---

---

---

---

•	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;

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

•	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;

•	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;

•	acts of nature, 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.

---

---

---

---

---

•	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;

•	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 coal, petroleum coke, fertilizer, steel and ores 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, 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.

---

---

---

(a)	We also operate this unit.

---

(a)	We do not operate Bravo pipeline.

(a)	Working interest less than 1 percent.

---

(a)	Includes active wells and wells temporarily shut-in.  As of December 31, 2016, 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, 2016. A development well is a well drilled in an already discovered oil field.

(a)	This is a working interest, in addition, we have a 28% net profits interest. The average net to us does not include the value associated with the net profits interest.

---

---

(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.

---

---

•	Order No. 436 (1985) which required open-access, nondiscriminatory transportation of natural gas;

•	Order No. 497 (1988) which set forth new standards and guidelines imposing certain constraints on the interaction between interstate natural gas pipelines and their marketing affiliates and imposing certain disclosure requirements regarding that interaction;

•

Order Nos. 587, et seq., Order No. 809 (1996-2015) which adopt regulations to standardize the business practices and communication methodologies of interstate natural gas pipelines to create a more integrated and efficient pipeline grid and wherein the FERC has incorporated by reference in its regulations standards for interstate natural gas pipeline business practices and electronic communications that were developed and adopted by the North American Energy Standards Board (NAESB). Interstate natural gas pipelines are required to incorporate by reference or verbatim in their respective tariffs the applicable version of the NAESB standards;

•

Order No. 636 (1992) which required interstate natural gas pipelines that perform open-access transportation under blanket certificates to “unbundle” or separate their traditional merchant sales services from their transportation and storage services and to provide comparable transportation and storage services with respect to all natural gas supplies. Natural gas pipelines must now separately state the applicable rates for each unbundled service they provide (i.e., for the natural gas commodity, transportation and storage);

---

•	Order No. 637 (2000) which revised, among other things, FERC regulations relating to scheduling procedures, capacity segmentation, and pipeline penalties in order to improve the competitiveness and efficiency of the interstate pipeline grid; and

•

Order No. 717 (2008) amending the Standards of Conduct for Transmission Providers (the Standards of Conduct or the Standards) to make them clearer and to refocus the marketing affiliate rules on the areas where there is the greatest potential for abuse. The FERC standards of conduct address and clarify multiple issues with respect to the actions and operations of interstate natural gas pipelines and public utilities using a functional approach to ensure that natural gas transmission is provided on a nondiscriminatory basis, including (i) the definition of transmission function and transmission function employees; (ii) the definition of marketing function and marketing function employees; (iii) the definition of transmission function information and non-disclosure requirements regarding non-public information; (iv) independent functioning and no conduit requirements; (v) transparency requirements; and (vi) the interaction of FERC standards with the NAESB business practice standards. The Standards of Conduct rules also require that a transmission provider provide annual training on the standards of conduct to all transmission function employees, marketing function employees, officers, directors, supervisory employees, and any other employees likely to become privy to transmission function information.

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

(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)	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 $1,149 million, $1,674 million, $1,785 million, $1,863 million and $2,479 million as of December 31, 2016, 2015, 2014, 2013 and 2012, respectively.

---

•	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 coal, petroleum coke, fertilizer, steel and ores 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, 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.

---

---

---

---

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

---

(a)	Includes 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)	2016, 2015 and 2014 amounts include decreases in earnings of $1,121 million, $1,748 million and $67 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)	2016, 2015 and 2014 amounts include decreases (increase) to expense of $5 million, $(25) million and $28 million, respectively, related to the combined net effect of the certain items related to general and administrative expenses disclosed below in “—General and Administrative, Interest, Corporate and Noncontrolling Interests.”

(d)	2016, 2015 and 2014 amounts include decreases in expense of $193 million, $27 million and $3 million, respectively, related to the combined net effect of the certain items related to interest expense, net disclosed below in “—General and Administrative, Interest, Corporate and Noncontrolling Interests.”

(e)	2016, 2015 and 2014 amounts include decreases (increase) to expense of $8 million, $(35) million and $22 million, respectively, related to the combined net effect of the certain items related to Corporate activities disclosed below in “—General and Administrative, Interest, Corporate and Noncontrolling Interests.

---

---

(a)	Consists of certain items summarized in footnotes (b) 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 both our management’s discussion and analysis of segment results and “—General and Administrative, Interest, Corporate and Noncontrolling Interests.”

(b)	Represents income tax provision on certain items plus discrete income tax items. For 2016, discrete income tax items included 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)	Represents noncontrolling interests share of certain items.

(d)	Includes DD&A, amortization of excess cost of equity investments and our share of equity investee’s DD&A of $349 million, $323 million and $305 million in 2016, 2015 and 2014, respectively.

(e)	Excludes book tax certain items. 2016, 2015 and 2014 amounts also include $94 million, $72 million and $75 million, respectively, of our share of taxable equity investee’s book tax expense.

(f)	Includes our share of taxable equity investee’s cash taxes of $(76) million, $(19) million and $(27) million in 2016, 2015 and 2014, respectively.

(g)	For 2016 and 2015, consists primarily of non-cash compensation associated with our restricted stock awards program and for 2014 consists primarily of excess coverage from our former master limited partnerships.

(h)	Includes our share of equity investee’s sustaining capital expenditures of $(90) million, $(70) million and $(59) million in 2016, 2015 and 2014, respectively.

(i)	Represents distributions to KMP and EPB limited partner units formerly owned by the public for the respective period.

(j)	Includes restricted stock awards that participate in common share dividends and, for 2015, the dilutive effect of warrants. 2014 amount also includes the common shares issued on November 26, 2014 for the Merger Transactions as if outstanding for the entire fourth quarter which differs from our GAAP presentation on our Consolidated Statement of Income.

---

(a)

2016 and 2014 amounts include decreases in revenues of $50 million and $2 million, respectively, and 2015 amount includes an increase in revenues of $32 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 and 2014 amounts also include increases in revenues of $200 million and $198 million, respectively, associated with amounts collected on the early termination of long-term natural gas transportation contracts on KMLP.

(b)

In addition to the revenue certain items described in footnote (a) above, 2016 amount also includes (i) $613 million related to equity investment impairments primarily related to our investments in MEP and Ruby; (ii) a decrease in earnings of $106 million of project write-offs; (iii) an $84 million pre-tax loss on the sale of a 50% interest in our SNG natural gas pipeline system; (iv) an increase in earnings of $18 million related to the early termination of a customer contract at an equity investee; and (v) a decrease in earnings of $29 million from other certain items. 2015 amount also includes (i) $1,150 million of losses related to goodwill impairments on our non-regulated midstream reporting unit; (ii) $52 million of losses related to divestitures of our non-regulated midstream assets; (iii) $47 million of losses related to other impairments on our non-regulated midstream assets; (iv) $26 million of impairments on equity investments; and (v) a $19 million net decrease in earnings related to project write-offs and other certain items. 2014 amount also includes a $6 million decrease in earnings from other certain items.

(c)

Income tax expense and interest income that were allocated to and presented in Segment EBDA in prior periods are presented herein in income tax expense and interest expense, net, respectively, to conform to our current presentation as discussed above in “—Overview.” The amounts for 2016, 2015 and 2014 were $7 million, $4 million and $6 million, respectively, in income tax expense and for 2014, $1 million in interest income.

(d)	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 $109 million (25%) from SNG primarily due to our sale of a 50% interest in SNG to The Southern Company (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 CPG primarily due to lower transport revenues as a result of contract expirations;

•	decrease of $15 million (48%) from TransColorado primarily due to lower transport revenues as a result of contract expirations;

•	increase of $171 million (18%) from TGP primarily due to a full year of earnings from expansion projects placed in service during 2015 and favorable 2016 firm transport revenues;

•	increase of $59 million (42%) from Hiland Midstream primarily due to favorable margins on renegotiated contracts, along with results of a full year from our February 2015 Hiland acquisition; and

•

increase of $7 million (2%) from our Texas intrastate natural gas pipeline operations (including the operations of its Kinder Morgan Tejas, Border, Kinder Morgan Texas, North Texas and Mier-Monterrey Mexico pipeline systems) primarily due to higher storage margins partially offset by lower sales and transportation margins as a result of lower volumes. The decrease in revenues of $278 million resulted primarily from a decrease in sales revenue due to lower commodity prices which was largely offset by a corresponding decrease in costs of sales.

---

(a)	Equity investment.

•	increase of $140 million from our February 2015 acquisition of the Hiland Midstream asset;

•

increase of $36 million (4%) from TGP primarily due to higher revenues from firm transportation and storage services due largely to expansion projects placed in service in the fourth quarter 2014 and during 2015. Partially offsetting this was an increase in the provision for revenue sharing during 2015, lower transportation usage revenues and natural gas park and loan revenues due to milder winter weather in 2015 and higher ad valorem taxes;

•	increase of $35 million (9%) from EPNG due largely to additional firm transport revenues due, in part, to additional demand from Mexico;

•	increase of $31 million (443%) from EagleHawk driven by higher volumes and lower pipeline integrity costs;

•

increase of $15 million (4%) 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) due largely to higher transportation and natural gas sales margins as a result of new customer contracts, partially offset by lower processing margins due to the non-renewal of a customer contract in the second quarter of 2014 and lower storage margins. The decrease in revenues of $1,231 million and associated decrease in costs of goods sold were caused by lower natural gas prices;

•	decrease of $67 million (34%) from KinderHawk primarily due to the expiration of a minimum volume contract;

•	decrease of $38 million (57%) from Oklahoma Midstream primarily due to lower commodity prices and lower volumes. Lower revenues of $247 million and associated decrease in costs of goods sold were also due to lower commodity prices;

•	decrease of $33 million (59%) from KMLP as a result of a customer contract buyout in the third quarter of 2014;

•	decrease of $24 million (29%) from CPG due primarily to lower transport revenues as a result of contract expirations;

•	decrease of $21 million (35%) from Altamont Midstream primarily due to lower commodity prices partially offset by higher volumes; and

•	decrease of $9 million (3%) from South Texas Midstream primarily due to lower commodity prices, partially offset by higher gathering and processing volumes. Lower revenues of $417 million and associated decrease in costs of goods sold were due to lower commodity prices.

---

(a)	2016, 2015 and 2014 amounts include an unrealized loss of $63 million, and unrealized gains of $138 million and $25 million, respectively, all relating to derivative contracts used to hedge forecasted commodity sales. 2015 amount also includes a favorable adjustment of $10 million related to carried working interest at McElmo Dome.

(b)

In addition to the revenue certain items described in footnote (a) above: 2016 amount also includes a decrease of $9 million in equity earnings for our share of a project write-off recorded by an equity investee and a $20 million increase in expense related to source and transportation project write-offs. 2015 amount also includes (i) oil and gas property impairments of $399 million; (ii) project write-offs of $207 million; and (iii) a $26 million decrease in equity earnings for our share of a project write-off. 2014 amount also includes oil and gas property impairments of $243 million.

(c)	Income tax expense that was allocated to and presented in Segment EBDA in prior periods is presented herein in income tax expense to conform to our current presentation as discussed above in “—Overview.” The amounts for 2016, 2015 and 2014 were $2 million, $1 million and $8 million, respectively, in income tax expense.

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

(e)	Represents 100% of the production from the field.  We own 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.

---

---

(a)	2016, 2015 and 2014 amounts include increases in revenues of $28 million, $23 million and $18 million, respectively, from the amortization of a fair value adjustment (associated with the below market contracts assumed upon acquisition) from our Jones Act tankers.

(b)

In addition to the revenue certain items described in footnote (a) above: 2016 amount also includes increases in expense of $103 million related to losses on impairments and divestitures, net and $16 million related to losses on impairments and divestitures of equity investments, net. 2015 amount also includes (i) 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; (ii) 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 (iii) $20 million primarily related to other impairment charges. 2014 amount also includes a $29 million write-down associated with a sale of certain terminals to a third-party and $24 million of increased expense from other certain items.

(c)	Income tax expense that was allocated to and presented in Segment EBDA in prior periods is presented herein in income tax expense to conform to our current presentation as discussed above in “—Overview.” The amounts for 2016, 2015 and 2014 were $42 million, $29 million and $29 million, respectively, in income tax expense.

(d)	Includes our proportionate share of joint venture tonnage.

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

---

•	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.

---

•	increase of $52 million (76%) from our Alberta, Canada terminals, driven by our Edmonton-area expansion projects, including storage and connectivity additions at our Edmonton South and North 40 terminals as well as the commissioning of two joint venture rail terminals;

•	increase of $44 million from our Marine Operations related primarily to the incremental earnings from the Jones Act tankers we acquired in the first and fourth quarters of 2014 as well as the December 2015 delivery from the NASSCO shipyard of the first new build tanker, the Lone Star State;

•	increase of $24 million (11%) from our Gulf Liquids terminals, related to the Vopak terminal acquisition completed in first quarter 2015 and the addition of nine new tanks at Galena Park placed into service during fourth quarter 2014 and first quarter 2015;

•	increase of $23 million (52%) from our Gulf Central terminals, driven by higher earnings from our expansion projects at our joint venture terminals, Battleground Oil Specialty Terminal Company LLC (BOSTCO) and Deeprock Development LLC;

•	decrease of $17 million (77%) from our sale of certain bulk and transload terminal facilities to Watco Companies, LLC in early 2015;

•	decrease of $16 million (18%) from our Gulf Bulk terminals, primarily from reduced coal earnings due to certain coal customers bankruptcies of $27 million partially offset by increased shortfall revenue from take-or-pay coal contracts;

•	decrease of $21 million (29%) from our Mid Atlantic terminals, driven by lower revenues as a result of lower tonnage partially offset by higher shortfall revenue from take-or-pay coal contracts; and

•	decrease of $21 million primarily from reduced coal earnings due to certain coal customers bankruptcies, which impacted our International Marine Terminals and Mid River terminals included in “All others” and the Mid Atlantic terminals noted above by $16 million, $3 million and $2 million, respectively.

---

(a)

2016 amount includes increases in expense of (i) $65 million related to the Palmetto project write-off; (ii) $31 million of rate case liability estimate adjustments associated with prior periods; (iii) $20 million related to a legal settlement; and (iv) $9 million of non-cash impairment charges related to the sale of a Transmix facility; offset by a $12 million gain related to the sale of an equity investment. 2015 and 2014 amounts include a $4 million decrease in expense and a $4 million increase in expense, respectively, associated with a certain Pacific operations litigation matter.

(b)	Income tax expense and interest income that were allocated to and presented in Segment EBDA in prior periods are presented herein in income tax expense and interest expense, net, respectively, to conform to our current presentation as discussed above in “—Overview.”

(c)	Volumes include ethanol pipeline volumes.

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

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

---

•	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.

---

•	increase of $102 million (124%) from Kinder Morgan Crude & Condensate Pipeline driven primarily by an increase of pipeline throughput volumes due to the ramp up of existing customer volumes and additional volumes from new customers;

•	increase of $33 million from our KMCC - Splitter due to the startup of the first and second phases in March 2015 and July 2015;

•	increase of $44 million from our Double H pipeline which was acquired in February 2015 as part of the Hiland acquisition;

•	increase of $35 million (40%) from Cochin driven by higher service revenues due to the completion of the Cochin Reversal project in the third quarter of 2014;

•	increase of $23 million (7%) from our Pacific operations due to higher service revenues, resulting from higher volumes and margins; and

•	increase of $8 million (33%) from our Transmix processing operations primarily due to favorable inventory adjustments impacting margins. The decrease in revenues of $490 million and associated decrease in costs of goods sold were caused by lower commodity prices.

(a)	Income tax expense that was allocated to and presented in Segment EBDA in prior periods is presented herein in income tax expense to conform to our current presentation as discussed above in “—Overview.” The amounts for 2016, 2015 and 2014 were $20 million, $19 million and $18 million, respectively, in income tax expense.

(b)	Represents Trans Mountain pipeline system volumes.

---

(a)	Amount consists of unrealized foreign currency gains, net of book tax, on outstanding, short-term intercompany borrowings that were repaid in December 2014. We sold our debt and equity investments in Express Pipeline on March 14, 2013.

(a)

2016 amount includes increases in expense of (i) $14 million related to severance costs; and (ii) $12 million related to acquisition costs; offset by a decrease in expense of $31 million related to certain corporate litigation matters. 2015 and 2014 amounts include decreases in expense of $35 million and $39 million related to pension credit income. 2015 amount also includes increases in expense of $45 million related to certain corporate legal matters and $15 million related to costs associated with acquisitions. 2014 amount also includes a net increase of $11 million in expense for various other certain items.

(b)

2016, 2015 and 2014 amounts include (i) decreases in interest expense of $115 million, $71 million and $65 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions; (ii) a $34 million decrease, a $21 million increase and a $15 million increase, respectively, in interest expense related to certain litigation matters; and (iii) a $44 million decrease, a $23 million increase and

---

(c)	2015 amount is primarily related to a litigation matter and 2014 amount is primarily related to our foreign operations.

(d)	2015 amount reflects the noncontrolling interest portion of certain items including (i) a $43 million impairment and a $6 million loss associated with Terminals segment certain items and disclosed above in “—Terminals” and (ii) a $14 million loss associated with a Natural Gas Pipelines segment impairment certain item and disclosed above in “—Natural Gas Pipelines.”

(e)	2016, 2015 and 2014 amounts include certain equity investee management fee revenue of $34 million, $37 million and $36 million, respectively. These amounts are recorded to the “Product sales and other” caption with the offsetting expenses primarily included in the “General and administrative” expense caption in our accompanying consolidated statements of income.

---

---

---

(a)	2016 and Expected 2017 amounts include $90 million and $112 million, respectively, for our proportionate share of sustaining capital expenditures of certain unconsolidated joint ventures.

(b)	2016 amount includes $574 million of discretionary capital expenditures of unconsolidated joint ventures and small acquisitions (i.e. excludes Hiland acquisition) and divestitures and excludes a combined $199 million of net changes from accrued capital expenditures and contractor retainage.

(c)	Expected 2017 amount includes our contributions to certain unconsolidated joint ventures and small acquisitions and divestitures, net of contributions estimated from unaffiliated joint venture partners for consolidated investments.

---

(a)	Less than 1 year amount primarily includes $2,541 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, KMI common stock and/or warrants. 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, 2016.

(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 fund assets for pension and other postretirement benefit plans at year-end. The payments by period include expected contributions to funded plans in 2017 and estimated benefit payments for unfunded plans in all years.

(e)	Primarily represents transportation agreements of $469 million, volume agreements of $434 million and storage agreements for capacity on third party and an affiliate pipeline systems of $147 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 “Other long-term liabilities and deferred credits” in our consolidated balance sheets.

(g)

The $219 million in letters of credit outstanding as of December 31, 2016 consisted of the following (i) $50 million under twelve letters of credit for insurance purposes; (ii) a $32 million letter of credit supporting our pipeline and terminal operations in Canada; (iii) our $30 million guarantee under 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 $10 million letter of credit supporting Nassau County, Florida Ocean Highway and Port Authority tax-exempt bonds; and (vii) a combined $32 million in twenty-four letters of credit supporting environmental, power and marketing purposes, and other obligations of us and our subsidiaries.

(h)	Represents commitments for the purchase of plant, property and equipment as of December 31, 2016 and obligations for the definitive construction agreement with Philly Tankers LLC for 2017.

---

•

a $414 million decrease in cash from overall net income after adjusting our period-to-period $513 million increase in net income for non-cash items primarily consisting of the following: (i) loss on impairment of goodwill; (ii) net losses on impairments and divestitures; (iii) losses on impairment and divestitures of equity investments; (iv) gains on early extinguishment of debt; (See discussion above in “—Results of Operations” for further information regarding these items); (v) DD&A expenses (including amortization of excess cost of equity investments); (vi) deferred income taxes; and (vii) equity earnings from our equity investments; and

•

a $102 million decrease in cash associated with net changes in working capital items and other non-current assets and liabilities. The decrease was driven, among other things, primarily by a $195 million income tax refund received in 2015, and lower cash flow due to unfavorable changes in the collection of trade and exchange gas receivables. These decreases were offset partially by higher cash flows associated with the timing of payments from our trade payables.

•

a $1,746 million decrease in expenditures for acquisitions and investments in 2016 compared to the respective 2015 period. The overall decrease in acquisitions was primarily related to the $324 million portion of the purchase price we paid in 2016 for the BP terminals acquisition, versus the $1,706 million (net of cash assumed) and $158 million we paid for the Hiland and Vopak acquisitions, respectively, and the $134 million we paid to increase our ownership in NGPL Holdings LLC to 50% in the 2015 period;

•	a $1,401 million net increase in cash due to proceeds from the sale of a 50% equity interest in SNG;

•	a $1,014 million reduction in capital expenditures; and

•	a $291 million increase in cash due to an increase in proceeds from sales of other long-lived assets; partially offset by,

•	a $312 million increase in contributions to equity investments in 2016 compared to 2015, primarily due to a $312 million contribution to our 50% investment in NGPL Holdings LLC in 2016; and

•	a $142 million decrease in Other, net primarily due to unfavorable changes in restricted deposits associated with our hedging activities.

•	a $3,870 million decrease in financing activities resulting from the issuances of our Class P shares under our equity distribution agreement in 2015 with no Class P Share issuance activity in 2016;

•	a $1,541 million decrease in financing activities due to the issuance of our mandatory convertible preferred stock in 2015;

•	a $626 million decrease in net debt proceeds. See Note 9 “Debt” for further information regarding our debt activity; and

•	a $154 million increase in dividends paid to our mandatory convertible preferred shareholders in 2016;

•	a $3,106 million reduction in dividend payments paid to our common shareholders; and

•	a $106 million increase in contributions provided by noncontrolling interests, primarily reflecting the contributions received from BP for its 25% share of a newly formed joint venture.

---

---

---

(a)	A hypothetical 10% change in the average interest rates applicable to such debt as of December 31, 2016 and 2015, would result in changes of approximately $1,527 million and $1,667 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 2016 and approximately 49 basis points in 2015) when applied to our outstanding balance of variable rate debt as of December 31, 2016 and 2015, including adjustments for the notional swap amounts described above, would result in changes of approximately $54 million and $55 million, respectively, in our 2016 and 2015 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.

---

---

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

(3)	Exhibits

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

(a)

Regulatory assets as of December 31, 2016 include (i) $188 million of unamortized losses on disposal of assets; (ii) $107 million income tax gross up on equity AFUDC; and (iii) $84 million of other assets including amounts related to fuel tracker arrangements. Approximately $172 million of the regulatory assets, with a weighted average remaining recovery period of 20 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, 2016 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 $24 million of the $108 million classified as non-current is expected to be credited to shippers over a remaining weighted average period of 22 years, while the remaining $84 million is not subject to a defined period.

---

(a)	As of December 31, 2016, there were approximately 9 million such restricted stock awards.

(a)	Each warrant entitles the holder to purchase one share of our common stock for an exercise price of $40 per share, payable in cash or by cashless exercise, at any time until May 25, 2017. The potential dilutive effect of the warrants does 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 dividends.

---

---

---

---

---

---

---

---

•

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—Effective September 1, 2016, 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. Veresen Inc. owns the remaining interest in Ruby in the form of a convertible preferred interest. If Veresen converted its preferred interest into common interest, we and Veresen would each own a 50% common interest in Ruby;

•

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 GE Financial Services and The Blackstone Group L.P.;

•	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;

•

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;

•	MEP—We operate MEP and own a 50% interest in MEP, the sole owner of the Midcontinent Express natural gas pipeline system.  The remaining 50% ownership interest is owned by subsidiaries of Energy Transfer Partners L.P.;

•	Red Cedar Gathering Company—We own a 49% interest in Red Cedar Gathering Company, the sole owner of the Red Cedar natural gas gathering, compression and treating system.  The Southern Ute Indian Tribe owns the remaining 51% interest and serves as operator of Red Cedar;

•

Watco Companies, LLC—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 3.4% common ownership that is accounted for under the equity method of accounting;

•	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 50% interest in Bear Creek through TGP, one of our wholly owned subsidiaries. SNG 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%;

•	Utopia Holding L.L.C. — We operate Utopia Holding L.L.C. and own a 50% interest in Utopia Holding L.L.C. after the sale of 50% of our interest to Riverstone Investment Group LLC on June 28, 2016;

•	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;

---

•	Parkway Pipeline LLC —Prior to the sale of our interest in Parkway, we operated and owned a 50% interest in Parkway Pipeline LLC, the sole owner of the Parkway Pipeline refined petroleum products pipeline system. Valero Energy Corp. owns the remaining 50% interest;

•	Cortez Pipeline Company—We operate the Cortez carbon dioxide pipeline system, and as of December 31, 2016, we owned a 50% interest in, the Cortez Pipeline Company, the sole owner of the Cortez carbon dioxide pipeline system.

(a)	2016 and 2015 amounts include $9 million and $26 million, respectively, representing our share of a non-cash impairment charge (pre-tax) recorded by Cortez Pipeline Company.

(b)	2016 amount includes non-cash impairment charges of $7 million (pre-tax) related to our investment.

---

(a)	2015 includes $93 million and $217 million, respectively, related to the February 2015 acquisition of Hiland by Natural Gas Pipelines Non-Regulated and Products Pipelines, and $7 million related to the February 2015 acquisition of Vopak terminal assets by Terminals, all of which are discussed in Note 3.

(b)	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.

---

(a)

On January 26, 2016, we entered into a $1 billion three-year unsecured term loan facility with a variable interest rate, which is determined in the same manner as interest on our revolving credit facility borrowings. In January 2016, we repaid $850 million of maturing 5.70% senior notes, and in February 2016, we repaid $250 million of maturing 8.00% senior notes primarily using proceeds from the three-year term loan. Since we refinanced a portion of the maturing debt with proceeds from long-term debt, we classified $1 billion of the maturing debt within “Long-term debt” on our consolidated balance sheet as of December 31, 2015.

(b)

Amounts include senior notes that are denominated in Euros and have been converted and are respectively reported above at the December 31, 2016 exchange rate of 1.0517 U.S. dollars per Euro and the December 31, 2015 exchange rate of 1.0862 U.S. dollars per Euro. For the year ended December 31, 2016, our debt decreased by $43 million as a result of the change in the exchange rate of U.S dollars per Euro. The decrease 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”).

---

(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)

On September 30, 2016, we repaid the $332 million principal amount of 7.125% senior notes due 2021, plus accrued interest. We recognized a $28.3 million gain from the early extinguishment of debt, included within “Interest, net” on the accompanying consolidated statements of income for the year ended December 31, 2016 consisting of an $11.8 million premium on the debt repaid and a $40.1 million gain from the write-off of unamortized purchase accounting associated with the extinguished debt. Copano continues to be a subsidiary guarantor under a cross guarantee agreement (see Note 19).

(e)	On August 16, 2016, CIG completed a private offering of $375 million in principal amount of 4.15% senior notes due August 15, 2026. The net proceeds of $372 million received from the offering were used to reduce debt incurred as the result of the repayment of CIG’s senior notes that matured in 2015 and for general corporate purposes.

(f)	Due to the September 1, 2016 sale of a 50% interest in SNG, we no longer consolidate SNG’s accounts in our consolidated financial statements. As of the transaction date, SNG had $1,211 million of debt outstanding (including a current portion of $500 million).

(g)

On October 1, 2016, a portion of the proceeds from the sale of a 50% interest in SNG was used to repay the $749 million principal amount of Hiland’s 7.25% senior notes due 2020, plus accrued interest. We recognized a $17.3 million gain from the early extinguishment of debt, included within “Interest, net” on the accompanying consolidated statements of income for the year ended December 31, 2016 consisting of a $27.1 million premium on the debt repaid and a $44.4 million gain from the write-off of unamortized purchase accounting associated with the extinguished debt.

(h)

Capital Trust I (Trust I), is a 100%-owned business trust that as of December 31, 2016, 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. 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, 2016, the outstanding balance of $221 million (of which $111 million was classified as current) was bifurcated between debt ($199 million) and equity ($22 million). During the years ended December 31, 2016 and 2015, 200 and 1,176,015, respectively, of Trust I Preferred Securities had been converted into (i) 143 and 846,369 shares of our Class P common stock; (ii) approximately $5,000 and $30 million in cash; and (iii) 220 and 1,293,615 in warrants, respectively.

(i)

As of December 31, 2016 and 2015, 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.

(j)

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, 2016, the principal amounts of the Totem and High Plains financing obligations were $71 million and $92 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.

(k)	Amounts include outstanding credit facility and commercial paper borrowings and other debt maturing within 12 months. See “—Maturities of Debt” below.

(l)

Excludes our “Debt fair value adjustments” which, as of December 31, 2016 and 2015, increased our combined debt balances by $1,149 million and $1,674 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.

---

•	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.

---

(a)	Senior notes are denominated in Euros and are presented above in U.S. dollars at the exchange rate on the issuance date of 1.0862 U.S. dollars per Euro. We entered into cross-currency swap agreements associated with these senior notes (see Note 14—“Risk Management—Foreign Currency Risk Management”).

(b)

As of the February 13, 2015 Hiland acquisition date, we assumed (i) $975 million in principal amount of senior notes (which were valued at $1,043 million as of the acquisition date) and (ii) $368 million of other borrowings that were immediately repaid after closing, primarily consisting of borrowings outstanding under a revolving credit facility. The senior notes are subject to our cross guarantee agreement discussed in Note 19.

---

---

---

(a)	2016 amounts represent December 31, 2015 balances associated with our Canadian pension and OPEB plans and Plantation Pipeline OPEB plan for prospective inclusion in these disclosures, which associated net periodic benefit costs were reported separately in prior years.

---

(a)	2016 OPEB amount includes $29 million of non-current benefit assets and $12 million of non-current benefit liabilities related to plans we sponsor which are associated with employee services provided to unconsolidated joint ventures, and for which we have recorded an offsetting related party deferred charge/credit.

•	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 master limited partnerships. These investments are valued at the closing price reported on the active market on which the individual securities are traded.

•

Level 2 assets’ fair values are primarily based on pricing data representative of quoted prices for similar assets in active markets (or identical assets in less active markets). Included in this level are short-term investment funds, fixed income securities and derivatives. Short-term investment funds are valued at amortized cost, which approximates fair value. The fixed income securities’ fair values are primarily based on an evaluated price which is based on a compilation of primarily observable market information or a broker quote in a non-active market. Derivatives are exchange-traded through clearinghouses and are valued based on these prices.

•	Level 3 assets’ fair values are calculated using valuation techniques that require inputs that are both significant to the fair value measurement and are unobservable, or are similar to Level 2 assets. Included in this level are guaranteed

---

•

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. These amounts are not categorized within the fair value hierarchy described above, but are separately identified in the following tables.

(a)	For 2016 and 2015, this category includes mutual funds which are invested in equity.

(b)	Plan assets include $126 million and $91 million of KMI Class P common stock for 2016 and 2015, 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 39% fixed income and 61% equity in 2016 and 45% fixed income and 55% equity in 2015.

(e)	Private investment funds were invested in approximately 54% fixed income and 46% equity in 2016 and 46% fixed income and 54% equity in 2015.

(f)	Private limited partnerships were invested in real estate, venture and buyout funds for 2016 and 2015.

---

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

(b)	Common/collective trust funds which are invested in approximately 72% equity and 28% fixed income securities for 2016 and 67% equity and 33% fixed income securities for 2015.

(c)	For 2016 and 2015, limited partnerships were invested in global equity securities.

---

(a)	Includes a reduction of approximately $3 million in each of the years 2017 - 2021 and approximately $16 million in aggregate for 2022 - 2026 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 2016, 2015 and 2014.

---

(a)

2016 OPEB amount includes $4 million of net benefit credits related to plans that we sponsor that are associated with employee services provided to unconsolidated joint ventures. We charge or refund these costs or credits associated with these plans 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.

---

(a)	See Note 9.

---

(a)	As a result of the Merger Transactions, no distribution was declared starting with the fourth quarter of 2014.

(b)

KMR’s distributions were paid in the form of additional shares or fractions thereof calculated by dividing the KMP cash distribution per common unit by the average of the market closing prices of a KMR share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for the shares.  Represents share distributions made in the period to noncontrolling interests and excludes 1,127,712 of shares distributed in 2014 on KMR shares we directly and indirectly owned.

---

---

---

---

---

(a)

We expect to reclassify an approximate $8 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balances as of December 31, 2016 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.

---

---

•	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).

---

(a)	Level 1 consists primarily of NYMEX natural gas futures.  Level 2 consists primarily of OTC WTI swaps and options and NGL swaps.  Level 3 consists primarily of power derivative contracts.

(b)	Cash margin deposits held by us associated with our energy commodity contract positions and OTC swap agreements and reported within “Other current liabilities” on our accompanying consolidated balance sheets.

(c)	Cash margin deposits posted by us associated with our energy commodity contract positions and OTC swap agreements and reported within “Restricted Deposits” on our accompanying consolidated balance sheets.

---

•	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—(i) the ownership and/or operation of 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 coal, petroleum coke, fertilizer, steel and ores 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, 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.

---

---

---

---

(a)	Includes a management fee for services we perform as operator of an equity investee.

(b)	Includes natural gas purchases and other 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) expense, net.

(d)	Includes revenues, earnings from equity investments, other, net, less operating expenses, and other (income) expense, 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 operations) not allocated to the reportable segments.

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---