Edgar Filing: KINDER MORGAN, INC.

Asset or project

Description

Approx. Capital Scope

Kinder Morgan Canada

An increase of capacity on our Trans Mountain pipeline system from approximately 300 to 890 MBbl/d, underpinned by long-term take-or-pay contracts.

Received federal government approval in December 2016. In the process of getting permits and other regulatory approval.

C$7.4
billion

Document

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_____________

Form 10-K



[X]	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2017



[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission file number: 001-35081

Kinder Morgan, Inc.

(Exact name of registrant as specified in its charter)



Delaware		80-0682103
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1001 Louisiana Street, Suite 1000, Houston, Texas 77002

(Address of principal executive offices) (zip code)

Registrant’s telephone number, including area code: 713-369-9000

____________

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	Name of each exchange on which registered
Class P Common Stock	New York Stock Exchange
Depositary Shares, each representing a 1/20th interest in a share of 9.75% Series A Mandatory Convertible Preferred Stock	New York Stock Exchange
1.500% Senior Notes due 2022	New York Stock Exchange
2.250% Senior Notes due 2027	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933. Yes þ No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934. Yes o No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K(§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

Large accelerated filer þ Accelerated filer o Non-accelerated filer o Smaller reporting company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes o No þ

Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on closing prices in the daily composite list for transactions on the New York Stock Exchange on June 30, 2017 was approximately $36,830,209,065. As of February 8, 2018, the registrant had 2,206,066,684 Class P shares outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s definitive proxy statement for the 2018 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2018, are incorporated into PART III, as specifically set forth in PART III.

KINDER MORGAN, INC. AND SUBSIDIARIES TABLE OF CONTENTS

		Page Number
	Glossary	1
	Information Regarding Forward-Looking Statements	2

	PART I
Items 1. and 2.	Business and Properties	4
	General Development of Business	4
	Organizational Structure	4
	Recent Developments	5
	Financial Information about Segments	8
	Narrative Description of Business	8
	Business Strategy	8
	Business Segments	9
	Natural Gas Pipelines	9
	CO₂	11
	Terminals	14
	Products Pipelines	15
	Kinder Morgan Canada	15
	Major Customers	17
	Regulation	17
	Environmental Matters	21
	Other	23
	Financial Information about Geographic Areas	24
	Available Information	24
Item 1A.	Risk Factors	24
Item 1B.	Unresolved Staff Comments	35
Item 3.	Legal Proceedings	35
Item 4.	Mine Safety Disclosures	35

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	36
Item 6.	Selected Financial Data	37
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
	General	38
	Critical Accounting Policies and Estimates	42
	Results of Operations	45
	Income Taxes	60
	Liquidity and Capital Resources	60
	Recent Accounting Pronouncements	67

KINDER MORGAN, INC. AND SUBSIDIARIES TABLE OF CONTENTS (continued)

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	67
	Energy Commodity Market Risk	68
	Interest Rate Risk	69
Item 8.	Financial Statements and Supplementary Data	70
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	70
Item 9A.	Controls and Procedures	70
Item 9B.	Other Information	70

	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	71
Item 11.	Executive Compensation	71
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	71
Item 13.	Certain Relationships and Related Transactions, and Director Independence	71
Item 14.	Principal Accounting Fees and Services	71

	PART IV
Item 15.	Exhibits, Financial Statement Schedules	71
	Index to Financial Statements	76
Item 16.	Form 10-K Summary	153
Signatures		154

KINDER MORGAN, INC. AND SUBSIDIARIES GLOSSARY Company Abbreviations

Calnev	=	Calnev Pipe Line LLC	KMGP	=	Kinder Morgan G.P., Inc.
CIG	=	Colorado Interstate Gas Company, L.L.C.	KMI	=	Kinder Morgan, Inc. and its majority-owned and/or
Copano	=	Copano Energy, L.L.C.			controlled subsidiaries
CPGPL	=	Cheyenne Plains Gas Pipeline Company, L.L.C.	KML	=	Kinder Morgan Canada Limited and its majority-
EagleHawk	=	EagleHawk Field Services LLC			owned and/or controlled subsidiaries
Elba Express	=	Elba Express Company, L.L.C.	KMLP	=	Kinder Morgan Louisiana Pipeline LLC
ELC	=	Elba Liquefaction Company, L.L.C.	KMP	=	Kinder Morgan Energy Partners, L.P. and its
EP	=	El Paso Corporation and its majority-owned and			majority-owned and controlled subsidiaries
		controlled subsidiaries	KMR	=	Kinder Morgan Management, LLC
EPB	=	El Paso Pipeline Partners, L.P. and its majority-	MEP	=	Midcontinent Express Pipeline LLC
		owned and controlled subsidiaries	NGPL	=	Natural Gas Pipeline Company of America LLC
EPNG	=	El Paso Natural Gas Company, L.L.C.	Ruby	=	Ruby Pipeline Holding Company, L.L.C.
EPPOC	=	El Paso Pipeline Partners Operating Company,	SFPP	=	SFPP, L.P.
		L.L.C.	SLNG	=	Southern LNG Company, L.L.C.
FEP	=	Fayetteville Express Pipeline LLC	SNG	=	Southern Natural Gas Company, L.L.C.
Hiland	=	Hiland Partners, LP	TGP	=	Tennessee Gas Pipeline Company, L.L.C.
KinderHawk	=	KinderHawk Field Services LLC	TMEP	=	Trans Mountain Expansion Project
KMCO₂	=	Kinder Morgan CO₂ Company, L.P.	WIC	=	Wyoming Interstate Company, L.L.C.
KMEP	=	Kinder Morgan Energy Partners, L.P.	WYCO	=	WYCO Development L.L.C.
Unless the context otherwise requires, references to “we,” “us,” “our,” or “the Company” are intended to mean Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries.

Common Industry and Other Terms
2017 Tax			IPO	=	Initial Public Offering
Reform	=	The Tax Cuts & Jobs Act of 2017	LIBOR	=	London Interbank Offered Rate
/d	=	per day	LLC	=	limited liability company
AFUDC	=	allowance for funds used during construction	LNG	=	liquefied natural gas
BBtu	=	billion British Thermal Units	MBbl	=	thousand barrels
Bcf	=	billion cubic feet	MDth	=	thousand dekatherms
CERCLA	=	Comprehensive Environmental Response,	MLP	=	master limited partnership
		Compensation and Liability Act	MMBbl	=	million barrels
C$	=	Canadian dollars	MMcf	=	million cubic feet
CO₂	=	carbon dioxide or our CO₂ business segment	NEB	=	National Energy Board
CPUC	=	California Public Utilities Commission	NGL	=	natural gas liquids
DCF	=	distributable cash flow	NYMEX	=	New York Mercantile Exchange
DD&A	=	depreciation, depletion and amortization	NYSE	=	New York Stock Exchange
DGCL	=	General Corporation Law of the state of Delaware	OTC	=	over-the-counter
Dth	=	dekatherms	PHMSA	=	United States Department of Transportation
EBDA	=	earnings before depreciation, depletion and			Pipeline and Hazardous Materials Safety
		amortization expenses, including amortization of			Administration
		excess cost of equity investments	U.S.	=	United States of America
EPA	=	United States Environmental Protection Agency	SEC	=	United States Securities and Exchange
FASB	=	Financial Accounting Standards Board			Commission
FERC	=	Federal Energy Regulatory Commission	TBtu	=	trillion British Thermal Units
FTC	=	Federal Trade Commission	WTI	=	West Texas Intermediate
GAAP	=	United States Generally Accepted Accounting
		Principles
When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

Information Regarding Forward-Looking Statements

This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “outlook,” “continue,” “estimate,” “expect,” “may,” or the negative of those terms or other variations of them or comparable terminology. In particular, expressed or implied statements concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow, service debt or pay dividends, are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results may differ materially from those expressed in our forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or accurately predict. Specific factors that could cause actual results to differ from those in our forward-looking statements include:


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


•	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;


•	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.

The foregoing list should not be construed to be exhaustive. We believe the forward-looking statements in this report are reasonable. However, there is no assurance that any of the actions, events or results expressed in forward-looking statements will occur, or if any of them do, of their timing or what impact they will have on our results of operations or financial condition. Because of these uncertainties, you should not put undue reliance on any forward-looking statements.

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

PART I

Items 1 and 2. Business and Properties.

We are one of the largest energy infrastructure companies in North America. We own an interest in or operate approximately 85,000 miles of pipelines and 152 terminals. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO₂ and other products, and our terminals transload and store liquid commodities including petroleum products, ethanol and chemicals, and bulk products, including petroleum coke, steel and coal. We are also a leading producer of CO₂, which we and others utilize for enhanced oil recovery projects primarily in the Permian basin. Our common stock trades on the NYSE under the symbol “KMI.”

(a) General Development of Business

Organizational Structure

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

Sale of Approximate 30% Interest in our Canadian Business

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

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

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

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

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

Recent Developments

The following is a brief listing of significant developments and updates related to our major projects and other transactions. Additional information regarding most of these items may be found elsewhere in this report. “Capital Scope” is estimated for our share of the described project which may include portions not yet completed.



Asset or project	Description	Activity	Approx. Capital Scope
Placed in service, acquisitions or divestitures
ELC	Sold 49% interest in ELC to investment funds of EIG Global Energy Partners and formed a joint venture, which includes our remaining 51% interest in ELC.	Completed in February 2017.	n/a
Jones Act Tankers	Purchase of nine new-build, medium-range Jones Act tankers constructed by General Dynamics NASSCO Shipyard (five) and Philly Shipyard, Inc. (four). Each of the 50,000-deadweight-ton, LNG conversion-ready product tankers has a capacity of approximately 330,000 barrels and is contracted under a term charter agreement.	First tanker delivery took place in December 2015. Four additional tankers were delivered during 2016. The final four tankers were delivered during 2017.	$1.4 billion
Elba Express and SNG Expansion	Expansion project that provides 854,000 Dth/d of incremental natural gas transportation service supporting the needs of customers in Georgia, South Carolina and northern Florida, and also serving ELC. Supported by long-term firm contracts.	Initial service began in December 2016. As of December 31, 2017, more than 70% of capacity has been placed in service. The remaining work is expected to be completed by November 2018.	$284 million
KM Export Terminal	Brownfield expansion along Houston Ship Channel that adds 12 storage tanks with 1.5 MMBbl of liquids storage capacity, one ship dock, one barge dock and cross-channel pipelines to connect with the KM Galena Park terminal. Supported by a long-term contract with a major ship channel refiner.	Storage tanks placed in service in January 2017 followed by the terminal’s full marine capabilities, which were commissioned in March 2017.	$246 million
Pit 11 Expansion	Project adds 2 MMBbl of refined products storage at Pasadena terminal along the Houston Ship Channel. Supported by long-term commitments from existing customers.	Placed in service throughout fourth quarter 2017.	$186 million
TGP Susquehanna West	Expansion project that provides 145,000 Dth/d of incremental natural gas transportation capacity from the northeast Marcellus supply basin to points of liquidity. Subscribed under long-term firm transportation contracts.	Placed in service September 2017.	$126 million
TGP Orion	Expansion project that provides 135,000 Dth/d of incremental firm transportation capacity from the Marcellus supply basin to TGP’s interconnection with Columbia Gas Transmission in Pike County, Pennsylvania. Subscribed under long-term firm transportation contracts.	Placed in service November 2017.	$104 million
TGP Connecticut Expansion	Expansion project that provides 72,100 Dth/d of incremental firm transportation capacity from Wright, New York to three local distribution companies in Connecticut. Subscribed under long-term firm transportation contracts.	Placed in service November 2017.	$104 million
TGP Triad Expansion	Expansion project that provides 180,000 Dth/d of incremental firm transportation capacity from the Marcellus supply basin to Invenergy’s Lackawanna Energy Center in Lackawanna County, Pennsylvania. Subscribed under long-term firm transportation contracts.	Project facilities placed in service November 2017 (customer contracts to begin June 2018).	$57 million
Other Announcements
Natural Gas Pipelines
ELC and SLNG Expansion	Building of new natural gas liquefaction and export facilities at our SLNG natural gas terminal on Elba Island, near Savannah, Ga., with a total capacity of 2.5 million tonnes per year of LNG, equivalent to 357,000 Dth/d of natural gas. Supported by a long-term firm contract with Shell.	First of 10 liquefaction units expected to be placed in service in mid-2018 with the remainder expected by mid-2019.	$1.2 billion
KMTP Gulf Coast Express Pipeline Project (GCX Project)(a)	New infrastructure joint venture project (KMTP 50%, DCP Midstream, LP 25% and Targa Resources Corp. 25% ownership interest) to provide up to 1.98 Bcf/d of transportation capacity from the Permian Basin to the Agua Dulce, Texas area with 1.76 Bcf/d under long-term contracts. A binding open season for the remaining 220,000 Dth/d of project capacity ends on March 1, 2018.	Pending regulatory approvals, the project is expected to be placed in service October 2019.	$638 million



Asset or project	Description	Activity	Approx. Capital Scope
TGP Broad Run Expansion	Second of two projects to create a total of 790,000 Dth/d of incremental firm transportation capacity from the southwest Marcellus and Utica supply basins to delivery points in Mississippi and Louisiana. Subscribed under long-term firm transportation contracts.	Broad Run Expansion (200,000 Dth/d) expected to be placed in service June 2018. Broad Run Flexibility facilities (590,000 Dth/d) were placed in service November 2015.	$453 million
Texas Intrastate Crossover Expansion	Expansion project that provides over 1,000,000 Dth/d of transportation capacity from the Katy Hub, the company’s Houston Central processing plant, and other third party receipt points to serve customers in Texas and Mexico. Phase I is supported by long-term firm transportation contracts of nearly 700,000 Dth/d, including a contract with Comisión Federal de Electricidad. Phase 2, which is supported by long-term firm transportation contracts with Cheniere Energy, Inc. at its Corpus Christi LNG facility and SK E&S LNG, LLC, that will provide service to the Freeport LNG export facility and other domestic markets.	Phase 1 was placed in service in September 2016. Phase 2 is expected to be placed in service by third quarter 2019.	$307 million
TGP Southwest Louisiana Supply	Expansion project to provide 900,000 Dth/d of incremental firm transportation capacity from multiple supply basins to the Cameron LNG export facility in Cameron Parish, Louisiana. Subscribed under long-term firm transportation contracts.	Expected in-service date March 2018.	$178 million
TGP Lone Star	Expansion project to provide 300,000 Dth/d of incremental firm transportation capacity from Louisiana receipt points to Cheniere’s Corpus Christi LNG export facility in Jackson County, Texas. Subscribed under long-term firm transportation contracts.	Expected in-service date July 2019.	$150 million
EPNG South Mainline Expansion (formerly upstream Sierrita)	Expansion project that provides 471,000 Dth/d of firm transportation capacity with a first phase of system improvements to deliver volumes to the Sierrita pipeline and the second phase for incremental deliveries of natural gas to Arizona and California. Subscribed under long-term firm transportation contracts.	Phase one placed in service October 2014, phase two expected to be in service July 2020.	$134 million
KMLP Magnolia LNG Liquefaction Transport	Expansion project to provide 700,000 Dth/d of incremental firm transportation capacity from various receipt points to the proposed Magnolia LNG export facility in Lake Charles, Louisiana. Subscribed under long-term firm agreements, subject to shipper’s final investment decision.	In-service date subject to timing of shipper’s final investment decision.	$127 million
KMLP Sabine Pass Expansion	Expansion project to provide 600,000 Dth/d of incremental firm transportation capacity from various receipt points to Cheniere’s Sabine Pass Liquefaction Terminal in Cameron Parish, Louisiana. Subscribed under long-term firm transportation contracts.	Expected in-service date as early as the first quarter 2019.	$122 million
SNG Fairburn Expansion	Expansion project in Georgia to provide 347,000 Dth/d of incremental long-term firm transportation capacity into the Southeast market, and includes the construction of a new compressor station, 6.5 miles of new pipeline and new meter stations.	Expected in-service date October 2018.	$119 million
NGPL Gulf Coast Southbound Expansion	Expansion project to provide 460,000 Dth/d of incremental firm transportation capacity from various interstate pipeline interconnects in Illinois, Arkansas and Texas, to points south on NGPL’s pipeline system to serve growing demand in the Gulf Coast area. Subscribed under long-term firm transportation contracts.	Partially in service April 2017 (75,000 Dth/d). Remaining (385,000 Dth/d) expected to be in service fourth quarter of 2018.	$106 million
Terminals
KM Base Line Terminal development(b)	A 4.8 MMBbl new-build merchant crude oil storage facility in Edmonton, Alberta. Developed as part of a 50-50 joint venture with Keyera Corp. Capital figure includes costs associated with the construction of a pipeline segment funded solely by Kinder Morgan. Subscribed under long-term contracts with an average initial term of 7.5 years.	Commissioning began in the first quarter of 2018. First four tanks placed in-service in January 2018 with balance expected to be phased into service throughout 2018.	C$398 million
Products Pipelines
Utopia Pipeline	Building of new 267 mile pipeline, supported by a long-term customer contract, to transport ethane and ethane-propane mixtures from the prolific Utica Shale, with an initial design capacity of 50 MBbl/d, expandable to more than 75 MBbl/d.	Placed in-service January 2018.	$275 million

_______

n/a - not applicable


(a)	Our share of capital scope is adjusted to reflect the potential exercise of Apache Corp.’s option to purchase 15% equity in the project.


(b)	As of May 31, 2017, these assets are now included in KML and are partially owned by KML’s Restricted Voting Stockholders.

KMI Financings

On August 10, 2017, 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 all of the $225 million principal amount outstanding of Hiland’s 5.50% senior notes due 2022, plus accrued interest, and to repay the $1 billion term loan facility due 2019.

KML Financings

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

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

2018 Outlook

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

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

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

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

In addition, our expectations for 2018 discussed above involve risks, uncertainties and assumptions, and are not guarantees of performance. Many of the factors that will determine these expectations are beyond our ability to control or predict, and because of these uncertainties, it is advisable to not put undue reliance on any forward-looking statement. Please read our Item 1A “Risk Factors” below for more information. Furthermore, we plan to provide updates to our 2018 expectations when we believe previously disclosed expectations no longer have a reasonable basis.

2017 Tax Reform

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

(b) Financial Information about Segments

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

Business Strategy

Our business strategy is to:


•	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.

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

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

Business Segments

We operate the following reportable business segments. These segments and their principal sources of revenues are as follows:


•	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.

Natural Gas Pipelines

Our Natural Gas Pipelines segment includes interstate and intrastate pipelines and our LNG terminals, and includes both FERC regulated and non-FERC regulated assets.

Our primary businesses in this segment consist of transportation, storage, natural gas sales, gathering, processing and treating, and the terminaling of LNG. Within this segment, are: (i) approximately 46,000 miles of wholly owned natural gas pipelines and (ii) our equity interests in entities that have approximately 26,000 miles of natural gas pipelines, along with associated storage and supply lines for these transportation networks, which are strategically located throughout the North American natural gas pipeline grid. Our transportation network provides access to the major natural gas supply areas and consumers in the western U.S., Louisiana, Texas, the Midwest, Northeast, Rocky Mountain, Midwest and Southeastern regions. Our LNG storage and regasification terminals also serve natural gas supply areas in the southeast. The following tables summarize our significant Natural Gas Pipelines segment assets, as of December 31, 2017. The Design Capacity represents either transmission, gathering or liquefaction capacity depending on the nature of the asset.



Asset (KMI ownership shown if not 100%)	Miles of Pipeline	Design (Bcf/d) Capacity	Storage (Bcf) [Processing (Bcf/d)] Capacity	Supply and Market Region
Natural Gas Pipelines
TGP	11,750	12.00	106	North to south to Gulf Coast and U.S.-Mexico border, southeast U.S.; Haynesville, Marcellus, Utica, and Eagle Ford shale formations
EPNG/Mojave pipeline system	10,600	5.65	44	Northern New Mexico, Texas, Oklahoma, to California, connects to San Juan, Permian and Anadarko basins
NGPL (50%)	9,100	7.60	288	Chicago and other Midwest markets and all central U.S. supply basins; north to south for LNG and to U.S.-Mexico border
SNG (50%)	6,900	4.16	68	Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee; basins in Texas, Louisiana, Mississippi and Alabama
Florida Gas Transmission (Citrus) (50%)	5,300	3.60	—	Texas to Florida; basins along Louisiana and Texas Gulf Coast, Mobile Bay and offshore Gulf of Mexico
CIG	4,350	5.15	37	Colorado and Wyoming; Rocky Mountains and the Anadarko Basin



Asset (KMI ownership shown if not 100%)	Miles of Pipeline	Design (Bcf/d) Capacity	Storage (Bcf) [Processing (Bcf/d)] Capacity	Supply and Market Region
WIC	850	3.88	—	Wyoming, Colorado and Utah; Overthrust, Piceance, Uinta, Powder River and Green River Basins
Ruby (50%)(a)	680	1.53	—	Wyoming to Oregon with interconnects supplying California and the Pacific Northwest; Rocky Mountain basins
MEP (50%)	510	1.80	—	Oklahoma and north Texas supply basins to interconnects with deliveries to interconnects with Transco, Columbia Gulf and various other pipelines
CPGPL	410	1.20	—	Colorado and Kansas, natural gas basins in the Central Rocky Mountain area
TransColorado Gas	310	0.98	—	Colorado and New Mexico; connects to San Juan, Paradox and Piceance basins
WYCO (50%)	224	1.20	7	Northeast Colorado; interconnects with CIG, WIC, Rockies Express Pipeline, Young Gas Storage and PSCo’s pipeline system
Elba Express	200	0.95	—	Georgia; connects to SNG (Georgia), Transco (Georgia/South Carolina), SLNG (Georgia) and Dominion Energy Carolina Gas Transmission (Georgia)
FEP (50%)	185	2.00	—	Arkansas to Mississippi; connects to NGPL, Trunkline Gas Company, Texas Gas Transmission and ANR Pipeline Company
KMLP	135	2.20	—	sources gas from Cheniere Sabine Pass LNG terminal to interconnects with Columbia Gulf, ANR and various other pipelines
Sierrita Gas Pipeline LLC (35%)	61	0.20	—	near Tucson, Arizona, to the U.S.-Mexico border near Sasabe, Arizona; connects to EPNG and via an international border crossing with a third-party natural gas pipeline in Mexico
Young Gas Storage (48%)	16	—	5.8	Morgan County, Colorado, capacity is committed to CIG and Colorado Springs Utilities
Keystone Gas Storage	15	—	6.4	located in the Permian Basin and near the WAHA natural gas trading hub in West Texas
Gulf LNG Holdings (50%)	5	—	6.6	near Pascagoula, Mississippi; connects to four interstate pipelines and a natural gas processing plant
Bear Creek Storage (75%)	—	—	59	located in Louisiana; provides storage capacity to SNG and TGP
SLNG	—	—	11.5	Georgia; connects to Elba Express, SNG and Dominion Energy Carolina Gas Transmission
ELC (51%)	—	0.35	—	Georgia; expect phased in-service from mid-2018 to mid-2019

Midstream Natural Gas Assets
KM Texas and Tejas pipelines	5,660	7.00	132 [0.54]	Texas Gulf Coast
Mier-Monterrey pipeline	90	0.65	—	Starr County, Texas to Monterrey, Mexico; connect to CENEGAS national system and multiple power plants in Monterrey
KM North Texas pipeline	80	0.33	—	interconnect from NGPL; connects to 1,750-megawatt Forney, Texas, power plant and a 1,000-megawatt Paris, Texas, power plant
Oklahoma
Oklahoma System	3,500	.50	[0.14]	Hunton Dewatering, Woodford Shale and Mississippi Lime
Hiland - Midcontinent	620	.22	—	Woodford Shale, Anadarko Basin and Arkoma Basin
Cedar Cove (70%)	85	0.03	—	Oklahoma STACK, capacity excludes third-party offloads
South Texas
South Texas System	1,300	1.74	[1.02]	Eagle Ford shale, Woodbine and Eaglebine formations
Webb/Duval gas gathering system (63%)	145	0.15	—	South Texas



Asset (KMI ownership shown if not 100%)	Miles of Pipeline	Design (Bcf/d) Capacity	Storage (Bcf) [Processing (Bcf/d)] Capacity	Supply and Market Region
EagleHawk (25%)	530	1.20	—	South Texas, Eagle Ford shale formation
KM Altamont	1,380	0.08	[0.08]	Utah, Uinta Basin
Red Cedar (49%)	900	0.70	—	La Plata County, Colorado, Ignacio Blanco Field
Rocky Mountain
Fort Union (37%)	310	1.25	—	Powder River Basin (Wyoming)
Bighorn (51%)	290	0.60	—	Powder River Basin (Wyoming)
KinderHawk	510	2.00	—	Northwest Louisiana, Haynesville and Bossier shale formations
North Texas	550	0.14	[0.10]	North Barnett Shale Combo
Endeavor (40%)	101	0.15	—	East Texas, Cotton Valley Sands and Haynesville/ Bossier Shale
Camino Real	70	0.15	—	South Texas, Eagle Ford shale formation
KM Treating	—	—	—	Odessa, Texas, other locations in Tyler and Victoria, Texas
Hiland - Williston	2,030	.32	[0.20]	Bakken/Three Forks shale formations (North Dakota/Montana)

Midstream Liquids/Oil/Condensate Pipelines
		(MBbl/d)	(MBbl)
Liberty Pipeline (50%)	87	140	—	Y-grade pipeline from Houston Central complex to the Texas Gulf Coast
South Texas NGL Pipelines	340	115	—	Ethane and propane pipelines from Houston Central complex to the Texas Gulf Coast
Camino Real - Condensate	69	110	60	South Texas, Eagle Ford shale formation
Hiland - Williston - Oil	1,500	282	—	Bakken/Three Forks shale formations (North Dakota/Montana)
EagleHawk - Condensate (25%)	400	220	60	South Texas, Eagle Ford shale formation

_______


(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.

Competition

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

Shippers on our natural gas pipelines compete with other forms of energy available to their natural gas customers and end users, including electricity, coal, propane, fuel oils and renewables such as wind and solar. Several factors influence the demand for natural gas, including price changes, the availability of natural gas and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the ability to convert to alternative fuels and weather.

CO₂

Our CO₂ business segment produces, transports, and markets CO₂ for use in enhanced oil recovery projects as a flooding medium for recovering crude oil from mature oil fields. Our CO₂ pipelines and related assets allow us to market a complete

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

Sales and Transportation Activities

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



	Ownership Interest %	Recoverable CO₂ (Bcf)	Compression Capacity (Bcf/d)	Location
Recoverable CO₂
McElmo Dome unit	45	4,159	1.5	Colorado
Doe Canyon Deep unit	87	382	0.2	Colorado
Bravo Dome unit(a)	11	285	0.3	New Mexico

_______


(a)	We do not operate this unit.

CO₂ Segment Pipelines

The principal market for transportation on our CO₂ pipelines is to customers, including ourselves, using CO₂ for enhanced recovery operations in mature oil fields in the Permian Basin, where industry demand is expected to remain stable for the next several years. The tariffs charged on the Wink crude oil pipeline system are regulated by both the FERC and the Texas Railroad Commission and the Pecos Carbon Dioxide Pipeline’s tariffs are regulated by the Texas Railroad Commission. The tariff charged on the Cortez pipeline is based on a consent decree and the tariffs charged by our other CO₂ pipelines are not regulated.

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



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

_______


(a)	We do not operate Bravo pipeline.

Oil and Gas Producing Activities

Oil Producing Interests

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



		KMI Gross
	Working	Developed
	Interest %	Acres
SACROC	97	49,156
Yates	50	9,576
Goldsmith Landreth San Andres	99	6,166
Katz Strawn	99	7,194
Sharon Ridge	14	2,619
Tall Cotton (ROZ)	100	641
MidCross	13	320
Reinecke(a)	—	80

_______


(a)	Working interest less than 1 percent.

The following table sets forth productive wells, service wells and drilling wells in the oil and gas fields in which we owned interests as of December 31, 2017. The oil and gas producing fields in which we own interests are located in the Permian Basin area of West Texas. When used with respect to acres or wells, “gross” refers to the total acres or wells in which we have a working interest, and “net” refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by us:



	Productive Wells(a)		Service Wells(b)		Drilling Wells(c)
	Gross	Net	Gross	Net	Gross	Net
Crude Oil	2,327	1,518	1,412	1,088	27	26
Natural Gas	5	2	—	—	—	—
Total Wells	2,332	1,520	1,412	1,088	27	26

_______


(a)	Includes active wells and wells temporarily shut-in. As of December 31, 2017, we did not operate any productive wells with multiple completions.


(b)	Consists of injection, water supply, disposal wells and service wells temporarily shut-in. A disposal well is used for disposal of salt water into an underground formation; and an injection well is a well drilled in a known oil field in order to inject liquids and/or gases that enhance recovery.


(c)	Consists of development wells in the process of being drilled as of December 31, 2017. A development well is a well drilled in an already discovered oil field.

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



	Year Ended December 31,
	2017	2016	2015
Productive
Development	108	40	87
Exploratory		3	20
Total Productive	108	43	107
Dry Exploratory	—	—	—
Total Wells	108	43	107

_______

Note: The above table includes wells that were completed during each year regardless of the year in which drilling was initiated, and does not include any wells where drilling and completion operations were not finalized as of the end of the applicable year. A completed well refers to the installation of permanent equipment for the production of oil and gas. A development well is a well drilled in an already discovered oil field. A dry hole is reflected once the well has been abandoned and reported to the appropriate governmental agency.

The following table reflects the developed and undeveloped oil and gas acreage that we held as of December 31, 2017:



	Gross	Net
Developed Acres	75,752	72,562
Undeveloped Acres	17,282	15,351
Total	93,034	87,913

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

Gas and Gasoline Plant Interests

Operated gas plants in the Permian Basin of West Texas:



	Ownership
	Interest %	Source
Snyder gasoline plant(a)	22	The SACROC unit and neighboring CO₂ projects, specifically the Sharon Ridge and Cogdell units
Diamond M gas plant	51	Snyder gasoline plant
North Snyder plant	100	Snyder gasoline plant

_______


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

Competition

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

Terminals

Our Terminals segment includes the operations of our refined petroleum product, crude oil, chemical, ethanol and other liquid terminal facilities (other than those included in the Products Pipelines segment) and all of our petroleum coke, steel and coal facilities. Our terminals are located throughout the U.S. and in portions of Canada. We believe the location of our facilities and our ability to provide flexibility to customers help attract new and retain existing customers at our terminals and provide expansion opportunities. We often classify our terminal operations based on the handling of either liquids or dry-bulk material products. In addition, Terminals’ marine operations include Jones Act qualified product tankers that provide marine transportation of crude oil, condensate and refined petroleum products between U.S. ports. The following summarizes our Terminals segment assets, as of December 31, 2017:



	Number	Capacity (MMBbl)
Liquids terminals	51	87.4
Bulk terminals	35	—
Jones Act tankers	16	5.3

Competition

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

operators with lower cost structures. Our Jones Act qualified product tankers compete with other Jones Act qualified vessel fleets.

Products Pipelines

Our Products Pipelines segment consists of our refined petroleum products, crude oil and condensate, and NGL pipelines and associated terminals, Southeast terminals, our condensate processing facility and our transmix processing facilities. The following summarizes our significant Products Pipelines segment assets we own and operate as of December 31, 2017:



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

_______


(a)	The terminals provide services including short-term product storage, truck loading, vapor handling, additive injection, dye injection and ethanol blending.


(b)	Our West Coast Products Pipelines assets include interstate common carrier pipelines rate-regulated by the FERC, intrastate pipelines in the state of California rate-regulated by the CPUC, and certain non rate-regulated operations and terminal facilities.

Competition

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

Kinder Morgan Canada

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

Trans Mountain Pipeline System

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

We also own and operate a connecting pipeline that delivers crude oil to refineries in the state of Washington referred to as the Puget Sound Pipeline System which is regulated by the FERC for tariffs and the U.S. Department of Transportation for safety and integrity.

TMEP

KML continues to move forward with its C$7.4 billion TMEP that upon completion would provide western Canadian crude oil producers with an additional 590 MBbl/d of shipping capacity and tidewater access to the western U.S. (most notably states of Washington, California and Hawaii) and global markets (most notably Asia). TMEP has firm transportation services agreements with 13 companies for a total of 707.5 MBbl/d based on a capacity of 890 MBbl/d (the maximum amount that Trans Mountain anticipated the NEB would authorize).

See “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—General—KML—TMEP Construction Progress.”

Jet Fuel Pipeline System

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

Competition

Although Trans Mountain is the only pipeline carrying crude oil and refined petroleum products from Alberta to the west coast, it is subject to competition resulting from the shipment of oil from the Western Canadian Sedimentary Basis (WCSB) to markets other than the Canadian and U.S. West Coast, including shipments to refineries in Ontario, the U.S. Midwest and the U.S. Gulf Coast. In addition, refineries in Washington State and California, which comprise an important point of sale on the U.S. West Coast, have, in the past, been supplied primarily by crude oil from the Alaska North Slope. As such, there has historically been some competitive pressure on supply originating from the WCSB for sale in the states of Washington and California refinery markets. A further source of competition exists from the transportation of oil to the Canadian West Coast by rail. We expect that such supply and demand conditions in the oil markets served from the Canadian West Coast will continue to impact the long-term value and economics of the TMPL system.

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

Major Customers

Our revenue is derived from a wide customer base. For each of the years ended December 31, 2017, 2016 and 2015, no revenues from transactions with a single external customer accounted for 10% or more of our total consolidated revenues. We do not believe that a loss of revenues from any single customer would have a material adverse effect on our business, financial position, results of operations or cash flows.

Our Texas Intrastate Natural Gas Pipeline operations (includes the operations of Kinder Morgan Tejas Pipeline LLC, Kinder Morgan Border Pipeline LLC, Kinder Morgan Texas Pipeline LLC, Kinder Morgan North Texas Pipeline LLC and the Mier-Monterrey Mexico pipeline system) buys and sells significant volumes of natural gas within the state of Texas, and, to a far lesser extent, the CO₂ business segment also sells natural gas. Combined, total revenues from the sales of natural gas from the Natural Gas Pipelines and CO₂ business segments in 2017, 2016 and 2015 accounted for 22%, 19% and 20%, respectively, of our total consolidated revenues. To the extent possible, we attempt to balance the pricing and timing of our natural gas purchases to our natural gas sales, and these contracts are often settled in terms of an index price for both purchases and sales.

Regulation

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

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

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

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

Common Carrier Pipeline Rate Regulation - Canadian Operations

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

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

Interstate Natural Gas Transportation and Storage Regulation

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

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


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


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

•

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

•

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


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

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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.

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

CPUC Rate Regulation

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

Railroad Commission of Texas (RCT) Rate Regulation

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

Mexico - Energy Regulatory Commission

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

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

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

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

Safety Regulation

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

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

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

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

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

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

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

State and Local Regulation

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

Marine Operations

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

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

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

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

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

Environmental Matters

Our business operations are subject to federal, state, provincial and local laws and regulations relating to environmental protection, pollution and human health and safety in the U.S. and Canada. For example, if an accidental leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines, or at or from our storage or other facilities, we may experience significant operational disruptions, and we may have to pay a significant amount to clean up the leak, release or spill, pay for government penalties, address natural resource damages, compensate for human exposure or property damage, install costly pollution control equipment or a combination of these and other measures. Furthermore, new projects may require approvals and environmental analysis under federal and state laws, including the National Environmental Policy Act and the Endangered Species Act. The resulting costs and liabilities could materially and negatively affect our business, financial condition, results of operations and cash flows. In addition, emission controls required under federal, state and provincial environmental laws could require significant capital expenditures at our facilities.

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

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

We believe that the ultimate resolution of these environmental matters will not have a material adverse effect on our business, financial position, results of operations or cash flows. However, it is possible that our ultimate liability with respect to these environmental matters could exceed the amounts accrued in an amount that could be material to our business, financial position, results of operations or cash flows in any particular reporting period. We have accrued an environmental reserve in the amount of $279 million as of December 31, 2017. Our aggregate reserve estimate ranges in value from approximately $279 million to approximately $443 million, and we recorded our liability equal to the low end of the range, as we did not identify any amounts within the range as a better estimate of the liability. For additional information related to environmental matters, see Note 17 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements.

Hazardous and Non-Hazardous Waste

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

Superfund

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

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

Clean Air Act

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

Clean Water Act

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

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

As required by the Clean Air Act, EPA establishes National Ambient Air Quality Standards (NAAQS) for how much pollution is permissible and then the states have to adopt rules so their air quality meets the NAAQS. In October 2015, EPA published a rule lowering the ground level ozone NAAQS from 75 ppb to a more stringent 70 ppb standard. This change triggers a process under which EPA will designate the areas of the country that are in or out of attainment with the new NAAQS standard. Then, certain states will have to adopt more stringent air quality regulations to meet the NAAQS standard. These new state rules, which are expected in 2020 or 2021, will likely require the installation of more stringent air pollution controls on newly installed equipment and possibly require retrofitting existing KMI facilities with air pollution controls. Given the nationwide implications of the new rule, it is expected that it will have financial impacts for each of our business units.

Climate Change

Studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases, may be contributing to warming of the Earth’s atmosphere. Methane, a primary component of natural gas, and CO₂, which is naturally occurring and also a byproduct of the burning of natural gas, are examples of greenhouse gases. Various laws and regulations exist or are under development that seek to regulate the emission of such greenhouse gases, including the EPA programs to control greenhouse gas emissions and state actions to develop statewide or regional programs. The U.S. Congress has in the past considered legislation to reduce emissions of greenhouse gases.

Beginning in December 2009, EPA published several findings and rulemakings under the Clean Air Act requiring the permitting and reporting of certain greenhouse gases including CO₂ and methane. Our facilities are subject to these requirements. Operational and/or regulatory changes could require additional facilities to comply with greenhouse gas emissions reporting and permitting requirements. For example, in August 2016, the EPA rule regarding the “Oil and Natural Gas Sector: Emission Standards for New and Modified Sources,” otherwise known as the Proposed New Source Performance Standard (NSPS) Part OOOOa Rule, became effective. This rule is the first federal rule under the Clean Air Act to regulate methane as a pollutant and impose additional pollution control and work practice requirements on applicable KMI facilities.

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

At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already

have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas “cap and trade” programs. Although many of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions, such as electric power plants, it is possible that sources such as our gas-fired compressors and processing plants could become subject to related state regulations. Various states are also proposing or have implemented more strict regulations for greenhouse gases that go beyond the requirements of the EPA. Depending on the particular program, we could be required to conduct monitoring, do additional emissions reporting and/or purchase and surrender emission allowances.

Because our operations, including the compressor stations and processing plants, emit various types of greenhouse gases, primarily methane and CO₂, such new legislation or regulation could increase the costs related to operating and maintaining the facilities. Depending on the particular law, regulation or program, we or our subsidiaries could be required to incur capital expenditures for installing new monitoring equipment of emission controls on the facilities, acquire and surrender allowances for the greenhouse gas emissions, pay taxes related to the greenhouse gas emissions and administer and manage a greenhouse gas emissions program. We are not able at this time to estimate such increased costs; however, as is the case with similarly situated entities in the industry, they could be significant to us. While we may be able to include some or all of such increased costs in the rates charged by our or our subsidiaries’ pipelines, such recovery of costs in all cases is uncertain and may depend on events beyond their control, including the outcome of future rate proceedings before the FERC or other regulatory bodies, and the provisions of any final legislation or other regulations. Any of the foregoing could have an adverse effect on our business, financial position, results of operations and prospects.

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

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

Department of Homeland Security

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

Other

Employees

We employed 10,897 full-time people at December 31, 2017, including approximately 801 full-time hourly personnel at certain terminals and pipelines covered by collective bargaining agreements that expire between 2018 and 2022. We consider relations with our employees to be good.

Most of our employees are employed by us and a limited number of our subsidiaries and provide services to one or more of our business units. The direct costs of compensation, benefits expenses, employer taxes and other employer expenses for these employees are allocated to our subsidiaries. Our human resources department provides the administrative support necessary to implement these payroll and benefits services, and the related administrative costs are allocated to our subsidiaries pursuant to our board-approved expense allocation policy. The effect of these arrangements is that each business unit bears the direct compensation and employee benefits costs of its assigned or partially assigned employees, as the case may be, while also bearing its allocable share of administrative costs.

Properties

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

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

(d) Financial Information about Geographic Areas

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

(e) Available Information

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

Item 1A. Risk Factors.

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

Risks Related to Operating our Business

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

Our pipelines, terminals and other assets and facilities depend in part on continued production of natural gas, oil and other products in the geographic areas that they serve. Our business also depends in part on the levels of demand for oil, natural gas, NGL, refined petroleum products, CO₂, coal, steel, chemicals and other products in the geographic areas to which our pipelines, terminals, shipping vessels and other facilities deliver or provide service, and the ability and willingness of our shippers and other customers to supply such demand. Without additions to oil and gas reserves, production will decline over time as reserves are depleted, and production costs may rise. Producers may shut down production at lower product prices or higher

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

Trends in the business environment, such as declining or sustained low commodity prices, supply disruptions, higher development costs, or high feedstock prices that adversely impact demand, could result in a slowing of supply to our pipelines, terminals and other assets. In addition, changes in the regulatory environment or governmental policies may have an impact on the supply of the products we handle. Each of these factors impacts our customers shipping through our pipelines or using our terminals, which in turn could impact the prospects of new contracts for transportation, terminaling or other midstream services, or renewals of existing contracts.

Implementation of new regulations or changes to existing regulations affecting the energy industry could reduce production of and/or demand for the products we handle, increase our costs and have a material adverse effect on our results of operations and financial condition. We cannot predict the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce the production of and/or demand for the products we handle.

Expanding our existing assets and constructing new assets is part of our growth strategy. Our ability to begin and complete construction on expansion and new-build projects may be inhibited by difficulties in obtaining, or our inability to obtain, permits and rights-of-way, as well as public opposition, cost overruns, inclement weather and other delays.

We regularly undertake major construction projects to expand our existing assets and to construct new assets. A variety of factors outside of our control, such as difficulties in obtaining permits and rights-of-way or other regulatory approvals, have caused, and may continue to cause, delays in our construction projects. These factors can be exacerbated by public opposition to our projects. Inclement weather, natural disasters and delays in performance by third-party contractors have also resulted in, and may continue to result in, increased costs or delays in construction. Significant cost overruns or delays, or our inability to obtain a required permit or right-of-way, could have a material adverse effect on our return on investment, results of operations and cash flows, and could result in project cancellations or limit our ability to pursue other growth opportunities.

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

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

Any current or future pipeline system or other form of transportation (such as barge, rail or truck) that delivers the products

we handle into the areas that our pipelines serve could offer transportation services that are more desirable to shippers than

those we provide because of price, location, facilities or other factors. Likewise, competing terminals or other storage options

may become more attractive to our customers. To the extent that competitors offer the markets we serve with new

transportation or storage options, this could result in unused capacity on our pipelines and in our terminals. If pipeline capacity

remains unsubscribed, our ability to re-contract for expiring capacity at favorable rates or otherwise retain existing customers

could be impaired. We also could experience competition for the supply of the products we handle from both existing and

proposed pipeline systems; for example, several pipelines access many of the same areas of supply as our pipeline systems and

transport to destinations not served by us.

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

Economic conditions worldwide have from time to time contributed to slowdowns in several industries, including the oil

and gas industry, the steel industry, the coal industry and in specific segments and markets in which we operate, resulting in

reduced demand and increased price competition for our products and services. Our operating results in one or more

geographic regions also may be affected by uncertain or changing economic conditions within that region. Volatility in

commodity prices or changes in markets for a given commodity might also have a negative impact on many of our customers,

which in turn could have a negative impact on their ability to meet their obligations to us. See “—Financial distress

experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.” In addition, decreases in the prices of crude oil, NGL and natural gas will have a negative impact on our operating results and cash flow. See “—The volatility of oil and natural gas prices could have a material adverse effect on our CO₂ business segment and businesses within our Natural Gas Pipeline and Products Pipelines business segments.”

If global economic and market conditions (including volatility in commodity markets), or economic conditions in the U.S.

or other key markets become more volatile or deteriorate, we may experience material impacts on our business, financial

condition and results of operations.

Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event

they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.

We are exposed to the risk of loss in the event of nonperformance by our customers or other counterparties, such as

hedging counterparties, joint venture partners and suppliers. Some of these counterparties may be highly leveraged and subject

to their own operating, market and regulatory risks, and some are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness.

In 2015 and 2016, several of our counterparties defaulted on their obligations to us, and some have filed for bankruptcy

protection. For more information regarding the impact to our operating results from customer bankruptcies, see Item 7

“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Segment Earnings Results—Terminals.” We cannot provide any assurance that other financially distressed counterparties will not also

default on their obligations to us or file for bankruptcy protection. If a counterparty files for bankruptcy protection, we likely

would be unable to collect all, or even a significant portion, of amounts that they owe to us. Additional counterparty defaults

and bankruptcy filings could have a material adverse effect on our business, financial position, results of operations or cash

flows. Furthermore, in the case of financially distressed customers, such events might force such customers to reduce or curtail

their future use of our products and services, which could have a material adverse effect on our results of operations, financial

condition, and cash flows.

The acquisition of additional businesses and assets is part of our growth strategy. We may experience difficulties

integrating new businesses and properties, and we may be unable to achieve the benefits we expect from any future

acquisitions.

Part of our business strategy includes acquiring additional businesses and assets. If we do not successfully integrate

acquisitions, we may not realize anticipated operating advantages and cost savings. Integration of acquired companies or assets

involves a number of risks, including (i) demands on management related to the increase in our size; (ii) the diversion of

management’s attention from the management of daily operations; (iii) difficulties in implementing or unanticipated costs of

accounting, budgeting, reporting, internal controls and other systems; and (iv) difficulties in the retention and assimilation of

necessary employees.

We may not be able to maintain the levels of operating efficiency that acquired companies have achieved or might achieve

separately. Successful integration of each acquisition will depend upon our ability to manage those operations and to eliminate

redundant and excess costs. Difficulties in integration may be magnified if we make multiple acquisitions over a relatively short period of time. Because of difficulties in combining and expanding operations, we may not be able to achieve the cost savings and other size-related benefits that we hoped to achieve after these acquisitions, which would harm our financial condition and results of operations.

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

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

construction projects on time, on budget, or at all, could be adversely affected. In addition, we are subject to the possibility of increased costs under our right-of-way or rental agreements with landowners, primarily through renewals of expiring agreements and rental increases. If we were to lose these rights, our operations could be disrupted or we could be required to relocate the affected pipelines, which could cause a substantial decrease in our revenues and cash flows and an increase in our costs.

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

There are a variety of hazards and operating risks inherent to transportation and storage of the products we handle, such as leaks, releases, explosions, mechanical problems and damage caused by third parties. Additional risks to vessels include adverse sea conditions, capsizing, grounding and navigation errors. These risks could result in serious injury and loss of human life, significant damage to property and natural resources, environmental pollution and impairment of operations, any of which also could result in substantial financial losses, negatively impact our reputation and increase public opposition to our expansion or new build projects. For pipeline and storage assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks may be greater. Incidents that cause an interruption of service, such as when unrelated third party construction damages a pipeline or a newly completed expansion experiences a weld failure, may negatively impact our revenues and cash flows while the affected asset is temporarily out of service. In addition, losses in excess of our insurance coverage could have a material adverse effect on our business, financial condition and results of operations.

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

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

Prices for oil, NGL and natural gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil, NGL and natural gas, uncertainties within the market and a variety of other factors beyond our control. These factors include, among other things (i) weather conditions and events such as hurricanes in the U.S.; (ii) the condition of the U.S. economy; (iii) the activities of the Organization of Petroleum Exporting Countries; (iv) governmental regulation; (v) political instability in the Middle East and elsewhere; (vi) the foreign supply of and demand for oil and natural gas; (vii) the price of foreign imports; and (viii) the availability of alternative fuel sources. We use hedging arrangements to partially mitigate our exposure to commodity prices, but these arrangements also are subject to inherent risks. Please read “—Our use of hedging arrangements does not eliminate our exposure to commodity price risks and could result in financial losses or volatility in our income.”

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

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

The future success of our oil and gas development and production operations depends in part upon our ability to develop additional oil and gas reserves that are economically recoverable.

The rate of production from oil and natural gas properties declines as reserves are depleted. Without successful development activities, the reserves, revenues and cash flows of the oil and gas producing assets within our CO₂ business segment will decline. We may not be able to develop or acquire additional reserves at an acceptable cost or have necessary financing for these activities in the future. Additionally, if we do not realize production volumes greater than, or equal to, our hedged volumes, we may suffer financial losses not offset by physical transactions.

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

The business of developing and operating oil and gas properties involves a high degree of business and financial risk that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Acquisition and development decisions generally are based on subjective judgments and assumptions that, while they may be reasonable, are by their nature speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, the successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational and market-related factors, including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions, may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable. A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of oil and/or gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances.

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

We engage in hedging arrangements to reduce our exposure to fluctuations in the prices of oil, NGL and natural gas. These hedging arrangements expose us to risk of financial loss in some circumstances, including when production is less than expected, when the counterparty to the hedging contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the hedging agreement and the actual price received. In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in prices for oil and natural gas.

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

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

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

Our business is dependent upon our operational systems to process a large amount of data and complex transactions. The

various uses of these IT systems, networks and services include, but are not limited to, controlling our pipelines and terminals

with industrial control systems, collecting and storing information and data, processing transactions, and handling other

processing necessary to manage our business.

If any of our systems are damaged, fail to function properly or otherwise become unavailable, we may incur substantial

costs to repair or replace them and may experience loss or corruption of critical data and interruptions or delays in our ability to

perform critical functions, which could adversely affect our business and results of operations. A significant failure,

compromise, breach or interruption in our systems could result in a disruption of our operations, customer dissatisfaction,

damage to our reputation and a loss of customers or revenues. Efforts by us and our vendors to develop, implement and

maintain security measures may not be successful in preventing these events from occurring, and any network and information

systems-related events could require us to expend significant resources to remedy such event. Although we believe that we have robust information security procedures and other safeguards in place, we may be required to expend additional resources to continue to enhance our information security measures and/or to investigate and remediate information security vulnerabilities.

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

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

Hurricanes, earthquakes and other natural disasters could have an adverse effect on our business, financial condition and results of operations.

Some of our pipelines, terminals and other assets are located in, and our shipping vessels operate in, areas that are susceptible to hurricanes, earthquakes and other natural disasters. These natural disasters could potentially damage or destroy our assets and disrupt the supply of the products we transport. In the third quarter of 2017, Hurricane Harvey caused

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

Our business requires the retention and recruitment of a skilled workforce, and difficulties recruiting and retaining our workforce could result in a failure to implement our business plans.

Our operations and management require the retention and recruitment of a skilled workforce, including engineers, technical personnel and other professionals. We and our affiliates compete with other companies in the energy industry for this skilled workforce. In addition, many of our current employees are retirement eligible and have significant institutional knowledge that must be transferred to other employees. If we are unable to (i) retain current employees; (ii) successfully complete the knowledge transfer; and/or (iii) recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased allocated costs to retain and recruit these professionals.

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

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

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

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

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

We are a U.S. dollar reporting company. As a result of the operations of our Kinder Morgan Canada and Terminals

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

Risks Related to Financing Our Business

Our substantial debt could adversely affect our financial health and make us more vulnerable to adverse economic conditions.

As of December 31, 2017, we had approximately $36.9 billion of consolidated debt (excluding debt fair value adjustments). Additionally, we and substantially all of our wholly owned U.S. subsidiaries are parties to a cross guarantee agreement under which each party to the agreement unconditionally guarantees the indebtedness of each other party, which means that we are liable for the debt of each of such subsidiaries. This level of consolidated debt and the cross guarantee agreement could have important consequences, such as (i) limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements or potential growth, or for other purposes; (ii) increasing the cost of our future borrowings; (iii) limiting our ability to use operating cash flow in other areas of our business or to pay dividends because we must dedicate a substantial portion of these funds to make payments on our debt; (iv) placing us at a competitive disadvantage compared to competitors with less debt; and (v) increasing our vulnerability to adverse economic and industry conditions.

Our ability to service our consolidated debt, and our ability to meet our consolidated leverage targets, will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond our control. If our consolidated cash flow is not sufficient to service our consolidated debt, and any future indebtedness that we incur, we will be forced to take actions such as reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may also take such actions to reduce our indebtedness if we determine that our earnings (or consolidated earnings before interest, taxes, depreciation and amortization, or EBITDA, as calculated in accordance with our revolving credit facility) may not be sufficient to meet our consolidated leverage targets, or to comply with consolidated leverage ratios required under certain of our debt agreements. We may not be able to effect any of these actions on satisfactory terms or at all. For more information about our debt, see Note 9 “Debt” to our consolidated financial statements.

Our business, financial condition and operating results may be affected adversely by increased costs of capital or a reduction in the availability of credit.

Adverse changes to the availability, terms and cost of capital, interest rates or our credit ratings (which would have a corresponding impact on the credit ratings of our subsidiaries that are party to the cross guarantee) could cause our cost of doing business to increase by limiting our access to capital, including our ability to refinance maturities of existing indebtedness on similar terms, which could in turn limit our ability to pursue acquisition or expansion opportunities and reduce our cash flows. Our credit ratings may be impacted by our leverage, liquidity, credit profile and potential transactions. Although the ratings from credit agencies are not recommendations to buy, sell or hold our securities, our credit ratings will generally affect the market value of our and our subsidiaries’ debt securities and the terms available to us for future issuances of debt securities.

Also, disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations on favorable terms. A significant reduction in the availability of credit could materially and adversely affect our business, financial condition and results of operations.

KML and its subsidiaries are not part of the cross guarantee and are rated separately by credit rating agencies. However, because of our approximate 70% ownership interest in KML, we could be indirectly affected if KML experiences material adverse changes in its credit ratings or access to capital.

Acquisitions and growth capital expenditures may require access to external capital. Limitations on our access to external financing sources could impair our ability to grow.

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

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

As of December 31, 2017, approximately $10.4 billion of our approximately $36.9 billion of consolidated debt (excluding debt fair value adjustments) was subject to variable interest rates, either as short-term or long-term variable-rate debt obligations, or as long-term fixed-rate debt effectively converted to variable rates through the use of interest rate swaps. Should interest rates increase, the amount of cash required to service this debt would increase, and our earnings and cash flows could be adversely affected. For more information about our interest rate risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk-Interest Rate Risk.”

Our debt instruments may limit our financial flexibility and increase our financing costs.

The instruments governing our debt contain restrictive covenants that may prevent us from engaging in certain transactions that may be beneficial to us. Some of the agreements governing our debt generally require us to comply with various affirmative and negative covenants, including the maintenance of certain financial ratios and restrictions on (i) incurring additional debt; (ii) entering into mergers, consolidations and sales of assets; (iii) granting liens; and (iv) entering into sale-leaseback transactions. The instruments governing any future debt may contain similar or more limiting restrictions. Our ability to respond to changes in business and economic conditions and to obtain additional financing, if needed, may be restricted.

Risks Related to Ownership of Our Capital Stock

The guidance we provide for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.

We disclose in this report and elsewhere the expected cash dividends on our common stock and on our preferred stock (or depositary shares). These reflect our current judgment, but as with any estimate, they may be affected by inaccurate assumptions and other risks and uncertainties, many of which are beyond our control. See “Information Regarding Forward-Looking Statements” at the beginning of this report. If we elect to pay dividends at the anticipated level and that action would leave us with insufficient cash to take timely advantage of growth opportunities (including through acquisitions), to meet any large unanticipated liquidity requirements, to fund our operations, to maintain our leverage metrics or otherwise to address properly our business prospects, our business could be harmed.

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

Our certificate of incorporation restricts the ownership of our common stock by non-U.S. citizens within the meaning of the Jones Act. These restrictions may affect the liquidity of our common stock and may result in non-U.S. citizens being required to sell their shares at a loss.

The Jones Act requires, among other things, that at least 75% of our common stock be owned at all times by U.S. citizens, as defined under the Jones Act, in order for us to own and operate vessels in the U.S. coastwise trade. As a safeguard to help us maintain our status as a U.S. citizen, our certificate of incorporation provides that, if the number of shares of our common stock owned by non-U.S. citizens exceeds 22%, we have the ability to redeem shares owned by non-U.S. citizens to reduce the percentage of shares owned by non-U.S. citizens to 22%. These redemption provisions may adversely impact the marketability of our common stock, particularly in markets outside of the U.S. Further, stockholders would not have control over the timing of such redemption, and may be subject to redemption at a time when the market price or timing of the redemption is disadvantageous. In addition, the redemption provisions might have the effect of impeding or discouraging a merger, tender offer or proxy contest by a non-U.S. citizen, even if it were favorable to the interests of some or all of our stockholders.

Risks Related to Regulation

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

Our assets and operations are subject to regulation and oversight by federal, state, provincial and local regulatory authorities. Legislative changes, as well as regulatory actions taken by these agencies, have the potential to adversely affect our profitability. In addition, a certain degree of regulatory uncertainty is created by the current U.S. presidential administration because it remains unclear specifically what the current administration may do with respect to future policies and regulations that may affect us. Regulation affects almost every part of our business and extends to such matters as (i) federal, state, provincial and local taxation; (ii) rates (which include tax, reservation, commodity, surcharges, fuel and gas lost and unaccounted for), operating terms and conditions of service; (iii) the types of services we may offer to our customers; (iv) the contracts for service entered into with our customers; (v) the certification and construction of new facilities; (vi) the integrity, safety and security of facilities and operations; (vii) the acquisition of other businesses; (viii) the acquisition, extension, disposition or abandonment of services or facilities; (ix) reporting and information posting requirements; (x) the maintenance of accounts and records; and (xi) relationships with affiliated companies involved in various aspects of the energy businesses.

Should we fail to comply with any applicable statutes, rules, regulations, and orders of regulatory authorities, we could be subject to substantial penalties and fines and potential loss of government contracts. Furthermore, new laws, regulations or policy changes sometimes arise from unexpected sources. New laws or regulations, unexpected policy changes or interpretations of existing laws or regulations, including the 2017 Tax Reform, applicable to our income, operations, assets or another aspect of our business, could have a material adverse impact on our earnings, cash flow, financial condition and results of operations. For more information, see Items 1 and 2 “Business and Properties—(c) Narrative Description of Business—Regulation.”

The FERC, the CPUC, or the NEB may establish pipeline tariff rates that have a negative impact on us. In addition, the FERC, the CPUC, the NEB, or our customers could initiate proceedings or file complaints challenging the tariff rates charged by our pipelines, which could have an adverse impact on us.

The profitability of our regulated pipelines is influenced by fluctuations in costs and our ability to recover any increases in our costs in the rates charged to our shippers. To the extent that our costs increase in an amount greater than what we are permitted by the FERC, the CPUC, or the NEB to recover in our rates, or to the extent that there is a lag before we can file for and obtain rate increases, such events can have a negative impact on our operating results.

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

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

Our operations are subject to federal, state, provincial and local laws, regulations and potential liabilities arising under or relating to the protection or preservation of the environment, natural resources and human health and safety. Such laws and regulations affect many aspects of our present and future operations, and generally require us to obtain and comply with various environmental registrations, licenses, permits, inspections and other approvals. Liability under such laws and regulations may be incurred without regard to fault under CERCLA, the Resource Conservation and Recovery Act, the Federal Clean Water Act, the Oil Pollution Act or analogous state or provincial laws as a result of the presence or release of hydrocarbons and other hazardous substances into or through the environment, and these laws may require response actions and remediation and may impose liability for natural resource and other damages. Private parties, including the owners of properties through which our pipelines pass, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with such laws and regulations or for personal injury or property damage. Our insurance may not cover all environmental risks and costs and/or may not provide sufficient coverage in the event an environmental claim is made against us.

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

We own and/or operate numerous properties that have been used for many years in connection with our business activities. While we believe we have utilized operating, handling, and disposal practices that were consistent with industry practices at the time, hydrocarbons or other hazardous substances may have been released at or from properties owned, operated or used by us or our predecessors, or at or from properties where our or our predecessors’ wastes have been taken for disposal. In addition, many of these properties have been owned and/or operated by third parties whose management, handling and disposal of hydrocarbons or other hazardous substances were not under our control. These properties and the hazardous substances released and wastes disposed on them may be subject to laws in the U.S. such as CERCLA, which impose joint and several liability without regard to fault or the legality of the original conduct. Under the regulatory schemes of the various Canadian provinces, such as British Columbia’s Environmental Management Act, Canada has similar laws with respect to properties owned, operated or used by us or our predecessors. Under such laws and implementing regulations, we could be required to remove or remediate previously disposed wastes or property contamination, including contamination caused by prior owners or operators. Imposition of such liability schemes could have a material adverse impact on our operations and financial position.

Further, we cannot ensure that such existing laws and regulations will not be revised or that new laws or regulations will not be adopted or become applicable to us. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects. For more information, see Items 1 and 2 “Business and Properties-(c) Narrative Description of Business—Environmental Matters.”

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

We are subject to extensive laws and regulations related to pipeline integrity. There are, for example, federal guidelines issued by the DOT for pipeline companies in the areas of testing, education, training and communication. The ultimate costs of compliance with the integrity management rules are difficult to predict. The majority of compliance costs relate to pipeline integrity testing and repairs. Technological advances in in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipeline determined to be located in “High Consequence Areas” can have a significant impact on integrity testing and repair costs. We plan to continue our integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by the DOT rules. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

Further, additional laws and regulations that may be enacted in the future or a new interpretation of existing laws and regulations could significantly increase the amount of these expenditures. There can be no assurance as to the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not deemed by regulators to be fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects.

Climate change and related regulation could result in significantly increased operating and capital costs for us and could reduce demand for our products and services.

Various laws and regulations exist or are under development that seek to regulate the emission of greenhouse gases such as methane and CO₂, including the EPA programs to control greenhouse gas emissions and state actions to develop statewide or regional programs. Existing EPA regulations require us to report greenhouse gas emissions in the U.S. from sources such as our larger natural gas compressor stations, fractionated NGL, and production of naturally occurring CO₂ (for example, from our McElmo Dome CO₂ field), even when such production is not emitted to the atmosphere. Proposed approaches to further regulate greenhouse gas emissions include establishing greenhouse gas “cap and trade” programs, increased efficiency standards, and incentives or mandates for pollution reduction, use of renewable energy sources, or use of alternative fuels with lower carbon content. For more information about climate change regulation, see Items 1 and 2 “Business and Properties—(c) Narrative Description of Business-Environmental Matters—Climate Change.”

Adoption of any such laws or regulations could increase our costs to operate and maintain our facilities and could require us to install new emission controls on our facilities, acquire allowances for our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program, and such increased costs could be significant. Recovery of such increased costs from our customers is uncertain in all cases and may depend on events beyond our control, including the outcome of future rate proceedings before the FERC. Such laws or regulations could also lead to reduced demand for hydrocarbon products that are deemed to contribute to greenhouse gases, or restrictions on their use, which in turn could adversely affect demand for our products and services.

Finally, some climatic models indicate that global warming is likely to result in rising sea levels and increased frequency and severity of weather events, which may lead to higher insurance costs, or a decrease in available coverage, for our assets in areas subject to severe weather. To the extent these phenomena occur, they could damage our physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone regions.

Any of the foregoing could have adverse effects on our business, financial position, results of operations or cash flows.

Increased regulation of exploration and production activities, including hydraulic fracturing, could result in reductions or delays in drilling and completing new oil and natural gas wells, as well as reductions in production from existing wells, which could adversely impact the volumes of natural gas transported on our natural gas pipelines and our own oil and gas development and production activities.

We gather, process or transport crude oil, natural gas or NGL from several areas in which the use of hydraulic fracturing is prevalent. Oil and gas development and production activities are subject to numerous federal, state, provincial and local laws and regulations relating to environmental quality and pollution control. The oil and gas industry is increasingly relying on supplies of hydrocarbons from unconventional sources, such as shale, tight sands and coal bed methane. The extraction of hydrocarbons from these sources frequently requires hydraulic fracturing. Hydraulic fracturing involves the pressurized injection of water, sand, and chemicals into the geologic formation to stimulate gas production and is a commonly used stimulation process employed by oil and gas exploration and production operators in the completion of certain oil and gas wells. There have been initiatives at the federal and state levels to regulate or otherwise restrict the use of hydraulic fracturing. Adoption of legislation or regulations placing restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on exploration and production operators, which could reduce their production of crude oil, natural gas or NGL and, in turn, adversely affect our revenues, cash flows and results of operations by decreasing the volumes of these commodities that we handle.

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

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

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

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

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

The Jones Act includes restrictions on ownership by non-U.S. citizens of our U.S. point to point maritime shipping vessels, and failure to comply with the Jones Act, or changes to or a repeal of the Jones Act, could limit our ability to operate our vessels in the U.S. coastwise trade, result in the forfeiture of our vessels or otherwise adversely impact our earnings, cash flows and operations.

We are subject to the Jones Act, which generally restricts U.S. point-to-point maritime shipping to vessels operating under the U.S. flag, built in the U.S., owned and operated by U.S.-organized companies that are controlled and at least 75% owned by U.S. citizens and manned by predominately U.S. crews. Our business would be adversely affected if we fail to comply with the Jones Act provisions on coastwise trade. If we do not comply with any of these requirements, we would be prohibited from operating our vessels in the U.S. coastwise trade and, under certain circumstances, we could be deemed to have undertaken an unapproved transfer to non-U.S. citizens that could result in severe penalties, including permanent loss of U.S. coastwise trading rights for our vessels, fines or forfeiture of vessels. Our business could be adversely affected if the Jones Act were to be modified or repealed so as to permit foreign competition that is not subject to the same U.S. government imposed burdens.

Item 1B. Unresolved Staff Comments.

None.

Item 3. Legal Proceedings.

See Note 17 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements.

Item 4. Mine Safety Disclosures.

We no longer own or operate mines for which reporting requirements apply under the mine safety disclosure requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank), except for one terminal that is in temporary idle status with the Mine Safety and Health Administration. We have not received any specified health and safety violations, orders or citations, related assessments or legal actions, mining-related fatalities, or similar events requiring disclosure pursuant to the mine safety disclosure requirements of Dodd-Frank for the year ended December 31, 2017.

PART II

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

Our Class P common stock is listed for trading on the NYSE under the symbol “KMI.” The high and low sale prices per Class P share as reported on the NYSE and the dividends declared per share by period for 2017, 2016 and 2015, are provided below.



	Price Range				Declared Cash Dividends(a)
	Low		High		Declared Cash Dividends(a)
2017
First Quarter	$	20.71	$	23.01	$	0.125
Second Quarter	18.31		21.92		0.125
Third Quarter	18.23		21.25		0.125
Fourth Quarter	16.68		19.17		0.125
2016
First Quarter	$	11.20	$	19.32	$	0.125
Second Quarter	16.63		19.40		0.125
Third Quarter	17.95		23.20		0.125
Fourth Quarter	19.43		23.36		0.125
2015
First Quarter	$	39.45	$	42.93	$	0.48
Second Quarter	38.33		44.71		0.49
Third Quarter	25.81		38.58		0.51
Fourth Quarter	14.22		32.89		0.125

_______


(a)	Dividend information is for dividends declared with respect to that quarter. Generally, our declared dividends for our Class P common stock are paid on or about the 15th day of each February, May, August and November.

As of February 8, 2018, we had 11,867 holders of our Class P common stock, which does not include beneficial owners whose shares are held by a nominee, such as a broker or bank.

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

The warrant repurchase program, dated June 12, 2015, which authorized us to repurchase up to $100 million of warrants, expired along with the warrants on May 25, 2017.

Our Purchases of Our Class P Shares

Period	Total number of securities purchased(a)	Average price paid per security		Total number of securities purchased as part of publicly announced plans(a)	Maximum number (or approximate dollar value) of securities that may yet be purchased under the plans or programs
December 1 to December 31, 2017	14,038,121	$	17.80	14,038,121	$	1,750,009,426

					$	1,750,009,426

_______


(a)	On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. After repurchase, the shares are cancelled and no longer outstanding.

Item 6. Selected Financial Data.

The following table sets forth, for the periods and at the dates indicated, our summary historical financial data. The table is derived from our consolidated financial statements and notes thereto, and should be read in conjunction with those audited financial statements. See also Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this report for more information.

Five-Year Review Kinder Morgan, Inc. and Subsidiaries

	As of or for the Year Ended December 31,
	2017		2016		2015		2014		2013
	(In millions, except per share amounts)
Income and Cash Flow Data:
Revenues	$	13,705	$	13,058	$	14,403	$	16,226	$	14,070
Operating income	3,544		3,572		2,447		4,448		3,990
Earnings from equity investments	578		497		414		406		327
Income from continuing operations	223		721		208		2,443		2,696
Loss from discontinued operations, net of tax	—		—		—		—		(4		)
Net income	223		721		208		2,443		2,692
Net income attributable to Kinder Morgan, Inc.	183		708		253		1,026		1,193
Net income available to common stockholders	27		552		227		1,026		1,193
Class P Shares
Basic and Diluted Earnings Per Common Share From Continuing Operations	$	0.01	$	0.25	$	0.10	$	0.89	$	1.15
Basic Weighted Average Common Shares Outstanding	2,230		2,230		2,187		1,137		1,036
Diluted Weighted Average Common Shares Outstanding	2,230		2,230		2,193		1,137		1,036

Dividends per common share declared for the period(a)	$	0.50	$	0.50	$	1.605	$	1.74	$	1.60
Dividends per common share paid in the period(a)	0.50		0.50		1.93		1.70		1.56

Balance Sheet Data (at end of period):
Property, plant and equipment, net	$	40,155	$	38,705	$	40,547	$	38,564	$	35,847
Total assets	79,055		80,305		84,104		83,049		75,071
Long-term debt(b)	34,088		36,205		40,732		38,312		31,910

_______


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


(b)	Excludes debt fair value adjustments. Increases to long-term debt for debt fair value adjustments totaled $927 million, $1,149 million, $1,674 million, $1,785 million and $1,863 million as of December 31, 2017, 2016, 2015, 2014 and 2013, respectively.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto. We prepared our consolidated financial statements in accordance with GAAP. Additional sections in this report which should be helpful to the reading of our discussion and analysis include the following: (i) a description of our business strategy found in Items 1 and 2 “Business and Properties—(c) Narrative Description of Business—Business Strategy;” (ii) a description of developments during 2017, found in Items 1 and 2 “Business and Properties—(a) General Development of Business—Recent Developments;” and (iii) a description of risk factors affecting us and our business, found in Item 1A “Risk Factors.”

Inasmuch as the discussion below and the other sections to which we have referred you pertain to management’s comments on financial resources, capital spending, our business strategy and the outlook for our business, such discussions contain forward-looking statements. These forward-looking statements reflect the expectations, beliefs, plans and objectives of management about future financial performance and assumptions underlying management’s judgment concerning the matters discussed, and accordingly, involve estimates, assumptions, judgments and uncertainties. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to any differences include, but are not limited to, those discussed below and elsewhere in this report, particularly in Item 1A “Risk Factors” and at the beginning of this report in “Information Regarding Forward-Looking Statements.”

General

Our business model, through our ownership and operation of energy related assets, is built to support two principal objectives:


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


•	creating long-term value for our shareholders.

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

Our reportable business segments are:


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


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


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


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


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

As an energy infrastructure owner and operator in multiple facets of the various U.S. and Canadian energy industries and markets, we examine a number of variables and factors on a routine basis to evaluate our current performance and our prospects for the future.

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

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

The CO₂ source and transportation business primarily has third-party contracts with minimum volume requirements, which as of December 31, 2017, had a remaining average contract life of approximately eight years. CO₂ sales contracts vary from customer to customer and have evolved over time as supply and demand conditions have changed. Our recent contracts have generally provided for a delivered price tied to the price of crude oil, but with a floor price. On a volume-weighted basis, for third-party contracts making deliveries in 2018, and utilizing the average oil price per barrel contained in our 2018 budget, approximately 97% of our revenue is based on a fixed fee or floor price, and 3% fluctuates with the price of oil. In the long-term, our success in this portion of the CO₂ business segment is driven by the demand for CO₂. However, short-term changes in the demand for CO₂ typically do not have a significant impact on us due to the required minimum sales volumes under many of our contracts. In the CO₂ business segment’s oil and gas producing activities, we monitor the amount of capital we expend in relation to the amount of production that we expect to add. In that regard, our production during any period is an important measure. In addition, the revenues we receive from our crude oil, NGL and CO₂ sales are affected by the prices we realize from the sale of these products. Over the long-term, we will tend to receive prices that are dictated by the demand and overall market price for these products. In the shorter term, however, market prices are likely not indicative of the revenues we will receive due to our risk management, or hedging, program, in which the prices to be realized for certain of our future sales quantities are fixed, capped or bracketed through the use of financial derivative contracts, particularly for crude oil. The realized weighted average crude oil price per barrel, with the hedges allocated to oil, was $58.40 per barrel in 2017, $61.52 per barrel in 2016 and $73.11 per barrel in 2015. Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $49.61 per barrel in 2017, $41.36 per barrel in 2016 and $47.56 per barrel in 2015.

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

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

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

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

KML

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

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

TMEP Permitting and Construction Progress

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

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

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

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

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

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

2017 Tax Reform

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

Critical Accounting Policies and Estimates

Accounting standards require information in financial statements about the risks and uncertainties inherent in significant estimates, and the application of GAAP involves the exercise of varying degrees of judgment. Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for our assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements. We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates, and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

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

For a summary of our significant accounting policies, see Note 2 “Summary of Significant Accounting Policies” to our consolidated financial statements. We believe that certain accounting policies are of more significance in our consolidated financial statement preparation process than others, which policies are discussed as follows.

Acquisition Method of Accounting

For acquired businesses, we generally recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition. Determining the fair value of these items requires management’s judgment, the utilization of independent valuation experts and involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The judgments made in the determination of the estimated fair value assigned to the assets acquired, the liabilities assumed and any noncontrolling interest in the investee, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. For more information on our acquisitions and application of the acquisition method, see Note 3 “Acquisitions and Divestitures” to our consolidated financial statements.

Environmental Matters

With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. We expense or capitalize, as appropriate, environmental expenditures that relate to current operations, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, we do not discount environmental liabilities to a net present value, and we recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We record at fair value, where appropriate, environmental liabilities assumed in a business combination.

Our recording of our environmental accruals often coincides with our completion of a feasibility study or our commitment to a formal plan of action, but generally, we recognize and/or adjust our environmental liabilities following routine reviews of potential environmental issues and claims that could impact our assets or operations. These adjustments may result in increases in environmental expenses and are primarily related to quarterly reviews of potential environmental issues and resulting environmental liability estimates. In making these liability estimations, we consider the effect of environmental compliance, pending legal actions against us, and potential third party liability claims. For more information on environmental matters, see PART I, Items 1 and 2 “Business and Properties—(c) Narrative Description of Business—Environmental Matters.” For more information on our environmental disclosures, see Note 17 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements.

Legal and Regulatory Matters

Many of our operations are regulated by various U.S. and Canadian regulatory bodies and we are subject to legal and regulatory matters as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. In general, we expense legal costs as incurred. When we identify contingent liabilities, we identify a range of possible costs expected to be required to resolve the matter. Generally, if no amount within this range is a better estimate than any other amount, we record a liability equal to the low end of the range. Any such liability recorded is revised as better information becomes available. Accordingly, to the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. For more information on legal proceedings, see Note 17 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements.

Intangible Assets

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

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

Hedging Activities

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

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

Employee Benefit Plans

We reflect an asset or liability for our pension and other postretirement benefit plans based on their overfunded or underfunded status. As of December 31, 2017, our pension plans were underfunded by $686 million and our other postretirement benefits plans were underfunded by $90 million. Our pension and other postretirement benefit obligations and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the rate at which we expect the compensation of our employees to increase over the plan term, the estimated cost of health care when benefits are provided under our plan and other factors. A significant assumption we utilize is the discount rate used in calculating our benefit obligations. We utilize a full yield curve approach in the estimation of the service and interest cost components of net periodic benefit cost (credit) for our pension and other postretirement benefit plans which applies the specific spot rates along the yield curve used in the determination of the benefit obligation to their underlying projected cash flows. The selection of these assumptions is further discussed in Note 10 “Share-based Compensation and Employee Benefits” to our consolidated financial statements.

Actual results may differ from the assumptions included in these calculations, and as a result, our estimates associated with our pension and other postretirement benefits can be, and often are, revised in the future. The income statement impact of the changes in the assumptions on our related benefit obligations are deferred and amortized into income over either the period of expected future service of active participants, or over the expected future lives of inactive plan participants. As of December 31, 2017, we had deferred net losses of approximately $547 million in pretax accumulated other comprehensive loss and noncontrolling interests related to our pension and other postretirement benefits.

The following table shows the impact of a 1% change in the primary assumptions used in our actuarial calculations associated with our pension and other postretirement benefits for the year ended December 31, 2017:



	Pension Benefits						Other Postretirement Benefits
	Net benefit cost (income)			Change in funded status(a)			Net benefit cost (income)			Change in funded status(a)
	(In millions)
One percent increase in:
Discount rates	$	(13	)	$	252		$	(1	)	$	33
Expected return on plan assets	(21		)	—			(3		)	—
Rate of compensation increase	4			(13		)	—			—
Health care cost trends	—			—			3			(24		)

One percent decrease in:
Discount rates	15			(299		)	1			(38		)
Expected return on plan assets	21			—			3			—
Rate of compensation increase	(3		)	13			—			—
Health care cost trends	—			—			(3		)	21

_______


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

Income Taxes

Income tax expense is recorded based on an estimate of the effective tax rate in effect or to be in effect during the relevant periods. Changes in tax legislation are included in the relevant computations in the period in which such changes are enacted. We do business in a number of states with differing laws concerning how income subject to each state’s tax structure is measured and at what effective rate such income is taxed. Therefore, we must make estimates of how our income will be apportioned among the various states in order to arrive at an overall effective tax rate. Changes in our effective rate, including any effect on previously recorded deferred taxes, are recorded in the period in which the need for such change is identified.

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

In determining the deferred income tax asset and liability balances attributable to our investments, we apply an accounting policy that looks through our investments. The application of this policy resulted in no deferred income taxes being provided on the difference between the book and tax basis on the non-tax-deductible goodwill portion of our investments.

Results of Operations

Overview

Our management evaluates our performance primarily using the measures of Segment EBDA and, as discussed below under “—Non-GAAP Measures,” DCF, and Segment EBDA before certain items. Segment EBDA is a useful measure of our operating performance because it measures the operating results of our segments before DD&A and certain expenses that are generally not controllable by our business segment operating managers, such as general and administrative expenses, interest expense, net, and income taxes. Our general and administrative expenses include such items as employee benefits, insurance, rentals, unallocated litigation and environmental expenses, and shared corporate services including accounting, information technology, human resources and legal services.

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

Consolidated Earnings Results



	Year Ended December 31,
	2017			2016			2015
	(In millions)
Segment EBDA(a)
Natural Gas Pipelines	$	3,487		$	3,211		$	3,067
CO₂	847			827			658
Terminals	1,224			1,078			878
Products Pipelines	1,231			1,067			1,106
Kinder Morgan Canada	186			181			182
Total segment EBDA(b)	6,975			6,364			5,891
DD&A	(2,261		)	(2,209		)	(2,309		)
Amortization of excess cost of equity investments	(61		)	(59		)	(51		)
General and administrative and corporate charges(c)	(660		)	(652		)	(708		)
Interest, net(d)	(1,832		)	(1,806		)	(2,051		)
Income before income taxes	2,161			1,638			772
Income tax expense(e)	(1,938		)	(917		)	(564		)
Net income	223			721			208
Net (income) loss attributable to noncontrolling interests	(40		)	(13		)	45
Net income attributable to Kinder Morgan, Inc.	183			708			253
Preferred Stock Dividends	(156		)	(156		)	(26		)
Net Income Available to Common Stockholders	$	27		$	552		$	227

_______


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

Certain items affecting Total Segment EBDA (see “—Non-GAAP Measures” below)


(b)	2017, 2016 and 2015 amounts include decreases in earnings of $384 million, $1,121 million and $1,748 million, respectively, related to the combined net effect of the certain items impacting Total Segment EBDA. The extent to which these items affect each of our business segments is discussed below in the footnotes to the tables within “—Segment Earnings Results.”

(c)

2017, 2016 and 2015 amounts include an increase to expense of $15 million, a decrease to expense of $13 million and an increase to expense of $60 million, respectively, related to the combined net effect of the certain items related to general and administrative and corporate charges disclosed below in “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests.”


(d)	2017, 2016 and 2015 amounts include decreases in expense of $39 million, $193 million and $27 million, respectively, related to the combined net effect of the certain items related to interest expense, net disclosed below in “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests.”


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

Year Ended December 31, 2017 vs. 2016

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

Year Ended December 31, 2016 vs. 2015

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

Non-GAAP Financial Measures

Our non-GAAP performance measures are DCF, both in the aggregate and per share, and Segment EBDA before certain items. Certain items, as used to calculate our non-GAAP measures, are items that are required by GAAP to be reflected in net income, but typically either (i) do not have a cash impact (for example, asset impairments), or (ii) by their nature are separately identifiable from our normal business operations and in our view are likely to occur only sporadically (for example certain legal settlements, enactment of new tax legislation and casualty losses).

Our non-GAAP performance measures described below should not be considered alternatives to GAAP net income or other GAAP measures and have important limitations as analytical tools. Our computations of DCF and Segment EBDA before certain items may differ from similarly titled measures used by others. You should not consider these non-GAAP performance measures in isolation or as substitutes for an analysis of our results as reported under GAAP. DCF should not be used as an alternative to net cash provided by operating activities computed under GAAP. Management compensates for the limitations of these non-GAAP performance measures by reviewing our comparable GAAP measures, understanding the differences between the measures and taking this information into account in its analysis and its decision making processes.

DCF

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

Segment EBDA Before Certain Items

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

therefore, are not included when we measure business segment operating performance. We believe Segment EBDA before certain items is a significant performance metric because it provides us and external users of our financial statements additional insight into the ability of our segments to generate segment cash earnings on an ongoing basis. We believe it is useful to investors because it is a performance measure that management uses to allocate resources to our segments and assess each segment’s performance. We believe the GAAP measure most directly comparable to Segment EBDA before certain items is segment earnings before DD&A and amortization of excess cost of equity investments (Segment EBDA).

In the tables for each of our business segments under “— Segment Earnings Results” below, Segment EBDA before certain items is calculated by adjusting the Segment EBDA for the applicable certain item amounts, which are totaled in the tables and described in the footnotes to those tables.

Reconciliation of Net Income Available to Common Stockholders to DCF



	Year Ended December 31,
	2017		2016		2015
	(In millions)
Net Income Available to Common Stockholders	$	27	$	552	$	227
Add/(Subtract):
Certain items before book tax(a)	141		915		1,781