest expense, net, were offset by unfavorable commodity prices affecting our CO2 business segment and decreased results on our Natural Gas Pipelines business segment. The decrease in DD&A was primarily driven by lower DD&A in our CO2 business segment and the decrease in interest expense was due to lower weighted average debt balances, partially offset by a slightly higher overall weighted average interest rate on outstanding debt.

Non-GAAP Financial Measures


Our non-GAAP performancefinancial measures are DCF, bothdescribed 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 aggregatedescriptions of consolidated non-GAAP measures below, understanding the differences between the measures and per share,taking this information into account in its analysis and Segment EBDA before certain items. its decision-making processes.

Certain items,Items

Certain Items, as adjustments used to calculate our non-GAAP financial measures, are items that are required by GAAP to be reflected in netNet income attributable to Kinder Morgan, Inc., but typically either (i) do not have a cash impact (for example, unsettled commodity hedges and asset impairments), or (ii) by their nature are separately identifiable from our normal business operations and in our viewmost 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.


Our non-GAAP
Year Ended December 31,
20232022
Certain Items
Fair value amortization$— $(15)
Legal, environmental and other reserves— 51 
Change in fair value of derivative contracts(a)(126)57 
Loss on impairment67 — 
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 measures described below should not be considered alternativesand ability to generate earnings that are core to our ongoing operations. We believe the GAAP measure most directly comparable to Adjusted Net Income Attributable to Kinder Morgan, Inc. is Net income attributable to Kinder Morgan, Inc. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Kinder Morgan, Inc.”

Adjusted Net Income Attributable to Common Stock and Adjusted EPS

Adjusted Net Income Attributable to Common Stock is calculated by adjusting Net income attributable to Kinder Morgan, Inc., the most comparable GAAP measure, for Certain Items, and further for net income or otherallocated 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 measures and have important limitationsmeasure to Adjusted EPS. Adjusted EPS is calculated as analytical tools. Our computations of DCF and Segment EBDA before certain items may differ from similarly titled measuresAdjusted 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 others. You should not consider these non-GAAP performance measures in isolation or as substitutes for an analysisus, investors and other external users of our resultsfinancial statements as reporteda 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 GAAP.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. Management compensates for the limitations of these non-GAAP performance measures by reviewing our comparable GAAP measures, understanding the differences between the measures and taking this information into account in its analysis and its decision making processes.

DCF
DCF is calculated by adjusting net income available to common stockholders before certain items for DD&A, total book and cash taxes, sustaining capital expenditures and other items. DCF is a significant performance measure useful to management and external users of our financial statements in evaluating our performance and in measuring and estimating the ability of our assets to generate cash earnings after servicing our debt and preferred stock dividends, paying cash taxes and expending sustaining capital that could be used for discretionary purposes such as common stock dividends, stock repurchases, retirement of debt, or expansion capital expenditures. We believe the GAAP measure most directly comparable to DCF is netNet income availableattributable to common stockholders. A reconciliation of DCF to net income available to common stockholders is provided in the table below.Kinder Morgan, Inc. DCF per share is DCF divided by average outstanding shares, including restricted stock awards that participate in dividends. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF” below.


Adjusted Segment EBDA

Adjusted Segment EBDA Beforeis calculated by adjusting Segment EBDA for Certain Items

attributable to the segment. Adjusted Segment EBDA before certain items is used by management in its analysis of segment performance and management of our business. General and administrative expenses are generally not under the control of our segment operating managers, and

therefore, are not included when we measure business segment operating performance. We believe Adjusted Segment EBDA before certain items is a significantuseful performance metric because it provides usmanagement, 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 segment cash earnings on an ongoing basis. Adjusted Segment EBDA is also used as a factor in determining compensation under our annual incentive compensation program for our business segment presidents and other business segment employees. We believe it is useful to investors because it is a performance measure that management uses to allocate resources to our segments and assess each segment’s performance. We believe the GAAP measure most directly comparable toSee “—Non-GAAP Financial Measures—Reconciliation of Segment EBDA before certain itemsto Adjusted Segment EBDA” below.

Adjusted EBITDA

Adjusted EBITDA is segment earnings beforecalculated 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, (Segment EBDA)income tax expense and interest. We also include amounts from joint ventures for income taxes and DD&A (see “Amounts from Joint Ventures” below).

In 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 tablesvaluations of companies across our industry. Our ratio of Net Debt-to-Adjusted EBITDA is used as a supplemental performance target for eachpurposes of our business segments under annual incentive compensation program. We believe the GAAP measure most directly comparable to Adjusted EBITDA is Net income attributable to Kinder Morgan, Inc. See “— Segment Earnings Results” below, Segment EBDA before certain items is calculated by adjusting the Segment EBDA for the applicable certain item amounts, which are totaled in the tables and described in the footnotes to those tables.

Non-GAAP Financial Measures—Reconciliation of Net Income AvailableAttributable to Common StockholdersKinder Morgan, Inc. to Adjusted EBITDA” below.

Amounts from Joint Ventures

Certain Items, DCF and Adjusted EBITDA reflect amounts from unconsolidated joint ventures and consolidated joint ventures utilizing the same recognition and measurement methods used to record “Earnings from equity investments” and “Noncontrolling interests,” respectively. The calculations of DCF and Adjusted EBITDA related to our unconsolidated and consolidated joint ventures include the same items (DD&A and income tax expense, and for DCF only, also cash taxes and sustaining capital expenditures) with respect to the joint ventures as those included in the calculations of DCF and Adjusted EBITDA for our wholly-owned consolidated subsidiaries; further, we remove the portion of these adjustments attributable to
 Year Ended December 31,
 2017 2016 2015
 (In millions)
Net Income Available to Common Stockholders$27
 $552
 $227
Add/(Subtract):     
Certain items before book tax(a)141
 915
 1,781
Book tax certain items(b)(77) 18
 (340)
Impact of 2017 Tax Reform(c)1,381
 —
 —
Total certain items1,445
 933
 1,441
      
Noncontrolling interest certain items(d)—
 (8) (63)
Net income available to common stockholders before certain items1,472
 1,477
 1,605
Add/(Subtract):     
DD&A expense(e)2,684
 2,617
 2,683
Total book taxes(f)957
 993
 976
Cash taxes(g)(72) (79) (32)
Other items(h)29
 43
 32
Sustaining capital expenditures(i)(588) (540) (565)
DCF$4,482
 $4,511
 $4,699
      
Weighted average common shares outstanding for dividends(j)2,240
 2,238
 2,200
DCF per common share$2.00
 $2.02
 $2.14
Declared dividend per common share0.500
 0.500
 1.605
44
_______
(a)
Consists of certain items summarized in footnotes (b) through (d) to the “—Results of Operations—Consolidated Earnings Results” table included above, and described in more detail below in the footnotes to tables included in both our management’s discussion and analysis of segment results and “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests.”

(b)Represents income tax provision on certain items plus discrete income tax items. For 2017, discrete income tax items include a $36 million federal return-to-provision tax benefit as a result of the recognition of an enhanced oil recovery credit instead of deduction. For 2016, discrete income tax items include a $276 million increase in tax expense primarily due to the impact of the sale of a 50% interest in SNG discussed in Note 5 “Income Taxes” to our consolidated financial statements.
(c)Amount includes book tax certain items and $219 million pre-tax certain items related to our FERC regulated business. See Note 5 “Income Taxes” to our consolidated financial statements.
(d)Represents noncontrolling interests share of certain items.
(e)Includes DD&A, amortization of excess cost of equity investments and our share of certain equity investee’s DD&A, net of the noncontrolling interests’ portion of KML DD&A and consolidating joint venture partners’ share of DD&A of $362 million, $349 million and $323 million in 2017, 2016 and 2015, respectively.
(f)Excludes book tax certain items of $(1,085) million, $(18) million and $340 million for 2017, 2016 and 2015, respectively. 2017, 2016 and 2015 amounts also include $104 million, $94 million and $72 million, respectively, of our share of taxable equity investee’s book taxes, net of the noncontrolling interests’ portion of KML book taxes.
(g)Includes our share of taxable equity investee’s cash taxes of $(69) million, $(76) million and $(19) million in 2017, 2016 and 2015, respectively.

(h)Amounts include non-cash compensation associated with our restricted stock program. 2017 amount also includes a pension contribution.
(i)Includes our share of (i) certain equity investee’s, (ii) KML’s, and (ii) consolidating subsidiaries’ sustaining capital expenditures of $(107) million, $(90) million and $(70) million in 2017, 2016 and 2015, respectively.
(j)Includes restricted stock awards that participate in common share dividends and, for 2015, the dilutive effect of warrants, which expired on May 25, 2017 without the issuance of Class P common stock.

Segmentnon-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 Debt

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

45

Consolidated Earnings Results


Natural Gas PipelinesThe following tables summarize the key components of our consolidated earnings results.

 Year Ended December 31,
 2017 2016 2015
 (In millions, except operating statistics)
Revenues(a)$8,618
 $8,005
 $8,725
Operating expenses(b)(5,457) (4,393) (4,738)
Loss on impairment of goodwill(c)—
 —
 (1,150)
Loss on impairments and divestitures, net(d)(27) (200) (122)
Other income1
 1
 3
Earnings from equity investments(e)453
 385
 351
Loss on impairments of equity investments(f)(150) (606) (26)
Other, net(g)49
 19
 24
Segment EBDA(a)(b)(c)(d)(e)(f)(g)3,487
 3,211
 3,067
Certain items(a)(b)(c)(d)(e)(f)(g)392
 825
 1,062
Segment EBDA before certain items$3,879
 $4,036
 $4,129
      
Change from prior periodIncrease/(Decrease)  
Revenues before certain items$594
 $(477)  
Segment EBDA before certain items$(157) $(93)  
      
Natural gas transport volumes (BBtu/d)(h)29,108
 28,095
 28,196
Natural gas sales volumes (BBtu/d)2,341
 2,335
 2,419
Natural gas gathering volumes (BBtu/d)(h)2,653
 2,970
 3,540
Crude/condensate gathering volumes (MBbl/d)(h)273
 292
 309
Year Ended December 31,
20232022Earnings
increase/(decrease)
(In millions, except percentages)
Revenues$15,334 $19,200 $(3,866)(20)%
Operating Costs, Expenses and Other
Costs of sales (exclusive of items shown separately below)(4,938)(9,255)4,317 47 %
Operations and maintenance(2,807)(2,655)(152)(6)%
DD&A(2,250)(2,186)(64)(3)%
General and administrative(668)(637)(31)(5)%
Taxes, other than income taxes(421)(441)20 5 %
Gain on divestitures and impairments, net15 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 Income4,263 4,065 198 5 %
Other Income (Expense)
Earnings from equity investments838 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 Taxes3,201 3,335 (134)(4)%
Income Tax Expense(715)(710)(5)(1)%
Net Income2,486 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 outstanding2,234 2,258 (24)(1)%
Declared dividends per share$1.13 $1.11 $0.02 2 %
_______Our consolidated revenues include fees for transportation and other midstream services that we perform. Fluctuations in our consolidated services revenue largely reflect changes in volumes and/or in the rates we charge. Our consolidated costs of sales and sales revenues also include purchases and sales of natural gas and products (which means, collectively, NGL, crude oil, CO2 and transmix) and related derivative activity. Our consolidated sales revenue will fluctuate with commodity prices and volumes, and the associated costs of sales will usually have a commensurate and offsetting impact, except for the CO2 segment, which produces, instead of purchases, the crude oil and CO2 it sells. Additionally, fluctuations in revenues and costs of sales may be further impacted by gains or losses from derivative contracts that we use to manage our commodity price risk.
Certain items affecting Segment EBDA
(a)2017 and 2015 amounts include increases in revenues of $8 million and $32 million, respectively, and 2016 amount includes a decrease in revenues of $50 million, all related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas, NGL and crude oil sales. 2016 amount also includes an increase in revenue of $39 million associated with revenue collected on a customer’s early buyout of a long-term natural gas storage contract. 2015 amount also includes an increase in revenues of $200 million associated with amounts collected on the early termination of a long-term natural gas transportation contract on KMLP.
(b)2017 amount includes a decrease in earnings of (i) $166 million related to the impact of the 2017 Tax Reform; (ii) $3 million related to the non-cash impairment loss associated with the Colden storage field; and (iii) $3 million from other certain items. 2016 and 2015 amounts include a decrease in earnings of $3 million and an increase in earnings of $1 million, respectively, from other certain items.
(c)2015 decrease in earnings of $1,150 million relates to goodwill impairments on our non-regulated midstream reporting unit.
(d)2017 amount includes a decrease in earnings of $27 million related to the non-cash impairment loss associated with the Colden storage field. 2016 amount includes (i) a decrease in earnings of $106 million of project write-offs; (ii) an $84 million pre-tax loss on the sale of a 50% interest in our SNG natural gas pipeline system; and (iii) an $11 million decrease in earnings from other certain items. 2015 amount includes (i) $52 million of losses related to divestitures of certain non-regulated midstream assets; (ii) $47 million of losses related to other impairments on our non-regulated midstream assets; and (iii) a $25 million net decrease in earnings related to project write-offs and other certain items.
(e)2017 amount includes (i) a decrease in earnings of $58 million related to 2017 Tax Reform adjustments recorded by equity investees; (ii) an increase in earnings from an equity investment of $22 million on the sale of a claim related to the early termination of a long-term natural gas transportation contract; (iii) an increase in earnings from an equity investment of $12 million related to a customer contract settlement; (iv) a decrease in earnings of $12 million related to early termination of debt at an equity investee; and (v) a decrease in earnings of $10 million related to a non-cash impairment at an equity investee. 2016 amount includes an increase in earnings of $18 million related to the early termination of a customer contract at an equity investee and a decrease in earnings of $12 million related to

other certain items at equity investees. 2015 amount includes an increase in earnings of $5 million related to other certain items at an equity investee.
(f)2017 amount includes a $150 million non-cash impairment loss related to our investment in FEP. 2016 amount includes $606 million of non-cash impairment losses primarily related to our investments in MEP and Ruby. 2015 amount includes $26 million of non-cash impairment losses primarily associated with our investment in Fort Union Gas Gathering L.L.C.
(g)2017 and 2016 amounts include decreases in earnings of $5 million and $10 million, respectively, related to certain litigation matters.
Other
(h)Joint venture throughput is reported at our ownership share. Volumes for acquired pipelines are included at our ownership share for the entire period, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition.


Below are theis a discussion of significant changes in both Segment EBDA before certain items and revenues before certain items in 2017 and 2016, when compared with the respective prior year:

Year Ended December 31, 2017 versus Year Ended December 31, 2016
 
Segment EBDA before certain items
increase/(decrease)
 
Revenues before
certain items
increase/(decrease)
 (In millions, except percentages)
SNG$(200) (62)% $(356) (92)%
CIG(50) (18)% (45) (12)%
South Texas Midstream(49) (18)% 10
 1%
KinderHawk(20) (23)% (20) (20)%
Oklahoma Midstream(11) (26)% 199
 71%
TGP68
 6% 93
 6%
Elba Express40
 43% 44
 48%
NGPL(a)22
 183% n/a
 n/a
EPNG18
 4% 22
 4%
Texas Intrastate Natural Gas Pipeline Operations13
 3% 605
 23%
Altamont Midstream10
 27% 32
 32%
All others (including eliminations)2
 —% 10
 1%
Total Natural Gas Pipelines$(157) (4)% $594
 7%
____________
(a) Equity investment

The changes in Segment EBDAour Consolidated Earnings Results for our Natural Gas Pipelines business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 2017ended 2023 and 2016:2022:

Revenues

Revenues decreased $3,866 million in 2023 compared to 2022. The decrease of $200 million (62%) from SNG primarily due to our sale of a 50% interest in SNG to Southern Company on September 1, 2016;
decrease of $50 million (18%) from CIG primarily due to a decrease in tariff rates effective January 1, 2017 as a result of a rate case settlement entered into in 2016;
decrease of $49 million (18%) from South Texas Midstreamwas primarily due to lower commodity based service revenues and residuenatural gas sales as a result of $3,616 million and lower volumesproduct sales of $1,029 million driven primarily by lower commodity prices partially offset by higher NGLthe impact of derivative contracts used to hedge commodity sales gross margin primarily dueof $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.”
46


Operating Costs, Expenses and Other

Costs of Sales

Costs of sales decreased $4,317 million in 2023 compared to rising NGL prices;
2022. The decrease of $20 million (23%) from KinderHawkwas primarily due to lower volumes;
decreasecosts of $11 million (26%) from Oklahoma Midstream primarily due to lower volumes and unfavorable producer mix. Higher revenuessales for natural gas of $199$3,587 million and associated increase in costsfor products of goods sold were primarily due to higher commodity prices;
increase of $68$622 million (6%) from TGP primarily due to higher firm transportation revenues driven by incremental capacity sales, expansion projects recently placed in service and an increase in operational gas sales, partially offset by an increase in the associated gas cost;
increase of $40 million (43%) from Elba Express primarily due to an expansion project placed in service in December 2016;
increase of $22 million (183%) from our equity investment in NGPL primarily due to lower interest expense due to a reduction in interest rates due to debt refinancing and the repayment of bank borrowings in 2017;

increase of $18 million (4%) from EPNG primarily due to higher transportation revenues driven by incremental Permian capacity sales and an increase in volumes due to the ramp up of existing customer volumes associated with an expansion project partially offset by increased operations and maintenance expense;
increase of $13 million (3%) from our Texas intrastate natural gas pipeline operations (including the operations of its Kinder Morgan Tejas, Border, Kinder Morgan Texas, North Texas and Mier-Monterrey Mexico pipeline systems) primarily due to higher transportation margins as a result of higher volumes and higher park and loan revenues partially offset by lower storage and sales margins. The increases in revenues of $605 million resulted primarily from an increase in sales revenue due primarily to higher commodity prices which was largely offset by a corresponding increase in costs of sales; and
increase of $10 million (27%) from Altamont Midstream primarily due to higher natural gas and liquids revenues due to higher commodity prices and volumes.

Year Ended December 31, 2016 versus Year Ended December 31, 2015
 
Segment EBDA before certain items
increase/(decrease)
 
Revenues before
certain items
increase/(decrease)
 (In millions, except percentages)
SNG$(109) (25)% $(188) (33)%
South Texas Midstream(62) (18)% (229) (18)%
KinderHawk(48) (36)% (51) (33)%
KMLP(31) (135)% (34) (100)%
CIG(27) (9)% (31) (8)%
CPGPL(22) (37)% (23) (29)%
TransColorado(15) (48)% (16) (42)%
TGP171
 18% 205
 17%
Hiland Midstream59
 42% 152
 38%
Texas Intrastate Natural Gas Pipeline Operations7
 2% (278) (9)%
All others (including eliminations)(16) (1)% 16
 1%
Total Natural Gas Pipelines$(93) (2)% $(477) (6)%

The changes in Segment EBDA for our Natural Gas Pipelines business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 2016 and 2015:
decrease of $109 million (25%) from SNG primarily due to our sale of a 50% interest in SNG to Southern Company on September 1, 2016;
decrease of $62 million (18%) from South Texas Midstream primarily due to lower volumes and price. Revenue decreased approximately $229 million partially offset by a decrease in costs of sales;
decrease of $48 million (36%) from KinderHawk due to lower volumes;
decrease of $31 million (135%) from KMLP as a result of a customer contract buyout in the fourth quarter of 2015;
decrease of $27 million (9%) from CIG primarily due to a recent rate case settlement and lower firm reservation revenues due to contract expirations and contract renewals at lower rates;
decrease of $22 million (37%) from CPGPL primarily due to lower transport revenues as a result of contract expirations;
decrease of $15 million (48%) from TransColorado primarily due to lower transport revenues as a result of contract expirations;
increase of $171 million (18%) from TGP primarily due to a full year of earnings from expansion projects placed in service during 2015 and favorable 2016 firm transport revenues;
increase of $59 million (42%) from Hiland Midstream primarily due to favorable margins on renegotiated contracts, along with results of a full year from our February 2015 Hiland acquisition; and
increase of $7 million (2%) from our Texas intrastate natural gas pipeline operations (including the operations of its Kinder Morgan Tejas, Border, Kinder Morgan Texas, North Texas and Mier-Monterrey Mexico pipeline systems) primarily due to higher storage margins partially offset by lower sales and transportation margins as a result of lower volumes. The decrease in revenues of $278 million resulted primarily from a decrease in sales revenue due to lower commodity prices which was largely offset by a corresponding decrease in costs of sales.



CO2
 Year Ended December 31,
 2017 2016 2015
 (In millions, except operating statistics)
Revenues(a)$1,196
 $1,221
 $1,699
Operating expenses(394) (399) (432)
Gain (loss) on impairments and divestitures, net(b)1
 (19) (606)
Earnings from equity investments(c)44
 24
 (3)
Segment EBDA(a)(b)(c)847
 827
 658
Certain items(a)(b)(c)40
 92
 484
Segment EBDA before certain items$887
 $919
 $1,142
      
Change from prior periodIncrease/(Decrease)  
Revenues before certain items$(43) $(267)  
Segment EBDA before certain items$(32) $(223)  
      
Southwest Colorado CO2 production (gross) (Bcf/d)(d)
1.3
 1.2
 1.2
Southwest Colorado CO2 production (net) (Bcf/d)(d)
0.6
 0.6
 0.6
SACROC oil production (gross)(MBbl/d)(e)27.9
 29.3
 33.8
SACROC oil production (net)(MBbl/d)(f)23.2
 24.4
 28.1
Yates oil production (gross)(MBbl/d)(e)17.3
 18.4
 19.0
Yates oil production (net)(MBbl/d)(f)7.7
 8.2
 8.5
Katz, Goldsmith, and Tall Cotton Oil Production - Gross (MBbl/d)(e)8.1
 7.0
 5.7
Katz, Goldsmith, and Tall Cotton Oil Production - Net (MBbl/d)(f)6.9
 5.9
 4.8
NGL sales volumes (net)(MBbl/d)(f)9.9
 10.3
 10.4
Realized weighted-average oil price per Bbl(g)$58.40
 $61.52
 $73.11
Realized weighted-average NGL price per Bbl(h)$25.15
 $17.91
 $18.35
_______
Certain items affecting Segment EBDA
(a)
2017, 2016 and 2015 amounts include unrealized losses of $54 million and $63 million, and an unrealized gain of $138 million, respectively, related to non-cash mark to market derivative contracts used to hedge forecasted commodity sales. 2017 amount also includes an increase in revenues of $9 million related to the settlement of a CO2 customer sales contract and 2015 amount also includes a favorable adjustment of $10 million related to carried working interest at McElmo Dome.
(b)2017, 2016 and 2015 amounts include a decrease in expense of $1 million and increases in expense of $20 million and $207 million, respectively, related to source and transportation project write-offs. 2015 amount also includes oil and gas property impairments of $399 million.
(c)2017, 2016 and 2015 amounts include an increase in equity earnings of $4 million and decreases in equity earnings of $9 million and $26 million, respectively, for our share of a project write-off recorded by an equity investee.
Other
(d)Includes McElmo Dome and Doe Canyon sales volumes.
(e)Represents 100% of the production from the field.  We own an approximately 97% working interest in the SACROC unit, an approximately 50% working interest in the Yates unit, an approximately 99% working interest in the Katz unit and a 99% working interest in the Goldsmith Landreth unit and a 100% working interest in the Tall Cotton field.  
(f)Net after royalties and outside working interests.  
(g)Includes all crude oil production properties. 
(h)Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements.


Below are the changes in both Segment EBDA before certain items and revenues before certain items in 2017 and 2016, when compared with the respective prior year:

Year Ended December 31, 2017 versus Year Ended December 31, 2016

 
Segment EBDA before certain items
increase/(decrease)
 
Revenues before
certain items
increase/(decrease)
 (In millions, except percentages)
Source and Transportation Activities$2
 1% $(9) (3)%
Oil and Gas Producing Activities(34) (6)% (33) (3)%
Intrasegment eliminations—
 —% (1) (3)%
Total CO2$(32) (3)% $(43) (3)%

The changes in Segment EBDA for our CO2 business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 2017 and 2016:
increase of $2 million (1%) from our Source and Transportation activities primarily due to increased earnings from an equity investee of $6 million and lower operating expenses of $5 million partially offset by lower revenues of $9 million driven by lower contract sales prices of $7 million and decreased volumes of $2 million; and
decrease of $34 million (6%) from our Oil and Gas Producing activities primarily due to decreased revenues of $33 million driven by lower volumes of $22 million and lower commodity prices of $11 million, and higher operating expenses of $1 million.

Year Ended December 31, 2016 versus Year Ended December 31, 2015


 
Segment EBDA before certain items
increase/(decrease)
 
Revenues before
certain items
increase/(decrease)
 (In millions, except percentages)
Source and Transportation Activities$(27) (8)% $(36) (9)%
Oil and Gas Producing Activities(196) (24)% (241) (20)%
Intrasegment Eliminations—
 —% 10
 21%
Total CO2$(223) (20)% $(267) (17)%

The changes in Segment EBDA for our CO2 business segment are further explained by the significant factors driving Segment EBDA before certain items in the comparable years of 2016 and 2015 which factors include lower revenues of $205 million from lower commodity prices and $72 million due to decreased volumes, partially offset by (i) $27 million in reduced operating costs; (ii) $15 million of lower severance and ad valorem tax expenses; and (iii) $11 million primarily related to increased earnings from an equity investee.





Terminals
 Year Ended December 31,
 2017 2016 2015
 (In millions, except operating statistics)
Revenues(a)$1,966
 $1,922
 $1,879
Operating expenses(b)(788) (768) (836)
Gain (loss) on impairments and divestitures, net(c)14
 (99) (191)
Other income—
 —
 1
Earnings from equity investments(d)24
 35
 21
Loss on impairments and divestitures of equity investments, net(e)—
 (16) (4)
Other, net8
 4
 8
Segment EBDA(a)(b)(c)(d)(e)1,224
 1,078
 878
Certain items, net(a)(b)(c)(d)(e)(10) 91
 206
Segment EBDA before certain items$1,214
 $1,169
 $1,084
      
Change from prior periodIncrease/(Decrease)  
Revenues before certain items$68
 $38
  
Segment EBDA before certain items$45
 $85
  
      
Bulk transload tonnage (MMtons)59.5
 54.8
 55.6
Ethanol (MMBbl)68.1
 66.7
 63.1
Liquids leaseable capacity (MMBbl)87.9
 84.7
 78.6
Liquids utilization %(f)93.6% 94.7% 94.6%
_______
Certain items affecting Segment EBDA
(a)2017, 2016 and 2015 amounts include increases in revenues of $9 million, $28 million and $23 million, respectively, from the amortization of a fair value adjustment (associated with the below market contracts assumed upon acquisition) from our Jones Act tankers. 2017 amount also includes a decrease in revenues of $5 million related to other certain items.
(b)2017 amount includes (i) an increase in expense of $21 million related to hurricane repairs; (ii) a decrease in expense of $10 million related to accrued dredging costs; and (iii) a decrease in expense of $2 million related to other certain items. 2016 amount includes an increase in expense of $3 million related to other certain items. 2015 amount includes a $34 million increase in bad debt expense due to certain coal customers bankruptcies related to revenues recognized in prior years but not yet collected and an increase in expense of $2 million related to other certain items.
(c)2017 amount includes a gain of $23 million primarily related to the sale of a 40% membership interest in the Deeprock Development joint venture in July 2017 and losses of $8 million related to other impairments and divestitures, net. 2016 amount includes an expense of $109 million related to various losses on impairments and divestitures, net. 2015 amount includes a $175 million non-cash pre-tax impairment of a terminal facility reflecting the impact of an agreement to adjust certain payment terms under a contract with a coal customer and $14 million related to other losses on impairments and divestitures, net.
(d)2016 amount includes an increase in earnings of $9 million related to our share of the settlement of a certain litigation matter at an equity investee. 2015 amount includes a decrease in earnings of $4 million related to a non-cash impairment at an equity investee.
(e)2016 amount includes $16 million related to various losses on impairments and divestitures of equity investments, net.
Other
(f)The ratio of our actual leased capacity to our estimated capacity.

Below are the changes in both Segment EBDA before certain items and revenues before certain items in 2017 and 2016, when compared with the respective prior year: 

Year Ended December 31, 2017 versus Year Ended December 31, 2016

 
Segment EBDA before certain items
increase/(decrease)
 
Revenues before
certain items
increase/(decrease)
 (In millions, except percentages)
Marine Operations$42
 27% $72
 31%
Gulf Liquids20
 8% 38
 11%
Alberta, Canada8
 6% 7
 5%
Midwest7
 11% 15
 11%
Held for sale operations(19) (100)% (55) (90)%
Gulf Central(17) (16)% (11) (8)%
All others (including intrasegment eliminations)4
 1% 2
 —%
Total Terminals$45
 4% $68
 4%

The changes in Segment EBDA for our Terminals business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 2017 and 2016:
increase of $42 million (27%) from our Marine Operations related to the incremental earnings from the May 2016, July 2016, September 2016, December 2016, March 2017, June 2017, July 2017 and December 2017 deliveries of the Jones Act tankers, the Magnolia State, Garden State, Bay State, American Endurance, American Freedom, Palmetto State, American Liberty and American Pride, respectively, partially offset by decreased charter rates on the Golden State, Pelican State, Sunshine State, Empire State and Pennsylvania Jones Act tankers;
increase of $20 million (8%) from our Gulf Liquids terminals primarily related to higher volumes as a result of various expansion projects, including the recently commissioned Kinder Morgan Export Terminal and North Docks terminal, partially offset by lost revenue associated with Hurricane Harvey-related operational disruptions;
increase of $8 million (6%) from our Alberta, Canada terminals primarily due to escalations in predominantly fixed, take-or-pay terminaling contracts and a true-up in terminal fees in connection with a favorable arbitration ruling;
increase of $7 million (11%) from our Midwest terminals primarily driven by increased ethanol throughput revenues in 2017 and a new bulk storage and handling contract entered into fourth quarter 2016;
decrease of $19 million (100%) from our sale of certain bulk terminal facilities to an affiliate of Watco Companies, LLC in December 2016 and early 2017; and
decrease of $17 million (16%) from our Gulf Central terminals primarily related to the sale of a 40% membership interest in the Deeprock Development joint venture in July 2017 and the subsequent change in accounting treatment of our retained 11% membership interest as well as lost revenue associated with Hurricane Harvey-related operational disruptions.



Year Ended December 31, 2016 versus Year Ended December 31, 2015


 
Segment EBDA before certain items
increase/(decrease)
 
Revenues before
certain items
increase/(decrease)
 (In millions, except percentages)
Marine Operations$52
 51% $73
 46%
Alberta, Canada14
 12% 19
 14%
Gulf Liquids14
 6% 18
 5%
Northeast11
 10% 19
 10%
Lower River4
 7% (12) (9)%
Gulf Bulk(13) (17)% (50) (29)%
Held for sale operations(2) (67)% (18) (100)%
All others (including intrasegment eliminations)5
 1% (11) (2)%
Total Terminals$85
 8% $38
 2%

The changes in Segment EBDA for our Terminals business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 2016 and 2015:
increase of $52 million (51%) from our Marine Operations related to the incremental earnings from the December 2015, May 2016, July 2016, September 2016 and December 2016 in-service of the Jones Act tankers the Lone Star State,Magnolia State,Garden State,Bay State,and American Endurance, respectively, and increased charter rates on the Empire State Jones Act tanker;
increase of $14 million (12%) from our Alberta, Canada terminals, driven by a full year of earnings from our Edmonton South rail terminal joint venture expansion, which began operations in second quarter 2015;
increase of $14 million (6%) from our Gulf Liquids terminals, primarily related to higher volumes as a result of various expansion projects, including marine infrastructure improvements at our Galena Park and North Docks terminals, as well as higher rates and ancillary service activities on existing business;
increase of $11 million (10%) from our Northeast terminals, primarily due to contributions from two terminals acquired as part of the BP Products North America Inc. acquisition which was completed in February 2016;
increase of $4 million (7%) from our Lower River terminals, due to a $15 million write-off of certain coal customers accounts receivable which occurred in 2015 and favorable results from certain Lower River terminals, partially offset by decreased revenues and earnings of $18 million due to certain coal customer bankruptcies;
decrease of $13 million (17%) from our Gulf Bulk terminals, driven by decreased revenues and earnings of $41 million due to certain coal customer bankruptcies offset by a $28 million write-off of a certain coal customer’s accounts receivable which occurred in the fourth quarter of 2015;
decrease of $2 million (67%) from our sale of certain bulk and transload terminal facilities to Watco Companies, LLC in early 2015; and
included in “All others” is a decrease in revenues and earnings of $11 million due to certain coal customer bankruptcies as compared to a $4 million write-off of certain coal customers accounts receivable which occurred in 2015.















Products Pipelines
 Year Ended December 31,
 2017 2016 2015
 (In millions, except operating statistics)
Revenues$1,661
 $1,649
 $1,831
Operating expenses(a)(487) (573) (772)
Loss on impairments and divestitures, net(b)—
 (76) —
Other (expense) income—
 —
 (2)
Earnings from equity investments(c)58
 53
 45
Gain on divestiture of equity investment(d)—
 12
 —
Other, net(1) 2
 4
Segment EBDA(a)(b)(c)(d)1,231
 1,067
 1,106
Certain items(a)(b)(c)(d)(38) 113
 (4)
Segment EBDA before certain items$1,193
 $1,180
 $1,102
      
Change from prior periodIncrease/(Decrease)  
Revenues before certain items$12
 $(182)  
Segment EBDA before certain items$13
 $78
  
      
Gasoline (MBbl/d) (e)1,038
 1,025
 1,011
Diesel fuel (MBbl/d)351
 342
 354
Jet fuel (MBbl/d)297
 288
 282
Total refined product volumes (MBbl/d)(f)1,686
 1,655
 1,647
NGL (MBbl/d)(f)112
 109
 106
Condensate (MBbl/d)(f)327
 324
 273
Total delivery volumes (MBbl/d)2,125
 2,088
 2,026
Ethanol (MBbl/d)(g)                                                                                    117
 115
 113
_______
Certain items affecting Segment EBDA
(a)2017 amount includes a decrease in expense of $34 million related to a right-of-way settlement and an increase in expense of $1 million related to hurricane repairs. 2016 amount includes increases in expense of $31 million of rate case liability estimate adjustments associated with prior periods and $20 million related to a legal settlement. 2015 amount includes a $4 million decrease in expense associated with a certain Pacific operations litigation matter.
(b)2016 amount includes increases in expense of $65 million related to the Palmetto project write-off and $9 million of non-cash impairment charges related to the sale of a Transmix facility.
(c)2017 amount includes an increase in equity earnings of $5 million related to the impact of the 2017 Tax Reform at an equity investee.
(d)2016 amount includes a $12 million gain related to the sale of an equity investment.
Other
(e)Volumes include ethanol pipeline volumes.
(f)Joint Venture throughput is reported at our ownership share.
(g)Represents total ethanol volumes, including ethanol pipeline volumes included in gasoline volumes above.


Below are the changes in both Segment EBDA before certain items and revenues before certain items in 2017 and 2016, when compared with the respective prior year:

Year Ended December 31, 2017 versus Year Ended December 31, 2016

 
Segment EBDA before certain items
increase/(decrease)
 
Revenues before
certain items
increase/(decrease)
 (In millions, except percentages)
Pacific operations$5
 1% $11
 2%
South East Terminals4
 5% 6
 5%
Calnev3
 6% 2
 3%
Double Eagle3
 30% 2
 40%
Transmix1
 3% (14) (6)%
Parkway(3) (100)% (1) (100)%
All others (including eliminations)—
 —% 6
 1%
Total Products Pipelines$13
 1% $12
 1%

The changes in Segment EBDA for our Products Pipelines business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 2017 and 2016:
increase of $5 million (1%) from Pacific operations primarily due to higher service revenues driven by an increase in volumes partially offset by a volume driven increase in power costs and an increase in right-of-way expense;
increase of $4 million (5%) from our South East Terminals primarily due to higher revenues driven by higher volumes as a result of capital expansion projects being placed in service during 2017;
increase of $3 million (6%) from Calnev primarily due to higher service revenues driven by higher volumes and a decrease in expense related to the reduction of a rate reserve;
increase of $3 million (30%) from Double Eagle primarily due to higher revenues driven by higher volumes and price;
increase of $1 million (3%) from our Transmix processing operations. The decrease in revenues of $14 million and associated decrease in costs of goods sold were driven by lower sales volumes primarily due to the sale of our Indianola plant in August 2016 and lower brokered sales at the Dorsey plant due to an expired contract in May 2017; and
decrease of $3 million (100%) from Parkway pipeline due to our sale of our 50% interest in Parkway pipeline on July 1, 2016.
Year Ended December 31, 2016 versus Year Ended December 31, 2015

 
Segment EBDA before certain items
increase/(decrease)
 
Revenues before
certain items
increase/(decrease)
 (In millions, except percentages)
Crude & Condensate Pipeline$37
 20% $36
 18%
KMCC - Splitter20
 53% 30
 71%
Double H pipeline15
 34% 22
 39%
Plantation Pipe Line9
 17% 1
 5%
Transmix8
 26% (286) (57)%
Cochin(13) (11)% 3
 2%
All others (including eliminations)2
 —% 12
 1%
Total Products Pipelines$78
 7% $(182) (10)%


The changes in Segment EBDA for our Products Pipelines business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 2016 and 2015:
increase of $37 million (20%) from Kinder Morgan Crude & Condensate Pipeline driven primarily by an increase in pipeline throughput volumeslower 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 existing customersderivatives.

Operations and additional volumes associated with expansion projects;Maintenance
increase of $20 million (53%) from our KMCC - Splitter due to first
Operations and second phases being in full operation for 2016. Start up of first phase was in March 2015 and second phase was in July 2015;
increase of $15 million (34%) due to full year of results from our Double H pipeline, which began operations in March 2015;
increase of $9 million (17%) from our equity investment in Plantation Pipe Line primarily due to lower operating costs;
increase of $8 million (26%) from our Transmix processing operations largely due to unfavorable market price impacts during the fourth quarter of 2015. The decrease in revenues of $286 million and associated decrease in costs of goods sold were driven by lower sales volumes primarily due to the sale of our Indianola plant in August 2016; and
decrease of $13 million (11%) from Cochin primarily due to higher pipeline integrity costs.

Kinder Morgan Canada
 Year Ended December 31,
 2017 2016 2015
 (In millions, except operating statistics)
Revenues$256
 $253
 $260
Operating expenses(95) (87) (87)
Other income—
 —
 1
Other, net25
 15
 8
Segment EBDA$186
 $181
 $182
      
Change from prior periodIncrease/(Decrease)  
Revenues$3
 $(7)  
Segment EBDA$5
 $(1)  
      
Transport volumes (MBbl/d)(a)308
 316
 316
______
(a)Represents Trans Mountain pipeline system volumes.
For the comparable years of 2017 and 2016, the Kinder Morgan Canada business segment had an increase in Segment EBDA of $5 million (3%) and an increase in revenues of $3 million (1%) primarily due to (i) higher capitalized equity financing costs due to spending on the TMEP; (ii) currency translation gains due to the strengthening of the Canadian dollar; and (iii) higher incentive revenues partly offset by lower state of Washington volumes and operating expense timing changes.

For the comparable years of 2016 and 2015, the Kinder Morgan Canada business segment had a decrease in Segment EBDA of $1 million (1%) and a decrease in revenues of $7 million (3%).


General and Administrative, Interest, Corporate and Noncontrolling Interests
 Year Ended December 31,
 2017 2016 2015
 (In millions)
General and administrative and corporate charges(a)$660
 $652
 $708
Certain items(a)(15) 13
 (60)
General and administrative and corporate charges before certain items$645
 $665
 $648
      
Interest, net(b)$1,832
 $1,806
 $2,051
Certain items(b)39
 193
 27
Interest, net, before certain items$1,871
 $1,999
 $2,078
      
Net income (loss) attributable to noncontrolling interests(c)$40
 $13
 $(45)
Noncontrolling interests associated with certain items(c)—
 8
 63
Net income attributable to noncontrolling interests before certain items$40
 $21
 $18
_______
Certain items
(a)2017 amount includes (i) an increase in expense of $10 million for acquisition and divestiture related costs; (ii) an increase in expense of $4 million related to certain corporate litigation matters; (iii) an increase in expense of $5 million related to a pension settlement; and (iv) decrease in expense of $4 million related to other certain items. 2016 amount includes increases in expense of (i) $14 million related to severance costs; and (ii) $12 million related to acquisition and divestiture costs; offset by decreases in expense of (i) $34 million related to certain corporate litigation matters; and (ii) $5 million related to other certain items. 2015 amount includes increases in expense of (i) $71 million related to certain corporate legal matters; (ii) $15 million related to costs associated with acquisitions; and (iii) $9 million associated with other certain items; offset by a decrease in expense of $35 million related to pension credit income.
(b)2017, 2016 and 2015 amounts include (i) decreases in interest expense of $44 million, $115 million and $71 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions and (ii) decreases of $3 million and $44 million and an increase of $23 million, respectively, in interest expense primarily related to non-cash true-ups of our estimates of swap ineffectiveness. 2017 amount also includes an $8 million increase in interest expense related to other certain items. 2016 and 2015 amounts also include a $34 million decrease and a $21 million increase, respectively, in interest expense related to certain litigation matters.
(c)Amounts reflect the noncontrolling interest portion of certain items including (i) a $49 million loss for 2015 associated with Terminals segment certain items and disclosed above in “—Terminals” and (ii) an $8 million loss for 2016 and a $14 million loss for 2015 associated with Natural Gas Pipelines segment certain items and disclosed above in “—Natural Gas Pipelines.”

General and administrative expenses and corporate charges before certain items decreased $20maintenance increased $152 million in 2017 and increased $17 million in 2016 when compared with the respective prior year. The decrease in 2017 as2023 compared to 2016 was primarily driven by the sale of a 50% interest in our SNG natural gas pipeline system (effective September 1, 2016), higher capitalized costs, lower state franchise taxes, legal and insurance costs, partially offset by higher labor accruals and pension costs. 2022. The increase in 2016 as compared to 2015 was primarily driven by higher benefitlabor and other expenses, including integrity costs higher corporate charges and lower capitalizedservices, fuel costs and materials and supplies, related to greater activity levels and inflation, partially offset by lower labor, outside services and insurance costs.legal costs due to a legal reserve established in the 2022 period associated with the EPNG pipeline rupture.


Other Income (Expense)

Interest, net

In the table above, we report our interest expense as “net,” meaning that we have subtracted interest income and capitalized interest from our total interest expense to arrive at one interest amount.  Our consolidated interest expense, net of interest income before certain items, decreased $128net increased $284 million in 2017 and $792023 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 2016, respectively, when2023 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 respective prior year. bankruptcy settlement involving our former equity investee, Ruby.

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Non-GAAP Financial Measures

Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Kinder Morgan, Inc.
Year Ended December 31,
20232022
(In millions, except per share amounts)
Net income attributable to Kinder Morgan, Inc.$2,391 $2,548 
Certain Items(a)
Fair value amortization— (15)
Legal, environmental and other reserves— 51 
Change in fair value of derivative contracts(126)57 
Loss on impairment67 — 
Income tax Certain Items33 (37)
Other45 32 
Total Certain Items19 88 
Adjusted Net Income Attributable to Kinder Morgan, Inc.$2,410 $2,636 
Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Common Stock
Net income attributable to Kinder Morgan, Inc.$2,391 $2,548 
Total Certain Items(b)19 88 
Net income allocated to participating securities(c)(14)(13)
Other(d)— (1)
Adjusted Net Income Attributable to Common Stock$2,396 $2,622 
Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF
Net income attributable to Kinder Morgan, Inc.$2,391 $2,548 
Total Certain Items(b)19 88 
DD&A2,250 2,186 
Amortization of excess cost of equity investments66 75 
Income tax expense(e)682 747 
Cash taxes(11)(13)
Sustaining capital expenditures(868)(761)
Amounts from joint ventures
Unconsolidated joint venture DD&A323 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 expenditures9 8 
Other items(h)67 (38)
DCF$4,715 $4,970 
Adjusted EPS$1.07 $1.16 
Weighted average shares outstanding for dividends(i)2,247 2,271 
DCF per share$2.10 $2.19 
Declared dividends per share$1.13 $1.11 
(a)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.
48

(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 EBITDA
Year Ended December 31,
20232022
(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 impairment67 — 
Income tax Certain Items33 (37)
Other45 32 
Total Certain Items19 88 
DD&A2,250 2,186 
Amortization of excess cost of equity investments66 75 
Income tax expense(b)682 747 
Interest, net(c)1,804 1,524 
Amounts from joint ventures
Unconsolidated joint venture DD&A323 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—Certain Items” above.
(c)To avoid duplication, adjustments for interest, net for 2023 and 2022 exclude $(7) million and $(11) million, respectively, which amounts are already included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items,” above.
(d)Includes that tax provision on Certain Items recognized by the investees that are taxable entities associated with our Citrus, NGPL Holdings and Products (SE) Pipe Line equity investments. The impact of KMI’s income tax provision on Certain Items affecting earnings from equity investments is included within “Certain Items” above.


49

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,
20232022
(In millions)
Adjusted Net Income Attributable to Kinder Morgan, Inc.$2,410 $2,636 
DCF4,715 4,970 
Adjusted EBITDA7,561 7,516 
Change from prior periodIncrease/(Decrease)
Adjusted Net Income Attributable to Kinder Morgan, Inc.$(226)
DCF$(255)
Adjusted EBITDA$45 

Adjusted Net Income Attributable to Kinder Morgan, Inc. decreased $226 million in 2023 compared to 2022. The decrease inwas primarily driven by higher interest expense. Higher interest expense also affected DCF. The$255 million decrease in 2017 asDCF in 2023 compared to 20162022 was further impacted by an increase in sustaining capital expenditures. Adjusted EBITDA increased $45 million in 2023 compared to 2022. The increase was due to favorable margins from settled derivatives on our Natural Gas Pipeline business segment partially offset by overall lower commodity prices across our business segments.

General and Administrative and Corporate Charges

Year Ended December 31,
20232022
(In millions)
General and administrative$(668)$(637)
Corporate (charges) benefit, net(91)44 
Certain Items45 6 
General and administrative and corporate charges$(714)$(587)
Change from prior periodEarnings increase/(decrease)
General and administrative$(31)
Corporate (charges) benefit, net(135)
Total$(166)

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

50

Reconciliation of Segment EBDA to Adjusted Segment EBDA
Year Ended December 31,
20232022
(In millions)
Segment EBDA(a)
Natural Gas Pipelines Segment EBDA$5,282 $4,801 
Certain Items(b)
Legal, environmental and other reserves— 51 
Change in fair value of derivative contracts(122)64 
Other— 26 
Natural Gas Pipelines Adjusted Segment EBDA$5,160 $4,942 
Products Pipelines Segment EBDA$1,062 $1,107 
Certain Items(b)
Change in fair value of derivative contracts(1)— 
Loss on impairment67 — 
Products Pipelines Adjusted Segment EBDA$1,128 $1,107 
Terminals Segment EBDA$1,040 $975 
CO2 Segment EBDA
$689 $819 
Certain Items(b)
Change in fair value of derivative contracts4 (11)
CO2 Adjusted Segment EBDA
$693 $808 
(a)Includes revenues, earnings from equity investments, operating expenses, gain on divestitures and impairments, net, other (expense) income, net, and other, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes. See “—Overview—GAAP Financial Measures” above.
(b)See “—Overview—Non-GAAP Financial Measures—Certain Items” above.
51

Segment Earnings Results

Natural Gas Pipelines
 Year Ended December 31,
 20232022
 (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, net10 10 
Other income2 3 
Earnings from equity investments776 683 
Other, net26 (19)
Segment EBDA5,282 4,801 
Certain Items:
Legal, environmental and other reserves— 51 
Change in fair value of derivative contracts(122)64 
Other— 26 
Certain Items(a)(122)141 
Adjusted Segment EBDA$5,160 $4,942 
Change from prior periodIncrease/(Decrease)
Segment EBDA$481 
Adjusted Segment EBDA$218 
Volumetric data(b)
Transport volumes (BBtu/d)40,282 38,657 
Sales volumes (BBtu/d)2,346 2,482 
Gathering volumes (BBtu/d)3,562 2,994 
NGLs (MBbl/d)34 30 
(a)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.

52

Below are the changes in Natural Gas Pipelines Segment EBDA:

Year Ended December 31,
 20232022increase/(decrease)
 (In millions)
Midstream$1,697 $1,441 $256 
East2,637 2,502 135 
West948 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.

Overall, Midstream’s revenue changes are partially offset by corresponding changes in costs of sales.

•The $135 million (5%) increase in East was primarily due 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 to 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.


53

Products Pipelines
 Year Ended December 31,
 20232022
 (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 investments23 68 
Other, net1 — 
Segment EBDA1,062 1,107 
Certain Items:
Change in fair value of derivative contracts(1)— 
Loss on impairment67 — 
Certain Items(a)66 — 
Adjusted Segment EBDA$1,128 $1,107 
Change from prior periodIncrease/(Decrease)
Segment EBDA$(45)
Adjusted Segment EBDA$21 
Volumetric data(b)
Gasoline(c)980 978 
Diesel fuel351 367 
Jet fuel285 264 
Total refined product volumes1,616 1,609 
Crude and condensate483 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 and 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.

54

Below are the changes in Products Pipelines Segment EBDA:

Year Ended December 31,
 20232022increase/(decrease)
 (In millions)
Crude and Condensate$265 $331 $(66)
Southeast Refined Products278 265 13 
West Coast Refined Products519 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.

55

Terminals
 Year Ended December 31,
 20232022
 (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, net19
Other income15
Earnings from equity investments914
Other, net88
Segment EBDA$1,040$975
Change from prior periodIncrease/(Decrease)
Segment EBDA$65 
Volumetric data(a)
Liquids leasable capacity (MMBbl)78.7 78.2 
Liquids utilization %(b)93.6 %91.3 %
Bulk transload tonnage (MMtons)53.3 53.2 
(a)Volumes for facilities divested, idled, and/or held for sale are excluded for all periods presented.
(b)The ratio of our tankage capacity in service to liquids leasable capacity.

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

Below are the changes in Terminals Segment EBDA:

Year Ended December 31,
 20232022increase/(decrease)
 (In millions)
Jones Act tankers$177 $146 $31 
Liquids601 573 28 
Bulk256 243 13 
Other6 13 (7)
Total Terminals$1,040 $975 $65 

The changes in Terminals Segment EBDA in the comparable years of 2023 and 2022 are explained by the following discussion:
•The $31 million (21%) increase in Jones Act tankers was primarily due to higher average charter rates.

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

56

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

CO2
 Year Ended December 31,
 20232022
 (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, net1 1 
Other expense(1)— 
Earnings from equity investments30 38 
Segment EBDA689 819 
Certain Items:
Change in fair value of derivative contracts4 (11)
Certain Items(a)4 (11)
Adjusted Segment EBDA$693 $808 
Change from prior periodIncrease/(Decrease)
Segment EBDA$(130)
Adjusted Segment EBDA$(115)
Volumetric data(b)
SACROC oil production(c)20.22 20.29 
Yates oil production6.63 6.52 
Other2.32 2.75 
Total oil production, net (MBbl/d)(d)29.17 29.56 
NGL sales volumes, net (MBbl/d)(d)8.97 9.40 
CO2 sales volumes, net (Bcf/d)
0.336 0.358 
RNG sales volumes (BBtu/d)6 3 
Realized weighted average oil price ($ per Bbl)$67.42 $66.78 
Realized weighted average NGL price ($ per Bbl)$30.84 $39.59 
(a)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 more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.
(b)Volumes for acquired assets are included for all periods presented, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition.
(c)Includes volumetric data for Diamond M.
(d)Net of royalties and outside working interests.

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Below are the changes in CO2 Segment EBDA:

Year Ended December 31,
 20232022increase/(decrease)
 (In millions)
Oil and Gas Producing activities$473 $553 $(80)
Source and Transportation activities187 247 (60)
Subtotal660 800 (140)
Energy Transition Ventures activities29 19 10 
Total CO2
$689 $819 $(130)
The changes in CO2 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 weighted average debt balances as proceeds from the May 2017 KML IPOrevenues related to lower CO2 sales prices and our September 2016 sale of a 50% interestvolumes.

•The $10 million (53%) increase in SNG were used to pay down debt, partially offset by a slightly higher overall weighted average interest rate on our outstanding debt. The decrease in interest expense in 2016 as compared to 2015Energy Transition Ventures activities was primarily duedriven by three additional plants placed into service during 2023 leading to lower weighted average debt balances, partially offset by a slightly higher overall weighted average interest rate on our outstanding debt.

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 both December 31, 2017 and 2016, approximately 28% of our debt balances (excluding debt fair value adjustments) 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. For more information on our interest rate swaps, see Note 14 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements.


Net income attributable to noncontrolling interests, represents the allocation of our consolidated net income attributable to all outstanding ownership interests in our consolidated subsidiaries that are not held by us.  Net income attributable to noncontrolling interests before certain items for 2017 as compared to 2016 increased $19 million (90%) due to the May 30, 2017 sale of approximately 30% of our Canadian business operations to the public in the KML IPO. The portion of our Canadian business operations net income attributable to the public is now reflected in “Net income attributable to noncontrolling interests.” Net income attributable to noncontrolling interests before certain items for 2016 as compared to 2015 increased $3 million (17%).

Income Taxes
Year Ended December 31, 2017 versus Year Ended December 31, 2016

Our tax expense for the year ended December 31, 2017 is approximately $1,938 million, as compared with 2016 tax expense of $917 million.  The $1,021 million increase in tax expense is primarily due to (i) an increase in year-over-year earningsRNG margins as a result of fewer asset impairments and project write-offs in 2017 and (ii) higher tax expense as a result of the 2017 Tax Reform. These increases arevolumes, partially offset by (i)higher operating expenses.

We believe that our existing hedge contracts in place within our CO2 business segment substantially mitigate commodity price sensitivities in the 2016 impactnear-term and to lesser extent over the following few years from price exposure. Below is a summary of our Regulated Natural Gas Pipeline segment’s $817 million non-tax-deductible goodwillCO2 business segment hedges outstanding as a result of the sale of a 50% interest in SNG; and (ii) the recognition of enhanced oil recovery credits.

Year Ended December 31, 2016 versus Year Ended December 31, 20152023.


Our tax expense for the year ended December 31, 2016 is approximately $917 million, as compared with 2015 tax expense of $564 million.  The $353 million increase in tax expense is primarily due to (i) an increase in our earnings as a result of lower impairments in 2016; (ii) the year over year increase in the deferred state tax expense as a result of our sale of a 50% interest in SNG in 2016 and the Hiland acquisition in 2015; and (iii) valuation allowances recorded in 2016 for foreign tax credits and capital loss carryforwards for which we do not expect to recognize any future tax benefits. These increases are partially offset by adjustments to our income tax reserve for uncertain tax positions.
20242025202620272028
Crude Oil(a)
Price ($ 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

General

As of December 31, 2017,2023, we had $264$83 million of “Cash and cash equivalents,” a decrease of $420$662 million (61%) from December 31, 2016.  We2022. 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 (discussed below in “—Short-term Liquidity”), and our cash flows from operating activities areis more than adequate to allow us to manage our day-to-day cash requirements and anticipated obligations as discussed further below.obligations.


We have consistently generated substantial cash flow from operations, providing a source of funds of $4,601$6,491 million and $4,795$4,967 million in 20172023 and 2016,2022, respectively. The year-to-year decreaseincrease is discussed below in “Cash“—Cash Flows—Operating Activities.” We have primarily reliedrely on cash provided fromby operations to fund our operations as well as our debt service, sustaining capital expenditures, dividend payments and during the last two years, our growth capital expenditures.

We expect KMLexpenditures; however, we may access the debt capital markets from time to fund the TMEP’s capital expenditures and its other capital expenditures through (i) additional borrowings on KML’s Credit Facility; (ii) the additional issuance of KML preferred shares; (iii) the issuance of additional KML restricted voting stock; (iv) the issuance of KML long-term notes payable; and (v) KML’s retained cash flow from operations or a combination of the above. KML established a dividend policy on its restricted voting shares pursuanttime to which it will pay its quarterly dividend in an amount based on a portion of its DCF discussed below in “—Noncontrolling interests—KML Restricted Voting Share Dividends.”

On June 16, 2017, KML’s indirect subsidiaries, Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC, entered into a definitive credit agreement establishing (i) a C$4.0 billion revolving construction facility for the purposes of funding the development, construction and completion of the TMEP; (ii) a C$1.0 billion revolving contingent credit facility for the purpose of funding, if necessary, additional TMEP costs (and, subject to the need to fund such additional costs and regulatory approval, meeting the Canadian NEB-mandated liquidity requirements); and (iii) a C$500 million revolving working capital facility, to be used for working capital and other general corporate purposes (collectively, the “KML Credit Facility”). On January 23, 2018, KML entered into an agreement amending certain terms of its Credit Facility to, among other things, provide additional funding certainty with respect to each tranche of its Credit Facility. The KML Credit Facility has a five-year term and is with a syndicate of financial institutions with Royal Bank of Canada as the administrative agent. As of December 31, 2017, KML had no amounts outstanding under the KML Credit Facility and C$53 million (U.S.$42 million) in letters of credit. In addition,

KML received C$537 million (U.S.$420 million) of net proceeds from the issuance of Series 1 Preferred Shares in August 2017 and Series 3 Preferred Shares in December 2017.

Generally, we expect that our short-term liquidity needs will be met primarily through retained cash from operations, short-term borrowings or by issuing new long-term debt to refinance certain of our maturing long-term debt obligations. We also expect that KMI’s current common stock dividend level will allow usand finance incremental investments, if any. From time to use retained cash to fund our growth projects and the previously mentioned share repurchase program in 2018. Moreover, as a result of KMI’s current common stock dividend policy and by continuing to focus on allocating capital to high return opportunities, we do not expect the need to access the equity capital markets to fund our other growth projects for the foreseeable future.

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.

As of December 31, 2017, our short-term corporate debt ratings were A-3, Prime-3 and F3 at Standard and Poor’s, Moody’s Investor Services and Fitch Ratings, Inc., respectively.

The following table represents KMI’s and KMP’s senior unsecured debt ratings as of December 31, 2017.time,
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Rating agencySenior debt ratingDate of last changeOutlook
Standard and Poor’sBBB-November 20, 2014Stable
Moody’s Investor ServicesBaa3November 21, 2014Stable
Fitch Ratings, Inc.BBB-November 20, 2014Stable

Short-term Liquidity

As of December 31, 2017, our principal sources of short-term liquidity are (i) our $5.0 billion revolving credit facility and associated $4.0 billion commercial paper program; (ii) the KML Credit Facility (for the purposes described above); and (iii) cash from operations. The loan commitments under our revolving credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Borrowings under our commercial paper program and letters of credit reduce borrowings allowed under ours and KML’s respective credit facilities. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facility and, as previously discussed, we have consistently generated strong cash flows from operations.

As of December 31, 2017, our $2,828 million of short-term debt consisted primarily of (i) $125 million outstanding borrowings under the KMI $5.0 billion revolving credit facility; (ii) $240 million outstanding under our $4.0 billion commercial paper program; and (iii) $2,284 million of senior notes that mature in the next year. We intend to refinance our short-term debt through credit facility borrowings, commercial paper borrowings, or by issuing new long-term debt or paying down short-term debt using cash retained from operations. Our short-term debt balance as of December 31, 2016 was $2,696 million.
We had working capital (defined as current assets less current liabilities) deficits of $3,466 million and $2,695 million as of December 31, 2017 and 2016, respectively. Our current liabilities may include 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 Liquidity

As 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 $771$1,552 million (29%) unfavorable change from year-end 20162022 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 restricted deposits, andcash 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 increaseunfavorable 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 portionassets, primarily in exchange gas receivables and regulatory assets; partially offset by favorable net short-term fair value adjustments of long-term debt$155 million on derivative contract assets and accounts payable.liabilities in 2023. Generally, our working capital balance 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”Financing” and “— “—Capital Expenditures”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.


Certain of
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Credit Ratings and Capital Market Liquidity

We believe that our wholly owned subsidiariescapital 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 FERC-enacted reporting requirements for oilcertain 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 natural gas pipeline companies that participate in cash management programs. FERC-regulated entities subjectcould limit our access to these rules must, among other things, place their cash management agreements in writing, maintain current copiescapital.

The following table represents our debt ratings as of the documents authorizing and supporting their cash management agreements, and file documentation establishing the cash management program with the FERC.December 31, 2023.
Rating agencyShort-term ratingLong-term ratingOutlook
Standard and Poor’sA-2BBBStable
Moody’s Investor ServicesPrime-2Baa2Stable
Fitch Ratings, Inc.F2BBBStable

Long-term Financing


Our equity consists of Class P common stock and mandatory convertible preferred stock each with a par value of $0.01 per share. We have in place an equity distribution agreement which allows us to issue and sell through or to our sales agents and/or principals shares of our Class P common stock. However, with the exception of the issuance of KML preferred equity and/or common equity to partially finance the TMEP or other KML capital expenditures, we do not expect theto need to access the equity capital markets to fund our growth projectsdiscretionary capital investments for the foreseeable future. Furthermore, we began repurchasing shares of our Class P common stock under a $2 billion share buy-back program in December 2017 that we intend to fund through retained cash. For more information on our equity buy-back programSee also “—Dividends and our equity distribution agreement, see Note 11 “Stockholders’ Equity”Stock Buy-back Program” below for additional discussion related to our consolidated financial statements.dividends and stock buy-back program.


From time to time, we issue long-term debt securities, often referred to as senior notes.  All of ourOur 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 have issuedissue 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 we each guarantee the debt ofparty guarantees each other.other party’s debt. See Note 19 “Guarantee“—Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries” to our consolidated financial statements.Subsidiaries.” As of December 31, 20172023 and 2016,2022, the aggregate principal amount outstanding of our various long-term debt obligations (excluding current maturities) was $34,088$27,880 million and $36,205$28,288 million, respectively. For more information regarding our debt-related transactions in 2017, see Note 9 “Debt”

We use interest rate swap agreements to convert a portion of the underlying cash flows related to our consolidated financial statements.

We achieve our variable rate exposure primarily by issuing long-term fixed rate debt and then swapping the fixed rate interest payments forsecurities (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 payments andrates—either as short-term or long-term variable-rate debt obligations or as fixed-rate debt converted to variable rates through the issuanceuse of interest rate swaps. The December 31, 2023 amount includes $1,989 million of commercial paper or credit facility borrowings.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 2017,2023, 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 statements and Item 7A “Quantitative7A. “Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.Risk.”


Capital Expenditures

We account for our capital expenditures in accordance with GAAP. We alsoAdditionally, we distinguish between capital expenditures that are maintenance/sustainingas follows:
Type of ExpenditurePhysical Determination of Expenditure
Sustaining capital expenditures
•Investments to maintain the operational integrity and extend the useful life of our assets
Expansion capital expenditures (discretionary capital expenditures)
•Investments to expand throughput or capacity from that which existed immediately prior to the making or acquisition of additions or improvements

Budgeting of maintenance capital expenditures, and those that are expansion capital expenditures (whichwhich we also refer to as discretionary capital expenditures). Expansion capital expenditures are those expenditures which increase throughput or capacity from that which existed immediately prior to the addition or improvement, and are not deducted in calculating DCF (see “Results of Operations—DCF”). With respect to our oil and gas producing activities, we classify a capital expenditure as an expansion capital expenditure if it is expected to increase capacity or throughput (i.e. production capacity) from the capacity or throughput immediately prior to the making or acquisition of such additions or improvements. Maintenance capital expenditures are those which maintain throughput or capacity. The distinction between maintenance and expansion capital expenditures is a physical determination rather than an economic one, irrespective of the amount by which the throughput or capacity is increased.

Budgeting of maintenancesustaining capital expenditures, is done annually on a bottom-up basis. For each of our assets, we budget for and make those maintenancesustaining 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 maintenancesustaining 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 are generally madeoccurs 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 maintenance/sustaining or as expansion capital expenditures is made on a project level. The classification of our capital expenditures as expansion capital expenditures or as maintenancesustaining 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 fromin calculating DCF, while those classified as maintenancesustaining capital expenditures are. See “—Common Dividends” and “—Preferred Dividends.”

Our capital expenditures for the year ended December 31, 2017,2023, and the amount we expect to spend for 20182024 to sustain our assets and growexpand our business are as follows (in millions):follows:
2023Expected 2024
(In millions)
Capital expenditures:
Sustaining capital expenditures$868 $990 
Expansion capital expenditures1,594 2,086 
Accrued capital expenditures, contractor retainage and other(145)— 
Capital expenditures$2,317 $3,076 
Add:
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)
Acquisitions1,843 — 
Accrued capital expenditures, contractor retainage and other145 — 
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.

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 2017 Expected 2018
Sustaining capital expenditures(a)(c)$588
 $664
KMI Discretionary capital investments(b)(c)(d)(e)$2,982
 $2,215
KML Discretionary capital investments post-IPO(c)$384
 $1,500
Our capital investments consist of the following:
_______
2023Expected 2024
(In millions)
Sustaining capital investments
Capital expenditures for property, plant and equipment$868 $990 
Sustaining capital expenditures of unconsolidated joint ventures(a)163 192 
Less: Consolidated joint venture partners’ sustaining capital expenditures(9)(11)
Total sustaining capital investments1,022 1,171 
Expansion capital investments
Capital expenditures for property, plant and equipment1,594 2,086 
Investments in unconsolidated joint ventures(b)238 214 
Less: Consolidated joint venture partners’ expansion capital expenditures(20)(24)
Acquisitions1,843 — 
Total expansion capital investments3,655 2,276 
Total capital investments$4,677 $3,447 
(a)2017 and Expected 2018 amounts include $107 million and $112 million, respectively, for our share of (i) certain equity investee’s, (ii) KML’s, and (ii) consolidating subsidiaries’ sustaining capital expenditures.
(b)2017 is net of $216 million of contributions from certain partners for capital investments at non-wholly owned consolidated subsidiaries offset by $629 million of our contributions to certain unconsolidated joint ventures for capital investments.
(c)2017 includes $246 million of net changes from accrued capital expenditures, contractor retainage, and other.
(d)2017 includes $107 million of capital expenditures spent on Canadian projects prior to KML’s May 25, 2017 IPO and excludes KML capital expenditures thereafter as it has the capacity to draw on its construction credit facility to fund its capital expenditures.
(e)Expected 2018 amount includes our estimated contributions to certain unconsolidated joint ventures, net of contributions estimated from certain partners in non-wholly owned consolidated subsidiaries for capital investments.

(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 Regulation

The 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 Arrangements
 
We 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 years3-5 years
More than
 5 years
 (In millions)
Contractual obligations:     
Debt borrowings-principal payments(a)$31,929 $4,049 $2,668 $2,773 $22,439 
Interest payments(b)
20,362 1,573 2,933 2,717 13,139 
Lease obligations(c)366 67 96 58 145 
Pension and OPEB plans(d)457 64 28 25 340 
Transportation, volume and storage agreements(e)660 158 266 116 120 
Other obligations(f)297 84 81 31 101 
Total$54,071 $5,995 $6,072 $5,720 $36,284 
Other commercial commitments:     
Standby letters of credit(g)$157 $85 $72 
Capital expenditures(h)$469 $469 
(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 willperform 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.

63
 Payments due by period
 Total 
Less than 1
year
 2-3 years 4-5 years More than 5 years
 (In millions)
Contractual obligations:         
Debt borrowings-principal payments(a)$36,916
 $2,828
 $5,024
 $4,980
 $24,084
Interest payments(b)24,555
 1,897
 3,462
 2,974
 16,222
Leases and rights-of-way obligations(c)722
 118
 187
 117
 300
Pension and postretirement welfare plans(d)975
 48
 32
 45
 850
Transportation, volume and storage agreements(e)1,043
 159
 308
 258
 318
Other obligations(f)279
 64
 82
 38
 95
Total$64,490
 $5,114
 $9,095
 $8,412
 $41,869
Other commercial commitments: 
  
  
  
  
Standby letters of credit(g)$224
 $125
 $99
 $—
 $—
Capital expenditures(h)$845
 $845
 $—
 $—
 $—
_______

(a)Less than 1 year amount primarily includes $2,717 million of current maturities on senior notes and $111 million associated with our Trust I Preferred Securities that are classified as current obligations because these securities have rights to convert into cash and/or KMI common stock. 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, 2017.  
(c)Represents commitments pursuant to the terms of operating lease agreements and liabilities for rights-of-way.
(d)Represents the amount by which the benefit obligations exceeded the fair value of plan assets at year-end for pension and other postretirement benefit plans whose accumulated postretirement benefit obligations exceeded the fair value of plan assets. The payments by period include expected contributions to funded plans in 2018 and estimated benefit payments for unfunded plans in all years. 
(e)
Primarily represents transportation agreements of$425 million, volume agreements of $377 million and storage agreements for capacity on third party and an affiliate pipeline systems of $203 million.
(f)
Primarily includes 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 willperform remediation activities. These liabilities are included within “Accrued contingencies” and “Other long-term liabilities and deferred credits” in our consolidated balance sheets.
(g)The $224 million in letters of credit outstanding as of December 31, 2017 consisted of the following (i) $47 million under eleven letters of credit for insurance purposes; (ii) a $42 million letter of credit supporting our pipeline and terminal operations in Canada; (iii) letters of credit totaling $46 million supporting our International Marine Terminals Partnership Plaquemines, Louisiana Port, Harbor, and Terminal Revenue Bonds; (iv) a $25 million letter of credit supporting our Kinder Morgan Liquids Terminals LLC New Jersey Economic Development Revenue Bonds; (v) a $24 million letter of credit supporting our Kinder Morgan Operating L.P. “B” tax-exempt bonds; (vi) a $9 million letter of credit supporting Nassau County, Florida Ocean Highway and Port Authority tax-exempt bonds; and (vii) a combined $31 million in twenty-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, 2017.

Cash Flows
 
The following table summarizes our net cash flows provided by (used in) operating, investing and financing activities between 2023 and 2022.
Year Ended December 31,
20232022Changes
(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
The net decrease of $194$1,524 million (4%) inmore cash provided by operating activities in 2017 compared to 2016 was primarily attributable to:the comparable years of 2023 and 2022 is explained by the following discussion.
a $348•an $894 million decrease in operating cash flow resulting from the combined effects of adjusting the $498 million decrease in net income for the period-to-period net increase in non-cash itemscash related to changes in deferred revenues primarily consisting ofdriven by an $843 million prepayment received for certain fixed reservation charges under long-term transportation and terminaling contracts in the following: (i) net losses on impairments2023 period. See Note 15 “Revenue Recognition” to our consolidated financial statements for further information regarding this prepayment; and divestitures of assets and equity investments (see discussion above in “—Results of Operations”); (ii) change in fair market value of derivative contracts; (iii) DD&A expense (including amortization of excess cost of equity investments); (iv) deferred income taxes, which includes a $1,162 million adjustment associated with the 2017 Tax Reform; (v) earnings from equity investments; and (vi) loss (gain) on early extinguishment of debt; and
a $154•an $896 million increase in cash associated with net changes in working capital items and other non-current assets and liabilities.liabilities, excluding the change in deferred revenues discussed above. The increase was primarily driven among other things, primarily by a $144 million income tax refund received(i) the sale of natural gas inventories and higher settlements associated with commodity hedges in 2017.2023, 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


The $1,657$2,000 million net increase inmore cash used in investing activities in 2017 compared to 2016 was primarily attributable to:the comparable years of 2023 and 2022 is explained by the following discussion.
•a $1,401$1,355 million increase in cash used due to proceeds received in the 2016 period from the sale of a 50% equity interest in SNG;
•
a $306 million increase in capital expenditures primarily due to higher expenditures related to natural gas, CO2 and Trans Mountain expansion projects, offset in part by lower expenditures in the Terminals segment;
a $276 million increase in cash used for contributions to equity investments primarily due to the contributions we made in 2017 to Utopia Holding LLC, FEP and SNG; and
$212 million lower cash proceeds from sales of property, plant and equipment and other net assets, primarily driven by the higher proceeds we received in 2016 from sales of other long-lived assets; partially offset by
a $329 million decrease in expenditures for acquisitionsthe acquisition of assets and investments, net of cash acquired, primarily driven by the $324$1,829 million portion of the purchase price we paid in the 2016 periodnet cash used for the BP terminals acquisition;
acquisition of STX Midstream in 2023, compared with a $143combined $487 million increase in cash for distributions received from equity investments in excess of cumulative earnings, primarily driven by the higher distributions from MEP, SNG and Ruby; and
a $66 million increase in Other, net primarily due to favorable changes in restricted deposits associated with our hedging activities, offset partially by increases in loans with an equity investee.


Financing Activities

The net decrease of $956 million in cash used by financing activitiesfor our acquisitions of Mas Ranger, LLC and NANR in 2017 compared to 2016 was primarily attributable to:
a $1,560 million increase in cash due to contributions from noncontrolling interests, primarily reflecting $1,245 million in net proceeds received from the May 2017 KML IPO and $420 million net proceeds received from the KML preferred share issuances in 2017, compared to the 2016 period which includes $84 million of contributions received from BP for its 25% share of a newly formed joint venture; and
a $485 million increase in cash resulting from contributions received in the 2017 period from EIG, consisting of $386 million for the sale of a 49% partnership interest in ELC and $99 million as additional contributions for 2017 capital expenditures; partially offset by
an $816 million net increase in cash used related to debt activities as a result of higher net debt payments in the 2017 period compared to the 2016 period.2022; See Note 9 “Debt”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;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 $250$154 million increase in cash used for share repurchases under theour share buy-back program that commenced in December 2017.program.


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Dividends and Stock BuybackBuy-back Program
KMI Common Stock Dividends
The table below reflects the paymentdeclaration of cash dividends of $0.50$1.13 per common share for 2017.
2023:
Three months ended Total quarterly dividend per share for the period Date of declaration Date of record Date of dividend
March 31, 2017 $0.125
 April 19, 2017 May 1, 2017 May 15, 2017
June 30, 2017 0.125
 July 19, 2017 July 31, 2017 August 15, 2017
September 30, 2017 0.125
 October 18, 2017 October 31, 2017 November 15, 2017
December 31, 2017 0.125
 January 17, 2018 January 31, 2018 February 15, 2018
Three months endedTotal quarterly dividend per share for the periodDate of declarationDate of recordDate of dividend
March 31, 2023$0.2825April 19, 2023May 1, 2023May 15, 2023
June 30, 20230.2825July 19, 2023July 31, 2023August 15, 2023
September 30, 20230.2825October 18, 2023October 31, 2023November 15, 2023
December 31, 20230.2825January 17, 2024January 31, 2024February 15, 2024


As previously announced, as a result of substantial balance sheet improvement achieved since the end of 2015, we have taken multiple stepsWe expect to continue to return significantadditional value to our shareholders. First, we expect to declare an annualshareholders in 2024 through our previously announced dividend of $0.80 per common share for 2018, a 60% increase from the 2017 dividend per common share. The first 2018 increase is expected to be the dividend declared for the first quarter of 2018. Additionally, weincrease. We plan to increase our dividenddividend by 2% to $1.00$1.15 per common share in 2019 and $1.252024. On January 18, 2023, our Board approved an increase to our stock buy-back program from $2 billion to $3 billion. Since 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 common share in 2020,for $1,472 million, leaving a growth rateremaining capacity of 25% annually.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 common 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“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 of directors inBoard when declaring dividends.


Our common stock dividends are not cumulative. Consequently, if dividends on our common stock are not paid at the intended levels, our common stockholders are not entitled to receive those payments in the future. Our common stock dividends generally will be paid on or about the 15th day of each February, May, August and November.


65

Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries

KMI Preferred Stock Dividendsand 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.


DividendsIn 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 Information20232022
(In millions)
Current assets$2,246 $3,514 
Current assets - affiliates760 618 
Noncurrent assets62,877 61,523 
Noncurrent assets - affiliates903 516 
Total Assets$66,786 $66,171 
Current liabilities$6,907 $6,612 
Current liabilities - affiliates734 707 
Noncurrent liabilities31,681 30,668 
Noncurrent liabilities - affiliates1,306 1,096 
Total Liabilities40,628 39,083 
Kinder Morgan, Inc.’s stockholders’ equity26,158 27,088 
Total Liabilities and Stockholders’ Equity$66,786 $66,171 
Summarized Combined Income Statement InformationYear Ended December 31, 2023
(In millions)
Revenues$14,131 
Operating income3,832 
Net income2,032 

66

Recent Accounting Pronouncements

Please refer to Note 19 “Recent Accounting Pronouncements” to our consolidated financial statements for information concerning recent accounting pronouncements.

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk.

Generally, our market risk sensitive instruments and positions have been determined to be “other than trading.”  Our exposure to market risk as discussed below includes forward-looking statements and represents an estimate of possible changes in fair value or future earnings that would occur assuming hypothetical future movements in energy commodity prices or interest rates.  Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated based on actual fluctuations in energy commodity prices or interest rates and the timing of transactions.

Energy Commodity Market Risk

We enter into certain energy commodity derivative contracts in order to reduce and minimize the risks encountered in the ordinary course of business associated with unfavorable changes in the market price of crude oil, natural gas and NGL. The derivative contracts that we use include exchange-traded and OTC commodity financial instruments, including, but not limited to, futures and options contracts, fixed price swaps and basis swaps. We may categorize such use of energy commodity derivative contracts as cash flow hedges because the derivative contract is used to hedge the anticipated future cash flow of a transaction that is expected to occur but whose value is uncertain.

Our hedging strategy involves entering into a financial position intended to offset our physical position, or anticipated position, in order to minimize the risk of financial loss from an adverse price change. For example, as sellers of crude oil, natural gas and NGL, we often enter into fixed price swaps and/or futures contracts to guarantee or lock-in the sale price of our crude oil or the margin from the sale and purchase of our natural gas at the time of market delivery, thereby in whole or in part offsetting any change in prices, either positive or negative. Using derivative contracts for this purpose helps provide increased certainty with regard to operating cash flows which helps us to undertake further capital improvement projects, attain budget results and meet dividend targets.

Our policies require that derivative contracts are only entered into with carefully selected major financial institutions or similar counterparties based upon their credit ratings and other factors, and we maintain strict dollar and term limits that correspond to our counterparties’ credit ratings. While it is our policy to enter into derivative transactions principally with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that losses will result from counterparty credit risk in the future.

We measure the risk of price changes in the derivative instrument portfolios utilizing a sensitivity analysis model. The sensitivity analysis applied to each portfolio measures the potential income or loss (i.e., the change in fair value of the derivative instrument portfolio) based upon a hypothetical 10% movement in the underlying quoted market prices. In addition to these variables, the fair value of each portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. Because we enter into derivative contracts largely for the purpose of mitigating the risks that accompany certain of our business activities, both in the sensitivity analysis model and in reality, the change in the market value of the derivative contracts’ portfolio is offset largely by changes in the value of the underlying physical transactions. A hypothetical 10% movement in the underlying commodity prices would have the following effect on the associated derivative contracts’ estimated fair value:
As of December 31,
Commodity derivative20232022
(In millions)
Crude oil$127 $157 
Natural gas28 49 
NGL4 5 
Total$159 $211 

Our sensitivity analysis represents an estimate of the reasonably possible gains and losses that would be recognized on the crude oil, natural gas and NGL portfolios of derivative contracts assuming hypothetical movements in future market rates and is
67

not necessarily indicative of actual results that may occur. It does not represent the maximum possible loss or any expected loss that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ from estimates due to actual fluctuations in market rates, operating exposures and the timing thereof, as well as changes in our portfolio of derivatives during the year.

Interest Rate Risk

In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt. Fixed-to-variable interest rate swap agreements are entered into for the purpose of converting a portion of the underlying cash flows related to long-term fixed rate debt securities into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. Variable-to-fixed interest rate swap agreements are entered into primarily for the purpose of managing our exposure to changes in interest rates on our mandatory convertible preferred stockdebt balances that are payablesubject to variable interest rates and adjusting, on a cumulativeshort-term basis, when,our mix of fixed rate debt and variable rate debt based on changes in market conditions. The market risk inherent in our debt instruments and positions is the potential change arising from increases or decreases in interest rates as and if declared by our board of directors (or an authorized committee thereof) at an annualdiscussed below.

For fixed rate of 9.750%debt, changes in interest rates generally affect the fair value of the liquidation preferencedebt instrument, but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of $1,000 per sharethe debt instrument, but may affect our future earnings and cash flows. Generally, there is not an obligation to prepay fixed rate debt prior to maturity and, as a result, changes in fair value should not have a significant impact on January 26, April 26, July 26 and October 26 of each year, commencing on January 26, 2016 to, and including, October 26, 2018.the fixed rate debt. We may pay dividends in cash or,are generally subject to certain limitations,interest rate risk upon refinancing maturing debt. Below are our debt balances, including debt fair value adjustments, and sensitivity to interest rates:
 December 31, 2023December 31, 2022
 Carrying
value		Estimated
fair value(a)		Carrying
value		Estimated
fair value(a)
(In millions)
Fixed rate debt(b)$30,063 $29,317 $31,474 $29,756 
Variable rate debt$2,053 $2,053 $314 $314 
Notional principal amount of variable-to-fixed interest rate swap agreements(c)— (1,500)
Notional principal amount of fixed-to-variable interest rate swap agreements6,200 7,500 
Debt balances subject to variable interest rates(d)$8,253 $6,314 
(a)Fair values were determined using Level 2 inputs.
(b)A hypothetical 10% change in sharesthe average interest rates applicable to such debt as of common stockDecember 31, 2023 and 2022, would result in changes of approximately $1,889 million and $1,882 million, respectively, in the estimated fair values of these instruments.
(c)December 31, 2022 amount includes $1.25 billion that expired in December 2023.
(d)A hypothetical 10% change in the weighted average interest rate on all of our borrowings (approximately 58 and 48 basis points in 2023 and 2022, respectively) when applied to our outstanding balance of variable rate debt as of December 31, 2023 and 2022, including adjustments for the notional swap amounts described in the table above, would result in changes of approximately $48 million and $30 million, respectively.

As presented in the table above, we monitor the mix of fixed rate and variable rate debt obligations in light of changing market conditions and from time to time, may alter that mix by, for example, refinancing outstanding balances of variable rate debt with fixed rate debt (or vice versa) or any combinationby entering into interest rate swap agreements or other interest rate hedging agreements. As of December 31, 2023, including debt converted to variable rates through the use of interest rate swaps but excluding our debt fair value adjustments, approximately 26% of our debt balances were subject to variable interest rates.

For more information on our interest rate risk management and on our interest rate swap agreements, see Note 14 “Risk Management” to our consolidated financial statements.

68

Foreign Currency Risk

As of December 31, 2023, we had a notional principal amount of $543 million of cross-currency swap agreements that effectively convert all of our fixed-rate Euro denominated debt, including annual interest payments and the payment of principal at maturity, to U.S. dollar denominated debt at fixed rates. These swaps eliminate the foreign currency risk associated with our foreign currency denominated debt.

69

Item 8.  Financial Statements and Supplementary Data.



KINDER MORGAN, INC. AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS
Page
Number
(PCAOB ID: 238)
71
74
75
76
77
79
80
Note 1.
80
Note 2.
80
Note 3.
90
Note 4.
93
Note 5.
94
Note 6.
97
Note 7.
98
Note 8.
99
Note 9.
100
Note 10.
104
Note 11.
110
Note 12.
112
Note 13.
112
Note 14.
113
Note 15.
118
Note 16.
121
Note 17.
125
Note 18.
126
Note 19.
130
70



Report of Independent Registered Public Accounting Firm

To theBoard of Directors and Stockholders of Kinder Morgan, Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Kinder Morgan, Inc. and its subsidiaries (the “Company”) as of December 31, 2023 and 2022,and the related consolidated statements of income, of comprehensive income, of stockholders’ equity and of cash and shares of common stock. The termsflows for each of the mandatory convertible preferred stock provide that, unless full cumulative dividendsthree years in the period ended December 31, 2023, including the related notes (collectively referred to as the “consolidated financial statements”). We also have been paid or set asideaudited the Company's internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of itsoperations and itscash flows for paymenteach of the three years in the period ended December 31, 2023 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on all outstanding mandatory convertible preferred stockcriteria established in Internal Control - Integrated Framework(2013)issued by the COSO.

Basis for all prior dividend periods, no dividends may be declared or paid on common stock.Opinions

Period Total dividend per share for the period Date of declaration Date of record Date of dividend
January 26, 2017 through April 25, 2017 $24.375
 January 18, 2017 April 11, 2017 April 26, 2017
April 26, 2017 through July 25, 2017 24.375
 April 19, 2017 July 11, 2017 July 26, 2017
July 26, 2017 through October 25, 2017 24.375
 July 19, 2017 October 11, 2017 October 26, 2017
October 26, 2017 through January 25, 2018 24.375
 October 18, 2017 January 11, 2018 January 26, 2018


The cash dividendCompany's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of $24.375 per sharethe effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our mandatory convertible preferred stock is equivalentaudits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to $1.21875 per depository share.be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.


Stock Buyback ProgramWe conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.


On July 19, 2017,Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our boardaudits provide a reasonable basis for our opinions.

As described in Management’s Report on Internal Control over Financial Reporting, management has excluded STX Midstream from its assessment of directors approvedinternal control over financial reporting as of December 31, 2023, because it was acquired by the Company in a $2 billion common share buyback program that began in December 2017. Duringpurchase business combination during 2023. We have also excluded STX Midstream from our audit of internal control over financial reporting. STX Midstream’s total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting both represent less than 3% of the related consolidated financial statement amounts as of and for the year ended December 31, 2017,2023.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the
71

company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we repurchased approximately 14are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Goodwill Impairment Assessment – Natural Gas Pipelines Regulated, Natural Gas Pipelines Non-Regulated, CO2, Products Pipelines, Products Pipelines Terminals, and Terminals Reporting Units

As described in Notes 2 and 8 to the consolidated financial statements, the Company’s consolidated goodwill balance was $20.1 billion as of December 31, 2023, of which $20.0 billion relates to the Natural Gas Pipelines Regulated, Natural Gas Pipelines Non-Regulated, CO2, Products Pipelines, Products Pipelines Terminals, and Terminals reporting units (collectively, “the reporting units”). Management evaluates goodwill for impairment on May 31 of each year, or more frequently to the extent events occur or conditions change between annual tests that would indicate a risk of possible impairment at the interim period. Management estimated the fair value of the reporting units based on a market approach utilizing forecasted earnings before interest, income taxes, depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments (EBITDA), and the enterprise value to estimated EBITDA multiples of comparable companies for each reporting unit.

The principal considerations for our determination that performing procedures relating to the goodwill impairment assessment of the reporting units is a critical audit matter are (i) the significant judgment by management when developing the fair value estimate of the reporting units; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to forecasted EBITDA and the enterprise value to estimated EBITDA multiples of comparable companies for each of the reporting units; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s goodwill impairment assessment, including controls over developing the fair value estimate of the reporting units. These procedures also included, among others (i) testing management’s process for developing the fair value estimate of the reporting units; (ii) evaluating the appropriateness of the market approach used by management; (iii) testing the completeness and accuracy of underlying data used in the market approach; and (iv) evaluating the reasonableness of the significant assumptions used by management related to forecasted EBITDA and the enterprise value to estimated EBITDA multiples of comparable companies for each of the reporting units. Evaluating management’s assumptions related to forecasted EBITDA and the enterprise value to estimated EBITDA multiples of comparable companies for each of the reporting units involved evaluating whether the assumptions used by management were reasonable considering (i) the current and past performance of the reporting units; (ii) the consistency with external market and industry data; and (iii) whether these assumptions were consistent with evidence obtained in other areas of the audit. Professionals with specialized skill and knowledge were used to assist in evaluating (i) the appropriateness of the market approach and (ii) the reasonableness of the assumption related to the enterprise value to estimated EBITDA multiples of comparable companies for each of the reporting units.

Acquisition of STX Midstream – Valuation of Property, Plant and Equipment

As described in Note 3 to the consolidated financial statements, on December 28, 2023, the Company completed the acquisition of STX Midstream for a purchase price of $1.8 billion. This acquisition resulted in the recognition of $1.2 billion of property, plant and equipment (PP&E). For acquired businesses, the Company recognizes the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Management determined the fair value of PP&E utilizing a replacement cost approach. Determining the fair value of this item requires management judgment and the utilization of an independent valuation specialist and involves the use of significant estimates and assumptions. The significant assumption made in performing this valuation includes the replacement costs used to value PP&E.

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The principal considerations for our determination that performing procedures relating to the valuation of PP&E acquired in the acquisition of STX Midstream is a critical audit matter are (i) the significant judgment by management when developing the fair value estimate of the PP&E acquired; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumption related to the replacement costs used to value the PP&E acquired; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the acquisition accounting, including controls over management’s valuation of the PP&E acquired. These procedures also included, among others (i) reading the purchase agreement; (ii) testing management’s process for developing the fair value estimate of the PP&E acquired; (iii) evaluating the appropriateness of the replacement cost approach used by management; (iv) testing the completeness and accuracy of underlying data used in the replacement cost approach; and (v) evaluating the reasonableness of the significant assumption used by management related to the replacement costs used to value the PP&E acquired. Professionals with specialized skill and knowledge were used to assist in evaluating (i) the appropriateness of the replacement cost approach and (ii) the reasonableness of the replacement costs assumption used to value the PP&E acquired.


/s/ PricewaterhouseCoopers LLP

Houston, Texas
February 20, 2024

We have served as the Company’s auditor since 1997.
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KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share amounts)
 Year Ended December 31,
 202320222021
Revenues 
Services$8,371 $8,145 $7,757 
Commodity sales6,786 10,897 8,714 
Other177 158 139 
Total Revenues15,334 19,200 16,610 
Operating Costs, Expenses and Other
Costs of sales (exclusive of items shown separately below)4,938 9,255 6,493 
Operations and maintenance2,807 2,655 2,368 
Depreciation, depletion and amortization2,250 2,186 2,135 
General and administrative668 637 655 
Taxes, other than income taxes421 441 426 
(Gain) loss on divestitures and impairments, net (Note 4)(15)(32)1,624 
Other expense (income), net2 (7)(7)
Total Operating Costs, Expenses and Other11,071 15,135 13,694 
Operating Income4,263 4,065 2,916 
Other Income (Expense)
Earnings from equity investments838 803 591 
Amortization of excess cost of equity investments(66)(75)(78)
Interest, net(1,797)(1,513)(1,492)
Other, net (Note 3)(37)55 282 
Total Other Expense(1,062)(730)(697)
Income Before Income Taxes3,201 3,335 2,219 
Income Tax Expense(715)(710)(369)
Net Income2,486 2,625 1,850 
Net Income Attributable to Noncontrolling Interests(95)(77)(66)
Net Income Attributable to Kinder Morgan, Inc.$2,391 $2,548 $1,784 
Class P Common Stock 
Basic and Diluted Earnings Per Share$1.06 $1.12 $0.78 
Basic and Diluted Weighted Average Shares Outstanding2,234 2,258 2,266 

The accompanying notes are an integral part of these consolidated financial statements.
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KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
Year Ended December 31,
 202320222021
Net income$2,486 $2,625 $1,850 
Other comprehensive income (loss), net of tax 
Net unrealized gain (loss) from derivative instruments (net of taxes of $(47), $92, and $131, respectively)155 (312)(432)
Reclassification into earnings of net derivative instruments loss (gain) to net income (net of taxes of $12, $(95), and $(83), respectively)(35)320 273 
Benefit plan adjustments (net of taxes of $(20), $(1), and $(47), respectively)65 1 155 
Total other comprehensive income (loss)185 9 (4)
Comprehensive income2,671 2,634 1,846 
Comprehensive income attributable to noncontrolling interests(95)(77)(66)
Comprehensive income attributable to KMI$2,576 $2,557 $1,780 

The accompanying notes are an integral part of these consolidated financial statements.
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KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions, except share and per share amounts)
 December 31,
 20232022
ASSETS  
Current assets  
Cash and cash equivalents$83 $745 
Restricted deposits13 49 
Accounts receivable1,588 1,840 
Fair value of derivative contracts126 231 
Inventories525 634 
Other current assets207 304 
Total current assets2,542 3,803 
Property, plant and equipment, net37,297 35,599 
Investments7,874 7,653 
Goodwill20,121 19,965 
Other intangibles, net1,957 1,809 
Deferred charges and other assets1,229 1,249 
Total Assets$71,020 $70,078 
LIABILITIES AND STOCKHOLDERS’ EQUITY  
Current liabilities  
Current portion of debt$4,049 $3,385 
Accounts payable1,366 1,444 
Accrued interest513 515 
Accrued taxes272 264 
Fair value of derivative contracts205 465 
Other current liabilities816 857 
Total current liabilities7,221 6,930 
Long-term liabilities and deferred credits  
Long-term debt
Outstanding27,880 28,288 
Debt fair value adjustments187 115 
Total long-term debt28,067 28,403 
Deferred income taxes1,388 623 
Other long-term liabilities and deferred credits2,615 2,008 
Total long-term liabilities and deferred credits32,070 31,034 
Total Liabilities39,291 37,964 
Commitments and contingencies (Notes 9, 13, 17 and 18)
Stockholders’ Equity  
Class P Common Stock, $0.01 par value, 4,000,000,000 shares authorized, 2,219,729,644 and 2,247,681,626 shares, respectively, issued and outstanding22 22 
Additional paid-in capital41,190 41,673 
Accumulated deficit(10,689)(10,551)
Accumulated other comprehensive loss(217)(402)
Total Kinder Morgan, Inc.’s stockholders’ equity30,306 30,742 
Noncontrolling interests1,423 1,372 
Total Stockholders’ Equity31,729 32,114 
Total Liabilities and Stockholders’ Equity$71,020 $70,078 

The accompanying notes are an integral part of these consolidated financial statements.
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KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
 Year Ended December 31,
 202320222021
Cash Flows From Operating Activities   
Net income$2,486 $2,625 $1,850 
Adjustments to reconcile net income to net cash provided by operating activities   
Depreciation, depletion and amortization2,250 2,186 2,135 
Deferred income taxes710 692 355 
Amortization of excess cost of equity investments66 75 78 
Change in fair market value of derivative contracts(126)56 20 
(Gain) loss on divestitures and impairments, net (Note 4)(15)(32)1,624 
Gain on sale of interest in equity investment (Note 3)— — (206)
Earnings from equity investments(838)(803)(591)
Distributions of equity investment earnings755 725 720 
Pension contributions net of noncash pension benefit expenses77 (50)(39)
Changes in components of working capital, net of the effects of acquisitions and dispositions   
Accounts receivable301 (220)(265)
Inventories188 (183)(202)
Other current assets108 (51)(109)
Accounts payable(201)161 387 
Accrued interest, net of interest rate swaps(13)50 (17)
Other current liabilities(58)6 165 
Change in deferred revenues (Note 15)870 (24)(28)
Rate reparations, refunds and other litigation reserve adjustments(19)(190)(57)
Other, net(50)(56)(112)
Net Cash Provided by Operating Activities6,491 4,967 5,708 
Cash Flows From Investing Activities   
Acquisitions of assets and investments, net of cash acquired (Note 3)(1,842)(487)(1,547)
Capital expenditures(2,317)(1,621)(1,281)
Sales of property, plant and equipment, investments, and other net assets, net of removal costs(28)6 406 
Contributions to investments(212)(229)(38)
Distributions from equity investments in excess of cumulative earnings228 156 163 
Other, net(4)— (8)
Net Cash Used in Investing Activities(4,175)(2,175)(2,305)
Cash Flows From Financing Activities
Issuances of debt7,590 9,058 5,959 
Payments of debt(7,356)(9,735)(6,831)
Debt issue costs(20)(25)(27)
Dividends (Note 11)(2,529)(2,504)(2,443)
Repurchases of shares (Note 11)(522)(368)— 
Proceeds from sale of noncontrolling interests (Note 3)— 557 — 
Contributions from noncontrolling interests3 2 4 
Distributions to investment partner— — (82)
Distributions to noncontrolling interests(151)(116)(20)
Other, net(29)(14)(25)
Net Cash Used in Financing Activities(3,014)(3,145)(3,465)
Net Decrease in Cash, Cash Equivalents and Restricted Deposits(698)(353)(62)
Cash, Cash Equivalents and Restricted Deposits, beginning of period794 1,147 1,209 
Cash, Cash Equivalents and Restricted Deposits, end of period$96 $794 $1,147 
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KINDER MORGAN, INC. AND SUBSIDIARIES (continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
 Year Ended December 31,
 202320222021
Cash and Cash Equivalents, beginning of period$745 $1,140 $1,184 
Restricted Deposits, beginning of period49 7 25 
Cash, Cash Equivalents and Restricted Deposits, beginning of period794 1,147 1,209 
Cash and Cash Equivalents, end of period83 745 1,140 
Restricted Deposits, end of period13 49 7 
Cash, Cash Equivalents and Restricted Deposits, end of period96 794 1,147 
Net Decrease in Cash, Cash Equivalents and Restricted Deposits$(698)$(353)$(62)
Noncash Investing and Financing Activities
Assets contributed to equity investment$16 $— $— 
Net increase in property, plant and equipment from both accruals and contractor retainage120 72 74 
ROU assets and operating lease obligations recognized (Note 17)56 22 59 
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)1,844 1,460 1,529 
Cash paid during the period for income taxes, net11 13 10 

The accompanying notes are an integral part of these consolidated financial statements.
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KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In millions)
Common stockAdditional
paid-in
capital		Accumulated
deficit		Accumulated
other
comprehensive
loss		Stockholders’
equity
attributable
to KMI		Non-controlling
interests		Total
 Issued sharesPar value
Balance at December 31, 20202,264 $23 $41,756 $(9,936)$(407)$31,436 $402 $31,838 
Restricted shares3 50 50 50 
Net income1,784 1,784 66 1,850 
Dividends(2,443)(2,443)(2,443)
Distributions— (20)(20)
Contributions— 4 4 
Reclassification of redeemable noncontrolling interest— 646 646 
Other comprehensive loss(4)(4)(4)
Balance at December 31, 20212,267 23 41,806 (10,595)(411)30,823 1,098 31,921 
Impact of adoption of ASU 2020-06 (Note 11)(11)(11)(11)
Balance at January 1, 20222,267 23 41,795 (10,595)(411)30,812 1,098 31,910 
Repurchases of shares(21)(1)(367)(368)(368)
EP Trust I Preferred security conversions1 1 1 
Restricted shares2 54 54 54 
Net income2,548 2,548 77 2,625 
Dividends(2,504)(2,504)(2,504)
Distributions— (116)(116)
Contributions— 2 2 
Impact of change in ownership interest in subsidiary190 190 311 501 
Other comprehensive income9 9 9 
Balance at December 31, 20222,248 22 41,673 (10,551)(402)30,742 1,372 32,114 
Repurchases of shares(32)(522)(522)(522)
Restricted shares4 44 44 44 
Net income2,391 2,391 95 2,486 
Dividends(2,529)(2,529)(2,529)
Distributions— (151)(151)
Contributions— 3 3 
Acquisition (Note 3)— 104 104 
Other(5)(5)(5)
Other comprehensive income185 185 185 
Balance at December 31, 20232,220 $22 $41,190 $(10,689)$(217)$30,306 $1,423 $31,729 

The accompanying notes are an integral part of these consolidated financial statements.
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KINDER MORGAN, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.General

We are one of the largest energy infrastructure companies in North America. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company,” or “KMI” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2, renewable fuels and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, jet fuel, chemicals, metals, petroleum coke, and ethanol and other renewable fuels and feedstocks.
2.Summary of Significant Accounting Policies

Basis of Presentation

Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars, unless stated otherwise. Our accompanying consolidated financial statements have been prepared under the rules and regulations of the SEC. These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification (ASC), the single source of GAAP. Under such rules and regulations, all significant intercompany items have been eliminated in consolidation. Additionally, certain amounts from prior years have been reclassified to conform to the current presentation.

Use of Estimates

Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities, our revenues and expenses during the reporting period, and our disclosures, including those related to contingent assets and liabilities at the date of our financial statements. We evaluate these estimates on an ongoing basis, 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. 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.

Certain accounting policies are of more significance in our financial statement preparation process than others, and set out below are the principal accounting policies we apply in the preparation of our consolidated financial statements.

Cash Equivalents and Restricted Deposits

We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less.

Amounts included in the restricted deposits in the accompanying consolidated financial statements represent a combination of restricted cash amounts required to be set aside by regulatory agencies to cover obligations for our captive insurance subsidiary, cash margin deposits posted by us with our counterparties associated with certain energy commodity contract positions and escrow deposits.

Allowance for Credit Losses

We evaluate our financial assets measured at amortized cost and off-balance sheet credit exposures for expected credit losses over the contractual term of the asset or exposure. We consider available information relevant to assessing the collectability of cash flows including the expected risk of credit loss even if that risk is remote. We measure expected credit losses on a collective (pool) basis when similar risk characteristics exist, and we reflect the expected credit losses on the amortized cost basis of the financial asset as of the reporting date.

Our financial instruments primarily consist of our accounts receivable from customers, notes receivable from affiliates and contingent liabilities such as proportional guarantees of debt obligations of an equity investee. We utilized historical analysis of credit losses experienced over the previous five years along with current conditions and reasonable and supportable forecasts of future conditions in our evaluation of collectability of our financial assets.
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Our allowance for credit losses as of both December 31, 2023 and 2022 was $1 million and is included in “Other current assets” in our accompanying consolidated balance sheets.

Inventories

Our inventories consist of materials and supplies and products such as natural gas, NGL, crude oil, condensate, refined petroleum products and transmix. We report products inventory at the lower of weighted-average cost or net realizable value. We report materials and supplies inventories at cost, and periodically review for physical deterioration and obsolescence.

Property, Plant and Equipment, net

Capitalization, Depreciation and Depletion and Disposals

We report property, plant and equipment at its acquisition cost. We expense costs for routine maintenance and repairs in the period incurred. The following table summarizes our significant policies related to our property, plant and equipment. The application of these policies can involve significant estimates.
AssetAccounting AreaPolicy
Straight-line assetsDepreciation rates
•Depreciable lives are based on estimated economic lives. This includes age, manufacturing specifications, technological advances, estimated production life of the oil or gas field served by the asset, contract terms for assets on leased or customer property and historical data concerning useful lives of similar assets.
Gains and losses
•A gain or loss on the sale of property, plant and equipment is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sale proceeds received or when held for sale, the market value of the asset.
•A gain on an asset disposal is recognized in income in the period that the sale is closed.
•A loss is recognized when the asset is sold or when classified as held for sale.
•Gains and losses are recorded in operating costs, expenses and other.
Composite assetsDepreciation rates
•A single depreciation rate is applied to the total cost of a functional group of assets that have similar economic characteristics until the net book value of the composite group equals the salvage value.
•Interstate natural gas FERC-regulated entities use the depreciation rates approved by the FERC.
•A depreciation rate for other composite assets is based on estimated economic lives. This includes age, manufacturing specifications, technological advances, estimated production life of the oil or gas field served by the asset, contract terms for assets on leased or customer property and historical data concerning useful lives of similar assets.
Gains and losses
•Gains and losses are credited or charged to accumulated depreciation, net of salvage and cost of removal.
•Gains and losses on FERC-approved operating unit sales and land sales are recorded in operating costs, expenses and other.
Oil and gas producing activities(a)Successful efforts method of accounting
•Costs that are incurred to acquire leasehold and subsequent development costs are capitalized.
•Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found.
•Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of certain non-producing leasehold costs are expensed as incurred.
•The capitalized costs of our producing oil and gas properties are depreciated and depleted by the units-of-production method.
•Other miscellaneous property, plant and equipment are depreciated over the estimated useful lives of the asset.
Enhanced recovery techniques
•In some cases, the cost of the CO2 associated with enhanced recovery is capitalized as part of our development costs when it is injected.
•The cost of CO2 associated with pressure maintenance operations for reservoir management is expensed when it is injected.
•When CO2 is recovered in conjunction with oil production, it is extracted and re-injected, and all of the associated costs are expensed as incurred.
•Proved developed reserves are used in computing units of production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs.
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(a)Gains and losses associated with assets in our oil and gas producing activities have a similar treatment as with that associated with our straight-line assets.

Circumstances may develop which cause us to change our estimates, thus impacting the future calculation of depreciation and amortization expense. Historically, adjustments to useful lives have not had a material impact on our aggregate depreciation levels from year to year.

Asset Retirement Obligations

We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses. The majority of our asset retirement obligations are associated with our CO2 business where we are required to plug and abandon oil and gas wells that have been removed from service and to remove the surface wellhead equipment and compressors, but we also have obligations for certain gathering and long-haul pipelines and certain processing plants. We record, as liabilities, the fair value of asset retirement obligations on a discounted basis when they are incurred and can be reasonably estimated, which is typically at the time the assets are installed or acquired. The fair value estimates are primarily based on Level 3 inputs of the fair value hierarchy. The inputs include estimates and assumptions related to timing of settlement and retirement costs, which we base on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities are accreted to reflect the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service. Our estimates of retirement costs could change as a result of changes in cost estimates and/or timing of the obligation.

The following table summarizes changes in the asset retirement obligations included in our accompanying consolidated balance sheets:
December 31,
20232022
(In millions)
Balance at beginning of period$204 $196 
Accretion expense12 12 
New obligations22 2 
Settlements(7)(6)
Balance at end of period(a)$231 $204 
(a)Balances at both December 31, 2023 and 2022 include $3 million included within “Other current liabilities” on our accompanying consolidated balance sheets.

For certain assets, we currently cannot reasonably estimate the fair value of the asset retirement obligations because the associated assets have indeterminate lives. These assets include certain pipelines, processing plants and distribution facilities, and liquids and bulk terminal facilities. Based on the widespread use of hydrocarbons domestically and for international export, management expects supply and demand to exist for the foreseeable future. Therefore, the remaining useful lives of these assets are indeterminate due to prolonged expected demand. Additionally, these assets could also benefit from potential future conversion opportunities. For example, certain assets could be converted to transport, handle or store products other than traditional hydrocarbons. Under our integrity program, individual asset parts are replaced regularly. Although some of the individual asset parts may be replaced, the assets themselves may remain intact indefinitely. For these assets, an asset retirement obligation, if any, will be recognized once sufficient information is available to reasonably estimate the fair value of the obligation.

Long-lived Asset Impairments

We evaluate long-lived assets including leases and investments for impairment whenever events or changes in circumstances indicate that our carrying amount of an asset or investment may not be recoverable.

In addition to our annual goodwill impairment test discussed further below, to the extent triggering events exist, we complete a review of the carrying value of our long-lived assets, including property, plant and equipment as well as other intangibles, and record, as applicable, the appropriate impairments using a two-step approach. To determine if a long-lived asset is recoverable, we compare the asset’s estimated undiscounted cash flows to its carrying value (step 1). Because the impairment test for long-lived assets held in use is based on estimated undiscounted cash flows, there may be instances where
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an asset or asset group is not considered impaired, even when its fair value may be less than its carrying value, because the asset or asset group is recoverable based on the cash flows to be generated over the estimated life of the asset or asset group. If the carrying value of a long-lived asset or asset group is in excess of estimated undiscounted cash flows, we typically use discounted cash flow analyses to calculate the fair value of the long-lived asset to determine if an impairment is required and the amount of the impairment losses to be recognized (step 2).

We evaluate our oil and gas producing properties for impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure, using undiscounted future cash flows based on estimated future oil and gas production volumes.

Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future cash flows based on estimated future oil and gas production volumes.  Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment.

Refer to Note 4 for further information.

Equity Method of Accounting and Basis Differences

We use the equity method of accounting for investments which we do not control, but for which we have the ability to exercise significant influence. The carrying values of these investments are impacted by our share of investee income or loss, distributions, amortization or accretion of basis differences and other-than-temporary impairments.

The difference between the carrying value of an investment and our share of the investment’s underlying equity in net assets is referred to as a basis difference. If the basis difference is assigned to depreciable or amortizable assets and liabilities, the basis difference is amortized or accreted as part of our share of investee earnings. To the extent that the basis difference relates to goodwill, referred to as equity method goodwill, the amount is not amortized.

We evaluate our equity method investments for other-than-temporary impairment. When an other-than-temporary impairment is recognized, the loss is recorded as a reduction in equity earnings.

Goodwill

Goodwill is the cost of an acquisition of a business in excess of the fair value of acquired assets and liabilities and is recorded as an asset on our balance sheet. Goodwill is not subject to amortization but must be tested for impairment at least annually and in interim periods if indicators of impairment exist. This test requires us to assign goodwill to an appropriate reporting unit and compare the fair value of a reporting unit to its carrying value. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value an impairment is measured and recorded at the amount by which the reporting unit’s carrying value exceeds its fair value.

We evaluate goodwill for impairment on May 31 of each year, or more frequently to the extent events occur or conditions change between annual tests that would indicate a risk of possible impairment at the interim period.  For purposes of our May 31, 2023 evaluation, we grouped our businesses into seven reporting units as follows: (i) Natural Gas Pipelines Regulated; (ii) Natural Gas Pipelines Non-Regulated; (iii) CO2; (iv) Products Pipelines (excluding associated terminals); (v) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (vi) Terminals; and (vii) Energy Transition Ventures. Generally, the evaluation of goodwill for impairment involves a quantitative test, although under certain circumstances an initial qualitative evaluation may be sufficient to conclude that goodwill is not impaired without conducting the quantitative test.

A large portion of our goodwill is non-deductible for tax purposes, and as such, to the extent there are impairments, all or a portion of the impairment may not result in a corresponding tax benefit.

Refer to Note 8 for further information.

Other Intangibles

Excluding goodwill, our other intangible assets include customer contracts and other relationships and agreements.

Our intangible assets primarily relate to customer contracts or other relationships for the handling and storage of petroleum, chemical, and dry-bulk materials, including oil, gasoline, and other refined petroleum products, petroleum coke, metals and
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ores, the gathering of natural gas and the production and supply of RNG. We determined the values of these intangible assets by first, estimating the revenues derived from a customer contract or relationship (offset by the cost and expenses of supporting assets to fulfill the contract), and second, discounting the revenues at a risk adjusted discount rate.

We amortize the costs of our intangible assets to expense in a systematic and rational manner over their estimated useful lives. The life of each intangible asset is based either on the life of the corresponding customer contract or agreement or, in the case of a customer relationship intangible (the life of which was determined by an analysis of all available data on that business relationship), the length of time used in the discounted cash flow analysis to determine the value of the customer relationship. Among the factors we weigh, depending on the nature of the asset, are the effects of obsolescence, new technology, and competition.

The following tables summarize our other intangible assets as of December 31, 2023 and 2022 and our amortization expense for the years ended December 31, 2023, 2022 and 2021: 
Weighted Average Amortization PeriodDecember 31,
20232022
(Years)(In millions)
Gross11.3$3,543 $3,382 
Accumulated amortization(1,586)(1,573)
Net carrying amount$1,957 $1,809 
December 31,
202320222021
(In millions)
Amortization expense$202 $253 $237 

Our estimated amortization expense for our intangible assets for each of the next five fiscal years is:
20242025202620272028
(In millions)
Estimated amortization expenses$198 $193 $191 $191 $190 

Revenue Recognition

The majority of our revenues are accounted for under Topic 606, Revenue from Contracts with Customers; however, to a limited extent, some revenues are accounted for under other guidance such as Topic 842, Leases or Topic 815, Derivatives and Hedging Activities.

Revenue from Contracts with Customers

We review our contracts with customers using the following steps to recognize revenue based on the transfer of goods or services to customers and in amounts that reflect the consideration the company expects to receive for those goods or services. The steps include: (i) identify the contract; (ii) identify the performance obligations of the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and then (v) recognize revenue when (or as) the performance obligation is satisfied. Each of these steps involves management judgment and an analysis of the contract’s material terms and conditions.

Our customer sales contracts primarily include sales of natural gas, NGL, crude oil, CO2 and transmix, as described below. Generally, for the majority of these contracts (i) each unit (Bcf, gallon, barrel, etc.) of commodity is a separate performance obligation, as our promise is to sell multiple distinct units of commodity at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on our right to invoice at month end for the value of commodity sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity’s standalone selling price and recognized as revenue upon delivery of the commodity, which is the point in time when the customer obtains control of the commodity and our performance obligation is satisfied.

Our customer services contracts are primarily for transportation service, storage service, gathering and processing service, and terminaling, as described below. Generally, for the majority of these contracts (i) our promise is to transfer (or stand ready
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to transfer) a series of distinct integrated services over a period of time, which is a single performance obligation; (ii) the transaction price includes fixed and/or variable consideration, which amount is determinable at contract inception and/or at each month end based on our right to invoice at month end for the value of services provided to the customer that month; and (iii) the transaction price is recognized as revenue over the service period specified in the contract (which can be a day, including each day in a series of promised daily services, a month, a year, or other time increment, including a deficiency makeup period) as the services are rendered using a time-based (passage of time) or units-based (units of service transferred) output method for measuring the transfer of control of the services and satisfaction of our performance obligation over the service period, based on the nature of the promised service (e.g., firm or non-firm) and the terms and conditions of the contract (e.g., contracts with or without makeup rights).

Firm Services

Firm services (also called uninterruptible services) are services that are promised to be available to the customer at all times during the period(s) covered by the contract, with limited exceptions. Our firm service contracts are typically structured with take-or-pay or minimum volume provisions, which specify minimum service quantities a customer will pay for even if it chooses not to receive or use them in the specified service period (referred to as “deficiency quantities”). We typically recognize the portion of the transaction price associated with such provisions, including any deficiency quantities, as revenue depending on whether the contract prohibits the customer from making up deficiency quantities in subsequent periods, or the contract permits this practice, as follows:

•Contracts without Makeup Rights. If contractually the customer cannot make up deficiency quantities in future periods, our performance obligation is satisfied, and revenue associated with any deficiency quantities is generally recognized as each service period expires. Because a service period may exceed a reporting period, we determine at inception of the contract and at the beginning of each subsequent reporting period if we expect the customer to take the minimum volume associated with the service period. If we expect the customer to make up all deficiencies in the specified service period (i.e., we expect the customer to take the minimum service quantities), the minimum volume provision is deemed not substantive and we will recognize the transaction price as revenue in the specified service period as the promised units of service are transferred to the customer. Alternatively, if we expect that there will be any deficiency quantities that the customer cannot or will not make up in the specified service period (referred to as “breakage”), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over such service period in proportion to the revenue that we will recognize for actual units of service transferred to the customer in the service period. For certain take-or-pay contracts where we make the service, or a part of the service (e.g., reservation) continuously available over the service period, we typically recognize the take-or-pay amount as revenue ratably over such period based on the passage of time.

•Contracts with Makeup Rights. If contractually the customer can acquire the promised service in a future period and make up the deficiency quantities in such future period (the “deficiency makeup period”), we have a performance obligation to deliver those services at the customer’s request (subject to contractual and/or capacity constraints) in the deficiency makeup period. At inception of the contract, and at the beginning of each subsequent reporting period, we estimate if we expect that there will be deficiency quantities that the customer will or will not make up. If we expect the customer will make up all deficiencies it is contractually entitled to, any non-refundable consideration received relating to temporary deficiencies that will be made up in the deficiency makeup period will be deferred as a contract liability, and we will recognize that amount as revenue in the deficiency makeup period when either of the following occurs: (i) the customer makes up the volumes or (ii) the likelihood that the customer will exercise its right for deficiency volumes then becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires). Alternatively, if we expect at inception of the contract, or at the beginning of any subsequent reporting period, that there will be any deficiency quantities that the customer cannot or will not make up (i.e., breakage), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over the specified service periods in proportion to the revenue that we will recognize for actual units of service transferred to the customer in those service periods.

Non-Firm Services

Non-firm services (also called interruptible services) are the opposite of firm services in that such services are provided to a customer on an “as available” basis. Generally, we do not have an obligation to perform these services until we accept a customer’s periodic request for service. For the majority of our non-firm service contracts, the customer will pay only for the actual quantities of services it chooses to receive or use, and we typically recognize the transaction price as revenue as those units of service are transferred to the customer in the specified service period (typically a daily or monthly period).

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Contract Balances

Contract assets and contract liabilities are the result of timing differences between revenue recognition, billings and cash collections. We recognize contract assets in those instances where billing occurs subsequent to revenue recognition, and our right to invoice the customer is conditioned on something other than the passage of time. Our contract assets are substantially related to breakage revenue associated with our firm service contracts with minimum volume commitment payment obligations and contracts where we apply revenue levelization (i.e., contracts with fixed rates per volume that increase over the life of the contract for which we record revenue ratably per unit over the life of the contract based on our performance obligations that are generally unchanged over the life of the contract). Our contract liabilities are substantially related to (i) capital improvements paid for in advance by certain customers generally in our non-regulated businesses, which we subsequently recognize as revenue on a straight-line basis over the initial term of the related customer contracts; (ii) consideration received from customers for temporary deficiency quantities under minimum volume contracts that we expect will be made up in a future period, which we subsequently recognize as revenue when the customer makes up the volumes or the likelihood that the customer will exercise its right for deficiency volumes becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires); and (iii) contracts with fixed rates per volume that decrease over the life of the contract where we apply revenue levelization for amounts received for our future performance obligations. We reassess amounts recorded as contract assets or liabilities upon contract modification.

Refer to Note 15 for further information.

Costs of Sales

Costs of sales primarily includes the cost to purchase energy commodities sold, including natural gas, crude oil, NGL and other refined petroleum products, adjusted for the effects of our energy commodity hedging activities, as applicable. Costs of our crude oil, gas and CO2 producing activities, such as those in our CO2 business segment, are not accounted for as costs of sales.

Operations and Maintenance

Operations and maintenance includes costs of services and is primarily comprised of (i) operational labor costs and (ii) operations, maintenance and asset integrity, regulatory and environmental costs. Costs associated with our crude oil, gas and CO2 producing activities included within operations and maintenance totaled $393 million, $367 million and $180 million for the years ended December 31, 2023, 2022 and 2021, respectively.

Environmental Matters

We capitalize certain environmental expenditures required to obtain rights-of-way, regulatory approvals or permitting as part of the construction of facilities we use in our business operations. We accrue and expense environmental costs that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We generally do not discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs, such as after the completion of a feasibility study or commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We record at estimated fair value, where appropriate, environmental liabilities assumed in a business combination.

We routinely conduct reviews of potential environmental issues and claims that assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. We also routinely adjust our environmental liabilities to reflect changes in previous estimates. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us, and potential third-party liability claims we may have against others. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs.

Leases

We lease property including corporate and field offices and facilities, vehicles, heavy work equipment including rail cars and large trucks, tanks, office equipment and land. Our leases have remaining lease terms of one to 47 years, some of which have options to extend or terminate the lease. We determine if an arrangement is a lease at inception or upon modification. For purposes of calculating operating lease liabilities, lease terms may be deemed to include options to extend or terminate the lease when it is reasonably certain that we will exercise that option.
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Our operating ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Leases with variable rate adjustments, such as Consumer Price Index (CPI) adjustments, are reflected based on contractual lease payments as outlined within the lease agreement and not adjusted for any CPI increases or decreases. Because most of our leases do not provide an explicit rate of return, we use our incremental secured borrowing rate based on lease term information available at the commencement date of the lease in determining the present value of lease payments. We have real estate lease agreements with lease and non-lease components, which are accounted for separately. For certain equipment leases, such as copiers and vehicles, we account for the leases under a portfolio method. Leases that were grandfathered under various portions of Topic 842, such as land easements, are reassessed when the agreements are modified.

Refer to Note 17 for further information.

Share-based Compensation
We recognize compensation expense ratably over the vesting period of the restricted stock award based on the grant-date fair value, which is determined based on the market price of our Class P common stock on the grant date, less estimated forfeitures. Forfeiture rates are estimated based on historical forfeitures under our restricted stock award plans. Upon vesting, the restricted stock award will be paid in shares for approximately $250 million. Subsequent to December 31, 2017 and through February 8, 2018, we repurchased approximately 13 million of our Class P sharescommon stock.
Pensions and Other Postretirement Benefits

We recognize the differences between the fair value of each of our and our consolidated subsidiaries’ pension and other postretirement benefit plans’ assets and the benefit obligations as either assets or liabilities on our consolidated balance sheets. We record deferred plan costs and income—unrecognized losses and gains, unrecognized prior service costs and credits, and any remaining unamortized transition obligations—net of income taxes in “Accumulated other comprehensive loss,” with the proportionate share associated with less than wholly owned consolidated subsidiaries allocated and included within “Noncontrolling interests,” or as a regulatory asset or liability for approximately $250 million.certain of our regulated operations, until they are amortized as a component of benefit expense.


Deferred Financing Costs

We capitalize financing costs incurred with new borrowings and amortize the costs over the contractual term of the related obligations.

Redeemable Noncontrolling Interest

Through December 14, 2021, we had a redeemable noncontrolling interest which represented the interest in one of our consolidated subsidiaries, not owned by us, and which in certain limited circumstances, the partner had the right to relinquish its interest in the subsidiary. Distributions paid to the partner prior to that date were recorded as a reduction to the redeemable noncontrolling interest balance and included in “Distributions to investment partner” in our accompanying consolidated statement of cash flows. On December 14, 2021, the ownership agreement was modified such that the noncontrolling interest was no longer contingently redeemable, and the balance was reclassified to “Noncontrolling Interests.” Net income attributable to redeemable noncontrolling interest was $58 million for the year ended December 31, 2021 and is included in “Net Income Attributable to Noncontrolling Interests” in our accompanying consolidated statement of income.

Noncontrolling InterestsEnergy Commodity Market Risk
Contributions
KML Restricted Voting SharesWe enter into certain energy commodity derivative contracts in order to reduce and minimize the risks encountered in the ordinary course of business associated with unfavorable changes in the market price of crude oil, natural gas and NGL. The derivative contracts that we use include exchange-traded and OTC commodity financial instruments, including, but not limited to, futures and options contracts, fixed price swaps and basis swaps. We may categorize such use of energy commodity derivative contracts as cash flow hedges because the derivative contract is used to hedge the anticipated future cash flow of a transaction that is expected to occur but whose value is uncertain.
As discussed
Our hedging strategy involves entering into a financial position intended to offset our physical position, or anticipated position, in Note 3 “Acquisitionsorder to minimize the risk of financial loss from an adverse price change. For example, as sellers of crude oil, natural gas and Divestitures”NGL, we often enter into fixed price swaps and/or futures contracts to guarantee or lock-in the sale price of our crude oil or the margin from the sale and purchase of our natural gas at the time of market delivery, thereby in whole or in part offsetting any change in prices, either positive or negative. Using derivative contracts for this purpose helps provide increased certainty with regard to operating cash flows which helps us to undertake further capital improvement projects, attain budget results and meet dividend targets.

Our policies require that derivative contracts are only entered into with carefully selected major financial institutions or similar counterparties based upon their credit ratings and other factors, and we maintain strict dollar and term limits that correspond to our consolidated financial statements, on May 30, 2017counterparties’ credit ratings. While it is our indirect subsidiary, KML, issued 102,942,000 restricted voting sharespolicy to enter into derivative transactions principally with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that losses will result from counterparty credit risk in the future.

We measure the risk of price changes in the derivative instrument portfolios utilizing a public offering.sensitivity analysis model. The public ownershipsensitivity analysis applied to each portfolio measures the potential income or loss (i.e., the change in fair value of the KML restricted voting shares represents an approximate 30% interestderivative instrument portfolio) based upon a hypothetical 10% movement in the voting sharesunderlying quoted market prices. In addition to these variables, the fair value of each portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. Because we enter into derivative contracts largely for the purpose of mitigating the risks that accompany certain of our Canadian operationsbusiness activities, both in the sensitivity analysis model and in reality, the change in the market value of the derivative contracts’ portfolio is reflected within “Noncontrolling interests”offset largely by changes in our consolidated financial statements asthe value of and for the periods presented after May 30, 2017.
KML Preferred Share Offerings

On August 15, 2017, KML completed an offering of 12,000,000 cumulative redeemable minimum rate reset preferred shares, Series 1 (Series 1 Preferred Shares)underlying physical transactions. A hypothetical 10% movement in the underlying commodity prices would have the following effect on the Toronto Stock Exchange at a price to the public of C$25.00 per Series 1 Preferred Share for total gross proceeds of C$300 million (U.S.$235 million). On December 15, 2017, KML completed an offering of 10,000,000 cumulative redeemable minimum rate reset preferred shares, Series 3 (Series 3 Preferred Shares) on the Toronto Stock Exchange at a price to the public of C$25.00 per Series 3 Preferred Share for total gross proceeds of C$250 million (U.S.$195 million). The net proceeds from the Series 1 and Series 3 Preferred Share offerings of C$293 million (U.S.$230 million) and C$243 million (U.S.$189 million), respectively, were used by KML to indirectly subscribe for preferred units in Kinder Morgan Canada Limited Partnership (KMC LP), which in turn were used by KMC LP to repay KML Credit Facility indebtedness recently incurred to, directly or indirectly, finance the development, construction and completion of the TMEP and Base Line Terminal project, and for general corporate purposes.associated derivative contracts’ estimated fair value:

As of December 31,
Commodity derivative20232022
(In millions)
Crude oil$127 $157 
Natural gas28 49 
NGL4 5 
Total$159 $211 
KML Distributions
KML established a dividend policy pursuant to which it may pay a quarterly dividend on its restricted voting shares in an amount based on a portion of its DCF. The payment of dividends is not guaranteed and the amount and timing of any dividends payable will be at the discretion of KML’s board of directors. The actual amount of cash dividends paid to KML’s shareholders, if any, will depend on numerous factors including: (i) KML’s results of operations; (ii) KML’s financial requirements, including the funding of its current and future growth projects; (iii) the amount of distributions paid indirectly by KMC LP to KML through Kinder Morgan Canada GP Inc. (KMC GP), including any contributions from the completion of its growth projects; (iv) the satisfaction by KML and KMC GP of certain liquidity and solvency tests; (v) any agreements relating to KML’s indebtedness or the limited partnership; and (vi) the cost and timely completion of current and future growth projects. KML intends to pay quarterly dividends, if any, on or about the 45th day (or next business day) following the end of each calendar quarter to holders of its restricted voting shares of record as of the close of business on or about the last business day of the month following the end of each calendar quarter.

KML also established a Dividend Reinvestment Plan (DRIP) which allows holders (excluding holders not resident in Canada) of restricted voting shares to elect to have any or all cash dividends payable to such shareholder automatically reinvested in additional restricted voting shares at a price per share calculated by reference to the volume-weighted average of the closing price of the restricted voting shares on the stock exchange on which the restricted voting shares are then listed for the five trading days immediately preceding the relevant dividend payment date, less a discount of between 0% and 5% (as determined from time to time by KML’s board of directors, in its sole discretion).

For 2018, KML announced that it expects to pay an annual dividend of C$0.65 per restricted voting share.

Dividends on the Series 1 Preferred Shares are fixed, cumulative, preferential and C$1.3125 per share annually, payable quarterly on the 15th day of February, May, August and November, as and when declared by the KML’s board of directors, for the initial fixed rate period to but excluding November 15, 2022.

Dividends on the Series 3 Preferred Shares are fixed, cumulative, preferential and C$1.3000 per share annually, payable quarterly on the 15th day of February, May, August and November, as and when declared by the KML’s board of directors, for the initial fixed rate period to but excluding February 15, 2023.

The following table provides information regarding distributions to our noncontrolling interests (in millions except per share and share distribution amounts):
  Year Ended December 31, 2017
  Shares U.S.$ C$
KML Restricted Voting Shares(a)      
Per restricted voting share declared for the period(b)     $0.3821
Per restricted voting share paid in the period   $0.1739 0.2196
Total value of distributions paid in the period   18 23
Cash distributions paid in the period to the public   13 16
Share distributions paid in the period to the public under KML’s DRIP 418,989    
KML Series 1 Preferred Shares(c)      
Per Series 1 Preferred Share paid in the period   $0.2624 $0.3308
Cash distributions paid in the period to the public   3 4
_______
(a)Represents dividends subsequent to KML’s May 30, 2017 IPO.
(b)The U.S.$ equivalent of the dividends declared is calculated based on the exchange rate on the dividend payment date, therefore, the U.S.$ equivalent of the dividend declared for the fourth quarter of 2017 will be calculated using the exchange rate on February 15, 2018.
The combined U.S.$ equivalent of the dividends declared for the second and third quarters of 2017 was $0.1739.
(c)Represents dividends subsequent to the issuance of KML’s Series 1 Preferred Shares.

On January 17, 2018, KML’s board of directors declared a cash dividend of C$0.328125 per share of its Series 1 Preferred Shares for the period from and including November 15, 2017 through and including February 14, 2018, which is payable on February 15, 2018 to Series 1 Preferred Shareholders of record as of the close of business on January 31, 2018.

On January 17, 2018, KML’s board of directors declared a cash dividend of C$0.22082 per share of its Series 3 Preferred Shares for the period from and including December 15, 2017 through and including February 14, 2018, which is payable on February 15, 2018 to Series 3 Preferred Shareholders of record as of the close of business on January 31, 2018.

Recent Accounting Pronouncements
Please refer to Note 18 “Recent Accounting Pronouncements” to our consolidated financial statements for information concerning recent accounting pronouncements.
Item 7A.  Quantitative and Qualitative Disclosures About Market Risk.
Generally, our market risk sensitive instruments and positions have been determined to be “other than trading.”  Our exposure to market risk as discussed below includes forward-looking statements andsensitivity analysis represents an estimate of the reasonably possible changes in fair value or future earningsgains and losses that would occurbe recognized on the crude oil, natural gas and NGL portfolios of derivative contracts assuming hypothetical future movements in energy commodity prices or interest rates.  Our views onfuture market risk are rates and is
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not necessarily indicative of actual results that may occur and dooccur. It does not represent the

maximum possible gains and lossesloss or any expected loss that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ from estimates due to actual fluctuations in market rates, operating exposures and the timing thereof, as well as changes in our portfolio of derivatives during the year.

Interest Rate Risk

In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt. Fixed-to-variable interest rate swap agreements are entered into for the purpose of converting a portion of the underlying cash flows related to long-term fixed rate debt securities into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. Variable-to-fixed interest rate swap agreements are entered into primarily for the purpose of managing our exposure to changes in interest rates on our debt balances that are subject to variable interest rates and adjusting, on a short-term basis, our mix of fixed rate debt and variable rate debt based on changes in market conditions. The market risk inherent in our debt instruments and positions is the potential change arising from increases or decreases in interest rates as discussed below.

For fixed rate debt, changes in interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows. Generally, there is not an obligation to prepay fixed rate debt prior to maturity and, as a result, changes in fair value should not have a significant impact on the fixed rate debt. We are generally subject to interest rate risk upon refinancing maturing debt. Below are our debt balances, including debt fair value adjustments, and sensitivity to interest rates:
 December 31, 2023December 31, 2022
 Carrying
value		Estimated
fair value(a)		Carrying
value		Estimated
fair value(a)
(In millions)
Fixed rate debt(b)$30,063 $29,317 $31,474 $29,756 
Variable rate debt$2,053 $2,053 $314 $314 
Notional principal amount of variable-to-fixed interest rate swap agreements(c)— (1,500)
Notional principal amount of fixed-to-variable interest rate swap agreements6,200 7,500 
Debt balances subject to variable interest rates(d)$8,253 $6,314 
(a)Fair values were determined using Level 2 inputs.
(b)A hypothetical 10% change in the average interest rates applicable to such debt as of December 31, 2023 and 2022, would result in changes of approximately $1,889 million and $1,882 million, respectively, in the estimated fair values of these instruments.
(c)December 31, 2022 amount includes $1.25 billion that expired in December 2023.
(d)A hypothetical 10% change in the weighted average interest rate on all of our borrowings (approximately 58 and 48 basis points in 2023 and 2022, respectively) when applied to our outstanding balance of variable rate debt as of December 31, 2023 and 2022, including adjustments for the notional swap amounts described in the table above, would result in changes of approximately $48 million and $30 million, respectively.

As presented in the table above, we monitor the mix of fixed rate and variable rate debt obligations in light of changing market conditions and from time to time, may alter that mix by, for example, refinancing outstanding balances of variable rate debt with fixed rate debt (or vice versa) or by entering into interest rate swap agreements or other interest rate hedging agreements. As of December 31, 2023, including debt converted to variable rates through the use of interest rate swaps but excluding our debt fair value adjustments, approximately 26% of our debt balances were subject to variable interest rates.

For more information on our interest rate risk management and on our interest rate swap agreements, see Note 14 “Risk Management” to our consolidated financial statements.

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Foreign Currency Risk

As of December 31, 2023, we had a notional principal amount of $543 million of cross-currency swap agreements that effectively convert all of our fixed-rate Euro denominated debt, including annual interest payments and the payment of principal at maturity, to U.S. dollar denominated debt at fixed rates. These swaps eliminate the foreign currency risk associated with our foreign currency denominated debt.

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Item 8.  Financial Statements and Supplementary Data.



KINDER MORGAN, INC. AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS
Page
Number
(PCAOB ID: 238)
71
74
75
76
77
79
80
Note 1.
80
Note 2.
80
Note 3.
90
Note 4.
93
Note 5.
94
Note 6.
97
Note 7.
98
Note 8.
99
Note 9.
100
Note 10.
104
Note 11.
110
Note 12.
112
Note 13.
112
Note 14.
113
Note 15.
118
Note 16.
121
Note 17.
125
Note 18.
126
Note 19.
130
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Report of Independent Registered Public Accounting Firm

To theBoard of Directors and Stockholders of Kinder Morgan, Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Kinder Morgan, Inc. and its subsidiaries (the “Company”) as of December 31, 2023 and 2022,and the related consolidated statements of income, of comprehensive income, of stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2023, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of itsoperations and itscash flows for each of the three years in the period ended December 31, 2023 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework(2013)issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As described in Management’s Report on Internal Control over Financial Reporting, management has excluded STX Midstream from its assessment of internal control over financial reporting as of December 31, 2023, because it was acquired by the Company in a purchase business combination during 2023. We have also excluded STX Midstream from our audit of internal control over financial reporting. STX Midstream’s total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting both represent less than 3% of the related consolidated financial statement amounts as of and for the year ended December 31, 2023.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the
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company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Goodwill Impairment Assessment – Natural Gas Pipelines Regulated, Natural Gas Pipelines Non-Regulated, CO2, Products Pipelines, Products Pipelines Terminals, and Terminals Reporting Units

As described in Notes 2 and 8 to the consolidated financial statements, the Company’s consolidated goodwill balance was $20.1 billion as of December 31, 2023, of which $20.0 billion relates to the Natural Gas Pipelines Regulated, Natural Gas Pipelines Non-Regulated, CO2, Products Pipelines, Products Pipelines Terminals, and Terminals reporting units (collectively, “the reporting units”). Management evaluates goodwill for impairment on May 31 of each year, or more frequently to the extent events occur or conditions change between annual tests that would indicate a risk of possible impairment at the interim period. Management estimated the fair value of the reporting units based on a market approach utilizing forecasted earnings before interest, income taxes, depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments (EBITDA), and the enterprise value to estimated EBITDA multiples of comparable companies for each reporting unit.

The principal considerations for our determination that performing procedures relating to the goodwill impairment assessment of the reporting units is a critical audit matter are (i) the significant judgment by management when developing the fair value estimate of the reporting units; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to forecasted EBITDA and the enterprise value to estimated EBITDA multiples of comparable companies for each of the reporting units; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s goodwill impairment assessment, including controls over developing the fair value estimate of the reporting units. These procedures also included, among others (i) testing management’s process for developing the fair value estimate of the reporting units; (ii) evaluating the appropriateness of the market approach used by management; (iii) testing the completeness and accuracy of underlying data used in the market approach; and (iv) evaluating the reasonableness of the significant assumptions used by management related to forecasted EBITDA and the enterprise value to estimated EBITDA multiples of comparable companies for each of the reporting units. Evaluating management’s assumptions related to forecasted EBITDA and the enterprise value to estimated EBITDA multiples of comparable companies for each of the reporting units involved evaluating whether the assumptions used by management were reasonable considering (i) the current and past performance of the reporting units; (ii) the consistency with external market and industry data; and (iii) whether these assumptions were consistent with evidence obtained in other areas of the audit. Professionals with specialized skill and knowledge were used to assist in evaluating (i) the appropriateness of the market approach and (ii) the reasonableness of the assumption related to the enterprise value to estimated EBITDA multiples of comparable companies for each of the reporting units.

Acquisition of STX Midstream – Valuation of Property, Plant and Equipment

As described in Note 3 to the consolidated financial statements, on December 28, 2023, the Company completed the acquisition of STX Midstream for a purchase price of $1.8 billion. This acquisition resulted in the recognition of $1.2 billion of property, plant and equipment (PP&E). For acquired businesses, the Company recognizes the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Management determined the fair value of PP&E utilizing a replacement cost approach. Determining the fair value of this item requires management judgment and the utilization of an independent valuation specialist and involves the use of significant estimates and assumptions. The significant assumption made in performing this valuation includes the replacement costs used to value PP&E.

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The principal considerations for our determination that performing procedures relating to the valuation of PP&E acquired in the acquisition of STX Midstream is a critical audit matter are (i) the significant judgment by management when developing the fair value estimate of the PP&E acquired; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumption related to the replacement costs used to value the PP&E acquired; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the acquisition accounting, including controls over management’s valuation of the PP&E acquired. These procedures also included, among others (i) reading the purchase agreement; (ii) testing management’s process for developing the fair value estimate of the PP&E acquired; (iii) evaluating the appropriateness of the replacement cost approach used by management; (iv) testing the completeness and accuracy of underlying data used in the replacement cost approach; and (v) evaluating the reasonableness of the significant assumption used by management related to the replacement costs used to value the PP&E acquired. Professionals with specialized skill and knowledge were used to assist in evaluating (i) the appropriateness of the replacement cost approach and (ii) the reasonableness of the replacement costs assumption used to value the PP&E acquired.


/s/ PricewaterhouseCoopers LLP

Houston, Texas
February 20, 2024

We have served as the Company’s auditor since 1997.
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KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share amounts)
 Year Ended December 31,
 202320222021
Revenues 
Services$8,371 $8,145 $7,757 
Commodity sales6,786 10,897 8,714 
Other177 158 139 
Total Revenues15,334 19,200 16,610 
Operating Costs, Expenses and Other
Costs of sales (exclusive of items shown separately below)4,938 9,255 6,493 
Operations and maintenance2,807 2,655 2,368 
Depreciation, depletion and amortization2,250 2,186 2,135 
General and administrative668 637 655 
Taxes, other than income taxes421 441 426 
(Gain) loss on divestitures and impairments, net (Note 4)(15)(32)1,624 
Other expense (income), net2 (7)(7)
Total Operating Costs, Expenses and Other11,071 15,135 13,694 
Operating Income4,263 4,065 2,916 
Other Income (Expense)
Earnings from equity investments838 803 591 
Amortization of excess cost of equity investments(66)(75)(78)
Interest, net(1,797)(1,513)(1,492)
Other, net (Note 3)(37)55 282 
Total Other Expense(1,062)(730)(697)
Income Before Income Taxes3,201 3,335 2,219 
Income Tax Expense(715)(710)(369)
Net Income2,486 2,625 1,850 
Net Income Attributable to Noncontrolling Interests(95)(77)(66)
Net Income Attributable to Kinder Morgan, Inc.$2,391 $2,548 $1,784 
Class P Common Stock 
Basic and Diluted Earnings Per Share$1.06 $1.12 $0.78 
Basic and Diluted Weighted Average Shares Outstanding2,234 2,258 2,266 

The accompanying notes are an integral part of these consolidated financial statements.
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KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
Year Ended December 31,
 202320222021
Net income$2,486 $2,625 $1,850 
Other comprehensive income (loss), net of tax 
Net unrealized gain (loss) from derivative instruments (net of taxes of $(47), $92, and $131, respectively)155 (312)(432)
Reclassification into earnings of net derivative instruments loss (gain) to net income (net of taxes of $12, $(95), and $(83), respectively)(35)320 273 
Benefit plan adjustments (net of taxes of $(20), $(1), and $(47), respectively)65 1 155 
Total other comprehensive income (loss)185 9 (4)
Comprehensive income2,671 2,634 1,846 
Comprehensive income attributable to noncontrolling interests(95)(77)(66)
Comprehensive income attributable to KMI$2,576 $2,557 $1,780 

The accompanying notes are an integral part of these consolidated financial statements.
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KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions, except share and per share amounts)
 December 31,
 20232022
ASSETS  
Current assets  
Cash and cash equivalents$83 $745 
Restricted deposits13 49 
Accounts receivable1,588 1,840 
Fair value of derivative contracts126 231 
Inventories525 634 
Other current assets207 304 
Total current assets2,542 3,803 
Property, plant and equipment, net37,297 35,599 
Investments7,874 7,653 
Goodwill20,121 19,965 
Other intangibles, net1,957 1,809 
Deferred charges and other assets1,229 1,249 
Total Assets$71,020 $70,078 
LIABILITIES AND STOCKHOLDERS’ EQUITY  
Current liabilities  
Current portion of debt$4,049 $3,385 
Accounts payable1,366 1,444 
Accrued interest513 515 
Accrued taxes272 264 
Fair value of derivative contracts205 465 
Other current liabilities816 857 
Total current liabilities7,221 6,930 
Long-term liabilities and deferred credits  
Long-term debt
Outstanding27,880 28,288 
Debt fair value adjustments187 115 
Total long-term debt28,067 28,403 
Deferred income taxes1,388 623 
Other long-term liabilities and deferred credits2,615 2,008 
Total long-term liabilities and deferred credits32,070 31,034 
Total Liabilities39,291 37,964 
Commitments and contingencies (Notes 9, 13, 17 and 18)
Stockholders’ Equity  
Class P Common Stock, $0.01 par value, 4,000,000,000 shares authorized, 2,219,729,644 and 2,247,681,626 shares, respectively, issued and outstanding22 22 
Additional paid-in capital41,190 41,673 
Accumulated deficit(10,689)(10,551)
Accumulated other comprehensive loss(217)(402)
Total Kinder Morgan, Inc.’s stockholders’ equity30,306 30,742 
Noncontrolling interests1,423 1,372 
Total Stockholders’ Equity31,729 32,114 
Total Liabilities and Stockholders’ Equity$71,020 $70,078 

The accompanying notes are an integral part of these consolidated financial statements.
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KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
 Year Ended December 31,
 202320222021
Cash Flows From Operating Activities   
Net income$2,486 $2,625 $1,850 
Adjustments to reconcile net income to net cash provided by operating activities   
Depreciation, depletion and amortization2,250 2,186 2,135 
Deferred income taxes710 692 355 
Amortization of excess cost of equity investments66 75 78 
Change in fair market value of derivative contracts(126)56 20 
(Gain) loss on divestitures and impairments, net (Note 4)(15)(32)1,624 
Gain on sale of interest in equity investment (Note 3)— — (206)
Earnings from equity investments(838)(803)(591)
Distributions of equity investment earnings755 725 720 
Pension contributions net of noncash pension benefit expenses77 (50)(39)
Changes in components of working capital, net of the effects of acquisitions and dispositions   
Accounts receivable301 (220)(265)
Inventories188 (183)(202)
Other current assets108 (51)(109)
Accounts payable(201)161 387 
Accrued interest, net of interest rate swaps(13)50 (17)
Other current liabilities(58)6 165 
Change in deferred revenues (Note 15)870 (24)(28)
Rate reparations, refunds and other litigation reserve adjustments(19)(190)(57)
Other, net(50)(56)(112)
Net Cash Provided by Operating Activities6,491 4,967 5,708 
Cash Flows From Investing Activities   
Acquisitions of assets and investments, net of cash acquired (Note 3)(1,842)(487)(1,547)
Capital expenditures(2,317)(1,621)(1,281)
Sales of property, plant and equipment, investments, and other net assets, net of removal costs(28)6 406 
Contributions to investments(212)(229)(38)
Distributions from equity investments in excess of cumulative earnings228 156 163 
Other, net(4)— (8)
Net Cash Used in Investing Activities(4,175)(2,175)(2,305)
Cash Flows From Financing Activities
Issuances of debt7,590 9,058 5,959 
Payments of debt(7,356)(9,735)(6,831)
Debt issue costs(20)(25)(27)
Dividends (Note 11)(2,529)(2,504)(2,443)
Repurchases of shares (Note 11)(522)(368)— 
Proceeds from sale of noncontrolling interests (Note 3)— 557 — 
Contributions from noncontrolling interests3 2 4 
Distributions to investment partner— — (82)
Distributions to noncontrolling interests(151)(116)(20)
Other, net(29)(14)(25)
Net Cash Used in Financing Activities(3,014)(3,145)(3,465)
Net Decrease in Cash, Cash Equivalents and Restricted Deposits(698)(353)(62)
Cash, Cash Equivalents and Restricted Deposits, beginning of period794 1,147 1,209 
Cash, Cash Equivalents and Restricted Deposits, end of period$96 $794 $1,147 
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KINDER MORGAN, INC. AND SUBSIDIARIES (continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
 Year Ended December 31,
 202320222021
Cash and Cash Equivalents, beginning of period$745 $1,140 $1,184 
Restricted Deposits, beginning of period49 7 25 
Cash, Cash Equivalents and Restricted Deposits, beginning of period794 1,147 1,209 
Cash and Cash Equivalents, end of period83 745 1,140 
Restricted Deposits, end of period13 49 7 
Cash, Cash Equivalents and Restricted Deposits, end of period96 794 1,147 
Net Decrease in Cash, Cash Equivalents and Restricted Deposits$(698)$(353)$(62)
Noncash Investing and Financing Activities
Assets contributed to equity investment$16 $— $— 
Net increase in property, plant and equipment from both accruals and contractor retainage120 72 74 
ROU assets and operating lease obligations recognized (Note 17)56 22 59 
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)1,844 1,460 1,529 
Cash paid during the period for income taxes, net11 13 10 

The accompanying notes are an integral part of these consolidated financial statements.
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KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In millions)
Common stockAdditional
paid-in
capital		Accumulated
deficit		Accumulated
other
comprehensive
loss		Stockholders’
equity
attributable
to KMI		Non-controlling
interests		Total
 Issued sharesPar value
Balance at December 31, 20202,264 $23 $41,756 $(9,936)$(407)$31,436 $402 $31,838 
Restricted shares3 50 50 50 
Net income1,784 1,784 66 1,850 
Dividends(2,443)(2,443)(2,443)
Distributions— (20)(20)
Contributions— 4 4 
Reclassification of redeemable noncontrolling interest— 646 646 
Other comprehensive loss(4)(4)(4)
Balance at December 31, 20212,267 23 41,806 (10,595)(411)30,823 1,098 31,921 
Impact of adoption of ASU 2020-06 (Note 11)(11)(11)(11)
Balance at January 1, 20222,267 23 41,795 (10,595)(411)30,812 1,098 31,910 
Repurchases of shares(21)(1)(367)(368)(368)
EP Trust I Preferred security conversions1 1 1 
Restricted shares2 54 54 54 
Net income2,548 2,548 77 2,625 
Dividends(2,504)(2,504)(2,504)
Distributions— (116)(116)
Contributions— 2 2 
Impact of change in ownership interest in subsidiary190 190 311 501 
Other comprehensive income9 9 9 
Balance at December 31, 20222,248 22 41,673 (10,551)(402)30,742 1,372 32,114 
Repurchases of shares(32)(522)(522)(522)
Restricted shares4 44 44 44 
Net income2,391 2,391 95 2,486 
Dividends(2,529)(2,529)(2,529)
Distributions— (151)(151)
Contributions— 3 3 
Acquisition (Note 3)— 104 104 
Other(5)(5)(5)
Other comprehensive income185 185 185 
Balance at December 31, 20232,220 $22 $41,190 $(10,689)$(217)$30,306 $1,423 $31,729 

The accompanying notes are an integral part of these consolidated financial statements.
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KINDER MORGAN, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.General

We are one of the largest energy infrastructure companies in North America. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company,” or “KMI” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2, renewable fuels and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, jet fuel, chemicals, metals, petroleum coke, and ethanol and other renewable fuels and feedstocks.
2.Summary of Significant Accounting Policies

Basis of Presentation

Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars, unless stated otherwise. Our accompanying consolidated financial statements have been prepared under the rules and regulations of the SEC. These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification (ASC), the single source of GAAP. Under such rules and regulations, all significant intercompany items have been eliminated in consolidation. Additionally, certain amounts from prior years have been reclassified to conform to the current presentation.

Use of Estimates

Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities, our revenues and expenses during the reporting period, and our disclosures, including those related to contingent assets and liabilities at the date of our financial statements. We evaluate these estimates on an ongoing basis, 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. 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.

Certain accounting policies are of more significance in our financial statement preparation process than others, and set out below are the principal accounting policies we apply in the preparation of our consolidated financial statements.

Cash Equivalents and Restricted Deposits

We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less.

Amounts included in the restricted deposits in the accompanying consolidated financial statements represent a combination of restricted cash amounts required to be set aside by regulatory agencies to cover obligations for our captive insurance subsidiary, cash margin deposits posted by us with our counterparties associated with certain energy commodity contract positions and escrow deposits.

Allowance for Credit Losses

We evaluate our financial assets measured at amortized cost and off-balance sheet credit exposures for expected credit losses over the contractual term of the asset or exposure. We consider available information relevant to assessing the collectability of cash flows including the expected risk of credit loss even if that risk is remote. We measure expected credit losses on a collective (pool) basis when similar risk characteristics exist, and we reflect the expected credit losses on the amortized cost basis of the financial asset as of the reporting date.

Our financial instruments primarily consist of our accounts receivable from customers, notes receivable from affiliates and contingent liabilities such as proportional guarantees of debt obligations of an equity investee. We utilized historical analysis of credit losses experienced over the previous five years along with current conditions and reasonable and supportable forecasts of future conditions in our evaluation of collectability of our financial assets.
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Our allowance for credit losses as of both December 31, 2023 and 2022 was $1 million and is included in “Other current assets” in our accompanying consolidated balance sheets.

Inventories

Our inventories consist of materials and supplies and products such as natural gas, NGL, crude oil, condensate, refined petroleum products and transmix. We report products inventory at the lower of weighted-average cost or net realizable value. We report materials and supplies inventories at cost, and periodically review for physical deterioration and obsolescence.

Property, Plant and Equipment, net

Capitalization, Depreciation and Depletion and Disposals

We report property, plant and equipment at its acquisition cost. We expense costs for routine maintenance and repairs in the period incurred. The following table summarizes our significant policies related to our property, plant and equipment. The application of these policies can involve significant estimates.
AssetAccounting AreaPolicy
Straight-line assetsDepreciation rates
•Depreciable lives are based on estimated economic lives. This includes age, manufacturing specifications, technological advances, estimated production life of the oil or gas field served by the asset, contract terms for assets on leased or customer property and historical data concerning useful lives of similar assets.
Gains and losses
•A gain or loss on the sale of property, plant and equipment is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sale proceeds received or when held for sale, the market value of the asset.
•A gain on an asset disposal is recognized in income in the period that the sale is closed.
•A loss is recognized when the asset is sold or when classified as held for sale.
•Gains and losses are recorded in operating costs, expenses and other.
Composite assetsDepreciation rates
•A single depreciation rate is applied to the total cost of a functional group of assets that have similar economic characteristics until the net book value of the composite group equals the salvage value.
•Interstate natural gas FERC-regulated entities use the depreciation rates approved by the FERC.
•A depreciation rate for other composite assets is based on estimated economic lives. This includes age, manufacturing specifications, technological advances, estimated production life of the oil or gas field served by the asset, contract terms for assets on leased or customer property and historical data concerning useful lives of similar assets.
Gains and losses
•Gains and losses are credited or charged to accumulated depreciation, net of salvage and cost of removal.
•Gains and losses on FERC-approved operating unit sales and land sales are recorded in operating costs, expenses and other.
Oil and gas producing activities(a)Successful efforts method of accounting
•Costs that are incurred to acquire leasehold and subsequent development costs are capitalized.
•Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found.
•Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of certain non-producing leasehold costs are expensed as incurred.
•The capitalized costs of our producing oil and gas properties are depreciated and depleted by the units-of-production method.
•Other miscellaneous property, plant and equipment are depreciated over the estimated useful lives of the asset.
Enhanced recovery techniques
•In some cases, the cost of the CO2 associated with enhanced recovery is capitalized as part of our development costs when it is injected.
•The cost of CO2 associated with pressure maintenance operations for reservoir management is expensed when it is injected.
•When CO2 is recovered in conjunction with oil production, it is extracted and re-injected, and all of the associated costs are expensed as incurred.
•Proved developed reserves are used in computing units of production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs.
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(a)Gains and losses associated with assets in our oil and gas producing activities have a similar treatment as with that associated with our straight-line assets.

Circumstances may develop which cause us to change our estimates, thus impacting the future calculation of depreciation and amortization expense. Historically, adjustments to useful lives have not had a material impact on our aggregate depreciation levels from year to year.

Asset Retirement Obligations

We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses. The majority of our asset retirement obligations are associated with our CO2 business where we are required to plug and abandon oil and gas wells that have been removed from service and to remove the surface wellhead equipment and compressors, but we also have obligations for certain gathering and long-haul pipelines and certain processing plants. We record, as liabilities, the fair value of asset retirement obligations on a discounted basis when they are incurred and can be reasonably estimated, which is typically at the time the assets are installed or acquired. The fair value estimates are primarily based on Level 3 inputs of the fair value hierarchy. The inputs include estimates and assumptions related to timing of settlement and retirement costs, which we base on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities are accreted to reflect the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service. Our estimates of retirement costs could change as a result of changes in cost estimates and/or timing of the obligation.

The following table summarizes changes in the asset retirement obligations included in our accompanying consolidated balance sheets:
December 31,
20232022
(In millions)
Balance at beginning of period$204 $196 
Accretion expense12 12 
New obligations22 2 
Settlements(7)(6)
Balance at end of period(a)$231 $204 
(a)Balances at both December 31, 2023 and 2022 include $3 million included within “Other current liabilities” on our accompanying consolidated balance sheets.

For certain assets, we currently cannot reasonably estimate the fair value of the asset retirement obligations because the associated assets have indeterminate lives. These assets include certain pipelines, processing plants and distribution facilities, and liquids and bulk terminal facilities. Based on the widespread use of hydrocarbons domestically and for international export, management expects supply and demand to exist for the foreseeable future. Therefore, the remaining useful lives of these assets are indeterminate due to prolonged expected demand. Additionally, these assets could also benefit from potential future conversion opportunities. For example, certain assets could be converted to transport, handle or store products other than traditional hydrocarbons. Under our integrity program, individual asset parts are replaced regularly. Although some of the individual asset parts may be replaced, the assets themselves may remain intact indefinitely. For these assets, an asset retirement obligation, if any, will be recognized once sufficient information is available to reasonably estimate the fair value of the obligation.

Long-lived Asset Impairments

We evaluate long-lived assets including leases and investments for impairment whenever events or changes in circumstances indicate that our carrying amount of an asset or investment may not be recoverable.

In addition to our annual goodwill impairment test discussed further below, to the extent triggering events exist, we complete a review of the carrying value of our long-lived assets, including property, plant and equipment as well as other intangibles, and record, as applicable, the appropriate impairments using a two-step approach. To determine if a long-lived asset is recoverable, we compare the asset’s estimated undiscounted cash flows to its carrying value (step 1). Because the impairment test for long-lived assets held in use is based on estimated undiscounted cash flows, there may be instances where
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an asset or asset group is not considered impaired, even when its fair value may be less than its carrying value, because the asset or asset group is recoverable based on the cash flows to be generated over the estimated life of the asset or asset group. If the carrying value of a long-lived asset or asset group is in excess of estimated undiscounted cash flows, we typically use discounted cash flow analyses to calculate the fair value of the long-lived asset to determine if an impairment is required and the amount of the impairment losses to be recognized (step 2).

We evaluate our oil and gas producing properties for impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure, using undiscounted future cash flows based on estimated future oil and gas production volumes.

Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future cash flows based on estimated future oil and gas production volumes.  Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment.

Refer to Note 4 for further information.

Equity Method of Accounting and Basis Differences

We use the equity method of accounting for investments which we do not control, but for which we have the ability to exercise significant influence. The carrying values of these investments are impacted by our share of investee income or loss, distributions, amortization or accretion of basis differences and other-than-temporary impairments.

The difference between the carrying value of an investment and our share of the investment’s underlying equity in net assets is referred to as a basis difference. If the basis difference is assigned to depreciable or amortizable assets and liabilities, the basis difference is amortized or accreted as part of our share of investee earnings. To the extent that the basis difference relates to goodwill, referred to as equity method goodwill, the amount is not amortized.

We evaluate our equity method investments for other-than-temporary impairment. When an other-than-temporary impairment is recognized, the loss is recorded as a reduction in equity earnings.

Goodwill

Goodwill is the cost of an acquisition of a business in excess of the fair value of acquired assets and liabilities and is recorded as an asset on our balance sheet. Goodwill is not subject to amortization but must be tested for impairment at least annually and in interim periods if indicators of impairment exist. This test requires us to assign goodwill to an appropriate reporting unit and compare the fair value of a reporting unit to its carrying value. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value an impairment is measured and recorded at the amount by which the reporting unit’s carrying value exceeds its fair value.

We evaluate goodwill for impairment on May 31 of each year, or more frequently to the extent events occur or conditions change between annual tests that would indicate a risk of possible impairment at the interim period.  For purposes of our May 31, 2023 evaluation, we grouped our businesses into seven reporting units as follows: (i) Natural Gas Pipelines Regulated; (ii) Natural Gas Pipelines Non-Regulated; (iii) CO2; (iv) Products Pipelines (excluding associated terminals); (v) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (vi) Terminals; and (vii) Energy Transition Ventures. Generally, the evaluation of goodwill for impairment involves a quantitative test, although under certain circumstances an initial qualitative evaluation may be sufficient to conclude that goodwill is not impaired without conducting the quantitative test.

A large portion of our goodwill is non-deductible for tax purposes, and as such, to the extent there are impairments, all or a portion of the impairment may not result in a corresponding tax benefit.

Refer to Note 8 for further information.

Other Intangibles

Excluding goodwill, our other intangible assets include customer contracts and other relationships and agreements.

Our intangible assets primarily relate to customer contracts or other relationships for the handling and storage of petroleum, chemical, and dry-bulk materials, including oil, gasoline, and other refined petroleum products, petroleum coke, metals and
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ores, the gathering of natural gas and the production and supply of RNG. We determined the values of these intangible assets by first, estimating the revenues derived from a customer contract or relationship (offset by the cost and expenses of supporting assets to fulfill the contract), and second, discounting the revenues at a risk adjusted discount rate.

We amortize the costs of our intangible assets to expense in a systematic and rational manner over their estimated useful lives. The life of each intangible asset is based either on the life of the corresponding customer contract or agreement or, in the case of a customer relationship intangible (the life of which was determined by an analysis of all available data on that business relationship), the length of time used in the discounted cash flow analysis to determine the value of the customer relationship. Among the factors we weigh, depending on the nature of the asset, are the effects of obsolescence, new technology, and competition.

The following tables summarize our other intangible assets as of December 31, 2023 and 2022 and our amortization expense for the years ended December 31, 2023, 2022 and 2021: 
Weighted Average Amortization PeriodDecember 31,
20232022
(Years)(In millions)
Gross11.3$3,543 $3,382 
Accumulated amortization(1,586)(1,573)
Net carrying amount$1,957 $1,809 
December 31,
202320222021
(In millions)
Amortization expense$202 $253 $237 

Our estimated amortization expense for our intangible assets for each of the next five fiscal years is:
20242025202620272028
(In millions)
Estimated amortization expenses$198 $193 $191 $191 $190 

Revenue Recognition

The majority of our revenues are accounted for under Topic 606, Revenue from Contracts with Customers; however, to a limited extent, some revenues are accounted for under other guidance such as Topic 842, Leases or Topic 815, Derivatives and Hedging Activities.

Revenue from Contracts with Customers

We review our contracts with customers using the following steps to recognize revenue based on the transfer of goods or services to customers and in amounts that reflect the consideration the company expects to receive for those goods or services. The steps include: (i) identify the contract; (ii) identify the performance obligations of the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and then (v) recognize revenue when (or as) the performance obligation is satisfied. Each of these steps involves management judgment and an analysis of the contract’s material terms and conditions.

Our customer sales contracts primarily include sales of natural gas, NGL, crude oil, CO2 and transmix, as described below. Generally, for the majority of these contracts (i) each unit (Bcf, gallon, barrel, etc.) of commodity is a separate performance obligation, as our promise is to sell multiple distinct units of commodity at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on our right to invoice at month end for the value of commodity sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity’s standalone selling price and recognized as revenue upon delivery of the commodity, which is the point in time when the customer obtains control of the commodity and our performance obligation is satisfied.

Our customer services contracts are primarily for transportation service, storage service, gathering and processing service, and terminaling, as described below. Generally, for the majority of these contracts (i) our promise is to transfer (or stand ready
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to transfer) a series of distinct integrated services over a period of time, which is a single performance obligation; (ii) the transaction price includes fixed and/or variable consideration, which amount is determinable at contract inception and/or at each month end based on our right to invoice at month end for the value of services provided to the customer that month; and (iii) the transaction price is recognized as revenue over the service period specified in the contract (which can be a day, including each day in a series of promised daily services, a month, a year, or other time increment, including a deficiency makeup period) as the services are rendered using a time-based (passage of time) or units-based (units of service transferred) output method for measuring the transfer of control of the services and satisfaction of our performance obligation over the service period, based on the nature of the promised service (e.g., firm or non-firm) and the terms and conditions of the contract (e.g., contracts with or without makeup rights).

Firm Services

Firm services (also called uninterruptible services) are services that are promised to be available to the customer at all times during the period(s) covered by the contract, with limited exceptions. Our firm service contracts are typically structured with take-or-pay or minimum volume provisions, which specify minimum service quantities a customer will pay for even if it chooses not to receive or use them in the specified service period (referred to as “deficiency quantities”). We typically recognize the portion of the transaction price associated with such provisions, including any deficiency quantities, as revenue depending on whether the contract prohibits the customer from making up deficiency quantities in subsequent periods, or the contract permits this practice, as follows:

•Contracts without Makeup Rights. If contractually the customer cannot make up deficiency quantities in future periods, our performance obligation is satisfied, and revenue associated with any deficiency quantities is generally recognized as each service period expires. Because a service period may exceed a reporting period, we determine at inception of the contract and at the beginning of each subsequent reporting period if we expect the customer to take the minimum volume associated with the service period. If we expect the customer to make up all deficiencies in the specified service period (i.e., we expect the customer to take the minimum service quantities), the minimum volume provision is deemed not substantive and we will recognize the transaction price as revenue in the specified service period as the promised units of service are transferred to the customer. Alternatively, if we expect that there will be any deficiency quantities that the customer cannot or will not make up in the specified service period (referred to as “breakage”), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over such service period in proportion to the revenue that we will recognize for actual units of service transferred to the customer in the service period. For certain take-or-pay contracts where we make the service, or a part of the service (e.g., reservation) continuously available over the service period, we typically recognize the take-or-pay amount as revenue ratably over such period based on the passage of time.

•Contracts with Makeup Rights. If contractually the customer can acquire the promised service in a future period and make up the deficiency quantities in such future period (the “deficiency makeup period”), we have a performance obligation to deliver those services at the customer’s request (subject to contractual and/or capacity constraints) in the deficiency makeup period. At inception of the contract, and at the beginning of each subsequent reporting period, we estimate if we expect that there will be deficiency quantities that the customer will or will not make up. If we expect the customer will make up all deficiencies it is contractually entitled to, any non-refundable consideration received relating to temporary deficiencies that will be made up in the deficiency makeup period will be deferred as a contract liability, and we will recognize that amount as revenue in the deficiency makeup period when either of the following occurs: (i) the customer makes up the volumes or (ii) the likelihood that the customer will exercise its right for deficiency volumes then becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires). Alternatively, if we expect at inception of the contract, or at the beginning of any subsequent reporting period, that there will be any deficiency quantities that the customer cannot or will not make up (i.e., breakage), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over the specified service periods in proportion to the revenue that we will recognize for actual units of service transferred to the customer in those service periods.

Non-Firm Services

Non-firm services (also called interruptible services) are the opposite of firm services in that such services are provided to a customer on an “as available” basis. Generally, we do not have an obligation to perform these services until we accept a customer’s periodic request for service. For the majority of our non-firm service contracts, the customer will pay only for the actual quantities of services it chooses to receive or use, and we typically recognize the transaction price as revenue as those units of service are transferred to the customer in the specified service period (typically a daily or monthly period).

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Contract Balances

Contract assets and contract liabilities are the result of timing differences between revenue recognition, billings and cash collections. We recognize contract assets in those instances where billing occurs subsequent to revenue recognition, and our right to invoice the customer is conditioned on something other than the passage of time. Our contract assets are substantially related to breakage revenue associated with our firm service contracts with minimum volume commitment payment obligations and contracts where we apply revenue levelization (i.e., contracts with fixed rates per volume that increase over the life of the contract for which we record revenue ratably per unit over the life of the contract based on our performance obligations that are generally unchanged over the life of the contract). Our contract liabilities are substantially related to (i) capital improvements paid for in advance by certain customers generally in our non-regulated businesses, which we subsequently recognize as revenue on a straight-line basis over the initial term of the related customer contracts; (ii) consideration received from customers for temporary deficiency quantities under minimum volume contracts that we expect will be made up in a future period, which we subsequently recognize as revenue when the customer makes up the volumes or the likelihood that the customer will exercise its right for deficiency volumes becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires); and (iii) contracts with fixed rates per volume that decrease over the life of the contract where we apply revenue levelization for amounts received for our future performance obligations. We reassess amounts recorded as contract assets or liabilities upon contract modification.

Refer to Note 15 for further information.

Costs of Sales

Costs of sales primarily includes the cost to purchase energy commodities sold, including natural gas, crude oil, NGL and other refined petroleum products, adjusted for the effects of our energy commodity hedging activities, as applicable. Costs of our crude oil, gas and CO2 producing activities, such as those in our CO2 business segment, are not accounted for as costs of sales.

Operations and Maintenance

Operations and maintenance includes costs of services and is primarily comprised of (i) operational labor costs and (ii) operations, maintenance and asset integrity, regulatory and environmental costs. Costs associated with our crude oil, gas and CO2 producing activities included within operations and maintenance totaled $393 million, $367 million and $180 million for the years ended December 31, 2023, 2022 and 2021, respectively.

Environmental Matters

We capitalize certain environmental expenditures required to obtain rights-of-way, regulatory approvals or permitting as part of the construction of facilities we use in our business operations. We accrue and expense environmental costs that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We generally do not discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs, such as after the completion of a feasibility study or commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We record at estimated fair value, where appropriate, environmental liabilities assumed in a business combination.

We routinely conduct reviews of potential environmental issues and claims that assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. We also routinely adjust our environmental liabilities to reflect changes in previous estimates. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us, and potential third-party liability claims we may have against others. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs.

Leases

We lease property including corporate and field offices and facilities, vehicles, heavy work equipment including rail cars and large trucks, tanks, office equipment and land. Our leases have remaining lease terms of one to 47 years, some of which have options to extend or terminate the lease. We determine if an arrangement is a lease at inception or upon modification. For purposes of calculating operating lease liabilities, lease terms may be deemed to include options to extend or terminate the lease when it is reasonably certain that we will exercise that option.
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Our operating ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Leases with variable rate adjustments, such as Consumer Price Index (CPI) adjustments, are reflected based on contractual lease payments as outlined within the lease agreement and not adjusted for any CPI increases or decreases. Because most of our leases do not provide an explicit rate of return, we use our incremental secured borrowing rate based on lease term information available at the commencement date of the lease in determining the present value of lease payments. We have real estate lease agreements with lease and non-lease components, which are accounted for separately. For certain equipment leases, such as copiers and vehicles, we account for the leases under a portfolio method. Leases that were grandfathered under various portions of Topic 842, such as land easements, are reassessed when the agreements are modified.

Refer to Note 17 for further information.

Share-based Compensation
We recognize compensation expense ratably over the vesting period of the restricted stock award based on the grant-date fair value, which is determined based on the market price of our Class P common stock on the grant date, less estimated forfeitures. Forfeiture rates are estimated based on actual fluctuationshistorical forfeitures under our restricted stock award plans. Upon vesting, the restricted stock award will be paid in energy commodity prices or interest ratesshares of our Class P common stock.
Pensions and Other Postretirement Benefits

We recognize the differences between the fair value of each of our and our consolidated subsidiaries’ pension and other postretirement benefit plans’ assets and the timingbenefit obligations as either assets or liabilities on our consolidated balance sheets. We record deferred plan costs and income—unrecognized losses and gains, unrecognized prior service costs and credits, and any remaining unamortized transition obligations—net of transactions.income taxes in “Accumulated other comprehensive loss,” with the proportionate share associated with less than wholly owned consolidated subsidiaries allocated and included within “Noncontrolling interests,” or as a regulatory asset or liability for certain of our regulated operations, until they are amortized as a component of benefit expense.

Deferred Financing Costs

We capitalize financing costs incurred with new borrowings and amortize the costs over the contractual term of the related obligations.

Redeemable Noncontrolling Interest

Through December 14, 2021, we had a redeemable noncontrolling interest which represented the interest in one of our consolidated subsidiaries, not owned by us, and which in certain limited circumstances, the partner had the right to relinquish its interest in the subsidiary. Distributions paid to the partner prior to that date were recorded as a reduction to the redeemable noncontrolling interest balance and included in “Distributions to investment partner” in our accompanying consolidated statement of cash flows. On December 14, 2021, the ownership agreement was modified such that the noncontrolling interest was no longer contingently redeemable, and the balance was reclassified to “Noncontrolling Interests.” Net income attributable to redeemable noncontrolling interest was $58 million for the year ended December 31, 2021 and is included in “Net Income Attributable to Noncontrolling Interests” in our accompanying consolidated statement of income.

Energy Commodity Market Risk

We are exposed to energy commodity market risk and other external risks in the ordinary course of business.  However, we manage these risks by executing a hedging strategy that seeks to protect us financially against adverse price movements and serves to minimize potential losses.  Our strategy involves the use ofenter into certain energy commodity derivative contracts in order to reduce and minimize the risks encountered in the ordinary course of business associated with unfavorable changes in the market price of crude oil, natural gas NGL and crude oil.NGL. The derivative contracts that we use include energy products traded on the NYMEXexchange-traded and OTC markets,commodity financial instruments, including, but not limited to, futures and options contracts, fixed price swaps and basis swaps. We may categorize such use of energy commodity derivative contracts as cash flow hedges because the derivative contract is used to hedge the anticipated future cash flow of a transaction that is expected to occur but whose value is uncertain.


Our hedging strategy involves entering into a financial position intended to offset our physical position, or anticipated position, in order to minimize the risk of financial loss from an adverse price change. For example, as sellers of crude oil, and natural gas and NGL, we often enter into fixed price swaps and/or futures contracts to guarantee or lock-in the sale price of our crude oil or the margin from the sale and purchase of our natural gas at the time of market delivery, thereby in whole or in part offsetting any change in prices, either positive or negative. Using derivative contracts for this purpose helps provide increased certainty with regard to operating cash flows which helps us to undertake further capital improvement projects, attain budget results and meet dividend targets.

Our policies require that derivative contracts are only entered into with carefully selected major financial institutions or similar counterparties based upon their credit ratings and other factors, and we maintain strict dollar and term limits that correspond to our counterparties’ credit ratings. While it is our policy to enter into derivative transactions principally with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that losses will result from counterparty credit risk in the future.
The credit ratings of the primary parties from whom we transact in energy commodity derivative contracts (based on contract market values) are as follows (credit ratings per Standard & Poor’s Rating Service): 
Credit Rating
Societe GeneraleA
MacquarieBBB
Wells FargoA
Canadian Imperial BankA+
NexteraA-

As discussed above, the principal use of energy commodity derivative contracts is to mitigate the market price risk associated with anticipated transactions for the purchase and sale of natural gas, NGL and crude oil.  Using derivative contracts for this purpose helps provide increased certainty with regard to operating cash flows which helps us to undertake further capital improvement projects, attain budget results and meet dividend targets.  We may categorize such use of energy commodity derivative contracts as cash flow hedges because the derivative contract is used to hedge the anticipated future cash flow of a transaction that is expected to occur but which value is uncertain.  


We measure the risk of price changes in the natural gas, NGL and crude oil derivative instrumentsinstrument portfolios utilizing a sensitivity analysis model. The sensitivity analysis applied to each portfolio measures the potential income or loss (i.e., the change in fair value of the derivative instrument portfolio) based upon a hypothetical 10% movement in the underlying quoted market prices. In addition to these variables, the fair value of each portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. A hypothetical 10% movement in the underlying commodity prices would have the following effect on the associated derivative contracts’ estimated fair value (in millions):
  As of December 31,
Commodity derivative 2017 2016
Crude oil $125
 $117
Natural gas 15
 16
NGL 10
 11
Total $150
 $144


As discussed above,Because we enter into derivative contracts largely for the purpose of mitigating the risks that accompany certain of our business activities, and, therefore both in the sensitivity analysis model and in reality, the change in the market value of the derivative contracts’ portfolio is offset largely by changes in the value of the underlying physical transactions. A hypothetical 10% movement in the underlying commodity prices would have the following effect on the associated derivative contracts’ estimated fair value:

As of December 31,
Commodity derivative20232022
(In millions)
Crude oil$127 $157 
Natural gas28 49 
NGL4 5 
Total$159 $211 

Our sensitivity analysis represents an estimate of the reasonably possible gains and losses that would be recognized on the crude oil, natural gas NGL and crude oilNGL portfolios of derivative contracts assuming hypothetical movements in future market rates and is
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not necessarily indicative of actual results that may occur. It does not represent the maximum possible loss or any expected loss that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ from estimates due to actual fluctuations in market rates, operating exposures and the timing thereof, as well as changes in our portfolio of derivatives during the year.


Interest Rate Risk

In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt. Fixed-to-variable interest rate swap agreements are entered into for the purpose of converting a portion of the underlying cash flows related to long-term fixed rate debt securities into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. Variable-to-fixed interest rate swap agreements are entered into primarily for the purpose of managing our exposure to changes in interest rates on our debt balances that are subject to variable interest rates and adjusting, on a short-term basis, our mix of fixed rate debt and variable rate debt based on changes in market conditions. The market risk inherent in our debt instruments and positions is the potential change arising from increases or decreases in interest rates as discussed below.

For fixed rate debt, changes in interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows. Generally, there is not an obligation to prepay fixed rate debt prior to maturity and, as a result, changes in fair value should not have a significant impact on the fixed rate debt. We are generally subject to interest rate risk upon refinancing maturing debt. Below are our debt balances, including debt fair value adjustments, and the preferred interest in KMGP, and sensitivity to interest rates:
 December 31, 2023December 31, 2022
 Carrying
value		Estimated
fair value(a)		Carrying
value		Estimated
fair value(a)
(In millions)
Fixed rate debt(b)$30,063 $29,317 $31,474 $29,756 
Variable rate debt$2,053 $2,053 $314 $314 
Notional principal amount of variable-to-fixed interest rate swap agreements(c)— (1,500)
Notional principal amount of fixed-to-variable interest rate swap agreements6,200 7,500 
Debt balances subject to variable interest rates(d)$8,253 $6,314 
(a)Fair values were determined using Level 2 inputs.
(b)A hypothetical 10% change in the average interest rates (in millions):applicable to such debt as of December 31, 2023 and 2022, would result in changes of approximately $1,889 million and $1,882 million, respectively, in the estimated fair values of these instruments.
(c)December 31, 2022 amount includes $1.25 billion that expired in December 2023.
 December 31, 2017 December 31, 2016
 Carrying
value		 Estimated
fair value(c)		 Carrying
value		 Estimated
fair value(c)
Fixed rate debt(a)$37,041
 $39,255
 $38,861
 $39,854
        
Variable rate debt$802
 $795
 $1,189
 $1,161
Notional principal amount of fixed-to-variable interest rate swap agreements9,575
   9,775
  
Debt balances subject to variable interest rates(b)$10,377
   $10,964
  
_______
(a)A hypothetical 10% change in the average interest rates applicable to such debt as of December 31, 2017 and 2016, would result in changes of approximately $1,525 million and $1,527 million, respectively, in the fair values of these instruments.
(b)A hypothetical 10% change in the weighted average interest rate on all of our borrowings (approximately 50 basis points in both 2017 and 2016)(d)A hypothetical 10% change in the weighted average interest rate on all of our borrowings (approximately 58 and 48 basis points in 2023 and 2022, respectively) when applied to our outstanding balance of variable rate debt as of December 31, 2017 and 2016, including adjustments for the notional swap amounts described above, would result in changes of approximately $52 million and $54 million, respectively, in our 2017 and 2016 annual pre-tax earnings.
(c)Fair values were determined using quoted market prices, where applicable, or future cash flows discounted at market rates for similar types of borrowing arrangements.

Fixed-to-variable interest rate swap agreements are entered into for the purpose of converting a portion of the underlying cash flows related to long-term fixed rate debt securities into variable rate debt in order to achieve our desired mixas of fixedDecember 31, 2023 and variable rate debt.  Since2022, including adjustments for the fair value of fixed rate debt varies with changesnotional swap amounts described in the market rate of interest, swap agreements are entered into to receive a fixed and pay a variable rate of interest.  Such swap agreementstable above, would result in future cash flows that vary with the market ratechanges of interest,approximately $48 million and therefore hedge against changes$30 million, respectively.

As presented in the fair value of the fixed rate debt due to market rate changes.

 Wetable above, we monitor the mix of fixed rate and variable rate debt obligations in light of changing market conditions and from time to time, may alter that mix by, for example, refinancing outstanding balances of variable rate debt with fixed rate debt (or vice versa) or by entering into interest rate swap agreements or other interest rate hedging agreements. As of December 31, 2017,2023, including debt converted to variable rates through the use of interest rate swaps but excluding our debt fair value adjustments, approximately 28%26% of our debt balances were subject to variable interest rates.



For more information on our interest rate risk management and on our interest rate swap agreements, see Note 14 “Risk Management” to our consolidated financial statements.


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Foreign Currency Risk


As of December 31, 2017,2023, we had a notional principal amount of $1,358$543 million of cross-currency swap agreements that effectively convert all of our fixed ratefixed-rate Euro denominated debt, including annual interest payments and the payment of principal at maturity, to U.S. dollar denominated debt at fixed rates. These swaps eliminate the foreign currency risk associated with our foreign currency denominated debt.


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Item 8.  Financial Statements and Supplementary Data.

The information required in this Item 8 is in this report as set forth in the “Index to Financial Statements” on page 76.



Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.KINDER MORGAN, INC. AND SUBSIDIARIES
None.

Item 9A. Controls and Procedures.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
As of December 31, 2017, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934.  There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures.  Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.  Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f).  Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.  Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an assessment of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on this assessment, our management concluded that our internal control over financial reporting was effective as of December 31, 2017.
The effectiveness of our internal control over financial reporting as of December 31, 2017, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their audit report, which appears herein.

Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting during the fourth quarter of 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.  Other Information.
None.


PART III
Item 10.  Directors, Executive Officers and Corporate Governance.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2018 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2018.

Item 11. Executive Compensation.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2018 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2018.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2018 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2018.

Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2018 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2018.  

Item 14.  Principal Accounting Fees and Services.

The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2018 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2018.

PART IV
Item 15.  Exhibits, Financial Statement Schedules.
(a)(1) Financial Statements and (2) Financial Statement Schedules
INDEX TO FINANCIAL STATEMENTS
Page
Number
See “Index to Financial Statements” set forth on Page76Report of Independent Registered Public Accounting Firm.

(PCAOB ID: 238)
(3)Exhibits
   Exhibit
NumberDescription71
3.1
*
3.2
*
Amended and Restated Bylaws of KMI (filed as Exhibit 3.1 to KMI’s Current Report on Form 8-K, filed October 20, 2017 (File No. 001-35081))
3.3
*
Certificate of Designations of KMI 9.75% Series A Mandatory Convertible Preferred Stock, par value $0.01 per share (KMI Preferred Stock) (filed as Exhibit 3.1 to KMI’s Current Report on Form 8-K filed October 30, 2015 (File No. 001-35081))
4.1
*
Form of certificate representing Class P common shares of KMI (filed as Exhibit 4.1 to KMI’s Registration Statement on Form S-1 filed on January 18, 2011 (File No. 333-170773))
4.2
*
Shareholders Agreement among KMI and certain holders of common stock (filed as Exhibit 4.2 to KMI’s Quarterly Report on Form 10-Q for the three Months ended March 31, 2011 (File No. 001-35081))
4.3
*
Amendment No. 1 to the Shareholders Agreement among KMI and certain holders of common stock (filed as Exhibit 4.3 to KMI’s Current Report on Form 8-K filed on May 30, 2012 (File No. 001-35081))
4.4
*
Amendment No. 2 to the Shareholders Agreement among KMI and certain holders of common stock (filed as Exhibit 4.1 to KMI’s Current Report on Form 8-K filed on December 3, 2014 (File No. 001-35081))
4.5
*
Form of certificate for KMI Preferred Stock (included as Exhibit A to Exhibit 3.1 to KMI’s Current Report on Form 8-K filed October 30, 2015 (File No. 001-35081))

   Exhibit
NumberDescription
4.6
*
Deposit Agreement, dated as of October 30, 2015, between KMI and Computershare Inc. and Computershare Trust Company, N.A., as joint depositary, on behalf of all holders from time to time of the depositary receipts issued thereunder (filed as Exhibit 4.2 to KMI’s Current Report on Form 8-K filed October 30, 2015 (File No. 001-35081))
4.7
*
Form of Depositary Receipt for depositary shares, each representing 1/20th of a share of KMI Preferred Stock (included as Exhibit A to Exhibit 4.2 to KMI’s Current Report on Form 8-K filed October 30, 2015 (File No. 001-35081))
4.8
*
Form of Senior Indenture between Kinder Morgan Kansas, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Kinder Morgan Kansas, Inc.’s Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102963))
4.9
*
Form of Senior Note of Kinder Morgan Kansas, Inc. (included in the Form of Senior Indenture filed as Exhibit 4.2 to Kinder Morgan Kansas, Inc.’s Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102963))
4.10
*
Indenture dated as of December 9, 2005, among Kinder Morgan Finance Company LLC (formerly Kinder Morgan Finance Company, ULC), Kinder Morgan Kansas, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 15, 2005 (File No. 1-06446))
4.11
*
Forms of Kinder Morgan Finance Company LLC Notes (included in the Indenture filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 15, 2005 (File No. 1-06446))
4.12
*
Indenture dated January 2, 2001 between Kinder Morgan Energy Partners, L.P. and First Union National Bank, as trustee, relating to Senior Debt Securities (including form of Senior Debt Securities) (filed as Exhibit 4.11 to Kinder Morgan Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2000 (File No. 1-11234))
4.13
*
Certificate of the Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 7.40% Notes due March 15, 2031 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Current Report on Form 8-K filed on March 14, 2001 (File No. 1-11234))
4.14
*
Specimen of 7.40% Notes due March 15, 2031 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P.’s Current Report on Form 8-K filed on March 14, 2001(File No. 1-11234))
4.15
*
Certificate of the Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 7.750% Notes due March 15, 2032 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002 (File No. 1-11234))
4.16
*
Specimen of 7.750% Notes due March 15, 2032 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002 (File No. 1-11234))
4.17
*
Indenture dated August 19, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346))
4.18
*
First Supplemental Indenture to Indenture dated August 19, 2002, dated August 23, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346))
4.19
*
Form of 7.30% Notes due 2033 (contained in the Indenture filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346))
4.20
*
Senior Indenture dated January 31, 2003 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102961))
4.21
*
Form of Senior Note of Kinder Morgan Energy Partners, L.P. (included in the Form of Senior Indenture filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102961))

   Exhibit
NumberDescription
4.22
*
Certificate of the Vice President, Treasurer and Chief Financial Officer and the Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 5.80% Notes due March 15, 2035 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 (File No. 1-11234))
4.23
*
Certificate of the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 6.00% Senior Notes due 2017 and 6.50% Senior Notes due 2037 (filed as Exhibit 4.28 to Kinder Morgan Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2006 (File No. 1-11234))
4.24
*
Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 6.95% Senior Notes due 2038 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 1-11234))
4.25
*
Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.95% Senior Notes due 2018 (filed as Exhibit 4.28 to Kinder Morgan Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 1-11234))
4.26
*
Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 9.00% Senior Notes due 2019 (filed as Exhibit 4.29 to Kinder Morgan Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2008 (File No. 1-11234))
4.27
*
Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 6.85% Senior Notes due 2020 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009 (File No. 1-11234))
4.28
*
Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.80% Senior Notes due 2021, and the 6.50% Senior Notes due 2039 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009 (File No. 1-11234))
4.29
*
Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.30% Senior Notes due 2020, and the 6.55% Senior Notes due 2040 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 (File No. 1-11234))
4.30
*
Indenture, dated December 20, 2010, among Kinder Morgan Finance Company LLC, Kinder Morgan Kansas, Inc. and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 23, 2010 (File No. 1-06446))
4.31
*
Certificate of the Vice President and Treasurer and the Vice President and Secretary of Kinder Morgan Finance Company, LLC establishing the terms of the 6.000% Senior Notes due 2018 of Kinder Morgan Finance Company LLC (with the form of note attached thereto) (filed as Exhibit 4.2 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 23, 2010 (File No. 1-06446))
4.32
*
Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 6.375% Senior Notes due 2041 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 1-11234))
4.33
*
Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 4.150% Senior Notes due 2022, and the 5.625% Senior Notes due 2041 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011 (File No. 1-11234))
4.34
*
Certificate of the Vice President, Finance and Investor Relations and the Vice President and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 3.500% Senior Notes due 2021 and the 5.500% Senior Notes due 2044 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014 (File No. 1-11234))

   Exhibit
NumberDescription
4.35
*
Certificate of the Vice President and Treasurer and the Vice President and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 4.250% Senior Notes due 2024 and the 5.400% Senior Notes due 2044 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014 (File No. 1-11234))
4.36
*
Indenture, dated March 1, 2012, between KMI and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to KMI’s Registration Statement on Form S-3 filed on March 1, 2012 (File No. 001-35081))
4.37
*
Certificate of the Vice President and Treasurer and the Vice President and Secretary of KMI establishing the terms of the 2.000% Senior Notes due 2017, the 3.050% Senior Notes due 2019, the 4.300% Senior Notes due 2025, the 5.300% Senior Notes due 2034 and the 5.550% Senior Notes due 2045 (filed as Exhibit 10.53 to KMI’s Annual Report on Form 10-K for the year ended December 31, 2014 (File No. 001-35081))
4.38
*
Certificate of the Vice President and Treasurer and Vice President and Secretary of KMI establishing the terms of the 5.050% Senior Notes due 2046 (filed as Exhibit 4.1 to KMI’s Quarterly Report on Form 10-Q for the three months ended March 31, 2015 (File No. 001-35081))
4.39
*
Certificate of the Vice President and Treasurer and Vice President and Secretary of KMI establishing the terms of the 1.500% Senior Notes due 2022 and 2.250% Senior Notes due 2027 (filed as Exhibit 4.2 to KMI’s Form 8-A, filed March 16, 2015 (File No. 001-35081))
4.40
*
Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of KMI establishing the terms of the 3.150% Senior Notes due January 15, 2023 (filed as Exhibit 4.1 to KMI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2017 (File No. 001-35081))
4.41
*
Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of KMI establishing the terms of the Floating Rate Senior Notes due January 15, 2023 (filed as Exhibit 4.2 to KMI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2017 (File No. 001-35081))
4.42
Certain instruments with respect to long-term debt of KMI and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of KMI and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. sec. #229.601. KMI hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request.
10.1
*
KMI 2015 Amended and Restated Stock Incentive Plan (filed as Exhibit 4.5 to KMI’s Registration Statement on Form S-8, filed on July 1, 2015 (File No. 333-205430))
10.2
*
Amendment No. 1 to KMI 2015 Amended and Restated Stock Incentive Plan (filed as Exhibit 10.2 to KMI’s Current Report on Form 8-K filed on January 24, 2017 (File No. 001-35081))
10.3
*
2015 Form of Employee Restricted Stock Unit Agreement (filed as Exhibit 4.6 to KMI’s Registration Statement on Form S-8, filed on July 1, 2015 (File No. 333-205430))
10.4
*
2016 Form of Employee Restricted Stock Unit Agreement (filed as Exhibit 10.2 to KMI’s Quarterly Report on Form 10-Q for the three months ended June 30, 2016 (File No. 001-35081))
10.5
*
Amended and Restated Stock Compensation Plan for Non-Employee Directors (filed as Exhibit 10.5 to KMI’s Quarterly Report on Form 10-Q for the three months ended June 30, 2015 (File No. 001-35081))
10.6
*
2015 Form of Non-Employee Director Stock Compensation Agreement (filed as Exhibit 10.6 to KMI’s Quarterly Report on Form 10-Q for the three months ended June 30, 2015 (File No. 001-35081))
10.7
*
2011 Form of Non-Employee Director Stock Compensation Agreement (filed as Exhibit 10.3 to KMI’s Quarterly Report on Form 10-Q for the three months ended March 31, 2011 (File No. 001-35081))
10.8
*
KMI Employees Stock Purchase Plan (filed as Exhibit 10.5 to KMI’s Quarterly Report on Form 10-Q for the three months ended March 31, 2011 (File No. 001-35081))
10.9
*
Amended and Restated Annual Incentive Plan of KMI (filed as Exhibit 10.4 to KMI’s Quarterly Report on Form 10-Q for the three months ended June 30, 2015 (File No. 001-35081))
10.10
*
Amendment No. 1 to Amended and Restated Incentive Plan of KMI (filed as Exhibit 10.1 to KMI’s Current Report on Form 8-K filed January 24, 2017 (File No. 001-35081))
10.11
*
Revolving Credit Agreement, dated September 19, 2014 among KMI, as borrower, Barclays Bank PLC, as administrative agent, and the lenders and issuing banks party thereto (filed as Exhibit 10.2 to KMI’s Current Report on Form 8-K filed September 25, 2014(File No. 001-35081))

   Exhibit
NumberDescription
10.12
*
Term Loan Agreement, dated as of January 26, 2016 among KMI, as borrower, the lenders party thereto and Barclays Bank PLC, as administrative agent (filed as exhibit 10.2 to KMI’s Quarterly Report on Form 10-Q for the three months ended March 31, 2016 (File No. 001-35081))
10.13
*
Joinder Agreement, dated as of January 26, 2016, to KMI’s Revolving Credit Agreement, dated as of September 19, 2014 among KMI, the lenders party thereto and Barclay Bank PLC, as administrative agent. (filed as exhibit 10.3 to KMI’s Quarterly Report on Form 10-Q for the three months ended March 31, 2016 (File No. 001-35081))
10.14
*
Credit Agreement, dated June 16, 2017, among Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC and the lenders party thereto (filed as Exhibit 10.1 to KMI’s Current Report on Form 8-K/A filed August 25, 2017 (File No. 001-35081)) (portions of the exhibit have been omitted pursuant to 17 CFR 240.24b-2 and filed separately with the Securities and Exchange Commission pursuant to a Confidential Treatment Application)
10.15
*
First Amending Agreement to the Credit Agreement, dated January 23, 2018, by and among Kinder Morgan Cochin ULC, Trans Mountain Pipeline ULC and the lenders party thereto (filed as Exhibit 10.1 to KML’s Current Report on Form 8-K/A filed on January 23, 2018 (File No. 000-55864))
10.16
Cross Guarantee Agreement, dated as of November 26, 2014 among KMI and certain of its subsidiaries with schedules updated as of December 31, 2017
12.1
Statement re: computation of ratio of earnings to fixed charges
21.1
Subsidiaries of KMI
23.1
Consent of PricewaterhouseCoopers LLP
31.1
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101
Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Statements of Income for the years ended December 31, 2017, 2016,2023, 2022 and 2015; (ii) our 2021
74
75
76
77
_______
*Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith, except as noted otherwise.



KINDER MORGAN, INC. AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS

79
Page
Number
77
Consolidated Statements of Income for the years ended December 31, 2017, 2016 and 2015
79
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2017, 2016 and 2015
80
Consolidated Balance Sheets as of December 31, 2017 and 2016
81
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015
82
Consolidated Statement of Stockholders’ Equity as of and for the years ended December 31, 2017, 2016 and 2015
84
Notes to Consolidated Financial Statements
8580
Note 1.
80
Supplemental Selected Quarterly Financial Data (Unaudited)Note 2.
80
Note 3.
90
Note 4.
93
Note 5.
94
Note 6.
97
Note 7.
98
Note 8.
99
Note 9.
100
Note 10.
104
Note 11.
110
Note 12.
112
Note 13.
112
Note 14.
113
Note 15.
118
Note 16.
121
Note 17.
125
Note 18.
126
Note 19.
130

70



Report of Independent Registered Public Accounting Firm


To theBoard of Directors and Stockholders of Kinder Morgan, Inc.:


Opinions on the Financial Statements and Internal Control over Financial Reporting


We have audited the accompanying consolidatedbalance sheets of Kinder Morgan, Inc. and its subsidiaries (the “Company”)as of December 31, 20172023 and 2016, 2022,and the related consolidatedstatements of income, of comprehensive income, (loss),of stockholders’ equity and of cash flows and of stockholders’ equity for each of the three years in the period ended December 31, 2017,2023, including the related notes (collectively referred to as the “consolidatedfinancial statements”).We also have audited the Company's internal control over financial reporting as of December 31, 2017,2023, based on criteria established in Internal Control - Integrated Framework(2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).


In our opinion, the consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20172023 and2016, 2022, and the results of theiritsoperations andtheir itscash flows for each of the three years in the period ended December 31, 20172023 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2023, based on criteria established in Internal Control - Integrated Framework(2013)issued by the COSO.


Basis for Opinions


The Company's management is responsible for these consolidatedfinancial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management'sManagement’s Report on Internal Control overOver Financial Reporting appearing under Item 9A.Our responsibility is to express opinions on the Company’s consolidatedfinancial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB")(PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.


We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidatedfinancial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.


Our audits of the consolidatedfinancial statements included performing procedures to assess the risks of material misstatement of the consolidatedfinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidatedfinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidatedfinancial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.


As described in Management’s Report on Internal Control over Financial Reporting, management has excluded STX Midstream from its assessment of internal control over financial reporting as of December 31, 2023, because it was acquired by the Company in a purchase business combination during 2023. We have also excluded STX Midstream from our audit of internal control over financial reporting. STX Midstream’s total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting both represent less than 3% of the related consolidated financial statement amounts as of and for the year ended December 31, 2023.

Definition and Limitations of Internal Control over Financial Reporting


A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the
71

company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.



Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.



Critical Audit Matters


The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Goodwill Impairment Assessment – Natural Gas Pipelines Regulated, Natural Gas Pipelines Non-Regulated, CO2, Products Pipelines, Products Pipelines Terminals, and Terminals Reporting Units

As described in Notes 2 and 8 to the consolidated financial statements, the Company’s consolidated goodwill balance was $20.1 billion as of December 31, 2023, of which $20.0 billion relates to the Natural Gas Pipelines Regulated, Natural Gas Pipelines Non-Regulated, CO2, Products Pipelines, Products Pipelines Terminals, and Terminals reporting units (collectively, “the reporting units”). Management evaluates goodwill for impairment on May 31 of each year, or more frequently to the extent events occur or conditions change between annual tests that would indicate a risk of possible impairment at the interim period. Management estimated the fair value of the reporting units based on a market approach utilizing forecasted earnings before interest, income taxes, depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments (EBITDA), and the enterprise value to estimated EBITDA multiples of comparable companies for each reporting unit.

The principal considerations for our determination that performing procedures relating to the goodwill impairment assessment of the reporting units is a critical audit matter are (i) the significant judgment by management when developing the fair value estimate of the reporting units; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to forecasted EBITDA and the enterprise value to estimated EBITDA multiples of comparable companies for each of the reporting units; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s goodwill impairment assessment, including controls over developing the fair value estimate of the reporting units. These procedures also included, among others (i) testing management’s process for developing the fair value estimate of the reporting units; (ii) evaluating the appropriateness of the market approach used by management; (iii) testing the completeness and accuracy of underlying data used in the market approach; and (iv) evaluating the reasonableness of the significant assumptions used by management related to forecasted EBITDA and the enterprise value to estimated EBITDA multiples of comparable companies for each of the reporting units. Evaluating management’s assumptions related to forecasted EBITDA and the enterprise value to estimated EBITDA multiples of comparable companies for each of the reporting units involved evaluating whether the assumptions used by management were reasonable considering (i) the current and past performance of the reporting units; (ii) the consistency with external market and industry data; and (iii) whether these assumptions were consistent with evidence obtained in other areas of the audit. Professionals with specialized skill and knowledge were used to assist in evaluating (i) the appropriateness of the market approach and (ii) the reasonableness of the assumption related to the enterprise value to estimated EBITDA multiples of comparable companies for each of the reporting units.

Acquisition of STX Midstream – Valuation of Property, Plant and Equipment

As described in Note 3 to the consolidated financial statements, on December 28, 2023, the Company completed the acquisition of STX Midstream for a purchase price of $1.8 billion. This acquisition resulted in the recognition of $1.2 billion of property, plant and equipment (PP&E). For acquired businesses, the Company recognizes the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Management determined the fair value of PP&E utilizing a replacement cost approach. Determining the fair value of this item requires management judgment and the utilization of an independent valuation specialist and involves the use of significant estimates and assumptions. The significant assumption made in performing this valuation includes the replacement costs used to value PP&E.

72

The principal considerations for our determination that performing procedures relating to the valuation of PP&E acquired in the acquisition of STX Midstream is a critical audit matter are (i) the significant judgment by management when developing the fair value estimate of the PP&E acquired; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumption related to the replacement costs used to value the PP&E acquired; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the acquisition accounting, including controls over management’s valuation of the PP&E acquired. These procedures also included, among others (i) reading the purchase agreement; (ii) testing management’s process for developing the fair value estimate of the PP&E acquired; (iii) evaluating the appropriateness of the replacement cost approach used by management; (iv) testing the completeness and accuracy of underlying data used in the replacement cost approach; and (v) evaluating the reasonableness of the significant assumption used by management related to the replacement costs used to value the PP&E acquired. Professionals with specialized skill and knowledge were used to assist in evaluating (i) the appropriateness of the replacement cost approach and (ii) the reasonableness of the replacement costs assumption used to value the PP&E acquired.


/s/PricewaterhouseCoopers LLP


Houston, Texas
February 9, 201820, 2024



We have served as the Company’s auditor since 1997.



73
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In Millions, Except Per Share Amounts)
 Year Ended December 31,
 2017 2016 2015
Revenues     
Natural gas sales$3,053
 $2,454
 $2,839
Services7,901
 8,146
 8,290
Product sales and other2,751
 2,458
 3,274
Total Revenues13,705
 13,058
 14,403
      
Operating Costs, Expenses and Other   
  
Costs of sales4,345
 3,429
 4,059
Operations and maintenance2,472
 2,372
 2,393
Depreciation, depletion and amortization2,261
 2,209
 2,309
General and administrative673
 669
 690
Taxes, other than income taxes398
 421
 439
Loss on impairment of goodwill—
 —
 1,150
Loss on impairments and divestitures, net13
 387
 919
Other income, net(1) (1) (3)
Total Operating Costs, Expenses and Other10,161
 9,486
 11,956
      
Operating Income3,544
 3,572
 2,447
      
Other Income (Expense)   
  
Earnings from equity investments578
 497
 414
Loss on impairments and divestitures of equity investments, net(150) (610) (30)
Amortization of excess cost of equity investments(61) (59) (51)
Interest, net(1,832) (1,806) (2,051)
Other, net82
 44
 43
Total Other Expense(1,383) (1,934) (1,675)
      
Income Before Income Taxes2,161
 1,638
 772
      
Income Tax Expense(1,938) (917) (564)
      
Net Income223
 721
 208
      
Net (Income) Loss Attributable to Noncontrolling Interests(40) (13) 45
      
Net Income Attributable to Kinder Morgan, Inc.183
 708
 253
      
Preferred Stock Dividends(156) (156) (26)
      
Net Income Available to Common Stockholders$27
 $552
 $227
      
Class P Shares   
  
Basic Earnings Per Common Share$0.01
 $0.25
 $0.10
      
Basic Weighted Average Common Shares Outstanding2,230
 2,230
 2,187
      
Diluted Earnings Per Common Share$0.01
 $0.25
 $0.10
      
Diluted Weighted Average Common Shares Outstanding2,230
 2,230
 2,193
      
Dividends Per Common Share Declared for the Period$0.500
 $0.500
 $1.605



KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share amounts)
 Year Ended December 31,
 202320222021
Revenues 
Services$8,371 $8,145 $7,757 
Commodity sales6,786 10,897 8,714 
Other177 158 139 
Total Revenues15,334 19,200 16,610 
Operating Costs, Expenses and Other
Costs of sales (exclusive of items shown separately below)4,938 9,255 6,493 
Operations and maintenance2,807 2,655 2,368 
Depreciation, depletion and amortization2,250 2,186 2,135 
General and administrative668 637 655 
Taxes, other than income taxes421 441 426 
(Gain) loss on divestitures and impairments, net (Note 4)(15)(32)1,624 
Other expense (income), net2 (7)(7)
Total Operating Costs, Expenses and Other11,071 15,135 13,694 
Operating Income4,263 4,065 2,916 
Other Income (Expense)
Earnings from equity investments838 803 591 
Amortization of excess cost of equity investments(66)(75)(78)
Interest, net(1,797)(1,513)(1,492)
Other, net (Note 3)(37)55 282 
Total Other Expense(1,062)(730)(697)
Income Before Income Taxes3,201 3,335 2,219 
Income Tax Expense(715)(710)(369)
Net Income2,486 2,625 1,850 
Net Income Attributable to Noncontrolling Interests(95)(77)(66)
Net Income Attributable to Kinder Morgan, Inc.$2,391 $2,548 $1,784 
Class P Common Stock 
Basic and Diluted Earnings Per Share$1.06 $1.12 $0.78 
Basic and Diluted Weighted Average Shares Outstanding2,234 2,258 2,266 

The accompanying notes are an integral part of these consolidated financial statements.

74


KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In Millions)millions)
Year Ended December 31,
 202320222021
Net income$2,486 $2,625 $1,850 
Other comprehensive income (loss), net of tax 
Net unrealized gain (loss) from derivative instruments (net of taxes of $(47), $92, and $131, respectively)155 (312)(432)
Reclassification into earnings of net derivative instruments loss (gain) to net income (net of taxes of $12, $(95), and $(83), respectively)(35)320 273 
Benefit plan adjustments (net of taxes of $(20), $(1), and $(47), respectively)65 1 155 
Total other comprehensive income (loss)185 9 (4)
Comprehensive income2,671 2,634 1,846 
Comprehensive income attributable to noncontrolling interests(95)(77)(66)
Comprehensive income attributable to KMI$2,576 $2,557 $1,780 
 Year Ended December 31,
 2017 2016 2015
Net income$223
 $721
 $208
Other comprehensive income (loss), net of tax 
  
  
Change in fair value of hedge derivatives (net of tax (expense) benefit of $(82), $60 and $(94), respectively)145
 (104) 164
Reclassification of change in fair value of derivatives to net income (net of tax benefit of $97, $67 and $156, respectively)(171) (116) (272)
Foreign currency translation adjustments (net of tax (expense) benefit of $(56), $(20) and $123, respectively)101
 34
 (214)
Benefit plan adjustments (net of tax (expense) benefit of $(27), $19 and $69, respectively)40
 (14) (122)
Total other comprehensive income (loss)115
 (200) (444)
      
Comprehensive income (loss)338
 521
 (236)
Comprehensive (income) loss attributable to noncontrolling interests(86) (13) 45
Comprehensive income (loss) attributable to KMI$252
 $508
 $(191)



The accompanying notes are an integral part of these consolidated financial statements.

75
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Millions, Except Share and Per Share Amounts)
 December 31,
 2017 2016
ASSETS   
Current assets   
Cash and cash equivalents$264
 $684
Restricted deposits62
 103
Accounts receivable, net1,448
 1,370
Fair value of derivative contracts114
 198
Inventories424
 357
Income tax receivable165
 180
Other current assets238
 337
Total current assets2,715
 3,229
    
Property, plant and equipment, net40,155
 38,705
Investments7,298
 7,027
Goodwill22,162
 22,152
Other intangibles, net3,099
 3,318
Deferred income taxes2,044
 4,352
Deferred charges and other assets1,582
 1,522
Total Assets$79,055
 $80,305
    
LIABILITIES AND STOCKHOLDERS’ EQUITY 
  
Current liabilities 
  
Current portion of debt$2,828
 $2,696
Accounts payable1,340
 1,257
Accrued interest621
 625
Accrued contingencies291
 261
Other current liabilities1,101
 1,085
Total current liabilities6,181
 5,924
    
Long-term liabilities and deferred credits 
  
Long-term debt   
Outstanding33,988
 36,105
Preferred interest in general partner of KMP100
 100
Debt fair value adjustments927
 1,149
Total long-term debt35,015
 37,354
Other long-term liabilities and deferred credits2,735
 2,225
Total long-term liabilities and deferred credits37,750
 39,579
Total Liabilities43,931
 45,503
    
Commitments and contingencies (Notes 9, 13 and 17)

 

Stockholders’ Equity 
  
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,217,110,072 and 2,230,102,384 shares, respectively, issued and outstanding22
 22
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 9.75% Series A Mandatory Convertible, $1,000 per share liquidation preference, 1,600,000 shares issued and outstanding—
 —
Additional paid-in capital41,909
 41,739
Retained deficit(7,754) (6,669)
Accumulated other comprehensive loss(541) (661)
Total Kinder Morgan, Inc.’s stockholders’ equity33,636
 34,431
Noncontrolling interests1,488
 371
Total Stockholders’ Equity35,124
 34,802
Total Liabilities and Stockholders’ Equity$79,055
 $80,305


KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions, except share and per share amounts)
 December 31,
 20232022
ASSETS  
Current assets  
Cash and cash equivalents$83 $745 
Restricted deposits13 49 
Accounts receivable1,588 1,840 
Fair value of derivative contracts126 231 
Inventories525 634 
Other current assets207 304 
Total current assets2,542 3,803 
Property, plant and equipment, net37,297 35,599 
Investments7,874 7,653 
Goodwill20,121 19,965 
Other intangibles, net1,957 1,809 
Deferred charges and other assets1,229 1,249 
Total Assets$71,020 $70,078 
LIABILITIES AND STOCKHOLDERS’ EQUITY  
Current liabilities  
Current portion of debt$4,049 $3,385 
Accounts payable1,366 1,444 
Accrued interest513 515 
Accrued taxes272 264 
Fair value of derivative contracts205 465 
Other current liabilities816 857 
Total current liabilities7,221 6,930 
Long-term liabilities and deferred credits  
Long-term debt
Outstanding27,880 28,288 
Debt fair value adjustments187 115 
Total long-term debt28,067 28,403 
Deferred income taxes1,388 623 
Other long-term liabilities and deferred credits2,615 2,008 
Total long-term liabilities and deferred credits32,070 31,034 
Total Liabilities39,291 37,964 
Commitments and contingencies (Notes 9, 13, 17 and 18)
Stockholders’ Equity  
Class P Common Stock, $0.01 par value, 4,000,000,000 shares authorized, 2,219,729,644 and 2,247,681,626 shares, respectively, issued and outstanding22 22 
Additional paid-in capital41,190 41,673 
Accumulated deficit(10,689)(10,551)
Accumulated other comprehensive loss(217)(402)
Total Kinder Morgan, Inc.’s stockholders’ equity30,306 30,742 
Noncontrolling interests1,423 1,372 
Total Stockholders’ Equity31,729 32,114 
Total Liabilities and Stockholders’ Equity$71,020 $70,078 

The accompanying notes are an integral part of these consolidated financial statements.

76
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Millions)
 Year Ended December 31,
 2017 2016 2015
Cash Flows From Operating Activities     
Net income$223
 $721
 $208
Adjustments to reconcile net income to net cash provided by operating activities 
  
  
Depreciation, depletion and amortization2,261
 2,209
 2,309
Deferred income taxes2,073
 1,087
 692
Amortization of excess cost of equity investments61
 59
 51
Change in fair market value of derivative contracts40
 64

(166)
Loss (gain) on early extinguishment of debt4
 (45) —
Loss on impairment of goodwill (Note 4)—
 —
 1,150
Loss on impairments and divestitures, net (Note 4)13
 387
 919
Loss on impairments and divestitures of equity investments, net (Note 4)150
 610
 30
Earnings from equity investments(578) (497) (414)
Distributions of equity investment earnings426
 431
 391
Pension contributions and noncash pension benefit expenses (credits)8
 9
 (90)
Changes in components of working capital, net of the effects of acquisitions and dispositions 
  
  
Accounts receivable, net(78) (107) 382
Income tax receivable7
 (148) 195
Inventories(90) 49
 34
Other current assets(25) (81) 113
Accounts payable73
 144
 (154)
Accrued interest, net of interest rate swaps10
 (18) 37
Accrued contingencies and other current liabilities101
 79
 (121)
Rate reparations, refunds and other litigation reserve adjustments(100) (32) 18
Other, net22
 (126) (271)
Net Cash Provided by Operating Activities4,601
 4,795
 5,313
      
Cash Flows From Investing Activities 
  
  
Acquisitions of assets and investments, net of cash acquired(4) (333) (2,079)
Capital expenditures(3,188) (2,882) (3,896)
Proceeds from sale of equity interests in subsidiaries, net—
 1,401
 —
Sales of property, plant and equipment, investments, and other net assets, net of removal costs118
 330
 39
Contributions to investments(684) (408) (96)
Distributions from equity investments in excess of cumulative earnings374
 231
 228
Other, net22
 (44) 98
Net Cash Used in Investing Activities(3,362) (1,705) (5,706)
      
Cash Flows From Financing Activities     
Issuances of debt8,868
 8,629
 14,316
Payments of debt(11,064) (10,060) (15,116)
Debt issue costs(70) (19) (24)
Issuances of common shares (Note 11)—
 —
 3,870
Issuance of mandatory convertible preferred stock (Note 11)—
 —
 1,541
Cash dividends - common shares (Note 11)(1,120) (1,118) (4,224)
Cash dividends - preferred shares (Note 11)(156) (154) —
Repurchases of shares and warrants (Note 11)(250) —
 (12)
Contributions from investment partner485
 —
 —
Contributions from noncontrolling interests - net proceeds from KML IPO (Note 3)1,245
 —
 —
Contributions from noncontrolling interests - net proceeds from KML preferred share issuances (Note 11)420
 —
 —
Contributions from noncontrolling interests - other12
 117
 11
Distributions to noncontrolling interests(42) (24) (34)
Other, net(9) (8) (11)
Net Cash (Used in) Provided by Financing Activities(1,681) (2,637) 317
      
Effect of Exchange Rate Changes on Cash and Cash Equivalents22
 2
 (10)
      
Net (decrease) increase in Cash and Cash Equivalents(420) 455
 (86)
Cash and Cash Equivalents, beginning of period684
 229
 315
Cash and Cash Equivalents, end of period$264
 $684
 $229





KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
(In Millions)
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
 Year Ended December 31,
 202320222021
Cash Flows From Operating Activities   
Net income$2,486 $2,625 $1,850 
Adjustments to reconcile net income to net cash provided by operating activities   
Depreciation, depletion and amortization2,250 2,186 2,135 
Deferred income taxes710 692 355 
Amortization of excess cost of equity investments66 75 78 
Change in fair market value of derivative contracts(126)56 20 
(Gain) loss on divestitures and impairments, net (Note 4)(15)(32)1,624 
Gain on sale of interest in equity investment (Note 3)— — (206)
Earnings from equity investments(838)(803)(591)
Distributions of equity investment earnings755 725 720 
Pension contributions net of noncash pension benefit expenses77 (50)(39)
Changes in components of working capital, net of the effects of acquisitions and dispositions   
Accounts receivable301 (220)(265)
Inventories188 (183)(202)
Other current assets108 (51)(109)
Accounts payable(201)161 387 
Accrued interest, net of interest rate swaps(13)50 (17)
Other current liabilities(58)6 165 
Change in deferred revenues (Note 15)870 (24)(28)
Rate reparations, refunds and other litigation reserve adjustments(19)(190)(57)
Other, net(50)(56)(112)
Net Cash Provided by Operating Activities6,491 4,967 5,708 
Cash Flows From Investing Activities   
Acquisitions of assets and investments, net of cash acquired (Note 3)(1,842)(487)(1,547)
Capital expenditures(2,317)(1,621)(1,281)
Sales of property, plant and equipment, investments, and other net assets, net of removal costs(28)6 406 
Contributions to investments(212)(229)(38)
Distributions from equity investments in excess of cumulative earnings228 156 163 
Other, net(4)— (8)
Net Cash Used in Investing Activities(4,175)(2,175)(2,305)
Cash Flows From Financing Activities
Issuances of debt7,590 9,058 5,959 
Payments of debt(7,356)(9,735)(6,831)
Debt issue costs(20)(25)(27)
Dividends (Note 11)(2,529)(2,504)(2,443)
Repurchases of shares (Note 11)(522)(368)— 
Proceeds from sale of noncontrolling interests (Note 3)— 557 — 
Contributions from noncontrolling interests3 2 4 
Distributions to investment partner— — (82)
Distributions to noncontrolling interests(151)(116)(20)
Other, net(29)(14)(25)
Net Cash Used in Financing Activities(3,014)(3,145)(3,465)
Net Decrease in Cash, Cash Equivalents and Restricted Deposits(698)(353)(62)
Cash, Cash Equivalents and Restricted Deposits, beginning of period794 1,147 1,209 
Cash, Cash Equivalents and Restricted Deposits, end of period$96 $794 $1,147 
77

 Year Ended December 31,
 2017 2016 2015
Noncash Investing and Financing Activities 
  
  
Assets acquired by the assumption or incurrence of liabilities$—
 $43
 $1,681
Net assets contributed to equity investments—
 37
 46
Increase in property, plant and equipment from both accruals and contractor retainage14
    
      
Supplemental Disclosures of Cash Flow Information   
  
Cash paid during the period for interest (net of capitalized interest)1,854
 2,050
 1,985
Cash (refunded) paid during the period for income taxes, net(140) 4
 (331)
KINDER MORGAN, INC. AND SUBSIDIARIES (continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
 Year Ended December 31,
 202320222021
Cash and Cash Equivalents, beginning of period$745 $1,140 $1,184 
Restricted Deposits, beginning of period49 7 25 
Cash, Cash Equivalents and Restricted Deposits, beginning of period794 1,147 1,209 
Cash and Cash Equivalents, end of period83 745 1,140 
Restricted Deposits, end of period13 49 7 
Cash, Cash Equivalents and Restricted Deposits, end of period96 794 1,147 
Net Decrease in Cash, Cash Equivalents and Restricted Deposits$(698)$(353)$(62)
Noncash Investing and Financing Activities
Assets contributed to equity investment$16 $— $— 
Net increase in property, plant and equipment from both accruals and contractor retainage120 72 74 
ROU assets and operating lease obligations recognized (Note 17)56 22 59 
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)1,844 1,460 1,529 
Cash paid during the period for income taxes, net11 13 10 


The accompanying notes are an integral part of these consolidated financial statements.

78

KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In Millions)
millions)
Common stock
Common stock
Common stockAdditional
paid-in
capital		Accumulated
deficit		Accumulated
other
comprehensive
loss		Stockholders’
equity
attributable
to KMI		Non-controlling
interests		Total
Balance at December 31, 2020
Balance at December 31, 2020
Balance at December 31, 2020
Restricted shares
Restricted shares
Restricted shares
Net income
Dividends
Distributions
Contributions
Reclassification of redeemable noncontrolling interest
Other comprehensive loss
Other comprehensive loss
Other comprehensive loss
Balance at December 31, 2021
Impact of adoption of ASU 2020-06 (Note 11)
Balance at January 1, 2022
Repurchases of shares
EP Trust I Preferred security conversions
Restricted shares
Net income
Dividends
Distributions
Contributions
Impact of change in ownership interest in subsidiary
Other comprehensive income
Other comprehensive income
Other comprehensive income
Balance at December 31, 2022
Repurchases of shares
Common stock Preferred stock            
Repurchases of shares
Issued shares Par value Issued shares Par value 
Additional
paid-in
capital
 
Retained
deficit
 
Accumulated
other
comprehensive
loss
 
Stockholders’
equity
attributable
to KMI
 
Non-controlling
interests
 Total
Balance at December 31, 20142,125
 $21
 —
 $—
 $36,178
 $(2,106) $(17) $34,076
 $350
 $34,426
Issuances of common shares103
 1
     3,869
     3,870
   3,870
Issuances of preferred shares    2
   1,541
     1,541
   1,541
Repurchase of warrants        (12)     (12)   (12)
EP Trust I Preferred security conversions1
       23
     23
   23
Warrants exercised        2
     2
   2
Repurchases of shares
Restricted shares
Restricted shares
Restricted shares        57
     57
   57
Net income          253
   253
 (45) 208
Dividends
Distributions              —
 (34) (34)
Contributions              —
 11
 11
Preferred stock dividends          (26)   (26)   (26)
Common stock dividends          (4,224)   (4,224)   (4,224)
Other        3
     3
 2
 5
Other comprehensive loss            (444) (444)   (444)
Balance at December 31, 20152,229
 22
 2
 —
 41,661
 (6,103) (461) 35,119
 284
 35,403
Restricted shares1
       66
     66
   66
Net income          708
   708
 13
 721
Distributions              —
 (24) (24)
Contributions              —
 117
 117
Preferred stock dividends          (156)   (156)   (156)
Common stock dividends          (1,118)   (1,118)   (1,118)
Other        12
     12
 (19) (7)
Other comprehensive loss            (200) (200)   (200)
Balance at December 31, 20162,230
 22
 2
 —

41,739

(6,669)
(661)
34,431

371
 34,802
Repurchases of shares(14)       (250)     (250)   (250)
Restricted shares1
       65
     65
   65
Net income          183
   183
 40
 223
KML IPO        314
   51
 365
 684
 1,049
KML preferred share issuance              —
 419
 419
Reorganization of foreign subsidiaries        38
     38
   38
Distributions              —
 (48) (48)
Contributions              —
 18
 18
Preferred stock dividends          (156)   (156)   (156)
Common stock dividends          (1,120)   (1,120)   (1,120)
Impact of adoption of ASU 2016-09 (See Note 5)          8
   8
   8
Sale and deconsolidation of interest in Deeprock Development, LLC              —
 (30) (30)
Acquisition (Note 3)
Other        3
     3
 (12) (9)
Other comprehensive income            69
 69
 46
 115
Balance at December 31, 20172,217
 $22
 2
 $—

$41,909

$(7,754)
$(541) $33,636
 $1,488
 $35,124
Balance at December 31, 2023


The accompanying notes are an integral part of these consolidated financial statements.

79

KINDER MORGAN, INC. AND SUBSIDIARIES


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.  
1.General

We are one of the largest energy infrastructure companies in North America and unlessAmerica. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company,” or “KMI” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2, renewable fuels and other products, and our terminals transloadstore and storehandle various commodities including gasoline, diesel fuel, jet fuel, chemicals, metals, petroleum products,coke, and ethanol and chemicals,other renewable fuels and handle products including petroleum coke, steel and coal. We are also a leading producer of CO2, which we and others utilize for enhanced oil recovery projects primarily in the Permian basin.

Our common stock trades on the NYSE under the symbol “KMI.”feedstocks.
 
2.  
2.Summary of Significant Accounting Policies

Basis of Presentation

Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars, unless stated otherwise. Our accompanying consolidated financial statements have been prepared under the rules and regulations of the SEC. These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification (ASC), the single source of GAAP. Under such rules and regulations, all significant intercompany items have been eliminated in consolidation. Additionally, certain amounts from prior years have been reclassified to conform to the current presentation.


Use of Estimates


Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities, our revenues and expenses during the reporting period, and our disclosures, including as it relatesthose related to contingent assets and liabilities at the date of our financial statements. We evaluate these estimates on an ongoing basis, 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. 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.

Certain accounting policies are of more significance in our financial statement preparation process than others, and set out below are the principal accounting policies we apply in the preparation of our consolidated financial statements.


Cash Equivalents and Restricted Deposits

We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less.

RestrictedAmounts included in the restricted deposits were $62in the accompanying consolidated financial statements represent a combination of restricted cash amounts required to be set aside by regulatory agencies to cover obligations for our captive insurance subsidiary, cash margin deposits posted by us with our counterparties associated with certain energy commodity contract positions and escrow deposits.

Allowance for Credit Losses

We evaluate our financial assets measured at amortized cost and off-balance sheet credit exposures for expected credit losses over the contractual term of the asset or exposure. We consider available information relevant to assessing the collectability of cash flows including the expected risk of credit loss even if that risk is remote. We measure expected credit losses on a collective (pool) basis when similar risk characteristics exist, and we reflect the expected credit losses on the amortized cost basis of the financial asset as of the reporting date.

Our financial instruments primarily consist of our accounts receivable from customers, notes receivable from affiliates and contingent liabilities such as proportional guarantees of debt obligations of an equity investee. We utilized historical analysis of credit losses experienced over the previous five years along with current conditions and reasonable and supportable forecasts of future conditions in our evaluation of collectability of our financial assets.
80


Our allowance for credit losses as of both December 31, 2023 and 2022 was $1 million and $103 million as of December 31, 2017 and 2016, respectively.

Accounts Receivable, net
The amounts reported as “Accounts receivable, net” onis included in “Other current assets” in our accompanying consolidated balance sheets as of December 31, 2017 and 2016 primarily consist of amounts due from customers net of the allowance for doubtful accounts.sheets.
Our policy for determining an appropriate allowance for doubtful accounts varies according to the type of business being conducted and the customers being served.  Generally, we make periodic reviews and evaluations of the appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and we record adjustments as necessary for changed circumstances and customer-specific information.  When specific receivables are determined to be uncollectible, the reserve and receivable are relieved.  

The allowance for doubtful accounts was $35 million and $39 million as of December 31, 2017 and 2016, respectively.


Inventories

Our inventories consist of materials and supplies and products such as natural gas, NGL, crude oil, condensate, refined petroleum products transmix and natural gas.transmix. We report products inventory at the lower of weighted-average cost or net realizable value. We report materials and supplies inventories at cost, and periodically review for physical deterioration and obsolescence.
Gas Imbalances
We value gas imbalances due to or due from interconnecting pipelines at market prices. As of December 31, 2017 and 2016, our gas imbalance receivables—including both trade and related party receivables—totaled $42 million and $108 million, respectively, and we included these amounts within “Other current assets” on our accompanying consolidated balance sheets. As of December 31, 2017 and 2016, our gas imbalance payables—including both trade and related party payables—totaled $47 million and $45 million, respectively, and we included these amounts within “Other current liabilities” on our accompanying consolidated balance sheets.

Property, Plant and Equipment, net

Capitalization, Depreciation and Depletion and Disposals


We report property, plant and equipment at its acquisition cost. We expense costs for routine maintenance and repairs in the period incurred. The following table summarizes our significant policies related to our property, plant and equipment. The application of these policies can involve significant estimates.

AssetAccounting AreaPolicy
Straight-line assetsDepreciation rates
•Depreciable lives are based on estimated economic lives. This includes age, manufacturing specifications, technological advances, estimated production life of the oil or gas field served by the asset, contract terms for assets on leased or customer property and historical data concerning useful lives of similar assets.
Gains and losses
•A gain or loss on the sale of property, plant and equipment is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sale proceeds received or when held for sale, the market value of the asset.
•A gain on an asset disposal is recognized in income in the period that the sale is closed.
•A loss is recognized when the asset is sold or when classified as held for sale.
•Gains and losses are recorded in operating costs, expenses and other.
Composite assetsDepreciation rates
•A single depreciation rate is applied to the total cost of a functional group of assets that have similar economic characteristics until the net book value of the composite group equals the salvage value.
•Interstate natural gas FERC-regulated entities use the depreciation rates approved by the FERC.
•A depreciation rate for other composite assets is based on estimated economic lives. This includes age, manufacturing specifications, technological advances, estimated production life of the oil or gas field served by the asset, contract terms for assets on leased or customer property and historical data concerning useful lives of similar assets.
Gains and losses
•Gains and losses are credited or charged to accumulated depreciation, net of salvage and cost of removal.
•Gains and losses on FERC-approved operating unit sales and land sales are recorded in operating costs, expenses and other.
Oil and gas producing activities(a)Successful efforts method of accounting
•Costs that are incurred to acquire leasehold and subsequent development costs are capitalized.
•Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found.
•Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of certain non-producing leasehold costs are expensed as incurred.
•The capitalized costs of our producing oil and gas properties are depreciated and depleted by the units-of-production method.
•Other miscellaneous property, plant and equipment are depreciated over the estimated useful lives of the asset.
Enhanced recovery techniques
•In some cases, the cost of the CO2 associated with enhanced recovery is capitalized as part of our development costs when it is injected.
•The cost of CO2 associated with pressure maintenance operations for reservoir management is expensed when it is injected.
•When CO2 is recovered in conjunction with oil production, it is extracted and re-injected, and all of the associated costs are expensed as incurred.
•Proved developed reserves are used in computing units of production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs.
We generally compute depreciation using either the
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(a)Gains and losses associated with assets in our oil and gas producing activities have a similar treatment as with that associated with our straight-line method based on estimated economic lives or the composite depreciation method,assets.

Circumstances may develop which applies a single depreciation rate for a group of assets. Generally, we apply composite depreciation rates to functional groups of property having similar economic characteristics. The rates range from 1.09% to 23.0% excluding certain short-lived assets such as vehicles. For FERC-regulated entities, the FERC-accepted composite depreciation rate is applied to the total cost of the composite group until the net book value equals the salvage value. For other entities, depreciation estimates are based on various factors, including age (in the case of acquired assets), manufacturing specifications, technological advances, contract term for assets on leased or customer property and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives (and salvage values where appropriate) that we believe are reasonable. Subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization expense. Historically, adjustments to useful lives have not had a material impact on our aggregate depreciation levels from year to year.


Our oil and gas producing activities are accounted for under the successful efforts method of accounting. Under this method costs that are incurred to acquire leasehold and subsequent development costs are capitalized. Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of certain non-producing leasehold costs are expensed as incurred. The capitalized costs of our producing oil and gas properties are depreciated and depleted by the units-of-production method. Other miscellaneous property, plant and equipment are depreciated over the estimated useful lives of the asset.

We engage in enhanced recovery techniques in which CO2 is injected into certain producing oil reservoirs. In some cases, the cost of the CO2 associated with enhanced recovery is capitalized as part of our development costs when it is injected. The cost of CO2 associated with pressure maintenance operations for reservoir management is expensed when it is injected. When CO2 is recovered in conjunction with oil production, it is extracted and re-injected, and all of the associated costs are expensed as incurred. Proved developed reserves are used in computing units of production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs.

A gain on the sale of property, plant and equipment used in our oil and gas producing activities or in our bulk and liquids terminal activities is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received. A gain on an asset disposal is recognized in income in the period that the sale is closed. A loss on the sale of property, plant and equipment is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received or the market value if the asset is being held for sale. A loss is recognized when the asset is sold or when the net cost of an asset held for sale is greater than the market value of the asset. For our pipeline system assets under the composite method of depreciation, we generally charge the original cost of property sold or retired to accumulated

depreciation and amortization, net of salvage and cost of removal. Gains and losses are booked for operating unit sales and land sales and are recorded to income or expense accounts in accordance with regulatory accounting guidelines. In those instances where we receive recovery in tariff rates related to losses on dispositions of operating units, we record a regulatory asset for the estimated recoverable amount.

Asset Retirement Obligations

We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses. The majority of our asset retirement obligations are associated with our CO2 business where we are required to plug and abandon oil and gas wells that have been removed from service and to remove the surface wellhead equipment and compressors, but we also have obligations for certain gathering and long-haul pipelines and certain processing plants. We record, as liabilities, the fair value of asset retirement obligations on a discounted basis when they are incurred and can be reasonably estimated, which is typically at the time the assets are installed or acquired. The fair value estimates are primarily based on Level 3 inputs of the fair value hierarchy. The inputs include estimates and assumptions related to timing of settlement and retirement costs, which we base on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities increase dueare accreted to reflect the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service. Our estimates of retirement costs could change as a result of changes in cost estimates and/or timing of the obligation.


We have various otherThe following table summarizes changes in the asset retirement obligations throughoutincluded in our businesses to remove facilitiesaccompanying consolidated balance sheets:
December 31,
20232022
(In millions)
Balance at beginning of period$204 $196 
Accretion expense12 12 
New obligations22 2 
Settlements(7)(6)
Balance at end of period(a)$231 $204 
(a)Balances at both December 31, 2023 and equipment2022 include $3 million included within “Other current liabilities” on rights-of-way and other leased facilities.  Weour accompanying consolidated balance sheets.

For certain assets, we currently cannot reasonably estimate the fair value of thesethe asset retirement obligations because the associated assets have indeterminate lives. These assets include certain pipelines, certain processing plants and distribution facilities, and certainliquids and bulk and liquids terminal facilities. AnBased on the widespread use of hydrocarbons domestically and for international export, management expects supply and demand to exist for the foreseeable future. Therefore, the remaining useful lives of these assets are indeterminate due to prolonged expected demand. Additionally, these assets could also benefit from potential future conversion opportunities. For example, certain assets could be converted to transport, handle or store products other than traditional hydrocarbons. Under our integrity program, individual asset parts are replaced regularly. Although some of the individual asset parts may be replaced, the assets themselves may remain intact indefinitely. For these assets, an asset retirement obligation, if any, will be recognized once sufficient information is available to reasonably estimate the fair value of the obligation.

Long-lived Asset and Other Intangibles Impairments

We evaluate long-lived assets including leases and investments for impairment whenever events or changes in circumstances indicate that our carrying amount of an asset or investment may not be recoverable.  We recognize impairment losses when estimated future cash flows expected to result from our use of the asset and its eventual disposition is less than its carrying amount.


In addition to our annual goodwill impairment test discussed further below, to the extent triggering events exist, we complete a review of the carrying value of our long-lived assets, including property, plant and equipment as well as other intangibles, and record, as applicable, the appropriate impairments.impairments using a two-step approach. To determine if a long-lived asset is recoverable, we compare the asset’s estimated undiscounted cash flows to its carrying value (step 1). Because the impairment test for long-lived assets held in use is based on estimated undiscounted cash flows, there may be instances where
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an asset or asset group is not considered impaired, even when its fair value may be less than its carrying value, because the asset or asset group is recoverable based on the cash flows to be generated over the estimated life of the asset or asset group. If the carrying value of a long-lived asset or asset group is in excess of estimated undiscounted cash flows, we typically use discounted cash flow analyses to calculate the fair value of the long-lived asset to determine if an impairment is required and the amount of the impairment losses to be recognized (step 2).


We evaluate our oil and gas producing properties for impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure, using undiscounted future cash flows based on total provedestimated future oil and risk-adjusted probable reserves.  gas production volumes.

Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future cash flows based on total provedestimated future oil and risk-adjusted probable and possible reserves or, if available, comparable market values.gas production volumes.  Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment.


Refer to Note 4 for further information.

Equity Method of Accounting and Excess Investment CostBasis Differences


We accountuse the equity method of accounting for investments which we do not control, but dofor which we have the ability to exercise significant influence using the equity methodinfluence. The carrying values of accounting. Under this method, our equitythese investments are carried originally at our acquisition cost, increasedimpacted by our proportionate share of investee income or loss, distributions, amortization or accretion of basis differences and other-than-temporary impairments.

The difference between the investee’s net incomecarrying value of an investment and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received.

With regard to our equity investments in unconsolidated affiliates, in almost all cases, either (i) the price we paid to acquire our share of the investment’s underlying equity in net assets of such equity investees or (ii) the revaluation of our share of the net assets of any retained noncontrolling equity investment (from the sale of a portion of our ownership interest in a consolidated subsidiary, thereby losing our controlling financial interest in the subsidiary) differed from the underlying carrying value of such net assets.  This differential consists of two pieces.  First, an amount related to the difference between the investee’s recognized net assets at book value and at current fair values (representing the appreciated value in plant and other net assets), and secondly, to any premium in excess of fair value (referredis referred to as equity method goodwill) we paid to acquirea basis difference. If the investment.  We include both amounts within “Investments” on our accompanying consolidated balance sheets.


The first differential, representing the excess of the fair market value of our investees’ plant and other net assets over its underlying book value at either the date of acquisition or the date of the loss of control totaled $732 million and $767 million as of December 31, 2017 and 2016, respectively. Generally, this basis difference relatesis assigned to our share of the underlying depreciable or amortizable assets and liabilities, the basis difference is amortized or accreted as such, we amortize this portionpart of our investment cost against our share of investee earnings. As of December 31, 2017, this excess investment cost is being amortized over a weighted average life of approximately fourteen years.

The second differential, representingTo the extent that the basis difference relates to goodwill, referred to as equity method goodwill, totaled $956 million for both periods as of December 31, 2017 and 2016. This differentialthe amount is not subject to amortization but rather toamortized.

We evaluate our equity method investments for other-than-temporary impairment. When an other-than-temporary impairment testing as part of our periodic evaluation ofis recognized, the recoverability of our investment as compared to the fair value of net assets accounted for under the equity method.  Our impairment test considers whether the fair value of the equity investmentloss is recorded as a whole has declined and whether that decline is other than temporary.reduction in equity earnings.


Goodwill

Goodwill is the cost of an acquisition of a business in excess of the fair value of acquired assets and liabilities and is recorded as an asset on our balance sheet. Goodwill is not subject to amortization but must be tested for impairment at least annually.annually and in interim periods if indicators of impairment exist. This test requires us to assign goodwill to an appropriate reporting unit and to determine ifcompare the implied fair value of a reporting unit to its carrying value. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value an impairment is measured and recorded at the amount by which the reporting unit’s goodwill is less thancarrying value exceeds its carrying amount.fair value.


We evaluate goodwill for impairment on May 31 of each year.year, or more frequently to the extent events occur or conditions change between annual tests that would indicate a risk of possible impairment at the interim period.  For this purpose,purposes of our May 31, 2023 evaluation, we havegrouped our businesses into seven reporting units as follows: (i) Natural Gas Pipelines Regulated; (ii) Natural Gas Pipelines Non-Regulated; (iii) CO2; (iv) Products Pipelines (excluding associated terminals); (ii)(v) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO2; (vi) Terminals; and (vii) Kinder Morgan Canada.  We also evaluate goodwill for impairment to the extent events or conditions indicate a risk of possible impairment during the interim periods subsequent to our annual impairment test.Energy Transition Ventures. Generally, the evaluation of goodwill for impairment involves a two-stepquantitative test, although under certain circumstancecircumstances an initial qualitative evaluation may be sufficient to conclude that goodwill is not impaired without conducting the quantitative test.

Step 1 involves comparing the estimated fair value of each respective reporting unit to its carrying value, including goodwill. If the estimated fair value exceeds the carrying value, the reporting unit’s goodwill is not considered impaired. If the carrying value exceeds the estimated fair value, step 2 must be performed to determine whether goodwill is impaired and, if so, the amount of the impairment. Step 2 involves calculating an implied fair value of goodwill by performing a hypothetical allocation of the estimated fair value of the reporting unit determined in step 1 to the respective tangible and intangible net assets of the reporting unit. The remaining implied goodwill is then compared to the actual carrying amount of the goodwill for the reporting unit. To the extent the carrying amount of goodwill exceeds the implied goodwill, the difference is the amount of the goodwill impairment.


A large portion of our goodwill is non-deductible for tax purposes, and as such, to the extent there are impairments, all or a portion of the impairment may not result in a corresponding tax benefit.


Refer to Note 8 “Goodwill” for further information.


Other Intangibles


Excluding goodwill, our other intangible assets include customer contracts and other relationships and agreements, lease value, and technology-based assets. As of both periods of December 31, 2017 and 2016, the gross carrying amounts of these intangible assets was $4,305 million and the accumulated amortization was $1,206 million and $987 million, respectively, resulting in net carrying amounts of $3,099 million and $3,318 million, respectively. Theseagreements.

Our intangible assets primarily consisted ofrelate to customer contracts or other relationships and agreements associated with our Natural Gas Pipelines and Terminals business segments.
Primarily, these contracts, relationships and agreements relate to the gathering of natural gas, andfor the handling and storage of petroleum, chemical, and dry-bulk materials, including oil, gasoline, and other refined petroleum products, petroleum coke, steelmetals and ores.
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ores, the gathering of natural gas and the production and supply of RNG. We determined the values of these intangible assets by first, estimating the revenues derived from a customer contract or relationship (offset by the cost and expenses of supporting assets to fulfill the contract), and second, discounting the revenues at a risk adjusted discount rate.


We amortize the costs of our intangible assets to expense in a systematic and rational manner over their estimated useful lives. The life of each intangible asset is based either on the life of the corresponding customer contract or agreement or, in

the case of a customer relationship intangible (the life of which was determined by an analysis of all available data on that business relationship), the length of time used in the discounted cash flow analysis to determine the value of the customer relationship. Among the factors we weigh, depending on the nature of the asset, are the effecteffects of obsolescence, new technology, and competition.

ForThe following tables summarize our other intangible assets as of December 31, 2023 and 2022 and our amortization expense for the years ended December 31, 2017, 20162023, 2022 and 2015, the amortization expense on our intangibles totaled $220 million, $223 million and $221 million, respectively.  2021: 
Weighted Average Amortization PeriodDecember 31,
20232022
(Years)(In millions)
Gross11.3$3,543 $3,382 
Accumulated amortization(1,586)(1,573)
Net carrying amount$1,957 $1,809 
December 31,
202320222021
(In millions)
Amortization expense$202 $253 $237 

Our estimated amortization expense for our intangible assets for each of the next five fiscal years (2018 – 2022) is approximately $214 million, $212 million, $209 million, $209 million, and $206 million, respectively.  As of December 31, 2017, the weighted average amortization period for our intangible assets was approximately sixteen years.is:

20242025202620272028
(In millions)
Estimated amortization expenses$198 $193 $191 $191 $190 

Revenue Recognition

The majority of our revenues are accounted for under Topic 606, Revenue from Contracts with Customers; however, to a limited extent, some revenues are accounted for under other guidance such as Topic 842, Leases or Topic 815, Derivatives and Hedging Activities.

Revenue from Contracts with Customers

We review our contracts with customers using the following steps to recognize revenue asbased on the transfer of goods or services are renderedto customers and in amounts that reflect the consideration the company expects to receive for those goods or goods are deliveredservices. The steps include: (i) identify the contract; (ii) identify the performance obligations of the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and if applicable, risk of loss has passed.  Wethen (v) recognize natural gas, crude and NGL sales revenue when (or as) the commodityperformance obligation is sold to a purchaser at a fixed or determinable price, delivery has occurredsatisfied. Each of these steps involves management judgment and risk of loss has transferred, and collectabilityan analysis of the revenue is reasonably assured. contract’s material terms and conditions.

Our customer sales and purchasescontracts primarily include sales of natural gas, NGL, crude oil, CO2and NGLtransmix, as described below. Generally, for the majority of these contracts (i) each unit (Bcf, gallon, barrel, etc.) of commodity is a separate performance obligation, as our promise is to sell multiple distinct units of commodity at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on our right to invoice at month end for the value of commodity sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity’s standalone selling price and recognized as revenue upon delivery of the commodity, which is the point in time when the customer obtains control of the commodity and our performance obligation is satisfied.

Our customer services contracts are primarily accounted for on a gross basistransportation service, storage service, gathering and processing service, and terminaling, as natural gas sales or product sales, as applicable, and costdescribed below. Generally, for the majority of sales, except in circumstances where we solely act as an agent and do not have price and related risk of ownership, in which case we recognize revenue on a net basis.
In addition to storing and transporting a significant portion of the natural gas volumes we purchase and resell, we provide various types of natural gas storage and transportation services for third-party customers.  Under these contracts (i) our promise is to transfer (or stand ready
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to transfer) a series of distinct integrated services over a period of time, which is a single performance obligation; (ii) the natural gas remainstransaction price includes fixed and/or variable consideration, which amount is determinable at contract inception and/or at each month end based on our right to invoice at month end for the propertyvalue of these customers at all times. In many cases, generally described as firm service,services provided to the customer pays a two-part rate that includes (i) a fixed fee reservingmonth; and (iii) the right to transport or store natural gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage.  The fixed-fee component of the overall ratetransaction price is recognized as revenue over the service period specified in the periodcontract (which can be a day, including each day in a series of promised daily services, a month, a year, or other time increment, including a deficiency makeup period) as the services are rendered using a time-based (passage of time) or units-based (units of service transferred) output method for measuring the transfer of control of the services and satisfaction of our performance obligation over the service period, based on the nature of the promised service (e.g., firm or non-firm) and the terms and conditions of the contract (e.g., contracts with or without makeup rights).

Firm Services

Firm services (also called uninterruptible services) are services that are promised to be available to the customer at all times during the period(s) covered by the contract, with limited exceptions. Our firm service contracts are typically structured with take-or-pay or minimum volume provisions, which specify minimum service quantities a customer will pay for even if it chooses not to receive or use them in the specified service period (referred to as “deficiency quantities”). We typically recognize the portion of the transaction price associated with such provisions, including any deficiency quantities, as revenue depending on whether the contract prohibits the customer from making up deficiency quantities in subsequent periods, or the contract permits this practice, as follows:

•Contracts without Makeup Rights. If contractually the customer cannot make up deficiency quantities in future periods, our performance obligation is provided.  The per-unit chargesatisfied, and revenue associated with any deficiency quantities is generally recognized as each service period expires. Because a service period may exceed a reporting period, we determine at inception of the contract and at the beginning of each subsequent reporting period if we expect the customer to take the minimum volume associated with the service period. If we expect the customer to make up all deficiencies in the specified service period (i.e., we expect the customer to take the minimum service quantities), the minimum volume provision is deemed not substantive and we will recognize the transaction price as revenue in the specified service period as the promised units of service are transferred to the customer. Alternatively, if we expect that there will be any deficiency quantities that the customer cannot or will not make up in the specified service period (referred to as “breakage”), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over such service period in proportion to the revenue that we will recognize for actual units of service transferred to the customer in the service period. For certain take-or-pay contracts where we make the service, or a part of the service (e.g., reservation) continuously available over the service period, we typically recognize the take-or-pay amount as revenue ratably over such period based on the passage of time.

•Contracts with Makeup Rights. If contractually the customer can acquire the promised service in a future period and make up the deficiency quantities in such future period (the “deficiency makeup period”), we have a performance obligation to deliver those services at the customer’s request (subject to contractual and/or capacity constraints) in the deficiency makeup period. At inception of the contract, and at the beginning of each subsequent reporting period, we estimate if we expect that there will be deficiency quantities that the customer will or will not make up. If we expect the customer will make up all deficiencies it is contractually entitled to, any non-refundable consideration received relating to temporary deficiencies that will be made up in the deficiency makeup period will be deferred as a contract liability, and we will recognize that amount as revenue in the deficiency makeup period when either of the following occurs: (i) the customer makes up the volumes or (ii) the likelihood that the customer will exercise its right for deficiency volumes then becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires). Alternatively, if we expect at inception of the contract, or at the beginning of any subsequent reporting period, that there will be any deficiency quantities that the customer cannot or will not make up (i.e., breakage), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over the specified service periods in proportion to the revenue that we will recognize for actual units of service transferred to the customer in those service periods.

Non-Firm Services

Non-firm services (also called interruptible services) are the opposite of firm services in that such services are provided to a customer on an “as available” basis. Generally, we do not have an obligation to perform these services until we accept a customer’s periodic request for service. For the majority of our non-firm service contracts, the customer will pay only for the actual quantities of services it chooses to receive or use, and we typically recognize the transaction price as revenue as those units of service are transferred to the customer in the specified service period (typically a daily or monthly period).

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Contract Balances

Contract assets and contract liabilities are the result of timing differences between revenue recognition, billings and cash collections. We recognize contract assets in those instances where billing occurs subsequent to revenue recognition, and our right to invoice the customer is conditioned on something other than the passage of time. Our contract assets are substantially related to breakage revenue associated with our firm service contracts with minimum volume commitment payment obligations and contracts where we apply revenue levelization (i.e., contracts with fixed rates per volume that increase over the life of the contract for which we record revenue ratably per unit over the life of the contract based on our performance obligations that are generally unchanged over the life of the contract). Our contract liabilities are substantially related to (i) capital improvements paid for in advance by certain customers generally in our non-regulated businesses, which we subsequently recognize as revenue on a straight-line basis over the initial term of the related customer contracts; (ii) consideration received from customers for temporary deficiency quantities under minimum volume contracts that we expect will be made up in a future period, which we subsequently recognize as revenue when the volumes are delivered to the customers’ agreed upon delivery point, or whencustomer makes up the volumes are injected into/withdrawn from our storage facilities. 

In other cases, generally described as interruptible service,or the likelihood that the customer will exercise its right for deficiency volumes becomes remote (e.g., there is noinsufficient capacity to make up the volumes, the deficiency makeup period expires); and (iii) contracts with fixed fee associated with the services because the customer accepts the possibilityrates per volume that service may be interrupted at our discretion in order to serve customers who have purchased firm service.  In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements.
We provide crude oil and refined petroleum products transportation and storage services to customers.  Revenues are recorded when products are delivered and services have been provided, and adjusted according to terms prescribed by the toll settlements with shippers and approved by regulatory authorities.
We recognize bulk terminal transfer service revenues based on volumes loaded and unloaded.  We recognize liquids terminal tank rental revenue ratablydecrease over the life of the contract period.where we apply revenue levelization for amounts received for our future performance obligations. We recognize liquids terminal throughput revenue based on volumes received and volumes delivered.  We recognize transmix processing revenues based on volumes processedreassess amounts recorded as contract assets or sold, and if applicable, when risk of loss has passed.  We recognize energy-related product sales revenues based on delivered quantities of product.liabilities upon contract modification.

Revenues from the sale of crude oil, NGL, CO2 and natural gas production within the CO2 business segment are recorded using the entitlement method.  Under the entitlement method, revenue is recorded when title passes based on our net interest.  We record our entitled share of revenues based on entitled volumes and contracted sales prices. Since there is a ready marketRefer to Note 15 for oil and gas production, we sell the majority of our products soon after production at various locations, at which time title and risk of loss pass to the buyer.further information.


CostCosts of Sales


CostCosts of sales primarily includes the cost ofto purchase energy commodities sold, including natural gas, crude oil, NGL and other refined petroleum products, adjusted for the effects of our energy commodity hedging activities, as applicable, other than production fromapplicable. Costs of our crude oil, gas and CO2 producing activities, such as those in our CO2 business segment.segment, are not accounted for as costs of sales.



Operations and Maintenance


Operations and maintenance includeincludes costs of services and is primarily comprised of (i) operational labor costs and (ii) operations, maintenance and asset integrity, regulatory and environmental costs. Costs associated with our crude oil, gas and CO2 producing activities included within operations and maintenance totaled $342$393 million, $349$367 million and $366$180 million for the years ended December 31, 2017, 20162023, 2022 and 2015,2021, respectively.


Environmental Matters

We capitalize or expense, as appropriate, environmental expenditures.  We capitalize certain environmental expenditures required in obtainingto obtain rights-of-way, regulatory approvals or permitting as part of the construction.construction of facilities we use in our business operations. We accrue and expense environmental costs that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We generally do not discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs.  Generally, our recording of these accruals coincides with ourcosts, such as after the completion of a feasibility study or our commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We record at estimated fair value, where appropriate, environmental liabilities assumed in a business combination.

We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations.  These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. We also routinely adjust our environmental liabilities to reflect changes in previous estimates. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us, and potential third-party liability claims.claims we may have against others. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs.  These revisions

Leases

We lease property including corporate and field offices and facilities, vehicles, heavy work equipment including rail cars and large trucks, tanks, office equipment and land. Our leases have remaining lease terms of one to 47 years, some of which have options to extend or terminate the lease. We determine if an arrangement is a lease at inception or upon modification. For purposes of calculating operating lease liabilities, lease terms may be deemed to include options to extend or terminate the lease when it is reasonably certain that we will exercise that option.
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Our operating ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Leases with variable rate adjustments, such as Consumer Price Index (CPI) adjustments, are reflected based on contractual lease payments as outlined within the lease agreement and not adjusted for any CPI increases or decreases. Because most of our leases do not provide an explicit rate of return, we use our incremental secured borrowing rate based on lease term information available at the commencement date of the lease in determining the present value of lease payments. We have real estate lease agreements with lease and non-lease components, which are accounted for separately. For certain equipment leases, such as copiers and vehicles, we account for the leases under a portfolio method. Leases that were grandfathered under various portions of Topic 842, such as land easements, are reassessed when the agreements are modified.

Refer to Note 17 for further information.

Share-based Compensation
We recognize compensation expense ratably over the vesting period of the restricted stock award based on the grant-date fair value, which is determined based on the market price of our incomeClass P common stock on the grant date, less estimated forfeitures. Forfeiture rates are estimated based on historical forfeitures under our restricted stock award plans. Upon vesting, the restricted stock award will be paid in the period in which they are reasonably determinable.shares of our Class P common stock.
 
Pensions and Other Postretirement Benefits

We recognize the differences between the fair value of each of our and our consolidated subsidiaries’ pension and other postretirement benefit plans’ assets and the benefit obligations as either assets or liabilities on our consolidated balance sheet.sheets. We record deferred plan costs and income—unrecognized losses and gains, unrecognized prior service costs and credits, and any remaining unamortized transition obligations—net of income taxes in “Accumulated other comprehensive loss,” with the proportionate share associated with less than wholly owned consolidated subsidiaries allocated and included within “Noncontrolling interests,” or as a regulatory asset or liability for certain of our regulated operations, until they are amortized as a component of benefit expense.


Deferred Financing Costs

We capitalize financing costs incurred with new borrowings and amortize the costs over the contractual term of the related obligations.

Redeemable Noncontrolling Interest

Through December 14, 2021, we had a redeemable noncontrolling interest which represented the interest in one of our consolidated subsidiaries, not owned by us, and which in certain limited circumstances, the partner had the right to relinquish its interest in the subsidiary. Distributions paid to the partner prior to that date were recorded as a reduction to the redeemable noncontrolling interest balance and included in “Distributions to investment partner” in our accompanying consolidated statement of cash flows. On December 14, 2021, the ownership agreement was modified such that the noncontrolling interest was no longer contingently redeemable, and the balance was reclassified to “Noncontrolling Interests.” Net income attributable to redeemable noncontrolling interest was $58 million for the year ended December 31, 2021 and is included in “Net Income Attributable to Noncontrolling Interests” in our accompanying consolidated statement of income.

Noncontrolling Interests


Noncontrolling interests represents the interests in our consolidated subsidiaries that are not owned by us.  In our accompanying consolidated statements of income, statements, the noncontrolling interest in the net income (or loss) of our less than wholly owned consolidated subsidiaries is shown as an allocation of our consolidated net income and is presented separately as “Net (Income) LossIncome Attributable to Noncontrolling Interests.”  In our accompanying consolidated balance sheets, noncontrolling interests is presented separately as “Noncontrolling interests” within “Stockholders’ Equity.”

Income Taxes

Income tax expense is recorded based on an estimate of the effective tax rate in effect or to be in effect during the relevant periods. Changes in tax legislation are included in the relevant computations in the period in which such changes are enacted. We do business in a number of states with differing laws concerning how income subject to each state’s tax structure is measured and at what effective rate such income is taxed. Therefore, we must make estimates of how our income will be
87

apportioned among the various states in order to arrive at an overall effective tax rate. Changes in our effective tax rate, including any effect on previously recorded deferred taxes, are recorded in the period in which the need for such change is identified.


Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Deferred tax assets are reduced by a valuation allowance for the amountwhen it is more-likely-than-not that is, more likely than not, toall, or a portion, of a deferred tax asset will not be realized. While we have considered estimated future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance, any change in the amount that we

expect to ultimately realize will be included in income in the period in which such a determination is reached. Income tax effects are released from accumulated other comprehensive loss to retained earnings, when applicable, on an individual item basis as those items are reclassified into income.


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


Foreign Currency Transactions and Translation
Foreign currency transaction gains or losses result from a change in exchange rates between (i) the functional currency, for example the Canadian dollar for a Canadian subsidiary and (ii) the currency in which a foreign currency transaction is denominated, for example the U.S. dollar for a Canadian subsidiary.  In our accompanying consolidated statements of income, gains and losses from our foreign currency transactions are included within “Other Income (Expense)—Other, net.”
Foreign currency translation is the process of expressing, in U.S. dollars, amounts recorded in a local functional currency other than U.S. dollars, for example the Canadian dollar for a Canadian subsidiary.  We translate the assets and liabilities of each of our consolidated foreign subsidiaries that have a local functional currency to U.S. dollars at year-end exchange rates.  Income and expense items are translated at weighted-average rates of exchange prevailing during the year and stockholders’ equity accounts are translated by using historical exchange rates.  The cumulative translation adjustments balance is reported as a component of “Accumulated other comprehensive loss.”

Risk Management ActivitiesAsset Retirement Obligations

We utilize energy commodity derivative contractsrecord liabilities for obligations related to the purposeretirement and removal of mitigatinglong-lived assets used in our risk resulting from fluctuations in the market pricebusinesses. The majority of commodities including natural gas, NGL and crude oil.  In addition, we enter into interest rate swap agreements for the purpose of hedging the interest rate riskour asset retirement obligations are associated with our debt obligations.CO2 business where we are required to plug and abandon oil and gas wells that have been removed from service and to remove the surface wellhead equipment and compressors, but we also have obligations for certain gathering and long-haul pipelines and certain processing plants. We also enter into cross-currency swap agreements to manage our foreign currency risk with certain debt obligations. We measure our derivative contracts atrecord, as liabilities, the fair value of asset retirement obligations on a discounted basis when they are incurred and can be reasonably estimated, which is typically at the time the assets are installed or acquired. The fair value estimates are primarily based on Level 3 inputs of the fair value hierarchy. The inputs include estimates and assumptions related to timing of settlement and retirement costs, which we report thembase on our balance sheet as either an asset or liability. For certain physical forward commodity derivatives contracts, we applyhistorical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. Amounts recorded for the normal purchase/normal sale exception, wherebyrelated assets are increased by the revenues and expenses associated with such transactionsamount of these obligations. Over time, the liabilities are recognized during the period when the commodities are physically delivered or received.

For qualifying accounting hedges, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives and the methods used for assessing and testing effectiveness, and how any ineffectiveness will be measured and recorded. If we designate a derivative contract as a cash flow accounting hedge, the effective portion ofaccreted to reflect the change in fairtheir present value, and the initial capitalized costs are depreciated over the useful lives of the derivativerelated assets. The liabilities are eventually extinguished when the asset is deferredtaken out of service. Our estimates of retirement costs could change as a result of changes in “Accumulated other comprehensive loss” and reclassified into earningscost estimates and/or timing of the obligation.

The following table summarizes changes in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value or amount excluded from the assessment of hedge effectiveness is recognized currently in earnings. If we designate a derivative contract as a fair value accounting hedge, the effective portion of the change in fair value of the derivative is recorded as an adjustment to the item being hedged. Any ineffective portion of the derivative’s change in fair value is recognized currently in earnings.

For derivative instruments that are not designated as accounting hedges, or for which we have not elected the normal purchase/normal sales exception, changes in fair value are recognized currently in earnings.
Regulatory Assets and Liabilities

 Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process.  Weasset retirement obligations included the amounts of our regulatory assets and liabilities within “Other current assets,” “Deferred charges and other assets,” “Other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance sheets.sheets:
December 31,
20232022
(In millions)
Balance at beginning of period$204 $196 
Accretion expense12 12 
New obligations22 2 
Settlements(7)(6)
Balance at end of period(a)$231 $204 

The following table summarizes our regulatory asset and liability balances as of (a)Balances at both December 31, 20172023 and 2016 (in millions):
 December 31,
 2017 2016
Current regulatory assets$60
 $49
Non-current regulatory assets288
 330
Total regulatory assets(a)$348
 $379
    
Current regulatory liabilities$107
 $101
Non-current regulatory liabilities236
 108
Total regulatory liabilities(b)$343
 $209
_______
(a)Regulatory assets as of December 31, 2017 include (i) $1932022 include $3 million of unamortized losses on disposal of assets; (ii) $55 million income tax gross up on equity AFUDC; and (iii) $100 million of other assets including amounts related to fuel tracker arrangements. Approximately $124 million of the regulatory assets, with a weighted average remaining recovery period of 17 years, are recoverable without earning a return, including the income tax gross up on equity AFUDC for which there is an offsetting deferred income tax balance for FERC rate base purposes, and therefore, it does not earn a return.
(b)Regulatory liabilities as of December 31, 2017 are comprised of customer prepayments to be credited to shippers or other over-collections that are expected to be returned to shippers or netted against under-collections over time. Approximately $20 million of the $236 million classified as non-current is expected to be credited to shippers over a remaining weighted average period of 28 years, while the remaining $216 million is not subject to a defined period.

Transfer of Net Assets Between Entities Under Common Control
We account for the transfer of net assets between entities under common control by carrying forward the net assets recognized in the balance sheets of each combining entity to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination.  Transfers of net assets between entities under common control do not affect the historical income statement or balance sheet of the combined entity.

Earnings per Share

We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares of common stock and participating securities 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. Our unvested restricted stock awards, which may be stock or stock units issued to management employees and include dividend equivalent payments, do not participate in excess distributions over earnings.

The following tables set forth the allocation of net income available to shareholders of Class P shares and participating securities and the reconciliation of Basic Weighted Average Common Shares Outstanding to Diluted Weighted Average Common Shares Outstanding (in millions):

 Year Ended December 31,
 2017 2016 2015
Net Income Available to Common Stockholders$27
 $552
 $227
Participating securities:     
   Less: Net Income Allocated to Restricted stock awards(a)(5) (4) (13)
Net Income Allocated to Class P Stockholders$22
 $548
 $214
      
Basic Weighted Average Common Shares Outstanding2,230
 2,230
 2,187
Basic Earnings Per Common Share$0.01
 $0.25
 $0.10

 Year Ended December 31,
 2017 2016 2015
Basic Weighted Average Common Shares Outstanding2,230
 2,230
 2,187
Effect of dilutive securities:     
   Warrants—
 —
 6
Diluted Weighted Average Common Shares Outstanding2,230
 2,230
 2,193
_______
(a)As of December 31, 2017, there were approximately 11 million such restricted stock awards.

The following maximum number of potential common stock equivalents are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share (in millions on a weighted average basis):
 Year Ended December 31,
 2017 2016 2015
Unvested restricted stock awards10
 8
 7
Warrants to purchase our Class P shares(a)116
 293
 291
Convertible trust preferred securities3
 8
 8
Mandatory convertible preferred stock(b)58
 58
 10
_______
(a)On May 25, 2017, approximately 293 million of unexercised warrants expired without the issuance of Class P common stock. Prior to expiration, each warrant entitled the holder to purchase one share of our common stock for an exercise price of $40 per share. The potential dilutive effect of the warrants did not consider the assumed proceeds to KMI upon exercise.
(b)Until our mandatory convertible preferred shares are converted to common shares, on or before the expected mandatory conversion date of October 26, 2018, the holder of each preferred share participates in our earnings by receiving preferred stock dividends.

3.  Acquisitions and Divestitures

Business Combinations

There were no significant acquisitions during 2017. During 2016 and 2015, we completed the following significant acquisitions.

Allocation of Purchase Price

As of December 31, 2017, the purchase allocation for our significant acquisitions completed during the reporting periods are detailed below (in millions):
        Assignment of Purchase Price
Ref. Date Acquisition 
Purchase
price
 
Current
assets
 
Property
plant &
equipment
 
Deferred
charges
& other
 Goodwill Debt Other liabilities
(1) 2/16 BP Products North America Inc. Terminal Assets $349
 $2
 $396
 $—
 $—
 $—
 $(49)
(2) 2/15 Vopak Terminal Assets 158
 2
 155
 —
 6
 —
 (5)
(3) 2/15 Hiland 1,709
 79
 1,492
 1,498
 310
 (1,413) (257)

After measuring all of the identifiable tangible and intangible assets acquired and liabilities assumed at fair value on the acquisition date, goodwill is an intangible asset representing the future economic benefits expected to be derived from an acquisition that are not assigned to other identifiable, separately recognizable assets.  We believe the primary items that generated our goodwill are both the value of the synergies created between the acquired assets and our pre-existing assets, and our expected ability to grow the business we acquired by leveraging our pre-existing business experience.  We apply a look through method of recording deferred income taxes on the outside book-tax basis differences in our investments. As a result, no deferred income taxes are recorded associated with non-deductible goodwill recorded at the investee level.


(1) BP Products North America Inc. (BP) Terminal Assets

On February 1, 2016, we completed the acquisition of 15 products terminals and associated infrastructure from BP for $349 million, including a transaction deposit paid in 2015 and working capital adjustments paid in 2016. In conjunction with this transaction, we and BP formed a joint venture with an equity ownership interest of 75% and 25%, respectively. Subsequent to the acquisition, we contributed 14 of the acquired terminals to the joint venture, which we operate, and the remaining terminal is solely owned by us. BP acquired its 25% interest in the joint venture for $84 million, which we reported as “Contributions from noncontrolling interests” within our accompanying consolidated statement of cash flows for the year ended December 31, 2016. Of the acquired assets, 10 terminals are included in our Terminals business segment and 5 terminals are included in our Products Pipelines business segment based on synergies with each segment’s respective existing operations.

(2) Vopak Terminal Assets

On February 27, 2015, we acquired three U.S. terminals and one undeveloped site from Royal Vopak (Vopak) for approximately $158 million in cash. The acquisition included (i) a 36-acre, 1,069,500-barrel storage facility at Galena Park, Texas that handles base oils, biodiesel and crude oil and is immediately adjacent to our Galena Park terminal facility; (ii) two terminals in North Carolina: one in North Wilmington that handles chemicals and black oil and the other in South Wilmington that is not currently operating; and (iii) an undeveloped waterfront access site in Perth Amboy, New Jersey. We include the acquired assets as part of our Terminals business segment.

(3) Hiland

On February 13, 2015, we acquired Hiland, a privately held Delaware limited partnership for aggregate consideration of approximately $3,122 million, including assumed debt. Approximately $368 million of the debt assumed was immediately paid down after closing. Hiland’s assets consist primarily of crude oil gathering and transportation pipelines and gas gathering and processing systems, primarily handling production from the Bakken Formation in North Dakota and Montana. The acquired gathering and processing assets are included in our Natural Gas Pipelines business segment while the acquired crude oil transport pipeline (Double H pipeline) is included in our Products Pipelines business segment. Deferred charges and other relates to customer contracts and relationships with a weighted average amortization period as of the acquisition date of 16.4 years.

Asset Purchase and Subsequent Sale of Noncontrolling Interest

On July 15, 2015, we purchased from Shell US Gas & Power LLC (Shell) its 49% interest in a joint venture, ELC, that was in the pre-construction stage of development for liquefaction facilities at Elba Island, Georgia. The transaction was treated as an asset purchase for the net cash consideration of $185 million. Immediately subsequent to the purchase and before the partial sale discussed below, we had full ownership and control of ELC and prospectively changed our method of accounting for ELC from the equity method to full consolidation. Shell remains subscribed to 100% of the liquefaction capacity.

Effective February 28, 2017, we sold a 49% partnership interest in ELC to investment funds managed by EIG Global Energy Partners (EIG). We continue to own a 51% controlling interest in and operate ELC. Under the terms of ELC’s limited liability company agreement, we are responsible for placing in service and operating certain supply pipelines and terminal facilities that support the operations of ELC and which are wholly owned by us. In certain limited circumstances which are not expected to occur, EIG has the right to relinquish its interest in ELC and redeem its capital account.
As a result of these contingencies, the sale proceeds of $386 million, and subsequent EIG contributions, have been recorded as a deferred credit within “Other long-term liabilities and deferred credits” on our consolidated balance sheet as of December 31, 2017. EIG is not entitled to any specified return on its capital. Once these contingencies expire, EIG’s capital account will be reflected in Noncontrolling interests on our consolidated balance sheet.
Investment Acquisition

On December 10, 2015, we and Brookfield Infrastructure Partners L.P. (Brookfield) acquired from Myria Holdings, Inc. the 53% equity interest in NGPL Holdings LLC not previously owned by us and Brookfield, increasing our ownership to 50% with Brookfield owning the remaining 50%. We paid $136 million for our additional 30% interest in NGPL Holdings LLC. See Note 7 “Investments” for additional information regarding our equity interests in NGPL Holdings LLC.


Sale of Approximate 30% Interest in Canadian Business

On May 30, 2017, our indirectly owned subsidiary, KML, completed an IPO of 102,942,000 restricted voting shares listed on the Toronto Stock Exchange at a price to the public of $17.00 per restricted voting share for total gross proceeds of approximately C$1,750 million (US$1,299 million). The net proceeds from the IPO were used by KML to indirectly acquire from us an approximate 30% interest in a limited partnership that holds our Canadian business while we retained the remaining 70% interest. We used the proceeds from KML’s IPO to pay down debt.
Subsequent to the IPO, we retained control of KML and the limited partnership, and as a result, they remain consolidated in our consolidated financial statements. The public ownership of the KML restricted voting shares is reflected within “Noncontrolling interests” in our consolidated statements of stockholders’ equity and consolidated balance sheets. Earnings attributable to the public ownership of KML are presented in “Net (income) loss attributable to noncontrolling interests” in our consolidated statements of income for the periods presented after May 30, 2017.
The net proceeds received of $1,245 million are presented as “Contributions from noncontrolling interests - net proceeds from KML IPO” on our consolidated statement of cash flows for the year ended December 31, 2017. Because we retained control of KML subsequent to the IPO, the $314 million adjustment made to “Additional paid-in capital” on our consolidated statement of stockholders equity for the year ended December 31, 2017 represents the difference between our book value prior to the sale and our share of book value in KML’s net assets after the sale. The impact of the IPO resulted in a $166 million deferred income tax adjustment. At the date of the IPO, $765 million was attributed to the KML public shareholders to reflect their proportionate ownership percentage in the net assets of KML acquired from us and is included in “Noncontrolling interests” on our consolidated statement of stockholders equity. The above amounts recorded to “Additional paid-in capital” and “Noncontrolling interests” are net of IPO fees.
In addition, the amount recorded to “Noncontrolling interests” at the date of the IPO was reduced by $81 million primarily associated with the allocation of currency translation adjustments from “Accumulated other comprehensive loss” to “Noncontrolling interests.”
The portion of the Canadian business operations that we sold to the public on May 30, 2017 represented Canadian assets that are included in our Kinder Morgan Canada, Terminals and Product Pipelines business segments and include (i) the Trans Mountain pipeline system; (ii) the Canadian Cochin pipeline system; (iii) the Puget Sound pipeline system; (iv) the Jet Fuel pipeline system; and (v) terminal facilities located in Western Canada. In January 2018, KML completed the registration of its restricted voting shares pursuant to Section 12(g) of the United States Securities Exchange Act of 1934 (the “Exchange Act”) and KML is now subject to the reporting requirements of Section 13(a) of the Exchange Act.

In conjunction with the IPO, Kinder Morgan Canada Limited Partnership (KMC LP) and Kinder Morgan Canada GP Inc. (KMC GP) were formed to hold our Canadian business. We have determined that KMC LP is a variable interest entity because a simple majority or lower threshold of the limited partnership interests do not possess substantive “kick-out rights” (i.e., the right to remove the general partner or to dissolve (liquidate) the entity without cause) or substantive participation rights. We have also determined KMC GP is the primary beneficiary because it has the power to direct the activities that most significantly impact KMC LP’s performance, the right to receive benefits and the obligation to absorb losses, that could be significant to KMC LP. As a result, KMC GP consolidates KMC LP. KMC GP is a wholly owned subsidiary of KML, which is indirectly controlled by us through our 100% interest in KML’s special voting shares that represent approximately 70% of KML’s total voting shares (comprised of restricted voting shares and special voting shares). Consequently, we consolidate KML and the variable interest entity, KMC LP, in our consolidated financial statements.


The following table shows the carrying amount and classification of KMC LP’s assets and liabilities in our consolidated balance sheet (in millions):
  December 31, 2017
Assets  
Total current assets $270
Property, plant and equipment, net 2,956
Total goodwill, deferred charges and other assets 322
         Total assets $3,548
Liabilities  
Current portion of debt $—
Total other current liabilities 236
Long-term debt, excluding current maturities —
Total other long-term liabilities and deferred credits 414
         Total liabilities $650

We receive distributions from KMC LP through our indirectly owned limited partnership interests in KMC LP, but otherwise the assets of KMC LP cannot be used to settle our obligations other than those of KML. Our subsidiaries that are the direct owners of our limited partnership interests in KMC LP have guaranteed the obligations of KMC LP’s wholly owned subsidiaries, Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC, under the Credit Facility (see Note 9 “Debt”), but recourse in respect of such guarantee is limited solely to the limited partnership interests of KMC LP held by such subsidiaries and any proceeds thereof.  Additionally, in connection with the Credit Facility, we entered into an Equity Nomination and Support Agreement whereby, among other things, we commit to contribute or cause to be contributed at the time of each drawdown on the construction credit facility or the contingent credit facility either equity or subordinated debt to Kinder Morgan Cochin ULC in an amount sufficient to cause the outstanding indebtedness under the credit facilities and any other funded debt for the TMEP not to exceed 60% of the total project costs for the project as projected over the six month period following the date of such drawdown.  Other than such guarantees and the Equity Nomination and Support Agreement, we do not guarantee the debt, commercial paper or other similar commitments of KMC LP or any of its subsidiaries, and the obligations of KMC LP may only be settled using the assets of KMC LP. KMC LP does not guarantee the debt or other similar commitments of KMI.

Terminals Asset Sale

In October 2016, we entered into a definitive agreement to sell several bulk terminals to an affiliate of Watco Companies, LLC for approximately $100 million. The terminals are predominantly located along the inland river system and handle mostly coal and steel products, and are included within our Terminals business segment. The sale of eight of the locations closed in the fourth quarter of 2016, for which we received $37 million of the total consideration, and the balance of this transaction, which included an additional eleven locations, closed in the second quarter of 2017 as certain conditions were satisfied. As a result of this transaction, we recognized a pre-tax loss of $81 million, including a $7 million reduction of goodwill, which is included within “Loss on impairments and divestitures, net” on our accompanying consolidated statement of income for the year ended December 31, 2016, and we classified $61 million as held for sale for the remaining locations which is included within “Other current assets”liabilities” on our accompanying consolidated balance sheet at December 31, 2016.sheets.


Sale of Equity Interest in SNG

On September 1, 2016, we completed the sale of a 50% interest in our SNG natural gas pipeline system to The Southern Company (Southern Company), receiving proceeds of $1.4 billion, and the formation of a joint venture, which includes our remaining 50% interest in SNG. We used the proceeds from the sale to reduce outstanding debt. We recognized a pre-tax loss of $84 million on the sale of our interest in SNG which is included within “Loss on impairments and divestitures, net” on the accompanying consolidated statement of income for the year ended December 31, 2016. As a result of this transaction, we no longer hold a controlling interest in SNG or Bear Creek Storage Company, LLC (Bear Creek) (50% of which is owned by SNG) and, as such, we now account for our remaining equity interests in SNG and Bear Creek as equity investments.




4.  Impairments and Losses on Divestitures

During the years ended December 31, 2017, 2016, and 2015, we recorded impairments of certain equity investments, long-lived assets, and intangible assets, and net losses on divestitures totaling $172 million, $1,013 million, and $2,125 million, respectively. During 2015 and 2016, and to a lesser degree in 2017, a sustained lower commodity price environment, and negative outlook for certain long-term transportation contracts, led us to cancel certain construction projects, divest ofFor certain assets, write-down certain assets and investments to fair value. In addition, an interim goodwill impairment test was performed during the fourth quarter of 2015 resulting in a partial impairment of goodwill in our Natural Gas Pipelines Non-Regulated reporting unit of approximately $1,150 million. See Note 8 “Goodwill” for further information.

These impairments were driven by market conditions that existed at the time and required management towe currently cannot reasonably estimate the fair value of the asset retirement obligations because the associated assets have indeterminate lives. These assets include certain pipelines, processing plants and distribution facilities, and liquids and bulk terminal facilities. Based on the widespread use of hydrocarbons domestically and for international export, management expects supply and demand to exist for the foreseeable future. Therefore, the remaining useful lives of these assets. The estimates of fair valueassets are based on Level 3 valuation estimates using industry standard income approach valuation methodologies which include assumptions primarily involving management’s significant judgments and estimates with respectindeterminate due to general economic conditions and the related demand for products handled or transported by ourprolonged expected demand. Additionally, these assets as well as assumptions regarding commodity prices,could also benefit from potential future cash flows based on rate and volume assumptions, terminal values and discount rates. In certain cases, management’s decisions to dispose ofconversion opportunities. For example, certain assets could be converted to transport, handle or store products other than traditional hydrocarbons. Under our integrity program, individual asset parts are replaced regularly. Although some of the individual asset parts may triggerbe replaced, the assets themselves may remain intact indefinitely. For these assets, an impairment. We typically use discounted cash flow analysesasset retirement obligation, if any, will be recognized once sufficient information is available to determinereasonably estimate the fair value of the obligation.

Long-lived Asset Impairments

We evaluate long-lived assets including leases and investments for impairment whenever events or changes in circumstances indicate that our assets. Wecarrying amount of an asset or investment may probability weight various forecasted cash flow scenarios utilized in the analysis as we consider the possible outcomes. We use discount rates representingnot be recoverable.

In addition to our estimate of the risk-adjusted discount rates that would be used by market participants specificannual goodwill impairment test discussed further below, to the particular asset.

We may identify additionalextent triggering events requiring future evaluations of the recoverabilityexist, we complete a review of the carrying value of our long-lived assets, investmentsincluding property, plant and goodwill.equipment as well as other intangibles, and record, as applicable, the appropriate impairments using a two-step approach. To determine if a long-lived asset is recoverable, we compare the asset’s estimated undiscounted cash flows to its carrying value (step 1). Because certainthe impairment test for long-lived assets held in use is based on estimated undiscounted cash flows, there may be instances where
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an asset or asset group is not considered impaired, even when its fair value may be less than its carrying value, because the asset or asset group is recoverable based on the cash flows to be generated over the estimated life of the asset or asset group. If the carrying value of a long-lived asset or asset group is in excess of estimated undiscounted cash flows, we typically use discounted cash flow analyses to calculate the fair value of the long-lived asset to determine if an impairment is required and the amount of the impairment losses to be recognized (step 2).

We evaluate our assets, including some equity investments and oil and gas producing properties have beenfor impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure, using undiscounted future cash flows based on estimated future oil and gas production volumes.

Oil and gas producing properties deemed to be impaired are written down to their fair value, any deterioration in fair value relative to our carrying value increases the likelihood of further impairments. Such non-cash impairments could have a significant effectas determined by discounted future cash flows based on our results of operations, which would be recognized in the period in which the carrying value is determined to be not fully recoverable.

We recognized the following non-cash pre-tax impairment chargesestimated future oil and losses (gains) on divestitures of assets (in millions):
 Year Ended December 31,
 2017 2016 2015
Natural Gas Pipelines     
Impairment of goodwill$—
 $—
 $1,150
  Impairments of long-lived assets(a)30
 106
 79
Losses on divestitures of long-lived assets(b)—
 94
 43
  Impairments of equity investments(c)150
 606
 26
  Impairments at equity investees(d)10
 7
 —
CO2
     
  Impairments of long-lived assets(e)(1) 20
 606
Gains on divestitures of long-lived assets—
 (1) —
  Impairments at equity investee(d)(4) 9
 26
Terminals     
  Impairments of long-lived assets(f)3
 19
 188
(Gains) losses on divestitures of long-lived assets(g)(18) 80
 3
Losses on impairments and divestitures of equity investments, net—
 16
 4
Products Pipelines     
  Impairments of long-lived assets(h)—
 66
 —
Losses (gains) on divestitures of long-lived assets—
 10
 1
Gain on divestiture of equity investment—
 (12) —
      
Other losses (gains) on divestitures of long-lived assets2
 (7) (1)
Pre-tax losses on impairments and divestitures, net$172
 $1,013
 $2,125
_______

(a) 2017 amount represents the impairment of our Colden storage facility, of which $3 million is included in “Costs of sales” on our accompanying consolidated statement of income. 2016 amount represents the project write-off of our portion of the Northeast Energy Direct (NED) Market project. 2015 amount represents $47 million and $32 million of project write-offs in our non-regulated midstream and regulated natural gas pipelines assets, respectively.
(b) 2016 amount primarily relates to our sale of a 50% interest in SNG.
(c) 2017 amount represents the impairment of our investment in FEP. 2016 amount includes a $350 million impairment of our investment in MEP and a $250 million impairment of our investment in Ruby. 2015 amount is primarily related to an impairment of an investment in a gathering and processing asset in Oklahoma.
(d) Amounts represent losses on impairments recorded by equity investees and are included in “Earnings from equity investments” on our accompanying consolidated statements of income.
(e) 2015 amount includes (i) $399 million related toproduction volumes.  Unproved oil and gas properties and (ii) $207 million related to the certain CO2 source and transportation project write-offs.
(f) 2015 amount is primarily related to certain terminals withthat are individually significant coal operations, including a $175 millionare periodically assessed for impairment of value, and a terminal facility reflectingloss is recognized at the impacttime of an agreementimpairment.

Refer to adjust certain payment terms under a contract with a coal customer in February 2016.Note 4 for further information.
(g) 2017 amount includes a $23 million gain related to the sale
Equity Method of a 40% membership interest in the Deeprock Development joint venture. 2016 amount primarily relates to the sale of 20 bulk terminals that handle mostly coalAccounting and steel products, predominately located along the inland river system.Basis Differences
(h) 2016 amount represents project write-offs associated with the canceled Palmetto project.

5.  Income Taxes

The components of “Income Before Income Taxes” are as follows (in millions):
 Year Ended December 31,
 2017 2016 2015
U.S.$1,976
 $1,466
 $611
Foreign185
 172
 161
Total Income Before Income Taxes$2,161
 $1,638
 $772

Components of the income tax provision applicable for federal, foreign and state taxes are as follows (in millions): 
 Year Ended December 31,
 2017 2016 2015
Current tax expense (benefit)     
Federal$(137) $(148) $(125)
State(16) (28) (7)
Foreign18
 6
 4
Total(135) (170) (128)
Deferred tax expense (benefit) 
  
  
Federal2,022
 998
 653
State4
 51
 (4)
Foreign47
 38
 43
Total2,073
 1,087
 692
Total tax provision$1,938
 $917
 $564


We use the equity method of accounting for investments which we do not control, but for which we have the ability to exercise significant influence. The carrying values of these investments are subject to taxation in Canadaimpacted by our share of investee income or loss, distributions, amortization or accretion of basis differences and Mexico. In Canada we recognized income tax expense of $58 million, $38 million and $46 million at December 31, 2017, 2016, and 2015, respectively.  In Mexico we recognized income tax expense of $7 million, $6 million and $1 million at December 31, 2017, 2016, and 2015, respectively. other-than-temporary impairments.



The difference between the statutory federal income tax ratecarrying value of an investment and our effective income tax rateshare of the investment’s underlying equity in net assets is summarizedreferred to as follows (in millions, except percentages):
 Year Ended December 31,
 2017 2016 2015
Federal income tax$756
 35.0 % $573
 35.0 % $271
 35.0 %
Increase (decrease) as a result of: 
  
  
  
  
  
State deferred tax rate change10
 0.5 % 11
 0.7 % (24) (3.1)%
Taxes on foreign earnings, net of federal benefit42
 1.9 % 28
 1.7 % 26
 3.5 %
Net effects of noncontrolling interests(14) (0.7)% (4) (0.3)% 15
 2.0 %
State income tax, net of federal benefit38
 1.8 % 26
 1.6 % 12
 1.5 %
Dividend received deduction(56) (2.6)% (48) (2.9)% (51) (6.6)%
Adjustments to uncertain tax positions(12) (0.6)% (23) (1.4)% (14) (1.9)%
Valuation allowance on investment and tax credits13
 0.6 % 34
 2.1 % —
 — %
Impact of the 2017 Tax Reform1,240
 57.4 % —
 — % —
 — %
Nondeductible goodwill—
 — % 301
 18.5 % 323
 41.7 %
General business credit(95) (4.4)% —
 — % —
 — %
Other16
 0.8 % 19
 1.1 % 6
 0.8 %
Total$1,938
 89.7 % $917
 56.1 % $564
 72.9 %

Deferred taxa basis difference. If the basis difference is assigned to depreciable or amortizable assets and liabilities, result from the following (in millions):basis difference is amortized or accreted as part of our share of investee earnings. To the extent that the basis difference relates to goodwill, referred to as equity method goodwill, the amount is not amortized.

 December 31,
 2017 2016
Deferred tax assets   
Employee benefits$251
 $401
Accrued expenses73
 118
Net operating loss, capital loss and tax credit carryforwards1,113
 1,307
Derivative instruments and interest rate and currency swaps12
 22
Debt fair value adjustment37
 74
Investments968
 2,804
Other6
 14
Valuation allowances(171) (184)
Total deferred tax assets2,289
 4,556
Deferred tax liabilities 
  
Property, plant and equipment225
 177
Other20
 27
Total deferred tax liabilities245
 204
Net deferred tax assets$2,044
 $4,352
    

Deferred Tax Assets and Valuation Allowances: The step-up in tax basis fromWe evaluate our equity method investments for other-than-temporary impairment. When an other-than-temporary impairment is recognized, the merger transactions that occurred in November 2014 resulted in a deferred tax asset, primarily related to our investment in KMP. As book earnings from our investment in KMP are projected to exceed taxable income (primarilyloss is recorded as a resultreduction in equity earnings.

Goodwill

Goodwill is the cost of the partnership’s tax depreciationan acquisition of a business in excess of book depreciation), the deferred taxfair value of acquired assets and liabilities and is recorded as an asset relatedon our balance sheet. Goodwill is not subject to our investmentamortization but must be tested for impairment at least annually and in KMPinterim periods if indicators of impairment exist. This test requires us to assign goodwill to an appropriate reporting unit and compare the fair value of a reporting unit to its carrying value. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value an impairment is expectedmeasured and recorded at the amount by which the reporting unit’s carrying value exceeds its fair value.

We evaluate goodwill for impairment on May 31 of each year, or more frequently to be fully realized.


We decreased our valuation allowances in 2017 by $13 million, primarily due to $4 million release for capital loss carryover asthe extent events occur or conditions change between annual tests that would indicate a resultrisk of possible impairment at the 2016 return to provision adjustment, $5 million release for foreign operating losses and $24 million reduction related to our investment in NGPL as a result of the reduction of federal tax rate, partially offset by $18 million for state net operating losses and $2 million for foreign tax credits.

We have deferred tax assets of $935 million related to net operating loss carryovers, $178 million related to general business, alternative minimum and foreign tax credits and $133 million of valuation allowances related to these deferred tax assets at December 31, 2017. As of December 31, 2016, we had deferred tax assets of $1,128 million related to net operating loss carryovers, $175 million related to alternative minimum and foreign tax credits, $4 million related to capital loss carryovers and valuation allowances related to these deferred tax assets of $123 million. We expect to generate taxable income and utilize federal net operating loss carryforwards and tax credits beginning in 2022.

Our alternative minimum tax credit carryforwards decreased by $143 million in 2017 as a resultinterim period.  For purposes of our decisionMay 31, 2023 evaluation, we grouped our businesses into seven reporting units as follows: (i) Natural Gas Pipelines Regulated; (ii) Natural Gas Pipelines Non-Regulated; (iii) CO2; (iv) Products Pipelines (excluding associated terminals); (v) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (vi) Terminals; and (vii) Energy Transition Ventures. Generally, the evaluation of goodwill for impairment involves a quantitative test, although under certain circumstances an initial qualitative evaluation may be sufficient to elect to forgo bonus depreciation on property placed in service inconclude that year. Code Section 168(k)(4) allowsgoodwill is not impaired without conducting the quantitative test.

A large portion of our goodwill is non-deductible for corporate taxpayers with minimum tax credit carryforwards to forgo bonus depreciation and accelerate their use of the credits to reduce tax liability in that same tax year if the amount of the allowable credit exceeds the taxpayer’s tax liability. The corporation may receive a cash refund of the excess notwithstanding that it may not otherwise be paying taxes. We received an income tax refund of $144 million in 2017.

The tax impact of ASU 2016-09, which was adopted and effective January 1, 2017, resulted in $8 million of deferred tax assets being recorded through a cumulative-effect adjustment to our retained deficit. The previously unrecorded deferred tax asset is related to net operating loss carryovers as a result of the delayed recognition of a windfall tax benefit related to share-based compensation. Post-adoption the excess tax benefits or deficiencies are recognized for income tax purposes, inand as such, to the period in which they occur through the income statement.

Expiration Periods for Deferred Tax Assets:As of December 31, 2017, we have U.S. federal net operating loss carryforwards of $3.4 billion, which will expire from 2018 - 2037; state losses of $3.2 billion which will expire from 2018 - 2037; and foreign losses of $134 million which will expire from 2029 - 2036. We also have $8 million of federal alternative minimum tax credits which do not expire; $147 million of general business credits which will expire from 2018 - 2027; and approximately $21 million of foreign tax credits, which will expire from 2018 - 2023. Use ofextent there are impairments, all or a portion of the impairment may not result in a corresponding tax benefit.

Refer to Note 8 for further information.

Other Intangibles

Excluding goodwill, our U.S. federal carryforwardsother intangible assets include customer contracts and other relationships and agreements.

Our intangible assets primarily relate to customer contracts or other relationships for the handling and storage of petroleum, chemical, and dry-bulk materials, including oil, gasoline, and other refined petroleum products, petroleum coke, metals and
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ores, the gathering of natural gas and the production and supply of RNG. We determined the values of these intangible assets by first, estimating the revenues derived from a customer contract or relationship (offset by the cost and expenses of supporting assets to fulfill the contract), and second, discounting the revenues at a risk adjusted discount rate.

We amortize the costs of our intangible assets to expense in a systematic and rational manner over their estimated useful lives. The life of each intangible asset is subject tobased either on the limitations provided under Sections 382 and 383life of the Internal Revenue Code as well ascorresponding customer contract or agreement or, in the separate return limitation rulescase of Internal Revenue Service regulations. If certain substantial changesa customer relationship intangible (the life of which was determined by an analysis of all available data on that business relationship), the length of time used in our ownership occur, there would be an annual limitationthe discounted cash flow analysis to determine the value of the customer relationship. Among the factors we weigh, depending on the amount of carryforwards that could be utilized.

Unrecognized Tax Benefits: We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based not only on the technical meritsnature of the tax position based on tax law, but alsoasset, are the past administrative practiceseffects of obsolescence, new technology, and precedents of the taxing authority.  competition.

The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate resolution.

A reconciliation offollowing tables summarize our gross unrecognized tax benefit excluding interest and penalties is as follows (in millions): 
 Year Ended December 31,
 2017 2016 2015
Balance at beginning of period$122
 $148
 $189
Additions based on current year tax positions3
 3
 4
Additions based on prior year tax positions—
 7
 —
Reductions based on prior year tax positions—
 (1) (6)
Reductions based on settlements with taxing authority(22) (26) (25)
Reductions due to lapse in statute of limitations(2) (9) (14)
Impact of the 2017 Tax Reform(4) —
 —
Balance at end of period$97
 $122
 $148

We recognize interest and/or penalties related to income tax matters in income tax expense. We recognized a tax benefit of $9 million, expense of $2 million and a benefit of $4 million at December 31, 2017, 2016, and 2015, respectively. As of December 31, 2017, 2016, and 2015, we had $19 million, $28 million and $24 million, respectively, of accrued interest. We

had no accrued penalties as of both December 31, 2017 and 2016 and $2 million in accrued penaltiesother intangible assets as of December 31, 2015.  All2023 and 2022 and our amortization expense for the years ended December 31, 2023, 2022 and 2021: 
Weighted Average Amortization PeriodDecember 31,
20232022
(Years)(In millions)
Gross11.3$3,543 $3,382 
Accumulated amortization(1,586)(1,573)
Net carrying amount$1,957 $1,809 
December 31,
202320222021
(In millions)
Amortization expense$202 $253 $237 

Our estimated amortization expense for our intangible assets for each of the $97 millionnext five fiscal years is:
20242025202620272028
(In millions)
Estimated amortization expenses$198 $193 $191 $191 $190 

Revenue Recognition

The majority of unrecognized tax benefits, if recognized, would affect our effective tax rate in future periods.  In addition, we believe it is reasonably possible that our liabilityrevenues are accounted for unrecognized tax benefits will decrease by approximately $6 million during the next yearunder Topic 606, Revenue from Contracts with Customers; however, to approximately $91 million, primarily due to lapses in statute of limitations partially offset by additionsa limited extent, some revenues are accounted for state filing positions taken in prior years.under other guidance such as Topic 842, Leases or Topic 815, Derivatives and Hedging Activities.

Revenue from Contracts with Customers

We are subjectreview our contracts with customers using the following steps to taxation,recognize revenue based on the transfer of goods or services to customers and have tax years openin amounts that reflect the consideration the company expects to examinationreceive for those goods or services. The steps include: (i) identify the contract; (ii) identify the performance obligations of the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and then (v) recognize revenue when (or as) the performance obligation is satisfied. Each of these steps involves management judgment and an analysis of the contract’s material terms and conditions.

Our customer sales contracts primarily include sales of natural gas, NGL, crude oil, CO2 and transmix, as described below. Generally, for the periods 2011-2016 in the U.S., 2005-2016 in various states and 2007-2016 in various foreign jurisdictions.

Impactmajority of 2017 Tax Reform

On December 22, 2017, the U.S. enacted the 2017 Tax Reform. Among the many provisions included in the 2017 Tax Reformthese contracts (i) each unit (Bcf, gallon, barrel, etc.) of commodity is a provisionseparate performance obligation, as our promise is to reducesell multiple distinct units of commodity at a point in time; (ii) the U.S. federal corporate income tax rate from 35%transaction price principally consists of variable consideration, which amount is determinable each month end based on our right to 21% effective January 1, 2018.

As of December 31, 2017, we had deferred tax assets related to our net operating loss carryforwards and tax credits, in addition to tax basis in excess of accounting basis primarily related to our investment in KMP. Prior to the 2017 Tax Reform,invoice at month end for the value of commodity sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity’s standalone selling price and recognized as revenue upon delivery of the commodity, which is the point in time when the customer obtains control of the commodity and our performance obligation is satisfied.

Our customer services contracts are primarily for transportation service, storage service, gathering and processing service, and terminaling, as described below. Generally, for the majority of these deferred tax assets was recordedcontracts (i) our promise is to transfer (or stand ready
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to transfer) a series of distinct integrated services over a period of time, which is a single performance obligation; (ii) the transaction price includes fixed and/or variable consideration, which amount is determinable at contract inception and/or at each month end based on our right to invoice at month end for the value of services provided to the customer that month; and (iii) the transaction price is recognized as revenue over the service period specified in the contract (which can be a day, including each day in a series of promised daily services, a month, a year, or other time increment, including a deficiency makeup period) as the services are rendered using a time-based (passage of time) or units-based (units of service transferred) output method for measuring the transfer of control of the services and satisfaction of our performance obligation over the service period, based on the nature of the promised service (e.g., firm or non-firm) and the terms and conditions of the contract (e.g., contracts with or without makeup rights).

Firm Services

Firm services (also called uninterruptible services) are services that are promised to be available to the customer at all times during the period(s) covered by the contract, with limited exceptions. Our firm service contracts are typically structured with take-or-pay or minimum volume provisions, which specify minimum service quantities a customer will pay for even if it chooses not to receive or use them in the specified service period (referred to as “deficiency quantities”). We typically recognize the portion of the transaction price associated with such provisions, including any deficiency quantities, as revenue depending on whether the contract prohibits the customer from making up deficiency quantities in subsequent periods, or the contract permits this practice, as follows:

•Contracts without Makeup Rights. If contractually the customer cannot make up deficiency quantities in future periods, our performance obligation is satisfied, and revenue associated with any deficiency quantities is generally recognized as each service period expires. Because a service period may exceed a reporting period, we determine at inception of the contract and at the previous income tax ratebeginning of 35%each subsequent reporting period if we expect the customer to take the minimum volume associated with the service period. If we expect the customer to make up all deficiencies in the specified service period (i.e., which represented their expectedwe expect the customer to take the minimum service quantities), the minimum volume provision is deemed not substantive and we will recognize the transaction price as revenue in the specified service period as the promised units of service are transferred to the customer. Alternatively, if we expect that there will be any deficiency quantities that the customer cannot or will not make up in the specified service period (referred to as “breakage”), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over such service period in proportion to the revenue that we will recognize for actual units of service transferred to the customer in the service period. For certain take-or-pay contracts where we make the service, or a part of the service (e.g., reservation) continuously available over the service period, we typically recognize the take-or-pay amount as revenue ratably over such period based on the passage of time.

•Contracts with Makeup Rights. If contractually the customer can acquire the promised service in a future benefitperiod and make up the deficiency quantities in such future period (the “deficiency makeup period”), we have a performance obligation to us. Asdeliver those services at the customer’s request (subject to contractual and/or capacity constraints) in the deficiency makeup period. At inception of the contract, and at the beginning of each subsequent reporting period, we estimate if we expect that there will be deficiency quantities that the customer will or will not make up. If we expect the customer will make up all deficiencies it is contractually entitled to, any non-refundable consideration received relating to temporary deficiencies that will be made up in the deficiency makeup period will be deferred as a contract liability, and we will recognize that amount as revenue in the deficiency makeup period when either of the following occurs: (i) the customer makes up the volumes or (ii) the likelihood that the customer will exercise its right for deficiency volumes then becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires). Alternatively, if we expect at inception of the contract, or at the beginning of any subsequent reporting period, that there will be any deficiency quantities that the customer cannot or will not make up (i.e., breakage), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over the specified service periods in proportion to the revenue that we will recognize for actual units of service transferred to the customer in those service periods.

Non-Firm Services

Non-firm services (also called interruptible services) are the opposite of firm services in that such services are provided to a customer on an “as available” basis. Generally, we do not have an obligation to perform these services until we accept a customer’s periodic request for service. For the majority of our non-firm service contracts, the customer will pay only for the actual quantities of services it chooses to receive or use, and we typically recognize the transaction price as revenue as those units of service are transferred to the customer in the specified service period (typically a daily or monthly period).

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Contract Balances

Contract assets and contract liabilities are the result of timing differences between revenue recognition, billings and cash collections. We recognize contract assets in those instances where billing occurs subsequent to revenue recognition, and our right to invoice the 2017 Tax Reform,customer is conditioned on something other than the passage of time. Our contract assets are substantially related to breakage revenue associated with our firm service contracts with minimum volume commitment payment obligations and contracts where we apply revenue levelization (i.e., contracts with fixed rates per volume that increase over the life of the contract for which we record revenue ratably per unit over the life of the contract based on our performance obligations that are generally unchanged over the life of the contract). Our contract liabilities are substantially related to (i) capital improvements paid for in advance by certain customers generally in our non-regulated businesses, which we subsequently recognize as revenue on a straight-line basis over the initial term of the related customer contracts; (ii) consideration received from customers for temporary deficiency quantities under minimum volume contracts that we expect will be made up in a future benefitperiod, which we subsequently recognize as revenue when the customer makes up the volumes or the likelihood that the customer will exercise its right for deficiency volumes becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires); and (iii) contracts with fixed rates per volume that decrease over the life of these deferred taxthe contract where we apply revenue levelization for amounts received for our future performance obligations. We reassess amounts recorded as contract assets was re-measured ator liabilities upon contract modification.

Refer to Note 15 for further information.

Costs of Sales

Costs of sales primarily includes the new income tax rate of 21%cost to purchase energy commodities sold, including natural gas, crude oil, NGL and we recorded an approximate $1,240 million provisional non-cash adjustmentother refined petroleum products, adjusted for the year ended December 31, 2017. We determined the effects of the rate change using our best estimate of temporary book-to-tax differences. Upon final analysis and remeasurementenergy commodity hedging activities, as applicable. Costs of our deferred tax balances, the December 31, 2017 adjustment we recorded to reflect the changecrude oil, gas and CO2 producing activities, such as those in corporate income tax rates may need to be adjusted in subsequent periods.our CO2 business segment, are not accounted for as costs of sales.


In addition, the 2017 Tax Reform will require a mandatory deemed repatriationOperations and Maintenance

Operations and maintenance includes costs of post-1986 undistributed foreign earningsservices and profits. Asis primarily comprised of December 31, 2017, we have recorded a provisional amount for this 2017 Tax Reform provision(i) operational labor costs and we are continuing to finalize earnings(ii) operations, maintenance and profits used in this calculation as well assess other 2017 Tax Reform impacts to completeasset integrity, regulatory and environmental costs. Costs associated with our analysis on this provision. However, we do not expect this provision of the 2017 Tax Reform to be material to us.

The income tax rate change in the 2017 Tax Reform had an impact not only on our corporate income taxes but also resulted in us recording an approximate $144crude oil, gas and CO2 producing activities included within operations and maintenance totaled $393 million, after-tax ($219$367 million pre-tax) provisional non-cash adjustment, including our share of equity investee provisional adjustments, related to our FERC regulated business for the year ended December 31, 2017.  We have determined a reasonable estimate of its impact and recorded a provisional regulatory reserve as of December 31, 2017. However, as the impact on the regulatory rate making process is currently uncertain, we have not completed our assessment of the 2017 Tax Reform’s effect on our FERC regulated business.

As described above, we continue to assess the impact of the 2017 Tax Reform on our business in order to complete our analysis. Any adjustment to our provisional amounts will be reported in the reporting period in which any such adjustments are determined and may be material in the period in which the adjustments are made.

6.  Property, Plant and Equipment, net
Classes and Depreciation
As of December 31, 2017 and 2016, our property, plant and equipment, net consisted of the following (in millions):
 December 31,
 2017 2016
Pipelines (Natural gas, liquids, crude oil and CO2)
$20,157
 $19,341
Equipment (Natural gas, liquids, crude oil, CO2, and terminals)
24,152
 23,298
Other(a)5,570
 4,780
Accumulated depreciation, depletion and amortization(14,175) (12,306)
 35,704
 35,113
Land and land rights-of-way1,456
 1,431
Construction work in process2,995
 2,161
Property, plant and equipment, net$40,155
 $38,705

_______
(a) Includes general plant, general structures and buildings, computer and communication equipment, intangibles, vessels, transmix products, linefill and miscellaneous property, plant and equipment.

As of December 31, 2017 and 2016, property, plant and equipment, net included $14,055 million and $12,900 million, respectively, of assets which were regulated by either the FERC or the NEB. Depreciation, depletion, and amortization expense charged against property, plant and equipment was $2,022 million, $1,970 million, and $2,059$180 million for the years ended December 31, 2017, 2016,2023, 2022 and 2015,2021, respectively.


Environmental Matters

We capitalize certain environmental expenditures required to obtain rights-of-way, regulatory approvals or permitting as part of the construction of facilities we use in our business operations. We accrue and expense environmental costs that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We generally do not discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs, such as after the completion of a feasibility study or commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We record at estimated fair value, where appropriate, environmental liabilities assumed in a business combination.

We routinely conduct reviews of potential environmental issues and claims that assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. We also routinely adjust our environmental liabilities to reflect changes in previous estimates. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us, and potential third-party liability claims we may have against others. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs.

Leases

We lease property including corporate and field offices and facilities, vehicles, heavy work equipment including rail cars and large trucks, tanks, office equipment and land. Our leases have remaining lease terms of one to 47 years, some of which have options to extend or terminate the lease. We determine if an arrangement is a lease at inception or upon modification. For purposes of calculating operating lease liabilities, lease terms may be deemed to include options to extend or terminate the lease when it is reasonably certain that we will exercise that option.
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Our operating ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Leases with variable rate adjustments, such as Consumer Price Index (CPI) adjustments, are reflected based on contractual lease payments as outlined within the lease agreement and not adjusted for any CPI increases or decreases. Because most of our leases do not provide an explicit rate of return, we use our incremental secured borrowing rate based on lease term information available at the commencement date of the lease in determining the present value of lease payments. We have real estate lease agreements with lease and non-lease components, which are accounted for separately. For certain equipment leases, such as copiers and vehicles, we account for the leases under a portfolio method. Leases that were grandfathered under various portions of Topic 842, such as land easements, are reassessed when the agreements are modified.

Refer to Note 17 for further information.

Share-based Compensation
We recognize compensation expense ratably over the vesting period of the restricted stock award based on the grant-date fair value, which is determined based on the market price of our Class P common stock on the grant date, less estimated forfeitures. Forfeiture rates are estimated based on historical forfeitures under our restricted stock award plans. Upon vesting, the restricted stock award will be paid in shares of our Class P common stock.
Pensions and Other Postretirement Benefits

We recognize the differences between the fair value of each of our and our consolidated subsidiaries’ pension and other postretirement benefit plans’ assets and the benefit obligations as either assets or liabilities on our consolidated balance sheets. We record deferred plan costs and income—unrecognized losses and gains, unrecognized prior service costs and credits, and any remaining unamortized transition obligations—net of income taxes in “Accumulated other comprehensive loss,” with the proportionate share associated with less than wholly owned consolidated subsidiaries allocated and included within “Noncontrolling interests,” or as a regulatory asset or liability for certain of our regulated operations, until they are amortized as a component of benefit expense.

Deferred Financing Costs

We capitalize financing costs incurred with new borrowings and amortize the costs over the contractual term of the related obligations.

Redeemable Noncontrolling Interest

Through December 14, 2021, we had a redeemable noncontrolling interest which represented the interest in one of our consolidated subsidiaries, not owned by us, and which in certain limited circumstances, the partner had the right to relinquish its interest in the subsidiary. Distributions paid to the partner prior to that date were recorded as a reduction to the redeemable noncontrolling interest balance and included in “Distributions to investment partner” in our accompanying consolidated statement of cash flows. On December 14, 2021, the ownership agreement was modified such that the noncontrolling interest was no longer contingently redeemable, and the balance was reclassified to “Noncontrolling Interests.” Net income attributable to redeemable noncontrolling interest was $58 million for the year ended December 31, 2021 and is included in “Net Income Attributable to Noncontrolling Interests” in our accompanying consolidated statement of income.

Noncontrolling Interests

Noncontrolling interests represents the interests in our consolidated subsidiaries that are not owned by us.  In our accompanying consolidated statements of income, the noncontrolling interest in the net income of our less than wholly owned consolidated subsidiaries is shown as an allocation of our consolidated net income and is presented separately as “Net Income Attributable to Noncontrolling Interests.”  In our accompanying consolidated balance sheets, noncontrolling interests is presented separately as “Noncontrolling interests” within “Stockholders’ Equity.”

Income Taxes

Income tax expense is recorded based on an estimate of the effective tax rate in effect or to be in effect during the relevant periods. Changes in tax legislation are included in the relevant computations in the period in which such changes are enacted. We do business in a number of states with differing laws concerning how income subject to each state’s tax structure is measured and at what effective rate such income is taxed. Therefore, we must make estimates of how our income will be
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apportioned among the various states in order to arrive at an overall effective tax rate. Changes in our effective tax rate, including any effect on previously recorded deferred taxes, are recorded in the period in which the need for such change is identified.

Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Deferred tax assets are reduced by a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. While we have considered estimated future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance, any change in the amount that we expect to ultimately realize will be included in income in the period in which such a determination is reached. Income tax effects are released from accumulated other comprehensive loss to retained earnings, when applicable, on an individual item basis as those items are reclassified into income.

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

Asset Retirement Obligations

AsWe record liabilities for obligations related to the retirement and removal of December 31, 2017 and 2016, we recognized asset retirement obligationslong-lived assets used in the aggregate amount of $208 million and $193 million, respectively, of which $4 million and $9 million, respectively, were classified as current.our businesses. The majority of our asset retirement obligations are associated with our CO2 business segment, where we are required to plug and abandon oil and gas wells that have been removed from service and to remove the surface wellhead equipment and compressors.compressors, but we also have obligations for certain gathering and long-haul pipelines and certain processing plants. We record, as liabilities, the fair value of asset retirement obligations on a discounted basis when they are incurred and can be reasonably estimated, which is typically at the time the assets are installed or acquired. The fair value estimates are primarily based on Level 3 inputs of the fair value hierarchy. The inputs include estimates and assumptions related to timing of settlement and retirement costs, which we base on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities are accreted to reflect the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service. Our estimates of retirement costs could change as a result of changes in cost estimates and/or timing of the obligation.

The following table summarizes changes in the asset retirement obligations included in our accompanying consolidated balance sheets:
December 31,
20232022
(In millions)
Balance at beginning of period$204 $196 
Accretion expense12 12 
New obligations22 2 
Settlements(7)(6)
Balance at end of period(a)$231 $204 
(a)Balances at both December 31, 2023 and 2022 include $3 million included within “Other current liabilities” on our accompanying consolidated balance sheets.

For certain assets, we currently cannot reasonably estimate the fair value of the asset retirement obligations because the associated assets have indeterminate lives. These assets include certain pipelines, processing plants and distribution facilities, and liquids and bulk terminal facilities. Based on the widespread use of hydrocarbons domestically and for international export, management expects supply and demand to exist for the foreseeable future. Therefore, the remaining useful lives of these assets are indeterminate due to prolonged expected demand. Additionally, these assets could also benefit from potential future conversion opportunities. For example, certain assets could be converted to transport, handle or store products other than traditional hydrocarbons. Under our integrity program, individual asset parts are replaced regularly. Although some of the individual asset parts may be replaced, the assets themselves may remain intact indefinitely. For these assets, an asset retirement obligation, if any, will be recognized once sufficient information is available to reasonably estimate the fair value of the obligation.

Long-lived Asset Impairments

We evaluate long-lived assets including leases and investments for impairment whenever events or changes in circumstances indicate that our carrying amount of an asset or investment may not be recoverable.

In addition to our annual goodwill impairment test discussed further below, to the extent triggering events exist, we complete a review of the carrying value of our long-lived assets, including property, plant and equipment as well as other intangibles, and record, as applicable, the appropriate impairments using a two-step approach. To determine if a long-lived asset is recoverable, we compare the asset’s estimated undiscounted cash flows to its carrying value (step 1). Because the impairment test for long-lived assets held in use is based on estimated undiscounted cash flows, there may be instances where
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an asset or asset group is not considered impaired, even when its fair value may be less than its carrying value, because the asset or asset group is recoverable based on the cash flows to be generated over the estimated life of the asset or asset group. If the carrying value of a long-lived asset or asset group is in excess of estimated undiscounted cash flows, we typically use discounted cash flow analyses to calculate the fair value of the long-lived asset to determine if an impairment is required and the amount of the impairment losses to be recognized (step 2).

We evaluate our oil and gas producing properties for impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure, using undiscounted future cash flows based on estimated future oil and gas production volumes.

Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future cash flows based on estimated future oil and gas production volumes.  Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment.

Refer to Note 4 for further information.

Equity Method of Accounting and Basis Differences

We use the equity method of accounting for investments which we do not control, but for which we have the ability to exercise significant influence. The carrying values of these investments are impacted by our share of investee income or loss, distributions, amortization or accretion of basis differences and other-than-temporary impairments.

The difference between the carrying value of an investment and our share of the investment’s underlying equity in net assets is referred to as a basis difference. If the basis difference is assigned to depreciable or amortizable assets and liabilities, the basis difference is amortized or accreted as part of our share of investee earnings. To the extent that the basis difference relates to goodwill, referred to as equity method goodwill, the amount is not amortized.

We evaluate our equity method investments for other-than-temporary impairment. When an other-than-temporary impairment is recognized, the loss is recorded as a reduction in equity earnings.

Goodwill

Goodwill is the cost of an acquisition of a business in excess of the fair value of acquired assets and liabilities and is recorded as an asset on our balance sheet. Goodwill is not subject to amortization but must be tested for impairment at least annually and in interim periods if indicators of impairment exist. This test requires us to assign goodwill to an appropriate reporting unit and compare the fair value of a reporting unit to its carrying value. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value an impairment is measured and recorded at the amount by which the reporting unit’s carrying value exceeds its fair value.

We evaluate goodwill for impairment on May 31 of each year, or more frequently to the extent events occur or conditions change between annual tests that would indicate a risk of possible impairment at the interim period.  For purposes of our May 31, 2023 evaluation, we grouped our businesses into seven reporting units as follows: (i) Natural Gas Pipelines Regulated; (ii) Natural Gas Pipelines Non-Regulated; (iii) CO2; (iv) Products Pipelines (excluding associated terminals); (v) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (vi) Terminals; and (vii) Energy Transition Ventures. Generally, the evaluation of goodwill for impairment involves a quantitative test, although under certain circumstances an initial qualitative evaluation may be sufficient to conclude that goodwill is not impaired without conducting the quantitative test.

A large portion of our goodwill is non-deductible for tax purposes, and as such, to the extent there are impairments, all or a portion of the impairment may not result in a corresponding tax benefit.

Refer to Note 8 for further information.

Other Intangibles

Excluding goodwill, our other intangible assets include customer contracts and other relationships and agreements.

Our intangible assets primarily relate to customer contracts or other relationships for the handling and storage of petroleum, chemical, and dry-bulk materials, including oil, gasoline, and other refined petroleum products, petroleum coke, metals and
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ores, the gathering of natural gas and the production and supply of RNG. We determined the values of these intangible assets by first, estimating the revenues derived from a customer contract or relationship (offset by the cost and expenses of supporting assets to fulfill the contract), and second, discounting the revenues at a risk adjusted discount rate.

We amortize the costs of our intangible assets to expense in a systematic and rational manner over their estimated useful lives. The life of each intangible asset is based either on the life of the corresponding customer contract or agreement or, in the case of a customer relationship intangible (the life of which was determined by an analysis of all available data on that business relationship), the length of time used in the discounted cash flow analysis to determine the value of the customer relationship. Among the factors we weigh, depending on the nature of the asset, are the effects of obsolescence, new technology, and competition.

The following tables summarize our other intangible assets as of December 31, 2023 and 2022 and our amortization expense for the years ended December 31, 2023, 2022 and 2021: 
Weighted Average Amortization PeriodDecember 31,
20232022
(Years)(In millions)
Gross11.3$3,543 $3,382 
Accumulated amortization(1,586)(1,573)
Net carrying amount$1,957 $1,809 
December 31,
202320222021
(In millions)
Amortization expense$202 $253 $237 

Our estimated amortization expense for our intangible assets for each of the next five fiscal years is:
20242025202620272028
(In millions)
Estimated amortization expenses$198 $193 $191 $191 $190 

Revenue Recognition

The majority of our revenues are accounted for under Topic 606, Revenue from Contracts with Customers; however, to a limited extent, some revenues are accounted for under other guidance such as Topic 842, Leases or Topic 815, Derivatives and Hedging Activities.

Revenue from Contracts with Customers

We review our contracts with customers using the following steps to recognize revenue based on the transfer of goods or services to customers and in amounts that reflect the consideration the company expects to receive for those goods or services. The steps include: (i) identify the contract; (ii) identify the performance obligations of the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and then (v) recognize revenue when (or as) the performance obligation is satisfied. Each of these steps involves management judgment and an analysis of the contract’s material terms and conditions.

Our customer sales contracts primarily include sales of natural gas, NGL, crude oil, CO2 and transmix, as described below. Generally, for the majority of these contracts (i) each unit (Bcf, gallon, barrel, etc.) of commodity is a separate performance obligation, as our promise is to sell multiple distinct units of commodity at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on our right to invoice at month end for the value of commodity sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity’s standalone selling price and recognized as revenue upon delivery of the commodity, which is the point in time when the customer obtains control of the commodity and our performance obligation is satisfied.

Our customer services contracts are primarily for transportation service, storage service, gathering and processing service, and terminaling, as described below. Generally, for the majority of these contracts (i) our promise is to transfer (or stand ready
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to transfer) a series of distinct integrated services over a period of time, which is a single performance obligation; (ii) the transaction price includes fixed and/or variable consideration, which amount is determinable at contract inception and/or at each month end based on our right to invoice at month end for the value of services provided to the customer that month; and (iii) the transaction price is recognized as revenue over the service period specified in the contract (which can be a day, including each day in a series of promised daily services, a month, a year, or other time increment, including a deficiency makeup period) as the services are rendered using a time-based (passage of time) or units-based (units of service transferred) output method for measuring the transfer of control of the services and satisfaction of our performance obligation over the service period, based on the nature of the promised service (e.g., firm or non-firm) and the terms and conditions of the contract (e.g., contracts with or without makeup rights).

Firm Services

Firm services (also called uninterruptible services) are services that are promised to be available to the customer at all times during the period(s) covered by the contract, with limited exceptions. Our firm service contracts are typically structured with take-or-pay or minimum volume provisions, which specify minimum service quantities a customer will pay for even if it chooses not to receive or use them in the specified service period (referred to as “deficiency quantities”). We typically recognize the portion of the transaction price associated with such provisions, including any deficiency quantities, as revenue depending on whether the contract prohibits the customer from making up deficiency quantities in subsequent periods, or the contract permits this practice, as follows:

•Contracts without Makeup Rights. If contractually the customer cannot make up deficiency quantities in future periods, our performance obligation is satisfied, and revenue associated with any deficiency quantities is generally recognized as each service period expires. Because a service period may exceed a reporting period, we determine at inception of the contract and at the beginning of each subsequent reporting period if we expect the customer to take the minimum volume associated with the service period. If we expect the customer to make up all deficiencies in the specified service period (i.e., we expect the customer to take the minimum service quantities), the minimum volume provision is deemed not substantive and we will recognize the transaction price as revenue in the specified service period as the promised units of service are transferred to the customer. Alternatively, if we expect that there will be any deficiency quantities that the customer cannot or will not make up in the specified service period (referred to as “breakage”), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over such service period in proportion to the revenue that we will recognize for actual units of service transferred to the customer in the service period. For certain take-or-pay contracts where we make the service, or a part of the service (e.g., reservation) continuously available over the service period, we typically recognize the take-or-pay amount as revenue ratably over such period based on the passage of time.

•Contracts with Makeup Rights. If contractually the customer can acquire the promised service in a future period and make up the deficiency quantities in such future period (the “deficiency makeup period”), we have a performance obligation to deliver those services at the customer’s request (subject to contractual and/or capacity constraints) in the deficiency makeup period. At inception of the contract, and at the beginning of each subsequent reporting period, we estimate if we expect that there will be deficiency quantities that the customer will or will not make up. If we expect the customer will make up all deficiencies it is contractually entitled to, any non-refundable consideration received relating to temporary deficiencies that will be made up in the deficiency makeup period will be deferred as a contract liability, and we will recognize that amount as revenue in the deficiency makeup period when either of the following occurs: (i) the customer makes up the volumes or (ii) the likelihood that the customer will exercise its right for deficiency volumes then becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires). Alternatively, if we expect at inception of the contract, or at the beginning of any subsequent reporting period, that there will be any deficiency quantities that the customer cannot or will not make up (i.e., breakage), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over the specified service periods in proportion to the revenue that we will recognize for actual units of service transferred to the customer in those service periods.

Non-Firm Services

Non-firm services (also called interruptible services) are the opposite of firm services in that such services are provided to a customer on an “as available” basis. Generally, we do not have an obligation to perform these services until we accept a customer’s periodic request for service. For the majority of our non-firm service contracts, the customer will pay only for the actual quantities of services it chooses to receive or use, and we typically recognize the transaction price as revenue as those units of service are transferred to the customer in the specified service period (typically a daily or monthly period).

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Contract Balances

Contract assets and contract liabilities are the result of timing differences between revenue recognition, billings and cash collections. We recognize contract assets in those instances where billing occurs subsequent to revenue recognition, and our right to invoice the customer is conditioned on something other than the passage of time. Our contract assets are substantially related to breakage revenue associated with our firm service contracts with minimum volume commitment payment obligations and contracts where we apply revenue levelization (i.e., contracts with fixed rates per volume that increase over the life of the contract for which we record revenue ratably per unit over the life of the contract based on our performance obligations that are generally unchanged over the life of the contract). Our contract liabilities are substantially related to (i) capital improvements paid for in advance by certain customers generally in our non-regulated businesses, which we subsequently recognize as revenue on a straight-line basis over the initial term of the related customer contracts; (ii) consideration received from customers for temporary deficiency quantities under minimum volume contracts that we expect will be made up in a future period, which we subsequently recognize as revenue when the customer makes up the volumes or the likelihood that the customer will exercise its right for deficiency volumes becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires); and (iii) contracts with fixed rates per volume that decrease over the life of the contract where we apply revenue levelization for amounts received for our future performance obligations. We reassess amounts recorded as contract assets or liabilities upon contract modification.

Refer to Note 15 for further information.

Costs of Sales

Costs of sales primarily includes the cost to purchase energy commodities sold, including natural gas, crude oil, NGL and other refined petroleum products, adjusted for the effects of our energy commodity hedging activities, as applicable. Costs of our crude oil, gas and CO2 producing activities, such as those in our CO2 business segment, are not accounted for as costs of sales.

Operations and Maintenance

Operations and maintenance includes costs of services and is primarily comprised of (i) operational labor costs and (ii) operations, maintenance and asset integrity, regulatory and environmental costs. Costs associated with our crude oil, gas and CO2 producing activities included within operations and maintenance totaled $393 million, $367 million and $180 million for the years ended December 31, 2023, 2022 and 2021, respectively.

Environmental Matters

We capitalize certain environmental expenditures required to obtain rights-of-way, regulatory approvals or permitting as part of the construction of facilities we use in our business operations. We accrue and expense environmental costs that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We generally do not discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs, such as after the completion of a feasibility study or commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We record at estimated fair value, where appropriate, environmental liabilities assumed in a business combination.

We routinely conduct reviews of potential environmental issues and claims that assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. We also routinely adjust our environmental liabilities to reflect changes in previous estimates. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us, and potential third-party liability claims we may have against others. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs.

Leases

We lease property including corporate and field offices and facilities, vehicles, heavy work equipment including rail cars and large trucks, tanks, office equipment and land. Our leases have remaining lease terms of one to 47 years, some of which have options to extend or terminate the lease. We determine if an arrangement is a lease at inception or upon modification. For purposes of calculating operating lease liabilities, lease terms may be deemed to include options to extend or terminate the lease when it is reasonably certain that we will exercise that option.
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Our operating ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Leases with variable rate adjustments, such as Consumer Price Index (CPI) adjustments, are reflected based on contractual lease payments as outlined within the lease agreement and not adjusted for any CPI increases or decreases. Because most of our leases do not provide an explicit rate of return, we use our incremental secured borrowing rate based on lease term information available at the commencement date of the lease in determining the present value of lease payments. We have real estate lease agreements with lease and non-lease components, which are accounted for separately. For certain equipment leases, such as copiers and vehicles, we account for the leases under a portfolio method. Leases that were grandfathered under various portions of Topic 842, such as land easements, are reassessed when the agreements are modified.

Refer to Note 17 for further information.

Share-based Compensation
 
We recognize compensation expense ratably over the vesting period of the restricted stock award based on the grant-date fair value, which is determined based on the market price of our Class P common stock on the grant date, less estimated forfeitures. Forfeiture rates are estimated based on historical forfeitures under our restricted stock award plans. Upon vesting, the restricted stock award will be paid in shares of our Class P common stock.
Pensions and Other Postretirement Benefits

We recognize the differences between the fair value of each of our and our consolidated subsidiaries’ pension and other postretirement benefit plans’ assets and the benefit obligations as either assets or liabilities on our consolidated balance sheets. We record deferred plan costs and income—unrecognized losses and gains, unrecognized prior service costs and credits, and any remaining unamortized transition obligations—net of income taxes in “Accumulated other comprehensive loss,” with the proportionate share associated with less than wholly owned consolidated subsidiaries allocated and included within “Noncontrolling interests,” or as a regulatory asset or liability for certain of our regulated operations, until they are amortized as a component of benefit expense.

Deferred Financing Costs

We capitalize financing costs incurred with new borrowings and amortize the costs over the contractual term of the related obligations.

Redeemable Noncontrolling Interest

Through December 14, 2021, we had a redeemable noncontrolling interest which represented the interest in one of our consolidated subsidiaries, not owned by us, and which in certain limited circumstances, the partner had the right to relinquish its interest in the subsidiary. Distributions paid to the partner prior to that date were recorded as a reduction to the redeemable noncontrolling interest balance and included in “Distributions to investment partner” in our accompanying consolidated statement of cash flows. On December 14, 2021, the ownership agreement was modified such that the noncontrolling interest was no longer contingently redeemable, and the balance was reclassified to “Noncontrolling Interests.” Net income attributable to redeemable noncontrolling interest was $58 million for the year ended December 31, 2021 and is included in “Net Income Attributable to Noncontrolling Interests” in our accompanying consolidated statement of income.

Noncontrolling Interests

Noncontrolling interests represents the interests in our consolidated subsidiaries that are not owned by us.  In our accompanying consolidated statements of income, the noncontrolling interest in the net income of our less than wholly owned consolidated subsidiaries is shown as an allocation of our consolidated net income and is presented separately as “Net Income Attributable to Noncontrolling Interests.”  In our accompanying consolidated balance sheets, noncontrolling interests is presented separately as “Noncontrolling interests” within “Stockholders’ Equity.”

Income Taxes

Income tax expense is recorded based on an estimate of the effective tax rate in effect or to be in effect during the relevant periods. Changes in tax legislation are included in the relevant computations in the period in which such changes are enacted. We do business in a number of states with differing laws concerning how income subject to each state’s tax structure is measured and at what effective rate such income is taxed. Therefore, we must make estimates of how our income will be
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apportioned among the various states in order to arrive at an overall effective tax rate. Changes in our effective tax rate, including any effect on previously recorded deferred taxes, are recorded in the period in which the need for such change is identified.

Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Deferred tax assets are reduced by a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. While we have considered estimated future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance, any change in the amount that we expect to ultimately realize will be included in income in the period in which such a determination is reached. Income tax effects are released from accumulated other comprehensive loss to retained earnings, when applicable, on an individual item basis as those items are reclassified into income.

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

Risk Management Activities

We utilize energy commodity derivative contracts for the purpose of mitigating our risk resulting from fluctuations in the market price of commodities including crude oil, natural gas, and NGL.  In addition, we enter into interest rate swap agreements for the purpose of managing our interest rate exposure associated with our debt obligations. We also enter into cross-currency swap agreements to manage our foreign currency risk associated with certain debt obligations. We measure our derivative contracts at fair value and we report them on our balance sheet as either an asset or liability. For certain physical forward commodity derivatives contracts, we apply the normal purchase/normal sale exception, whereby the revenues and expenses associated with such transactions are recognized during the period when the commodities are physically delivered or received.

For qualifying accounting hedges, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness. When we designate a derivative contract as a cash flow accounting hedge, the entire change in fair value of the derivative that is included in the assessment of hedge effectiveness is deferred in “Accumulated other comprehensive loss” and reclassified into earnings in the period in which the hedged item affects earnings. When we designate a derivative contract as a fair value accounting hedge, the change in fair value of the hedged item is recorded as an adjustment to the carrying value of the hedged item and recognized currently in earnings in the same line item that the change in fair value of the derivative is recognized currently in earnings. Therefore, any difference between the changes in fair values of the item being hedged and the derivative contract results in a gain or loss from the hedging relationship recognized currently in earnings.

For derivative instruments that are not designated as accounting hedges, or for which we have not elected the normal purchase/normal sales exception, changes in fair value are recognized currently in earnings.

Unrealized gains and losses associated with our derivative activities that affect income are reflected as “Change in fair market value of derivative contracts” within our accompanying consolidated statement of cash flows as a noncash add back to net income to arrive at cash flows from our derivative activities for the period. Net changes in our interest receivable and payable balances that represent accruals and periodic settlements of interest on our interest rate swaps are included within “Accrued interest, net of interest rate swaps” on our accompanying consolidated statement of cash flows.

Fair Value

The fair values of our financial instruments are separated into three broad levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. We assign each fair value measurement to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety. Recognized valuation techniques utilize inputs such as contractual prices, quoted market prices or rates, and discount factors.  These inputs may be either readily observable or corroborated by market data.

Regulatory Assets and Liabilities

Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or returned to customers through the ratemaking process. In instances where we receive recovery in tariff rates related to losses on dispositions of operating units, we record a regulatory asset for the estimated recoverable
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amount.  We include the amounts of our regulatory assets and liabilities within “Other current assets,” “Deferred charges and other assets,” “Other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance sheets.

The following table summarizes our regulatory asset and liability balances as of December 31, 2023 and 2022:
December 31,
20232022
(In millions)
Current regulatory assets$26 $73 
Non-current regulatory assets214 183 
Total regulatory assets(a)$240 $256 
Current regulatory liabilities$45 $50 
Non-current regulatory liabilities188 175 
Total regulatory liabilities(b)$233 $225 
(a)Regulatory assets as of December 31, 2023 include (i) $100 million of unamortized losses on disposal of assets; (ii) $43 million income tax gross up on equity AFUDC; and (iii) $97 million of other assets, including amounts related to fuel tracker arrangements. Approximately $138 million of the regulatory assets, with a weighted average remaining recovery period of 10 years, are recoverable without earning a return, including the income tax gross up on equity AFUDC for which there is an offsetting deferred income tax balance for FERC rate base purposes; therefore, it does not earn a return.
(b)Regulatory liabilities as of December 31, 2023 are comprised of customer prepayments to be credited to shippers or other over-collections that are expected to be returned to shippers or netted against under-collections over time. Approximately $104 million of the $188 million classified as non-current is expected to be credited to shippers over a remaining weighted average period of 13 years, while the remaining $84 million is not subject to a defined period.

Earnings per Share

We calculate earnings per share using the two-class method. Earnings were allocated to Class P common stock and participating securities 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. Our unvested restricted stock awards, which may be restricted stock or restricted stock units issued to employees and non-employee directors and include dividend equivalent payments, do not participate in excess distributions over earnings.

The following table sets forth the allocation of net income available to shareholders of Class P common stock and participating securities:
Year Ended December 31,
202320222021
(In millions, except per share amounts)
Net Income Available to Stockholders$2,391 $2,548 $1,784 
Participating securities:
   Less: Net Income Allocated to Restricted stock awards(a)(14)(13)(14)
Net Income Allocated to Common Stockholders$2,377 $2,535 $1,770 
Basic Weighted Average Shares Outstanding2,234 2,258 2,266 
Basic Earnings Per Share$1.06 $1.12 $0.78 
(a)As of December 31, 2023, there were approximately 13 million restricted stock awards outstanding.

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The following maximum number of potential common stock equivalents are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share. As we have no other common stock equivalents, our diluted earnings per share are the same as our basic earnings per share for all periods presented.
Year Ended December 31,
202320222021
(In millions on a weighted average basis)
Unvested restricted stock awards13 13 13 
Convertible trust preferred securities3 3 3 

3.Acquisitions and Divestitures

Business Combinations

For acquired businesses, we recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Determining the fair value of these items requires management’s judgment and the utilization of an independent valuation specialist, if applicable, and involves the use of significant estimates and assumptions.

Our allocation of the purchase price for acquisitions completed during the years ended December 31, 2023, 2022 and 2021 are detailed below:
Assignment of Purchase Price
RefAcquisitionPurchase priceCurrent assetsProperty, plant & equipmentOther long-term assetsCurrent liabilitiesLong-term liabilitiesNon-controlling interestResulting goodwill
(In millions)
(1)STX Midstream(a)$1,831 $41 $1,199 $552 $(11)$(2)$(104)$156 
(2)Diamond M13 — 25 — — (12)— — 
(3)North American Natural Resources132 2 5 64 — — — 61 
(4)Mas Ranger, LLC358 9 31 320 (2)— — — 
(5)Kinetrex Energy318 18 49 272 (6)(68)— 53 
(6)Stagecoach1,258 53 1,187 24 (6)— — — 
(a)The purchase price allocation for the STX Midstream Acquisition is preliminary.

(1) STX Midstream Pipeline System (STX Midstream) Acquisition

On December 28, 2023, we completed the acquisition of STX Midstream from NextEra Energy Partners for a purchase price of $1,831 million, including preliminary purchase price adjustments for working capital. Other long-term assets includes $357 million related to customer relationships with weighted average amortization period of 15 years and $192 million related to a 50% equity investment interest in Dos Caminos, LLC. The acquisition includes a 90% interest in NET Mexico Pipeline LLC. The goodwill consists primarily of synergies expected from the business combination and is tax deductible. The acquired assets are included in our Natural Gas business segment.

The determination of fair value utilized valuation methodologies including discounted cash flows for the customer relationships intangible assets and the equity method investment and the replacement cost approach for the property, plant and equipment. The significant assumptions made in performing these valuations include the discount rate utilized to value the customer relationships intangible assets and equity method investment and replacement costs used to value property, plant and equipment.

(2) Diamond M Acquisition

On June 1, 2023, we completed the acquisition of the Diamond M Field from Parallel Petroleum LLC for a purchase price of $13 million, including purchase price adjustments for working capital. The acquired assets, which are adjacent to our SACROC field, are included in our CO2 business segment.

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(3) North American Natural Resources Acquisition

On August 11, 2022, we completed the acquisition of seven landfill assets with the purchase of North American Natural Resources, Inc. and, its sister companies, North American Biofuels, LLC and North American-Central, LLC (NANR) consisting of GTE facilities in Michigan and Kentucky for $132 million, including purchase price adjustments for working capital. Other long-term assets within the purchase price allocation consists of intangibles related to gas rights and customer contracts with a weighted average amortization period of approximately 13 years. The goodwill associated with this acquisition is tax deductible. The acquired assets align with our strategy to invest in low-carbon energy and are included as part of our new Energy Transition Ventures group within our CO2 business segment. During November 2023, the seller exercised its option to repurchase one of the landfill assets for an insignificant amount.

(4) Mas Ranger Acquisition

On July 19, 2022, we completed an acquisition of three landfill assets with the purchase of Mas Ranger, LLC and its subsidiaries from Mas CanAm, LLC, comprising an RNG facility in Arlington, Texas and medium Btu facilities in Shreveport, Louisiana and Victoria, Texas for $358 million including purchase price adjustments for working capital. Other long-term assets within the purchase price allocation reflects an intangible related to a customer contract with an amortization period of approximately 17 years. The acquired assets align with our strategy to invest in low-carbon energy and are included as part of our new Energy Transition Ventures group within our CO2 business segment.

(5)Kinetrex Acquisition

On August 20, 2021, we completed the acquisition of Indianapolis-based Kinetrex Energy (Kinetrex) from an affiliate of Parallel49 Equity for $318 million, including purchase price adjustments for working capital. Other long-term assets within the purchase price allocation includes $63 million related to an equity investment and $199 million related to a customer relationship with an amortization period of approximately 10 years. Kinetrex was a supplier of LNG in the Midwest and a producer and supplier of RNG under long-term contracts to transportation service providers. At the acquisition date, Kinetrex had a 50% interest in the largest RNG facility in Indiana, and we commenced construction on three additional landfill-based RNG facilities in September 2021. The acquired assets align with our strategy to invest in low-carbon energy and are included as part of our new Energy Transition Ventures group within our CO2 business segment.

(6) Stagecoach Acquisition

On July 9, 2021 and November 24, 2021, we completed the acquisitions of Stagecoach and its subsidiaries, a natural gas pipeline and storage joint venture between Consolidated Edison, Inc. and Crestwood Equity Partners, LP, for approximately $1,258 million, including a purchase price adjustment for working capital. Other long-term assets within the purchase price allocation relates to customer contracts with a weighted average amortization period of less than two years. The determination of fair value utilized valuation methodologies including discounted cash flows and the cost approach. The significant assumptions made in performing these valuations include a discount rate of approximately 12%, future revenues and replacement costs. To compute estimated future cash flows for Stagecoach, transportation and storage revenue forecasts were developed based on projected demand and future rates for services in the Northeast market areas.

Pro Forma Information

Pro forma consolidated income statement information that gives effect to the above acquisitions as if they had occurred as of January 1 of each year preceding each transaction is not presented because it would not be materially different from the information presented in our accompanying consolidated statements of income.

Divestitures

Sale of Interest in ELC

On September 26, 2022, we completed the sale of a 25.5% ownership interest in ELC. We received net proceeds of $557 million which were used to reduce short-term borrowings. As we continue to have a controlling financial interest in ELC, we recorded an increase of $190 million to “Additional paid in capital” for the impact of the change in our ownership interest in ELC, which is reflected on our accompanying consolidated statement of stockholders’ equity for the year ended December 31, 2022. We continue to own a 25.5% interest in and operate ELC.

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We continue to consolidate ELC. We have determined that ELC is a variable interest entity and Southern Liquefaction Company, LLC (SLC), which is indirectly controlled by us, is the primary beneficiary because it has the ability to direct the activities that most significantly impact ELC’s economic performance and the right to receive benefits and the obligation to absorb losses. In addition to being the operator of ELC, the evaluation of ELC as a variable interest entity and SLC as the primary beneficiary included consideration of the following: (i) a liquefaction service agreement between ELC and its customer was designed for recovery by ELC of actual costs for operating and maintaining ELC’s facilities, which reduces the risk for all equity owners to absorb losses resulting from cost variability; and (ii) substantially all ELC’s activities involve KMI subsidiaries under common control that provide services for and benefit from the operations of ELC.

The following table shows the carrying amount and classification of ELC’s assets and liabilities in our consolidated balance sheets:
December 31,
20232022
(In millions)
Assets
Current assets$46 $34 
Property, plant and equipment, net1,162 1,197 
Deferred charges and other assets5 6 
Liabilities
Current liabilities$15 $15 
Other long-term liabilities and deferred credits25 5 

We receive distributions from ELC, indirectly, through our interest in SLC, but otherwise, the assets of ELC cannot be used to settle our obligations. ELC’s creditors have no recourse against our general credit and the obligations of ELC may only be settled using the assets of ELC. ELC does not guarantee our debt or other similar commitments.

Sale of an Interest in NGPL Holdings LLC

On March 8, 2021, we and Brookfield Infrastructure Partners L.P. (Brookfield) completed the sale of a combined 25% interest in our joint venture, NGPL Holdings LLC (NGPL Holdings), to a fund controlled by ArcLight Capital Partners, LLC (ArcLight). We received net proceeds of $412 million for our proportionate share of the interests sold, which included the transfer of $125 million of our $500 million related party promissory note receivable from NGPL Holdings to ArcLight with quarterly interest payments at 6.75%. We recognized a pre-tax gain of $206 million for our proportionate share, which is included within “Other, net” in our accompanying consolidated statement of income for the year ended December 31, 2021. After a subsequent transfer of third party interest, we and Arclight now each hold a 37.5% interest in NGPL Holdings.

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4.  Losses and Gains on Divestitures, Impairments and Other Write-downs

During the years ended December 31, 2023, 2022, and 2021, we recorded net pre-tax losses (gains) of $52 million, $(32) million and $1,535 million, respectively, reflecting net losses (gains) on divestitures, impairments and other write downs as detailed further below. The year ended December 31, 2021 amount primarily includes pre-tax long-lived asset impairments of $1,634 million.

We recognized the following non-cash pre-tax losses (gains) on divestitures, impairments or other write-downs on assets and equity investments during the years ended December 31, 2023, 2022, and 2021:
Year Ended December 31,
202320222021
(In millions)
Natural Gas Pipelines
Impairments of long-lived assets(a)$— $— $1,600 
Gain on sale of interest in NGPL Holdings(b)— — (206)
Loss on write-down of related party note receivable(c)— — 117 
Gains on divestitures of long-lived assets(10)(10)(1)
Products Pipelines
Impairment of equity investment(d)67 — — 
Gain on divestiture of long-lived asset— (12)— 
Terminals
Impairments of long-lived assets— — 34 
(Gains) losses on divestitures of long-lived assets(1)(9)2 
CO2
Gains on divestitures of long-lived assets(1)(1)(8)
Other gains on divestitures of long-lived assets(3)— (3)
Pre-tax losses (gains) on divestitures, impairments and other write-downs, net$52 $(32)$1,535 
(a)2021 amount represents non-cash impairments associated with our South Texas gathering and processing assets.
(b)See Note 3.
(c)See “—Investment in Ruby” below for a further discussion.
(d)See “—Investments” below for a further discussion.

Impairments

Investments

During the first quarter of 2023, we recognized an impairment of $67 million related to our investment in Double Eagle Pipeline LLC (Double Eagle). The impairment was driven by lower expected renewal rates on contracts that expired in the second half of 2023. The impairment is recognized on our accompanying consolidated statement of income for the year ended December 31, 2023 within “Earnings from equity investments.” Our investment in Double Eagle and associated earnings is included within our Products Pipelines business segment.

Long-lived Assets

During the second quarter of 2021, we evaluated our South Texas gathering and processing assets within our Natural Gas Pipeline business segment for impairment, which was driven by lower expectations regarding the volumes and rates associated with the re-contracting of contracts expiring through 2024. To compute the estimated undiscounted future cash flows we used the forecast of expected revenues adjusted for upcoming contract expirations. This analysis indicated that our South Texas gathering and processing assets failed step one. In step two, we utilized an income approach to estimate fair value and compared it to the carrying value. The significant assumptions made in calculating fair value include estimates of future cash flows and discount rates. We applied an approximate 8.5% discount rate, a Level 3 input, which we believed represented the estimated weighted average cost of capital of a theoretical market participant. As a result of our evaluation, we recognized a non-cash, long-lived asset impairment of $1,600 million during the year ended December 31, 2021.

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Investment in Ruby

During the first quarter of 2021, we recognized a pre-tax charge of $117 million related to a write-down of our subordinated note receivable from our former equity investee, Ruby, which is included within “Earnings from equity investments” in our accompanying consolidated statement of income for the year ended December 31, 2021. The write-down was driven by the impairment recognized by Ruby of its assets.

Ruby Chapter 11 Bankruptcy Filing

The balance of Ruby Pipeline, L.L.C.’s 2022 unsecured notes matured on April 1, 2022 in the principal amount of $475 million. Although Ruby had sufficient liquidity to operate its business, it lacked sufficient liquidity to satisfy its obligations under the 2022 unsecured notes on the maturity date of April 1, 2022. Accordingly, on March 31, 2022, Ruby filed a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. Ruby, as the debtor, continued to operate in the ordinary course as a debtor in possession under the jurisdiction of the United States Bankruptcy Court. We fully impaired our equity investment in Ruby in the fourth quarter of 2019 and fully impaired our investment in Ruby’s subordinated notes in the first quarter of 2021. We had no amounts included in our “Investments” on our accompanying consolidated balance sheet associated with Ruby as of December 31, 2022.

On January 13, 2023, the bankruptcy court confirmed a plan of reorganization satisfactory to all interested parties regarding Ruby, which involved payment of Ruby’s outstanding senior notes with the proceeds from the sale of Ruby to Tallgrass, a settlement by KMI and Pembina of certain potential causes of action relating to the bankruptcy, and cash on hand. Our payment to the bankruptcy estate, net of payments it received in respect of a long-term subordinated note receivable from Ruby, was approximately $28.5 million which was accrued for as of December 31, 2022 and included within “Other, net” in our accompanying consolidated statement of income for the year ended December 31, 2022. Consummation of the settlement and the sale of Ruby to Tallgrass occurred on January 13, 2023.

5.Income Taxes

The components of “Income Before Income Taxes” are as follows:
 Year Ended December 31,
 202320222021
(In millions)
U.S.$3,192 $3,318 $2,217 
Foreign9 17 2 
Total Income Before Income Taxes$3,201 $3,335 $2,219 

Components of the income tax provision applicable for federal, foreign and state taxes are as follows:
 Year Ended December 31,
 202320222021
(In millions)
Current tax expense   
State$5 $14 $11 
Foreign— 4 3 
Total5 18 14 
Deferred tax expense   
Federal619 642 334 
State91 50 21 
Total710 692 355 
Total tax provision$715 $710 $369 

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The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows:
 Year Ended December 31,
 202320222021
(In millions, except percentages)
Federal income tax$672 21.0 %$700 21.0 %$466 21.0 %
Increase (decrease) as a result of:      
State income tax, net of federal benefit64 2.0 %69 2.0 %50 2.2 %
Dividend received deduction(34)(1.1)%(36)(1.1)%(46)(2.1)%
Release of valuation allowance— — %— — %(38)(1.7)%
General business credit(1)— %— — %(36)(1.6)%
Other14 0.4 %(23)(0.7)%(27)(1.2)%
Total$715 22.3 %$710 21.2 %$369 16.6 %

Deferred tax assets and liabilities result from the following:
 December 31,
 20232022
(In millions)
Deferred tax assets  
Employee benefits$114 $116 
Net operating loss carryforwards2,024 2,007 
Tax credit carryforwards300 303 
Interest expense limitation266 82 
Other181 192 
Valuation allowances(77)(79)
Total deferred tax assets2,808 2,621 
Deferred tax liabilities
Property, plant and equipment215 163 
Investments(a)3,951 3,056 
Other30 25 
Total deferred tax liabilities4,196 3,244 
Net deferred tax liability$(1,388)$(623)
(a)Amounts as of December 31, 2023 and 2022 are primarily associated with KMI’s investment in KMP.

Deferred Tax Assets and Valuation Allowances

A reconciliation of our valuation allowances for the year ended December 31, 2023 is as follows:
Year Ended
December 31, 2023
(In millions)
Balance at beginning of period$79 
Statute expirations for state NOL and foreign tax credits(5)
Currency fluctuation3 
Balance at end of period$77 

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The following table provides details related to our deferred tax assets and valuation allowances as of December 31, 2023:
Unused AmountDeferred Tax AssetValuation AllowanceExpiration Period
(In millions)
Net Operating Loss
U.S. federal net operating loss$6,565 $1,379 $— Indefinite
U.S. federal net operating loss1,716 360 — 2035 - 2037
State losses5,293 254 (46)2024 - 2043
Foreign losses90 31 (31)Indefinite
Tax Credits
General business credits300 300 — 2036 - 2042

Use of a portion of our U.S. federal carryforwards is subject to the limitations provided under Sections 382 and 383 of the Internal Revenue Code as well as the separate return limitation rules of Internal Revenue Service regulations. If certain substantial changes in our ownership occur, there would be an annual limitation on the amount of carryforwards that could be utilized.

Unrecognized Tax Benefits: We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based not only on the technical merits of the tax position based on tax law, but also the past administrative practices and precedents of the taxing authority.  The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate resolution.

A reconciliation of our gross unrecognized tax benefit excluding interest and penalties is as follows:
Year Ended December 31,
202320222021
(In millions)
Balance at beginning of period$23 $21 $18 
Reductions based on statute expirations(5)(5)— 
Audit settlement(1)— — 
Additions to state reserves for prior years1 7 3 
Balance at end of period$18 $23 $21 
Amounts which, if recognized, would affect the effective tax rate$18 

In addition, we believe it is reasonably possible that our liability for unrecognized tax benefits will increase by $4 million during the next year, primarily due to additions for state filing positions taken in prior years, offset by releases from statute expirations.

The following table summarizes information of our open tax years:
JurisdictionOpen Tax Year
U.S.2019 - 2023
Various states2012 - 2023
Foreign2008 - 2023

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6.  Property, Plant and Equipment, net
As of December 31, 2023 and 2022, our property, plant and equipment, net consisted of the following:
 
Straight-Line
Estimated Useful Life
Composite
Depreciation Rates		December 31,
 20232022
(Years) (%)(In millions)
Interstate Natural Gas FERC-Regulated
Pipelines (Natural gas)0.80-6.67$12,019 $11,793 
Equipment (Natural gas)0.80-6.679,190 8,839 
Other(a)0.00-25823 833 
Accumulated depreciation, depletion and amortization(10,301)(9,883)
Depreciable assets11,731 11,582 
Land and land rights-of-way(b)399 388 
Construction work in process394 258 
Total interstate natural gas FERC-regulated12,524 12,228 
Other
Pipelines (Natural gas, liquids, crude oil and CO2)
5-400.09-33.339,631 8,329 
Equipment (Natural gas, liquids, crude oil, CO2 and terminals)
5-400.09-33.3319,974 18,645 
Other(a)3-100.00-33.334,773 4,791 
Accumulated depreciation, depletion and amortization(11,774)(10,529)
Depreciable assets22,604 21,236 
Land and land rights-of-way(c)1,518 1,350 
Construction work in process651 785 
Total other24,773 23,371 
Property, plant and equipment, net$37,297 $35,599 
(a)Includes general plant, general structures and buildings, computer and communication equipment, intangibles, vessels, transmix products, linefill and miscellaneous property, plant and equipment.
(b)Balances as of both December 31, 2023 and 2022 include land rights-of-way of $346 million which are depreciable.
(c)Balances as of December 31, 2023 and 2022 include land rights-of-way of $720 million and $551 million, respectively, which are depreciable.

Depreciation, depletion and amortization expense for property, plant and equipment was $2,020 million, $1,905 million and $1,873 million for the years ended December 31, 2023, 2022 and 2021, respectively.

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7.  Investments
 
Our investments primarily consist of equity investments where we hold significant influence over investee actions and for which we apply the equity method of accounting. As of December 31, 2017 and 2016,The following table provides details on our investments consisted of the following (in millions): 
 December 31,
 2017 2016
Citrus Corporation$1,698
 $1,709
SNG1,495
 1,505
Ruby774
 798
NGPL Holdings LLC687
 475
Gulf LNG Holdings Group, LLC461
 485
Plantation Pipe Line Company331
 333
EagleHawk314
 329
Utopia Holding LLC276
 55
MEP253
 328
Red Cedar Gathering Company187
 191
Watco Companies, LLC182
 180
Double Eagle Pipeline LLC149
 151
FEP112
 101
Liberty Pipeline Group LLC71
 75
Bear Creek Storage63
 61
Sierrita Gas Pipeline LLC55
 57
Fort Union Gas Gathering L.L.C.12
 25
All others                                                                                                 178
 169
Total investments$7,298
 $7,027

As shown in the investment balance table above and the earnings (losses) from equity investments table below, our significant equity investments as of December 31, 2017 consisted2023 and 2022 and our earnings (loss) from these respective investments for the years ended December 31, 2023, 2022 and 2021: 
Ownership InterestEquity InvestmentsEarnings (Loss) from
Equity Investments
 December 31,December 31,Year Ended December 31,
 202320232022202320222021
(In millions)
Citrus Corporation50%$1,789 $1,781 $143 $145 $151 
SNG50%1,668 1,669 140 145 128 
PHP27.74%763 666 70 70 63 
NGPL Holdings(a)37.5%623 610 121 111 94 
Gulf Coast Express Pipeline LLC34%566 597 93 91 86 
Products (SE) Pipe Line Corporation51.17%369 348 65 51 48 
MEP50%342 371 87 10 (17)
Utopia Holding LLC50%322 325 22 20 20 
Gulf LNG Holdings Group, LLC50%275 311 25 24 22 
EagleHawk25%273 273 18 13 8 
Dos Caminos, LLC50%192 — — — — 
Red Cedar Gathering Company49%155 155 15 17 10 
Watco Companies, LLC(b)84 79 10 9 9 
Cortez Pipeline Company52.98%30 31 25 30 29 
Double Eagle(c)50%14 90 (42)18 9 
Ruby(d)— — — — (116)
All others409 347 46 49 47 
Total investments$7,874 $7,653 $838 $803 $591 
Amortization of excess cost$(66)$(75)$(78)
(a)Our investment in NPGL Holdings includes a related party promissory note receivable from NGPL Holdings with quarterly interest payments at 6.75%. As of the following:
Citrus Corporation—We own a 50% interest in Citrus Corporation, the sole owner of Florida Gas Transmission Company, L.L.C. (Florida Gas). Florida Gas transports natural gas to cogeneration facilities, electric utilities, independent power producers, municipal generators, and local distribution companies through a 5,300-mile natural gas pipeline. Energy Transfer Partners L.P. operates Florida Gas and owns the remaining 50% interest in Citrus;
SNG—We operate SNG and own a 50% interest in SNG; and Evergreen Enterprise Holdings, LLC, a subsidiary of Southern Company, owns the remaining 50% interest.

Ruby—We operate Ruby and own the common interest in Ruby, the sole owner of the Ruby Pipeline natural gas transmission system. Pembina Pipeline Corporation (Pembina) owns the remaining interest in Ruby in the form of a convertible preferred interest. If Pembina converted its preferred interest into common interest,December 31, 2023, we and Pembina wouldArclight each ownhold a 50% common37.5% interest in Ruby;
NGPL Holdings LLC— We operate NGPL Holdings LLC and own a 50% interest in NGPL Holdings LLC, the indirect owner of NGPL and certain affiliates, collectively referred to in this report as NGPL, a major interstate natural gas pipeline and storage system. The remaining 50% interest is owned by Brookfield;
Gulf LNG Holdings Group, LLC—We operate Gulf LNG Holdings Group, LLC and own a 50% interest in Gulf LNG Holdings Group, LLC, the owner of a LNG receiving, storage and regasification terminal near Pascagoula, Mississippi, as well as pipeline facilities to deliver vaporized natural gas into third party pipelines for delivery into various markets around the country. The remaining 50% interest is owned by a variety of investment entities, including subsidiaries of The Blackstone Group, LP; Warburg Pincus, LLC; Kelso and Company; and Lightfoot Capital Partners, LP, which is majority owned by GE Energy Financial Services.
Plantation—We operate Plantation and own a 51.17% interest in Plantation, the sole owner of the Plantation refined petroleum products pipeline system.  A subsidiary of Exxon Mobil Corporation owns the remaining interest.  Each investor has an equal number of directors on Plantation’s board of directors, and board approval is required for certain corporate actions that are considered substantive participating rights; therefore, we do not control Plantation, and account for the investment under the equity method;
BHP Billiton Petroleum (Eagle Ford) LLC, (EagleHawk)—We ownBrookfield holds a 25% interest in EagleHawk,NGPL Holdings. The outstanding principal amount of our related party promissory note receivable at both December 31, 2023 and 2022 was $375 million. For the sole owneryears ended December 31, 2023, 2022 and 2021, we recognized $25 million, $25 million and $27 million, respectively, of natural gas and condensate gathering systems serving the producersinterest within “Earnings from equity investments” on our accompanying consolidated statements of the Eagle Ford shale formation. A subsidiary of BHP Billiton Petroleum operates EagleHawk and owns the remaining 75% ownership interest;income.
Utopia Holding L.L.C. — We operate Utopia Holding L.L.C. and own a 50% interest in Utopia Holding L.L.C. Riverstone Investment Group LLC owns the remaining 50% interest;
MEP—We operate MEP and own a 50% interest in MEP, the sole owner of the MEP natural gas pipeline system.  The remaining 50% ownership interest is owned by subsidiaries of Energy Transfer Partners L.P.;
Red Cedar Gathering Company—We own a 49% interest in Red Cedar Gathering Company, the sole owner of the Red Cedar natural gas gathering, compression and treating system.  The Southern Ute Indian Tribe owns the remaining 51% interest and serves as operator of Red Cedar;
Watco Companies, LLC—(b)We hold a preferred and common equity investment in Watco Companies, LLC the largest privately held short line railroad company in the U.S.(Watco).  We own100,000 Class A and 50,000 Class B preferred shares and pursuant to the terms of the investment, receive priority, cumulative cash and stock distributions from the preferred shares at a rate of 3.25% and 3.00% per quarter, respectively, and participate partially in additional profit distributions at a rate equal to 0.4%.  Neither class holdsquarter.  We do not hold any voting powers, but dothe class does provide us certain approval rights, including the right to appoint one of the members to Watco’s board of managers. In addition to
(c)Loss for the senior interests,year ended December 31, 2023 includes $67 million of our share of a non-cash impairment charge (pre-tax). For further information, see Note 4 “Losses and Gains on Divestitures, Impairments and Other Write-downs—Investments.”
(d)As of January 13, 2023, we also hold approximately 13,000 common equity units, which represents a 3.2% common ownership;
Double Eagle Pipeline LLC - Weno longer own a 50% equityan interest in Double Eagle Pipeline LLC.Ruby. The remaining 50% interest is ownedloss from our investment in Ruby for the year ended December 31, 2021 includes a non-cash impairment charge of $117 million related to a write-down of our subordinated note receivable from Ruby driven by Magellan Midstream Partners;the impairment by Ruby of its assets. For further information regarding our investment in Ruby, see Note 4 “Losses and Gains on Divestitures, Impairments and Other Write-downs—Investment in Ruby.”
FEP —We own a 50% interest in FEP, the sole owner of the Fayetteville Express natural gas pipeline system.  Energy Transfer Partners, L.P. owns the remaining 50% interest and serves as operator of FEP;

Liberty Pipeline Group, LLC (Liberty) —We own a 50% interest in Liberty.  ETC NGL Transport, LLC, a subsidiary of Energy Transfer Partners, L.P. owns the remaining 50% interest and serves as operator of Liberty;
Bear Creek Storage—We own a combined 75% interest in Bear Creek through: our wholly owned subsidiary’s (TGP) 50% interest and an additional 25% indirect interest through our 50% equity interest in SNG, which owns the remaining 50% interest;
Sierrita Gas Pipeline LLC — We operate Sierrita Gas Pipeline LLC and own a 35% equity interest in the Sierrita Gas Pipeline LLC. MGI Enterprises U.S. LLC, a subsidiary of PEMEX, owns 35%; and MIT Pipeline Investment Americas, Inc., a subsidiary of Mitsui & Co., Ltd, owns 30%;
Fort Union Gas Gathering LLC—We own a 37.04% equity interest in the Fort Union Gas Gathering LLC. Crestone Powder River LLC, a subsidiary of ONEOK Partners L.P., owns 37.04%; Powder River Midstream, LLC owns 11.11%; and Western Gas Wyoming, LLC owns the remaining 14.81%. Western Gas Resources, Inc. serves as operator of Fort Union Gas Gathering LLC;

•
Cortez Pipeline Company—We operate the Cortez CO2 pipeline system, and as of December 31, 2017, we owned a 52.98% interest in the Cortez Pipeline Company, the sole owner of the Cortez CO2 pipeline system. Mobil Cortez Pipeline Inc. owns 33.25%; and Cortez Vickers Pipeline Company owns the remaining 13.77%.

Our earnings (losses) from equity investments were as follows (in millions):
 Year Ended December 31,
 2017 2016 2015
Citrus Corporation$108
 $102
 $96
SNG77
 58
 —
FEP53
 51
 55
Gulf LNG Holdings Group, LLC47
 48
 49
Plantation Pipe Line Company46
 37
 29
Cortez Pipeline Company(a)44
 24
 (3)
Ruby44
 15
 18
MEP38
 40
 45
EagleHawk24
 10
 24
Watco Companies, LLC19
 25
 16
Red Cedar Gathering Company(b)14
 24
 26
Fort Union Gas Gathering L.L.C.(c)10
 1
 16
NGPL Holdings LLC10
 12
 —
Liberty Pipeline Group LLC9
 11
 9
Bear Creek Storage8
 2
 —
Sierrita Gas Pipeline LLC7
 7
 9
Double Eagle Pipeline LLC7
 5
 3
Parkway Pipeline LLC—
 14
 5
All others13
 11
 17
Total earnings from equity investments$578

$497
 $414
Amortization of excess costs(61) (59) (51)
_______
(a)2017, 2016 and 2015 amounts include $(4) million, $9 million and $26 million, respectively, representing our share of a non-cash impairment charge (pre-tax) recorded by Cortez Pipeline Company.
(b)2017 amount includes non-cash impairment charges of $10 million (pre-tax) related to our investment.
(c)2016 amount includes non-cash impairment charges of $7 million (pre-tax) related to our investment.

Summarized combined financial information for our significant equity investments (listed or described above) is reported below (in millions; amounts(amounts represent 100% of investee financial information):
Year Ended December 31,
Income Statement202320222021(a)
(In millions)
Revenues$5,981 $5,953 $5,521 
Costs and expenses4,149 4,193 6,137 
Net income (loss)$1,832 $1,760 $(616)
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  Year Ended December 31,
Income Statement 2017 2016 2015
Revenues $4,703
 $4,084
 $3,857
Costs and expenses 3,398
 3,056
 3,408
Net income $1,305
 $1,028
 $449
December 31,
Balance Sheet20232022
(In millions)
Current assets$1,844 $1,461 
Non-current assets23,193 23,360 
Current liabilities1,534 1,617 
Non-current liabilities10,102 10,206 
Partners’/owners’ equity13,401 12,998 

(a)2021 amounts include a non-cash impairment charge of $2.2 billion recorded by Ruby.


  December 31,
Balance Sheet 2017 2016
Current assets $956
 $892
Non-current assets 22,344
 22,170
Current liabilities 1,241
 3,532
Non-current liabilities 10,605
 9,187
Partners’/owners’ equity 11,454
 10,343

8.  Goodwill
 
Changes in the amounts of our goodwill for each of the years ended December 31, 20172023 and 20162022 are summarized by reporting unit as follows (in millions):follows:  
 Natural Gas Pipelines RegulatedNatural Gas Pipelines Non-Regulated
CO2
Products PipelinesProducts Pipelines TerminalsTerminalsEnergy Transition VenturesTotal
(In millions)
Gross goodwill$15,892 $4,940 $1,528 $2,575 $221 $1,481 $63 $26,700 
Accumulated impairment losses(1,643)(2,597)(600)(1,197)(70)(679)— (6,786)
December 31, 202114,249 2,343 928 1,378 151 802 63 19,914 
Acquisitions(a)— — — — — — 51 51 
December 31, 202214,249 2,343 928 1,378 151 802 114 19,965 
Acquisition of STX Midstream— 156 — — — — — 156 
December 31, 202314,249 2,499 928 1,378 151 802 114 20,121 
Gross goodwill15,892 5,096 1,528 2,575 221 1,481 114 26,907 
Accumulated impairment losses(1,643)(2,597)(600)(1,197)(70)(679)— (6,786)
December 31, 2023$14,249 $2,499 $928 $1,378 $151 $802 $114 $20,121 
 Natural Gas Pipelines Regulated Natural Gas Pipelines Non-Regulated 
CO2
 Products Pipelines Products Pipelines Terminals Terminals 
Kinder
Morgan
Canada
 Total
Historical Goodwill$17,527
 $5,812
 $1,528
 $2,125
 $221
 $1,584
 $556
 $29,353
Accumulated impairment losses(1,643) (1,597) —
 (1,197) (70) (679) (377) (5,563)
December 31, 201515,884
 4,215
 1,528
 928
 151
 905
 179
 23,790
Currency translation—
 —
 —
 —
 —
 —
 6
 6
Divestitures(a)(1,635) —
 —
 —
 —
 (9) —
 (1,644)
December 31, 201614,249
 4,215
 1,528
 928
 151
 896
 185
 22,152
Currency translation—
 —
 —
 —
 —
 —
 13
 13
Divestitures(b)—
 —
 —
 —
 —
 (3) —
 (3)
December 31, 2017$14,249
 $4,215
 $1,528
 $928
 $151
 $893
 $198
 $22,162
(a)Includes goodwill arising from our acquisition of NANR and a $10 million purchase price adjustment related to our acquisition of Kinetrex in 2021 that was attributed to long-term deferred tax liabilities.
_______
(a)2016 includes $1,635 million related to the sale of a 50% interest in our SNG natural gas pipeline system by Natural Gas Pipelines Regulated to Southern Company and $9 million related to certain terminal divestitures.
(b)2017 includes $3 million related to certain terminal divestitures.


Refer to Note 2 “Summary of Significant Accounting Policies—Goodwill” for a descriptionResults of our accountingMay 31, 2023 annual impairment test indicated that for each of our reporting units, the reporting unit’s fair value exceeded carrying value, with our Terminals reporting unit’s fair value in excess of its carrying values by less than 10% which was impacted by a decline in market multiples. We did not identify any triggers requiring further impairment analysis during the remainder of the year.

The fair value estimates used in our goodwill and Note 4 “Impairments and Losses on Divestitures” for further discussion regarding impairments.

We determineimpairment test include Level 3 inputs of the fair value of eachhierarchy. For all reporting unit as of May 31 of each yearunits other than Energy Transition Ventures, we estimated fair value based primarily on a market approach utilizing forecasted earnings before interest, income taxes, DD&A expenses, including amortization of excess cost of equity investments, (EBITDA) and the enterprise value to estimated EBITDA multiples of comparable companies.companies for each of our reporting units. The value of each reporting unit iswas determined on a stand-alone basis from the perspective of a market participant representing the price estimated to be received in a sale of the reporting unit in an orderly transaction between market participants at the measurement date. For our Natural Gas Pipelines Non-Regulated reporting unit, our May 31, 2017 annual test included a discounted cash flow analysis (income approach) to evaluate the fair value of this reporting unit to provide additional indication ofEnergy Transition Ventures, we estimated fair value based on the present value ofan income approach, which includes assumptions regarding future cash flows this reporting unit is expected to generate in the future. We weighted the market and income approaches for this reporting unit to arrive at an estimated fair value of this reporting unit giving more weightingbased on the income approach and lessprimarily on the market approach as we believed the value indicated using the income approach is more representative of the value that could be received from a market participant. As of May 31, 2017, each of our reporting units indicated a fair value in excess of their respective carryingproduction growth assumptions, terminal values and step 2 was not required. The amount of excess fair value over the carrying value ranged from approximately 3% for our Natural Gas Pipelines Non-Regulated reporting unit to 89% for our Products Pipelines Terminals as of May 31, 2017. The results of our Step 1 analysis did not indicate an impairment of goodwill and we did not identify any triggers for further impairment analysis during the remainder of the year.discount rates.


Due to the effect of commodity prices on market conditions that impacted the energy sector, during the fourth quarter 2015, we conducted an interim test of the recoverability of goodwill as of December 31, 2015, and concluded that the goodwill of our Natural Gas Pipelines - Non-Regulated reporting unit was impaired by $1.15 billion.


The fair value estimates of our reporting unit fair value, and in arriving at the fourth quarter 2015 impairment amount, were based on Level 3 inputs of the fair value hierarchy.

A continued period of volatile commodity prices could result in further deterioration of market multiples, comparable sales transactions prices, weighted average costs of capital, and our cash flow estimates. A significant unfavorable changeChanges to any one or a combination of these factors would result in a change to the reporting unit fair values, discussed above potentially resulting in additional impairments of long-lived assets, equity method investments, and/or goodwill.which could lead to future impairment charges. Such potential non-cash impairments could have a significant effect on our results of operations.


99

9.  Debt

We classify our debt based on the contractual maturity dates of the underlying debt instruments.  We defer costs associated with debt issuance over the applicable term. These costs are then amortized as interest expense in our accompanying consolidated statements of income.


The following table provides detail on the principal amount of our outstanding debt balances.balances:
December 31,
 20232022
(In millions)
Credit facility and commercial paper borrowings(a)$1,989 $— 
Corporate senior notes(b)
3.15%, due January 2023— 1,000 
Floating rate, due January 2023(c)— 250 
3.45%, due February 2023— 625 
3.50%, due September 2023— 600 
5.625%, due November 2023— 750 
4.15%, due February 2024650 650 
4.30%, due May 2024600 600 
4.25%, due September 2024650 650 
4.30%, due June 20251,500 1,500 
1.75%, due November 2026500 500 
6.70%, due February 20277 7 
2.25%, due March 2027(d)552 535 
6.67%, due November 20277 7 
4.30%, due March 20281,250 1,250 
7.25%, due March 202832 32 
6.95%, due June 202831 31 
8.05%, due October 2030234 234 
2.00%, due February 2031750 750 
7.40%, due March 2031300 300 
7.80%, due August 2031537 537 
7.75%, due January 20321,005 1,005 
7.75%, due March 2032300 300 
4.80%, due February 2033750 750 
5.20%, due June 20331,500 — 
7.30%, due August 2033500 500 
5.30%, due December 2034750 750 
5.80%, due March 2035500 500 
7.75%, due October 20351 1 
6.40%, due January 203636 36 
6.50%, due February 2037400 400 
7.42%, due February 203747 47 
6.95%, due January 20381,175 1,175 
6.50%, due September 2039600 600 
6.55%, due September 2040400 400 
7.50%, due November 2040375 375 
6.375%, due March 2041600 600 
5.625%, due September 2041375 375 
5.00%, due August 2042625 625 
4.70%, due November 2042475 475 
5.00%, due March 2043700 700 
5.50%, due March 2044750 750 
5.40%, due September 2044550 550 
5.55%, due June 20451,750 1,750 
5.05%, due February 2046800 800 
5.20%, due March 2048750 750 
3.25%, due August 2050500 500 
3.60%, due February 20511,050 1,050 
5.45%, due January 2052750 750 
7.45%, due March 209826 26 
TGP senior notes(b)
7.00%, due March 2027300 300 
7.00%, due October 2028400 400 
2.90%, due March 20301,000 1,000 
100

December 31,
 20232022
8.375%, due June 2032240 240 
7.625%, due April 2037300 300 
EPNG senior notes(b)
7.50%, due November 2026200 200 
3.50%, due February 2032300 300 
8.375%, due June 2032300 300 
CIG senior notes(b)
4.15%, due August 2026375 375 
6.85%, due June 2037100 100 
EPC Building, LLC, promissory note, 3.967%, due January 2022 through December 2035330 348 
Trust I Preferred Securities, 4.75%, due March 2028(e)221 220 
Other miscellaneous debt(f)234 242 
Total debt – KMI and Subsidiaries31,929 31,673 
Less: Current portion of debt4,049 3,385 
Total long-term debt – KMI and Subsidiaries(g)$27,880 $28,288 
(a)Weighted average interest rate on borrowings at December 31, 2023 was 5.68%.
(b)Notes provide for the redemption at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make whole premium and are subject to a number of restrictions and covenants. The tablemost restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions.
(c)As of December 31, 2022, we had outstanding an associated floating-to-fixed interest rate swap agreement which was designated as a cash flow hedge.
(d)Consists of senior notes denominated in Euros that have been converted to U.S. dollars and are respectively reported above at the December 31, 2023 exchange rate of 1.1039 U.S. dollars per Euro and at the December 31, 2022 exchange rate of 1.0705 U.S. dollars per Euro. As of December 31, 2023 and 2022, the cumulative changes in the exchange rate of U.S. dollars per Euro since issuance had resulted in an increase of $9 million and a decrease of $8 million, respectively. As of December 31, 2023, we had outstanding associated cross-currency swap agreements which are designated as cash flow hedges.
(e)Capital Trust I (Trust I), is a 100%-owned business trust that as of December 31, 2023, had 4.4 million of 4.75% trust convertible preferred securities outstanding (referred to as the Trust I Preferred Securities). Trust I exists for the sole purpose of issuing preferred securities and investing the proceeds in 4.75% convertible subordinated debentures, which are due 2028. Trust I’s sole source of income is interest earned on these debentures. This interest income is used to pay distributions on the preferred securities. We provide a full and unconditional guarantee of the Trust I Preferred Securities. There are no significant restrictions from these securities on our ability to obtain funds from our subsidiaries by distribution, dividend or loan. The Trust I Preferred Securities are non-voting (except in limited circumstances), pay quarterly distributions at an annual rate of 4.75% and carry a liquidation value of $50 per security plus accrued and unpaid distributions. The Trust I Preferred Securities outstanding as of December 31, 2023 are convertible at any time prior to the close of business on March 31, 2028, at the option of the holder, into the following mixed consideration: (i) 0.7197 of a share of our Class P common stock; and (ii) $25.18 in cash without interest. We have the right to redeem these Trust I Preferred Securities at any time.
(f)Includes finance lease obligations with monthly installments. The lease terms expire between 2026 and 2070.
(g)Excludes our “Debt fair value adjustments” which, as of December 31, 2023 and 2022, increased our combined debt balances by $187 million and $115 million, respectively. In addition to all unamortized debt discount/premium amounts, exclude alldebt issuance costs and purchase accounting on our debt balances, our debt fair value adjustments includingalso include amounts associated with the offsetting entry for hedged debt discounts, premiums and issuance costs (in millions):any unamortized portion of proceeds received from the early termination of interest rate swap agreements. For further information about our debt fair value adjustments, see “—Debt Fair Value Adjustments” below.

 December 31,
 2017 2016
Unsecured term loan facility, variable rate, due January 26, 2019(a)$—
 $1,000
Senior note, floating rate, due January 15, 2023(a)250
 —
Senior notes, 1.50% through 8.05%, due 2017 through 2098(a)(b)(c)13,136
 13,236
Credit facility due November 26, 2019125
 —
Commercial paper borrowings240
 —
KML Credit Facility(d)—
 —
KMP senior notes, 2.65% through 9.00%, due 2017 through 2044(c)(e)18,885
 19,485
TGP senior notes, 7.00% through 8.375%, due 2017 through 2037(c)(f)1,240
 1,540
EPNG senior notes, 5.95% through 8.625%, due 2017 through 2032(c)(g)760
 1,115
CIG senior notes, 4.15% and 6.85%, due 2026 and 2037(c)475
 475
Kinder Morgan Finance Company, LLC, senior notes, 6.00% and 6.40%, due 2018 and 2036(c)786
 786
Hiland Partners Holdings LLC, senior notes, 5.50%, due 2022(a)(h)—
 225
EPC Building, LLC, promissory note, 3.967%, due 2017 through 2035421
 433
Trust I preferred securities, 4.75%, due March 31, 2028(i)221
 221
KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock(j)100
 100
Other miscellaneous debt(k)277
 285
Total debt – KMI and Subsidiaries36,916
 38,901
Less: Current portion of debt(l)2,828
 2,696
Total long-term debt – KMI and Subsidiaries(m)$34,088
 $36,205
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.
_______
(a)On August 10, 2017, we issued $1 billion of unsecured senior notes with a fixed rate of 3.15% and $250 million of unsecured senior notes with a floating rate, both due January 2023. The net proceeds from the notes were primarily used to repay the principal amount of Hiland’s 5.50% senior notes due 2022, plus accrued interest, and to repay the $1 billion term loan facility due 2019. Interest on the 3.15% senior notes due 2023 is payable semi-annually in arrears on January 15 and July 15 of each year, beginning on January 15, 2018, and the notes will mature on January 15, 2023. Interest on the floating rate senior notes due 2023 is payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year, beginning on October 15, 2017, and such notes will mature on January 15, 2023. We may redeem all or a part of the 3.15% fixed rate notes at any time at the redemption prices. The floating rate notes are not redeemable prior to maturity. See (b) and (h) below.
(b)
Amounts include senior notes that are denominated in Euros and have been converted to U.S. dollars and are respectively reported above at the December 31, 2017 exchange rate of 1.2005 U.S. dollars per Euro and the December 31, 2016 exchange rate of 1.0517 U.S. dollars per Euro. For the year ended December 31, 2017, our debt balance increased by $186 million as a result of the change in the exchange rate of U.S dollars per Euro. The increase in debt due to the changes in exchange rates is offset by a corresponding change in the value of cross-currency swaps reflected in “Deferred charges and other assets” and “ Other long-term liabilities and deferred credits” on our consolidated balance sheets. At the time of issuance, we entered into cross-currency swap agreements associated with these senior notes, effectively converting these Euro-denominated senior notes to U.S. dollars (see Note 14 “Risk Management—Foreign Currency Risk Management”). In June 2017, we repaid $786 million of maturing 7.00% senior notes and in December 2017, we repaid $500 million of maturing 2.00% senior notes. The December 31, 2017 balance includes the $1 billion of unsecured term notes with a fixed rate of 3.15% due January 15, 2023 discussed in (a) above.
(c)Notes provide for the redemption at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make whole premium and are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions.
(d)
The KML Credit Facility is denominated in C$ and has been converted to U.S. dollars and reported above at the December 31, 2017 exchange rate of 0.7971 U.S. dollars per C$. See “—Credit Facilities and Restrictive Covenants” below.

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 and received combined net proceeds of $2,230 million.
(e)In February 2017, we repaid $600 million of maturing 6.00% senior notes.
(f)In April 2017, we repaid $300 million of maturing 7.50% senior notes.
(g)In April 2017, we repaid $355 million of maturing 5.95% senior notes.
(h)In August 2017, we repaid $225 million of the outstanding principal amount of 5.50% senior notes with a maturity date of May 15, 2022 using net proceeds from the sale of the January 2023 notes (see (a) above). We recognized a $3.8 million loss from the early extinguishment of debt, included within “Interest, net” on the accompanying consolidated statements of income for the year ended December 31, 2017 consisting of a $9.3 million premium on the debt repaid and a $5.5 million gain from the write-off of unamortized purchase accounting associated with the early extinguished debt.
(i)Capital Trust I (Trust I), is a 100%-owned business trust that as of December 31, 2017, had 4.4 million of 4.75% trust convertible preferred securities outstanding (referred to as the Trust I Preferred Securities). Trust I exists for the sole purpose of issuing preferred securities and investing the proceeds in 4.75% convertible subordinated debentures, which are due 2028. Trust I’s sole source of income is interest earned on these debentures. This interest income is used to pay distributions on the preferred securities. We provide a full and unconditional guarantee of the Trust I Preferred Securities. There are no significant restrictions from these securities on our ability to obtain funds from our subsidiaries by distribution, dividend or loan. The Trust I Preferred Securities are non-voting (except in limited circumstances), pay quarterly distributions at an annual rate of 4.75%, carry a liquidation value of $50 per security plus accrued and unpaid distributions and are convertible at any time prior to the close of business on March 31, 2028, at the option of the holder, into the following mixed consideration: (i) 0.7197 of a share of our Class P common stock; (ii) $25.18 in cash without interest; and (iii) 1.100 warrants to purchase a share of our Class P common stock. Our warrants expired on May 25, 2017, along with the portion of the mixed consideration that provided for the conversion into 1.100 warrants to purchase a share of our Class P common stock. We have the right to redeem these Trust I Preferred Securities at any time. Because of the substantive conversion rights of the securities into the mixed consideration, we bifurcated the fair value of the Trust I Preferred Securities into debt and equity components and as of December 31, 2017, the outstanding balance of $221 million (of which $111 million was classified as current) was bifurcated between debt ($200 million) and equity ($21 million).
(j)As of December 31, 2017 and 2016, KMGP had outstanding, 100,000 shares of its $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock due 2057.  Since August 18, 2012, dividends on the preferred stock accumulate at a floating rate of the 3-month LIBOR plus 3.8975% and are payable quarterly in arrears, when and if declared by KMGP’s board of directors, on February 18, May 18, August 18 and November 18 of each year, beginning November 18, 2012.  The preferred stock has approval rights over a commencement of or filing of voluntary bankruptcy by KMP or its SFPP or Calnev subsidiaries.
(k)In conjunction with the construction of the Totem Gas Storage facility (Totem) and the High Plains pipeline (High Plains), CIG’s joint venture partner in WYCO funded 50% of the construction costs. Upon project completion, the advances were converted into a financing obligation to WYCO. As of December 31, 2017, the principal amounts of the Totem and High Plains financing obligations were $69 million and $88 million, respectively, which will be paid in monthly installments through 2039 based on the initial lease term. The interest rate on these obligations is 15.5%, payable on a monthly basis.
(l)Amounts include KMI and KML outstanding credit facility borrowings, commercial paper borrowings and other debt maturing within 12 months. See “—Current Portion of Debt” below.
(m)Excludes our “Debt fair value adjustments” which, as of December 31, 2017 and 2016, increased our combined debt balances by $927 million and $1,149 million, respectively. In addition to all unamortized debt discount/premium amounts, debt issuance costs and purchase accounting on our debt balances, our debt fair value adjustments also include amounts associated with the offsetting entry for hedged debt and any unamortized portion of proceeds received from the early termination of interest rate swap agreements. For further information about our debt fair value adjustments, see —“Debt Fair Value Adjustments” below.


We and substantially all of our wholly owned domestic subsidiaries are a party 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. Also, see Note 19 “Guarantee of Securities of Subsidiaries.”


Credit Facilities and Restrictive Covenants
101
KMI


On January 26, 2016, we increased the capacity of our revolving credit agreement, initially entered into during 2014, from $4.0 billion to $5.0 billion. The other terms of our revolving credit agreement remain the same. We also maintain a $4.0 billion commercial paper program through the private placement of short-term notes. The notes mature up to 270 days from the date of issue and are not redeemable or subject to voluntary prepayment by us prior to maturity. The notes are sold at par value less a discount representing an interest factor or if interest bearing, at par. Borrowings under our revolving credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Borrowings under our commercial paper program reduce the borrowings allowed under our credit facility.
Our credit facility borrowings bear interest at either (i) LIBOR plus an applicable margin ranging from 1.125% to 2.000% per annum based on our credit ratings or (ii) the greatest of (1) the Federal Funds Rate plus 0.5%; (2) the Prime Rate; and (3) LIBOR Rate for a one month eurodollar loan, plus 1%, plus, in each case, an applicable margin ranging from 0.125% to 1.00% per annum based on our credit rating.

Our credit facility included the following restrictive covenants as of December 31, 2017:
total debt divided by earnings before interest, income taxes, depreciation and amortization may not exceed:
6.50: 1.00, for the period ended on or prior to December 31, 2017; or
6.25: 1.00, for the period ended after December 31, 2017 and on or prior to December 31, 2018; or
6.00: 1.00, for the period ended after December 31, 2018;
certain limitations on indebtedness, including payments and amendments;
certain limitations on entering into mergers, consolidations, sales of assets and investments;
limitations on granting liens; and
prohibitions on making any dividend to shareholders if an event of default exists or would exist upon making such dividend.

As of December 31, 2017, we had $125 million outstanding under our credit facility, $240 million outstanding under our commercial paper program and $107 million in letters of credit. Our availability under this facility as of December 31, 2017 was $4,528 million. As of December 31, 2017, we were in compliance with all required covenants.

KML

On June 16, 2017, KML’s indirect subsidiaries, Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC, entered into a definitive credit agreement establishing (i) a C$4.0 billion revolving construction facility for the purposes of funding the development, construction and completion of the TMEP, (ii) a C$1.0 billion revolving contingent credit facility for the purpose of funding, if necessary, additional TMEP costs (and, subject to the need to fund such additional costs, meeting the Canadian NEB-mandated liquidity requirements) and (iii) a C$500 million revolving working capital facility to be used for working capital and other general corporate purposes (collectively, the “KML Credit Facility”). On January 23, 2018, KML entered into an agreement amending certain terms of its Credit Facility to, among other things, provide additional funding certainty with respect to each tranche of its Credit Facility. The KML Credit Facility has a five-year term and is with a syndicate of financial institutions with Royal Bank of Canada as the administrative agent. Any undrawn commitments under the KML Credit Facility will incur a standby fee of 0.30% to 0.625%, with the range dependent on the credit ratings of Kinder Morgan Cochin ULC or KML. The KML Credit Facility is guaranteed by KML and all of the non-borrower subsidiaries of KML and are secured by a first lien security interest on all of the assets of KML and the equity and assets of the other guarantors.

Draw downs of funds on the KML Credit Facility bear interest dependent on the type of loans requested and are as follows:

bankers’ acceptances or LIBOR loans are at an annual rate of approximately Canadian Dealer Offered Rate (CDOR);
or the LIBOR, as the case may be, plus a fixed spread ranging from 1.50% to 2.50%;
loans in Canadian dollars or U.S. dollars are at an annual rate of approximately the Canadian prime rate or the U.S. dollar base rate, as the case may be, plus a fixed spread ranging from 0.50% to 1.50%, in each case, with the range dependent on the credit ratings of KML; and
letters of credit (under the working capital facility only) will have issuance fees based on an annual rate of approximately CDOR plus a fixed spread ranging from 1.50% to 2.50%, with the range dependent on the credit ratings of the Company.

The foregoing rates and fees will increase by 0.25% upon the fourth anniversary of the KML Credit Facility.

The KML Credit Facility includes various financial and other covenants including:

a maximum ratio of consolidated total funded debt to consolidated capitalization of 70%;
restrictions on ability to incur debt;
restrictions on ability to make dispositions, restricted payments and investments;
restrictions on granting liens and on sale-leaseback transactions;
restrictions on ability to engage in transactions with affiliates; and
restrictions on ability to amend organizational documents and engage in corporate reorganization transactions.

As of December 31, 2017, KML had C$447 million available under its five year C$500 million working capital facility (after reducing the capacity for the C$53.0 million (U.S.$42 million) in letters of credit) and no amounts outstanding under its C$4.0 billion construction facility or its C$1.0 billion revolving contingent credit facility. As of December 31, 2017, KML was in compliance with all required covenants.


Current Portion of Debt
The primaryfollowing table details the components of our current“Current portion of debt include the following significant series of long-term notes (in millions):
debt” reported on our consolidated balance sheets:
As of December 31, 2017$750Kinder Morgan Finance Company, LLC, 6.00% senior notes due January 2018
$827.00% senior notes due February 2018
$975KMP 5.95% senior notes due February 2018
$4777.25% senior notes due June 2018
As of December 31, 2016$600KMP 6.00% senior notes due February 2017
$300TGP 7.50% senior notes due April 2017
$355EPNG 5.95% senior notes due April 2017
$7867.00% senior notes due June 2017
$5002.00% senior notes due December 2017
December 31,
20232022
(In millions)
$3.5 billion credit facility due August 20, 2027— — 
$500 million credit facility due November 16, 2023— — 
Commercial paper notes1,989 — 
Current portion of senior notes
3.15%, due January 2023(a)— 1,000 
Floating rate, due January 2023(b)— 250 
3.45%, due February 2023— 625 
3.50%, due September 2023— 600 
5.625%, due November 2023— 750 
4.15%, due February 2024(c)650 — 
4.30%, due May 2024600 — 
4.25%, due September 2024650 — 
Trust I Preferred Securities, 4.75% due March 2028(d)111 111 
Current portion of other debt49 49 
Total current portion of debt$4,049 $3,385 

Subsequent Event—Debt Repayments

In(a)On January 2018,17, 2023, we repaid $750 million of maturing 6.00% Kinder Morgan Finance Company, LLCthese senior notes using cash on hand and inshort-term borrowings.
(b)These senior notes had an associated floating-to-fixed interest rate swap agreement which was designated as a cash flow hedge.
(c)On February 2018,1, 2024, we repaid $82 million of maturing 7.00%these senior notes both listed above in currentusing cash on hand and short-term borrowings.
(d)Reflects the portion of cash consideration payable if all the outstanding securities as of the end of the reporting period were converted by the holders.

Credit Facility and Restrictive Covenants

We have a $3.5 billion revolving credit facility due August 2027 with a syndicate of lenders, which can be increased by up to $1.0 billion if certain conditions, including the receipt of additional lender commitments, are met. Borrowings under our credit facility can be used for working capital and other general corporate purposes and as backup to our commercial paper program. We had a $500 million credit facility that expired on November 16, 2023.

We maintain a $3.5 billion commercial paper program through the private placement of short-term notes which matures in August 2027. The notes mature up to 270 days from the date of issue and are not redeemable or subject to voluntary prepayment by us prior to maturity. The notes are sold at par value less a discount representing an interest factor or if interest bearing, at par. Borrowings under our commercial paper program reduce the borrowings allowed under our credit facility.

Depending on the type of loan request, our borrowings under our credit facility bears interest at either (i) SOFR, plus (x) a credit spread adjustment and (y) an applicable margin ranging from 1.000% to 1.750% per annum based on our credit ratings or (ii) the greatest of (1) the Federal Funds Rate plus 0.5%; (2) the Prime Rate; or (3) SOFR for a one-month eurodollar loan, plus (x) a credit spread adjustment, (y) 1%, and (z) in each case, an applicable margin ranging from 0.100% to 0.750% per annum based on our credit rating. Standby fees for the unused portion of the credit facility will be calculated at a rate ranging from 0.100% to 0.250%.
Our credit facility contains financial and various other covenants that apply to us and our subsidiaries and are common in such agreements, including a maximum ratio of Consolidated Net Indebtedness to Consolidated EBITDA (as defined in the credit facility, as amended) of 5.50 to 1.00, for any four-fiscal-quarter period. Other negative covenants include restrictions on our and certain of our subsidiaries’ ability to incur debt, grant liens, make fundamental changes or engage in certain transactions with affiliates, or in the case of certain material subsidiaries, permit restrictions on dividends, distributions or making or prepayments of loans to us or any guarantor. Our credit facility also restricts our ability to make certain restricted payments if an event of default (as defined in the credit facility) has occurred and is continuing or would occur and be continuing.

102

As of December 31, 2023, we had no borrowings outstanding under our credit facility, $1,989 million borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit facility as of December 31, 2017.2023 was approximately $1.4 billion. For the years ended December 31, 2023, 2022, and 2021, we were in compliance with all required covenants.


Maturities of Debt


The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2017,2023, are summarized as follows (in millions):
follows:
Year Total
2018 $2,828
2019 2,820
2020 2,204
2021 2,422
2022 2,558
Thereafter                      24,084
Total                      $36,916
YearTotal
(In millions)
2024$4,049 
20251,566 
20261,102 
2027906 
20281,867 
Thereafter22,439 
Total$31,929 



Debt Fair Value Adjustments


The carrying value adjustment to debt securities whose fair value is being hedged is included withinfollowing table summarizes the “Debt fair value adjustments” included on our accompanying consolidated balance sheets. “Debt fair value adjustments” also include unamortized debt discount/premiums, purchase accounting debt fair value adjustments, unamortized portion of proceeds received from the early termination of interest rate swap agreements, and debt issuance costs. sheets:
December 31,
20232022
(In millions)
Purchase accounting debt fair value adjustments$430 $472 
Carrying value adjustment to hedged debt(236)(367)
Unamortized portion of proceeds received from the early termination of interest rate swap agreements(a)185 204 
Unamortized debt discounts, net(67)(68)
Unamortized debt issuance costs(125)(126)
Total debt fair value adjustments$187 $115 
(a)As of December 31, 2017,2023, the weighted-average amortization period of the unamortized premium from the termination of interest rate swaps was approximately 1611 years.

Fair Value of Financial Instruments
The following table summarizes the “Debtcarrying value and estimated fair value adjustments” included onof our accompanying consolidatedoutstanding debt balances is disclosed below:
 December 31, 2023December 31, 2022
 Carrying
value		Estimated
fair value(a)		Carrying
value		Estimated
fair value(a)
(In millions)
Total debt$32,116 $31,370 $31,788 $30,070 
(a)Included in the estimated fair value are amounts for our Trust I Preferred Securities of $207 million and $195 million as of December 31, 2023 and 2022, respectively.

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance sheets (in millions):as of both December 31, 2023 and 2022.

103
  December 31,
Debt Fair Value Adjustments 2017 2016
  Purchase accounting debt fair value adjustments $719
 $806
  Carrying value adjustment to hedged debt 115
 220
  Unamortized portion of proceeds received from the early termination of interest rate swap agreements 297
 342
  Unamortized debt discounts, net (74) (80)
  Unamortized debt issuance costs (130) (139)
Total debt fair value adjustments $927
 $1,149


Interest Rates, Interest Rate Swaps and Contingent Debt


The weighted average interest rate on all of our borrowings was 5.02%5.84% during 20172023 and 4.95%4.76% during 2016.2022. Information on our interest rate swaps is contained in Note 14 “Risk Management.”14. For information about our contingent debt agreements, see Note 13“Commitments and Contingent Liabilities—Liabilities—Contingent Debt”).


10.      Share-based Compensation and Employee Benefits

Share-based Compensation

Class P SharesCommon Stock

Following is a summary of our stock compensation plans:
Directors’ PlanLong Term Incentive Plan
Participating individualsEligible non-employee directorsEligible employees
Total number of shares of Class P common stock authorized1,190,000 63,000,000 
Vesting period6 months1 year to 10 years

Kinder Morgan, Inc. Second Amended and Restated Stock Compensation Plan for Non-Employee Directors

We have a Kinder Morgan, Inc. Second Amended and Restated Stock Compensation Plan for Non-Employee Directors in which our eligible non-employee directors participate.(Directors’ Plan).  The plan recognizes that the compensation paid to each eligible non-employee director is fixed by our board of directors (Board), generally annually, and that the compensation is payable in cash.  Pursuant to the plan, in lieu of receiving some or all of the cash compensation, each eligible non-employee director may elect annually to receive shares of Class P common stock.  Each election will be generally at or aroundDuring the first board meeting in January of each calendar year and will be effective for the entire calendar year.  An eligible director may make a new election each calendar year.  The total number of shares of Class P common stock authorized under the plan is 250,000.  During 2017, 2016 and 2015,ended December 31, 2023, we made restricted Class P common stock grants to our non-employee directors of 17,740, 31,880 and 9,580, respectively. These grants were valued at time of issuance at $400,000, $400,000 and $401,000, respectively. All of the restricted stock awards made to non-employee directors vest during a six-month period.11,220.



Kinder Morgan, Inc. 20152021 Amended and Restated Stock Incentive Plan

TheWe also have a Kinder Morgan, Inc. 20152021 Amended and Restated Stock Incentive Plan is an equity awards plan available to eligible employees.  The total number of shares of Class P common stock authorized under the plan is 33,000,000.(Long Term Incentive Plan).  The following table sets forth a summary of activity and related balances ofunder our restricted stock awards excluding that issued to non-employee directors (in millions, except share and per share amounts):Long Term Incentive Plan:
SharesWeighted Average Grant Date Fair Value per Share
(In thousands, except per share amounts)
Outstanding at December 31, 202213,288 $16.87 
Granted5,253 17.41 
Vested(5,226)16.09 
Forfeited(454)17.03 
Outstanding at December 31, 202312,861 $17.41 

104
 Year Ended Year Ended Year Ended
 December 31, 2017 December 31, 2016 December 31, 2015
 Shares Weighted Average
Grant Date
Fair Value		 Shares Weighted Average
Grant Date
Fair Value		 Shares 
Weighted Average
Grant Date
Fair Value
Outstanding at beginning of period9,038,137
 $32.72
 7,645,105
 $37.91
 7,373,294
 $37.63
Granted                                                      3,221,691
 19.52
 2,816,599
 21.36
 1,488,467
 38.20
Vested(1,501,939) 36.67
 (1,226,652) 38.53
 (817,797) 35.66
Forfeited                                                      (239,545) 28.34
 (196,915) 35.74
 (398,859) 38.51
Outstanding at end of period                                                      10,518,344
 $28.21
 9,038,137
 $32.72
 7,645,105
 $37.91


The intrinsic value of restricted stock awards vested during the years ended December 31, 2017, 2016 and 2015 was $30 million, $25 million and $31 million, respectively. Restricted stock awards made to employees have vesting periods ranging from 1 year with variable vesting dates to 10 years. Following is a summary of the future vesting of our outstanding restricted stock awards:
Year Vesting of Restricted Shares
2018 2,272,019
2019 4,268,118
2020 3,647,967
2021 199,850
2022 65,928
Thereafter 64,462
Total Outstanding 10,518,344

The related compensation costs less estimated forfeitures is generally recognized ratably over the vesting period of the restricted stock awards.  Upon vesting, the grants will be paid in our Class P common shares.
During 2017, 2016 and 2015, we recorded $65 million, $66 million and $52 million, respectively, in expensefollowing tables set forth additional information related to restricted stock awards and capitalized approximately $9 million, $9 million and $15 million, respectively.  At December 31, 2017 and 2016, unrecognized restricted stock awards compensation costs, less estimated forfeitures, was approximately $112 million and $133 million, respectively.our Long Term Incentive Plan:

Year Ended December 31,
202320222021
(In millions, except per share amounts)
Weighted average grant date fair value per share$17.41 $17.31 $17.44 
Intrinsic value of awards vested during the year93 47 77 
Restricted stock awards expense(a)63 60 59 
Restricted stock awards capitalized(a)10 9 9 
(a)We allocate labor and benefit costs to joint ventures that we operate in accordance with our partnership agreements.
December 31, 2023
Unrecognized restricted stock awards compensation costs, less estimated forfeitures (in millions)
$117 
Weighted average remaining amortization period2.06 years
KML Restricted Shares

KML adopted the 2017 Restricted Share Unit Plan for Employees, an equity awards plan, for its eligible employees, and the 2017 Restricted Share Unit Plan for Non-Employee Directors, in which its eligible non-employee directors participate.During the year ended December 31, 2017, we recognized $1 million of expense and capitalized $1 million related to these compensation programs. At December 31, 2017, unrecognized compensation costs, less estimated forfeitures associated with KML’s restricted share unit awards, was approximately $8 million.


Pension and Other Postretirement Benefit (OPEB) Plans


Savings Plan


We maintain a defined contribution plan covering eligible U.S. employees. We contribute 5% of eligible compensation for most of the plan participants. Certain collectively bargained participants receive Company contributions in accordance with collective bargaining agreements. A participant becomes fully vested in Company contributions after two years and may take a distribution upon termination of employment or retirement. The total cost for our savings plan was approximately $47$53 million, $47$51 million and $46

$48 million for the years ended December 31, 2017, 20162023, 2022 and 2015,2021, respectively.


Pension Plans


Our U.S. pension plans are defined benefit plans that cover substantially all of our U.S. employees and provide benefits under a cash balance formula. A participant in the cash balance formula accrues benefits through contribution credits based on a combination of age and years of service, multiplied by eligible compensation. Interest is also credited to the participant’s plan account. A participant becomes fully vested in the plan after three years and may take a lump sum or annuity distribution upon termination of employment or retirement. Certain collectively bargained and grandfathered employees accrue benefits through career pay or final pay formulas.


TwoIn 2023, we settled approximately $179 million of the retiree benefit obligation for our subsidiaries, Kinder Morgan Canada Inc. and Trans Mountain Pipeline ULC (as general partner of Trans Mountain Pipeline L.P.), are sponsors of pension plans for eligible Canadian and Trans Mountain pipeline employees.through an annuity purchase. The plans include registered defined benefit pension plans, supplemental unfunded arrangements (which provide pension benefits in excessimpact of statutory limits) and defined contributory plans. Benefits under the defined benefit components accrue through career pay or final pay formulas. The net periodic benefit costs, contributions and liability amounts associated with our Canadian plans are not material to our consolidated income statements or balance sheets; however, we began to include the activity and balances associated with our Canadian plans (including our Canadian OPEB plans discussed below)annuity purchase is reflected in the following disclosures on a prospective basis beginning in 2016. For the year ended December 31, 2015, the associated net periodic2023 benefit costsobligation for these combined Canadian plans of $12 million were reported separately.our pension plans.


Other Postretirement BenefitOPEB Plans


We and certain of our U.S. subsidiaries provide other postretirementOPEB benefits, (OPEB), including medical benefits for closed groups of retired employees and certain grandfathered employees and their dependents, and limited postretirement life insurance benefits for retired employees. Our Canadian subsidiaries also provide OPEB benefits to current and future retirees and their dependents. The U.S.These plans provide a fixed subsidy to post-age 65 Medicare eligible participants to purchase coverage through a retiree Medicare exchange. Medical benefits under these OPEB plans may be subject to deductibles, co-payment provisions, dollar caps and other limitations on the amount of employer costs, and we reserve the right to change these benefits.


Additionally, our subsidiary SFPP has incurred certain liabilities for postretirement benefits to certain current and former employees, their covered dependents, and their beneficiaries. However, the net periodic benefit costs, contributions and liability amounts associated with the SFPP postretirement benefit plan are not material to our consolidated income statements or balance sheets.
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Benefit Obligation, Plan Assets and Funded Status. The following table provides information about our pension and OPEB plans as of and for each of the years ended December 31, 20172023 and 2016 (in millions):2022:
Pension BenefitsOPEB
2023202220232022
(In millions)
Change in benefit obligation:
Benefit obligation at beginning of period$2,077 $2,658 $195 $257 
Service cost55 55 1 1 
Interest cost107 57 10 5 
Actuarial loss (gain)14 (503)(6)(44)
Benefits paid(132)(190)(25)(26)
Participant contributions— — 1 1 
Settlements(219)— — — 
Other— — 1 1 
Benefit obligation at end of period1,902 2,077 177 195 
Change in plan assets:   
Fair value of plan assets at beginning of period1,741 2,231 302 382 
Actual return on plan assets122 (350)44 (63)
Employer contributions50 50 — 7 
Participant contributions— — 1 1 
Benefits paid(132)(190)(25)(26)
Settlements(219)— — — 
Other— — 1 1 
Fair value of plan assets at end of period1,562 1,741 323 302 
Funded status - net (liability) asset at December 31,$(340)$(336)$146 $107 
Amounts recognized in the consolidated balance sheets:
Non-current benefit asset(a)$— $— $263 $239 
Current benefit liability— — (14)(15)
Non-current benefit liability(340)(336)(103)(117)
Funded status - net (liability) asset at December 31,$(340)$(336)$146 $107 
Amounts of pre-tax accumulated other comprehensive (loss) income recognized in the consolidated balance sheets:
Unrecognized net actuarial (loss) gain$(384)$(455)$149 $135 
Unrecognized prior service (cost) credit— (1)3 4 
Accumulated other comprehensive (loss) income$(384)$(456)$152 $139 
Information related to plans whose accumulated benefit obligations exceeded the fair value of plan assets:
Accumulated benefit obligation$1,870 $2,047 $119 $167 
Fair value of plan assets1,562 1,741 2 34 
 Pension Benefits OPEB
 2017 2016 2017 2016
Change in benefit obligation:       
Benefit obligation at beginning of period$2,884
 $2,654
 $473
 $509
Service cost40
 36
 1
 1
Interest cost88
 89
 13
 16
Actuarial loss (gain)155
 127
 (16) (42)
Benefits paid(180) (180) (38) (41)
Participant contributions3
 3
 2
 2
Medicare Part D subsidy receipts—
 —
 1
 1
Exchange rate changes13
 4
 1
 1
Settlements(21) —
 —
 —
Other(a)—
 151
 (12) 26
   Benefit obligation at end of period2,982
 2,884
 425
 473
Change in plan assets:       
Fair value of plan assets at beginning of period2,160
 2,050
 332
 325
Actual return on plan assets292
 157
 29
 29
Employer contributions32
 8
 9
 16
Participant contributions3
 3
 2
 2
Medicare Part D subsidy receipts—
 —
 1
 1
Benefits paid(180) (180) (38) (41)
Exchange rate changes10
 3
 —
 —
Settlements(21) —
 —
 —
Other(a)—
 119
 —
 —
Fair value of plan assets at end of period2,296
 2,160
 335
 332
Funded status - net liability at December 31,$(686) $(724) $(90) $(141)
_______
(a)2017 amounts represent December 31, 2016 balances associated with our Plantation Pipeline OPEB plan that are no longer included in these disclosures. 2016 amounts primarily represent December 31, 2015 balances associated with our Canadian pension and OPEB plans for prospective inclusion in these disclosures, which associated net periodic benefit costs were reported separately in years prior to 2016.

Components(a)2023 and 2022 OPEB amounts include $53 million and $45 million, respectively, of Funded Status. The following table details the amounts recognized in our balance sheets at December 31, 2017 and 2016non-current benefit assets related to our pensiona plan we sponsor which is associated with employee services provided to an unconsolidated joint venture, and OPEB plans (in millions):for which we have recorded an offsetting related party deferred credit.

 Pension Benefits OPEB
 2017 2016 2017 2016
Non-current benefit asset(a)$—
 $—
 $198
 $153
Current benefit liability—
 —
 (15) (16)
Non-current benefit liability(686) (724) (273) (278)
   Funded status - net liability at December 31,$(686) $(724) $(90) $(141)
_______
(a)2017 and 2016 OPEB amounts include $33 million and $29 million, respectively, of non-current benefit assets related to a plan we sponsor which is associated with employee services provided to an unconsolidated joint venture, and for which we have recorded an offsetting related party deferred credit.


Components of Accumulated Other Comprehensive (Loss) Income. The following table details the amounts of pre-tax accumulated other comprehensive (loss) income at December 31, 2017 and 2016 related to our pension and OPEB plans which are included on our accompanying consolidated balance sheets, including the portion attributable to our noncontrolling interests, (in millions):
 Pension Benefits OPEB
 2017 2016 2017 2016
Unrecognized net actuarial (loss) gain$(635) $(682) $88
 $69
Unrecognized prior service (cost) credit                                                                         (4) (5) 17
 18
Accumulated other comprehensive (loss) income$(639) $(687) $105
 $87

We anticipate that approximately $34 million of pre-tax accumulated other comprehensive loss, inclusive of amounts reported as noncontrolling interests, will be recognized as part of our net periodic benefit cost in 2018, including approximately $36 million of unrecognized2023 net actuarial loss and approximately $2 million of unrecognized prior service credit.

Our accumulated benefit obligation for ourthe pension plans was $2,840 million and $2,834 million atprimarily due to a decrease in the weighted average discount rate used to determine the benefit obligation as of December 31, 2017 and 2016, respectively.

Our accumulated postretirement2023. The 2023 net actuarial gain for the OPEB plans was primarily due to changes in the claims cost assumptions. The 2022 net actuarial gain for the pension plans was primarily due to an increase in the weighted average discount rate used to determine the benefit obligation as of December 31, 2022. The 2022 net actuarial
106

gain for ourthe OPEB plans whose accumulated postretirementwas primarily due to an increase in the weighted average discount rate used to determine the benefit obligations exceeded the fair valueas of plan assets, was $373 million and $415 million at December 31, 20172022 and 2016, respectively. The fair value of these plans’ assets was approximately $84 million and $121 million at December 31, 2017 and 2016, respectively.changes in the claims cost assumptions.


Plan Assets. The investment policies and strategies are established by the Fiduciary Committeeour plan’s fiduciary committee for the assets of each of the U.S. pension and OPEB plans, and by the Pension Committee for the assets of the Canadian pension plans (the “Committees”), which are responsible for investment decisions and management oversight of the plans. The stated philosophy of each of the Committeesfiduciary committee is to manage these assets in a manner consistent with the purpose for which the plans were established and the time frame over which the plans’ obligations need to be met. The objectives of the investment management program are to (1)(i) meet or exceed plan actuarial earnings assumptions over the long term and (2)(ii) provide a reasonable return on assets within established risk tolerance guidelines and to maintain the liquidity needs of the plans with the goal of paying benefit and expense obligations when due. In seeking to meet these objectives, the Committees recognizefiduciary committee recognizes that prudent investing requires taking reasonable risks in order to raise the likelihood of achieving the targeted investment returns. In order to reduce portfolio risk and volatility, the Committees have eachfiduciary committee has adopted a strategy of using multiple asset classes.


As of December 31, 2017, theThe allowable range for asset allocations in effect for our U.S. pension plan were 34% to 59% equity, 37% to 57% fixed income, 0% to 5% cash, 0% to 2% alternative investments and 0% to 10% company securities (KMI Class P common stock and/or debt securities).  Asplans as of December 31, 2017, the allowable range for2023, by asset allocations in effect for our U.S. retiree medical and retiree life insurance plans were 15% to 55% equity, 15% to 47% fixed income, 0% to 20% cash and 13% to 39% MLPs. As of December 31, 2017, the target asset allocation for our Canadian pension plans thatcategory, are closed to new participants was 90% fixed income and 10% equity. The target allocation for the remaining Canadian pension plans were 45% fixed income and 55% equity.as follows:

Pension BenefitsOPEB
Cash0% to 23%
Equities42% to 52%43% to 71%
Fixed income securities37% to 47%26% to 50%
Real estate2% to 12%
Company securities (KMI Class P common stock and/or debt securities)0% to 10%

Below are the details of our pension and OPEB plan assets by class and a description of the valuation methodologies used for assets measured at fair value.


•Level 1 assets’ fair values are based on quoted market prices for the instruments in actively traded markets. Included in this level are cash, equities and exchange traded mutual funds and MLPs.funds. These investments are valued at the closing price reported on the active market on which the individual securities are traded.


•Level 2 assets’ fair values are primarily based on pricing data representative of quoted prices for similar assets in active markets (or identical assets in less active markets). Included in this level are short-term investment funds, fixed income securities and derivatives. Short-term investment funds are valued at amortized cost, which approximates fair value. The fixed income securities’ fair values are primarily based on an evaluated price which is based on a compilation of primarily observable market information or a broker quote in a non-active market. Derivatives are exchange-traded through clearinghouses and are valued based on these prices.


Level 3 assets’ fair values are calculated using valuation techniques that require inputs that are both significant to the fair value measurement and are unobservable, or are similar to Level 2 assets. Included in this level are guaranteed

insurance contracts and immediate participation guarantee contracts. These contracts are valued at contract value, which approximates fair value.

•Plan assets with fair values that are based on the net asset value per share, or its equivalent (NAV), as a practical expedient to measure fair value, as reported by the issuers are determined based on the fair value of the underlying securities as of the valuation date and include common/collective trust funds, private investment funds, real estate and limited partnerships, and fixed income trusts.partnerships. The plan assets measured at NAV are not categorized within the fair value hierarchy described above, but are separately identified in the following tables.


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Listed below are the fair values of our pension and OPEB plans’ assets that are recorded at fair value by class and categorized by fair value measurement used at December 31, 20172023 and 2016 (in millions):2022:
Pension Assets
20232022
Level 1Level 2TotalLevel 1Level 2Total
(In millions)
Measured within fair value hierarchy
Short-term investment funds$— $32 $32 $— $27 $27 
Equities(a)143 — 143 152 — 152 
Fixed income securities— 410 410 — 421 421 
Subtotal$143 $442 585 $152 $448 600 
Measured at NAV
Common/collective trusts(b)976 1,138 
Private limited partnerships(c)1 3 
Subtotal977 1,141 
Total plan assets fair value$1,562 $1,741 
 Pension Assets
 2017 2016
 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Measured within fair value hierarchy               
Cash$6
 $—
 $—
 $6
 $10
 $—

$—
 $10
Short-term investment funds—
 65
 —
 65
 —
 100

—
 100
Mutual funds(a)245
 —
 —
 245
 197
 —
 —
 197
Equities(b)278
 —
 —
 278
 283
 —

—
 283
Fixed income securities(c)—
 416
 —
 416
 —
 428

—
 428
Immediate participation guarantee contract—
 —
 —
 —
 —
 —

16
 16
Derivatives—
 5
 —
 5
 —
 (2) —
 (2)
Subtotal$529
 $486
 $—
 1,015
 $490
 $526
 $16
 1,032
Measured at NAV(d)               
Common/collective trusts(e)      895
       829
Private investment funds(f)      337
       290
Private limited partnerships(g)      49
       9
Subtotal

 

 

 1,281
 

 

 

 1,128
Total plan assets fair value

 

 

 $2,296
 

 

 

 $2,160
(a)Plan assets include $107 and $110 of KMI Class P common stock for 2023 and 2022, respectively.
_______(b)Common/collective trust funds were invested in approximately 64% equities, 23% fixed income securities and 13% real estate in 2023 and 66% equities, 22% fixed income securities and 12% real estate in 2022.
(a)Includes mutual funds which are invested in equity.
(b)Plan assets include $110 million
(c)Includes assets invested in real estate, venture and buyout funds.
OPEB Assets
20232022
Level 1Level 2TotalLevel 1Level 2Total
(In millions)
Measured within fair value hierarchy
Short-term investment funds$— $5 $5 $— $3 $3 
Measured at NAV
Common/collective trusts(a)318 299 
Total plan assets fair value$323 $302 
(a)Common/collective trust funds were invested in approximately 62% equities and 38% fixed income securities for 2023 and 61% equities and 39% fixed income securities for 2022.

Employer Contributions and $126 million of KMI Class P common stock for 2017 and 2016, respectively.
(c)
For 2016, plan assets include $1 million of KMI debt securities.
(d)Plan assets for which fair value was measured using NAV as a practical expedient.
(e)Common/collective trust funds were invested in approximately 36% fixed income and 64% equity in 2017 and 39% fixed income and 61% equity in 2016.
(f)Private investment funds were invested in approximately 52% fixed income and 48% equity in 2017 and 54% fixed income and 46% equity in 2016.
(g)Includes assets invested in real estate, venture and buyout funds. 2016 also includes high yield investments.


 OPEB Assets
 2017 2016
 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Measured within fair value hierarchy               
Short-term investment funds$—
 $7
 $—
 $7
 $—
 $15
 $—
 $15
Equities(a)16
 —
 —
 16
 11
 —
 —
 11
MLPs50
 —
 —
 50
 57
 —
 —
 57
Guaranteed insurance contracts—
 —
 49
 49
 —
 —
 47
 47
Mutual funds1
 —
 —
 1
 1
 —
 —
 1
Subtotal$67
 $7
 $49
 123
 $69
 $15
 $47
 131
Measured at NAV(b)               
Common/collective trusts(c)      68
       68
Fixed income trusts      66
       64
Limited partnerships(d)      78
       69
Subtotal      212
       201
Total plan assets fair value

 

 

 $335
 

 

 

 $332
_______
(a)Plan assets include $2 million of KMI Class P common stock for each 2017 and 2016.
(b)Plan assets for which fair value was measured using NAV as a practical expedient.
(c)Common/collective trust funds were invested in approximately 71% equity and 29% fixed income securities for 2017 and 72% equity and 28% fixed income securities for 2016.
(d)Limited partnerships were invested in global equity securities.

The following tables present the changes in our pension and OPEB plans’ assets included in Level 3 for the years ended December 31, 2017 and 2016 (in millions):
 Pension Assets
 Balance at Beginning of Period Transfers In (Out) Realized and Unrealized Gains (Losses), net Purchases (Sales), net Balance at End of Period
2017         
Insurance contracts$16
 $—
 $—
 $(16) $—
          
2016         
Insurance contracts$15
 $—
 $1
 $—
 $16
 OPEB Assets
 Balance at Beginning of Period Transfers In (Out) Realized and Unrealized Gains (Losses), net Purchases (Sales), net Balance at End of Period
2017         
    Insurance contracts$47
 $—
 $5
 $(3) $49
          
2016         
    Insurance contracts$49
 $—
 $(2) $—
 $47

Changes in the underlying value of Level 3 assets due to the effect of changes of fair value were immaterial for the years ended December 31, 2017 and 2016.

Expected Payment of Future Benefits and Employer Contributions. As of December 31, 2017,2023, we expect to make the following benefit paymentscash flows under our plans (in millions):plans:
Pension BenefitsOPEB
(In millions)
Contributions expected in 2024$50 $— 
Benefit payments expected in:
2024$190 $24 
2025187 22 
2026185 21 
2027179 19 
2028175 18 
2029 - 2033777 67 

108

Fiscal year Pension Benefits OPEB(a)
2018 $244
 $36
2019 241
 36
2020 242
 35
2021 232
 34
2022 230
 33
2023 - 2027 1,029
 149
_______
(a)
Includes a reduction of approximately $2 million in each of the years 2018 - 2022 and approximately $13 million in aggregate for 2023 - 2027 for an expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.

In 2018, we expect to contribute approximately $30 million to our U.S. pension plans and $7 million, net of anticipated subsidies, to our U.S. OPEB plans. In 2018, we expect to contribute approximately $10 million to our Canadian pension plans and $1 million to our Canadian OPEB plan.

Actuarial Assumptions and Sensitivity Analysis. Benefit obligations and net benefit cost are based on actuarial estimates and assumptions. The following table details the weighted-average actuarial assumptions used in determining our benefit obligation as of December 31, 2023 and 2022 and net benefit costs of our pension and OPEB plans for 2017, 20162023, 2022 and 2015:2021:
Pension BenefitsOPEB
2023202220232022
Assumptions related to benefit obligations:
Discount rate5.13 %5.41 %5.08 %5.38 %
Rate of compensation increase3.50 %3.50 %n/an/a
Interest crediting rate3.85 %3.50 %n/an/a
Pension BenefitsOPEB
202320222021202320222021
Assumptions related to benefit costs:
Discount rate5.41 %2.74 %2.27 %5.38 %2.56 %2.08 %
Expected return on plan assets7.00 %6.50 %6.25 %6.00 %5.75 %5.75 %
Rate of compensation increase3.50 %3.50 %3.50 %n/an/an/a
Interest crediting rate3.50 %3.01 %2.57 %n/an/an/a
  Pension Benefits OPEB
  2017 2016 2015 2017 2016 2015
Assumptions related to benefit obligations:            
Discount rate 3.56% 3.83% 4.05% 3.48% 3.69% 3.91%
Rate of compensation increase 3.53% 3.52% 3.50% n/a
 n/a
 n/a
Assumptions related to benefit costs:            
Discount rate for benefit obligations 3.83% 4.05% 3.66% 3.69% 3.91% 3.56%
Discount rate for interest on benefit obligations 3.09% 3.24% 3.66% 3.05% 3.18% 3.56%
Discount rate for service cost 3.88% 4.15% 3.66% 4.15% 4.36% 3.56%
Discount rate for interest on service cost 3.24% 3.50% 3.66% 3.95% 4.17% 3.56%
Expected return on plan assets(a) 7.07% 7.31% 7.50% 6.84% 7.07% 7.08%
Rate of compensation increase 3.52% 3.51% 4.50% n/a
 n/a
 n/a

_______
(a)
The expected return on plan assets listed in the table above is a pre-tax rate of return based on our targeted portfolio of investments. For the OPEB assets subject to unrelated business income taxes (UBIT), we utilize an after-tax expected return on plan assets to determine our benefit costs, which is based on a UBIT rate of 21% for 2017, 2016 and 2015.

Prior to 2016, we selected our discount rates by matching the timing and amount of our expected future benefit payments for our pension and other postretirement benefit obligations to the average yields of various high-quality bonds with corresponding maturities. Effective January 1, 2016, we changed our estimate ofWe utilize a full yield curve approach in estimating the service and interest cost components of net periodic benefit cost (credit) for our pension and other postretirementretirement benefit plans. The new estimate utilizes a full yield curve approach in the estimation of these componentsplans by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to their underlying projected cash flows. The new estimate provides a more precise

measurement of service and interest costs by improving the correlation between projected benefit cash flows and their corresponding spot rates. The change did not affect the measurement of our pension and postretirement benefit obligations and it was accounted for as a change in accounting estimate, which was applied prospectively. The expected long-term rates of return on plan assets were determined by combining a review of the historical returns realized within the portfolio, the investment strategy included in the plans’ investment policy, and capital market projections for the asset classes in which the portfolio is invested and the target weightings of each asset class. The expected return on plan assets listed in the table above is a pre-tax rate of return based on our targeted portfolio of investments. For the OPEB assets subject to unrelated business income taxes, we utilize an after-tax expected return on plan assets to determine our benefit costs.


Actuarial estimates for our OPEB plans assumed a weighted-averageassume an annual rate of increase in the per capita cost of covered health care benefitsbenefits. The initial annual rate of 7.71%,increase is 5.60% which gradually decreasingdecreases to 4.54%4.00% by the year 2038. Assumed health care cost trends have a significant effect on the amounts reported for OPEB plans. A one-percentage point change in assumed health care cost trends would have the following effects as of December 31, 2017 and 2016 (in millions):2047.

109

  2017 2016
One-percentage point increase:    
Aggregate of service cost and interest cost $1
 $1
Accumulated postretirement benefit obligation 22
 27
One-percentage point decrease:    
Aggregate of service cost and interest cost $(1) $(1)
Accumulated postretirement benefit obligation (19) (23)


Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income. Income. For each of the years ended December 31, the components of net benefit cost and other amounts recognized in pre-tax other comprehensive income related to our pension and OPEB plans are as follows (in millions):
follows:
 Pension Benefits OPEB
 2017 2016 2015 2017 2016 2015
Components of net benefit cost:            
Pension BenefitsPension BenefitsOPEB
2023202320222021202320222021
(In millions)(In millions)
Components of net benefit cost (credit):
Service cost
Service cost
Service cost $40
 $36
 $33
 $1
 $1
 $—
Interest cost 88
 89
 99
 13
 16
 21
Expected return on assets (147) (151)
(172) (19) (19) (23)
Amortization of prior service cost (credit) 1
 1

—
 (3) (3) (3)
Amortization of net actuarial loss (gain) 52
 35
 5
 (6) —
 1
Curtailment and settlement loss 5
 —
 —
 —
 —
 —
Net benefit (credit) cost(a) 39
 10
 (35) (14) (5) (4)
Settlement loss
Net benefit cost (credit)
            
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:            
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
Net loss (gain) arising during period 17
 116
 267
 (25) (48) (49)
Prior service cost (credit) arising during period —
 —
 —
 —
 —
 —
Net loss (gain) arising during period
Net loss (gain) arising during period
Amortization or settlement recognition of net actuarial (loss) gain (64) (34) (5) 6
 —
 (1)
Amortization of prior service credit (1) —
 —
 1
 1
 1
Exchange rate changes —
 1
 —
 —
 —
 —
Total recognized in total other comprehensive (income) loss (48) 83
 262
 (18) (47) (49)
Amortization or settlement recognition of net actuarial (loss) gain
Amortization or settlement recognition of net actuarial (loss) gain
Amortization of prior service (cost) credit
Total recognized in total other comprehensive (income) loss(a)
Total recognized in total other comprehensive (income) loss(a)
Total recognized in total other comprehensive (income) loss(a)
Total recognized in net benefit cost (credit) and other comprehensive (income) loss $(9) $93
 $227
 $(32) $(52) $(53)
_______
(a)2017 and 2016 OPEB amounts each include(a)Excludes $4 million and $3 million of net benefit credits related to a plan that we sponsor that is associated with employee services provided to an unconsolidated joint venture. We charge or refund these costs or credits associated with this plan to the joint venture as an offset to our net benefit cost or credit and receive our proportionate share of these costs or credits through our share of the equity investee’s earnings.

Multiemployer Plans
We participate in several multi-employer pension plans for the benefit of employees who are union members.  We do not administer these plans and contribute to them in accordance with the provisions of negotiated labor contracts.  Other benefits include a self-insured health and welfare insurance plan and an employee health plan where employees may contribute for their dependents’ health care costs.  Amounts charged to expense for these plans were approximately $8 million, $8 million and $10 million for the years ended December 31, 2017, 20162022 and 2015, respectively. We consider the overall multi-employer pension plan liability exposure to be minimal in relation to the value of its total consolidated assets and net income.2021, respectively, associated with other plans.



11.  Stockholders’ Equity
11.Stockholders’ Equity
Common Equity

As of December 31, 2017, our common equity consisted of our Class P common stock.Common Stock


On July 19, 2017, our board of directorsBoard approved a $2 billion common share buy-back program that began in December 2017. DuringOn January 18, 2023, our Board approved an increase in our share repurchase authorization to $3 billion. All shares we have repurchased are canceled and are no longer outstanding. Activity under the year ended December 31, 2017, we repurchased approximately 14 million of our Class P shares for approximately $250 million. buy-back program is as follows:
Year Ended December 31,
202320222021
(In millions, except per share amounts)
Total value of shares repurchased$522 $368 $— 
Total number of shares repurchased32 21 — 
Average repurchase price per share$16.56 $16.94 $— 

Subsequent to December 31, 20172023 and through February 8, 2018,16, 2024, we repurchased approximately 13less than 1 million shares at an average price of $16.50 for $7 million. Since December 2017, in total, we have repurchased 86 million of our Class P shares under the program at an average price of $17.09 per share for approximately $250 million.

$1,472 million, leaving capacity under the program of $1.5 billion.
On December 19, 2014, we entered into an equity distribution agreement authorizing us to issue and sell through or to the managers party thereto, as sales agents and/or principals, shares of our Class P common stock having an aggregate offering price of up to $5.0$5 billion from time to time during the term of this agreement. During the years ended December 31, 20172023, 2022 and 20162021 we did not issue any Class P common stockshares under this agreement. During the year ended December 31, 2015, we issued and sold 102,614,508 shares of our Class P common stock pursuant to the equity distribution agreement resulting in net proceeds of $3.9 billion.
 
KMI Common Stock
110

Dividends


Holders of our common stock participate in any dividend declared by our board of directors, subject to the rights of the holders of any outstanding preferred stock. The following table provides information about our per share dividends: 
Year Ended December 31,
202320222021
Per share cash dividend declared for the period$1.13 $1.11 $1.08 
Per share cash dividend paid in the period1.1250 1.1025 1.0725 
 Year Ended December 31,
 2017 2016 2015
Per common share cash dividend declared for the period$0.50
 $0.50
 $1.605
Per common share cash dividend paid in the period0.50
 0.50
 1.93


On January 17, 2018,2024, our board of directorsBoard declared a cash dividend of $0.125$0.2825 per common share for the quarterly period ended December 31, 2017,2023, which is payablewas paid on February 15, 20182024 to shareholders of record as of January 31, 2018.2024.


WarrantsAdoption of Accounting Pronouncement


DuringOn January 1, 2022, we adopted Accounting Standards Update (ASU) No. 2020-06, “Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity.” This ASU (i) simplifies an issuer’s accounting for convertible instruments by eliminating two of the three models in Subtopic 470-20 that require separate accounting for embedded conversion features, (ii) amends diluted earnings per share calculations for convertible instruments by requiring the use of the if-converted method and (iii) simplifies the settlement assessment entities are required to perform on contracts that can potentially settle in an entity’s own equity by removing certain requirements. Using the modified retrospective method, the adoption of this ASU resulted in a pre-tax adjustment of $14 million to unwind the remaining unamortized debt discount within “Debt fair value adjustments” on our consolidated balance sheet and an adjustment of $11 million to unwind the balance of the conversion feature classified in “Additional paid in capital” on our consolidated statement of stockholders’ equity for the year ended December 31, 2015, we paid a total of $12 million for2022.

Accumulated Other Comprehensive Loss

Changes in the repurchases of warrants. The warrant repurchase program dated June 12, 2015, which authorized us to repurchase up to $100 million of warrants, expired along with the warrants on May 25, 2017, at which time 293 million of unexercised warrants to buy KMI common stock expired without the issuance of Class P common stock. Prior to expiration, each of the warrants entitled the holder to purchase one sharecomponents of our common stock for an exercise price of $40 per share, payable in cash or by cashless exercise.

Mandatory Convertible Preferred Stock

On October 30, 2015, we completed an offering of 32,000,000 depositary shares, each of which represents a 1/20th interest in a share of our 1,600,000 shares of 9.75% Series A mandatory convertible preferred stock, with a liquidating preference of $1,000 per share (equal to a $50 liquidation preference per depositary share). Net proceeds, after underwriting discount and expenses, from the depositary share offering were approximately $1,541 million. The proceeds from the offering were used to repay borrowings under our revolving credit facility and commercial paper debt and for general corporate purposes.

Unless converted earlier at the option of the holders, on or around October 26, 2018, each share of convertible preferred stock will automatically convert into between 30.8800 and 36.2840 shares of our common stock (and, correspondingly, each depositary share will convert into between 1.5440 and 1.8142 shares of our common stock), subject to customary anti-dilution adjustments. The conversion range depends on the volume-weighted average price of our common stock over a 20 trading day averaging period immediately prior to that date (Applicable Market Value). If the Applicable Market Value for our common stock is greater than $32.38 or less than $27.56, the conversion rate per preferred stock will be 30.8800 or 36.2840, respectively. If the Applicable Market Value is between $32.38 and $27.56, the conversion rate per preferred stock will be between 30.8800 and 36.2840.

Preferred Stock Dividends

Dividends on our mandatory convertible preferred stock are payable on a cumulative basis when, as and if declared by our board of directors (or an authorized committee thereof) at an annual rate of 9.75% of the liquidation preference of $1,000 per share on January 26, April 26, July 26 and October 26 of each year, commencing on January 26, 2016 to, and“Accumulated other comprehensive loss” not including October 26, 2018. We may pay dividends in cash or, subject to certain limitations, in shares of common stock or any combination of cash and shares of common stock. The terms of the mandatory convertible preferred stock provide that, unless full cumulative dividends have been paid or set aside for payment on all outstanding mandatory convertible preferred stock for all prior dividend periods, no dividends may be declared or paid on common stock. The following table provides information regarding our preferred stock dividends:
PeriodTotal dividend per share for the periodDate of declarationDate of recordDate of dividend
January 26, 2017 through April 25, 2017$24.375January 18, 2017April 11, 2017April 26, 2017
April 26, 2017 through July 25, 201724.375April 19, 2017July 11, 2017July 26, 2017
July 26, 2017 through October 25, 201724.375July 19, 2017October 11, 2017October 26, 2017
October 26, 2017 through January 25, 201824.375October 18, 2017January 11, 2018January 26, 2018

The cash dividend of $24.375 per share of our mandatory convertible preferred stock is equivalent to $1.21875 per depository share.

Noncontrolling Interests

KML Restricted Voting Shares

As discussed in Note 3 “Acquisitions and Divestitures,” on May 30, 2017 our indirect subsidiary, KML, issued 102,942,000 restricted voting shares in a public offering listed on the Toronto Stock Exchange. The public ownership of the KML restricted voting shares represents an approximate 30% interest in our Canadian operations and is reflected within “Noncontrolling interests” in our consolidated financial statements as of and for the period presented after May 30, 2017.

KML Preferred Share Offerings

On August 15, 2017, KML completed an offering of 12,000,000 cumulative redeemable minimum rate reset preferred shares, Series 1 (Series 1 Preferred Shares) on the Toronto Stock Exchange at a price to the public of C$25.00 per Series 1 Preferred Share for total gross proceeds of C$300 million (U.S.$235 million). On December 15, 2017, KML completed an offering of 10,000,000 cumulative redeemable minimum rate reset preferred shares, Series 3 (Series 3 Preferred Shares) on the Toronto Stock Exchange at a price to the public of C$25.00 per Series 3 Preferred Share for total gross proceeds of C$250 million (U.S.$195 million). The net proceeds from the Series 1 and Series 3 Preferred Share offerings of C$293 million (U.S. $230 million) and C$243 million (U.S.$189 million), respectively, were used by KML to indirectly subscribe for preferred units in KMC LP, which in turn were used by KMC LP to repay the KML Credit Facility indebtedness recently incurred to, directly or indirectly, finance the development, construction and completion of the TMEP and Base Line Terminal project, and for its general corporate purposes.

KML Distributions

KML established a dividend policy pursuant to which it may pay a quarterly dividend on its restricted voting shares in an amount based on a portion of its DCF. The payment of dividends is not guaranteed and the amount and timing of any dividends payable will be at the discretion of KML’s board of directors. If declared by KML’s board of directors, KML will pay quarterly dividends, on or about the 45th day (or next business day) following the end of each calendar quarter to holders of its restricted voting shares of record as of the close of business on or about the last business day of the month following the end of each calendar quarter. KML also established a Dividend Reinvestment Plan (DRIP) which allows holders (excluding holders not resident in Canada) of restricted voting shares to elect to have any or all cash dividends payable to such shareholder automatically reinvested in additional restricted voting shares at a price per share calculated by reference to the volume-weighted average of the closing price of the restricted voting shares on the stock exchange on which the restricted voting shares

are then listed for the five trading days immediately preceding the relevant dividend payment date, less a discount of between 0% and 5% (as determined from time to time by KML’s board of directors, in its sole discretion).

Dividends on the Series 1 Preferred Shares are fixed, cumulative, preferential and C$1.3125 per share annually, payable quarterly on the 15th day of February, May, August and November, as and when declared by the KML’s board of directors, for the initial fixed rate period to but excluding November 15, 2022.

Dividends on the Series 3 Preferred Shares are fixed, cumulative, preferential and C$1.3000 per share annually, payable quarterly on the 15th day of February, May, August and November, as and when declared by the KML’s board of directors, for the initial fixed rate period to but excluding February 15, 2023.

The following table provides information regarding distributions to our noncontrolling interests (in millions except per share and share distribution amounts):are summarized as follows:
 Net unrealized
gains/(losses)
on cash flow
hedge derivatives		Pension and
other
postretirement
liability adjustments		Total
Accumulated other
comprehensive
loss
(In millions)
Balance at December 31, 2020$(13)$(394)$(407)
Other comprehensive (loss) gain before reclassifications(432)155 (277)
Losses reclassified from accumulated other comprehensive loss273 — 273 
Net current-period change in accumulated other comprehensive loss(159)155 (4)
Balance at December 31, 2021(172)(239)(411)
Other comprehensive (loss) gain before reclassifications(312)1 (311)
Losses reclassified from accumulated other comprehensive loss320 — 320 
Net current-period change in accumulated other comprehensive loss8 1 9 
Balance at December 31, 2022(164)(238)(402)
Other comprehensive gain before reclassifications155 65 220 
Gains reclassified from accumulated other comprehensive loss(35)— (35)
Net current-period change in accumulated other comprehensive loss120 65 185 
Balance at December 31, 2023$(44)$(173)$(217)

111
  Year Ended December 31, 2017
  Shares U.S.$ C$
KML Restricted Voting Shares(a)      
Per restricted voting share declared for the period(b)     $0.3821
Per restricted voting share paid in the period   $0.1739 0.2196
Total value of distributions paid in the period   18 23
Cash distributions paid in the period to the public   13 16
Share distributions paid in the period to the public under KML’s DRIP 418,989    
KML Series 1 Preferred Shares(c)      
Per Series 1 Preferred Share paid in the period   $0.2624 $0.3308
Cash distributions paid in the period to the public   3 4
_______

(a)Represents dividends subsequent to KML’s May 30, 2017 IPO.
(b)The U.S.$ equivalent of the dividends declared is calculated based on the exchange rate on the dividend payment date, therefore, the U.S.$ equivalent of the dividend declared for the fourth quarter of 2017 will be calculated using the exchange rate on February 15, 2018.
The combined U.S.$ equivalent of the dividends declared for the second and third quarters of 2017 was $0.1739.
(c)Represents dividends subsequent to the issuance of KML’s Series 1 Preferred Shares.

On January 17, 2018, KML’s board of directors declared a cash dividend of C$0.328125 per share of its Series 1 Preferred Shares for the period from and including November 15, 2017 through and including February 14, 2018, which is payable on February 15, 2018 to Series 1 Preferred Shareholders of record as of the close of business on January 31, 2018.

On January 17, 2018, KML’s board of directors declared a cash dividend of C$0.22082 per share of its Series 3 Preferred Shares for the period from and including December 15, 2017 through and including February 14, 2018, which is payable on February 15, 2018 to Series 3 Preferred Shareholders of record as of the close of business on January 31, 2018.

12.  Related Party Transactions


Affiliate Balances and Activities


We have transactions with affiliates which consist of (i) unconsolidated affiliates in which we hold an investment accounted for under the equity method of accounting (see Note 7 “Investments” for additional information related to these investments); and (ii) external joint venture partners of our proportional method joint ventures for which we include our proportionate share of balances and activity in our financial statements. consolidate.

The following tables summarize our affiliate balance sheet balances and income statement activity, (in millions):other than amounts reported within our “Investments” balances and “Earnings from equity investments” activity:

December 31,
20232022
(In millions)
Balance sheet location
Accounts receivable$45 $39 
Other current assets2 3 
$47 $42 
Current portion of debt$5 $6 
Accounts payable16 19 
Other current liabilities3 8 
Long-term debt137 142 
Other long-term liabilities and deferred credits54 47 
$215 $222 
Year Ended December 31,
202320222021
(In millions)
Income statement location
Revenues$172 $172 $164 
Operating Costs, Expenses and Other
Costs of sales$132 $134 $145 
Other operating expenses57 50 52 
 December 31,
 2017 2016
Balance sheet location   
Accounts receivable, net$34
 $37
Other current assets8
 —
Deferred charges and other assets23
 10
 $65
 $47
    
Current portion of debt$6
 $6
Accounts payable18
 28
Other current liabilities4
 9
Long-term debt155
 161
Other long-term liabilities and deferred credits35
 29
 $218
 $233

 Year Ended December 31,
 2017 2016 2015
Income statement location     
Revenues     
Services$73
 $71
 $72
Product sales and other89
 71
 71
 $162
 $142
 $143
      
Operating Costs, Expenses and Other     
Costs of sales$20
 $38
 $60
Other operating expenses100
 75
 55

13.  Commitments and Contingent Liabilities
 
Rights-Of-Way

Our rights-of-way obligations primarily consist of non-lease agreements that existed at the time of Topic 842, Leases, and Rights-of-Way Obligations
The table below depictsadoption, at which time we elected a practical expedient which allowed us to continue our historical treatment. Our future gross minimum rental commitments underrelated to our operating leases and rights-of-way obligations were $98 million as of December 31, 2017 (in millions):2023.

Year Commitment
2018 $118
2019 106
2020 81
2021 62
2022 55
Thereafter 300
Total minimum payments $722

The remaining terms on our operating leases, including probable elections to exercise renewal options, range fromone to forty-one years. Total lease and rental expenses were$140 million, $138 million and $143 million for the years ended December 31, 2017, 2016 and 2015, respectively. The amount of capital leases included within “Property, plant and equipment, net” in our accompanying consolidated balance sheets as of December 31, 2017 and 2016 is not material to our consolidated balance sheets.

Fair Value of Financial Instruments
The carrying value and estimated fair value of our outstanding debt balances is disclosed below:
 December 31, 2023December 31, 2022
 Carrying
value		Estimated
fair value(a)		Carrying
value		Estimated
fair value(a)
(In millions)
Total debt$32,116 $31,370 $31,788 $30,070 
(a)Included in the estimated fair value are amounts for our Trust I Preferred Securities of $207 million and $195 million as of December 31, 2023 and 2022, respectively.

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both December 31, 2023 and 2022.

103

Interest Rates, Interest Rate Swaps and Contingent Debt


The weighted average interest rate on all of our borrowings was 5.84% during 2023 and 4.76% during 2022. Information on our interest rate swaps is contained in Note 14. For information about our contingent debt agreements, see Note 13“Commitments and Contingent Liabilities—Contingent Debt”).

10.      Share-based Compensation and Employee Benefits

Share-based Compensation

Class P Common Stock

Following is a summary of our stock compensation plans:
Directors’ PlanLong Term Incentive Plan
Participating individualsEligible non-employee directorsEligible employees
Total number of shares of Class P common stock authorized1,190,000 63,000,000 
Vesting period6 months1 year to 10 years

Kinder Morgan, Inc. Second Amended and Restated Stock Compensation Plan for Non-Employee Directors

We have a Kinder Morgan, Inc. Second Amended and Restated Stock Compensation Plan for Non-Employee Directors (Directors’ Plan).  The plan recognizes that the compensation paid to each eligible non-employee director is fixed by our board of directors (Board), generally annually, and that the compensation is payable in cash.  Pursuant to the plan, in lieu of receiving some or all of the cash compensation, each eligible non-employee director may elect annually to receive shares of Class P common stock.  During the year ended December 31, 2023, we made restricted Class P common stock grants to our non-employee directors of 11,220.

Kinder Morgan, Inc. 2021 Amended and Restated Stock Incentive Plan

We also have a Kinder Morgan, Inc. 2021 Amended and Restated Stock Incentive Plan (Long Term Incentive Plan).  The following table sets forth a summary of activity and related balances under our Long Term Incentive Plan:
SharesWeighted Average Grant Date Fair Value per Share
(In thousands, except per share amounts)
Outstanding at December 31, 202213,288 $16.87 
Granted5,253 17.41 
Vested(5,226)16.09 
Forfeited(454)17.03 
Outstanding at December 31, 202312,861 $17.41 

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The following tables set forth additional information related to our Long Term Incentive Plan:
Year Ended December 31,
202320222021
(In millions, except per share amounts)
Weighted average grant date fair value per share$17.41 $17.31 $17.44 
Intrinsic value of awards vested during the year93 47 77 
Restricted stock awards expense(a)63 60 59 
Restricted stock awards capitalized(a)10 9 9 
(a)We allocate labor and benefit costs to joint ventures that we operate in accordance with our partnership agreements.
December 31, 2023
Unrecognized restricted stock awards compensation costs, less estimated forfeitures (in millions)
$117 
Weighted average remaining amortization period2.06 years

Pension and Other Postretirement Benefit (OPEB) Plans

Savings Plan

We maintain a defined contribution plan covering eligible U.S. employees. We contribute 5% of eligible compensation for most of the plan participants. Certain collectively bargained participants receive Company contributions in accordance with collective bargaining agreements. A participant becomes fully vested in Company contributions after two years and may take a distribution upon termination of employment or retirement. The total cost for our savings plan was approximately $53 million, $51 million and $48 million for the years ended December 31, 2023, 2022 and 2021, respectively.

Pension Plans

Our contingent debt disclosures pertainpension plans are defined benefit plans that cover substantially all of our U.S. employees and provide benefits under a cash balance formula. A participant in the cash balance formula accrues benefits through contribution credits based on a combination of age and years of service, multiplied by eligible compensation. Interest is also credited to the participant’s plan account. A participant becomes fully vested in the plan after three years and may take a lump sum or annuity distribution upon termination of employment or retirement. Certain collectively bargained and grandfathered employees accrue benefits through career pay or final pay formulas.

In 2023, we settled approximately $179 million of the retiree benefit obligation for our pension plans through an annuity purchase. The impact of the annuity purchase is reflected in the December 31, 2023 benefit obligation for our pension plans.

OPEB Plans

We and certain types of guarantees or indemnificationsour subsidiaries provide OPEB benefits, including medical benefits for closed groups of retired employees and certain grandfathered employees and their dependents, and limited postretirement life insurance benefits for retired employees. These plans provide a fixed subsidy to post-age 65 Medicare eligible participants to purchase coverage through a retiree Medicare exchange. Medical benefits under these OPEB plans may be subject to deductibles, co-payment provisions, dollar caps and other limitations on the amount of employer costs, and we reserve the right to change these benefits.

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Benefit Obligation, Plan Assets and Funded Status. The following table provides information about our pension and OPEB plans as of and for each of the years ended December 31, 2023 and 2022:
Pension BenefitsOPEB
2023202220232022
(In millions)
Change in benefit obligation:
Benefit obligation at beginning of period$2,077 $2,658 $195 $257 
Service cost55 55 1 1 
Interest cost107 57 10 5 
Actuarial loss (gain)14 (503)(6)(44)
Benefits paid(132)(190)(25)(26)
Participant contributions— — 1 1 
Settlements(219)— — — 
Other— — 1 1 
Benefit obligation at end of period1,902 2,077 177 195 
Change in plan assets:   
Fair value of plan assets at beginning of period1,741 2,231 302 382 
Actual return on plan assets122 (350)44 (63)
Employer contributions50 50 — 7 
Participant contributions— — 1 1 
Benefits paid(132)(190)(25)(26)
Settlements(219)— — — 
Other— — 1 1 
Fair value of plan assets at end of period1,562 1,741 323 302 
Funded status - net (liability) asset at December 31,$(340)$(336)$146 $107 
Amounts recognized in the consolidated balance sheets:
Non-current benefit asset(a)$— $— $263 $239 
Current benefit liability— — (14)(15)
Non-current benefit liability(340)(336)(103)(117)
Funded status - net (liability) asset at December 31,$(340)$(336)$146 $107 
Amounts of pre-tax accumulated other comprehensive (loss) income recognized in the consolidated balance sheets:
Unrecognized net actuarial (loss) gain$(384)$(455)$149 $135 
Unrecognized prior service (cost) credit— (1)3 4 
Accumulated other comprehensive (loss) income$(384)$(456)$152 $139 
Information related to plans whose accumulated benefit obligations exceeded the fair value of plan assets:
Accumulated benefit obligation$1,870 $2,047 $119 $167 
Fair value of plan assets1,562 1,741 2 34 
(a)2023 and 2022 OPEB amounts include $53 million and $45 million, respectively, of non-current benefit assets related to a plan we sponsor which is associated with employee services provided to an unconsolidated joint venture, and for which we have maderecorded an offsetting related party deferred credit.

The 2023 net actuarial loss for the pension plans was primarily due to a decrease in the weighted average discount rate used to determine the benefit obligation as of December 31, 2023. The 2023 net actuarial gain for the OPEB plans was primarily due to changes in the claims cost assumptions. The 2022 net actuarial gain for the pension plans was primarily due to an increase in the weighted average discount rate used to determine the benefit obligation as of December 31, 2022. The 2022 net actuarial
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gain for the OPEB plans was primarily due to an increase in the weighted average discount rate used to determine the benefit obligations as of December 31, 2022 and cover certain typeschanges in the claims cost assumptions.

Plan Assets. The investment policies and strategies are established by our plan’s fiduciary committee for the assets of guarantees includedeach of the pension and OPEB plans, which are responsible for investment decisions and management oversight of the plans. The stated philosophy of the fiduciary committee is to manage these assets in a manner consistent with the purpose for which the plans were established and the time frame over which the plans’ obligations need to be met. The objectives of the investment management program are to (i) meet or exceed plan actuarial earnings assumptions over the long term and (ii) provide a reasonable return on assets within debt agreements, even ifestablished risk tolerance guidelines and to maintain the liquidity needs of the plans with the goal of paying benefit and expense obligations when due. In seeking to meet these objectives, the fiduciary committee recognizes that prudent investing requires taking reasonable risks in order to raise the likelihood of requiringachieving the targeted investment returns. In order to reduce portfolio risk and volatility, the fiduciary committee has adopted a strategy of using multiple asset classes.

The allowable range for asset allocations in effect for our performance under such guaranteeplans as of December 31, 2023, by asset category, are as follows:
Pension BenefitsOPEB
Cash0% to 23%
Equities42% to 52%43% to 71%
Fixed income securities37% to 47%26% to 50%
Real estate2% to 12%
Company securities (KMI Class P common stock and/or debt securities)0% to 10%

Below are the details of our pension and OPEB plan assets by class and a description of the valuation methodologies used for assets measured at fair value.

•Level 1 assets’ fair values are based on quoted market prices for the instruments in actively traded markets. Included in this level are cash, equities and exchange traded mutual funds. These investments are valued at the closing price reported on the active market on which the individual securities are traded.

•Level 2 assets’ fair values are primarily based on pricing data representative of quoted prices for similar assets in active markets (or identical assets in less active markets). Included in this level are short-term investment funds, fixed income securities and derivatives. Short-term investment funds are valued at amortized cost, which approximates fair value. The fixed income securities’ fair values are primarily based on an evaluated price which is remote.based on a compilation of primarily observable market information or a broker quote in a non-active market. Derivatives are exchange-traded through clearinghouses and are valued based on these prices.


•Plan assets with fair values that are based on the net asset value per share, or its equivalent (NAV), as a practical expedient to measure fair value, as reported by the issuers are determined based on the fair value of the underlying securities as of the valuation date and include common/collective trust funds, private investment funds, real estate and limited partnerships. The plan assets measured at NAV are not categorized within the fair value hierarchy described above, but are separately identified in the following tables.

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Listed below are the fair values of our pension and OPEB plans’ assets that are recorded at fair value by class and categorized by fair value measurement used at December 31, 2023 and 2022:
Pension Assets
20232022
Level 1Level 2TotalLevel 1Level 2Total
(In millions)
Measured within fair value hierarchy
Short-term investment funds$— $32 $32 $— $27 $27 
Equities(a)143 — 143 152 — 152 
Fixed income securities— 410 410 — 421 421 
Subtotal$143 $442 585 $152 $448 600 
Measured at NAV
Common/collective trusts(b)976 1,138 
Private limited partnerships(c)1 3 
Subtotal977 1,141 
Total plan assets fair value$1,562 $1,741 
(a)Plan assets include $107 and $110 of KMI Class P common stock for 2023 and 2022, respectively.
(b)Common/collective trust funds were invested in approximately 64% equities, 23% fixed income securities and 13% real estate in 2023 and 66% equities, 22% fixed income securities and 12% real estate in 2022.
(c)Includes assets invested in real estate, venture and buyout funds.
OPEB Assets
20232022
Level 1Level 2TotalLevel 1Level 2Total
(In millions)
Measured within fair value hierarchy
Short-term investment funds$— $5 $5 $— $3 $3 
Measured at NAV
Common/collective trusts(a)318 299 
Total plan assets fair value$323 $302 
(a)Common/collective trust funds were invested in approximately 62% equities and 38% fixed income securities for 2023 and 61% equities and 39% fixed income securities for 2022.

Employer Contributions and Expected Payment of Future Benefits. As of December 31, 20172023, we expect the following cash flows under our plans:
Pension BenefitsOPEB
(In millions)
Contributions expected in 2024$50 $— 
Benefit payments expected in:
2024$190 $24 
2025187 22 
2026185 21 
2027179 19 
2028175 18 
2029 - 2033777 67 

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Actuarial Assumptions and 2016,Sensitivity Analysis. Benefit obligations and net benefit cost are based on actuarial estimates and assumptions. The following table details the weighted-average actuarial assumptions used in determining our contingent debt obligations,benefit obligation as wellof December 31, 2023 and 2022 and net benefit costs of our pension and OPEB plans for 2023, 2022 and 2021:
Pension BenefitsOPEB
2023202220232022
Assumptions related to benefit obligations:
Discount rate5.13 %5.41 %5.08 %5.38 %
Rate of compensation increase3.50 %3.50 %n/an/a
Interest crediting rate3.85 %3.50 %n/an/a
Pension BenefitsOPEB
202320222021202320222021
Assumptions related to benefit costs:
Discount rate5.41 %2.74 %2.27 %5.38 %2.56 %2.08 %
Expected return on plan assets7.00 %6.50 %6.25 %6.00 %5.75 %5.75 %
Rate of compensation increase3.50 %3.50 %3.50 %n/an/an/a
Interest crediting rate3.50 %3.01 %2.57 %n/an/an/a

We utilize a full yield curve approach in estimating the service and interest cost components of net periodic benefit cost (credit) for our retirement benefit plans by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to their underlying projected cash flows. The expected long-term rates of return on plan assets were determined by combining a review of the historical returns realized within the portfolio, the investment strategy included in the plans’ investment policy, and capital market projections for the asset classes in which the portfolio is invested and the target weightings of each asset class. The expected return on plan assets listed in the table above is a pre-tax rate of return based on our targeted portfolio of investments. For the OPEB assets subject to unrelated business income taxes, we utilize an after-tax expected return on plan assets to determine our benefit costs.

Actuarial estimates for our OPEB plans assume an annual increase in the per capita cost of covered health care benefits. The initial annual rate of increase is 5.60% which gradually decreases to 4.00% by the year 2047.

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Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income. For each of the years ended December 31, the components of net benefit cost and other amounts recognized in pre-tax other comprehensive income related to our pension and OPEB plans are as our obligations with respect to related letters of credit, totaled $1,070follows:
Pension BenefitsOPEB
202320222021202320222021
(In millions)
Components of net benefit cost (credit):
Service cost$55 $55 $53 $1 $1 $1 
Interest cost107 57 45 10 5 4 
Expected return on assets(117)(142)(133)(13)(17)(16)
Amortization of prior service cost (credit)1 1 — (3)(3)(5)
Amortization of net actuarial loss (gain)35 29 52 (16)(18)(17)
Settlement loss46 — — — — — 
Net benefit cost (credit)127 — 17 (21)(32)(33)
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
Net loss (gain) arising during period10 (11)(127)(30)24 (40)
Amortization or settlement recognition of net actuarial (loss) gain(81)(29)(52)16 17 17 
Amortization of prior service (cost) credit(1)(1)— 1 2 3 
Total recognized in total other comprehensive (income) loss(a)(72)(41)(179)(13)43 (20)
Total recognized in net benefit cost (credit) and other comprehensive (income) loss$55 $(41)$(162)$(34)$11 $(53)
(a)Excludes $4 million and $1,179$3 million respectively. Bothfor the years ended December 31, 2022 and 2021, respectively, associated with other plans.

11.Stockholders’ Equity

Class P Common Stock

On July 19, 2017, our Board approved a $2 billion share buy-back program that began in December 2017. On January 18, 2023, our Board approved an increase in our share repurchase authorization to $3 billion. All shares we have repurchased are canceled and 2016 amounts are primarily representedno longer outstanding. Activity under the buy-back program is as follows:
Year Ended December 31,
202320222021
(In millions, except per share amounts)
Total value of shares repurchased$522 $368 $— 
Total number of shares repurchased32 21 — 
Average repurchase price per share$16.56 $16.94 $— 

Subsequent to December 31, 2023 and through February 16, 2024, we repurchased less than 1 million shares at an average price of $16.50 for $7 million. Since December 2017, in total, we have repurchased 86 million of our shares under the program at an average price of $17.09 per share for $1,472 million, leaving capacity under the program of $1.5 billion.
On December 19, 2014, we entered into an equity distribution agreement authorizing us to issue and sell through or to the managers party thereto, as sales agents and/or principals, shares having an aggregate offering price of up to $5 billion from time to time during the term of this agreement. During the years ended December 31, 2023, 2022 and 2021 we did not issue any shares under this agreement.
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Dividends

The following table provides information about our per share dividends: 
Year Ended December 31,
202320222021
Per share cash dividend declared for the period$1.13 $1.11 $1.08 
Per share cash dividend paid in the period1.1250 1.1025 1.0725 

On January 17, 2024, our Board declared a cash dividend of $0.2825 per share for the quarterly period ended December 31, 2023, which was paid on February 15, 2024 to shareholders of record as of January 31, 2024.

Adoption of Accounting Pronouncement

On January 1, 2022, we adopted Accounting Standards Update (ASU) No. 2020-06, “Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity.” This ASU (i) simplifies an issuer’s accounting for convertible instruments by our proportional shareeliminating two of the debt obligations of two equity investees. Under such guarantees we are severally liablethree models in Subtopic 470-20 that require separate accounting for our percentage ownershipembedded conversion features, (ii) amends diluted earnings per share of these equity investees’ debt issued incalculations for convertible instruments by requiring the event of their non-performance. Also included in our contingent debt obligations is a guarantee of a throughput and deficiency agreement supporting certain debt obligations of a subsidiary of our investee, Cortez Pipeline Company. Through this guarantee, we are severally liable for 50% of a Cortez Pipeline Company subsidiary’s debt obligations with respect to a $50 million credit facility and $100 million in bonds. In addition, we have guaranteed 100%use of the debt issued by another Cortez Pipeline Company subsidiary to fund an expansion project, of which debt consists of a $50 million credit facilityif-converted method and a $120 million private placement note.

Guarantees and Indemnifications

We are involved in joint ventures and other ownership arrangements that sometimes require financial and performance guarantees. In a financial guarantee, we are obligated to make payments if(iii) simplifies the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, wesettlement assessment entities are required to perform on their behalf. We also periodically provide indemnification arrangements relatedcontracts that can potentially settle in an entity’s own equity by removing certain requirements. Using the modified retrospective method, the adoption of this ASU resulted in a pre-tax adjustment of $14 million to assets or businesses we have sold. These arrangements include, but are not limitedunwind the remaining unamortized debt discount within “Debt fair value adjustments” on our consolidated balance sheet and an adjustment of $11 million to indemnifications for income taxes,unwind the resolution of existing disputes and environmental matters.

While many of these agreements may specify a maximum potential exposure, or a specified duration to the indemnification obligation, there are also circumstances where the amount and duration are unlimited. Currently, we are not subject to any material requirements to perform under quantifiable arrangements, and we expect future requirements to perform under quantifiable arrangements will be immaterial. We are unable to estimate a maximum exposure for our guarantee and indemnification agreements that do not provide for limits on the amount of future payments due to the uncertainty of these exposures.

See Note 17 “Litigation, Environmental and Other Contingencies” for a description of matters that we have identified as contingencies requiring accrual of liabilities and/or disclosure, including any such matters arising under guarantee or indemnification agreements.

14.  Risk Management
Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, NGL and crude oil.  We also have exposure to interest rate and foreign currency risk as a resultbalance of the issuanceconversion feature classified in “Additional paid in capital” on our consolidated statement of our debt obligations.  Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to some of these risks. In addition, prior to May 2016, we had legacy power forward and swap contracts related to operations of acquired businesses.


Energy Commodity Price Risk Management
As of December 31, 2017, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales: 
Net open position long/(short)
Derivatives designated as hedging contracts
Crude oil fixed price(21.0)MMBbl
Crude oil basis(7.2)MMBbl
Natural gas fixed price(46.4)Bcf
Natural gas basis(21.7)Bcf
Derivatives not designated as hedging contracts
Crude oil fixed price(1.9)MMBbl
Crude oil basis(1.2)MMBbl
Natural gas fixed price(9.0)Bcf
Natural gas basis(23.1)Bcf
NGL fixed price(4.1)MMBbl

As of December 31, 2017, the maximum length of time over which we have hedged, for accounting purposes, our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2021.

Interest Rate Risk Management

As of December 31, 2017 and December 31, 2016, we had a combined notional principal amount of $9,575 million and $9,775 million, respectively, of fixed-to-variable interest rate swap agreements, all of which were designated as fair value hedges. All of our swap agreements effectively convert the interest expense associated with certain series of senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread and have termination dates that correspond to the maturity dates of the related series of senior notes. As of December 31, 2017, the maximum length of time over which we have hedged a portion of our exposure to the variability in the value of this debt due to interest rate risk is through March 15, 2035.

Foreign Currency Risk Management

As of both December 31, 2017 and 2016, we had a notional principal amount of $1,358 million of cross-currency swap agreements to manage the foreign currency risk related to our Euro denominated senior notes by effectively converting all of the fixed-rate Euro denominated debt, including annual interest payments and the payment of principal at maturity, to U.S. dollar denominated debt at fixed rates equivalent to approximately 3.79% and 4.67%stockholders’ equity for the 7-year and 12-year senior notes, respectively. These cross-currency swaps are accounted for as cash flow hedges. The terms of the cross-currency swap agreements correspond to the related hedged senior notes, and such agreements have the same maturities as the hedged senior notes.


Fair Value of Derivative Contracts

The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets (in millions):
Fair Value of Derivative Contracts
   Asset derivatives Liability derivatives
   December 31, December 31,
   2017 2016 2017 2016
 Location Fair value Fair value
Derivatives designated as
hedging contracts
         
Energy commodity derivative contractsFair value of derivative contracts/(Other current liabilities) $65
 $101
 $(53) $(57)
 Deferred charges and other assets/(Other long-term liabilities and deferred credits) 14
 70
 (24) (24)
Subtotal  79
 171
 (77) (81)
Interest rate swap agreementsFair value of derivative contracts/(Other current liabilities) 41
 94
 (3) —
 Deferred charges and other assets/(Other long-term liabilities and deferred credits) 164
 206
 (62) (57)
Subtotal  205
 300
 (65) (57)
Cross-currency swap agreementsFair value of derivative contracts/(Other current liabilities) —
 —
 (6) (7)
 Deferred charges and other assets/(Other long-term liabilities and deferred credits) 166
 —
 —
 (24)
Subtotal  166
 —
 (6) (31)
Total  450
 471
 (148) (169)
Derivatives not designated as
 hedging contracts
   
  
  
  
Energy commodity derivative contractsFair value of derivative contracts/(Other current liabilities) 8
 3
 (22) (29)
 Deferred charges and other assets/(Other long-term liabilities and deferred credits) —
 —
 (2) (1)
Total  8
 3
 (24) (30)
Total derivatives  $458
 $474
 $(172) $(199)

 Effect of Derivative Contracts on the Income Statement
The following tables summarize the impact of our derivative contracts on our accompanying consolidated statements of income (in millions):
Derivatives in fair value hedging relationships Location Gain/(loss) recognized in income on derivatives and related hedged item
    Year Ended December 31,
    2017 2016 2015
Interest rate swap agreements Interest, net $(103) $(180) $25
         
Hedged fixed rate debt Interest, net $105
 $160
 $(33)


Derivatives in cash flow hedging relationships Gain/(loss) recognized in OCI on derivative (effective portion)(a) Location Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b) Location Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)
  Year Ended   Year Ended   Year Ended
  December 31,   December 31,   December 31,
  2017 2016 2015   2017 2016 2015   2017 2016 2015
Energy commodity derivative contracts $24
 $(115) $201
 Revenues—Natural gas sales $12
 $15
 $54
 Revenues—Natural gas sales $—
 $—
 $—
   
  
   Revenues—Product sales and other 35
 148
 236
 Revenues—Product sales and other 11
 (12) 2
   
  
   Costs of sales 9
 (17) (15) Costs of sales —
 —
 —
Interest rate swap agreements(c) —
 (2) (4) Interest, net (3) (3) (3) Interest, net —
 —
 —
Cross-currency swap 121
 13
 (33) Other, net 118
 (27) —
 Other, net —
 —
 —
Total $145
 $(104) $164
 Total $171
 $116
 $272
 Total $11
 $(12) $2
_______
(a)
We expect to reclassify an approximate $1 million loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balances as of December 31, 2017 into earnings during the next twelve months (when the associated forecasted transactions are also expected to occur), however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.
(b)Amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).
(c)Amounts represent our share of an equity investee’s accumulated other comprehensive loss.
Derivatives not designated as accounting hedges Location Gain/(loss) recognized in income on derivatives
    Year Ended December 31,
    2017 2016 2015
Energy commodity derivative contracts Revenues—Natural gas sales $20
 $(10) $17
  Revenues—Product sales and other (16) (26) 176
  Costs of sales —
 3
 (2)
Interest rate swap agreements Interest, net —
 63
 (15)
Total(a)   $4
 $30
 $176
________
(a) For the yearsyear ended December 31, 2017, 2016 and 2015 includes approximate gains of $57 million, $73 million and $31 million, respectively, associated with natural gas, crude and NGL derivative contract settlements.2022.


Credit Risks
 In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts.  As of December 31, 2017 and 2016, we had no outstanding letters of credit supporting our commodity price risk management program. As of December 31, 2017 and December 31, 2016, we had cash margins of $1 million and $37 million, respectively, posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance sheets. The balance at December 31, 2017, consisted of initial margin requirements of $13 million, offset by variation margin requirements of $12 million. We also use industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we generally utilize netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty.

We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in our credit rating.  As of December 31, 2017, based on our current mark to market positions and posted collateral, we estimate that if our credit rating were downgraded one notch we would be required to post $31 million of additional collateral and no additional collateral beyond this $31 million if we were downgraded two notches.

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss


Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Stockholders’ Equity” in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” not including non-controllingnoncontrolling interests are summarized as follows (in millions):follows:
 Net unrealized
gains/(losses)
on cash flow
hedge derivatives		Pension and
other
postretirement
liability adjustments		Total
Accumulated other
comprehensive
loss
(In millions)
Balance at December 31, 2020$(13)$(394)$(407)
Other comprehensive (loss) gain before reclassifications(432)155 (277)
Losses reclassified from accumulated other comprehensive loss273 — 273 
Net current-period change in accumulated other comprehensive loss(159)155 (4)
Balance at December 31, 2021(172)(239)(411)
Other comprehensive (loss) gain before reclassifications(312)1 (311)
Losses reclassified from accumulated other comprehensive loss320 — 320 
Net current-period change in accumulated other comprehensive loss8 1 9 
Balance at December 31, 2022(164)(238)(402)
Other comprehensive gain before reclassifications155 65 220 
Gains reclassified from accumulated other comprehensive loss(35)— (35)
Net current-period change in accumulated other comprehensive loss120 65 185 
Balance at December 31, 2023$(44)$(173)$(217)

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Net unrealized
gains/(losses)
on cash flow
hedge derivatives
 
Foreign
currency
translation
adjustments
 
Pension and
other
postretirement
liability adjustments
 
Total
Accumulated other
comprehensive
loss
Balance as of December 31, 2014$327
 $(108) $(236) $(17)
Other comprehensive gain (loss) before reclassifications164
 (214) (122) (172)
Gains reclassified from accumulated other comprehensive loss(272) —
 —
 (272)
Net current-period other comprehensive loss(108) (214) (122) (444)
Balance as of December 31, 2015219
 (322) (358) (461)
Other comprehensive (loss) gain before reclassifications(104) 34
 (14) (84)
Gains reclassified from accumulated other comprehensive loss(116) —
 —
 (116)
Net current-period other comprehensive (loss) income(220) 34
 (14) (200)
Balance as of December 31, 2016(1) (288) (372) (661)
Other comprehensive gain before reclassifications145
 55
 40
 240
Gains reclassified from accumulated other comprehensive loss(171) —
 —
 (171)
KML IPO—
 44
 7
 51
Net current-period other comprehensive (loss) income(26) 99
 47
 120
Balance as of December 31, 2017$(27) $(189) $(325) $(541)


12.  Related Party Transactions

15.  Fair ValueAffiliate Balances and Activities

The fair valuesWe have transactions with affiliates which consist of (i) unconsolidated affiliates in which we hold an investment accounted for under the equity method of accounting (see Note 7 for additional information related to these investments); and (ii) external partners of our financial instruments are separated into three broad levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Each fair value measurement must be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety.joint ventures we consolidate.

The three broad levels of inputs defined by the fair value hierarchy are as follows:
Level 1 Inputs—quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date;
Level 2 Inputs—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and
Level 3 Inputs—unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data).


Fair Value of Derivative Contracts

The following two tables summarize our affiliate balance sheet balances and income statement activity, other than amounts reported within our “Investments” balances and “Earnings from equity investments” activity:
December 31,
20232022
(In millions)
Balance sheet location
Accounts receivable$45 $39 
Other current assets2 3 
$47 $42 
Current portion of debt$5 $6 
Accounts payable16 19 
Other current liabilities3 8 
Long-term debt137 142 
Other long-term liabilities and deferred credits54 47 
$215 $222 
Year Ended December 31,
202320222021
(In millions)
Income statement location
Revenues$172 $172 $164 
Operating Costs, Expenses and Other
Costs of sales$132 $134 $145 
Other operating expenses57 50 52 

13.  Commitments and Contingent Liabilities
Rights-Of-Way

Our rights-of-way obligations primarily consist of non-lease agreements that existed at the fair value measurementstime of Topic 842, Leases, adoption, at which time we elected a practical expedient which allowed us to continue our (i) energy commodity derivative contracts; (ii) interest rate swap agreements; and (iii) cross-currency swap agreements, based on the three levels established by the Codification (in millions). The tables also identify the impacthistorical treatment. Our future minimum rental commitments related to our rights-of-way obligations were $98 million as of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements. December 31, 2023.

 Balance sheet asset fair value measurements by level    
 

Level 1
 

Level 2
 

Level 3
 Gross amount Contracts available for netting Cash collateral held(b) Net amount
As of December 31, 2017             
Energy commodity derivative contracts(a)$17
 $70
 $—
 $87
 $(42) $(12) $33
Interest rate swap agreements$—
 $205
 $—
 $205
 $(15) $—
 $190
Cross-currency swap agreements$—
 $166
 $—
 $166
 $(6) $—
 $160
As of December 31, 2016 
  
  
        
Energy commodity derivative contracts(a)$6
 $168
 $—
 $174
 $(43) $—
 $131
Interest rate swap agreements$—
 $300
 $—
 $300
 $(18) $—
 $282

 
Balance sheet liability
fair value measurements by level
    
 Level 1 Level 2 Level 3 Gross amount Contracts available for netting Collateral posted(b) Net amount
As of December 31, 2017             
Energy commodity derivative contracts(a)$(3) $(98) $—
 $(101) $42
 $—
 $(59)
Interest rate swap agreements$—
 $(65) $—
 $(65) $15
 $—
 $(50)
Cross-currency swap agreements$—
 $(6) $—
 $(6) $6
 $—
 $—
As of December 31, 2016             
Energy commodity derivative contracts(a)$(29) $(82) $—
 $(111) $43
 $37
 $(31)
Interest rate swap agreements$—
 $(57) $—
 $(57) $18
 $—
 $(39)
Cross-currency swap agreements$—
 $(31) $—
 $(31) $—
 $—
 $(31)
_______
(a)Level 1 consists primarily of NYMEX natural gas futures.  Level 2 consists primarily of OTC WTI swaps and NGL swaps. 
(b)Any cash collateral paid or received is reflected in this table, but only to the extent that it represents variation margins. Any amount associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from this table.

The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts (in millions): 
Significant unobservable inputs (Level 3)
 Year Ended December 31,
 2017 2016
Derivatives-net asset (liability)   
Beginning of period$—
 $(15)
Total gains or (losses) included in earnings—
 (9)
Settlements—
 24
End of period$—
 $—
The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or (losses) relating to assets held at the reporting date$—
 $—


During 2016, our Level 3 derivative asset and liability activity consisted primarily of power derivative contracts (which expired in April 2016), where a significant portion of fair value is calculated from underlying market data that is not readily observable. The derived values use industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in management’s best estimate of fair value, and management would not expect materially different valuation results were we to use different input amounts within reasonable ranges.

Fair Value of Financial Instruments
 
The carrying value and estimated fair value of our outstanding debt balances is disclosed below (in millions): below:
 December 31, 2023December 31, 2022
 Carrying
value		Estimated
fair value(a)		Carrying
value		Estimated
fair value(a)
(In millions)
Total debt$32,116 $31,370 $31,788 $30,070 
 December 31, 2017 December 31, 2016
 
Carrying
value
 
Estimated
fair value
 
Carrying
value
 
Estimated
fair value
Total debt$37,843
 $40,050
 $40,050
 $41,015
(a)Included in the estimated fair value are amounts for our Trust I Preferred Securities of $207 million and $195 million as of December 31, 2023 and 2022, respectively.


We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both December 31, 2023 and 2022.

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Interest Rates, Interest Rate Swaps and Contingent Debt

The weighted average interest rate on all of our borrowings was 5.84% during 2023 and 4.76% during 2022. Information on our interest rate swaps is contained in Note 14. For information about our contingent debt agreements, see Note 13“Commitments and Contingent Liabilities—Contingent Debt”).

10.      Share-based Compensation and Employee Benefits

Share-based Compensation

Class P Common Stock

Following is a summary of our stock compensation plans:
Directors’ PlanLong Term Incentive Plan
Participating individualsEligible non-employee directorsEligible employees
Total number of shares of Class P common stock authorized1,190,000 63,000,000 
Vesting period6 months1 year to 10 years

Kinder Morgan, Inc. Second Amended and Restated Stock Compensation Plan for Non-Employee Directors

We have a Kinder Morgan, Inc. Second Amended and Restated Stock Compensation Plan for Non-Employee Directors (Directors’ Plan).  The plan recognizes that the compensation paid to each eligible non-employee director is fixed by our board of directors (Board), generally annually, and that the compensation is payable in cash.  Pursuant to the plan, in lieu of receiving some or all of the cash compensation, each eligible non-employee director may elect annually to receive shares of Class P common stock.  During the year ended December 31, 2023, we made restricted Class P common stock grants to our non-employee directors of 11,220.

Kinder Morgan, Inc. 2021 Amended and Restated Stock Incentive Plan

We also have a Kinder Morgan, Inc. 2021 Amended and Restated Stock Incentive Plan (Long Term Incentive Plan).  The following table sets forth a summary of activity and related balances under our Long Term Incentive Plan:
SharesWeighted Average Grant Date Fair Value per Share
(In thousands, except per share amounts)
Outstanding at December 31, 202213,288 $16.87 
Granted5,253 17.41 
Vested(5,226)16.09 
Forfeited(454)17.03 
Outstanding at December 31, 202312,861 $17.41 

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The following tables set forth additional information related to our Long Term Incentive Plan:
Year Ended December 31,
202320222021
(In millions, except per share amounts)
Weighted average grant date fair value per share$17.41 $17.31 $17.44 
Intrinsic value of awards vested during the year93 47 77 
Restricted stock awards expense(a)63 60 59 
Restricted stock awards capitalized(a)10 9 9 
(a)We allocate labor and benefit costs to joint ventures that we operate in accordance with our partnership agreements.
December 31, 2023
Unrecognized restricted stock awards compensation costs, less estimated forfeitures (in millions)
$117 
Weighted average remaining amortization period2.06 years

Pension and Other Postretirement Benefit (OPEB) Plans

Savings Plan

We maintain a defined contribution plan covering eligible U.S. employees. We contribute 5% of eligible compensation for most of the plan participants. Certain collectively bargained participants receive Company contributions in accordance with collective bargaining agreements. A participant becomes fully vested in Company contributions after two years and may take a distribution upon termination of employment or retirement. The total cost for our savings plan was approximately $53 million, $51 million and $48 million for the years ended December 31, 2023, 2022 and 2021, respectively.

Pension Plans

Our pension plans are defined benefit plans that cover substantially all of our U.S. employees and provide benefits under a cash balance formula. A participant in the cash balance formula accrues benefits through contribution credits based on a combination of age and years of service, multiplied by eligible compensation. Interest is also credited to the participant’s plan account. A participant becomes fully vested in the plan after three years and may take a lump sum or annuity distribution upon termination of employment or retirement. Certain collectively bargained and grandfathered employees accrue benefits through career pay or final pay formulas.

In 2023, we settled approximately $179 million of the retiree benefit obligation for our pension plans through an annuity purchase. The impact of the annuity purchase is reflected in the December 31, 2023 benefit obligation for our pension plans.

OPEB Plans

We and certain of our subsidiaries provide OPEB benefits, including medical benefits for closed groups of retired employees and certain grandfathered employees and their dependents, and limited postretirement life insurance benefits for retired employees. These plans provide a fixed subsidy to post-age 65 Medicare eligible participants to purchase coverage through a retiree Medicare exchange. Medical benefits under these OPEB plans may be subject to deductibles, co-payment provisions, dollar caps and other limitations on the amount of employer costs, and we reserve the right to change these benefits.

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Benefit Obligation, Plan Assets and Funded Status. The following table provides information about our pension and OPEB plans as of and for each of the years ended December 31, 2023 and 2022:
Pension BenefitsOPEB
2023202220232022
(In millions)
Change in benefit obligation:
Benefit obligation at beginning of period$2,077 $2,658 $195 $257 
Service cost55 55 1 1 
Interest cost107 57 10 5 
Actuarial loss (gain)14 (503)(6)(44)
Benefits paid(132)(190)(25)(26)
Participant contributions— — 1 1 
Settlements(219)— — — 
Other— — 1 1 
Benefit obligation at end of period1,902 2,077 177 195 
Change in plan assets:   
Fair value of plan assets at beginning of period1,741 2,231 302 382 
Actual return on plan assets122 (350)44 (63)
Employer contributions50 50 — 7 
Participant contributions— — 1 1 
Benefits paid(132)(190)(25)(26)
Settlements(219)— — — 
Other— — 1 1 
Fair value of plan assets at end of period1,562 1,741 323 302 
Funded status - net (liability) asset at December 31,$(340)$(336)$146 $107 
Amounts recognized in the consolidated balance sheets:
Non-current benefit asset(a)$— $— $263 $239 
Current benefit liability— — (14)(15)
Non-current benefit liability(340)(336)(103)(117)
Funded status - net (liability) asset at December 31,$(340)$(336)$146 $107 
Amounts of pre-tax accumulated other comprehensive (loss) income recognized in the consolidated balance sheets:
Unrecognized net actuarial (loss) gain$(384)$(455)$149 $135 
Unrecognized prior service (cost) credit— (1)3 4 
Accumulated other comprehensive (loss) income$(384)$(456)$152 $139 
Information related to plans whose accumulated benefit obligations exceeded the fair value of plan assets:
Accumulated benefit obligation$1,870 $2,047 $119 $167 
Fair value of plan assets1,562 1,741 2 34 
(a)2023 and 2022 OPEB amounts include $53 million and $45 million, respectively, of non-current benefit assets related to a plan we sponsor which is associated with employee services provided to an unconsolidated joint venture, and for which we have recorded an offsetting related party deferred credit.

The 2023 net actuarial loss for the pension plans was primarily due to a decrease in the weighted average discount rate used to determine the benefit obligation as of December 31, 2023. The 2023 net actuarial gain for the OPEB plans was primarily due to changes in the claims cost assumptions. The 2022 net actuarial gain for the pension plans was primarily due to an increase in the weighted average discount rate used to determine the benefit obligation as of December 31, 2022. The 2022 net actuarial
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gain for the OPEB plans was primarily due to an increase in the weighted average discount rate used to determine the benefit obligations as of December 31, 2022 and changes in the claims cost assumptions.

Plan Assets. The investment policies and strategies are established by our plan’s fiduciary committee for the assets of each of the pension and OPEB plans, which are responsible for investment decisions and management oversight of the plans. The stated philosophy of the fiduciary committee is to manage these assets in a manner consistent with the purpose for which the plans were established and the time frame over which the plans’ obligations need to be met. The objectives of the investment management program are to (i) meet or exceed plan actuarial earnings assumptions over the long term and (ii) provide a reasonable return on assets within established risk tolerance guidelines and to maintain the liquidity needs of the plans with the goal of paying benefit and expense obligations when due. In seeking to meet these objectives, the fiduciary committee recognizes that prudent investing requires taking reasonable risks in order to raise the likelihood of achieving the targeted investment returns. In order to reduce portfolio risk and volatility, the fiduciary committee has adopted a strategy of using multiple asset classes.

The allowable range for asset allocations in effect for our plans as of December 31, 2023, by asset category, are as follows:
Pension BenefitsOPEB
Cash0% to 23%
Equities42% to 52%43% to 71%
Fixed income securities37% to 47%26% to 50%
Real estate2% to 12%
Company securities (KMI Class P common stock and/or debt securities)0% to 10%

Below are the details of our pension and OPEB plan assets by class and a description of the valuation methodologies used for assets measured at fair value.

•Level 1 assets’ fair values are based on quoted market prices for the instruments in actively traded markets. Included in this level are cash, equities and exchange traded mutual funds. These investments are valued at the closing price reported on the active market on which the individual securities are traded.

•Level 2 assets’ fair values are primarily based on pricing data representative of quoted prices for similar assets in active markets (or identical assets in less active markets). Included in this level are short-term investment funds, fixed income securities and derivatives. Short-term investment funds are valued at amortized cost, which approximates fair value. The fixed income securities’ fair values are primarily based on an evaluated price which is based on a compilation of primarily observable market information or a broker quote in a non-active market. Derivatives are exchange-traded through clearinghouses and are valued based on these prices.

•Plan assets with fair values that are based on the net asset value per share, or its equivalent (NAV), as a practical expedient to measure fair value, as reported by the issuers are determined based on the fair value of the underlying securities as of the valuation date and include common/collective trust funds, private investment funds, real estate and limited partnerships. The plan assets measured at NAV are not categorized within the fair value hierarchy described above, but are separately identified in the following tables.

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Listed below are the fair values of our pension and OPEB plans’ assets that are recorded at fair value by class and categorized by fair value measurement used at December 31, 2023 and 2022:
Pension Assets
20232022
Level 1Level 2TotalLevel 1Level 2Total
(In millions)
Measured within fair value hierarchy
Short-term investment funds$— $32 $32 $— $27 $27 
Equities(a)143 — 143 152 — 152 
Fixed income securities— 410 410 — 421 421 
Subtotal$143 $442 585 $152 $448 600 
Measured at NAV
Common/collective trusts(b)976 1,138 
Private limited partnerships(c)1 3 
Subtotal977 1,141 
Total plan assets fair value$1,562 $1,741 
(a)Plan assets include $107 and $110 of KMI Class P common stock for 2023 and 2022, respectively.
(b)Common/collective trust funds were invested in approximately 64% equities, 23% fixed income securities and 13% real estate in 2023 and 66% equities, 22% fixed income securities and 12% real estate in 2022.
(c)Includes assets invested in real estate, venture and buyout funds.
OPEB Assets
20232022
Level 1Level 2TotalLevel 1Level 2Total
(In millions)
Measured within fair value hierarchy
Short-term investment funds$— $5 $5 $— $3 $3 
Measured at NAV
Common/collective trusts(a)318 299 
Total plan assets fair value$323 $302 
(a)Common/collective trust funds were invested in approximately 62% equities and 38% fixed income securities for 2023 and 61% equities and 39% fixed income securities for 2022.

Employer Contributions and Expected Payment of Future Benefits. As of December 31, 2023, we expect the following cash flows under our plans:
Pension BenefitsOPEB
(In millions)
Contributions expected in 2024$50 $— 
Benefit payments expected in:
2024$190 $24 
2025187 22 
2026185 21 
2027179 19 
2028175 18 
2029 - 2033777 67 

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Actuarial Assumptions and Sensitivity Analysis. Benefit obligations and net benefit cost are based on actuarial estimates and assumptions. The following table details the weighted-average actuarial assumptions used in determining our benefit obligation as of December 31, 2023 and 2022 and net benefit costs of our pension and OPEB plans for 2023, 2022 and 2021:
Pension BenefitsOPEB
2023202220232022
Assumptions related to benefit obligations:
Discount rate5.13 %5.41 %5.08 %5.38 %
Rate of compensation increase3.50 %3.50 %n/an/a
Interest crediting rate3.85 %3.50 %n/an/a
Pension BenefitsOPEB
202320222021202320222021
Assumptions related to benefit costs:
Discount rate5.41 %2.74 %2.27 %5.38 %2.56 %2.08 %
Expected return on plan assets7.00 %6.50 %6.25 %6.00 %5.75 %5.75 %
Rate of compensation increase3.50 %3.50 %3.50 %n/an/an/a
Interest crediting rate3.50 %3.01 %2.57 %n/an/an/a

We utilize a full yield curve approach in estimating the service and interest cost components of net periodic benefit cost (credit) for our retirement benefit plans by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to their underlying projected cash flows. The expected long-term rates of return on plan assets were determined by combining a review of the historical returns realized within the portfolio, the investment strategy included in the plans’ investment policy, and capital market projections for the asset classes in which the portfolio is invested and the target weightings of each asset class. The expected return on plan assets listed in the table above is a pre-tax rate of return based on our targeted portfolio of investments. For the OPEB assets subject to unrelated business income taxes, we utilize an after-tax expected return on plan assets to determine our benefit costs.

Actuarial estimates for our OPEB plans assume an annual increase in the per capita cost of covered health care benefits. The initial annual rate of increase is 5.60% which gradually decreases to 4.00% by the year 2047.

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Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income. For each of the years ended December 31, the components of net benefit cost and other amounts recognized in pre-tax other comprehensive income related to our pension and OPEB plans are as follows:
Pension BenefitsOPEB
202320222021202320222021
(In millions)
Components of net benefit cost (credit):
Service cost$55 $55 $53 $1 $1 $1 
Interest cost107 57 45 10 5 4 
Expected return on assets(117)(142)(133)(13)(17)(16)
Amortization of prior service cost (credit)1 1 — (3)(3)(5)
Amortization of net actuarial loss (gain)35 29 52 (16)(18)(17)
Settlement loss46 — — — — — 
Net benefit cost (credit)127 — 17 (21)(32)(33)
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
Net loss (gain) arising during period10 (11)(127)(30)24 (40)
Amortization or settlement recognition of net actuarial (loss) gain(81)(29)(52)16 17 17 
Amortization of prior service (cost) credit(1)(1)— 1 2 3 
Total recognized in total other comprehensive (income) loss(a)(72)(41)(179)(13)43 (20)
Total recognized in net benefit cost (credit) and other comprehensive (income) loss$55 $(41)$(162)$(34)$11 $(53)
(a)Excludes $4 million and $3 million for the years ended December 31, 2022 and 2021, respectively, associated with other plans.

11.Stockholders’ Equity

Class P Common Stock

On July 19, 2017, our Board approved a $2 billion share buy-back program that began in December 2017. On January 18, 2023, our Board approved an increase in our share repurchase authorization to $3 billion. All shares we have repurchased are canceled and 2016.are no longer outstanding. Activity under the buy-back program is as follows:
Year Ended December 31,
202320222021
(In millions, except per share amounts)
Total value of shares repurchased$522 $368 $— 
Total number of shares repurchased32 21 — 
Average repurchase price per share$16.56 $16.94 $— 


Subsequent to December 31, 2023 and through February 16, 2024, we repurchased less than 1 million shares at an average price of $16.50 for $7 million. Since December 2017, in total, we have repurchased 86 million of our shares under the program at an average price of $17.09 per share for $1,472 million, leaving capacity under the program of $1.5 billion.
On December 19, 2014, we entered into an equity distribution agreement authorizing us to issue and sell through or to the managers party thereto, as sales agents and/or principals, shares having an aggregate offering price of up to $5 billion from time to time during the term of this agreement. During the years ended December 31, 2023, 2022 and 2021 we did not issue any shares under this agreement.
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Dividends

The following table provides information about our per share dividends: 
Year Ended December 31,
202320222021
Per share cash dividend declared for the period$1.13 $1.11 $1.08 
Per share cash dividend paid in the period1.1250 1.1025 1.0725 

On January 17, 2024, our Board declared a cash dividend of $0.2825 per share for the quarterly period ended December 31, 2023, which was paid on February 15, 2024 to shareholders of record as of January 31, 2024.

Adoption of Accounting Pronouncement

On January 1, 2022, we adopted Accounting Standards Update (ASU) No. 2020-06, “Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity.” This ASU (i) simplifies an issuer’s accounting for convertible instruments by eliminating two of the three models in Subtopic 470-20 that require separate accounting for embedded conversion features, (ii) amends diluted earnings per share calculations for convertible instruments by requiring the use of the if-converted method and (iii) simplifies the settlement assessment entities are required to perform on contracts that can potentially settle in an entity’s own equity by removing certain requirements. Using the modified retrospective method, the adoption of this ASU resulted in a pre-tax adjustment of $14 million to unwind the remaining unamortized debt discount within “Debt fair value adjustments” on our consolidated balance sheet and an adjustment of $11 million to unwind the balance of the conversion feature classified in “Additional paid in capital” on our consolidated statement of stockholders’ equity for the year ended December 31, 2022.

Accumulated Other Comprehensive Loss

Changes in the components of our “Accumulated other comprehensive loss” not including noncontrolling interests are summarized as follows:
 Net unrealized
gains/(losses)
on cash flow
hedge derivatives		Pension and
other
postretirement
liability adjustments		Total
Accumulated other
comprehensive
loss
(In millions)
Balance at December 31, 2020$(13)$(394)$(407)
Other comprehensive (loss) gain before reclassifications(432)155 (277)
Losses reclassified from accumulated other comprehensive loss273 — 273 
Net current-period change in accumulated other comprehensive loss(159)155 (4)
Balance at December 31, 2021(172)(239)(411)
Other comprehensive (loss) gain before reclassifications(312)1 (311)
Losses reclassified from accumulated other comprehensive loss320 — 320 
Net current-period change in accumulated other comprehensive loss8 1 9 
Balance at December 31, 2022(164)(238)(402)
Other comprehensive gain before reclassifications155 65 220 
Gains reclassified from accumulated other comprehensive loss(35)— (35)
Net current-period change in accumulated other comprehensive loss120 65 185 
Balance at December 31, 2023$(44)$(173)$(217)

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12.  Related Party Transactions

Affiliate Balances and Activities

We have transactions with affiliates which consist of (i) unconsolidated affiliates in which we hold an investment accounted for under the equity method of accounting (see Note 7 for additional information related to these investments); and (ii) external partners of our joint ventures we consolidate.

The following tables summarize our affiliate balance sheet balances and income statement activity, other than amounts reported within our “Investments” balances and “Earnings from equity investments” activity:
December 31,
20232022
(In millions)
Balance sheet location
Accounts receivable$45 $39 
Other current assets2 3 
$47 $42 
Current portion of debt$5 $6 
Accounts payable16 19 
Other current liabilities3 8 
Long-term debt137 142 
Other long-term liabilities and deferred credits54 47 
$215 $222 
Year Ended December 31,
202320222021
(In millions)
Income statement location
Revenues$172 $172 $164 
Operating Costs, Expenses and Other
Costs of sales$132 $134 $145 
Other operating expenses57 50 52 

13.  Commitments and Contingent Liabilities
Rights-Of-Way

Our rights-of-way obligations primarily consist of non-lease agreements that existed at the time of Topic 842, Leases, adoption, at which time we elected a practical expedient which allowed us to continue our historical treatment. Our future minimum rental commitments related to our rights-of-way obligations were $98 million as of December 31, 2023.

Contingent Debt

Our contingent debt disclosures pertain to certain types of guarantees or indemnifications we have made and cover certain types of guarantees included within debt agreements, even if the likelihood of requiring our performance under such guarantee is remote.

As of December 31, 2023 and 2022, our contingent debt obligations totaled $154 million and $163 million, respectively. These amounts represent our proportional share of the debt obligations of one equity investee, Cortez Pipeline Company (Cortez). Under such guarantees we are severally liable for our percentage ownership share of Cortez’s debt in the event of its non-performance. The contingent debt obligations balances as of December 31, 2023 and 2022 each included $120 million for 100% guaranteed debt obligations for a subsidiary of Cortez.

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Guarantees and Indemnifications

We are involved in joint ventures and other ownership arrangements that sometimes require financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. We also periodically provide indemnification arrangements related to assets or businesses we have sold. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes and environmental matters.

While many of these agreements may specify a maximum potential exposure, or a specified duration to the indemnification obligation, there are also circumstances where the amount and duration are unlimited. Other than with our rights-of-way obligations and contingent debt described above, we are currently not subject to any material requirements to perform under quantifiable arrangements. We are unable to estimate a maximum exposure for our other guarantee and indemnification agreements that do not provide for limits on the amount of future payments due to the uncertainty of these exposures.

See Note 18 for a description of matters that we have identified as contingencies requiring accrual of liabilities and/or disclosure, including any such matters arising under guarantee or indemnification agreements.

14.  Risk Management

Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, NGL and crude oil.  We also have exposure to interest rate and foreign currency risk as a result of the issuance of our debt obligations.  Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to some of these risks.

Energy Commodity Price Risk Management

As of December 31, 2023, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales: 
Net open position long/(short)
Derivatives designated as hedging contracts
Crude oil fixed price(16.9)MMBbl
Natural gas fixed price(61.0)Bcf
Natural gas basis(35.4)Bcf
NGL fixed price(0.6)MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price(1.2)MMBbl
Crude oil basis(4.1)MMBbl
Natural gas fixed price(7.5)Bcf
Natural gas basis(101.6)Bcf
NGL fixed price(0.7)MMBbl
As of December 31, 2023, the maximum length of time over which we have hedged, for accounting purposes, our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2028.

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Interest Rate Risk Management

We utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of December 31, 2023:
Notional amountAccounting treatmentMaximum term
(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)(b)$6,200 Fair value hedgeMarch 2035
Treasury locks(c)1,000 Cash flow hedgeMarch 2024
(a)The principal amount of hedged senior notes consisted of $1,450 million included in “Current portion of debt” and $4,750 million included in “Long-term debt” on our accompanying consolidated balance sheet.
(b)During the year ended December 31, 2023, certain optional expedients as set forth in Topic 848 – Reference Rate Reform were elected on certain of these contracts to preserve fair value hedge accounting treatment. See Note 19 “Recent Accounting Pronouncements” for further information on Topic 848.
(c)The treasury lock agreements were terminated on January 29, 2024 concurrently with the issuance of senior notes which closed on February 1, 2024 (see Note 9 “Debt”).

Foreign Currency Risk Management

We utilize foreign currency derivatives to hedge our exposure to variability in foreign exchange rates. The following table summarizes our outstanding foreign currency contracts as of December 31, 2023:
Notional amountAccounting treatmentMaximum term
(In millions)
Derivatives designated as hedging instruments
EUR-to-USD cross currency swap contracts(a)$543 Cash flow hedgeMarch 2027
(a)These swaps eliminate the foreign currency risk associated with our Euro-denominated debt.

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Impact of Derivative Contracts on Our Consolidated Financial Statements

The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets:
Fair Value of Derivative Contracts
LocationDerivatives AssetDerivatives Liability
December 31,December 31,
2023202220232022
(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contracts
Fair value of derivative contracts/(Fair value of derivative contracts)$77 $150 $(75)$(156)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)12 6 (29)(91)
Subtotal89 156 (104)(247)
Interest rate contracts
Fair value of derivative contracts/(Fair value of derivative contracts)— — (120)(144)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)37 39 (158)(261)
Subtotal37 39 (278)(405)
Foreign currency contracts
Fair value of derivative contracts/(Fair value of derivative contracts)— — (2)(3)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)— — (2)(32)
Subtotal— — (4)(35)
Total126 195 (386)(687)
Derivatives not designated as hedging instruments
Energy commodity derivative contracts
Fair value of derivative contracts/(Fair value of derivative contracts)49 80 (8)(162)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)3 23 (1)(19)
Subtotal52 103 (9)(181)
Interest rate contracts
Fair value of derivative contracts/(Fair value of derivative contracts)— 1 — — 
Total52 104 (9)(181)
Total derivatives$178 $299 $(395)$(868)

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The following two tables summarize the fair value measurements of our derivative contracts based on the three levels established by the ASC. The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements.
 Balance sheet asset fair value measurements by level
 
Level 1
Level 2
Level 3		Gross amountContracts available for nettingCash collateral held(a)Net amount
(In millions)
As of December 31, 2023   
Energy commodity derivative contracts(b)$65 $75 $— $140 $(16)$— $124 
Interest rate contracts— 38 — 38 — — 38 
As of December 31, 2022   
Energy commodity derivative contracts(b)$115 $144 $— $259 $(186)$— $73 
Interest rate contracts— 40 — 40 — — 40 

Balance sheet liability
fair value measurements by level
Level 1Level 2Level 3Gross amountContracts available for nettingCash collateral posted(a)Net amount
(In millions)
As of December 31, 2023
Energy commodity derivative contracts(b)$(17)$(96)$— $(113)$16 $(85)$(182)
Interest rate contracts— (278)— (278)— — (278)
Foreign currency contracts— (4)— (4)— — (4)
As of December 31, 2022
Energy commodity derivative contracts(b)(23)(405)— (428)186 (30)(272)
Interest rate contracts— (405)— (405)— — (405)
Foreign currency contracts— (35)— (35)— — (35)
(a)Any cash collateral paid or received is reflected in this table, but only to the extent that it represents variation margins. Any amount associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from this table.
(b)Level 1 consists primarily of NYMEX natural gas futures.  Level 2 consists primarily of OTC WTI swaps, NGL swaps and crude oil basis swaps.

The following tables summarize the pre-tax impact of our derivative contracts in our accompanying consolidated statements of income and comprehensive income:
Derivatives in fair value hedging relationshipsLocationGain/(loss) recognized in income on derivatives and related hedged item
  Year Ended December 31,
  202320222021
(In millions)
Interest rate contractsInterest, net$138 $(738)$(322)
Hedged fixed rate debt(a)Interest, net$(132)$743 $326 
(a)As of December 31, 2023, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was a decrease of $236 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.
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Derivatives in cash flow hedging relationshipsGain/(loss) recognized in OCI on derivatives(a)LocationGain/(loss) reclassified from Accumulated OCI into income(b)
Year EndedYear Ended
 December 31, December 31,
 202320222021 202320222021
(In millions)(In millions)
Energy commodity derivative contracts$182 $(338)$(475)Revenues—Commodity sales$103 $(491)$(271)
   Costs of sales(73)144 20 
Interest rate contracts(10)7 5 Interest, net— — — 
Foreign currency contracts30 (73)(93)Other, net17 (68)(105)
Total$202 $(404)$(563)Total$47 $(415)$(356)
(a)We expect to reclassify an approximately $10 million loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of December 31, 2023 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.
(b)During the years ended December 31, 2023, 2022 and 2021, we recognized gains of none, $121 million and $41 million, respectively, associated with a write-down of hedged inventory. All other amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).

Derivatives not designated as accounting hedgesLocationGain/(loss) recognized in income on derivatives
 Year Ended December 31,
 202320222021
(In millions)
Energy commodity derivative contractsRevenues—Commodity sales$75 $137 $(652)
Costs of sales100 (190)152 
 Earnings from equity investments2 (11)(5)
Interest rate contractsInterest, net1 (10)12 
Total(a)$178 $(74)$(493)
(a)The years ended December 31, 2023, 2022 and 2021 include approximate gains (losses) of $58 million, $(11) million and $(479) million, respectively, associated with natural gas, crude and NGL derivative contract settlements.

Credit Risks

In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts.  As of December 31, 2023 and 2022, we had no outstanding letters of credit supporting our commodity price risk management program. As of December 31, 2023 and 2022, we had cash margins of $63 million and $1 million, respectively, posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheets. The balance at December 31, 2023 represents the initial margin requirements of $22 million, offset by counterparty variation margin requirements of $85 million. We also use industry standard commercial agreements that allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we generally utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty.

We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in our credit rating.  As of December 31, 2023, based on our current mark-to- market positions and posted collateral, we estimate that if our credit rating were downgraded one notch, we would not be required to post additional collateral. If we were downgraded two notches, we estimate that we would be required to post $54 million of additional collateral.

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15.  Revenue Recognition

Nature of Revenue by Segment

Natural Gas Pipelines Segment

We provide various types of natural gas transportation and storage services, natural gas and NGL sales contracts, and various types of gathering and processing services for producers, including receiving, compressing, transporting and re-delivering quantities of natural gas and/or NGLs made available to us by producers to a specified delivery location.

Natural Gas Transportation and Storage Contracts

The natural gas we receive under our transportation and storage contracts remains under the control of our customers. Under firm service contracts, the customer generally pays a two-part transaction price that includes (i) a fixed take-or-pay reservation fee and (ii) a fee-based per-unit rate for quantities of natural gas actually transported or injected into/withdrawn from storage. Under non-firm service contracts, generally described as interruptible service, the customer pays a transaction price on a fee-based per-unit rate for the quantities actually transported or injected into/withdrawn from storage.

Natural Gas and NGL Sales Contracts

Our sales and purchases of natural gas and NGL are primarily accounted for on a gross basis as natural gas sales or product sales, as applicable, and cost of sales. These customer contracts generally provide for the customer to nominate a specified quantity of commodity products to be delivered and sold to the customers at specified delivery points. The customer pays a transaction price typically based on a market indexed per-unit rate for the quantities sold.

Gathering and Processing Contracts

We provide various types of gathering and processing services for producers, including receiving, processing, compressing, transporting and re-delivering quantities of natural gas made available to us by producers to a specified delivery location. This integrated service can be firm if subject to a minimum volume commitment or acreage dedication or non-firm when offered on an as requested, non-guaranteed basis. In our gathering contracts we generally promise to provide the contracted integrated services each day over the life of the contract. The customer pays a transaction price typically based on a per-unit rate for the quantities actually gathered and/or processed, including amounts attributable to deficiency quantities associated with minimum volume contracts.

Products Pipelines Segment

We provide crude oil and refined petroleum transportation and storage services on a firm or non-firm basis. For our firm transportation service, the customer is obligated to pay for its minimum volume commitment amount, regardless of whether or not it flows volumes into our pipeline. The customer pays a transaction price typically based on a per-unit rate for quantities transported, including amounts attributable to deficiency quantities. Our firm storage service generally includes a fixed take-or-pay monthly reservation fee for the portion of storage capacity reserved by the customer and a per-unit rate for actual quantities injected into/withdrawn from storage. Under the non-firm transportation and storage service the customer typically pays a per-unit rate for actual quantities of product injected into/withdrawn from storage and/or transported.

We sell transmix, crude oil or other commodity products. The customer’s contracts generally include a specified quantity of commodity products to be delivered and sold to the customers at specified delivery points. The customer pays a transaction price typically based on a market indexed per-unit rate for the quantities sold.

Terminals Segment

We provide various types of liquid tank and bulk terminal services. These services are generally comprised of inbound, storage and outbound handling of customer products.

Liquids Tank Services

Firm Storage and Handling Contracts: We have liquids tank storage and handling service contracts that include a promised tank storage capacity provision and prepaid volume throughput of the stored product. In these contracts, the customers have fixed take-or-pay monthly obligation which generally include a per-unit rate for any quantities we handle at the request of the
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customer in excess of the prepaid volume throughput amount and also typically include per-unit rates for additional, ancillary services that may be periodically requested by the customer.

Firm Handling Contracts: For our firm handling service contracts, we typically promise to handle on a stand-ready basis throughput volumes up to the customer’s minimum volume commitment amount. The customer is obligated to pay for its minimum volume commitment amount, regardless of whether or not it used the handling service. The customer pays a transaction price typically based on a per-unit rate for volumes handled, including amounts attributable to deficiency quantities.

Bulk Services

Our bulk storage and handling contracts generally include inbound handling of our customers’ dry bulk material product (e.g., petcoke, metals, ores) into our storage facility and outbound handling of these products from our storage facility. These services are provided on both a firm basis, including amounts attributable to deficiency quantities, and non-firm basis where the customer pays a transaction price typically based on a per-unit rate for quantities handled on an as requested, non-guaranteed basis.

CO2 Segment

Our crude oil, NGL, CO2 and natural gas production customer sales contracts typically include a specified quantity and quality of commodity product to be delivered and sold to the customer at a specified delivery point. The customer pays a transaction price typically based on a market indexed per-unit rate for the quantities sold.

Disaggregation of Revenues

The following tables present our revenues disaggregated by segment, revenue source and type of revenue for each revenue source:
Year Ended December 31, 2023
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)$3,543 $171 $819 $1 $3 $4,537 
Fee-based services1,008 1,036 427 40 (9)2,502 
Total services4,551 1,207 1,246 41 (6)7,039 
Commodity sales
Natural gas sales2,651 — — 85 (12)2,724 
Product sales1,110 1,635 33 1,114 (8)3,884 
Total commodity sales3,761 1,635 33 1,199 (20)6,608 
Total revenues from contracts with customers8,312 2,842 1,279 1,240 (26)13,647 
Other revenues(c)
Leasing services(d)475 200 638 55 — 1,368 
Derivatives adjustments on commodity sales285 — — (107)— 178 
Other96 24 — 21 — 141 
Total other revenues856 224 638 (31)— 1,687 
Total revenues$9,168 $3,066 $1,917 $1,209 $(26)$15,334 

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Year Ended December 31, 2022
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)$3,547 $207 $763 $1 $(3)$4,515 
Fee-based services926 962 426 46 — 2,360 
Total services4,473 1,169 1,189 47 (3)6,875 
Commodity sales
Natural gas sales6,266 — — 94 (20)6,340 
Product sales1,433 2,032 29 1,426 (7)4,913 
Total commodity sales7,699 2,032 29 1,520 (27)11,253 
Total revenues from contracts with customers12,172 3,201 1,218 1,567 (30)18,128 
Other revenues(c)
Leasing services(d)474 194 574 60 — 1,302 
Derivatives adjustments on commodity sales(26)(3)— (325)— (354)
Other66 26 — 32 — 124 
Total other revenues514 217 574 (233)— 1,072 
Total revenues$12,686 $3,418 $1,792 $1,334 $(30)$19,200 

Year Ended December 31, 2021
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)$3,402 $259 $751 $1 $(2)$4,411 
Fee-based services746 949 375 45 (1)2,114 
Total services4,148 1,208 1,126 46 (3)6,525 
Commodity sales
Natural gas sales6,463 — — 32 (15)6,480 
Product sales1,260 845 24 1,070 (50)3,149 
Total commodity sales7,723 845 24 1,102 (65)9,629 
Total revenues from contracts with customers11,871 2,053 1,150 1,148 (68)16,154 
Other revenues(c)
Leasing services(d)473 172 565 56 — 1,266 
Derivatives adjustments on commodity sales(700)(1)— (222)— (923)
Other65 21 — 27 — 113 
Total other revenues(162)192 565 (139)— 456 
Total revenues$11,709 $2,245 $1,715 $1,009 $(68)$16,610 
(a)Differences between the revenue classifications presented on the consolidated statements of income and the categories for the disaggregated revenues by type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category above (see note (c)).
(b)Includes non-cancellable firm service customer contracts with take-or-pay or minimum volume commitment elements, including those contracts where both the price and quantity amount are fixed. Excludes service contracts with index-based pricing, which along with revenues from other customer service contracts are reported as “Fee-based services.”
(c)Amounts recognized as revenue under guidance prescribed in Topics of the ASC other than in Topic 606 were primarily from leases and derivative contracts. See Note 14 for additional information related to our derivative contracts.
(d)Our revenues from leasing services are predominantly comprised of specific assets that we lease to customers under operating leases where one customer obtains substantially all of the economic benefit from the asset and has the right to direct the use of that asset. These leases primarily consist of specific tanks, treating facilities, marine vessels and gas equipment and pipelines with separate control locations. We do not lease assets that qualify as sales-type or finance leases.

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Contract Balances

As of December 31, 2023 and 2022, our contract asset balances were $34 million and $33 million, respectively. Of the contract asset balance at December 31, 2022, $23 million was transferred to accounts receivable during the year ended December 31, 2023. As of December 31, 2023 and 2022, our contract liability balances were $415 million and $204 million, respectively. Of the contract liability balance at December 31, 2022, $71 million was recognized as revenue during the year ended December 31, 2023.

During the year ended December 31, 2023, we entered into an agreement with a customer to prepay certain fixed reservation charges under long-term transportation and terminaling contracts. We received $843 million in the fourth quarter of 2023 as part of this agreement. The prepayment, which relates to contracts expiring from 2035 to 2040, was discounted to present value at a rate that is attractive relative to our cost of issuing long-term debt. As of December 31, 2023, we had a lease contract liability balance of $643 million and a contract liability balance of $195 million associated with this prepayment.

Revenue Allocated to Remaining Performance Obligations

The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, representing our “contractually committed” revenue as of December 31, 2023 that we will invoice or transfer from contract liabilities and recognize in future periods:
YearEstimated Revenue
(In millions)
2024$4,687 
20254,007 
20263,472 
20272,874 
20282,475 
Thereafter14,336 
Total$31,851 

Our contractually committed revenue, for purposes of the tabular presentation above, is generally limited to service or commodity sale customer contracts which have fixed pricing and fixed volume terms and conditions, generally including contracts with take-or-pay or minimum volume commitment payment obligations. Our contractually committed revenue amounts, based on the practical expedient that we elected to apply, generally exclude remaining performance obligations for contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation.

16.  Reportable Segments
 
Our reportable business segments are:


•Natural Gas Pipelines—the ownership and operation of (i) major interstate and intrastate natural gas pipeline and storage systems; (ii) natural gas and crude oil gathering systems and natural gas processing and treating facilities; (iii) NGL fractionation facilities and transportation systems; and (iv) LNG regasification, liquefaction and storage facilities;

•
CO2—(i) the production, transportation and marketing of CO2 to oil fields that use CO2 as a flooding medium for recovering crude oil from mature oil fields to increase production; (ii) ownership interests in and/or operation of oil fields and gas processing plants in West Texas; and (iii) the ownership and operation of a crude oil pipeline system in West Texas;


Terminals—the ownership and/or operation of (i) liquids and bulk terminal facilities located throughout the U.S. and portions of Canada that transload and store refined petroleum products, crude oil, chemicals, and ethanol and bulk products, including petroleum coke, steel and coal; and (ii) Jones Act tankers;

•Products Pipelines—the ownership and operation of refined petroleum products, NGL and crude oil and condensate pipelines that primarily deliver, among other products, gasoline, diesel and jet fuel, propane, ethane, crude oil and condensate to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities;

•Terminals—the ownership and/or operation of (i) liquids and bulk terminal facilities located throughout the U.S. that store and handle various commodities including gasoline, diesel fuel, chemicals, petroleum coke, metals and ethanol and other renewable fuels and feedstocks; and (ii) Jones Act-qualified tankers;


Kinder Morgan Canada—•CO2—(i) the production, transportation and marketing of CO2 to oil fields that use CO2 as a flooding medium to increase recovery and production of crude oil from mature oil fields; (ii) ownership interests in and/or operation of oil fields and gasoline processing plants in West Texas; (iii) the ownership and operation of the Trans Mountaina crude oil pipeline system that transports crude oilin West Texas; and (iv) the ownership and refined petroleum products from Edmonton, Alberta, Canada to marketing terminalsoperation of RNG and refineries in British Columbia, Canada and the state of Washington, plus the Jet Fuel aviation turbine fuel pipeline that serves the Vancouver (Canada) International Airport.LNG facilities.


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We evaluate performance principally based on each segment’s EBDA,earnings before DD&A expenses, including amortization of excess cost of equity investments, (EBDA), which excludes general and administrative expenses and corporate charges, interest expense, net, and income tax expense.  Our reportable segments are strategic business units that offer different products and services, and they are structured based on how our chief operating decision makers organize their operations for optimal performance and resource allocation.  Each segment is managed separately because each segment involves different products and services and marketing strategies.


We consider each period’s earnings before all non-cash DD&A expenses to be an important measure of business segment performance for our reporting segments.  We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value.

During 2017, 20162023, 2022 and 2015,2021, we did not have revenues from any single external customer that exceeded 10% of our consolidated revenues.

 
Financial information by segment follows (in millions):follows: 

Year Ended December 31,
202320222021
(In millions)
Revenues   
Natural Gas Pipelines   
Revenues from external customers$9,152 $12,659 $11,644 
Intersegment revenues16 27 65 
Products Pipelines3,066 3,418 2,245 
Terminals 
Revenues from external customers1,911 1,789 1,712 
Intersegment revenues6 3 3 
CO2
Revenues from external customers1,205 1,334 1,009 
Intersegment revenues4 — — 
Corporate and intersegment eliminations(26)(30)(68)
Total consolidated revenues$15,334 $19,200 $16,610 
 Year Ended December 31,
202320222021
(In millions)
Operating expenses(a)   
Natural Gas Pipelines$4,700 $8,562 $7,000 
Products Pipelines2,024 2,391 1,239 
Terminals896 853 793 
CO2
550 554 289 
Corporate and intersegment eliminations(4)(9)(34)
Total consolidated operating expenses$8,166 $12,351 $9,287 
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 Year Ended December 31,
 2017 2016 2015
Revenues     
Natural Gas Pipelines     
Revenues from external customers$8,608
 $7,998
 $8,704
Intersegment revenues10
 7
 21
CO2
1,196
 1,221
 1,699
Terminals     
Revenues from external customers1,965
 1,921
 1,878
Intersegment revenues1
 1
 1
Products Pipelines     
Revenues from external customers1,645
 1,631
 1,828
Intersegment revenues16
 18
 3
Kinder Morgan Canada256
 253
 260
Corporate and intersegment eliminations(a)8
 8
 9
Total consolidated revenues$13,705
 $13,058
 $14,403
 Year Ended December 31,
 202320222021
(In millions)
Other expense (income)(b)   
Natural Gas Pipelines$(12)$(13)$1,597 
Products Pipelines4 (12)— 
Terminals(2)(14)32 
CO2
— (1)(8)
Corporate(3)1 (4)
Total consolidated other expense (income)$(13)$(39)$1,617 
 Year Ended December 31,
 202320222021
(In millions)
DD&A   
Natural Gas Pipelines$1,041 $1,096 $1,099 
Products Pipelines367 336 335 
Terminals493 458 440 
CO2
325 272 236 
Corporate24 24 25 
Total consolidated DD&A$2,250 $2,186 $2,135 
 Year Ended December 31,
 202320222021
(In millions)
Earnings from equity investments and amortization of excess cost of equity investments   
Natural Gas Pipelines$746 $650 $435 
Products Pipelines(6)33 34 
Terminals9 14 15 
CO2
23 31 29 
Total consolidated equity earnings$772 $728 $513 
 Year Ended December 31,
 202320222021
(In millions)
Other, net-income (expense)   
Natural Gas Pipelines$26 $(19)$216 
Products Pipelines1 — 1 
Terminals8 8 3 
Corporate(72)66 62 
Total consolidated other, net-income (expense)$(37)$55 $282 
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Year Ended December 31,
Year Ended December 31, 202320222021
(In millions)(In millions)
Segment EBDA(c)Segment EBDA(c)  
Natural Gas Pipelines
Products Pipelines
Terminals
CO2
2017 2016 2015
Operating expenses(b)     
Natural Gas Pipelines$5,457
 $4,393
 $4,738
CO2
394
 399
 432
Terminals788
 768
 836
Products Pipelines487
 573
 772
Kinder Morgan Canada95
 87
 87
Corporate and intersegment eliminations(6) 2
 26
Total consolidated operating expenses$7,215
 $6,222
 $6,891
Total Segment EBDA
Total Segment EBDA
Total Segment EBDA
DD&A
Amortization of excess cost of equity investments
General and administrative and corporate charges
Interest, net
Income tax expense
Total consolidated net income

 Year Ended December 31,
 202320222021
(In millions)
Capital expenditures   
Natural Gas Pipelines$1,299 $666 $570 
Products Pipelines221 — 122 
Terminals406 552 332 
CO2
355 371 230 
Corporate36 32 27 
Total consolidated capital expenditures$2,317 $1,621 $1,281 

December 31,
 20232022
(In millions)
Investments  
Natural Gas Pipelines$7,273 $6,993 
Products Pipelines390 445 
Terminals130 128 
CO2
81 87 
Total consolidated investments               $7,874 $7,653 

December 31,
 20232022
(In millions)
Other intangibles, net  
Natural Gas Pipelines$742 $439 
Products Pipelines687 777 
Terminals26 38 
CO2
502 555 
Total consolidated other intangibles, net              $1,957 $1,809 

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December 31,December 31,
20232022
(In millions)(In millions)
AssetsAssets  
Natural Gas Pipelines
Products Pipelines
Terminals
CO2
Year Ended December 31,
Corporate assets(d)
Corporate assets(d)
Corporate assets(d)
2017 2016 2015
Other expense (income)(c)     
Natural Gas Pipelines$26
 $199
 $1,269
CO2
(1) 19
 606
Terminals(14) 99
 190
Products Pipelines—
 76
 2
Kinder Morgan Canada—
 —
 (1)
Corporate1
 (7) —
Total consolidated other expense (income)$12
 $386
 $2,066
Total consolidated assets
Total consolidated assets
Total consolidated assets

(a)Includes costs of sales, operations and maintenance expenses, and taxes, other than income taxes.

(b)Includes (gain) loss on divestitures and impairments, net and other (expense) income, net.
(c)Includes revenues, earnings from equity investments, and other, net, less operating expenses, (gain) loss on divestitures and impairments, net and other (expense) income, net.
 Year Ended December 31,
 2017 2016 2015
DD&A     
Natural Gas Pipelines$1,011
 $1,041
 $1,046
CO2
493
 446
 556
Terminals472
 435
 433
Products Pipelines216
 221
 206
Kinder Morgan Canada46
 44
 46
Corporate23
 22
 22
Total consolidated DD&A$2,261
 $2,209
 $2,309
(d)Includes cash and cash equivalents, restricted deposits, certain prepaid assets and deferred charges, risk management assets related to derivative contracts, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy activity) not allocated to our reportable segments.

 Year Ended December 31,
 2017 2016 2015
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments     
Natural Gas Pipelines$253
 $(269) $285
CO2
42
 22
 (5)
Terminals24
 19
 17
Products Pipelines48
 56
 36
Total consolidated equity earnings$367
 $(172) $333

 Year Ended December 31,
 2017 2016 2015
Other, net-income (expense)     
Natural Gas Pipelines$49
 $19
 $24
Terminals8
 4
 8
Products Pipelines(1) 2
 4
Kinder Morgan Canada25
 15
 8
Corporate1
 4
 (1)
Total consolidated other, net-income (expense)$82
 $44
 $43


 Year Ended December 31,
 2017 2016 2015
Segment EBDA(d)     
Natural Gas Pipelines$3,487
 $3,211
 $3,067
CO2
847
 827
 658
Terminals1,224
 1,078
 878
Products Pipelines1,231
 1,067
 1,106
Kinder Morgan Canada186
 181
 182
Total segment EBDA6,975
 6,364
 5,891
DD&A(2,261) (2,209) (2,309)
Amortization of excess cost of equity investments(61) (59) (51)
General and administrative and corporate charges(660) (652) (708)
Interest, net(1,832) (1,806) (2,051)
Income tax expense(1,938) (917) (564)
Total consolidated net income$223
 $721
 $208

 Year Ended December 31,
 2017 2016 2015
Capital expenditures     
Natural Gas Pipelines$1,376
 $1,227
 $1,642
CO2
436
 276
 725
Terminals888
 983
 847
Products Pipelines127
 244
 524
Kinder Morgan Canada338
 124
 142
Corporate23
 28
 16
Total consolidated capital expenditures$3,188
 $2,882
 $3,896

 2017 2016  
Investments at December 31     
Natural Gas Pipelines$6,218
 $6,185
  
CO2
6
 —
  
Terminals263
 252
  
Products Pipelines777
 566
  
Kinder Morgan Canada34
 20
  
Corporate—
 4
  
Total consolidated investments                                                                           $7,298
 $7,027
  


 2017 2016  
Assets at December 31     
Natural Gas Pipelines$51,173
 $50,428
  
CO2
3,946
 4,065
  
Terminals9,935
 9,725
  
Products Pipelines8,539
 8,329
  
Kinder Morgan Canada2,080
 1,572
  
Corporate assets(e)3,382
 6,108
  
Assets held for sale—
 78
  
Total consolidated assets                                                                           $79,055
 $80,305
  
_______
(a)Includes a management fee for services we perform as operator of an equity investee. 
(b)Includes costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
(c)Includes loss on impairment of goodwill, loss on impairments and divestitures, net and other income, net.
(d)Includes revenues, earnings from equity investments, other, net, less operating expenses, and other income, net, loss on impairment of goodwill, and loss on impairments and divestitures, net and loss on impairments and divestitures of equity investments, net.
(e)Includes cash and cash equivalents, margin and restricted deposits, unallocable interest receivable, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to debt fair value adjustments, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy activity) not allocated to the reportable segments.


We do not attribute interest and debt expense to any of our reportable business segments.


Following is geographic information regarding the revenues and long-lived assets of our business (in millions):business:
 Year Ended December 31,
 202320222021
(In millions)
Revenues from external customers   
U.S.$15,255 $19,036 $16,479 
Mexico and other foreign79 164 131 
Total consolidated revenues from external customers$15,334 $19,200 $16,610 
 Year Ended December 31,
 2017 2016 2015
Revenues from external customers     
U.S.$13,073
 $12,459
 $13,797
Canada503
 483
 479
Mexico129
 116
 127
Total consolidated revenues from external customers$13,705
 $13,058
 $14,403
December 31,
 202320222021
(In millions)
Long-term assets, excluding goodwill and other intangibles  
U.S.$46,328 $44,425 $44,916 
Mexico and other foreign72 75 78 
Canada— 1 1 
Total consolidated long-lived assets$46,400 $44,501 $44,995 


 December 31,
 2017 2016 2015
Long-term assets, excluding goodwill and other intangibles     
U.S.$47,928
 $49,125
 $51,679
Canada3,071
 2,399
 2,193
Mexico80
 82
 67
Total consolidated long-lived assets$51,079
 $51,606
 $53,939

17.  Leases

Following are components of our lease cost:
Year Ended December 31,
202320222021
(In millions)
Operating leases$71 $62 $60 
Short-term and variable leases127 101 109 
Total lease cost$198 $163 $169 

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Other information related to our operating leases are as follows:
Year Ended December 31,
202320222021
(In millions,
except lease term and discount rate)
Operating cash flows from operating leases$(157)$(132)$(137)
Investing cash flows from operating leases(41)(31)(32)
ROU assets obtained in exchange for operating lease obligations, net of retirements56 22 59 
Amortization of ROU assets58 50 47 
Weighted average remaining lease term8.72 years9.8 years10.39 years
Weighted average discount rate4.59 %4.26 %3.95 %

Amounts recognized in the accompanying consolidated balance sheets are as follows:
December 31,
Lease Activity(a)Balance sheet location20232022
(In millions)
ROU assetsDeferred charges and other assets$285 $287 
Short-term lease liabilityOther current liabilities55 47 
Long-term lease liabilityOther long-term liabilities and deferred credits230 240 
(a)We have immaterial financing leases recorded as of December 31, 2023 and 2022.

Operating lease liabilities under non-cancellable leases (excluding short-term leases) as of December 31, 2023 are as follows:
YearCommitment
 (In millions)
2024$67 
202556 
202640 
202733 
202825 
Thereafter145 
Total lease payments366 
Less: Interest(81)
Present value of lease liabilities$285 

Short-term lease costs are not material to us and are anticipated to be similar to the current year short-term lease expense outlined in this disclosure.

18. Litigation Environmental and Other ContingenciesEnvironmental

We and our subsidiaries are parties to various legal, regulatory and other matters arising from the day-to-day operations of our businesses or certain predecessor operations that may result in claims against the Company. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves and insurance, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position, results of operations or dividends to our shareholders.business. We believe we have meritoriousnumerous and substantial defenses to the matters to which we are a party and intend to vigorously defend the Company. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose the following contingencies where an adverse outcome may be material or, in the judgment of management, we conclude the matter should otherwise be disclosed.

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FERC Proceedings

SFPP

The tariffs and rates charged by SFPP are subject to a number of ongoing proceedings at the FERC, including the complaints and protests of various shippers the most recent of which was filed in 2015 (docketed at OR16-6) challenging SFPP’s filed East Line rates. In general, these complaints and protests allege the rates and tariffs charged by SFPP are not just and reasonable under the Interstate Commerce Act (ICA). In some of these proceedings shippers have challenged the overall rate being charged by SFPP, and in others the shippers have challenged SFPP’s index-based rate increases. If the shippers prevail on their arguments or claims, they are entitled to seek reparations (which may reach back up to two years prior to the filing date of their complaints) or refunds of any excess rates paid, and SFPP may be required to reduce its rates going forward. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts. The issues involved in these proceedings include, among others, whether indexed rate increases are justified, and the appropriate level of return and income tax allowance SFPP may include in its rates. On March 22, 2016, the D.C. Circuit issued a decision in United Airlines, Inc. v. FERC remanding to FERC for further consideration of two issues: (1) the appropriate data to be used to determine the return on equity for SFPP in the underlying docket, and (2) the just and reasonable return to be provided to a tax pass-through entity that includes an income tax allowance in its underlying cost of service. On July 21, 2017, an initial decision by the Administrative Law Judge (ALJ) in OR16-6 concluded that the Complainants are due reparations, with appropriate interest, equal to the difference between what SFPP collected from the Complainants for service on the East Line and the amounts SFPP would have collected had it charged just and reasonable rates for that line.  The ALJ ruled that an income tax allowance should be included in the cost of service both to determine reparations and to set going forward rates, and found that the new just and reasonable rates are not knowable until the FERC reviews the initial decision and orders a compliance filing.  The FERC will determine which portions of the initial decision to affirm, reject or amend. With respect to the various SFPP related complaints and protest proceedings at the FERC, we estimate that the shippers are seeking approximately $40 million in annual rate reductions and approximately $230 million in refunds. Management believes SFPP has meritorious arguments supporting SFPP’s rates and intends to vigorously defend SFPP against these complaints and protests. However, to the extent the shippers are successful in one or more of the complaints or protest proceedings, SFPP estimates that applying the principles of FERC precedent, as applicable, to pending SFPP cases would result in rate reductions and refunds substantially lower than those sought by the shippers.

EPNG

The tariffs and rates charged by EPNG are subject to two ongoing FERC proceedings (the “2008 rate case” and the “2010 rate case”). With respect to the 2008 rate case, the FERC issued its decision (Opinion 517-A) in July 2015. The FERC generally upheld its prior determinations, ordered refunds to be paid within 60 days, and stated that it will apply its findings in Opinion 517-A to the same issues in the 2010 rate case. EPNG sought federal appellate review of Opinion 517-A and oral arguments were held on February 15, 2017. On February 21, 2017, the reviewing court delayed the case until the FERC rules on the rehearing requests pending in the 2010 Rate Case. With respect to the 2010 rate case, the FERC issued its decision (Opinion 528-A) on February 18, 2016. The FERC generally upheld its prior determinations, affirmed prior findings of an Administrative Law Judge that certain shippers qualify for lower rates, and required EPNG to file revised pro forma recalculated rates consistent with the terms of Opinions 517-A and 528-A. EPNG and two intervenors sought rehearing of certain aspects of the decision, and the judicial review sought by certain intervenors has been delayed until the FERC issues an order on rehearing. All refund obligations related to the 2008 rate case were satisfied during calendar year 2015. With respect to the 2010 rate case, EPNG believes it has an appropriate reserve related to the findings in Opinions 517-A and 528-A.

NGPL and WIC

On January 19, 2017, FERC initiated separate proceedings against NGPL and WICpursuant to section 5 of the Natural Gas Act. The matters were intended to determine whether NGPL’s and WIC’s current rates were just and reasonable. NGPL and WIC each submitted an Offer of Settlement to the FERC in their respective proceedings. The FERC approved WIC’s Offer of Settlement on November 27, 2017, and the FERC approved NGPL’s Offer of Settlement on January 5, 2018. These settlements will not have a material adverse impact on KMI’s results of operations or cash flows from operations.

TMEP Litigation

There are numerous legal challenges pending before the Federal Court of Appeal which have been filed by various governmental and non-governmental organizations, Aboriginal groups or other parties that seek judicial review of the recommendation of the NEB and subsequent decision by the Federal Governor in Council to conditionally approve the TMEP.

The petitions allege, among other things, that additional consultation, engagement or accommodation is required and that various non-economic impacts of the TMEP were not adequately considered. The remedies sought include requests that the NEB recommendation be quashed, that additional consultations be undertaken, and that the order of the Governor in Council approving the TMEP be quashed. After provincial elections in British Columbia (BC) on May 9, 2017, the New Democratic Party and Green Party formed a majority government. The new BC government sought and was granted limited intervenor status in the Federal Court of Appeal proceedings to argue against the government’s approval of the TMEP. A hearing was conducted by the Federal Court of Appeal from October 2 through October 13, 2017. A decision is expected in the coming months, and is subject to potential further appeal to the Supreme Court of Canada. Although we believe that each of the foregoing appeals lacks merit, in the event an applicant is successful at the Supreme Court of Canada, among other potential impacts, the NEB recommendation or Governor in Council’s approval may be quashed, permits may be revoked, the TMEP may be subject to additional significant regulatory reviews, there may be significant changes to the TMEP plans, further obligations or restrictions may be implemented, or the TMEP may be stopped altogether, which could materially impact the overall feasibility or economic benefits of the TMEP, which in turn would have a material adverse effect on the TMEP and, consequently, our investment in KML.

In addition to the judicial reviews of the NEB recommendation report and Governor in Council’s order, two judicial review proceedings have been commenced at the Supreme Court of BC (Squamish Nation; and the City of Vancouver). The petitions allege a duty and failure to consult or accommodate First Nations, and generally, among other claims, that the Province ought not to have approved the TMEP. Each Applicant seeks to quash the Environmental Assessment Certificate (EAC) that was issued by the BC Environmental Assessment Office. On September 29, 2017, the BC government filed evidence in support of the EAC approval in the judicial review proceeding involving the Squamish Nation. Hearings were conducted in October and November 2017, respectively, for the City of Vancouver and the Squamish Nation judicial review proceedings and the Court took the matters under consideration with decisions expected in the coming months. Although we believe that each of the foregoing appeals lacks merit, in the event that an applicant for judicial review is successful, among other potential impacts, the EAC may be quashed, provincial permits may be revoked, the TMEP may be subject to additional significant regulatory reviews, there may be significant changes to the TMEP plans, further obligations or restrictions may be imposed or the TMEP may be stopped altogether. In the event that an applicant is unsuccessful at the Supreme Court of BC, they may further seek to appeal the decision to the BC Court of Appeal. Any decision of the BC Court of Appeal may be appealed to the Supreme Court of Canada. A successful appeal at either of these levels could result in the same types of consequences described above.

On October 26, 2017 and November 14, 2017, Trans Mountain filed motions with the NEB. The first motion sought to resolve delays experienced by Trans Mountain in obtaining preliminary plan approvals from the City of Burnaby. The second motion sought to establish an NEB process to backstop provincial and municipal processes in a fair, transparent and expedited fashion. On December 7, 2017, the NEB issued an order granting the relief requested by Trans Mountain in respect of its motion related to Burnaby. On January 19, 2018, the NEB granted, in part, Trans Mountain’s motion by establishing a generic process to hear any future motions as they relate to provincial and municipal permitting issues. Burnaby or other interested parties may seek leave to appeal to the Federal Court of Appeal and, if unsuccessful at the Federal Court of Appeal, may further seek to appeal the decision to the Supreme Court of Canada. A successful appeal at either of these levels could result in either one or both of the NEB orders being quashed.

Other Commercial Matters
Union Pacific Railroad Company Easements & Related Litigation
SFPP and Union Pacific Railroad Company (UPRR) have engaged in litigation since 2004 to determine both the extent, if any, to which rent payable by SFPP for the use of pipeline easements on rights-of-way held by UPRR should be adjusted, and the circumstances and conditions under which SFPP must pay to relocate its pipeline within the UPRR rights-of-way. In July 2017, UPRR and SFPP reached a confidential settlement of both the rental and relocation litigation. The amount paid by SFPP to settle the rental litigation was within the right-of-way liability previously recorded by SFPP, and the parties generally agreed to share and allocate the cost of future potential relocations. Although the cost sharing mechanism in the settlement is expected to reduce the cost of future relocations, SFPP does not know UPRR’s plans for projects or other activities that would cause pipeline relocations such that it is difficult to quantify the cost of future potential relocations. Such costs could have an adverse effect on our financial position, results of operations, cash flows, and dividends to our shareholders.

A purported class action lawsuit was filed in 2015 in a U.S. District Court in California by private landowners who claim to be the lawful owners of subsurface real property allegedly used or occupied by UPRR or SFPP. Substantially similar follow-on lawsuits were filed in federal courts by landowners in Nevada, Arizona and New Mexico. These suits, which are brought purportedly as class actions on behalf of all landowners who own land in fee adjacent to and underlying the railroad easement under which the SFPP pipeline is located in those respective states, assert claims against UPRR, SFPP, KMGP, and Kinder

Morgan Operating L.P. “D” alleging that the defendants occupation and use of the subsurface real property was improper. Plaintiffs’ motions for class certification were denied by the federal courts in Arizona and California. The Ninth Circuit Court of Appeals denied Plaintiffs’ request for interlocutory review of the decisions on class certification. The New Mexico and Nevada lawsuits have been stayed. An additional suit was filed in a U.S. District Court in Arizona by private landowners seeking recovery for claims substantially the same as those made in the purported class actions. SFPP views the litigation involving private landowners as primarily a dispute between UPRR and the plaintiff landowners; as such, we expect the lawsuits will be resolved on terms that are not material to KMI’s results of operations, cash flows or dividends to shareholders.


Gulf LNG Facility ArbitrationDisputes


On March 1, 2016, Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) receivedfiled a Noticelawsuit in 2018 against Eni S.p.A. in the Supreme Court of Disagreement and Disputed Statements andthe State of New York to enforce a Notice of Arbitration fromGuarantee Agreement (Guarantee) entered into by Eni S.p.A. in 2007 in connection with a contemporaneous terminal use agreement entered into by its affiliate, Eni USA Gas Marketing LLC (Eni USA), one of two companies that entered into a terminal use agreement for capacity of. GLNG filed suit to enforce the Gulf LNG Facility in Mississippi for an initial term that is not scheduled to expire until the year 2031. Eni USA is an indirect subsidiary ofGuarantee against Eni S.p.A., a multi-national integrated energy company headquartered in Milan, Italy.  Pursuant to its Notice after an arbitration tribunal delivered an award which called for the termination of Arbitration, Eni USA seeks declaratory and monetary relief based upon its assertion that (i) the terminal use agreement should be terminated because changes in the U.S. natural gas market since the executionand payment of the agreement in December 2007 have “frustrated the essential purpose” of the agreement and (ii) activities allegedly undertakencompensation by affiliates of Gulf LNG Holdings Group LLC “in connection with a plan to convert the LNG Facility into a liquefaction/export facility have given rise to a contractual right on the part of Eni USA to terminate” the agreement.  As set forth inGLNG. In response to GLNG’s lawsuit, Eni S.p.A. filed counterclaims and other claims based on the terminal use agreement disputes are meantand a parent direct agreement with Gulf LNG Energy (Port), LLC. The foregoing counterclaims and other claims asserted by Eni S.p.A sought unspecified damages based on the same substantive allegations which were dismissed with prejudice in previous separate arbitrations with Eni USA described above and with GLNG’s remaining customer Angola LNG Supply Services LLC, a consortium of international oil companies including Eni S.p.A. In early 2022, the trial court granted Eni S.p.A’s motion for summary judgment on GLNG’s claims to be resolvedenforce the Guarantee. The Appellate Division denied GLNG’s appeal and its motion for rehearing in 2023. GLNG elected not to pursue further recourse to the state Court of Appeals, which is the state’s highest appellate court, thereby concluding GLNG’s efforts to enforce the Guarantee. With respect to the counterclaims and other claims asserted by finalEni S.p.A., the trial court granted GLNG’s motion for summary judgment and binding arbitration. A three-member arbitration panel conducted an arbitration hearingentered judgment dismissing all of Eni S.p.A.’s claims with prejudice on September 15, 2023. Eni S.p.A. filed a notice of appeal to the state Appellate Division. We intend to vigorously oppose Eni S.p.A’s appeal, which remains pending.

Freeport LNG Winter Storm Litigation

On September 13, 2021, Freeport LNG Marketing, LLC (Freeport) filed a lawsuit against KMTP and Kinder Morgan Tejas Pipeline LLC in January 2017. During fourth quarter 2017 the arbitration panel informed133rd District Court of Harris County, Texas (Case No. 2021-58787) alleging that defendants breached the partiesparties’ base contract for sale and purchase of natural gas by failing to repurchase natural gas nominated by Freeport between February 10-22, 2021 during Winter Storm Uri. We deny that we were obligated to repurchase natural gas from Freeport given our declaration of force majeure during the storm and our compliance with emergency orders issued by the Railroad Commission of Texas providing heightened priority for the delivery of gas to human needs customers. Freeport alleges that it expectsis owed approximately $104 million, plus attorney fees and interest. On October 24, 2022, the trial court granted our motion for summary judgment on all of Freeport’s claims. On November 21, 2022, Freeport filed a notice of appeal to issue its decision on or before February 28, 2018. Eni USA has indicated that it willthe 14th Court of Appeals, where the matter remains pending. We believe our declaration of force majeure was proper and intend to continue to pay the amounts claimed to be due pending resolution of the dispute. The successful assertion by Eni USA of its claim to terminate or amend its payment obligations under the agreement prior to the expiration of its initial term could have an adverse effect on the business, financial position, results of operations, or cash flows of GLNGvigorously defend this case.

Pension Plan Litigation

On February 22, 2021, Kinder Morgan Retirement Plan A participants Curtis Pedersen and distributions to KMI, a 50% shareholder of GLNG. We view the demand for arbitration to be without merit, and we will continue to contest it vigorously.

Brinckerhoff Merger Litigation

In April 2017,Beverly Leutloff filed a purported class action suit was filedlawsuit under the Employee Retirement Income Security Act of 1974 (ERISA). The named plaintiffs were hired initially by the ANR Pipeline Company (ANR) in the Delaware Court of Chancery by Peter Brinckerhoff, a former EPB unitholder on behalf of a class of former unaffiliated unitholders of EPB, seeking to challenge the $9.2 billion merger of EPB into a subsidiary of KMI as part oflate 1970s. Following a series of transactionscorporate acquisitions, plaintiffs became participants in November 2014 whereby KMI acquired allpension plans sponsored by the Coastal Corporation (Coastal), El Paso Corporation (El Paso) and our company by virtue of our acquisition of El Paso in 2012 and our assumption of certain of El Paso’s pension plan obligations. The complaint, which was filed initially in federal court in Michigan, then transferred to the outstanding equity interests in KMP, KMR,U.S. District Court for the Southern District of Texas (Civil Action No. 4:21-3590), and EPB that KMI and its subsidiaries did not already own. The suitlater amended to include the Kinder Morgan Retirement Plan B, alleges that the merger consideration did not sufficiently compensate EPB unitholdersseries of foregoing transactions resulted in changes to plaintiffs’ retirement benefits which are now contested on a purported class-wide basis in the lawsuit. The complaint asserts six claims that fall within three primary theories of liability. Claims I, II, and III all seek the same plan modification as to how the plans calculate benefits for former participants in the valueCoastal plan. These claims challenge plan provisions which are alleged to constitute impermissible “backloading” or “cutback” of benefits. Claims IV and V allege that former participants in the ANR plans should be eligible for unreduced benefits at younger ages than the plans currently provide. Claim VI asserts that actuarial assumptions used to calculate reduced early retirement benefits for current or former ANR employees are outdated and therefore unreasonable. On February 8, 2024, the Court certified a class defined as any and all persons who participated in the Kinder Morgan Retirement Plan A or B who are current or former employees of ANR or Coastal, and participated in the El Paso pension plan after El Paso acquired Coastal in 2001, and are members of at least one of three derivative suits concerning drop down transactions which the derivative plaintiff lost standing to pursue after the merger and which the present suit now alleges were collectively worth as much as $700 million. The suit claims that the alleged failure to obtain sufficient merger consideration for the drop down lawsuits constitutes a breachsubclasses of individuals who are allegedly due benefits under one or more of the EPB limited partnership agreement andsix claims asserted in the implied covenant of good faith and fair dealing. The suit also asserts claims against KMI and certain individual defendants for allegedly tortiously interfering with and/or aiding and abetting the alleged breach of the limited partnership agreement. Defendants’ motion to dismiss was granted, and the Court dismissed the suit in its entirety. Brinckerhoff filed a notice to appeal the dismissal. In November 2017, counsel for Brinckerhoff filed a separate lawsuit against KMEP and KMI seekingcomplaint. Plaintiffs seek to recover upearly retirement benefits as well as declaratory and injunctive relief, but have not pleaded, disclosed or otherwise specified a calculation of alleged damages. Accordingly, the extent of potential plan liabilities for past or future benefits, if any, remains to $44 millionbe determined in attorneys’ fees allegedly incurred in connection with the assertion of derivative claims that Brinckerhoff lost standinga bench trial scheduled to pursue. Defendantsbegin on August 5, 2024. We believe we have moved to dismiss the suit. We continue to believe that both the mergernumerous and the drop down transactions were appropriatesubstantial defenses and in the best interests of EPB, and we intend to continue tovigorously defend these lawsuits vigorously.this case.


Price Reporting Litigation

Beginning in 2003, several lawsuits were filed by purchasers of natural gas against El Paso Corporation, El Paso Marketing L.P. and numerous other energy companies based on a claim under state antitrust law that such defendants conspired to manipulate the price of natural gas by providing false price information to industry trade publications that published gas indices. Several of the cases have been settled or dismissed. The remaining cases, which are pending in a U.S. District Court in Nevada, were dismissed, but the dismissal was reversed by the NinthCircuit Court of Appeals. The U.S. Supreme Court affirmed the Ninth Circuit Court of Appeals in a decision dated April 21, 2015, and the cases were then remanded to the District Court for further consideration and trial, if necessary, of numerous remaining issues. On May 24, 2016, the District Court granted a motion for summary judgment dismissing a lawsuit brought by an industrial consumer in Kansas in which approximately $500 million in damages has been alleged. That ruling has been appealed to the Ninth Circuit Court of Appeals. Settlements have been reached in class actions originally filed in Kansas and Missouri, which settlements received final court approval and have been paid. In the remaining case, a Wisconsin class action in which approximately $300 million in damages

has been alleged against all defendants, the District Court denied plaintiff’s motion for class certification. The Ninth Circuit Court of Appeals granted plaintiff’s request for an interlocutory appeal of this ruling. There remains significant uncertainty regarding the validity of the causes of action, the damages asserted and the level of damages, if any, which may be allocated to us in the remaining lawsuits and therefore, our legal exposure, if any, and costs are not currently determinable.

Pipeline Integrity and Releases


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


Arizona Line 2000 Rupture

On August 15, 2021, the 30” EPNG Line 2000 natural gas transmission pipeline ruptured in a rural area in Coolidge, Arizona. The failure resulted in a fire which destroyed a home, resulting in two fatalities and one injury. The National Transportation Safety Board investigated the incident and issued its report on April 27, 2023. EPNG completed the physical work on Line 2000 in accordance with PHMSA’s requirements and returned the pipeline to commercial service in February 2023. We notified our insurers and resolved the claims presented by or on behalf of the owner and residents of the home without litigation or a material adverse impact to our business.

General

As of December 31, 20172023 and 2016,2022, our total reserve for legal matters was $350$23 million and $407$70 million, respectively. The reserve primarily relates to various claims from regulatory proceedings arising in our products and natural gas pipeline segments.


Environmental Matters

We and our subsidiaries are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to federal,local, state and localfederal laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal, and CO2 field and oil field, and our other operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments could result in substantial costs and liabilities to us, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us.operations.


We are currently involved in several governmental proceedings involving alleged violations of local, state and federal environmental and safety regulations, including alleged violations of the Risk Management Program and leak detection and repair requirements of the Clean Air Act.regulations. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. These alleged violations may result in fines and penalties, but except as disclosed herein we do not believe any such fines and penalties will be material to our business, individually or in the aggregate, will be material.aggregate. We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under state or federal administrative orders or related state remediation programs. We have established a reserve to address the costs associated with the cleanup.remediation efforts.


In addition, we are involved with and have been identified as a potentially responsible party (PRP) in several federal and state superfundSuperfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, crude oil, NGL, natural gas andor CO2., including natural resource damage (NRD) claims.


Portland Harbor Superfund Site, Willamette River, Portland, Oregon


In December 2000,On January 6, 2017, the EPA issued General Notice letters to potentially responsible parties including GATX Terminals Corporation (n/k/a KMLT). AtRecord of Decision (ROD) that time, GATX owned two liquids terminals alongestablished a final remedy and cleanup plan for an industrialized area on the lower reach of the Willamette River an industrialized area knowncommonly referred to as Portland Harbor. Portland Harbor is listed on the National Priorities List and is designated as a Superfund Site under CERCLA. A group of potentially responsible parties formed what is known as the Lower Willamette Group (LWG), of which KMLT is a non-voting member. The LWG agreed to conduct the remedial investigation and feasibility study (RI/FS) leading to the proposed remedy for cleanup of the Portland Harbor site.Superfund Site (PHSS). The EPA issued the FS and the Proposed Plan on June 8, 2016 which included a proposed combination of dredging, capping, and enhanced natural recovery. On January 6, 2017, the EPA issued its Record of Decision (ROD)cost for the final cleanup plan. The final remedy is estimated to be more stringent than the remedy proposed in the EPA’s Proposed Plan. The estimated cost increased from approximately $750 million to approximately $1.1$2.8 billion and active cleanup is now expected to take as long as 13more than 10 years to complete. KMLT, KMBT, and some 90 other partiesPRPs identified by the EPA are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs.costs related to the final remedy set forth by the ROD. We are participating in the allocation process on behalf of KMLT (in connection with its ownership or operation of two facilities) and KMBT in(in connection with their currentits ownership or former ownership or

operation of four facilities located in Portland Harbor.two facilities). Effective January 31, 2020, KMLT entered into separate Administrative Settlement Agreements and Orders on Consent (ASAOC) to complete remedial design for two distinct areas within the PHSS associated with KMLT’s facilities. The ASAOC obligates KMLT to pay a share of the remedial design costs for cleanup activities related to these two areas as required by the ROD. Our share of responsibility for Portland Harbor Superfund Sitethe PHSS costs will not be determined until the ongoing non-judicial allocation process is concluded in several years or a lawsuit is filed that results in a judicial decision allocating responsibility. At this time we anticipate the non-judicial allocation process will be
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complete in or around June 2025. Until the allocation process is completed, we are unable to reasonably estimate the extent of our liability for the costs related to the design of the proposed remedy and cleanup of the site. PHSS. Because costs associated with any remedial plan are expected to be spread over at least several years, we do not anticipate that our share of the costs of the remediation will have a material adverse impact to our business.

In addition to CERCLA cleanup costs, we are reviewing and will attempt to settle, if possible, natural resource damage (NRD)NRD claims in the amount of approximately $5 million asserted by state and federal trustees following their natural resource assessment of the site. At this time, we are unable to reasonably estimate the extent of our potential NRD liability.PHSS.

Roosevelt Irrigation District v. Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P. , U.S. District Court, Arizona
The Roosevelt Irrigation District sued KMGP, KMEP and others under CERCLA for alleged contamination of the water purveyor’s wells. The First Amended Complaint sought $175 million in damages from approximately 70 defendants. On August 6, 2013 plaintiffs filed their Second Amended Complaint seeking monetary damages in unspecified amounts and reducing the number of defendants to 26 including KMEP and SFPP. The claims now presented against KMEP and SFPP are related to alleged releases from a specific parcel within the SFPP Phoenix Terminal and the alleged impact of such releases on water wells owned by the plaintiffs and located in the vicinity of the Terminal. We filed an answer in response to the Second Amended Complaint and fact discovery is proceeding.

Uranium Mines in Vicinity of Cameron, Arizona

In the 1950s and 1960s, Rare Metals Inc., a historical subsidiary of EPNG, mined approximately twenty uranium mines in the vicinity of Cameron, Arizona, many of which are located on the Navajo Indian Reservation. The mining activities were in response to numerous incentives provided to industry by the U.S. to locate and produce domestic sources of uranium to support the Cold War-era nuclear weapons program. In May 2012, EPNG received a general notice letter from the EPA notifying EPNG of the EPA’s investigation of certain sites and its determination that the EPA considers EPNG to be a potentially responsible party within the meaning of CERCLA. In August 2013, EPNG and the EPA entered into an Administrative Order on Consent and Scope of Work pursuant to which EPNG is conducting a radiological assessment of the surface of the mines and the immediate vicinity. On September 3, 2014, EPNG filed a complaint in the U.S. District Court for the District of Arizona seeking cost recovery and contribution from the applicable federal government agencies toward the cost of environmental activities associated with the mines, given the position of the U.S. as owner of the Navajo Reservation, the U.S.’s exploration activities at the mines, and the pervasive control of such federal agencies over all aspects of the nuclear weapons program. Defendants filed an answer and counterclaims seeking contribution and recovery of response costs allegedly incurred by the federal agencies in investigating uranium impacts on the Navajo Reservation. The counterclaim of defendant EPA has been settled, and no viable claims for reimbursement by the other defendants are known to exist. In August 2017, the District Court found the U.S. liable under CERCLA as owner of the Navajo Reservation. The matter seeking cost recovery and contribution from federal government agencies is set for trial in February 2019. We intend to continue to prosecute and defend this case vigorously.


Lower Passaic River Study Area of the Diamond Alkali Superfund Site, Essex, Hudson, Bergen and Passaic Counties, New Jersey


EPEC Polymers, Inc. (EPEC Polymers) and EPEC Oil Company Liquidating Trust (EPEC Oil Trust), former El Paso Corporation entities now owned by KMI,(collectively EPEC) are involvedidentified as PRPs in an administrative action under CERCLA known as the Lower Passaic River Study Area Superfund Site (Site) concerning the lower 17-mile stretch of the Passaic River. It has been alleged that EPEC Polymers and EPEC Oil Trust may be potentially responsible parties (PRPs) under CERCLA based on prior ownership and/or operation of properties located along the relevant section of the Passaic River. EPEC Polymers and EPEC Oil Trust entered into two Administrative Orders on Consent (AOCs) which obligate them to investigate and characterize contamination at the Site. They are also part of a joint defense group of approximately 70 cooperating parties, referred to as the Cooperating Parties Group (CPG), which has entered into AOCs and is directing and funding the work required by the EPA. Under the first AOC, draft remedial investigation and feasibility studies (RI/FS) of the Site were submitted toRiver in New Jersey. On March 4, 2016, the EPA in 2015, and comments from the EPA remain pending. Under the second AOC, the CPG members conductedissued a CERCLA removal action at the Passaic River Mile 10.9, and the group is currently conducting EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with the AOCs.

On April 11, 2014, the EPA announced the issuance of its Focused Feasibility Study (FFS)ROD for the lower eight miles of the Passaic River Study Area, and its proposed plan for remedial alternatives to addressSite. At that time the dioxin sediment contamination from the mouth of Newark Bay to River Mile 8.3. The EPA estimates the cost for the alternatives will range from $365 million to $3.2 billion. The EPA’s preferred alternative would involve dredging the river bank-to-bank and installing an engineered cap at

an estimated cost of $1.7 billion. On March 4, 2016, the EPA issued its Record of Decision (ROD) for the lower eight miles of the Passaic River Study area. The final cleanup plan in the ROD is substantially similarwas estimated to the EPA’s preferred alternative announced on April 11, 2014. On October 5, 2016, the EPA entered into an AOC with one member of the PRP group requiring such member to spend $165 million to perform engineering and design work necessary to begin the cleanup of the lower eight miles of the Passaic River.cost $1.7 billion. The design work is expected to take four years to complete and the cleanup is expected to take at least six years to complete.

complete once it begins. In addition, the EPA has notifiedand numerous PRPs, including EPEC, Polymers and EPEC Oil Trust that it intends to proposeengaged in an allocation process for the implementation of the remedy for the lower eight miles of the Passaic River Study area. The allocationSite. That process has not been finalizedwas completed December 28, 2020 and we anticipatecertain PRPs, including EPEC, engaged in discussions with the EPA will propose an allocation during 2018. There remains significant uncertainty as toa result thereof. On October 4, 2021, the implementation and associated costs ofEPA issued a ROD for the remedy set forth in the FFS and ROD. There is also uncertainty as to the impact of the RI/FS that the CPG is currently preparing for portionsupper nine miles of the Site. The draft RI/FSAt that time, the cleanup plan in the ROD was submitted by the CPG in 2015 and proposes a different remedy than the FFS announced by the EPA. Therefore, the scope of potential EPA claimsestimated to cost $440 million. No timeline for the lower eight milescleanup has been established. On December 16, 2022, the United States Department of Justice (DOJ) and the EPA announced a settlement and proposed consent decree with 85 PRPs, including EPEC, to resolve their collective liability at the Site. The total amount of the Passaic Riversettlement is not reasonably estimable at this time.

Southeast Louisiana Flood Protection Litigation

On July 24, 2013,$150 million. Also on December 16, 2022, the Board of CommissionersDOJ on behalf of the Southeast Louisiana Flood Protection Authority - East (SLFPA)EPA filed a petition for damagesComplaint against the 85 PRPs, including EPEC, a Notice of Lodging of Consent Decree, and injunctive reliefa Consent Decree in a state district court for Orleans Parish, Louisiana against TGP, SNG and approximately 100 other energy companies, alleging that defendants’ drilling, dredging, pipeline and industrial operations since the 1930’s have caused direct land loss and increased erosion and submergence resulting in alleged increased storm surge risk, increased flood protection costs and unspecified damages to the plaintiff. The SLFPA asserts claims for negligence, strict liability, public nuisance, private nuisance, and breach of contract. Among other relief, the petition seeks unspecified monetary damages, attorney fees, interest, and injunctive relief in the form of abatement and restoration of the alleged coastal land loss including but not limited to backfilling and re-vegetation of canals, wetlands and reef creation, land bridge construction, hydrologic restoration, shoreline protection, structural protection, and bank stabilization. On August 13, 2013, the suit was removed to the U.S. District Court for the Eastern District of Louisiana.New Jersey. On February 13, 2015,January 17, 2024, the Court granted defendants’ motion to dismissDOJ on behalf of the suit for failure to stateEPA voluntarily dismissed its Complaint against 3 PRPs, filed an Amended Complaint against 82 PRPs, including EPEC, and a claim, and issued an order dismissing the SLFPA’s claims with prejudice. On March 3, 2017, the Fifth Circuit Court of Appeals affirmedmodified Consent Decree in the U.S. District Court’s decision,Court. On January 31, 2024, the DOJ on behalf of the EPA filed a motion to Enter Consent Decree in the U.S. District Court. We believe our share of the costs to resolve this matter, including our share of the settlement with the EPA and the SLFPA’s petition for writcosts to remediate the Site, if any, will not have a material adverse impact to our business.

Louisiana Governmental Coastal Zone Erosion Litigation

Beginning in 2013, several parishes in Louisiana and the City of certiorariNew Orleans filed separate lawsuits in state district courts in Louisiana against a number of oil and gas companies, including TGP and SNG. In these cases, the parishes and New Orleans, as Plaintiffs, allege that certain of the defendants’ oil and gas exploration, production and transportation operations were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended (SLCRMA) and that those operations caused substantial damage to the U.S. Supreme Court was denied on October 30, 2017, thereby resolving this mattercoastal waters of Louisiana and nearby lands. The Plaintiffs seek, among other relief, unspecified money damages, attorneys’ fees, interest, and payment of costs necessary to restore the affected areas. There are more than 40 of these cases pending in its entirety.Louisiana against oil and gas companies, one of which is against TGP and one of which is against SNG, both described further below.

Plaquemines Parish Louisiana Coastal Zone Litigation


On November 8, 2013, the Parish of Plaquemines, Louisiana and others filed a petition for damages in the state district court for Plaquemines Parish, Louisiana against TGP and 17 other energy companies, alleging that the defendants’ oil and gas exploration, production and transportation operations in the Bastian Bay, Buras, EmpirePlaquemines Parish violated SLCRMA and Fort Jackson oilLouisiana law, and gas fields of Plaquemines Parish caused substantial damage to the coastal waters and nearby lands (Coastal Zone) within the Parish, including the erosion of marshes and the discharge of oil waste and other pollutants which detrimentally affected the quality of state waters and plant and animal life, in violation of the State and Local Coastal Resources Management Act of 1978 (Coastal Zone Management Act). As a result of such alleged violations of the Coastal Zone Management Act,lands. Plaquemines Parish seeks, among other relief, unspecified monetary relief,money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected Coastal Zone to its original condition, including costs to clear, vegetate and detoxifyareas. In May 2018, the Coastal Zone. In connection with this suit, TGP has made two tenders for defense and indemnity: (1) to Anadarko, as successor to the entity that purchased TGP’s oil and gas assets in Bastian Bay, and (2) to Kinetica, which purchased TGP’s pipeline assets in Bastian Bay in 2013. Anadarko has accepted TGP’s tender (limited to oil and gas assets), and Kinetica rejected TGP’s tender. The Louisiana Department of Natural Resources and Attorney General have intervened in the lawsuit. The Court has separated the defendants into several trial groups with trials expected to be set to begin in 2019. We expect the case involving TGP will be set for trial in 2020. We will continue to vigorously defend the suit.

Vermilion Parish Louisiana Coastal Zone Litigation

On July 28, 2016, the District Attorney for the Fifteenth Judicial District of Louisiana, purporting to act on behalf of Vermilion Parish and the State of Louisiana, filed suit in the state district court for Vermilion Parish, Louisiana against TGP and 52 other energy companies, alleging that the defendants’ oil and gas and transportation operations associated with the development of several fields in Vermilion Parish (Operational Areas) were conducted in violation of the Coastal Zone Management Act. The suit alleges such operations caused substantial damage to the coastal waters and nearby lands (Coastal Zone) of Vermilion Parish, resulting in the release of pollutants and contaminants into the environment, improper discharge of oil field wastes, the improper use of waste pits and failure to close such pits, and the dredging of canals, which resulted in degradation of the Operational Areas, including erosion of marshes and degradation of terrestrial and aquatic life therein. As a

result of such alleged violations of the Coastal Zone Management Act, the suit seeks a judgment against the defendants awarding all appropriate damages, the payment of costs to clear, revegetate, detoxify and otherwise restore the Vermilion Parish Coastal Zone, actual restoration of the affected Coastal Zone to its original condition, and reasonable costs and attorney fees. On September 2, 2016, the case was removed to the U.S. District Court for the Western District of Louisiana. Plaintiffs filed a motion to remand the case to the state district court. On September 26, 2017, the U.S. District Court remanded the case to the State District Court for Vermillion Parish. We intend to vigorously defend the suit.

Vintage Assets, Inc. Coastal Erosion Litigation

On December 18, 2015, Vintage Assets, Inc. and several individual landowners filed a petition in the State District Court for Plaquemines Parish, Louisiana alleging that its 5,000 acre property is composed of coastal wetlands, and that SNG and TGP failed to maintain pipeline canals and banks, causing widening of the canals, land loss, and damage to the ecology and hydrology of the marsh, in breach of right of way agreements, prudent operating practices, and Louisiana law. The suit also claims that defendants’ alleged failure to maintain pipeline canals and banks constitutes negligence and has resulted in encroachment of the canals, constituting trespass. The suit seeks in excess of $80 million in money damages, including recovery of litigation costs, damages for trespass, and money damages associated with an alleged loss of natural resources and projected reconstruction cost of replacing or restoring wetlands. The suit was removed to the U.S. District Court for the Eastern District of Louisiana. The SNG assets at issue were sold to Highpoint Gas Transmission, LLC in 2011, which was subsequently purchased by American Midstream Partners, LP. In response to SNG’s demand for defense and indemnity, American Midstream Partners agreed to pay 50% of joint defense costs and expenses, with a percentage of indemnity to be determined upon finalcase has been effectively stayed pending the resolution of jurisdictional issues in separate, consolidated cases to which TGP is not a party; The Parish of Plaquemines, et al. vs. Chevron USA, Inc. et al. consolidated with The Parish of Cameron, et al. v. BP America Production Company, et al. Those cases were removed to federal court and subsequently remanded to the suit.state district courts for Plaquemines and Cameron Parishes, respectively. On October 20, 2016, plaintiffs filed an amended complaint naming Highpoint Gas Transmission, LLC as an additional defendant. A non-jury trial was held during September 2017.27, 2023, the U.S. District Court ordered the case be stayed and administratively closed pending the resolution of jurisdictional issues. At this time, we are not able to reasonably estimate the extent of our potential liability, if any. We anticipate a ruling in the first quarter 2018. We will continueintend to vigorously defend this case.

On March 29, 2019, the suit,City of New Orleans (Orleans) filed a petition for damages in the state district court for Orleans Parish, Louisiana against SNG and 10 other energy companies alleging that the defendants’ operations in Orleans Parish violated the SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Orleans seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In April 2019, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In January 2020, the U.S. District Court ordered the case to be stayed and administratively closed pending the resolution of
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issues in a separate case to which SNG is not a party. On May 3, 2023, the U.S. District Court re-opened the case. At this time, we are not able to reasonably estimate the extent of our potential liability, if any. We intend to appealvigorously defend this case.

Hurricane Harvey Emission Event

In August 2017, KMLT discovered that three tanks at its Pasadena, Texas Terminal failed during Hurricane Harvey. The tank failures resulted in emissions of products being stored in the tanks. The emissions were properly reported to the Texas Commission on Environmental Quality. On November 15, 2019, the State of Texas filed a petition against KMLT in a state district court in Harris County, Texas alleging that violations of maintenance standards contributed to cause both the tank failures in August 2017, and a subsequent tank failure in 2018. The State seeks monetary penalties and corrective actions by KMLT. The State amended its petition in May 2023; the amended petition also seeks penalties and corrective actions. We intend to vigorously defend this case, and we do not anticipate the cost to resolve this matter including the costs to comply with corrective actions, if any, adverse ruling that may result from the trial.will have a material impact to our business.


General

Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we and our subsidiaries are a party, will not have a material adverse effect on our business, financial position, results of operations or cash flows.business. As of December 31, 20172023 and 2016,2022, we have accrued a total reserve for environmental liabilities in the amount of $279$199 million and $302$221 million, respectively. In addition, as of both December 31, 20172023 and 2016,2022, we havehad receivables of $11 million and $12 million, respectively, recorded a receivable of $13 million for expected cost recoveries that have been deemed probable.


Challenge to Federal “Good Neighbor Plan”
18.  Recent Accounting Pronouncements

On July 14, 2023, we filed a Petition for Review against the EPA and others in the U.S. Court of Appeals for the District of Columbia Circuit seeking review of the EPA’s final action promulgating the EPA’s final rule known as the “Good Neighbor Plan” (the Plan). The Plan was published in the Federal Register as a final rule on June 5, 2023. The Plan is a federal implementation plan to address certain interstate transport requirements of the Clean Air Act for the 2015 8-hour Ozone NAAQS. We believe that the Plan is deeply flawed and that numerous and substantial bases for challenging the Plan exist. 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. On July 27, 2023, we filed a Motion to Stay the Plan Pending Review, and on September 25, 2023, the U.S. Court of Appeals denied the Motion. On October 13, 2023, we filed an Emergency Application for Stay of Final Agency Action in the United States Supreme Court. On December 20, 2023, the Supreme Court issued an order deferring consideration of the Emergency Application for Stay pending oral argument which is scheduled to take place February 21, 2024.

On July 31, 2023 and September 29, 2023, the EPA published interim final rules entitled, respectively, “Federal ‘Good Neighbor Plan’ for the 2015 Ozone NAAQS; Response to Judicial Stays of SIP Disapproval Action for Certain States” and “Federal ‘Good Neighbor Plan’ for the 2015 Ozone NAAQS; Response to Additional Judicial Stays of SIP Disapproval Action for Certain States.” We filed petitions for review against the EPA and others in the U.S. Court of Appeals for the District of Columbia seeking review of the interim final rule and the second interim final rule on September 29, 2023 and November 17, 2023, respectively.

If the Plan were to remain in effect in its current form (including full compliance by its compliance deadline, and assuming failure of all pending challenges to state implementation plan disapprovals and no successful challenge to the Plan), we anticipate that it would have a material impact on us. However, impacts of the Plan are difficult to predict, given the extensive pending litigation. We would seek to mitigate the impacts, and to recover expenditures through adjustments to our rates on our regulated assets where available.

19.Recent Accounting Pronouncements

Accounting Standards Updates


Topic 606Reference Rate Reform (Topic 848)


On May 28, 2014,March 12, 2020, the FASB issued ASU No. 2014-09,2020-04, “Revenue from Contracts with CustomersReference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting.” followed by a series of related accounting standard updates (collectively referredThis ASU provides temporary optional expedients and exceptions to as “Topic 606”). Topic 606 is designed to create greater revenue recognition and disclosure comparability in financial statements. The provisions of Topic 606 include a five-step process by which an entity will determine revenue recognition, depicting the transfer of goods or services to customers in amounts reflecting the payment to which an entity expects to be entitled in exchange for those goods or services. Topic 606 requires certain disclosures about contracts with customers and provides more comprehensiveGAAP guidance for transactions such as service revenue,on contract modifications and multiple-element arrangements.

Topic 606 will require that our revenue recognition policy disclosure include further detail regarding our performance obligations ashedge accounting to ease the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers. Topic 606 will require us to reclassify certain gathering and processing service fees currently reflected as revenues within our Natural Gas segment as reductions to Cost of sales in the Consolidated Statements of Income prospectively beginning January 1, 2018.  Topic 606 will also require disclosure of significant changes in contract asset and contract liability balances period to period and the amountfinancial reporting burdens of the transaction price allocatedexpected market
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transition from LIBOR and other interbank offered rates to performance obligations that are unsatisfied (or partially unsatisfied)alternative reference rates, such as of the end of the reporting period, as applicable. We utilized the modified retrospective method to adopt the provisions of this standard effective January 1, 2018, which required usSOFR. Entities can elect not to apply certain modification accounting requirements to contracts affected by reference rate reform, if certain criteria are met. An entity that makes this election would not have to remeasure the new revenue standardcontracts at the modification date or reassess a previous accounting determination. Entities can also elect various optional expedients that would allow them to (i) all new revenue contracts entered into aftercontinue applying hedge accounting for hedging relationships affected by reference rate reform, if certain criteria are met.

On January 1, 2018 and (ii) all existing revenue contracts as of January 1, 2018 through a cumulative adjustment to our retained deficit balance. In accordance with this approach, our consolidated revenues for periods

prior to January 1, 2018 will not be revised. The cumulative effect of the adoption of this standard as of January 1, 2018 was not material.

ASU No. 2015-11

On July 22, 2015,7, 2021, the FASB issued ASU No. 2015-11,2021-01, “InventoryReference Rate Reform (Topic 330)848): Simplifying the Measurement of Inventory.Scope.” This ASU requires entitiesclarifies that all derivative instruments affected by changes to subsequently measure inventory at the lower of cost and net realizable value, and defines net realizable value as the estimated sellinginterest rates used for discounting, margining or contract price alignment (the “Discounting Transition”) are in the ordinary coursescope of business, less reasonably predictable costs of completion, disposal,Topic 848 and transportation. ASU No. 2015-11 was effective January 1, 2017. We adopted ASU No. 2015-11 with no material impacttherefore qualify for the available temporary optional expedients and exceptions. As such, entities that employ derivatives that are the designated hedged item in a hedge relationship where perfect effectiveness is assumed can continue to our financial statements.apply hedge accounting without de-designating the hedging relationship to the extent such derivatives are impacted by the Discounting Transition.


ASU No. 2016-02

On February 25, 2016,December 21, 2022, the FASB issued ASU No. 2016-02,2022-06, “LeasesReference Rate Reform (Topic 842).848): Deferral of the Sunset Date of Topic 848.” This ASU requires that lessees recognize assetsdefers the sunset date of Topic 848 from December 31, 2022, to December 31, 2024, after which entities will no longer be permitted to apply the optional expedients and liabilities onexceptions in Topic 848.

The guidance was effective upon issuance.

We amended certain of our existing fixed-to-variable interest rate swap agreements, which were designated as fair value hedges, to transition the balance sheet for the present valuevariable leg of such agreements from LIBOR to SOFR. Concurrent with these amendments, we elected certain of the rights and obligations created by all leases with termsoptional expedients provided in Topic 848 which allow us to maintain our prior designation of more than 12 months. The ASU also will require disclosures designedfair value hedge accounting to give financial statement usersthese agreements. As of December 31, 2023, we no longer have any such agreements outstanding that include a LIBOR reference rate. See Note 14 “Risk Management—Interest Rate Risk Management” for more information on the amount, timing, and uncertainty of cash flows arising from leases. ASU 2016-02 will be effective for us as of January 1, 2019. We are currently reviewing the effect of ASU No. 2016-02.our interest rate risk management activities.


ASU No. 2016-092023-07


On March 30, 2016,November 27, 2023, the FASB issued ASU No. 2016-09, 2023-07, “Compensation - Stock CompensationSegment Reporting (Topic 718)280): Improvements to Reportable Segment Disclosures.” This ASU was issued as partamends reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. This ASU is effective for annual periods beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption of the FASB’s simplification initiativeASU is permitted. Management is currently evaluating this ASU to determine its impact on the Company’s annual and affects all entities that issue share-based payment awards to their employees. This ASU covers accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. ASU No. 2016-09 was effective January 1, 2017. We adopted ASU No. 2016-09 with no material impact to our financial statements. See Note 5 “Income Taxes.”interim disclosures.


ASU No. 2016-132023-09


On June 16, 2016,December 14, 2023, the FASB issued ASU No. 2016-13,2023-09, “Financial Instruments - Credit LossesIncome Taxes (Topic 326)740): Measurement of Credit Losses on Financial InstrumentsImprovements to Income Tax Disclosures.” This ASU modifiesimproves the impairment model to utilize an expected loss methodology in placetransparency of the currently used incurred loss methodology, which will resultincome tax disclosures by requiring (i) consistent categories and greater disaggregation of information in the more timely recognition of losses.rate reconciliation and (ii) income taxes paid disaggregated by jurisdiction. This ASU No. 2016-13 will be effective for us as of January 1, 2020. We areannual periods beginning after December 15, 2024, and early adoption is permitted. Management is currently reviewing the effect of ASU No. 2016-13.

ASU No. 2016-18

On November 17, 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force).” This ASU requires the statement of cash flows to explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are to be included with cash and cash equivalents when reconciling the beginning of period and end of period amounts shown on the statement of cash flows.  We adopted ASU No. 2016-18 effective January 1, 2018 with no material impact to our financial statements.

ASU No. 2017-04

On January 26, 2017, the FASB issued ASU No. 2017-04, “Simplifying the Test for Goodwill Impairment (Topic 350)” to simplify the accounting for goodwill impairment. The guidance removes Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. ASU No. 2017-04 will be effective for us as of January 1, 2020. We are currently reviewing the effect ofevaluating this ASU to determine its impact on the Company’s annual disclosures.

Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.
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Item 9A. Controls and Procedures.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of December 31, 2023, our financial statements.

ASU No. 2017-05

On February 22, 2017,management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the FASB issued ASU No. 2017-05, “Other Income-Gainseffectiveness of the design and Losses fromoperation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the DerecognitionSecurities Exchange Act of Nonfinancial Assets (Subtopic 610-20): Clarifying1934.  There are inherent limitations to the Scopeeffectiveness of Asset Derecognition Guidanceany system of disclosure controls and Accounting for Partial Salesprocedures, including the possibility of Nonfinancial Assets.”  This ASU clarifieshuman error and the scopecircumvention or overriding of the controls and applicationprocedures.  Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of ASC 610-20 on contracts forachieving their control objectives.  Based upon and as of the sale or transferdate of nonfinancial assetsthe evaluation, our Chief Executive Officer and in substance nonfinancial assets to noncustomers, including partial sales. This ASU also clarifiesour Chief Financial Officer concluded that the derecognitiondesign and operation of all businesses isour disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the scopereports we file or submit under the Securities Exchange Act of ASC 8101934 is recorded, processed, summarized and defines an “in substance nonfinancial asset.” We utilizedreported within the modified retrospective method to adopttime periods specified in the provisions of this ASU effective January 1, 2018, which required us to apply the

new standard to (i) all new contracts entered into after January 1, 2018,SEC’s rules and (ii) to contracts that were not completed contracts as of January 1, 2018 through a cumulative adjustmentforms, and is accumulated and communicated to our retained deficit balance. The cumulative effectmanagement, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f).  Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.  Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an assessment of the adoptioneffectiveness of this standard asour internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of January 1, 2018 was less than $100 million. We will also reclassify EIG’s cumulative contribution to ELC of $485 million from “Other long-term liabilities and deferred credits” to a mezzanine equity classification described as “Redeemable noncontrolling interest” on our future consolidated balance sheets.

ASU No. 2017-07

On March 10, 2017, the FASB issued ASU No. 2017-07, “Compensation - Retirement Benefits (Topic 715).” This ASU requires an employer to disaggregate the service cost component from the other components of net benefit cost, allows only the service cost component of net benefit cost to be eligible for capitalization, and addresses how to present the service cost component and the other components of net benefit cost in the income statement. We adopted ASU No. 2017-07 effective January 1, 2018 with no material impact to our financial statements.

ASU No. 2017-12

On August 28, 2017, the FASB issued ASU No. 2017-12, “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” This ASU amends and simplifies existing guidance in order to allow companies to more accurately present the economic effects of risk management activities in the financial statements. ASU No. 2017-12 will be effective for us as of January 1, 2019, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.

ASU No. 2018-01

On January 25, 2018, the FASB issued ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842.” This ASU provides an optional transition practical expedient that, if elected, would not require companies to reconsider its accounting for existing or expired land easements before the adoption of Topic 842 and that were not previously accounted for as leases under Topic 840. ASU No. 2018-01 will be effective for us as of January 1, 2019, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.

19. Guarantee of Securities of Subsidiaries

KMI, along with its direct subsidiary KMP, are issuers of certain public debt securities. KMI, KMP and substantially all of KMI’s wholly owned domestic subsidiaries, 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, the parent issuer, subsidiary issuer and other subsidiaries are all guarantors of each series of public debt. As a resultSponsoring Organizations of the cross guarantee agreement, a holder of any of the guaranteed public debt securities issued by KMI or KMP are in the same position with respect to the net assets, income and cash flows of KMI and the Subsidiary Issuer and Guarantors. The only amountsTreadway Commission.  Based on this assessment, our management concluded that are not available to the holders of each of the guaranteed public debt securities to satisfy the repayment of such securities are the net assets, income and cash flows of the Subsidiary Non-Guarantors.

In lieu of providing separateour internal control over financial statements for subsidiary issuer and guarantor, we have included the accompanying condensed consolidating financial statements based on Rule 3-10 of the SEC’s Regulation S-X.  We have presented each of the parent and subsidiary issuer in separate columns in this single set of condensed consolidating financial statements.

On September 1, 2016, we sold a 50% equity interest in SNG (see further details discussed in Note 3, “Acquisitions and Divestitures”). Subsequent to the transaction, we deconsolidated SNG and now account for our equity interest in SNG as an equity investment. Our wholly owned subsidiary which holds our interest in SNG is reflected within the Subsidiary Guarantors column of these condensed consolidating financial statements.

On December 31, 2017, KMP’s interests in Kinder Morgan Bulk Terminals LLC were transferred to KMI. The following condensed consolidating financial information reflects this transaction for all periods presented.

Excluding fair value adjustments,reporting was effective as of December 31, 2017, Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, and Subsidiary Guarantors had $13,750 million, $18,885 million, and $3,310 million of Guaranteed Notes outstanding, respectively.   Included in the Subsidiary Guarantors debt balance as presented in the accompanying December 31,2023.

2017 condensed consolidating balance sheet are approximately $162 million of capitalized lease debt that is not subject to the cross guarantee agreement.


The accounts within the Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, Subsidiary Guarantors and Subsidiary Non-Guarantors are presented using the equity method of accounting for investments in subsidiaries, including subsidiaries that are guarantors and non-guarantors, for purposes of these condensed consolidating financial statements only.  These intercompany investments and related activity eliminate in consolidation and are presented separately in the accompanying condensed consolidating balance sheets and statements of income and cash flows.

A significant amount of each Issuers’ income and cash flow is generated by its respective subsidiaries.  As a result, the funds necessary to meet its debt service and/or guarantee obligations are provided in large part by distributions or advances it receives from its respective subsidiaries.  We utilize a centralized cash pooling program among our majority-owned and consolidated subsidiaries, including the Subsidiary Issuers and Guarantors and Subsidiary Non-Guarantors. The following Condensed Consolidating Statements of Cash Flows present the intercompany loan and distribution activity, as well as cash collection and payments made on behalfeffectiveness of our subsidiaries,internal control over financial reporting as cash activities.of December 31, 2023, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their audit report, which appears herein.



We completed the STX Midstream acquisition in a purchase business acquisition on December 28, 2023. We excluded this business from the scope of management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2023. STX Midstream’s total assets and total revenues each represent less than 3% of our related consolidated financial statement amounts as of and for the year ended December 31, 2023.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the fourth quarter of 2023 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.  Other Information.
Condensed Consolidating Statements of Income and Comprehensive Income
for the Year Ended December 31, 2017
(In Millions)
  Parent
Issuer and
Guarantor		 Subsidiary
Issuer and
Guarantor -
KMP		 Subsidiary
Guarantors		 Subsidiary
Non-Guarantors		 Consolidating Adjustments Consolidated KMI
Total Revenues $35
 $—
 $12,202
 $1,614
 $(146) $13,705
             
Operating Costs, Expenses and Other            
Costs of sales —
 —
 4,124
 322
 (101) 4,345
Depreciation, depletion and amortization 16
 —
 1,933
 312
 —
 2,261
Other operating expenses 76
 1
 2,999
 524
 (45) 3,555
Total Operating Costs, Expenses and Other 92

1

9,056

1,158

(146)
10,161
             
Operating (Loss) Income (57) (1)
3,146

456

—
 3,544
             
Other Income (Expense)            
Earnings from consolidated subsidiaries 3,575
 2,681
 419
 59
 (6,734) —
Earnings from equity investments —
 —
 428
 —
 —
 428
Interest, net (701) 7
 (1,104) (34) —
 (1,832)
Amortization of excess cost of equity investments and other, net —
 —
 (2) 23
 —
 21
             
Income Before Income Taxes 2,817
 2,687

2,887

504

(6,734) 2,161
             
Income Tax (Expense) Benefit (2,634) (5) 237
 464
 —
 (1,938)
             
Net Income 183
 2,682

3,124

968

(6,734) 223
Net Income Attributable to Noncontrolling Interests —
 —
 —
 —
 (40) (40)
             
Net Income Attributable to Controlling Interests 183
 2,682

3,124

968

(6,774) 183
Preferred Stock Dividends (156) —
 —
 —
 —
 (156)
Net Income Available to Common Stockholders $27
 $2,682
 $3,124
 $968
 $(6,774) $27
             
Net Income $183
 $2,682

$3,124

$968

$(6,734) $223
Total other comprehensive income 69
 194
 217
 160
 (525) 115
Comprehensive income 252
 2,876

3,341

1,128

(7,259) 338
Comprehensive income attributable to noncontrolling interests —
 —
 —
 —
 (86) (86)
Comprehensive income attributable to controlling interests $252
 $2,876

$3,341

$1,128

$(7,345) $252


During the quarter ended December 31, 2023, none of our directors or officers (as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934) adopted, terminated or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K).

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.
Condensed Consolidating Statements of Income and Comprehensive Income
for the Year Ended December 31, 2016
(In Millions)
  Parent
Issuer and
Guarantor		 Subsidiary
Issuer and
Guarantor -
KMP		 Subsidiary
Guarantors		 Subsidiary
Non-Guarantors		 Consolidating Adjustments Consolidated KMI
Total Revenues $34
 $—
 $11,572
 $1,511
 $(59) $13,058
             
Operating Costs, Expenses and Other            
Costs of sales —
 —
 3,176
 266
 (13) 3,429
Depreciation, depletion and amortization 18
 —
 1,872
 319
 —
 2,209
Other operating expenses 725
 (36) 2,459
 746
 (46) 3,848
Total Operating Costs, Expenses and Other 743
 (36) 7,507
 1,331
 (59) 9,486
             
Operating (Loss) Income (709) 36
 4,065
 180
 —
 3,572
             
Other Income (Expense)            
Earnings from consolidated subsidiaries 2,948
 2,802
 245
 58
 (6,053) —
Losses from equity investments —
 —
 (113) —
 —
 (113)
Interest, net (696) 90
 (1,149) (51) —
 (1,806)
Amortization of excess cost of equity investments and other, net —
 —
 (20) 5
 —
 (15)
             
Income Before Income Taxes 1,543
 2,928
 3,028
 192
 (6,053) 1,638
             
Income Tax Expense (835) (5) (33) (44) —
 (917)
             
Net Income 708
 2,923
 2,995
 148
 (6,053) 721
Net Income Attributable to Noncontrolling Interests —
 —
 —
 —
 (13) (13)
             
Net Income Attributable to Controlling Interests 708
 $2,923
 $2,995
 $148
 $(6,066) $708
Preferred Stock Dividends (156) $—
 $—
 $—
 $—
 $(156)
Net Income Available to Common Stockholders $552
 $2,923
 $2,995
 $148
 $(6,066) $552
             
Net Income $708
 $2,923
 $2,995
 $148
 $(6,053) $721
Total other comprehensive (loss) income (200) (341) (352) 55
 638
 (200)
Comprehensive income 508
 2,582
 2,643
 203
 (5,415) 521
Comprehensive income attributable to noncontrolling interests —
 —
 —
 —
 (13) (13)
Comprehensive income attributable to controlling interests $508
 $2,582
 $2,643
 $203
 $(5,428) $508

Condensed Consolidating Statements of Income and Comprehensive Income
for the Year Ended December 31, 2015
(In Millions)
  Parent
Issuer and
Guarantor		 Subsidiary
Issuer and
Guarantor -
KMP		 Subsidiary
Guarantors		 Subsidiary
Non-Guarantors		 Consolidating Adjustments Consolidated KMI
Total Revenues $37
 $—
 $12,840
 $1,575
 $(49) $14,403
             
Operating Costs, Expenses and Other            
Costs of sales —
 —
 3,691
 367
 1
 4,059
Depreciation, depletion and amortization 22
 —
 1,929
 358
 —
 2,309
Other operating expenses 71
 38
 4,770
 759
 (50) 5,588
Total Operating Costs, Expenses and Other 93
 38
 10,390
 1,484
 (49) 11,956
             
Operating (Loss) Income (56) (38) 2,450
 91
 —
 2,447
             
Other Income (Expense)            
Earnings (losses) from consolidated subsidiaries 1,430
 1,631
 118
 (30) (3,149) —
Earnings from equity investments —
 —
 384
 —
 —
 384
Interest, net (686) 23
 (1,345) (43) —
 (2,051)
Amortization of excess cost of equity investments and other, net —
 1
 (17) 8
 —
 (8)
             
Income Before Income Taxes 688
 1,617
 1,590
 26
 (3,149) 772
             
Income Tax Expense (435) (4) (6) (119) —
 (564)
             
Net Income (Loss) 253
 1,613
 1,584
 (93) (3,149) 208
Net Loss Attributable to Noncontrolling Interests —
 —
 —
 —
 45
 45
             
Net Income (Loss) Attributable to Controlling Interests 253
 1,613
 1,584
 (93) (3,104) 253
Preferred Stock Dividends (26) —
 —
 —
 —
 (26)
Net Income (Loss) Available to Common Stockholders 227
 1,613
 1,584
 (93) (3,104) 227
             
Net Income (Loss) $253
 $1,613
 $1,584
 $(93) $(3,149) $208
Total other comprehensive loss (444) (460) (325) (326) 1,111
 (444)
Comprehensive (loss) income (191) 1,153
 1,259
 (419) (2,038) (236)
Comprehensive loss attributable to noncontrolling interests —
 —
 —
 —
 45
 45
Comprehensive (loss) income attributable to controlling interests $(191) $1,153
 $1,259
 $(419) $(1,993) $(191)


Condensed Consolidating Balance Sheet as of December 31, 2017
(In Millions)

  Parent
Issuer and
Guarantor		 Subsidiary
Issuer and
Guarantor -
KMP		 Subsidiary
Guarantors		 Subsidiary
Non-Guarantors		 
Consolidating
Adjustments
 Consolidated KMI
ASSETS            
Cash and cash equivalents $3
 $—
 $—
 $262
 $(1) $264
Other current assets - affiliates 6,214
 5,201
 22,402
 858
 (34,675) —
All other current assets 243
 59
 1,938
 235
 (24) 2,451
Property, plant and equipment, net 236
 —
 31,093
 8,826
 —
 40,155
Investments 665
 —
 6,498
 135
 —
 7,298
Investments in subsidiaries 37,983
 36,728
 5,417
 4,232
 (84,360) —
Goodwill 13,789
 22
 5,166
 3,185
 —
 22,162
Notes receivable from affiliates 1,033
 20,363
 1,233
 776
 (23,405) —
Deferred income taxes 3,635
 —
 —
 —
 (1,591) 2,044
Other non-current assets 254
 164
 4,080
 183
 —
 4,681
Total assets $64,055
 $62,537

$77,827

$18,692

$(144,056) $79,055
             
LIABILITIES AND STOCKHOLDERS’ EQUITY            
Liabilities            
Current portion of debt $924
 $975
 $805
 $124
 $—
 $2,828
Other current liabilities - affiliates 13,225
 14,188
 6,512
 750
 (34,675) —
All other current liabilities 468
 347
 2,055
 508
 (25) 3,353
Long-term debt 13,104
 18,206
 3,052
 653
 —
 35,015
Notes payable to affiliates 2,009
 448
 20,593
 355
 (23,405) —
Deferred income taxes —
 —
 449
 1,142
 (1,591) —
Other long-term liabilities and deferred credits 689
 117
 1,462
 467
 —
 2,735
     Total liabilities 30,419
 34,281

34,928

3,999

(59,696)
43,931
             
Stockholders’ equity            
Total KMI equity 33,636
 28,256
 42,899
 14,693
 (85,848) 33,636
Noncontrolling interests —
 —
 —
 —
 1,488
 1,488
Total stockholders’ equity 33,636
 28,256

42,899

14,693

(84,360) 35,124
Total liabilities and stockholders’ equity $64,055
 $62,537

$77,827

$18,692

$(144,056) $79,055

Condensed Consolidating Balance Sheet as of December 31, 2016
(In Millions)
  Parent
Issuer and
Guarantor		 Subsidiary
Issuer and
Guarantor -
KMP		 Subsidiary
Guarantors		 Subsidiary
Non-Guarantors		 
Consolidating
Adjustments
 Consolidated KMI
ASSETS            
Cash and cash equivalents $471
 $—
 $9
 $205
 $(1) $684
Other current assets - affiliates 5,739
 1,999
 13,207
 655
 (21,600) —
All other current assets 269
 139
 1,935
 205
 (3) 2,545
Property, plant and equipment, net 242
 —
 30,795
 7,668
 —
 38,705
Investments 665
 2
 6,236
 124
 —
 7,027
Investments in subsidiaries 26,907
 28,894
 4,307
 4,015
 (64,123) —
Goodwill 13,789
 22
 5,167
 3,174
 —
 22,152
Notes receivable from affiliates 516
 21,608
 1,132
 412
 (23,668) —
Deferred income taxes 6,647
 —
 —
 —
 (2,295) 4,352
Other non-current assets 72
 206
 4,455
 107
 —
 4,840
Total assets $55,317
 $52,870
 $67,243
 $16,565
 $(111,690) $80,305
             
LIABILITIES AND STOCKHOLDERS’ EQUITY            
Liabilities            
Current portion of debt $1,286
 $600
 $687
 $123
 $—
 $2,696
Other current liabilities - affiliates 3,551
 13,299
 4,197
 553
 (21,600) —
All other current liabilities 432
 362
 2,016
 422
 (4) 3,228
Long-term debt 13,308
 19,277
 4,095
 674
 —
 37,354
Notes payable to affiliates 1,533
 448
 20,520
 1,167
 (23,668) —
Deferred income taxes —
 —
 681
 1,614
 (2,295) —
Other long-term liabilities and deferred credits 776
 111
 821
 517
 —
 2,225
     Total liabilities 20,886
 34,097
 33,017
 5,070
 (47,567) 45,503
             
Stockholders’ equity            
Total KMI equity 34,431
 18,773
 34,226
 11,495
 (64,494) 34,431
Noncontrolling interests —
 —
 —
 —
 371
 371
Total stockholders’ equity 34,431
 18,773
 34,226
 11,495
 (64,123) 34,802
Total liabilities and stockholders’ equity $55,317
 $52,870
 $67,243
 $16,565
 $(111,690) $80,305




Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2017
(In Millions)

  Parent
Issuer and
Guarantor		 Subsidiary
Issuer and
Guarantor -
KMP		 Subsidiary
Guarantors		 Subsidiary
Non-Guarantors		 Consolidating Adjustments Consolidated KMI
Net cash (used in) provided by operating activities $(3,184) $3,911
 $11,523
 $1,121
 $(8,770) $4,601
             
Cash flows from investing activities            
Acquisitions of assets and investments, net of cash acquired —
 —
 (4) —
 —
 (4)
Capital expenditures (23) —
 (2,390) (775) —
 (3,188)
Sales of property, plant and equipment, investments and other net assets, net of removal costs 16
 —
 94
 8
 —
 118
Contributions to investments (237) —
 (435) (12) —
 (684)
Distributions from equity investments in excess of cumulative earnings 2,297
 —
 326
 —
 (2,249) 374
Funding (to) from affiliates (4,419) 779
 (7,040) (1,028) 11,708
 —
Other, net (23) 36
 4
 5
 —
 22
Net cash (used in) provided by investing activities (2,389) 815
 (9,445)
(1,802)
9,459
 (3,362)
             
Cash flows from financing activities            
Issuances of debt 8,609
 —
 —
 259
 —
 8,868
Payments of debt (9,288) (600) (897) (279) —
 (11,064)
Debt issue costs (12) —
 —
 (58) —
 (70)
Cash dividends - common shares (1,120) —
 —
 —
 —
 (1,120)
Cash dividends - preferred shares (156) —
 —
 —
 —
 (156)
Repurchases of shares (250) —
 —
 —
 —
 (250)
Funding from (to) affiliates 7,327
 776
 3,797
 (192) (11,708) —
Contributions from investment partner —
 —
 485
 —
 —
 485
Contributions from parents, including net proceeds from KML IPO and preferred share issuance —
 —
 —
 1,673
 (1,673) —
Contributions from noncontrolling interests - net proceeds from KML IPO 4
 —
—
—
 —
 1,241
 1,245
Contributions from noncontrolling interests - net proceeds from KML preferred share issuances —
 —
 —
 —
 420
 420
Contributions from noncontrolling interests - other —
 —
 —
 —
 12
 12
Distributions to parents —
 (4,902) (5,472) (687) 11,061
 —
Distributions to noncontrolling interests —
 —
 —
 —
 (42) (42)
Other, net (9) —
 —
 —
 —
 (9)
Net cash provided by (used in) financing activities 5,105
 (4,726) (2,087)
716

(689) (1,681)
             
Effect of exchange rate changes on cash and cash equivalents —
 —
 —
 22
 —
 22
             
Net (decrease) increase in cash and cash equivalents (468) —
 (9)
57

—
 (420)
Cash and cash equivalents, beginning of period 471
 —
 9
 205
 (1) 684
Cash and cash equivalents, end of period $3
 $—
 $—

$262

$(1) $264

Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2016
(In Millions)
  Parent
Issuer and
Guarantor		 Subsidiary
Issuer and
Guarantor -
KMP		 Subsidiary
Guarantors		 Subsidiary
Non-Guarantors		 Consolidating Adjustments Consolidated KMI
Net cash (used in) provided by operating activities $(3,981) $4,980
 $11,641
 $885
 $(8,730) $4,795
             
Cash flows from investing activities            
Acquisitions of assets and investments (2) —
 (331) —
 —
 (333)
Capital expenditures (27) —
 (2,258) (597) —
 (2,882)
Proceeds from sale of equity interests in subsidiaries net —
 —
 1,401
 —
 —
 1,401
Sales of property, plant and equipment, investments and other net assets, net of removal costs 6
 —
 326
 (2) —
 330
Contributions to investments (343) —
 (54) (11) —
 (408)
Distributions from equity investments in excess of cumulative earnings 2,417
 298
 190
 —
 (2,674) 231
Funding to affiliates (2,820) (535) (5,062) (727) 9,144
 —
Other, net —
 (73) 39
 (10) —
 (44)
Net cash used in investing activities (769) (310) (5,749) (1,347) 6,470
 (1,705)
             
Cash flows from financing activities            
Issuances of debt 8,255
 —
 374
 —
 —
 8,629
Payments of debt (7,322) (500) (2,227) (11) —
 (10,060)
Debt issue costs (16) —
 (2) (1) —
 (19)
Cash dividends - common shares (1,118) —
 —
 —
 —
 (1,118)
Cash dividends - preferred shares (154) —
 —
 —
 —
 (154)
Funding from affiliates 5,461
 1,116
 1,959
 608
 (9,144) —
Contributions from parents —
 —
 117
 —
 (117) —
Contributions from noncontrolling interests —
 —
 —
 —
 117
 117
Distributions to parents —
 (5,286) (6,116) (73) 11,475
 —
Distributions to noncontrolling interests —
 —
 —
 —
 (24) (24)
Other, net (8) —
 —
 —
 —
 (8)
Net cash provided by (used in) financing activities 5,098
 (4,670) (5,895) 523
 2,307
 (2,637)
             
Effect of exchange rate changes on cash and cash equivalents —
 —
 —
 2
 —
 2
             
Net increase (decrease) in cash and cash equivalents 348
 —
 (3) 63
 47
 455
Cash and cash equivalents, beginning of period 123
 —
 12
 142
 (48) 229
Cash and cash equivalents, end of period $471
 $—
 $9
 $205
 $(1) $684

Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2015
(In Millions)
  Parent
Issuer and
Guarantor		 Subsidiary
Issuer and
Guarantor -
KMP		 Subsidiary
Guarantors		 Subsidiary
Non-Guarantors		 Consolidating Adjustments Consolidated KMI
Net cash (used in) provided by operating activities $(4,208) $6,824
 $11,039
 $347
 $(8,689) $5,313
             
Cash flows from investing activities            
Acquisitions of assets and investments (1,843) —
 (236) —
 —
 (2,079)
Capital expenditures (10) —
 (3,555) (331) —
 (3,896)
Sales of property, plant and equipment, investments, and other net assets, net of removal costs —
 —
 39
 —
 —
 39
Contributions to investments (21) —
 (70) (10) 5
 (96)
Distributions from equity investments in excess of cumulative earnings 2,653
 —
 143
 —
 (2,568) 228
Investment in KMP (159) —
 —
 —
 159
 —
Funding to affiliates (3,204) (8,388) (7,980) (779) 20,351
 —
Other, net —
 24
 16
 58
 —
 98
Net cash used in investing activities (2,584) (8,364) (11,643) (1,062) 17,947
 (5,706)
             
Cash flows from financing activities            
Issuances of debt 14,316
 —
 —
 —
 —
 14,316
Payments of debt (14,048) (675) (383) (10) —
 (15,116)
Debt issue costs (24) —
 —
 —
 —
 (24)
Issuances of common shares 3,870
 —
 —
 —
 —
 3,870
Issuance of mandatory convertible preferred stock 1,541
 —
 —
 —
 —
 1,541
Cash dividends - common shares (4,224) —
 —
 —
 —
 (4,224)
Repurchases of warrants (12) —
 —
 —
 —
 (12)
Funding from affiliates 5,502
 6,989
 7,112
 748
 (20,351) —
Contributions from parents —
 156
 3
 16
 (175) —
Contributions from noncontrolling interests —
 —
 —
 —
 11
 11
Distributions to parents —
 (4,944) (6,133) (166) 11,243
 —
Distributions to noncontrolling interests —
 —
 —
 —
 (34) (34)
Other, net (10) (1) —
 —
 —
 (11)
Net cash provided by financing activities 6,911
 1,525
 599
 588
 (9,306) 317
             
Effect of exchange rate changes on cash and cash equivalents —
 —
 —
 (10) —
 (10)
             
Net increase (decrease) in cash and cash equivalents 119
 (15) (5) (137)
(48) (86)
Cash and cash equivalents, beginning of period 4
 15
 17
 279
 —
 315
Cash and cash equivalents, end of period $123
 $—
 $12
 $142

$(48) $229


Supplemental Selected Quarterly Financial Data (Unaudited)

 Quarters Ended
 March 31 June 30 September 30 December 31
 (In millions, except per share amounts)
2017       
Revenues$3,424
 $3,368
 $3,281
 $3,632
Operating Income980
 922
 830
 812
Net Income (Loss)445
 383
 387
 (992)
Net Income (Loss) Attributable to Kinder Morgan, Inc.440
 376
 373
 (1,006)
Net Income (Loss) Available to Common Stockholders401
 337
 334
 (1,045)
Basic and Diluted Earnings (Loss) Per Common Share0.18
 0.15
 0.15
 (0.47)
        
2016       
Revenues$3,195
 $3,144
 $3,330
 $3,389
Operating Income816
 940
 882
 934
Net Income (Loss)314
 375
 (183) 215
Net Income (Loss) Attributable to Kinder Morgan, Inc.315
 372
 (188) 209
Net Income (Loss) Available to Common Stockholders276
 333
 (227) 170
Basic and Diluted Earnings (Loss) Per Common Share0.12
 0.15
 (0.10) 0.08

Item 16.  Form 10-K Summary.


Not Applicable.


132

PART III

Item 10.  Directors, Executive Officers and Corporate Governance.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2024 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2024.

Item 11. Executive Compensation.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2024 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2024.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2024 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2024.

Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2024 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2024.

Item 14.  Principal Accounting Fees and Services.

The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2024 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2024.
133

PART IV

Item 15.  Exhibits, Financial Statement Schedules.

(a)Documents Filed as Part of the Report

(1) Financial Statements

See Part II, Item 8. “Financial Statements and Supplementary Data—Index to Financial Statements” set forth on Page70.


(2) Financial Statement Schedules

Financial statement schedules are omitted because they are not applicable or the required information is contained in the consolidated financial statements or notes thereto.

(3)Exhibits

Exhibit NumberDescription
3.1
3.2
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
134

4.13
4.14
4.15
4.16
4.17
4.18
4.19
4.20
4.21
4.22
4.23
4.24
4.25
4.26
4.27
135

4.28
4.29
4.32
4.33
4.34
4.35
4.36
4.37
4.38Certain instruments with respect to long-term debt of KMI and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of KMI and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. sec. #229.601. KMI hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request.
4.39
4.40
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
136

10.10
10.11
21.1
22.1
23.1
31.1
31.2
32.1
32.2
97.1
101Interactive data files (formatted as Inline XBRL).
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

Item 16.  Form 10-K Summary.

Not Applicable.
137

SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
KINDER MORGAN, INC.
Registrant
By: /s/ Kimberly A. Dang/s/ David P. Michels
Kimberly A. Dang
David P. Michels
Vice President and Chief Financial Officer
(principal financial and accounting officer)
Date:February 9, 201820, 2024



138

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.
SignatureTitleDate
SignatureTitleDate
/s/ KIMBERLY A. DANGDAVID P. MICHELSVice President and Chief Financial Officer (principal financial officer and principal accounting officer); DirectorFebruary 9, 201820, 2024
KimberlyDavid P. Michels
/s/ KIMBERLY A. DangDANG
/s/ STEVEN J. KEANPresident and Chief Executive Officer (principal executive officer); DirectorFebruary 9, 201820, 2024
Steven J. KeanKimberly A. Dang
/s/ RICHARD D. KINDERExecutive ChairmanFebruary 9, 201820, 2024
Richard D. Kinder
/s/ TED A. GARDNERDirectorDirectorFebruary 9, 201820, 2024
Ted A. Gardner
/s/ ANTHONY W. HALL, JR.DirectorDirectorFebruary 9, 201820, 2024
Anthony W. Hall, Jr.
/s/ STEVEN J. KEANDirectorFebruary 20, 2024
Steven J. Kean
/s/ GARY L. HULTQUISTDirectorFebruary 9, 2018
Gary L. Hultquist
/s/ RONALD L. KUEHN, JR.DirectorDirectorFebruary 9, 201820, 2024
Ronald L. Kuehn, Jr.
/s/ DEBORAH A. MACDONALDDirectorDirectorFebruary 9, 201820, 2024
Deborah A. Macdonald
/s/ MICHAEL C. MORGANDirectorDirectorFebruary 9, 201820, 2024
Michael C. Morgan
/s/ ARTHUR C. REICHSTETTERDirectorDirectorFebruary 9, 201820, 2024
Arthur C. Reichstetter
/s/ FAYEZ SAROFIMDirectorFebruary 9, 2018
Fayez Sarofim
/s/ C. PARK SHAPERDirectorDirectorFebruary 9, 201820, 2024
C. Park Shaper
/s/ WILLIAM A. SMITHDirectorDirectorFebruary 9, 201820, 2024
William A. Smith
/s/ JOEL V. STAFFDirectorDirectorFebruary 9, 201820, 2024
Joel V. Staff
/s/ ROBERT F. VAGTDirectorDirectorFebruary 9, 201820, 2024
Robert F. Vagt
/s/ PERRY M. WAUGHTALDirectorFebruary 9, 2018
Perry M. Waughtal

155139