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•	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;

•	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 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;

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

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(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.

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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.

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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;

•	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

•	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.

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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. 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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(a)	We do not operate this unit.

(a)	We do not operate Bravo pipeline.

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(a)	Working interest less than 1 percent.

(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.

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

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(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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•	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

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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.

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(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.

(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.

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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)	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.

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

•	creating long-term value for our shareholders.

•	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

•	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.

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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, 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.

(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.”

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(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.

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(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.

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(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.

(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

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(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.

(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.

•	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 Midstream 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;

•	decrease of $20 million (23%) from KinderHawk primarily due to lower volumes;

•	decrease of $11 million (26%) from Oklahoma Midstream primarily due to lower volumes and unfavorable producer mix. Higher revenues of $199 million and associated increase in costs of goods sold were primarily due to higher commodity prices;

•	increase of $68 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;

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•	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;

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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.

•	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

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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.

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(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.

(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.

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•	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)	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.

(f)	The ratio of our actual leased capacity to our estimated capacity.

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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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•	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.

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(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.

(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.

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•	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.

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•	increase of $37 million (20%) from Kinder Morgan Crude & Condensate Pipeline driven primarily by an increase in pipeline throughput volumes from existing customers and additional volumes associated with expansion projects;

•	increase of $20 million (53%) from our KMCC - Splitter due to first 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.

(a)	Represents Trans Mountain pipeline system volumes.

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(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.”

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(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)	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.

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(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 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 $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.

•

a $348 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 items primarily consisting of the following: (i) net losses on impairments 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 million increase in cash associated with net changes in working capital items and other non-current assets and liabilities. The increase was driven, among other things, primarily by a $144 million income tax refund received in 2017.

•	a $1,401 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 acquisitions of assets and investments, primarily driven by the $324 million portion of the purchase price we paid in the 2016 period for the BP terminals acquisition;

•	a $143 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.

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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. See Note 9 “Debt” to our consolidated financial statements for further information regarding our debt activity; and

•	a $250 million increase in cash used for share repurchases under the share buy-back program that commenced in December 2017.

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(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.

(c)	Represents dividends subsequent to the issuance of KML’s Series 1 Preferred Shares.

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(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) 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.

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

(3)	Exhibits

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(a)

Regulatory assets as of December 31, 2017 include (i) $193 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.

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(a)	As of December 31, 2017, there were approximately 11 million such restricted stock awards.

(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.

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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.

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•	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;

•	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 Lightfoot Capital Partners, LP, which is majority owned by GE Energy Financial Services.

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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;

•	BHP Billiton Petroleum (Eagle Ford) 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 operates EagleHawk and owns the remaining 75% ownership interest;

•	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;

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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;

•	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;

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•	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%.

(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.

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(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.

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(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.

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(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.

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•	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.

•	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.

•	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.

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(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.

(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.

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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

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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 $110 million 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.

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(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.

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(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.

(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.

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(a)

2017 and 2016 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)	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.

(c)	Represents dividends subsequent to the issuance of KML’s Series 1 Preferred Shares.

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(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.

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•	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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•	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

•	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.

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(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.

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