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•	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;

•	economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand;

•	changes in our tariff rates required by the FERC, the CPUC, Canada’s NEB or another regulatory agency;

•	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 assets including pipelines, terminals, gas processing, gas storage and NGL fractionation capacity;

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

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

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

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

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

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

•	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;

•	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;

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•	competition from other pipelines, terminals 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) or other similar acts or accidents causing damage to our properties greater than our insurance coverage limits;

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

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

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

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

•	our ability to achieve cost savings and revenue growth;

•	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 18 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements.

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(a)	These assets were included in KML and were partially owned by KML’s Restricted Voting Stockholders.

(b)	These assets are included in KML and are partially owned by KML’s Restricted Voting Stockholders.

(c)

An affiliate of an anchor shipper exercised its option in January 2019 to acquire 20% equity interest in the project, bringing KMTP’s and BCP’s ownership interest to 40% each. Altus Midstream Company (Altus Midstream) (a gas gathering, processing and transportation company formed by shipper Apache Corporation) has an option to acquire an equity interest in the project from the initial partners by September 2019. If Altus Midstream exercises its option, KMTP, BCP and Altus Midstream will each hold a 26.67% ownership interest in the project. Our share of capital scope is adjusted to reflect the potential exercise of Altus Midstream’s option.

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•	focus on stable, fee-based energy transportation and storage assets that are central to the energy infrastructure of growing markets within North America;

•	increase utilization of our existing assets while controlling costs, operating safely, and employing environmentally sound operating practices;

•	leverage economies of scale from incremental acquisitions and expansions of assets that fit within our strategy and are accretive to cash flow; and

•	maintain a strong balance sheet and return value to our stockholders.

•	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;

•	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. and portions of Canada that transload and store refined petroleum products, crude oil, ethanol and chemicals, and bulk products, including petroleum coke, metals and ores; and (ii) Jones Act tankers;

•	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 gas processing plants in West Texas; and (iii) the ownership and operation of a crude oil pipeline system in West Texas; and

•	Kinder Morgan Canada (prior to August 31, 2018)—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. As a result of the TMPL Sale, this segment does not have results of operations on a prospective basis.

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(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 and has 50% voting rights. If Pembina converted its preferred interest into common interest, we and Pembina would each own a 50% common interest in Ruby.

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(b)	Effective January 1, 2019, these assets were transferred from the Natural Gas Pipelines business segment to the Products Pipelines business segment.

(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.

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(c)	Effective January 1, 2019, these assets were transferred from the Products Pipelines business segment to the Natural Gas Pipelines business segment.

(d)	Effective January 1, 2019, a small number of terminals were transferred between the Products Pipelines and Terminals business segments.

(a)	Effective January 1, 2019, a small number of terminals were transferred between the Terminals and Products Pipelines business segments.

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(a)	We do not operate this unit.

(a)	We do not operate Bravo pipeline.

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

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•	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;

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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;

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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.

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(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.

(b)	Excludes repurchases made in December 2018 of 0.1 million shares for approximately $2 million which settled on January 2, 2019.

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

(b)	Using part of our portion of proceeds from the TMPL Sale that KML distributed to us in January 2019, we immediately repaid our outstanding balance of commercial paper of $409 million and then repaid $500 million of maturing 9.00% senior notes and $800 million of maturing 2.65% senior notes in February 2019.

(c)	Excludes debt fair value adjustments.

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•	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;

•	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. and portions of Canada that transload and store refined petroleum products, crude oil, ethanol and chemicals, and bulk products, including petroleum coke, metals and ores; and (ii) Jones Act tankers;

•	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; and (iii) the ownership and operation of a crude oil pipeline system in West Texas; and

•	Kinder Morgan Canada (prior to August 31, 2018)—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. As a result of the TMPL Sale, this segment does not have results of operations on a prospective basis.

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

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

(b)	As a result of the TMPL Sale on August 31, 2018, this segment does not have results of operations on a prospective basis.

(c)	2018, 2017 and 2016 amounts include net decreases in earnings of $269 million, $384 million and $1,121 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.”

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(d)	2018, 2017 and 2016 amounts include net increases in expense of $24 million and $15 million and a net decrease in expense of $13 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.”

(e)	2018, 2017 and 2016 amounts include a net increase in expense of $26 million and net decreases in expense of $39 million and $193 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.”

(f)	2018, 2017 and 2016 amounts include a net decrease of $58 million and net increases in expense of $1,085 million and $18 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.

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(a)	Consists of certain items summarized in footnotes (c) through (e) to the “—Results of Operations—Consolidated Earnings Results” table included above, and described in more detail below in the footnotes to tables included in “—Segment Earnings Results” and “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests.”

(b)	Represents noncontrolling interests share of certain items. 2018 includes KML shareholders’ approximately 30% share of the gain on the TMPL Sale.

(c)	Represents income tax provision on certain items plus discrete income tax items.

(d)	2018 amount represents 2017 Tax Reform provisional adjustments including our share of certain equity investees’ 2017 Tax Reform provisional adjustments related to our FERC regulated business. 2017 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.

(e)	Includes DD&A and amortization of excess cost of equity investments. Also includes 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 $360 million, $362 million and $349 million in 2018, 2017 and 2016, respectively.

(f)	Excludes book tax certain items of $58 million, $(1,085) million and $(18) million for 2018, 2017 and 2016, respectively. 2018, 2017 and 2016 amounts also include $65 million, $104 million and $94 million, respectively, of our share of taxable equity investees’ book taxes, net of the noncontrolling interests’ portion of KML book taxes.

(g)	Includes our share of taxable equity investees’ cash taxes of $(68) million, $(69) million and $(76) million in 2018, 2017 and 2016, respectively.

(h)	Includes pension contributions and non-cash compensation associated with our restricted stock program.

(i)	Includes our share of (i) certain equity investees’; (ii) KML’s; and (iii) certain consolidating joint venture subsidiaries’ sustaining capital expenditures of $(105) million, $(107) million and $(90) million in 2018, 2017 and 2016, respectively.

(j)	Includes restricted stock awards that participate in common share dividends.

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(a)

2018 and 2017 amounts include an increases in revenues of $24 million and $8 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. 2018 amount also includes increases in revenue of (i) $9 million related to a transportation contract refund; (ii) $5 million related to the early termination of a long-term natural gas transportation contract; and (iii) $4 million from other certain items. 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.

(b)

2018 amount includes (i) an increase in earnings of $7 million as a result of a property tax refund; (ii) an increase in earnings of $6 million related to the release of certain sales and use tax reserves; and (iii) a decrease in earnings of $2 million related to other certain items. 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 amount includes a decrease in earnings of $3 million from other certain items.

(c)

2018 amount includes a decrease in earnings of $600 million related to a non-cash loss on impairment of certain gathering and processing assets in Oklahoma and an increase in earnings of $1 million related to other certain item. 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.

(d)	2018 amount includes (i) a net loss of $89 million in our equity investment in Gulf LNG Holdings Group, LLC (Gulf LNG), due to a ruling by an arbitration panel affecting a customer contract, which resulted in a non-cash impairment of our investment partially offset

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(e)	2018, 2017 and 2016 amounts include decreases in earnings of $24 million, $5 million and $10 million, respectively, related to certain litigation matters.

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

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Midstream’s increase of $150 million (14%) was primarily due to increased earnings from Texas intrastate natural gas pipeline operations, KinderHawk, Hiland Midstream and South Texas Midstream. Texas intrastate natural gas pipeline operations were favorably impacted by higher volumes with new and existing customers serving the Mexico and Texas Gulf Coast industrial markets partially offset by lower park and loan revenues and storage margins. KinderHawk and South Texas Midstream benefited from increased drilling and production in the Haynesville and Eagle Ford basins, respectively. Hiland Midstream increased earnings were primarily due to higher gas and crude oil volumes and higher NGL sales prices. While these factors also drove an increase in revenue, these increases in revenues were partially offset by the effect of the January 1, 2018 adoption of Topic 606 which caused a corresponding decrease in cost of goods sold;

•	West Region’s increase of $100 million (11%) was primarily due to higher earnings from EPNG, CIG and CPGPL. EPNG experienced higher volumes in 2018 from increased Permian basin-related activity and associated capacity sales. CIG and CPGPL earnings were higher due to continued growing production in the Denver Julesburg basin;

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North Region’s increase of $43 million (4%) was primarily due to an increase in equity earnings from NGPL, and higher earnings from TGP and KMLP. NGPL increase in earnings was due to increased Permian basin-related activity and lower interest expense resulting from a 2017 refinancing, partially offset by lower storage-related revenue. TGP and KMLP contributed increased earnings primarily from expansion projects recently placed in service; and

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South Region’s increase of $33 million (5%) was primarily due to increases in equity earnings from Citrus and SNG, and an increase in earnings from SLNG, partially offset by a decrease in earnings from Southern Gulf LNG due to a loss of revenues from an arbitration ruling calling for a contract termination. Citrus had lower income tax expense due to the 2017 Tax Reform, and SNG increased earnings were from higher transportation revenues from increased system usage and non-recurring 2017 operating expenses. SLNG earnings were driven by higher capitalized AFUDC equity associated with the Elba Liquefaction project.

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•	South Region’s decrease of $143 million (18%) was primarily due to the sale of a 50% interest in SNG to Southern Company on September 1, 2016, partially offset by an increase in earnings from Elba Express primarily due to an expansion project placed in service in December 2016;

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Midstream’s decrease of $66 million (6%) was primarily due to decreases in earnings from South Texas Midstream, KinderHawk and Oklahoma Midstream, partially offset by increased earnings from Texas intrastate natural gas pipeline operations and Altamont Midstream. South Texas Midstream lower earnings were primarily due to lower commodity based service revenues and residue gas sales as a result of lower volumes partially offset by higher NGL sales gross margin primarily due to rising NGL prices. KinderHawk experienced lower volumes, which lowered its earnings and Oklahoma Midstream’s lower earnings were primarily due to lower volumes and unfavorable producer mix. Texas intrastate natural gas pipeline operations increased earnings were 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. Altamont Midstream primarily increased earnings were due to higher natural gas and liquids revenues due to higher commodity prices and volumes. Texas intrastate natural gas pipeline operations, Hiland Midstream and Oklahoma Midstream had increases in revenues due to higher commodity prices which was largely offset by a corresponding increases in costs of sales;

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West Region’s decrease of $38 million (4%) was primarily due to a decrease in earnings at CIG, partially offset by higher earnings at EPNG. CIG lower earnings were primarily due to a decrease in tariff rates effective January 1, 2017 as a result of a rate case settlement entered into in 2016. EPNG had higher earnings primarily due to higher transportation revenues driven by incremental Permian basin 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; and

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North Region’s increase of $84 million (7%) was primarily due to higher earnings from TGP and an increase in equity earnings from NGPL. TGP’s increase in earnings was primarily due to higher firm transportation revenues driven by incremental capacity sales and expansion projects recently placed in service. NGPL higher earnings were 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.

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(a)

2018 amount includes (i) an increase in expense of $31 million associated with a certain Pacific operations litigation matter; (ii) an increase in earnings of $5 million as a result of a property tax refund; and (iii) a decrease in expense of $1 million related to other certain items. 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.

(b)	2018 amount includes a decrease in earnings of $36 million associated with a project write-off on the Utica Marcellus Texas pipeline. 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.2016 amount includes a $12 million gain related to the sale of an equity investment.

(d)	Volumes include ethanol pipeline volumes.

(e)	Joint Venture throughput is reported at our ownership share.

(f)	Represents total ethanol volumes, including ethanol pipeline volumes included in gasoline volumes above.

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NGLs’ increase of $33 million (27%) was primarily due to increases in earnings from Cochin pipeline and to a lesser extent an increase in earnings from equity earnings from Utopia, which went into service in 2018. Cochin’s earnings were higher primarily due to foreign exchange transaction losses in 2017 primarily related to an intercompany note receivable, integrity work during 2017 and an expansion project placed in service during 2018;

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Southeast Refined Products’ increase of $26 million (11%) was primarily due to increased equity earnings from Plantation pipeline and earnings from South East Terminals. Plantation pipeline earnings were higher primarily due to lower income tax expense due to the 2017 Tax Reform, lower operating expense attributable to a 2017 project write-off and product net gains as a result of higher product prices. South East Terminals earnings were favorably impacted primarily due to higher revenues as a result of expansion projects that were placed into service in the later part of 2017 and higher volumes with existing customers;

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Crude & Condensate’s decrease of $15 million (4%) was primarily due to a decrease of earnings from Kinder Morgan Crude & Condensate Pipeline partially offset by an increase of Double H Pipeline earnings. The Kinder Morgan Crude & Condensate Pipeline lower earnings were primarily due to lower services revenues as a result of unfavorable rates on contract renewals partially offset by recognition of deficiency revenue. Double H Pipeline increase in earnings was primarily due to an increase in volumes and the recognition of deficiency revenue; and

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West Coast Refined Products’ decrease of $3 million (1%) was primarily due to lower earnings from Pacific operations partially offset by an increase in Calnev earnings. Pacific operations earnings were lower primarily due to higher operating expenses driven by an unfavorable change in product gain/loss, an increase in 2018 environmental reserves and higher fuel and power costs. Calnev earnings were higher due to an increase in services revenues driven by an increase in volumes, the result of an interruption of service by a provider for a competing pipeline that also serves the Las Vegas market.

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West Coast Refined Products’ increase of $7 million (1%) was primarily due to improved earnings at both Pacific operations and Calnev. Pacific operations increase in earnings was 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. Calnev earnings were higher primarily due to higher service revenues driven by higher volumes and a decrease in expense related to the reduction of a rate reserve;

•	NGLs’ increase of $4 million (3%) was primarily due to increased development fee revenues in 2017 for Utopia Pipeline ;

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Southeast Refined Products’ increase of $3 million (1%) was primarily due to increased earnings at South East Terminals and to a lesser extent at Transmix processing operations, partially offset by our sale of a 50% interest in Parkway Pipeline on July 1, 2016. South East Terminals increased earnings were primarily due to higher revenues driven by higher volumes as a result of capital expansion projects being placed in service during 2017. The decrease in revenues was 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

•	Crude & Condensate’s decrease of $1 million (—%) was primarily due a decrease in earnings on Kinder Morgan Crude & Condensate Pipeline resulting from higher cost of goods sold offset by an increase in earnings from Double Eagle primarily due to higher revenues driven by higher volumes and price.

(a)	2018, 2017 and 2016 amounts include increases in revenues of $2 million, $9 million and $28 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)

2018 amount includes a decrease in expense of $18 million related to hurricane damage insurance recoveries, net of repair costs and an increase in expense of $1 million related to other certain item. 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.

(c)

2018 amount includes a net loss of $53 million on impairments and divestitures, net, primarily related to our Staten Island terminal. 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 divestitures and impairments, net. 2016 amount includes an expense of $109 million related to various 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 and a decrease in earnings of $16 million related to various losses on impairments and divestitures of equity investments, net.

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

•	decrease of $19 million (15%) from our Northeast terminals primarily due to low utilization at our Staten Island terminal;

•	decrease of $19 million (22%) 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 expiration of a crude by rail terminaling contract in August 2018 at our Deer Park Rail Terminal;

•	decrease of $8 million (13%) from our Southeast terminals primarily due to the sale of certain terminal assets in December 2017 and higher operating expenses at our steel handling operations;

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decrease of $1 million (1%) from our Alberta Canada terminals primarily due to an increase in operating expenses associated with tank lease fees at our Edmonton South Terminal following the TMPL Sale and the impact of the expiration of a third party crude-by-rail terminaling contract at our Edmonton Rail Terminal joint venture partially offset by an increase in earnings due to the commencement of operations at our Base Line Terminal joint venture;

•	increase of $31 million (11%) from our Gulf Liquids terminals primarily driven by contributions from expansion projects at our Pasadena Terminal and the Kinder Morgan Export Terminal as well as organic volume growth at several of our Houston Ship Channel locations;

•	increase of $6 million (8%) from our Midwest terminals primarily driven by increased ethanol storage revenues and new liquids customer contracts entered into in 2018; and

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increase of $3 million (2%) from our Marine Operations primarily due to the incremental earnings from the March 2017, June 2017, July 2017 and December 2017 deliveries of the Jones Act tankers, the American Freedom, Palmetto State, American Liberty and American Pride, respectively, partially offset by decreased contributions from existing Jones Act tankers driven by lower charter rates and a reduced operating cost credit attributable to capitalized overhead.

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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.

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(a)	2018, 2017 and 2016 amounts include unrealized losses of $90 million and $54 million, and $63 million, respectively, related to 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.

(b)	2018 amount includes an increase in earnings of $21 million as a result of a severance tax refund.

(c)	2018 amount includes oil and gas property impairments of $79 million. 2017 and 2016 amounts include a decrease in expense of $1 million and an increase in expense of $20 million, respectively, related to source and transportation project write-offs.

(d)	2017 and 2016 amounts include an increase in equity earnings of $4 million and a decrease in equity earnings of $9 million, respectively, for our share of a project write-off recorded by an equity investee.

(e)	Includes McElmo Dome and Doe Canyon sales volumes.

(f)	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.

(g)	Net after royalties and outside working interests.

(h)	Includes all crude oil production properties.

(i)	Includes all NGL sales.

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•	increase of $27 million (5%) from our Oil and Gas Producing activities primarily due to increased revenues of $45 million primarily driven by higher NGL prices of $23 million and higher volumes of $22 million partially offset by an increase of $16 million in operating expenses and higher severance tax expense of $2 million; and

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decrease of $7 million (2%) from our Source and Transportation activities primarily due to lower other revenues of $5 million, higher ad valorem tax expense of $4 million and decreased earnings from an equity investee of $3 million partially offset by higher CO2 sales of $3 million driven by higher contract sales prices of $25 million offset by lower volumes of $22 million and lower operating expenses of $2 million. The increase in revenues of $52 million is primarily due to the effect of the January 1, 2018 adoption of Topic 606, which increased both revenues and operating expenses (costs of sales) by $54 million, as discussed in Note 16 “Revenue Recognition” to our consolidated financial statements.

•	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.

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(a)	2018 amount includes a gain of $596 million on the TMPL Sale.

(b)	Represents TMPL average daily volumes reported until date of sale, August 31, 2018.

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(a)

2018 amount includes: (i) an increase in expense of $10 million associated with an estimated environmental reserve adjustment; (ii) a decrease in expense of $12 million related to the release of certain sales and use tax reserves; (iii) an increase in expense of $10 million of asset sale related costs; (iv) an increase in expense of $9 million related to certain corporate litigation matters; and (v) an increase in expense of $7 million related to other certain items. 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) a 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.

(b)

2018, 2017 and 2016 amounts include: (i) decreases in interest expense of $32 million, $44 million and $115 million, respectively, related to amortization of non-cash debt fair value adjustments associated with acquisitions and (ii) an increase of $9 million and decreases of $3 million and $44 million, respectively, in interest expense related to non-cash true-ups of our estimates of swap ineffectiveness. 2018 amount also includes increases in interest expense of $47 million related to the write-off of capitalized KML credit facility fees and $2 million related to other certain items. 2017 amount also includes an $8 million increase in interest expense related to other certain items. 2016 amount also includes a $34 million decrease in interest expense related to certain litigation matters.

(c)	2018 amount is primarily associated with the $596 million gain on the TMPL Sale and is disclosed above in “—Kinder Morgan Canada.” The 2016 amount is associated with Natural Gas Pipelines segment certain items and disclosed above in “—Natural Gas Pipelines.”

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(a)	Subsequently was upgraded to BBB on January 7, 2019 with a Stable outlook.

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(a)	2018 and Expected 2019 amounts include $105 million and $127 million, respectively, for our proportionate share of (i) certain equity investee’s; (ii) KML’s; and (iii) certain consolidating joint venture subsidiaries’ sustaining capital expenditures.

(b)	2018 includes $128 million of net changes from accrued capital expenditures, contractor retainage, and other.

(c)	2018 amount includes $279 million of our contributions to certain unconsolidated joint ventures for capital investments and small acquisitions.

(d)	Amounts include our actual or estimated contributions to certain unconsolidated joint ventures, net of actual or estimated contributions from certain partners in non-wholly owned consolidated subsidiaries for capital investments.

(e)	2018 amount includes TMEP capital investments for the period ending on August 31, 2018, the closing of the TMPL Sale.

(a)	Less than 1 year amount primarily includes $3,277 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, 2018.

(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 2019 and estimated benefit payments for unfunded plans in all years.

(e)	Primarily represents transportation agreements of $374 million, volume agreements of $338 million and storage agreements for capacity of $183 million.

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(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 will perform remediation activities. These liabilities are included within “Accrued contingencies” and “Other long-term liabilities and deferred credits” in our consolidated balance sheets.

(g)

The $156 million in letters of credit outstanding as of December 31, 2018 consisted of the following (i) letters of credit totaling $46 million supporting our International Marine Terminals Partnership Plaquemines, Louisiana Port, Harbor, and Terminal Revenue Bonds; (ii) $33 million under nine letters of credit for insurance purposes; (iii) a $24 million letter of credit supporting our Kinder Morgan Operating L.P. “B” tax-exempt bonds; (iv) thirteen letters of credit totaling $8 million supporting our pipeline and terminal operations in Canada; and (v) a combined $45 million in twenty-five 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, 2018.

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a $346 million increase in cash associated with net changes in working capital items and other non-current assets and liabilities, primarily driven, among other things, by a $137 income tax refund received in the 2018 period, and an increase in current income tax liabilities associated with the tax gain on the TMPL Sale in the 2018 period. These increases were partially offset by higher payments for litigation matters in the 2018 period compared with the 2017 period; and

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a $96 million increase in operating cash flow resulting from the combined effects of adjusting the $1,696 million increase in net income for the period-to-period net changes in non-cash items including the following: (i) loss on impairments and divestitures, net (see discussion above in “—Results of Operations”); (ii) loss on impairments and divestitures of equity investments, net (see discussion above in “—Results of Operations”); (iii) the change in fair market value of derivative contracts; (iv) DD&A expenses (including amortization of excess cost of equity investments); (v) deferred income taxes; (vi) earnings from equity investments; and (vii) loss on early extinguishment of debt.

•	a $2,998 million increase in cash reflecting proceeds received from the TMPL Sale, net of cash disposed in the 2018 period. See Note 3 “Divestitures and Acquisition” for further information regarding this transaction;

•	a $284 million decrease in capital expenditures in the 2018 period over the comparative 2017 period primarily due to lower expenditures in our Terminals business segment, partially offset by higher expenditures related to construction projects in our Natural Gas Pipelines business segment;

•	a $251 million decrease in cash used for contributions to equity investments primarily due to lower contributions we made to NGPL Holdings LLC, FEP and Utopia Holding LLC in the 2018 period compared to the 2017 period, partially offset by the contributions made to Gulf Coast Express Pipeline LLC in the 2018 period; and

•	a $124 million increase in cash proceeds received from the sale of equity investments, primarily driven by a sale of our partial interest in Gulf Coast Express LLC in the 2018 period; partially offset by,

•	a $138 million decrease in cash proceeds from sale of property, plant and equipment and other net assets in the 2018 period compared to the 2017 period; and

•	a $137 million decrease in cash resulting from lower distributions received from equity investments in excess of cumulative earnings, primarily from MEP, SNG and Citrus Corporation in the 2018 period over the comparative 2017 period.

•	a combined $1,665 million decrease in cash reflecting $1,245 million net proceeds we received from the KML IPO in May 2017 and $420 million net proceeds received from the KML preferred share issuances in the 2017 period;

•	a $498 million increase in dividend payments to our common shareholders;

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•	a $304 million decrease in cash due to lower contributions received from EIG in the 2018 period compared to the 2017 period as the 2017 period included $386 million we received from EIG Global Energy Partners for our sale of a 49% partnership interest in ELC;

•	a $36 million increase in distributions to noncontrolling interests, primarily to KML restricted share holders and preferred shareholders; and

•	a $23 million increase in cash used for common shares repurchased under our common share buy-back program in the 2018 period compared to the 2017 period; partially offset by,

•	a $2,384 million net increase in cash related to debt activity as a result of $118 million of net debt issuances in the 2018 period compared to $2,266 million of net debt payments in the 2017 period. See Note 9 “Debt” for further information regarding our debt activity.

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(a)	The reduction in the noncontrolling interests associated with KML is primarily attributable to the accrual of the return of capital distribution for the net proceeds from the TMPL Sale paid to KML’s Restricted Voting Shareholders on January 3, 2019 of approximately $0.9 billion. For more information see “—General—KML—Sale of Trans Mountain Pipeline System and Its Expansion Project” above.

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(a)	A hypothetical 10% change in the average interest rates applicable to such debt as of December 31, 2018 and 2017, would result in changes of approximately $1,638 million and $1,525 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 52 and 50 basis points, respectively, in 2018 and 2017) when applied to our outstanding balance of variable rate debt as of December 31, 2018 and 2017, including adjustments for the notional swap amounts described above, would result in changes of approximately $59 million and $52 million, respectively, in our 2018 and 2017 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.

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(a)	(1) Financial Statements and (2) Financial Statement Schedules

(3)	Exhibits

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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.

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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.

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(a)

Regulatory assets as of December 31, 2018 include (i) $176 million of unamortized losses on disposal of assets; (ii) $53 million income tax gross up on equity AFUDC; and (iii) $82 million of other assets including amounts related to fuel tracker arrangements. Approximately $98 million of the regulatory assets, with a weighted average remaining recovery period of 23 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, 2018 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 $136 million of the $206 million classified as non-current is expected to be credited to shippers over a remaining weighted average period of 18 years, while the remaining $70 million is not subject to a defined period.

(a)	As of December 31, 2018, there were approximately 13 million such restricted stock awards.

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(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)	The holder of each convertible preferred share participated in our earnings by receiving preferred stock dividends through the mandatory conversion date of October 26, 2018 at which time our convertible preferred shares were converted to common shares.

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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, we and Pembina would each own a 50% common interest in Ruby;

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•	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;

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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 Chatham Asset Management, LLC, which is directed by Chatham Asset GP, LLC;

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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;

•	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;

•	BHP Billiton Petroleum (Eagle Ford Gathering) LLC, (EagleHawk)—We own a 25% interest in EagleHawk, the sole owner of natural gas and condensate gathering systems serving the producers of the Eagle Ford shale formation. A subsidiary of BHP Billiton Petroleum (Tx Gathering), LLC operates EagleHawk and owns the remaining 75% ownership interest;

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Gulf Coast Express Pipeline LLC — We operate Gulf Coast Express Pipeline LLC and own 35% interest of Gulf Coast Express Pipeline LLC indirectly through Kinder Morgan Texas Pipeline LLC, our 100% subsidiary. DCP GCX Pipeline LLC, an indirect subsidiary of DCP Midstream, owns 25% interest; Targa GCX Pipeline LLC, an indirect subsidiary of Targa Resources Corp., owns 25% interest and Altus Midstream Company, an indirect subsidiary of Apache Corporation, owns 15% 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;

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Watco Companies, LLC—We hold a preferred and common equity investment in Watco Companies, LLC, the largest privately held short line railroad company in the U.S.  We own 100,000 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 holds any voting powers, but do provide us certain approval rights, including the right to appoint one of the members to Watco’s board of managers. In addition to the senior interests, we also hold approximately 13,000 common equity units, which represents a 3.2% common ownership;

•	Double Eagle Pipeline LLC - We own a 50% equity interest in Double Eagle Pipeline LLC. The remaining 50% interest is owned by Magellan Midstream Partners;

•	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% interest in 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%;

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Permian Highway Pipeline — We operate Permian Highway Pipeline and own a 50% interest of Permian Highway Pipeline indirectly through KMTP, our wholly owned subsidiary. BCP PHP, LLC (BCP), a portfolio company of Blackstone Energy Partners, owns the remaining 50% interest. An affiliate of an anchor shipper exercised its option in January 2019 to acquire a 20% equity interest in the project, bringing KMTP’s and BCP’s ownership interest to 40% each. Altus Midstream Company (Altus Midstream) (a gas gathering, processing and transportation company formed

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•	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;

•	Cortez Pipeline Company—We operate the Cortez CO2 pipeline system, and own 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%.

(a)	2018 amount includes our share of earnings recognized due to a ruling by an arbitration panel affecting a customer contract.

(b)	2017 and 2016 amounts include $(4) million and $9 million, respectively, representing our share of a non-cash impairment charge (pre-tax) recorded by Cortez Pipeline Company.

(c)	2017 amount includes non-cash impairment charges of $10 million (pre-tax) related to our investment.

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(a)	2017 includes $3 million related to certain terminal divestitures.

(b)	2018 includes $190 million related to the TMPL Sale.

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(a)	See “—Current portion of debt” below for further details regarding the outstanding credit facility and commercial paper borrowings.

(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 most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions.

(c)

Consists of senior notes denominated in Euros that have been converted to U.S. dollars and are respectively reported above at the December 31, 2018 exchange rate of 1.1467 U.S. dollars per Euro and at the December 31, 2017 exchange rate of 1.2005 U.S. dollars per Euro. As of December 31, 2018 and 2017, the cumulative changes in the exchange rate of U.S. dollars per Euro since issuance had resulted in increases to our debt balance of $46 million and $86 million, respectively, related to the 1.50% series and increases of $30 million and $57 million, respectively, related to the 2.25% series. The cumulative 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”).

(d)

Capital Trust I (Trust I), is a 100%-owned business trust that as of December 31, 2018, 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. The Trust I Preferred Securities outstanding as of December 31, 2018 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.

(e)

As of December 31, 2018 and 2017, 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.

(f)	Includes capital lease obligations with monthly installments. The lease terms expire between 2024 and 2061.

(g)	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.

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(h)

Excludes our “Debt fair value adjustments” which, as of December 31, 2018 and 2017, increased our combined debt balances by $731 million and $927 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.

(a)	On November 16, 2018, we replaced our $5 billion, five-year credit facility with two new credit facilities discussed further in “—Credit Facilities and Restrictive Covenants” following.

(b)	Interest rates are weighted average rates at December 31, 2018 and 2017, respectively.

(c)	Borrowings under the KML 2018 Credit Facility are denominated in C$ and are converted to U.S. dollars. The exchange rate was 0.7330 U.S. dollars per C$ at December 31, 2018 and 0.7971 U.S. dollars per C$ at December 31, 2017. See “—Credit Facilities” below.

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(a)	2018 amounts represent December 31, 2017 balances associated with Canadian pension and OPEB plans that were included in the TMPL Sale. 2017 amounts represent December 31, 2016 balances associated with our Plantation Pipeline OPEB plan that are no longer included in these disclosures.

(a)	2018 and 2017 OPEB amounts include $32 million and $33 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.

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•	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, exchange traded mutual funds and MLPs. These investments are valued at the closing price reported on the active market on which the individual securities are traded.

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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.

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Plan assets with fair values that are based on the net asset value per share, or its equivalent (NAV), 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, limited partnerships, and fixed income trusts. The plan assets measured at NAV are not categorized within the fair value hierarchy described above, but are separately identified in the following tables.

(a)	Includes mutual funds which are invested in equity.

(b)	Plan assets include $94 million and $110 million of KMI Class P common stock for 2018 and 2017, respectively.

(c)	Plan assets for which fair value was measured using NAV as a practical expedient.

(d)	Common/collective trust funds were invested in approximately 37% fixed income and 63% equity in 2018 and 36% fixed income and 64% equity in 2017.

(e)	Private investment funds were invested in approximately 71% fixed income and 29% equity in 2018 and 52% fixed income and 48% equity in 2017.

(f)	Includes assets invested in real estate, venture and buyout funds.

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(a)	Plan assets include $2 million of KMI Class P common stock for 2017.

(b)	Plan assets for which fair value was measured using NAV as a practical expedient.

(c)	Common/collective trust funds were invested in approximately 60% equity and 40% fixed income securities for 2018 and 71% equity and 29% fixed income securities for 2017.

(d)	Limited partnerships were invested in global equity securities.

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(a)	Includes a reduction of approximately $2 million in each of the years 2019 - 2023 and approximately $13 million in aggregate for 2024 - 2028 for an expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.

(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 2018, 2017 and 2016.

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(a)

2018 and 2017 OPEB amounts each include $4 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.

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(a)	The reduction in the noncontrolling interests associated with KML is primarily attributable to the accrual of the return of capital distribution for the net proceeds from the TMPL Sale paid to KML’s Restricted Voting Shareholders on January 3, 2019 of approximately $0.9 billion.

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(a)

We expect to reclassify an approximate $165 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of December 31, 2018 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)

During the year ended December 31, 2018, we recognized a $3 million loss as a result of our equity investment’s forecasted transactions being probable of not occurring and a $21 million gain 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).

(c)	Amounts represent our share of an equity investee’s accumulated other comprehensive income (loss).

(a)	During the year ended December 31, 2018, we recognized a $26 million gain from our accumulated other comprehensive loss balance related to the TMPL Sale. See Note 3.

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(a)	Amounts for foreign currency translation adjustments and pension and other postretirement liability adjustments reflect the deferred losses recognized in income during the year ended December 31, 2018 related to the TMPL Sale.

•	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).

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(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.

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(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) below).

(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 indexed-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 Accounting Standards Codification other than in Topic 606 and primarily include leases and derivatives. The majority of our lease revenues are from certain firm service contracts that are accounted for as operating leases. See Note 14 for additional information related to our derivative contracts.

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(a)	Includes current and non-current balances of $14 million and $10 million reported within “Other current assets” and “Deferred charges and other assets,” respectively, in our accompanying consolidated balance sheet at December 31, 2018.

(b)	Includes 2018 foreign currency translation adjustments associated with the balances at December 31, 2017.

(c)	Includes current and non-current balances of $80 million and $212 million reported within “Other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance sheet at December 31, 2018.

•	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;

•	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

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•	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, ethanol and chemicals, and bulk products, including petroleum coke, metals and ores; and (ii) Jones Act tankers;

•	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 gas processing plants in West Texas; and (iii) the ownership and operation of a crude oil pipeline system in West Texas; and

•	Kinder Morgan Canada (prior to August 31, 2018)—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. As a result of the TMPL Sale, this segment does not have results of operations on a prospective basis.

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(a)	2017 and 2016 amounts include a management fee of $35 million and $34 million, respectively, 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 impairments and divestitures, net and other income, net.

(d)	Includes revenues, earnings from equity investments, other, net, less operating expenses, loss on impairments and divestitures, net, loss on impairments and divestitures of equity investments, net and other income, net.

(e)

Includes cash and cash equivalents, margin and restricted deposits, 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 our reportable segments.

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