Item 15. Exhibits, Financial Statement Schedules.

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Item 15. Exhibits, Financial Statement Schedules.

(a)(1) Financial Statements and (2) Financial Statement Schedules
See “Index to Financial Statements” set forth on Page 73.
(3)Exhibits
Exhibit Number Description
2.1*Agreement and Plan of Merger, dated as of August 9, 2014, by and among Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Management, LLC, Kinder Morgan, Inc. (KMI) and P Merger Sub LLC (schedules omitted pursuant to Item 601(b)(2) of Regulation S-K) (filed as Exhibit 2.1 to KMI’s Current Report on Form 8-K, filed August 12, 2014 (File No. 001-35081))
2.2*Agreement and Plan of Merger, dated as of August 9, 2014, by and among Kinder Morgan Management, LLC, KMI, and R Merger Sub LLC (schedules omitted pursuant to Item 601(b)(2) of Regulation S-K) (filed as Exhibit 2.2 to KMI’s Current Report on Form 8-K, filed August 12, 2014 (File No. 001-35081))
2.3*Agreement and Plan of Merger, dated as of August 9, 2014, by and among El Paso Pipeline Partners, L.P., El Paso Pipeline GP Company, L.L.C., KMI, and E Merger Sub LLC (schedules omitted pursuant to Item 601(b)(2) of Regulation S-K) (filed as Exhibit 2.3 to KMI’s Current Report on Form 8-K, filed August 12, 2014 (File No. 001-35081))
3.1*Amended and Restated Certificate of Incorporation of KMI (filed as Exhibit 3.1 to KMI’s Quarterly Report on Form 10-Q for the three months ended June 30, 2015 (File No. 001-35081))
3.2*Amended and Restated Bylaws of KMI (filed as Exhibit 3.1 to KMI’s Current Report on Form 8-K, filed January 24, 2017 (File No. 001-35081))
3.3*Certificate of Designations of KMI 9.75% Series A Mandatory Convertible Preferred Stock, par value $0.01 per share (KMI Preferred Stock) (filed as Exhibit 3.1 to KMI’s Current Report on Form 8-K filed October 30, 2015 (File No. 001-35081))
Exhibit Number Description
4.1*Form of certificate representing Class P common shares of KMI (filed as Exhibit 4.1 to KMI’s Registration Statement on Form S-1 filed on January 18, 2011 (File No. 333-170773))
4.2*Shareholders Agreement among KMI and certain holders of common stock (filed as Exhibit 4.2 to KMI’s Quarterly Report on Form 10-Q for the three Months ended March 31, 2011 (File No. 001-35081))
4.3*Amendment No. 1 to the Shareholders Agreement among KMI and certain holders of common stock (filed as Exhibit 4.3 to KMI’s Current Report on Form 8-K filed on May 30, 2012 (File No. 001-35081))
4.4*Amendment No. 2 to the Shareholders Agreement among KMI and certain holders of common stock (filed as Exhibit 4.1 to KMI’s Current Report on Form 8-K filed on December 3, 2014 (File No. 001-35081))
4.5*Warrant Agreement, dated as of May 25, 2012, among KMI, Computershare Trust Company, N.A. and Computershare Inc., as Warrant Agent (filed as Exhibit 4.1 to KMI’s Current Report on Form 8-K filed on May 30, 2012 (File No. 001-35081))
4.6*Form of certificate for KMI Preferred Stock (included as Exhibit A to Exhibit 3.1 to KMI’s Current Report on Form 8-K filed October 30, 2015 (File No. 001-35081))
4.7*Deposit Agreement, dated as of October 30, 2015, between KMI and Computershare Inc. and Computershare Trust Company, N.A., as joint depositary, on behalf of all holders from time to time of the depositary receipts issued thereunder (filed as Exhibit 4.2 to KMI’s Current Report on Form 8-K filed October 30, 2015 (File No. 001-35081))
4.8*Form of Depositary Receipt for depositary shares, each representing 1/20th of a share of KMI Preferred Stock (included as Exhibit A to Exhibit 4.2 to KMI’s Current Report on Form 8-K filed October 30, 2015 (File No. 001-35081))
4.9*Form of Senior Indenture between Kinder Morgan Kansas, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Kinder Morgan Kansas, Inc.’s Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102963))
4.10*Form of Senior Note of Kinder Morgan Kansas, Inc. (included in the Form of Senior Indenture filed as Exhibit 4.2 to Kinder Morgan Kansas, Inc.’s Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102963))
4.11*Indenture dated as of December 9, 2005, among Kinder Morgan Finance Company LLC (formerly Kinder Morgan Finance Company, ULC), Kinder Morgan Kansas, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 15, 2005 (File No. 1-06446))
4.12*Forms of Kinder Morgan Finance Company LLC Notes (included in the Indenture filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 15, 2005 (File No. 1-06446))
4.13*Indenture dated January 2, 2001 between Kinder Morgan Energy Partners, L.P. and First Union National Bank, as trustee, relating to Senior Debt Securities (including form of Senior Debt Securities) (filed as Exhibit 4.11 to Kinder Morgan Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2000 (File No. 1-11234))
4.14*Certificate of Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 7.40% Notes due March 15, 2031 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Current Report on Form 8-K filed on March 14, 2001 (File No. 1-11234))
4.15*Specimen of 7.40% Notes due March 15, 2031 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P.’s Current Report on Form 8-K filed on March 14, 2001(File No. 1-11234))
4.16*Certificate of Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 7.750% Notes due March 15, 2032 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002 (File No. 1-11234))
4.17*Specimen of 7.750% Notes due March 15, 2032 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002 (File No. 1-11234))
Exhibit Number Description
4.18*Indenture dated August 19, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346))
4.19*First Supplemental Indenture to Indenture dated August 19, 2002, dated August 23, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346))
4.20*Form of 7.30% Notes due 2033 (contained in the Indenture filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346))
4.21*Senior Indenture dated January 31, 2003 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102961))
4.22*Form of Senior Note of Kinder Morgan Energy Partners, L.P. (included in the Form of Senior Indenture filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102961))
4.23*Certificate of Vice President, Treasurer and Chief Financial Officer and Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 5.80% Notes due March 15, 2035 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 (File No. 1-11234))
4.24*Certificate of Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 6.00% Senior Notes due 2017 and 6.50% Senior Notes due 2037 (filed as Exhibit 4.28 to Kinder Morgan Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2006 (File No. 1-11234))
4.25*Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 6.95% Senior Notes due 2038 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 1-11234))
4.26*Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.95% Senior Notes due 2018 (filed as Exhibit 4.28 to Kinder Morgan Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 1-11234))
4.27*Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 9.00% Senior Notes due 2019 (filed as Exhibit 4.29 to Kinder Morgan Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2008 (File No. 1-11234))
4.28*Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 6.85% Senior Notes due 2020 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009 (File No. 1-11234))
4.29*Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.80% Senior Notes due 2021, and the 6.50% Senior Notes due 2039 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009 (File No. 1-11234))
4.30*Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.30% Senior Notes due 2020, and the 6.55% Senior Notes due 2040 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 (File No. 1-11234))
4.31*Indenture, dated December 20, 2010, among Kinder Morgan Finance Company LLC, Kinder Morgan Kansas, Inc. and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 23, 2010 (File No. 1-06446))
Exhibit Number Description
4.32*Officers’ Certificate establishing the terms of the 6.000% Senior Notes due 2018 of Kinder Morgan Finance Company LLC (with the form of note attached thereto) (filed as Exhibit 4.2 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 23, 2010 (File No. 1-06446))
4.33*Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 6.375% Senior Notes due 2041 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 1-11234))
4.34*Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 4.150% Senior Notes due 2022, and the 5.625% Senior Notes due 2041 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011 (File No. 1-11234))
4.35*Certificate of the Vice President, Finance and Investor Relations and the Vice President and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 3.500% Senior Notes due 2021 and the 5.500% Senior Notes due 2044 (Filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014 (File No. 1-11234))
4.36*Certificate of the Vice President and Treasurer and the Vice President and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 4.250% Senior Notes due 2024 and the 5.400% Senior Notes due 2044 (Filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014 (File No. 1-11234))
4.37*Indenture, dated March 1, 2012, among KMI and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to KMI’s Registration Statement on Form S-3 filed on March 1, 2012 (File No. 001-35081))
4.38*Certificate of the Vice President and Treasurer and the Vice President and Secretary of KMI establishing the terms of the 2.000% Senior Notes due 2017, the 3.050% Senior Notes due 2019, the 4.300% Senior Notes due 2025, the 5.300% Senior Notes due 2034 and the 5.550% Senior Notes due 2045 (filed as Exhibit 10.53 to KMI’s Annual Report on Form 10-K for the year ended December 31, 2014 (File No. 001-35081))
4.39*Certificate of Vice President and Treasurer and Vice President and Secretary of KMI establishing the terms of the 5.050% Senior Notes due 2046 (filed as Exhibit 4.1 to KMI’s Quarterly Report on Form 10-Q for the three months ended March 31, 2015 (File No. 001-35081))
4.40*Certificate of Vice President and Treasurer and Vice President and Secretary of KMI establishing the terms of the 1.500% Senior Notes due 2022 and 2.250% Senior Notes due 2027 (filed as Exhibit 4.2 to KMI’s Form 8-A, filed March 16, 2015 and incorporated herein by reference (File No. 001-35081))
4.41Certain instruments with respect to long-term debt of KMI and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of KMI and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. sec. #229.601. KMI hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request.
10.1*KMI 2015 Amended and Restated Stock Incentive Plan (filed as Exhibit 4.5 to KMI’s Registration Statement on Form S-8, filed on July 1, 2015, and incorporated herein by reference (File No. 333-205430))
10.2*Amendment No. 1 to KMI 2015 Amended and Restated Stock Incentive Plan (filed as Exhibit 10.2 to KMI’s Current Report on Form 8-K filed on January 24, 2017 (File No. 001-35081))
10.3*2015 Form of Employee Restricted Stock Unit Agreement (filed as Exhibit 4.6 to KMI’s Registration Statement on Form S-8, filed on July 1, 2015, and incorporated herein by reference (File No. 333-205430))
10.4*2016 Form of Employee Restricted Stock Unit Agreement (filed as Exhibit 10.2 to KMI’s Quarterly Report on Form 10-Q for the three months ended June 30, 2016 (File No. 001-35081))
10.5*Amended and Restated Stock Compensation Plan for Non-Employee Directors (filed as Exhibit 10.5 to KMI’s Quarterly Report on Form 10-Q for the three months ended June 30, 2015 (File No. 001-35081))
10.6*2015 Form of Non-Employee Director Stock Compensation Agreement (filed as Exhibit 10.6 to KMI’s Quarterly Report on Form 10-Q for the three months ended June 30, 2015 (File No. 001-35081))
Exhibit Number Description
10.7*2011 Form of Non-Employee Director Stock Compensation Agreement (filed as Exhibit 10.3 to KMI’s Quarterly Report on Form 10-Q for the three months ended March 31, 2011 (File No. 001-35081))
10.8*KMI Employees Stock Purchase Plan (filed as Exhibit 10.5 to KMI’s Quarterly Report on Form 10-Q for the three months ended March 31, 2011 (File No. 001-35081))
10.9*Amended and Restated Annual Incentive Plan of KMI (filed as Exhibit 10.4 to KMI’s Quarterly Report on Form 10-Q for the three months ended June 30, 2015 (File No. 001-35081))
10.10*Amendment No. 1 to Amended and Restated Incentive Plan of KMI (filed as Exhibit 10.1 to KMI’s Current Report on Form 8-K filed January 24, 2017 (File No. 001-35081))
10.11*Support Agreement, dated as of August 9, 2014, by and among Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Management, LLC, El Paso Pipeline Partners, L.P., El Paso Pipeline GP Company, L.L.C., Richard D. Kinder and RDK Investments, Ltd. (filed as Exhibit 10.1 to KMI’s Current Report on Form 8-K filed August 12, 2014 (File No. 001-35081))
10.12*Bridge Credit Agreement, dated September 19, 2014 among KMI, as borrower, Barclays Bank PLC, as administrative agent, and the lenders party thereto (filed as Exhibit 10.1 to KMI’s Current Report on Form 8-K filed September 25, 2014 (File No. 001-35081))
10.13*Revolving Credit Agreement, dated September 19, 2014 among KMI, as borrower, Barclays Bank PLC, as administrative agent, and the lenders and issuing banks party thereto (filed as Exhibit 10.2 to KMI’s Current Report on Form 8-K filed September 25, 2014(File No. 001-35081))
10.14*Term Loan Agreement, dated as of January 26, 2016 among KMI, as borrower, the lenders party thereto and Barclays Bank PLC, as administrative agent (filed as exhibit 10.2 to KMI’s Quarterly Report on Form 10-Q for the three months ended March 31, 2016 (File No. 001-35081))
10.15*Joinder Agreement, dated as of January 26, 2016, to KMI’s Revolving Credit Agreement, dated as of September 19, 2014 among KMI, the lenders party thereto and Barclay Bank PLC, as administrative agent. (filed as exhibit 10.3 to KMI’s Quarterly Report on Form 10-Q for the three months ended March 31, 2016 (File No. 001-35081))
10.16Cross Guarantee Agreement, dated as of November 26, 2014 among KMI and certain of its subsidiaries with schedules updated as of December 31, 2016
12.1Statement re: computation of ratio of earnings to fixed charges
21.1Subsidiaries of KMI
23.1Consent of PricewaterhouseCoopers LLP
31.1Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
95.1Mine Safety Disclosures
101Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Statements of Income for the years ended December 31, 2016, 2015, and 2014; (ii) our Consolidated Statements of Comprehensive Income for the years ended December 31, 2016, 2015, and 2014; (iii) our Consolidated Balance Sheets as of December 31, 2016 and 2015; (iv) our Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015, and 2014; (v) our Consolidated Statement of Stockholders’ Equity as of and for the years ended December 31, 2016, 2015, and 2014; and (vi) the notes to our Consolidated Financial Statements

*Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith, except as noted otherwise.

KINDER MORGAN, INC. AND SUBSIDIARIES INDEX TO FINANCIAL STATEMENTS
Page Number
Report of Independent Registered Public Accounting Firm74
Consolidated Statements of Income for the years ended December 31, 2016, 2015 and 201475
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2016, 2015 and 201476
Consolidated Balance Sheets as of December 31, 2016 and 201577
Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 201478
Consolidated Statement of Stockholders’ Equity as of and for the years ended December 31, 2016, 2015 and 201480
Notes to Consolidated Financial Statements81
Supplemental Selected Quarterly Financial Data (Unaudited)147

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Kinder Morgan, Inc.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of comprehensive income, of stockholders’ equity and of cash flows present fairly, in all material respects, the financial position of Kinder Morgan, Inc. and its subsidiaries (the “Company”) at December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing in Item 9A of the Company’s 2016 Annual Report on Form 10-K. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

/s/PricewaterhouseCoopers LLP

Houston, Texas

February 10, 2017

KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In Millions, Except Per Share Amounts)
Year Ended December 31,
201620152014
Revenues
Natural gas sales$2,454$2,839$4,115
Services8,1468,2907,650
Product sales and other2,4583,2744,461
Total Revenues13,05814,40316,226
Operating Costs, Expenses and Other
Costs of sales3,4984,1156,278
Operations and maintenance2,3032,3372,157
Depreciation, depletion and amortization2,2092,3092,040
General and administrative669690610
Taxes, other than income taxes421439418
Loss on impairment of goodwill—1,150—
Loss on impairments and divestitures, net387919274
Other (income) expense, net(1)(3)1
Total Operating Costs, Expenses and Other9,48611,95611,778
Operating Income3,5722,4474,448
Other Income (Expense)
Earnings from equity investments497414406
Loss on impairments and divestitures of equity investments, net(610)(30)—
Amortization of excess cost of equity investments(59)(51)(45)
Interest, net(1,806)(2,051)(1,798)
Other, net444380
Total Other Expense(1,934)(1,675)(1,357)
Income Before Income Taxes1,6387723,091
Income Tax Expense(917)(564)(648)
Net Income7212082,443
Net (Income) Loss Attributable to Noncontrolling Interests(13)45(1,417)
Net Income Attributable to Kinder Morgan, Inc.7082531,026
Preferred Stock Dividends(156)(26)—
Net Income Available to Common Stockholders$552$227$1,026
Class P Shares
Basic Earnings Per Common Share$0.25$0.10$0.89
Basic Weighted Average Common Shares Outstanding2,2302,1871,137
Diluted Earnings Per Common Share$0.25$0.10$0.89
Diluted Weighted Average Common Shares Outstanding2,2302,1931,137
Dividends Per Common Share Declared for the Period$0.50$1.605$1.74

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Millions)

Year Ended December 31,
201620152014
Net income$721$208$2,443
Other comprehensive income (loss), net of tax
Change in fair value of hedge derivatives (net of tax benefit (expense) of $60, $(94) and $(163), respectively)(104)164409
Reclassification of change in fair value of derivatives to net income (net of tax benefit of $67, $156 and $13, respectively)(116)(272)(25)
Foreign currency translation adjustments (net of tax (expense) benefit of $(20), $123 and $48, respectively)34(214)(138)
Benefit plan adjustments (net of tax benefit of $19, $69 and $126, respectively)(14)(122)(226)
Total other comprehensive (loss) income(200)(444)20
Comprehensive income (loss)521(236)2,463
Comprehensive (income) loss attributable to noncontrolling interests(13)45(1,486)
Comprehensive income (loss) attributable to KMI$508$(191)$977

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

KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Millions, Except Share and Per Share Amounts)
December 31,
20162015
ASSETS
Current assets
Cash and cash equivalents$684$229
Restricted deposits10360
Accounts receivable, net1,3701,315
Fair value of derivative contracts198507
Inventories357407
Income tax receivable18040
Other current assets337266
Total current assets3,2292,824
Property, plant and equipment, net38,70540,547
Investments7,0276,040
Goodwill22,15223,790
Other intangibles, net3,3183,551
Deferred income taxes4,3525,323
Deferred charges and other assets1,5222,029
Total Assets$80,305$84,104
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of debt$2,696$821
Accounts payable1,2571,192
Accrued interest625695
Accrued contingencies261298
Other current liabilities1,0851,059
Total current liabilities5,9244,065
Long-term liabilities and deferred credits
Long-term debt
Outstanding36,10540,632
Preferred interest in general partner of KMP100100
Debt fair value adjustments1,1491,674
Total long-term debt37,35442,406
Other long-term liabilities and deferred credits2,2252,230
Total long-term liabilities and deferred credits39,57944,636
Total Liabilities45,50348,701
Commitments and contingencies (Notes 9, 13 and 17)
Stockholders’ Equity
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,230,102,384 and 2,229,223,864 shares, respectively, issued and outstanding2222
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 9.75% Series A Mandatory Convertible, $1,000 per share liquidation preference, 1,600,000 shares issued and outstanding——
Additional paid-in capital41,73941,661
Retained deficit(6,669)(6,103)
Accumulated other comprehensive loss(661)(461)
Total Kinder Morgan, Inc.’s stockholders’ equity34,43135,119
Noncontrolling interests371284
Total Stockholders’ Equity34,80235,403
Total Liabilities and Stockholders’ Equity$80,305$84,104

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Millions)

Year Ended December 31,
201620152014
Cash Flows From Operating Activities
Net income$721$208$2,443
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization2,2092,3092,040
Deferred income taxes1,087692615
Amortization of excess cost of equity investments595145
Gain on early extinguishment of debt(45)——
Loss on impairment of goodwill (Note 4)—1,150—
Loss on impairments and divestitures, net (Note 4)387919274
Loss on impairments and divestitures of equity investments, net (Note 4)61030—
Earnings from equity investments(497)(414)(406)
Distributions of equity investment earnings431391381
Pension contributions and noncash pension benefit credits—(85)(88)
Changes in components of working capital, net of the effects of acquisitions
Accounts receivable(107)382(84)
Income tax receivable(148)195(195)
Inventories4934(30)
Other current assets(81)113(17)
Accounts payable144(156)(1)
Accrued interest, net of interest rate swaps(18)3761
Accrued contingencies and other current liabilities71(129)108
Rate reparations, refunds and other litigation reserve adjustments(32)18(280)
Other, net(53)(442)(399)
Net Cash Provided by Operating Activities4,7875,3034,467
Cash Flows From Investing Activities
Acquisitions of assets and investments, net of cash acquired(333)(2,079)(1,388)
Capital expenditures(2,882)(3,896)(3,617)
Proceeds from sale of equity interests in subsidiaries, net1,401——
Sales of property, plant and equipment, investments, and other net assets, net of removal costs330395
Contributions to investments(408)(96)(389)
Distributions from equity investments in excess of cumulative earnings231228182
Other, net(44)98(3)
Net Cash Used in Investing Activities(1,705)(5,706)(5,210)
Cash Flows From Financing Activities
Issuances of debt8,62914,31624,573
Payments of debt(10,060)(15,116)(17,801)
Debt issue costs(19)(24)(89)
Issuances of common shares (Note 11)—3,870—
Issuance of mandatory convertible preferred stock (Note 11)—1,541—
Cash dividends - common shares (Note 11)(1,118)(4,224)(1,760)
Cash dividends - preferred shares (Note 11)(154)——
Repurchases of shares and warrants—(12)(192)
Cash consideration of Merger Transactions (Note 1)——(3,937)
Merger Transactions costs—(2)(74)
Contributions from noncontrolling interests117111,767
Distributions to noncontrolling interests(24)(34)(2,013)
Other, net—1(3)
Net Cash (Used in) Provided by Financing Activities(2,629)327471
Effect of Exchange Rate Changes on Cash and Cash Equivalents2(10)(11)
Net increase (decrease) in Cash and Cash Equivalents455(86)(283)
Cash and Cash Equivalents, beginning of period229315598
Cash and Cash Equivalents, end of period$684$229$315

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

(In Millions)

Year Ended December 31,
201620152014
Noncash Investing and Financing Activities
Assets acquired by the assumption or incurrence of liabilities$43$1,681$106
Net assets contributed to equity investments3746—
Net assets and liabilities or noncontrolling interests acquired by the issuance of shares and warrants (Notes 1)——16,023
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)2,0501,9851,718
Cash paid (refunded) during the period for income taxes, net4(331)227

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In Millions)

Common stockPreferred stock
Issued sharesPar valueIssued sharesPar valueAdditional paid-in capitalRetained deficitAccumulated other comprehensive lossStockholders’ equity attributable to KMINon-controlling interestsTotal
Balance at December 31, 20131,031$10—$—$14,479$(1,372)$(24)$13,093$15,192$28,285
Impact of Merger Transactions1,0971121,88021,891(15,936)5,955
Merger Transactions costs(75)(75)(75)
Repurchase of shares and warrants(3)(192)(192)(192)
Restricted shares525252
Impact from equity transactions of KMP, EPB and KMR3636(55)(19)
Net income1,0261,0261,4172,443
Distributions—(2,013)(2,013)
Contributions—1,7671,767
Common stock dividends(1,760)(1,760)(1,760)
Other(2)(2)(4)(6)
Other comprehensive (loss) income(49)(49)6920
Impact of Merger Transactions on Accumulated other comprehensive loss5656(87)(31)
Balance at December 31, 20142,12521——36,178(2,106)(17)34,07635034,426
Issuances of common shares10313,8693,8703,870
Issuances of preferred shares21,5411,5411,541
Repurchase of warrants(12)(12)(12)
EP Trust I Preferred security conversions1232323
Warrants exercised222
Restricted shares575757
Net income253253(45)208
Distributions—(34)(34)
Contributions—1111
Preferred stock dividends(26)(26)(26)
Common stock dividends(4,224)(4,224)(4,224)
Other3325
Other comprehensive loss(444)(444)(444)
Balance at December 31, 20152,229222—41,661(6,103)(461)35,11928435,403
Restricted shares1666666
Net income70870813721
Distributions—(24)(24)
Contributions—117117
Preferred stock dividends(156)(156)(156)
Common stock dividends(1,118)(1,118)(1,118)
Other1212(19)(7)
Other comprehensive loss(200)(200)(200)
Balance at December 31, 20162,230$222$—$41,739$(6,669)$(661)$34,431$371$34,802

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

KINDER MORGAN, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

  1. General

We are one of the largest energy infrastructure companies in North America and unless the context requires otherwise, references to “we,” “us,” “our,” “the Company,” or “KMI” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2 and other products, and our terminals transload and store petroleum products, ethanol and chemicals, and handle such products as steel, coal and petroleum coke. We are also a leading producer of CO2, which we and others utilize for enhanced oil recovery projects primarily in the Permian basin.

On November 26, 2014, we completed our acquisition, pursuant to three separate merger agreements, of all of the outstanding common units of KMP and EPB and all of the outstanding shares of KMR that we did not already own. The transactions are referred to collectively as the “Merger Transactions.”

As we controlled each of KMP, KMR and EPB and continued to control each of them after the Merger Transactions, the changes in our ownership interest in each of KMP, KMR and EPB were accounted for as an equity transaction and no gain or loss was recognized in our consolidated statements of income related to the Merger Transactions. After closing the Merger Transactions, KMR was merged with and into KMI. On January 1, 2015, EPB and its subsidiary, EPPOC, merged with and into KMP. References to EPB refer to EPB for periods prior to its merger into KMP.

Prior to the Merger Transactions, we owned an approximate 10% limited partner interest (including our interest in KMR) and the 2% general partner interest including incentive distribution rights in KMP, and an approximate 39% limited partner interest and the 2% general partner interest and incentive distribution rights in EPB. Effective with the Merger Transactions, the incentive distribution rights held by the general partner of KMP were eliminated.

The equity interests in KMP, EPB and KMR (which are all consolidated in our financial statements) owned by the public prior to the Merger Transactions are reflected within “Noncontrolling interests” in our accompanying consolidated statements of stockholders’ equity. The earnings recorded by KMP, EPB and KMR that are attributed to their units and shares, respectively, held by the public prior to the Merger Transactions are reported as “Net (income) loss attributable to noncontrolling interests” in our accompanying consolidated statement of income for the year ended December 31, 2014.

Our common stock trades on the NYSE under the symbol “KMI.”

  1. Summary of Significant Accounting Policies

Basis of Presentation

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

Use of Estimates

Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities, our revenues and expenses during the reporting period, and our disclosures, including as it relates to contingent assets and liabilities at the date of our financial statements. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

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

Cash Equivalents and Restricted Deposits

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

Restricted deposits were $103 million and $60 million as of December 31, 2016 and 2015, respectively.

Accounts Receivable, net

The amounts reported as “Accounts receivable, net” on our accompanying consolidated balance sheets as of December 31, 2016 and 2015 primarily consist of amounts due from customers net of the allowance for doubtful accounts.

Our policy for determining an appropriate allowance for doubtful accounts varies according to the type of business being conducted and the customers being served. Generally, we make periodic reviews and evaluations of the appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and we record adjustments as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved.

The allowance for doubtful accounts was $39 million and $91 million as of December 31, 2016 and 2015, respectively. The decrease was primarily associated with certain coal customers’ receivables that were written off in 2016 and had been reserved in prior periods.

Inventories

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

Gas Imbalances

We value gas imbalances due to or due from interconnecting pipelines at market prices. As of December 31, 2016 and 2015, our gas imbalance receivables—including both trade and related party receivables—totaled $108 million and $21 million, respectively, and we included these amounts within “Other current assets” on our accompanying consolidated balance sheets. As of December 31, 2016 and 2015, our gas imbalance payables—including both trade and related party payables—totaled $45 million and $17 million, respectively, and we included these amounts within “Other current liabilities” on our accompanying consolidated balance sheets.

Property, Plant and Equipment, net

Capitalization, Depreciation and Depletion and Disposals

We report property, plant and equipment at its acquisition cost. We expense costs for routine maintenance and repairs in the period incurred.

We generally compute depreciation using either the straight-line method based on estimated economic lives or, for certain depreciable assets, we employ the composite depreciation method, applying a single depreciation rate for a group of assets. Generally, we apply composite depreciation rates to functional groups of property having similar economic characteristics. The rates range from 1.09% to 23.0% excluding certain short-lived assets such as vehicles. For FERC-regulated entities, the FERC-accepted composite depreciation rate is applied to the total cost of the composite group until the net book value equals the salvage value. For other entities, depreciation estimates are based on various factors, including age (in the case of acquired assets), manufacturing specifications, technological advances, contract term for assets on leased or customer property and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives (and salvage values where appropriate) that we believe are reasonable. Subsequent events could cause us to change our estimates, thus

impacting the future calculation of depreciation and amortization expense. Historically, adjustments to useful lives have not had a material impact on our aggregate depreciation levels from year to year.

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

We engage in enhanced recovery techniques in which CO2 is injected into certain producing oil reservoirs. In some cases, the cost of the CO2 associated with enhanced recovery is capitalized as part of our development costs when it is injected. The cost of CO2 associated with pressure maintenance operations for reservoir management is expensed when it is injected. When CO2 is recovered in conjunction with oil production, it is extracted and re-injected, and all of the associated costs are expensed as incurred. Proved developed reserves are used in computing units of production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs. The units-of-production depreciation rate is determined by field and for our oil and gas producing fields that have no proved reserves, the units-of-production depreciation rate is based on each field’s probable reserves and NYMEX forward curve prices.

A gain on the sale of property, plant and equipment used in our oil and gas producing activities or in our bulk and liquids terminal activities is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received. A gain on an asset disposal is recognized in income in the period that the sale is closed. A loss on the sale of property, plant and equipment is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received or the market value if the asset is being held for sale. A loss is recognized when the asset is sold or when the net cost of an asset held for sale is greater than the market value of the asset. For our pipeline system assets under the composite method of depreciation, we generally charge the original cost of property sold or retired to accumulated depreciation and amortization, net of salvage and cost of removal. Gains and losses are booked for operating unit sales and land sales and are recorded to income or expense accounts in accordance with regulatory accounting guidelines. In those instances where we receive recovery in tariff rates related to losses on dispositions of operating units, we record a regulatory asset for the estimated recoverable amount.

Asset Retirement Obligations

We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses. We record, as liabilities, the fair value of asset retirement obligations on a discounted basis when they are incurred and can be reasonably estimated, which is typically at the time the assets are installed or acquired. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities increase due to the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service.

We have various other obligations throughout our businesses to remove facilities and equipment on rights-of-way and other leased facilities. We currently cannot reasonably estimate the fair value of these obligations because the associated assets have indeterminate lives. These assets include pipelines, certain processing plants and distribution facilities, and certain bulk and liquids terminal facilities. An asset retirement obligation, if any, will be recognized once sufficient information is available to reasonably estimate the fair value of the obligation.

Long-lived Asset Impairments

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

Prior to us conducting the goodwill impairment test, to the extent triggering events exist, we complete a review of the carrying value of our long-lived assets, including property, plant and equipment as well as other intangibles, and record, as applicable, the appropriate impairments. Because the impairment test for long-lived assets held in use is based on undiscounted cash flows, there may be instances where an asset or asset group is not considered impaired, even when its fair value may be less than its carrying value, because the asset or asset group is recoverable based on the cash flows to be generated over the estimated life of the asset or asset group.

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

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

Equity Method of Accounting and Excess Investment Cost

We account for investments which we do not control, but do have the ability to exercise significant influence using the equity method of accounting. Under this method, our equity investments are carried originally at our acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received.

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

The first differential, representing the excess of the fair market value of our investees’ plant and other net assets over its underlying book value at either the date of acquisition or the date of the loss of control totaled $767 million and $808 million as of December 31, 2016 and 2015, respectively. Generally, this basis difference relates to our share of the underlying depreciable assets, and, as such, we amortize this portion of our investment cost against our share of investee earnings. As of December 31, 2016, this excess investment cost is being amortized over a weighted average life of approximately fourteen years.

The second differential, representing equity method goodwill, totaled $956 million and $138 million, as of December 31, 2016 and 2015, respectively. This differential is not subject to amortization but rather to impairment testing as part of our periodic evaluation of the recoverability of our investment as compared to the fair value of net assets accounted for under the equity method. Our impairment test considers whether the fair value of the equity investment as a whole has declined and whether that decline is other than temporary. The increase in the equity method goodwill balance from December 31, 2015 is due to the sale of a 50% interest in our SNG natural gas pipeline system, see Note 3.

Goodwill

Goodwill is the cost of an acquisition in excess of the fair value of acquired assets and liabilities and is recorded as an asset on our balance sheet. Goodwill is not subject to amortization but must be tested for impairment at least annually. This test requires us to assign goodwill to an appropriate reporting unit and to determine if the implied fair value of the reporting unit’s goodwill is less than its carrying amount.

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

Step 1 involves comparing the estimated fair value of each respective reporting unit to its carrying value, including goodwill. If the estimated fair value exceeds the carrying value, the reporting unit’s goodwill is not considered impaired. If the carrying value exceeds the estimated fair value, step 2 must be performed to determine whether goodwill is impaired and, if so, the amount of the impairment. Step 2 involves calculating an implied fair value of goodwill by performing a

hypothetical allocation of the estimated fair value of the reporting unit determined in step 1 to the respective tangible and intangible net assets of the reporting unit. The remaining implied goodwill is then compared to the actual carrying amount of the goodwill for the reporting unit. To the extent the carrying amount of goodwill exceeds the implied goodwill, the difference is the amount of the goodwill impairment.

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

Refer to Note 8 for further information.

Other Intangibles

Excluding goodwill, our other intangible assets include customer contracts, relationships and agreements, lease value, and technology-based assets. As of December 31, 2016 and 2015, the gross carrying amounts of these intangible assets was $4,305 million and $4,335 million, respectively and the accumulated amortization was $986 million and $784 million, respectively, resulting in net carrying amounts of $3,318 million and $3,551 million, respectively. These intangible assets primarily consisted of customer contracts, relationships and agreements associated with our Natural Gas Pipelines and Terminals business segments.

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

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

For the years ended December 31, 2016, 2015 and 2014, the amortization expense on our intangibles totaled $223 million, $221 million and $143 million, respectively. Our estimated amortization expense for our intangible assets for each of the next five fiscal years (2017 – 2021) is approximately $215 million, $213 million, $211 million, $209 million, and $208 million, respectively. As of December 31, 2016, the weighted average amortization period for our intangible assets was approximately seventeen years.

Other intangibles are evaluated for recoverability consistent with the discussion above on long-lived asset impairments.

Revenue Recognition

We recognize revenue as services are rendered or goods are delivered and, if applicable, risk of loss has passed. We recognize natural gas, crude and NGL sales revenue when the commodity is sold to a purchaser at a fixed or determinable price, delivery has occurred and risk of loss has transferred, and collectability of the revenue is reasonably assured. Our sales and purchases of natural gas, crude and NGL are primarily accounted for on a gross basis as natural gas sales or product sales, as applicable, and cost of sales, except in circumstances where we solely act as an agent and do not have price and related risk of ownership, in which case we recognize revenue on a net basis.

In addition to storing and transporting a significant portion of the natural gas volumes we purchase and resell, we provide various types of natural gas storage and transportation services for third-party customers. Under these contracts, the natural gas remains the property of these customers at all times. In many cases, generally described as firm service, the customer pays a two-part rate that includes (i) a fixed fee reserving the right to transport or store natural gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fixed-fee component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customers’ agreed upon delivery point, or when the volumes are injected into/withdrawn from our storage facilities.

In other cases, generally described as interruptible service, there is no fixed fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements.

We provide crude oil and refined petroleum products transportation and storage services to customers. Revenues are recorded when products are delivered and services have been provided, and adjusted according to terms prescribed by the toll settlements with shippers and approved by regulatory authorities.

We recognize bulk terminal transfer service revenues based on volumes loaded and unloaded. We recognize liquids terminal tank rental revenue ratably over the contract period. We recognize liquids terminal throughput revenue based on volumes received and volumes delivered. We recognize transmix processing revenues based on volumes processed or sold, and if applicable, when risk of loss has passed. We recognize energy-related product sales revenues based on delivered quantities of product.

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

Cost of Sales

Cost of sales primarily includes the cost of energy commodities sold, including natural gas, NGL and other refined petroleum products, adjusted for the effects of our energy commodity activities, as applicable, other than production from our CO2 business segment.

Operations and Maintenance

Operations and maintenance include costs of services and is primarily comprised of (i) operational labor costs and (ii) operations, maintenance and asset integrity, regulatory and environmental costs. Costs associated with our oil, gas and carbon dioxide producing activities included within operations and maintenance totaled $349 million, $366 million and $403 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Environmental Matters

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

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

Pensions and Other Postretirement Benefits

We recognize the differences between the fair value of each of our and our consolidated subsidiaries’ pension and other postretirement benefit plans’ assets and the benefit obligations as either assets or liabilities on our consolidated balance sheet. We record deferred plan costs and income—unrecognized losses and gains, unrecognized prior service costs and credits, and

any remaining unamortized transition obligations—in “Accumulated other comprehensive loss” or as a regulatory asset or liability for certain of our regulated operations, until they are amortized as a component of benefit expense.

Noncontrolling Interests

Noncontrolling interests represents the interests in our consolidated subsidiaries that are not owned by us. In our accompanying consolidated income statements, the noncontrolling interest in the net income (or loss) of our consolidated subsidiaries is shown as an allocation of our consolidated net income and is presented separately as “Net (Income) Loss Attributable to Noncontrolling Interests.” In our accompanying consolidated balance sheets, noncontrolling interests is presented separately as “Noncontrolling interests” within “Stockholders’ Equity.”

Income Taxes

Income tax expense is recorded based on an estimate of the effective tax rate in effect or to be in effect during the relevant periods. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. 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 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.

Foreign Currency Transactions and Translation

Foreign currency transaction gains or losses result from a change in exchange rates between (i) the functional currency, for example the Canadian dollar for a Canadian subsidiary and (ii) the currency in which a foreign currency transaction is denominated, for example the U.S. dollar for a Canadian subsidiary. In our accompanying consolidated statements of income, gains and losses from our foreign currency transactions are included within “Other Income (Expense)—Other, net.”

Foreign currency translation is the process of expressing, in U.S. dollars, amounts recorded in a local functional currency other than U.S. dollars, for example the Canadian dollar for a Canadian subsidiary. We translate the assets and liabilities of each of our consolidated foreign subsidiaries that have a local functional currency to U.S. dollars at year-end exchange rates. Income and expense items are translated at weighted-average rates of exchange prevailing during the year and stockholders’ equity accounts are translated by using historical exchange rates. The cumulative translation adjustments balance is reported as a component of “Accumulated other comprehensive loss.”

Risk Management Activities

We utilize energy commodity derivative contracts for the purpose of mitigating our risk resulting from fluctuations in the market price of commodities including natural gas, NGL and crude oil. In addition, we enter into interest rate swap agreements for the purpose of hedging the interest rate risk associated with our debt obligations. We also enter into cross-currency swap agreements to manage our foreign currency risk with certain debt obligations. We measure our derivative contracts at fair value and we report them on our balance sheet as either an asset or liability. For certain physical forward commodity derivatives contracts, we apply the normal purchase/normal sale exception, whereby the revenues and expenses associated with such transactions are recognized during the period when the commodities are physically delivered or received.

For qualifying accounting hedges, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives and the methods used for assessing and testing effectiveness, and how any

ineffectiveness will be measured and recorded. If we designate a derivative contract as a cash flow accounting hedge, the effective portion of the change in fair value of the derivative is deferred in accumulated other comprehensive income/(loss) and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value or amount excluded from the assessment of hedge effectiveness is recognized currently in earnings. If we designate a derivative contract as a fair value accounting hedge, the effective portion of the change in fair value of the derivative is recorded as an adjustment to the item being hedged. Any ineffective portion of the derivative’s change in fair value is recognized currently in earnings.

For derivative instruments that are not designated as accounting hedges, or for which we have not elected the normal purchase/normal sales exception, changes in fair value are recognized currently in earnings.

Regulatory Assets and Liabilities

Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. We included the amounts of our regulatory assets and liabilities within “Other current assets,” “Deferred charges and other assets,” “Other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance sheets.

The following table summarizes our regulatory asset and liability balances as of December 31, 2016 and 2015 (in millions):

December 31,
20162015
Current regulatory assets$49$55
Non-current regulatory assets330378
Total regulatory assets(a)$379$433
Current regulatory liabilities$101$161
Non-current regulatory liabilities108166
Total regulatory liabilities(b)$209$327
(a)Regulatory assets as of December 31, 2016 include (i) $188 million of unamortized losses on disposal of assets; (ii) $107 million income tax gross up on equity AFUDC; and (iii) $84 million of other assets including amounts related to fuel tracker arrangements. Approximately $172 million of the regulatory assets, with a weighted average remaining recovery period of 20 years, are recoverable without earning a return, including the income tax gross up on equity AFUDC for which there is an offsetting deferred income tax balance for FERC rate base purposes, and therefore, it does not earn a return.
(b)Regulatory liabilities as of December 31, 2016 are comprised of customer prepayments to be credited to shippers or other over-collections that are expected to be returned to shippers or netted against under-collections over time. Approximately $24 million of the $108 million classified as non-current is expected to be credited to shippers over a remaining weighted average period of 22 years, while the remaining $84 million is not subject to a defined period.

Transfer of Net Assets Between Entities Under Common Control

We account for the transfer of net assets between entities under common control by carrying forward the net assets recognized in the balance sheets of each combining entity to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination. Transfers of net assets between entities under common control do not affect the historical income statement or balance sheet of the combined entity.

Earnings per Share

We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares of common stock and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards, which may be stock or stock units issued to management employees and include dividend equivalent payments, do not participate in excess distributions over earnings.

The following tables set forth the allocation of net income available to shareholders of Class P shares and participating securities and the reconciliation of Basic Weighted Average Common Shares Outstanding to Diluted Weighted Average Common Shares Outstanding (in millions):

Year Ended December 31,
201620152014
Class P$548$214$1,015
Participating securities:
Restricted stock awards(a)41311
Net Income Available to Common Stockholders$552$227$1,026
Year Ended December 31,
201620152014
Basic Weighted Average Common Shares Outstanding2,2302,1871,137
Effect of dilutive securities:
Warrants—6—
Diluted Weighted Average Common Shares Outstanding2,2302,1931,137
(a)As of December 31, 2016, there were approximately 9 million such restricted stock awards.

The following maximum number of potential common stock equivalents are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share (in millions on a weighted average basis):

Year Ended December 31,
201620152014
Unvested restricted stock awards877
Warrants to purchase our Class P shares(a)293291312
Convertible trust preferred securities8810
Mandatory convertible preferred stock(b)5810n/a

n/a - not applicable

(a)Each warrant entitles the holder to purchase one share of our common stock for an exercise price of $40 per share, payable in cash or by cashless exercise, at any time until May 25, 2017. The potential dilutive effect of the warrants does not consider the assumed proceeds to KMI upon exercise.
(b)Until our mandatory convertible preferred shares are converted to common shares, on or before the expected mandatory conversion date of October 26, 2018, the holder of each preferred share participates in our earnings by receiving preferred dividends.
  1. Acquisitions and Divestitures

Business Combinations

During 2016, 2015 and 2014, we completed the following significant acquisitions.

Allocation of Purchase Price

As of December 31, 2016, the evaluation of the assigned fair values for the BP terminals acquisition was ongoing and subject to adjustment. As of December 31, 2016, our preliminary allocation of the purchase price for the BP terminals acquisition and the purchase allocation for other significant acquisitions completed during 2016, 2015 and 2014 are detailed below (in millions):

Assignment of Purchase Price
Ref.DateAcquisitionPurchase priceCurrent assetsProperty plant & equipmentDeferred charges & otherGoodwillDebtOther liabilities
(1)2/16BP Products North America Inc. Terminal Assets$349$2$396$—$—$—$(49)
(2)2/15Vopak Terminal Assets1582155—6—(5)
(3)2/15Hiland1,709791,4921,498310(1,413)(257)
(4)11/14Pennsylvania and Florida Jones Act Tankers270—270825—(33)
(5)1/14American Petroleum Tankers and State Class Tankers9616951664—(66)

After measuring all of the identifiable tangible and intangible assets acquired and liabilities assumed at fair value on the acquisition date, goodwill is an intangible asset representing the future economic benefits expected to be derived from an acquisition that are not assigned to other identifiable, separately recognizable assets. We believe the primary items that generated our goodwill are both the value of the synergies created between the acquired assets and our pre-existing assets, and our expected ability to grow the business we acquired by leveraging our pre-existing business experience. We apply a look through method of recording deferred income taxes on the outside book-tax basis differences in our investments. As a result, no deferred income taxes are recorded associated with non-deductible goodwill recorded at the investee level.

(1) BP Products North America Inc. (BP) Terminal Assets

On February 1, 2016, we completed the acquisition of 15 products terminals and associated infrastructure from BP for $349 million, including a transaction deposit paid in 2015 and working capital adjustments paid in 2016. In conjunction with this transaction, we and BP formed a joint venture with an equity ownership interest of 75% and 25%, respectively. Subsequent to the acquisition, we contributed 14 of the acquired terminals to the joint venture, which we operate, and the remaining terminal is solely owned by us. BP acquired its 25% interest in the joint venture for $84 million, which we reported as “Contributions from noncontrolling interests” within our accompanying consolidated statement of cash flows for the year ended December 31, 2016. Of the acquired assets, 10 terminals are included in our Terminals business segment and 5 terminals are included in our Products Pipelines business segment based on synergies with each segment’s respective existing operations.

(2) Vopak Terminal Assets

On February 27, 2015, we acquired three U.S. terminals and one undeveloped site from Royal Vopak (Vopak) for approximately $158 million in cash. The acquisition included (i) a 36-acre, 1,069,500-barrel storage facility at Galena Park, Texas that handles base oils, biodiesel and crude oil and is immediately adjacent to our Galena Park terminal facility; (ii) two terminals in North Carolina: one in North Wilmington that handles chemicals and black oil and the other in South Wilmington that is not currently operating; and (iii) an undeveloped waterfront access site in Perth Amboy, New Jersey. We include the acquired assets as part of our Terminals business segment.

(3) Hiland

On February 13, 2015, we acquired Hiland, a privately held Delaware limited partnership for aggregate consideration of approximately $3,122 million, including assumed debt. Approximately $368 million of the debt assumed was immediately paid down after closing. Hiland’s assets consist primarily of crude oil gathering and transportation pipelines and gas gathering and processing systems, primarily handling production from the Bakken Formation in North Dakota and Montana. The

acquired gathering and processing assets are included in our Natural Gas Pipelines business segment while the acquired crude oil transport pipeline (Double H pipeline) is included in our Products Pipelines business segment. Deferred charges and other relates to customer contracts and relationships with a weighted average amortization period as of the acquisition date of 16.4 years.

(4) Pennsylvania and Florida Jones Act Tankers

On November 5, 2014, we acquired two Jones Act tankers from Crowley Maritime Corporation (Crowley) for approximately $270 million. The MT Pennsylvania and the MT Florida engage in the marine transportation of crude oil, condensate and refined products in the U.S. domestic trade, commonly referred to as the Jones Act trade, and are currently operating pursuant to multi-year charters with a major integrated oil company. The vessels each have approximately 330 MBbl of cargo capacity and are included in our Terminals business segment.

(5) American Petroleum Tankers and State Class Tankers

Effective January 17, 2014, we acquired APT and State Class Tankers (SCT) for aggregate consideration of $961 million in cash (the APT acquisition). APT is engaged in Jones Act trade and its primary assets consist of a fleet of five medium range Jones Act qualified product tankers, each with 330 MBbl of cargo capacity, and each operating pursuant to long-term time charters with high quality counterparties, including major integrated oil companies, major refiners and the U.S. Military Sealift Command. As of the closing date, the vessels’ time charters had an average remaining term of approximately four years, with renewal options to extend the terms by an average of two years.

SCT commissioned the construction of four medium range Jones Act qualified product tankers, by General Dynamics’ NASSCO shipyard, each with 330 MBbl of cargo capacity and were delivered in 2015 and 2016. The time charters for each vessel upon completion had an initial term of five years, with renewal options to extend the term by up to three years. The APT acquisition complements and extends our existing crude oil and refined products transportation and storage business. We include the acquired assets as part of our Terminals business segment.

Asset Purchase

On July 15, 2015, we purchased from Shell US Gas & Power LLC (Shell) its 49% interest in a joint venture, ELC, that was in the pre-construction stage of development for liquefaction facilities at Elba Island, Georgia. The transaction was treated as an asset purchase for the net cash consideration of $185 million. The purchase gives us full ownership and control of ELC. Therefore, we prospectively changed our method of accounting for ELC from the equity method to full consolidation. Shell remains subscribed to 100% of the liquefaction capacity.

Investment Acquisition

On December 10, 2015, we and Brookfield Infrastructure Partners L.P. (Brookfield) acquired from Myria Holdings, Inc. the 53% equity interest in NGPL Holdings LLC not previously owned by us and Brookfield, increasing our ownership to 50% with Brookfield owning the remaining 50%. We paid $136 million for our additional 30% interest in NGPL Holdings LLC. See Note 7 for additional information regarding our equity interests in NGPL Holdings LLC.

Sale of Equity Interest and Terminal Assets

Sale of Equity Interest in SNG

On September 1, 2016, we completed the sale of a 50% interest in our SNG natural gas pipeline system to The Southern Company (Southern Company), receiving proceeds of $1.4 billion, and the formation of a joint venture, which includes our remaining 50% interest in SNG. We used the proceeds from the sale to reduce outstanding debt (see Note 9). We recognized a pre-tax loss of $84 million on the sale of our interest in SNG which is included within “Loss on impairments and divestitures, net” on the accompanying consolidated statement of income for the year ended December 31, 2016. As a result of this transaction, we no longer hold a controlling interest in SNG or Bear Creek Storage Company, LLC (Bear Creek) (50% of which is owned by SNG) and, as such, we now account for our remaining equity interests in SNG and Bear Creek as equity investments.

Terminals Asset Sale

In October 2016, we entered into a definitive agreement to sell 20 bulk terminals to an affiliate of Watco Companies, LLC for approximately $100 million. The terminals are predominantly located along the inland river system and handle mostly coal and steel products, and are included within our Terminals business segment. The sale of seven of the locations closed in the fourth quarter of 2016, for which we received $37 million of the total consideration, with the balance of this transaction expected to close by April 2017 as certain conditions are satisfied. As a result of this transaction, we recognized a pre-tax loss of $81 million, including a $7 million reduction of goodwill, which is included within “Loss on impairments and divestitures, net” on our accompanying December 31, 2016 consolidated statement of income for the year ended December 31, 2016, and we have classified $61 million as held for sale for the remaining thirteen locations which is included within “Other current assets” on our accompanying consolidated balance sheet at December 31, 2016.

  1. Impairments and Losses on Divestitures

During the years ended December 31, 2016, 2015, and 2014, we recorded impairments of certain equity investments, long-lived assets, and intangible assets, and net losses on divestitures totaling $1,013 million, $2,125 million, and $274 million, respectively. These adjustments were precipitated by a period of sustained deterioration in commodity prices which impacted the values of certain of our assets because of lower customer demand and, in the case of our CO2 segment, reduced economics on our oil and gas properties. This lower commodity price environment led us to cancel certain projects that were in progress and divest of certain assets. For two of our equity investments in the Natural Gas Pipelines business segment, we determined that the negative outlook for long-term transportation contracts for those entities resulted in an other than temporary impairment of those investments in 2016 leading to a fair value write-down.

In addition, an interim goodwill impairment test was performed during the fourth quarter of 2015 resulting in a partial impairment of goodwill in our Natural Gas Pipelines Non-Regulated reporting unit of approximately $1,150 million. See Note 8 for further information.

These impairments require management to estimate fair value of these assets. The impairments resulting from decisions to classify assets as held-for-sale are based on the value expected to be realized in the transaction which is generally known at the time. The estimates of fair value are based on Level 3 valuation estimates using industry standard income approach valuation methodologies which include assumptions primarily involving management’s significant judgments and estimates with respect to general economic conditions and the related demand for products handled or transported by our assets as well as assumptions regarding commodity prices, future cash flows based on rate and volume assumptions, terminal values and discount rates. In certain cases, management’s decisions to dispose of certain assets may trigger an impairment. We typically use discounted cash flow analyses to determine the fair value of our assets. We may probability weight various forecasted cash flow scenarios utilized in the analysis as we consider the possible outcomes. We use discount rates representing our estimate of the risk-adjusted discount rates that would be used by market participants specific to the particular asset.

We may identify additional triggering events requiring future evaluations of the recoverability of the carrying value of our long-lived assets, investments and goodwill. Because certain of our assets, including certain equity investments and oil and gas producing properties, have been written down to fair value, any deterioration in fair value relative to our carrying value increases the likelihood of further impairments. Such non-cash impairments could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value is determined to not be fully recoverable.

We recognized the following non-cash pre-tax impairment charges and losses (gains) on divestitures of assets (in millions):

Year Ended December 31,
201620152014
Natural Gas Pipelines
Impairment of goodwill$—$1,150$—
Impairments of long-lived assets(a)10679—
Losses on divestitures of long-lived assets(b)94435
Impairment of equity investments(c)60626—
Impairment at equity investee(d)7——
CO2
Impairments of long-lived assets(e)20606243
Gains on divestitures of long-lived assets(1)——
Impairment at equity investee(d)926—
Terminals
Impairments of long-lived assets(f)19188—
Losses on divestitures of long-lived assets(g)80329
Losses on impairments and divestitures of equity investments, net164—
Products Pipelines
Impairments of long-lived assets(h)66——
Losses (gains) on divestitures of long-lived assets101(3)
Gain on divestiture of equity investment(12)——
Other gains on divestitures of long-lived assets(7)(1)—
Pre-tax losses on impairments and divestitures, net$1,013$2,125$274

(a) 2016 amount represents the project write-off of our portion of the Northeast Energy Direct (NED) Market project. 2015 amount represents $47 million and $32 million of project write-offs in our non-regulated midstream and regulated natural gas pipelines assets, respectively.

(b) 2016 amount primarily relates to our sale of a 50% interest in SNG.

(c) 2016 amount includes a $350 million impairment of our investment in MEP and a $250 million impairment of our investment in Ruby. 2015 amount is primarily related to an impairment of an investment in a gathering and processing asset in Oklahoma.

(d) 2016 and 2015 amounts are losses on impairments recorded by equity investees and included in “Earnings from equity investments” in our accompanying consolidated statements of income.

(e) 2015 amount includes (i) $399 million related to oil and gas properties and (ii) $207 million related to the certain CO2 source and transportation project write-offs. 2014 amount is primarily related to oil and gas properties.

(f) 2015 amount is primarily related to certain terminals with significant coal operations, including a $175 million impairment of a terminal facility reflecting the impact of an agreement to adjust certain payment terms under a contract with a coal customer in February 2016.

(g) 2016 amount primarily relates to an agreement to sell 20 bulk terminals that handle mostly coal and steel products, predominately located along the inland river system. The sale of seven locations closed in the fourth quarter of 2016.

(h) 2016 amount represents project write-offs associated with the canceled Palmetto project.

  1. Income Taxes

The components of “Income Before Income Taxes” are as follows (in millions):

Year Ended December 31,
201620152014
U.S.$1,466$611$2,941
Foreign172161150
Total Income Before Income Taxes$1,638$772$3,091

Components of the income tax provision applicable for federal, foreign and state taxes are as follows (in millions):

Year Ended December 31,
201620152014
Current tax expense (benefit)
Federal$(148)$(125)$(16)
State(28)(7)36
Foreign6413
Total(170)(128)33
Deferred tax expense (benefit)
Federal998653572
State51(4)14
Foreign384329
Total1,087692615
Total tax provision$917$564$648

The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows (in millions, except percentages):

Year Ended December 31,
201620152014
Federal income tax$57335.0%$27135.0%$1,08235.0%
Increase (decrease) as a result of:
State deferred tax rate change110.7%(24)(3.1)%——%
Taxes on foreign earnings281.7%263.5%401.3%
Net effects of consolidating KMP and EPB and other noncontrolling interests(4)(0.3)%152.0%(433)(14.0)%
State income tax, net of federal benefit261.6%121.5%371.2%
Dividend received deduction(48)(2.9)%(51)(6.6)%(50)(1.6)%
Adjustments to uncertain tax positions(23)(1.4)%(14)(1.9)%(5)(0.2)%
Valuation allowance on investment and tax credits342.1%——%612.0%
Disposition of certain international holdings——%——%(112)(3.6)%
Nondeductible goodwill30118.5%32341.7%——%
Other191.1%60.8%280.9%
Total$91756.1%$56472.9%$64821.0%

Deferred tax assets and liabilities result from the following (in millions):

December 31,
20162015
Deferred tax assets
Employee benefits$401$394
Accrued expenses118129
Net operating loss, capital loss and tax credit carryforwards1,3071,344
Derivative instruments and interest rate and currency swaps2245
Debt fair value adjustment74110
Investments2,8043,607
Other143
Valuation allowances(184)(152)
Total deferred tax assets4,5565,480
Deferred tax liabilities
Property, plant and equipment177143
Other2714
Total deferred tax liabilities204157
Net deferred tax assets$4,352$5,323

Deferred Tax Assets and Valuation Allowances: The step-up in tax basis from the Merger Transactions in November 2014 resulted in a deferred tax asset, primarily related to our investment in KMP. As book earnings from our investment in KMP are projected to exceed taxable income (primarily as a result of the partnership’s tax depreciation in excess of book depreciation), the deferred tax asset related to our investment in KMP is expected to be fully realized.

We recorded a full valuation allowance of $61 million against the deferred tax asset at December 31, 2014 related to our investment in NGPL as we concluded it was no longer realizable.

We increased our valuation allowances in 2016 by $32 million, primarily due to $18 million for our foreign tax credits, $10 million for foreign net operating losses, and $4 million for capital losses for which we do not expect to realize a future tax benefit.

We have deferred tax assets of $1,128 million related to net operating loss carryovers, $175 million related to alternative minimum and foreign tax credits, $4 million related to capital loss carryovers and $123 million of valuation allowances related to these deferred tax assets at December 31, 2016. As of December 31, 2015, we had deferred tax assets of $1,005 million related to net operating loss carryovers, $339 million related to alternative minimum and foreign tax credits, and valuation allowances related to these deferred tax assets of $91 million. We expect to generate taxable income beginning in 2020 and utilize all federal net operating loss carryforwards and alternative minimum tax carryforwards by the end of 2025.

Our alternative minimum tax credit carryforwards decreased by $151 million in 2016 as a result of our decision to elect to forgo bonus depreciation on property placed in service in that year. Code Section 168(k)(4) allows for corporate taxpayers with minimum tax credit carryforwards to forgo bonus depreciation and accelerate their use of the credits to reduce tax liability in that same tax year if the amount of the allowable credit exceeds the taxpayer’s tax liability. The corporation may receive a cash refund of the excess notwithstanding that it may not otherwise be paying taxes.

In addition we have unrecorded deferred tax assets of $9 million as of December 31, 2016 related to net operating loss carryovers as a result of the delayed recognition of a windfall tax benefit related to share-based compensation. Upon the adoption of ASU 2016-09, the $9 million unrecorded deferred tax assets will be recorded through a cumulative-effect adjustment to retained earnings.

Expiration Periods for Deferred Tax Assets: As of December 31, 2016, we have U.S. federal net operating loss carryforwards of $2.7 billion, which will expire from 2018 - 2036; state losses of $3.0 billion which will expire from 2017 - 2036; and foreign losses of $183 million, of which approximately $137 million carries over indefinitely and $46 million expires from 2029 - 2036. We also have $153 million of federal alternative minimum tax credits which do not expire; and

approximately $21 million of foreign tax credits, which will expire from 2017 - 2023. Use of a portion of our U.S. federal carryforwards is subject to the limitations provided under Sections 382 and 383 of the Internal Revenue Code as well as the separate return limitation rules of Internal Revenue Service regulations. If certain substantial changes in our ownership occur, there would be an annual limitation on the amount of carryforwards that could be utilized.

Unrecognized Tax Benefits: We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based not only on the technical merits of the tax position based on tax law, but also the past administrative practices and precedents of the taxing authority. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate resolution.

A reconciliation of our gross unrecognized tax benefit excluding interest and penalties is as follows (in millions):

Year Ended December 31,
201620152014
Balance at beginning of period$148$189$209
Additions based on current year tax positions3412
Additions based on prior year tax positions7——
Reductions based on prior year tax positions(1)(6)(3)
Reductions based on settlements with taxing authority(26)(25)(24)
Reductions due to lapse in statute of limitations(9)(14)(5)
Balance at end of period$122$148$189

We recognize interest and/or penalties related to income tax matters in income tax expense. We recognized tax expense of $2 million and a benefit of $4 million and $1 million at December 31, 2016, 2015, and 2014, respectively. As of December 31, 2016, 2015, and 2014, we had $28 million, $24 million and $28 million, respectively, of accrued interest. We had no accrued penalties as of December 31, 2016 and $2 million in accrued penalties as of both December 31, 2015 and 2014. All of the $122 million of unrecognized tax benefits, if recognized, would affect our effective tax rate in future periods. In addition, we believe it is reasonably possible that our liability for unrecognized tax benefits will increase by approximately $2 million during the next year to approximately $124 million, primarily due to additions for state filing positions taken in prior years.

We are subject to taxation, and have tax years open to examination for the periods 2011-2015 in the U.S., 2002-2015 in various states and 2007-2015 in various foreign jurisdictions.

  1. Property, Plant and Equipment, net

Classes and Depreciation

As of December 31, 2016 and 2015, our property, plant and equipment, net consisted of the following (in millions):

December 31,
20162015
Pipelines (Natural gas, liquids, crude oil and CO2)$19,341$19,855
Equipment (Natural gas, liquids, crude oil, CO2, and terminals)23,29822,979
Other(a)4,7804,719
Accumulated depreciation, depletion and amortization(12,306)(10,851)
35,11336,702
Land and land rights-of-way1,4311,450
Construction work in process2,1612,395
Property, plant and equipment, net$38,705$40,547

(a) Includes buildings, computer and communication equipment, vessels, linefill and other.

As of December 31, 2016 and 2015, property, plant and equipment, net included $12,900 million and $16,089 million, respectively, of assets which were regulated by either the FERC or the NEB. Depreciation, depletion, and amortization expense charged against property, plant and equipment was $1,970 million, $2,059 million, and $1,862 million for the years ended December 31, 2016, 2015, and 2014, respectively.

Asset Retirement Obligations

As of December 31, 2016 and 2015, we recognized asset retirement obligations in the aggregate amount of $193 million and $215 million, respectively, of which $9 million were classified as current for each respective period. The majority of our asset retirement obligations are associated with our CO2 business segment, where we are required to plug and abandon oil and gas wells that have been removed from service and to remove the surface wellhead equipment and compressors.

  1. Investments

Our investments primarily consist of equity investments where we hold significant influence over investee actions and for which we apply the equity method of accounting. As of December 31, 2016 and 2015, our investments consisted of the following (in millions):

December 31,
20162015
Citrus Corporation$1,709$1,719
SNG1,505—
Ruby7981,093
Gulf LNG Holdings Group, LLC485516
NGPL Holdings LLC475153
Plantation Pipe Line Company333327
EagleHawk329348
MEP328713
Red Cedar Gathering Company191185
Watco Companies, LLC180201
Double Eagle Pipeline LLC151158
FEP101116
Liberty Pipeline Group LLC7579
Bear Creek Storage61—
Sierrita Gas Pipeline LLC5760
Utopia Holding LLC55—
Fort Union Gas Gathering L.L.C.2550
Parkway Pipeline LLC—131
All others169183
Total equity investments7,0276,032
Bond investments—8
Total investments$7,027$6,040

As shown in the table above, our significant equity investments, as of December 31, 2016 consisted of the following:

•Citrus Corporation—We own a 50% interest in Citrus Corporation, the sole owner of Florida Gas Transmission Company, L.L.C. (Florida Gas). Florida Gas transports natural gas to cogeneration facilities, electric utilities, independent power producers, municipal generators, and local distribution companies through a 5,300-mile natural gas pipeline. Energy Transfer Partners L.P. operates Florida Gas and owns the remaining 50% interest in Citrus;
•SNG—Effective September 1, 2016, we operate SNG and own a 50% interest in SNG; and Evergreen Enterprise Holdings, LLC, a subsidiary of Southern Company, owns the remaining 50% interest.
•Ruby—We operate Ruby and own the common interest in Ruby, the sole owner of the Ruby Pipeline natural gas transmission system. Veresen Inc. owns the remaining interest in Ruby in the form of a convertible preferred interest. If Veresen converted its preferred interest into common interest, we and Veresen would each own a 50% common interest in Ruby;
•Gulf LNG Holdings Group, LLC—We operate Gulf LNG Holdings Group, LLC and own a 50% interest in Gulf LNG Holdings Group, LLC, the owner of a LNG receiving, storage and regasification terminal near Pascagoula, Mississippi, as well as pipeline facilities to deliver vaporized natural gas into third party pipelines for delivery into various markets around the country. The remaining 50% interest is owned by a variety of investment entities including subsidiaries of GE Financial Services and The Blackstone Group L.P.;
•NGPL Holdings LLC— We operate NGPL Holdings LLC and own a 50% interest in NGPL Holdings LLC, the indirect owner of NGPL and certain affiliates, collectively referred to in this report as NGPL, a major interstate natural gas pipeline and storage system. The remaining 50% interest is owned by Brookfield;
•Plantation—We operate Plantation and own a 51.17% interest in Plantation, the sole owner of the Plantation refined petroleum products pipeline system. A subsidiary of Exxon Mobil Corporation owns the remaining interest. Each investor has an equal number of directors on Plantation’s board of directors, and board approval is required for certain corporate actions that are considered substantive participating rights; therefore, we do not control Plantation, and account for the investment under the equity method;
•BHP Billiton Petroleum (Eagle Ford) LLC, (EagleHawk)—We own a 25% interest in EagleHawk, the sole owner of natural gas and condensate gathering systems serving the producers of the Eagle Ford shale formation. A subsidiary of BHP Billiton Petroleum operates EagleHawk and owns the remaining 75% ownership interest;
•MEP—We operate MEP and own a 50% interest in MEP, the sole owner of the Midcontinent Express natural gas pipeline system. The remaining 50% ownership interest is owned by subsidiaries of Energy Transfer Partners L.P.;
•Red Cedar Gathering Company—We own a 49% interest in Red Cedar Gathering Company, the sole owner of the Red Cedar natural gas gathering, compression and treating system. The Southern Ute Indian Tribe owns the remaining 51% interest and serves as operator of Red Cedar;
•Watco Companies, LLC—We hold a preferred and common equity investment in Watco Companies, LLC, the largest privately held short line railroad company in the U.S. We own 100,000 Class A and 50,000 Class B preferred shares and pursuant to the terms of the investment, receive priority, cumulative cash and stock distributions from the preferred shares at a rate of 3.25% and 3.00% per quarter, respectively, and participate partially in additional profit distributions at a rate equal to 0.4%. Neither class holds any voting powers, but do provide us certain approval rights, including the right to appoint one of the members to Watco’s board of managers. In addition to the senior interests, we also hold approximately 13,000 common equity units, which represents a 3.4% common ownership that is accounted for under the equity method of accounting;
•Double Eagle Pipeline LLC - We own a 50% equity interest in Double Eagle Pipeline LLC. The remaining 50% interest is owned by Magellan Midstream Partners;
•FEP —We own a 50% interest in FEP, the sole owner of the Fayetteville Express natural gas pipeline system. Energy Transfer Partners, L.P. owns the remaining 50% interest and serves as operator of FEP;
•Liberty Pipeline Group, LLC (Liberty) —We own a 50% interest in Liberty. ETC NGL Transport, LLC, a subsidiary of Energy Transfer Partners, L.P. owns the remaining 50% interest and serves as operator of Liberty;
•Bear Creek Storage—We own a 50% interest in Bear Creek through TGP, one of our wholly owned subsidiaries. SNG owns the remaining 50% interest;
•Sierrita Gas Pipeline LLC — We operate Sierrita Gas Pipeline LLC and own a 35% equity interest in the Sierrita Gas Pipeline LLC. MGI Enterprises U.S. LLC, a subsidiary of PEMEX, owns 35%; and MIT Pipeline Investment Americas, Inc., a subsidiary of Mitsui & Co., Ltd, owns 30%;
•Utopia Holding L.L.C. — We operate Utopia Holding L.L.C. and own a 50% interest in Utopia Holding L.L.C. after the sale of 50% of our interest to Riverstone Investment Group LLC on June 28, 2016;
•Fort Union Gas Gathering LLC—We own a 37.04% equity interest in the Fort Union Gas Gathering LLC. Crestone Powder River LLC, a subsidiary of ONEOK Partners L.P., owns 37.04%; Powder River Midstream, LLC owns 11.11%; and Western Gas Wyoming, LLC owns the remaining 14.81%. Western Gas Resources, Inc. serves as operator of Fort Union Gas Gathering LLC;
•Parkway Pipeline LLC —Prior to the sale of our interest in Parkway, we operated and owned a 50% interest in Parkway Pipeline LLC, the sole owner of the Parkway Pipeline refined petroleum products pipeline system. Valero Energy Corp. owns the remaining 50% interest;
•Cortez Pipeline Company—We operate the Cortez carbon dioxide pipeline system, and as of December 31, 2016, we owned a 50% interest in, the Cortez Pipeline Company, the sole owner of the Cortez carbon dioxide pipeline system.

Our earnings (losses) from equity investments were as follows (in millions):

Year Ended December 31,
201620152014
Citrus Corporation$102$96$97
SNG58——
FEP515555
Gulf LNG Holdings Group, LLC484948
MEP404545
Plantation Pipe Line Company372929
Watco Companies, LLC251613
Red Cedar Gathering Company242633
Cortez Pipeline Company(a)24(3)25
Ruby151815
Parkway Pipeline LLC1458
NGPL Holdings LLC12——
Liberty Pipeline Group LLC1196
EagleHawk1024(7)
Sierrita Gas Pipeline LLC793
Double Eagle Pipeline LLC53(1)
Bear Creek Storage2——
Fort Union Gas Gathering L.L.C.(b)11616
All others111721
Total earnings from equity investments$497$414$406
Amortization of excess costs(59)(51)(45)
(a)2016 and 2015 amounts include $9 million and $26 million, respectively, representing our share of a non-cash impairment charge (pre-tax) recorded by Cortez Pipeline Company.
(b)2016 amount includes non-cash impairment charges of $7 million (pre-tax) related to our investment.

Summarized combined financial information for our significant equity investments (listed or described above) is reported below (in millions; amounts represent 100% of investee financial information):

Year Ended December 31,
Income Statement201620152014
Revenues$4,084$3,857$3,829
Costs and expenses3,0563,4083,063
Net income$1,028$449$766
December 31,
Balance Sheet20162015
Current assets$892$811
Non-current assets22,17019,745
Current liabilities3,5321,009
Non-current liabilities9,18711,227
Partners’/owners’ equity10,3438,320
  1. Goodwill

Changes in the amounts of our goodwill for each of the years ended December 31, 2016 and 2015 are summarized by reporting unit as follows (in millions):

Natural Gas Pipelines RegulatedNatural Gas Pipelines Non-RegulatedCO2Products PipelinesProducts Pipelines TerminalsTerminalsKinder Morgan CanadaTotal
Historical Goodwill$17,527$5,719$1,528$1,908$221$1,573$591$29,067
Accumulated impairment losses(1,643)(447)—(1,197)(70)(679)(377)(4,413)
December 31, 201415,8845,2721,52871115189421424,654
Acquisitions(a)—93—217—11—321
Currency translation——————(35)(35)
Impairment—(1,150)—————(1,150)
December 31, 201515,8844,2151,52892815190517923,790
Currency translation——————66
Divestitures(b)(1,635)————(9)—(1,644)
December 31, 2016$14,249$4,215$1,528$928$151$896$185$22,152
(a)2015 includes $93 million and $217 million, respectively, related to the February 2015 acquisition of Hiland by Natural Gas Pipelines Non-Regulated and Products Pipelines, and $7 million related to the February 2015 acquisition of Vopak terminal assets by Terminals, all of which are discussed in Note 3.
(b)2016 includes $1,635 million related to the sale of a 50% interest in our SNG natural gas pipeline system by Natural Gas Pipelines Regulated to Southern Company and $9 million related to certain terminal divestitures.

Refer to Note 2 “Summary of Significant Accounting Policies—Goodwill” for a description of our accounting for goodwill and Note 4 for further discussion regarding impairments.

We determine the fair value of each reporting unit as of May 31 of each year based primarily on a market approach utilizing enterprise value to estimated EBITDA multiplies of comparable companies. The value of each reporting unit is determined on a stand-alone basis from the perspective of a market participant representing the price estimated to be received in a sale of the reporting unit in an orderly transaction between market participants at the measurement date. As of May 31, 2016, with the exception of our Natural Gas Pipelines Non-Regulated reporting unit, each of our reporting units indicated a fair value in excess of their respective carrying values. The amount of excess fair value over the carrying value ranged from approximately 9% for our Natural Gas Pipelines Regulated reporting unit to 80% for our Products Pipelines Terminals as of May 31, 2016. The results of our Step 2 analysis for our Natural Gas Pipelines Non-Regulated reporting unit did not indicate an impairment of goodwill and we did not identify any triggers for further impairment analysis during the remainder of the year.

Due to the effect of commodity prices on market conditions that impacted the energy sector, during the fourth quarter 2015, we conducted an interim test of the recoverability of goodwill as of December 31, 2015, and concluded that the goodwill of our Natural Gas Pipelines - Non-Regulated reporting unit was impaired by $1.15 billion.

For our Natural Gas Pipelines Non-Regulated and our CO2 reporting units, our May 31, 2016 annual test and our December 31, 2015 interim test included a discounted cash flow analysis (income approach) to evaluate the fair value of these reporting units to

provide additional indication of fair value based on the present value of cash flows these reporting units are expected to generate in the future. We weighted the market and income approaches for these reporting units to arrive at an estimated fair value of these respective reporting units giving more weighting on the income approach and less on the market approach as we believed the values indicated using the income approach are more representative of the value that could be received from a market participant.

The fair value estimates of our reporting unit fair value, and in arriving at the fourth quarter 2015 impairment amount, were based on Level 3 inputs of the fair value hierarchy as discussed in Note 4.

A continued period of volatile commodity prices could result in further deterioration of market multiples, comparable sales transactions prices, weighted average costs of capital, and our cash flow estimates. A significant unfavorable change to any one or combination of these factors would result in a change to the reporting unit fair values discussed above potentially resulting in additional impairments of long-lived assets, equity method investments, and/or goodwill. Such non-cash impairments could have a significant effect on our results of operations.

  1. Debt

We classify our debt based on the contractual maturity dates of the underlying debt instruments. We defer costs associated with debt issuance over the applicable term. These costs are then amortized as interest expense in our accompanying consolidated statements of income.

The following table provides detail on the principal amount of our outstanding debt balances. The table amounts exclude all debt fair value adjustments, including debt discounts, premiums and issuance costs (in millions):

December 31,
20162015
KMI
Unsecured term loan facility, variable rate, due January 26, 2019(a)$1,000$—
Senior notes 1.50% through 8.25%, due 2016 through 2098(b)(c)13,23613,346
Credit facility expiring November 26, 2019——
Commercial paper borrowings——
KMP
Senior notes, 2.65% through 9.00%, due 2016 through 2044(c)19,48519,985
TGP senior notes, 7.00% through 8.375%, due 2016 through 2037(a)(c)1,5401,790
EPNG senior notes, 5.95% through 8.625%, due 2017 through 2032(c)1,1151,115
Copano senior notes, 7.125%, due April 1, 2021(c)(d)—332
CIG senior notes, 4.15% through 6.85%, due 2026 through 2037(c)(e)475100
SNG notes, 4.40% through 8.00%, due 2017 through 2032(c)(f)—1,211
Other Subsidiary Borrowings (as obligor)
Kinder Morgan Finance Company, LLC, senior notes, 5.70% through 6.40%, due 2016 through 2036(a)(c)7861,636
Hiland Partners Holdings LLC, senior notes, 5.50% and 7.25%, due 2020 and 2022(c)(g)225974
EPC Building, LLC, promissory note, 3.967%, due 2016 through 2035433443
Trust I preferred securities, 4.75%, due March 31, 2028(h)221221
KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock(i)100100
Other miscellaneous debt(j)285300
Total debt – KMI and Subsidiaries38,90141,553
Less: Current portion of debt(a)(f)(k)2,696821
Total long-term debt – KMI and Subsidiaries(l)$36,205$40,732
(a)On January 26, 2016, we entered into a $1 billion three-year unsecured term loan facility with a variable interest rate, which is determined in the same manner as interest on our revolving credit facility borrowings. In January 2016, we repaid $850 million of maturing 5.70% senior notes, and in February 2016, we repaid $250 million of maturing 8.00% senior notes primarily using proceeds from the three-year term loan. Since we refinanced a portion of the maturing debt with proceeds from long-term debt, we classified $1 billion of the maturing debt within “Long-term debt” on our consolidated balance sheet as of December 31, 2015.
(b)Amounts include senior notes that are denominated in Euros and have been converted and are respectively reported above at the December 31, 2016 exchange rate of 1.0517 U.S. dollars per Euro and the December 31, 2015 exchange rate of 1.0862 U.S. dollars per Euro. For the year ended December 31, 2016, our debt decreased by $43 million as a result of the change in the exchange rate of U.S dollars per Euro. The decrease in debt due to the changes in exchange rates is offset by a corresponding change in the value of cross-currency swaps reflected in “Deferred charges and other assets” and “ Other long-term liabilities and deferred credits” on our consolidated balance sheets. At the time of issuance, we entered into cross-currency swap agreements associated with these senior notes, effectively converting these Euro-denominated senior notes to U.S. dollars (see Note 14 “Risk Management—Foreign Currency Risk Management”).
(c)Notes provide for the redemption at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make whole premium and are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions.
(d)On September 30, 2016, we repaid the $332 million principal amount of 7.125% senior notes due 2021, plus accrued interest. We recognized a $28.3 million gain from the early extinguishment of debt, included within “Interest, net” on the accompanying consolidated statements of income for the year ended December 31, 2016 consisting of an $11.8 million premium on the debt repaid and a $40.1 million gain from the write-off of unamortized purchase accounting associated with the extinguished debt. Copano continues to be a subsidiary guarantor under a cross guarantee agreement (see Note 19).
(e)On August 16, 2016, CIG completed a private offering of $375 million in principal amount of 4.15% senior notes due August 15, 2026. The net proceeds of $372 million received from the offering were used to reduce debt incurred as the result of the repayment of CIG’s senior notes that matured in 2015 and for general corporate purposes.
(f)Due to the September 1, 2016 sale of a 50% interest in SNG, we no longer consolidate SNG’s accounts in our consolidated financial statements. As of the transaction date, SNG had $1,211 million of debt outstanding (including a current portion of $500 million).
(g)On October 1, 2016, a portion of the proceeds from the sale of a 50% interest in SNG was used to repay the $749 million principal amount of Hiland’s 7.25% senior notes due 2020, plus accrued interest. We recognized a $17.3 million gain from the early extinguishment of debt, included within “Interest, net” on the accompanying consolidated statements of income for the year ended December 31, 2016 consisting of a $27.1 million premium on the debt repaid and a $44.4 million gain from the write-off of unamortized purchase accounting associated with the extinguished debt.
(h)Capital Trust I (Trust I), is a 100%-owned business trust that as of December 31, 2016, had 4.4 million of 4.75% trust convertible preferred securities outstanding (referred to as the Trust I Preferred Securities). Trust I exists for the sole purpose of issuing preferred securities and investing the proceeds in 4.75% convertible subordinated debentures, which are due 2028. Trust I’s sole source of income is interest earned on these debentures. This interest income is used to pay distributions on the preferred securities. We provide a full and unconditional guarantee of the Trust I Preferred Securities. There are no significant restrictions from these securities on our ability to obtain funds from our subsidiaries by distribution, dividend or loan. The Trust I Preferred Securities are non-voting (except in limited circumstances), pay quarterly distributions at an annual rate of 4.75%, carry a liquidation value of $50 per security plus accrued and unpaid distributions and are convertible at any time prior to the close of business on March 31, 2028, at the option of the holder, into the following mixed consideration: (i) 0.7197 of a share of our Class P common stock; (ii) $25.18 in cash without interest; and (iii) 1.100 warrants to purchase a share of our Class P common stock. We have the right to redeem these Trust I Preferred Securities at any time. Because of the substantive conversion rights of the securities into the mixed consideration, we bifurcated the fair value of the Trust I Preferred Securities into debt and equity components and as of December 31, 2016, the outstanding balance of $221 million (of which $111 million was classified as current) was bifurcated between debt ($199 million) and equity ($22 million). During the years ended December 31, 2016 and 2015, 200 and 1,176,015, respectively, of Trust I Preferred Securities had been converted into (i) 143 and 846,369 shares of our Class P common stock; (ii) approximately $5,000 and $30 million in cash; and (iii) 220 and 1,293,615 in warrants, respectively.
(i)As of December 31, 2016 and 2015, KMGP had outstanding, 100,000 shares of its $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock due 2057. Since August 18, 2012, dividends on the preferred stock accumulate at a floating rate of the 3-month LIBOR plus 3.8975% and are payable quarterly in arrears, when and if declared by KMGP’s board of directors, on February 18, May 18, August 18 and November 18 of each year, beginning November 18, 2012. The preferred stock has approval rights over a commencement of or filing of voluntary bankruptcy by KMP or its SFPP or Calnev subsidiaries.
(j)In conjunction with the construction of the Totem Gas Storage facility (Totem) and the High Plains pipeline (High Plains), CIG’s joint venture partner in WYCO funded 50% of the construction costs. Upon project completion, the advances were converted into a financing obligation to WYCO. As of December 31, 2016, the principal amounts of the Totem and High Plains financing obligations were $71 million and $92 million, respectively, which will be paid in monthly installments through 2039 based on the initial lease term. The interest rate on these obligations is 15.5%, payable on a monthly basis.
(k)Amounts include outstanding credit facility and commercial paper borrowings and other debt maturing within 12 months. See “—Maturities of Debt” below.
(l)Excludes our “Debt fair value adjustments” which, as of December 31, 2016 and 2015, increased our combined debt balances by $1,149 million and $1,674 million, respectively. In addition to all unamortized debt discount/premium amounts, debt issuance costs and purchase accounting on our debt balances, our debt fair value adjustments also include amounts associated with the offsetting entry for hedged debt and any unamortized portion of proceeds received from the early termination of interest rate swap agreements. For further information about our debt fair value adjustments, see —“Debt Fair Value Adjustments” below.

We and substantially all of our wholly owned domestic subsidiaries are a party to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement. Also, see Note 19.

Credit Facilities and Restrictive Covenants

On January 26, 2016, we increased the capacity of our revolving credit agreement, initially entered into during 2014, from $4.0 billion to $5.0 billion. The other terms of our revolving credit agreement remain the same. We also maintain a $4.0 billion commercial paper program through the private placement of short-term notes. The notes mature up to 270 days from the date of issue and are not redeemable or subject to voluntary prepayment by us prior to maturity. The notes are sold at par value less a discount representing an interest factor or if interest bearing, at par. Borrowings under our revolving credit facility can be

used for working capital and other general corporate purposes and as a backup to our commercial paper program. Borrowings under our commercial paper program reduce the borrowings allowed under our credit facility.

Our credit facility borrowings bear interest at either (i) LIBOR plus an applicable margin ranging from 1.125% to 2.000% per annum based on our credit ratings or (ii) the greatest of (1) the Federal Funds Rate plus 0.5%; (2) the Prime Rate; and (3) LIBOR Rate for a one month eurodollar loan, plus 1%, plus, in each case, an applicable margin ranging from 0.125% to 1.00% per annum based on our credit rating. As of December 31, 2016, we were in compliance with all required financial covenants.

Our credit facility included the following restrictive covenants as of December 31, 2016:

•total debt divided by earnings before interest, income taxes, depreciation and amortization may not exceed:
•6.50: 1.00, for the period ended on or prior to December 31, 2017; or
•6.25: 1.00, for the period ended after December 31, 2017 and on or prior to December 31, 2018; or
•6.00: 1.00, for the period ended after December 31, 2018;
•certain limitations on indebtedness, including payments and amendments;
•certain limitations on entering into mergers, consolidations, sales of assets and investments;
•limitations on granting liens; and
•prohibitions on making any dividend to shareholders if an event of default exists or would exist upon making such dividend.

As of December 31, 2016, we had no borrowings outstanding under our five-year $5.0 billion revolving credit facility, no borrowings outstanding under our $4.0 billion commercial paper program and $160 million in letters of credit. Our availability under our revolving credit facility as of December 31, 2016 was $4,840 million.

Current Portion of Debt

The primary components of our current portion of debt include the following significant series of long-term notes:

As of December 31, 2016$600 million 6.00% notes due February 2017
$300 million 7.50% notes due April 2017
$355 million 5.95% notes due April 2017
$786 million 7.00% notes due June 2017
$500 million 2.00% notes due December 2017
As of December 31, 2015$500 million 3.50% notes due March 2016

Long-term Debt Issuances, Repayments and Other Significant Changes in Debt

Following are significant long-term debt issuances, repayments and other significant changes made during 2016 and 2015:

20162015
Issuances$1.0 billion unsecured term loan facility due 2019$800 million 5.05% notes due 2046
$375 million 4.15% notes due 2026$815 million 1.50% notes due 2022(a)
$543 million 2.25% notes due 2027(a)
Repayments$850 million 5.70% notes due 2016$300 million 5.625% notes due 2015
$500 million 3.50% notes due 2016$250 million 5.15% notes due 2015
$250 million 8.00% notes due 2016$340 million 6.80% notes due 2015
$67 million 8.25% notes due 2016$375 million 4.10% notes due 2015
$332 million 7.125% notes due 2021
$749 million 7.25% notes due 2020
Other significant changes$1,211 million reduction due to the deconsolidation of SNG, including a current portion of $500 million (see Note 3)$1,413 million assumption of senior notes and other borrowings due to the Hiland acquisition of which $368 million was immediately paid down after closing (see Note 3)(b)
(a)Senior notes are denominated in Euros and are presented above in U.S. dollars at the exchange rate on the issuance date of 1.0862 U.S. dollars per Euro. We entered into cross-currency swap agreements associated with these senior notes (see Note 14—“Risk Management—Foreign Currency Risk Management”).
(b)As of the February 13, 2015 Hiland acquisition date, we assumed (i) $975 million in principal amount of senior notes (which were valued at $1,043 million as of the acquisition date) and (ii) $368 million of other borrowings that were immediately repaid after closing, primarily consisting of borrowings outstanding under a revolving credit facility. The senior notes are subject to our cross guarantee agreement discussed in Note 19.

Maturities of Debt

The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2016, are summarized as follows (in millions):

YearTotal
2017$2,696
20182,328
20193,820
20202,204
20212,422
Thereafter25,431
Total$38,901

Debt Fair Value Adjustments

The carrying value adjustment to debt securities whose fair value is being hedged is included within “Debt fair value adjustments” on our accompanying consolidated balance sheets. “Debt fair value adjustments” also include unamortized debt discount/premiums, purchase accounting debt fair value adjustments, unamortized portion of proceeds received from the early termination of interest rate swap agreements, and debt issuance costs. As of December 31, 2016, the weighted-average amortization period of the unamortized premium from the termination of interest rate swaps was approximately 16 years. The

following table summarizes the “Debt fair value adjustments” included on our accompanying consolidated balance sheets (in millions):

December 31,
Debt Fair Value Adjustments20162015
Purchase accounting debt fair value adjustments$806$1,135
Carrying value adjustment to hedged debt220380
Unamortized portion of proceeds received from the early termination of interest rate swap agreements342397
Unamortized debt discount/premiums(80)(86)
Unamortized debt issuance costs(139)(152)
Total debt fair value adjustments$1,149$1,674

Interest Rates, Interest Rate Swaps and Contingent Debt

The weighted average interest rate on all of our borrowings was 4.95% during 2016 and 4.92% during 2015. Information on our interest rate swaps is contained in Note 14. For information about our contingent debt agreements, see Note 13 “Commitments and Contingent Liabilities—Contingent Debt”).

  1. Share-based Compensation and Employee Benefits

Share-based Compensation

Class P Shares

Kinder Morgan, Inc. Amended and Restated Stock Compensation Plan for Non-Employee Directors

We have a Kinder Morgan, Inc. Amended and Restated Stock Compensation Plan for Non-Employee Directors, in which our eligible non-employee directors participate. The plan recognizes that the compensation paid to each eligible non-employee director is fixed by our board, generally annually, and that the compensation is payable in cash. Pursuant to the plan, in lieu of receiving some or all of the cash compensation, each eligible non-employee director may elect to receive shares of Class P common stock. Each election will be generally at or around the first board meeting in January of each calendar year and will be effective for the entire calendar year. An eligible director may make a new election each calendar year. The total number of shares of Class P common stock authorized under the plan is 250,000. During 2016, 2015 and 2014, we made restricted Class P common stock grants to our non-employee directors of 31,880, 9,580 and 6,210, respectively. These grants were valued at time of issuance at $400,000, $401,000 and $220,000, respectively. All of the restricted stock awards made to non-employee directors vest during a six-month period.

Kinder Morgan, Inc. 2015 Amended and Restated Stock Incentive Plan

The Kinder Morgan, Inc. 2015 Amended and Restated Stock Incentive Plan is an equity awards plan available to eligible employees. The following table sets forth a summary of activity and related balances of our restricted stock awards excluding that issued to non-employee directors (in millions, except share and per share amounts):

Year EndedYear EndedYear Ended
December 31, 2016December 31, 2015December 31, 2014
SharesWeighted Average Grant Date Fair ValueSharesWeighted Average Grant Date Fair ValueSharesWeighted Average Grant Date Fair Value
Outstanding at beginning of period7,645,105$37.917,373,294$37.636,382,885$37.38
Granted2,816,59921.361,488,46738.201,694,66836.01
Vested(1,226,652)38.53(817,797)35.66(460,032)28.84
Forfeited(196,915)35.74(398,859)38.51(244,227)36.39
Outstanding at end of period9,038,137$32.727,645,105$37.917,373,294$37.63

The intrinsic value of restricted stock awards vested during the years ended December 31, 2016, 2015 and 2014 was $25 million, $31 million and $17 million, respectively. Restricted stock awards made to employees have vesting periods ranging from 1 year with variable vesting dates to 10 years. Following is a summary of the future vesting of our outstanding restricted stock awards:

YearVesting of Restricted Shares
20171,476,832
20182,352,443
20194,358,728
2020539,790
2021199,850
Thereafter110,494
Total Outstanding9,038,137

The related compensation costs less estimated forfeitures is generally recognized ratably over the vesting period of the restricted stock awards. Upon vesting, the grants will be paid in our Class P common shares.

During 2016, 2015 and 2014, we recorded $66 million, $52 million and $51 million, respectively, in expense related to restricted stock awards and capitalized approximately $9 million, $15 million and $6 million, respectively. At December 31, 2016 and 2015, unrecognized restricted stock awards compensation costs, less estimated forfeitures, was approximately $133 million and $154 million, respectively.

Pension and Other Postretirement Benefit Plans

Savings Plan

We maintain a defined contribution plan covering eligible U.S. employees. We contribute 5% of eligible compensation for most of the plan participants. Certain plan participants’ contributions and Company contributions are based on collective bargaining agreements. The total expense for our savings plan was approximately $48 million, $46 million, and $42 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Pension Plans

Our U.S. pension plan is a defined benefit plan that covers substantially all of our U.S. employees and provides benefits under a cash balance formula. A participant in the cash balance plan accrues benefits through contribution credits based on a combination of age and years of service, times eligible compensation. Interest is also credited to the participant’s plan account. A participant becomes fully vested in the plan after three years, and may take a lump sum distribution upon termination of employment or retirement. Certain collectively bargained and grandfathered employees continue to accrue benefits through career pay or final pay formulas.

Two of our subsidiaries, Kinder Morgan Canada Inc. and Trans Mountain Pipeline Inc. (as general partner of Trans Mountain Pipeline L.P.), are sponsors of pension plans for eligible Canadian and Trans Mountain pipeline employees. The plans include registered defined benefit pension plans, supplemental unfunded arrangements (which provide pension benefits in excess of statutory limits) and defined contributory plans. Benefits under the defined benefit components accrue through career pay or final pay formulas. The net periodic benefit costs, contributions and liability amounts associated with our Canadian plans are not material to our consolidated income statements or balance sheets; however, we began to include the activity and balances associated with our Canadian plans (including our Canadian OPEB plans discussed below) in the following disclosures on a prospective basis beginning in 2016. The associated net periodic benefit costs for these combined Canadian plans of $12 million and $10 million for the years ended December 31, 2015 and 2014, respectively, were reported separately in prior years.

Other Postretirement Benefit Plans

We and certain of our U.S. subsidiaries provide other postretirement benefits (OPEB), including medical benefits for closed groups of retired employees and certain grandfathered employees and their dependents, and limited postretirement life insurance benefits for retired employees. Our Canadian subsidiaries also provide OPEB benefits to current and future retirees and their dependents. Medical benefits under these OPEB plans may be subject to deductibles, co-payment provisions, dollar

caps and other limitations on the amount of employer costs, and we reserve the right to change these benefits. Effective January 1, 2014, the U.S. plans were amended to provide a fixed subsidy to post-age 65 Medicare eligible participants to purchase coverage through a retiree Medicare exchange.

Additionally, our subsidiary SFPP has incurred certain liabilities for postretirement benefits to certain current and former employees, their covered dependents, and their beneficiaries. However, the net periodic benefit costs, contributions and liability amounts associated with the SFPP postretirement benefit plan are not material to our consolidated income statements or balance sheets.

Benefit Obligation, Plan Assets and Funded Status. The following table provides information about our pension and OPEB plans as of and for each of the years ended December 31, 2016 and 2015 (in millions):

Pension BenefitsOPEB
2016201520162015
Change in benefit obligation:
Benefit obligation at beginning of period$2,654$2,804$509$624
Service cost36331—
Interest cost89991621
Actuarial loss (gain)127(109)(42)(101)
Benefits paid(180)(173)(41)(39)
Participant contributions3—22
Medicare Part D subsidy receipts——12
Exchange rate changes4—1—
Other(a)151—26—
Benefit obligation at end of period2,8842,654473509
Change in plan assets:
Fair value of plan assets at beginning of period2,0502,377325389
Actual return (loss) on plan assets157(204)29(45)
Employer contributions8501616
Participant contributions3—22
Medicare Part D subsidy receipts——12
Benefits paid(180)(173)(41)(39)
Exchange rate changes3———
Other(a)119———
Fair value of plan assets at end of period2,1602,050332325
Funded status - net liability at December 31,$(724)$(604)$(141)$(184)
(a)2016 amounts represent December 31, 2015 balances associated with our Canadian pension and OPEB plans and Plantation Pipeline OPEB plan for prospective inclusion in these disclosures, which associated net periodic benefit costs were reported separately in prior years.

Components of Funded Status. The following table details the amounts recognized in our balance sheet at December 31, 2016 and 2015 related to our pension and OPEB plans (in millions):

Pension BenefitsOPEB
2016201520162015
Non-current benefit asset(a)$—$—$153$139
Current benefit liability——(16)(16)
Non-current benefit liability(a)(724)(604)(278)(307)
Funded status - net liability at December 31,$(724)$(604)$(141)$(184)
(a)2016 OPEB amount includes $29 million of non-current benefit assets and $12 million of non-current benefit liabilities related to plans we sponsor which are associated with employee services provided to unconsolidated joint ventures, and for which we have recorded an offsetting related party deferred charge/credit.

Components of Accumulated Other Comprehensive (Loss) Income. The following table details the amounts of pre-tax accumulated other comprehensive (loss) income at December 31, 2016 and 2015 related to our pension and OPEB plans which are included on our accompanying consolidated balance sheets, including the portion attributable to our noncontrolling interests, (in millions):

Pension BenefitsOPEB
2016201520162015
Unrecognized net actuarial (loss) gain$(682)$(558)$69$23
Unrecognized prior service (cost) credit(5)(4)1819
Accumulated other comprehensive (loss) income$(687)$(562)$87$42

We anticipate that approximately $44 million of pre-tax accumulated other comprehensive loss will be recognized as part of our net periodic benefit cost in 2017, including approximately $45 million of unrecognized net actuarial loss and approximately $1 million of unrecognized prior service credit.

Our accumulated benefit obligation for our pension plans was $2,834 million and $2,615 million at December 31, 2016 and 2015, respectively.

Our accumulated postretirement benefit obligation for our OPEB plans, whose accumulated postretirement benefit obligations exceeded the fair value of plan assets, was $415 million and $444 million at December 31, 2016 and 2015, respectively. The fair value of these plans’ assets was approximately $121 million at both December 31, 2016 and 2015.

Plan Assets. The investment policies and strategies are established by the Fiduciary Committee for the assets of each of the U.S. pension and OPEB plans and by the Pension Committee for the assets of the Canadian pension plans (the “Committees”), which are responsible for investment decisions and management oversight of the plans. The stated philosophy of each of the Committees is to manage these assets in a manner consistent with the purpose for which the plans were established and the time frame over which the plans’ obligations need to be met. The objectives of the investment management program are to (1) meet or exceed plan actuarial earnings assumptions over the long term and (2) provide a reasonable return on assets within established risk tolerance guidelines and to maintain the liquidity needs of the plans with the goal of paying benefit and expense obligations when due. In seeking to meet these objectives, the Committees recognize that prudent investing requires taking reasonable risks in order to raise the likelihood of achieving the targeted investment returns. In order to reduce portfolio risk and volatility, the Committees have each adopted a strategy of using multiple asset classes.

As of December 31, 2016, the allowable range for asset allocations in effect for our U.S. pension plan were 34% to 59% equity, 37% to 57% fixed income, 0% to 5% cash, 0% to 2% alternative investments and 0% to 10% company securities (KMI Class P common stock). As of December 31, 2016, the allowable range for asset allocations in effect for our U.S. retiree medical and retiree life insurance plans were 15% to 55% equity, 15% to 47% fixed income, 0% to 20% cash and 13% to 39% master limited partnerships. As of December 31, 2016, the allowable range for asset allocations in effect for our Canadian pension plans were 0% to 55% equity and 45% to 100% fixed income.

Below are the details of our pension and OPEB plan assets by class and a description of the valuation methodologies used for assets measured at fair value.

•Level 1 assets’ fair values are based on quoted market prices for the instruments in actively traded markets. Included in this level are cash, equities, exchange traded mutual funds and master limited partnerships. These investments are valued at the closing price reported on the active market on which the individual securities are traded.
•Level 2 assets’ fair values are primarily based on pricing data representative of quoted prices for similar assets in active markets (or identical assets in less active markets). Included in this level are short-term investment funds, fixed income securities and derivatives. Short-term investment funds are valued at amortized cost, which approximates fair value. The fixed income securities’ fair values are primarily based on an evaluated price which is based on a compilation of primarily observable market information or a broker quote in a non-active market. Derivatives are exchange-traded through clearinghouses and are valued based on these prices.
•Level 3 assets’ fair values are calculated using valuation techniques that require inputs that are both significant to the fair value measurement and are unobservable, or are similar to Level 2 assets. Included in this level are guaranteed

insurance contracts and immediate participation guarantee contracts. These contracts are valued at contract value, which approximates fair value.

•Plan assets with fair values that are based on the net asset value per share, or its equivalent (NAV), as reported by the issuers are determined based on the fair value of the underlying securities as of the valuation date and include common/collective trust funds, private investment funds, limited partnerships, and fixed income trusts. These amounts are not categorized within the fair value hierarchy described above, but are separately identified in the following tables.

Listed below are the fair values of our pension and OPEB plans’ assets that are recorded at fair value by class and categorized by fair value measurement used at December 31, 2016 and 2015 (in millions):

Pension Assets
20162015
Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Measured within fair value hierarchy
Cash$10$—$—$10$15$—$—$15
Short-term investment funds—100—100—110—110
Mutual funds(a)197——19770——70
Equities(b)283——283271——271
Fixed income securities—428—428—449—449
Immediate participation guarantee contract——1616——1515
Derivatives—(2)—(2)—(14)—(14)
Subtotal$490$526$161,032$356$545$15916
Measured at NAV(c)
Common/collective trusts(d)829775
Private investment funds(e)290347
Private limited partnerships(f)912
Subtotal1,1281,134
Total plan assets fair value$2,160$2,050
(a)For 2016 and 2015, this category includes mutual funds which are invested in equity.
(b)Plan assets include $126 million and $91 million of KMI Class P common stock for 2016 and 2015, respectively.
(c)Plan assets for which fair value was measured using NAV as a practical expedient.
(d)Common/collective trust funds were invested in approximately 39% fixed income and 61% equity in 2016 and 45% fixed income and 55% equity in 2015.
(e)Private investment funds were invested in approximately 54% fixed income and 46% equity in 2016 and 46% fixed income and 54% equity in 2015.
(f)Private limited partnerships were invested in real estate, venture and buyout funds for 2016 and 2015.
OPEB Assets
20162015
Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Measured within fair value hierarchy
Short-term investment funds$—$15$—$15$—$16$—$16
Equities11——118——8
Master limited partnerships57——5751——51
Guaranteed insurance contracts——4747——4949
Mutual funds1——11——1
Subtotal$69$15$47131$60$16$49125
Measured at NAV(a)
Common/collective trusts(b)6871
Fixed income trusts6458
Limited partnerships(c)6971
Subtotal201200
Total plan assets fair value$332$325
(a)Plan assets for which fair value was measured using NAV as a practical expedient.
(b)Common/collective trust funds which are invested in approximately 72% equity and 28% fixed income securities for 2016 and 67% equity and 33% fixed income securities for 2015.
(c)For 2016 and 2015, limited partnerships were invested in global equity securities.

The following tables present the changes in our pension and OPEB plans’ assets included in Level 3 for the years ended December 31, 2016 and 2015 (in millions):

Pension Assets
Balance at Beginning of PeriodTransfers In (Out)Realized and Unrealized Gains (Losses), netPurchases (Sales), netBalance at End of Period
2016
Insurance contracts$15$—$1$—$16
2015
Insurance contracts$15$—$—$—$15
OPEB Assets
Balance at Beginning of PeriodTransfers In (Out)Realized and Unrealized Gains (Losses), netPurchases (Sales), netBalance at End of Period
2016
Insurance contracts$49$—$(2)$—$47
2015
Insurance contracts$51$—$(1)$(1)$49

Changes in the underlying value of Level 3 assets due to the effect of changes of fair value were immaterial for the years ended December 31, 2016 and 2015.

Expected Payment of Future Benefits and Employer Contributions. As of December 31, 2016, we expect to make the following benefit payments under our plans (in millions):

Fiscal yearPension BenefitsOPEB(a)
2017$235$39
201823738
201923239
202023137
202122037
2022 - 20261,016168
(a)Includes a reduction of approximately $3 million in each of the years 2017 - 2021 and approximately $16 million in aggregate for 2022 - 2026 for an expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.

In 2017, we expect to contribute approximately $22 million to our U.S. pension plan and $7 million, net of anticipated subsidies, to our U.S. OPEB plans. In 2017, we expect to contribute approximately $8 million to our Canadian pension plans and $1 million to our Canadian OPEB plan.

Actuarial Assumptions and Sensitivity Analysis. Benefit obligations and net benefit cost are based on actuarial estimates and assumptions. The following table details the weighted-average actuarial assumptions used in determining our benefit obligation and net benefit costs of our pension and OPEB plans for 2016, 2015 and 2014:

Pension BenefitsOPEB
201620152014201620152014
Assumptions related to benefit obligations:
Discount rate3.83%4.05%3.66%3.69%3.91%3.56%
Rate of compensation increase3.52%3.50%4.50%n/an/an/a
Assumptions related to benefit costs:
Discount rate for benefit obligations4.05%3.66%4.45%3.91%3.56%4.34%
Discount rate for interest on benefit obligations3.24%3.66%4.45%3.18%3.56%4.34%
Discount rate for service cost4.15%3.66%4.45%4.36%3.56%4.34%
Discount rate for interest on service cost3.50%3.66%4.45%4.17%3.56%4.34%
Expected return on plan assets(a)7.31%7.50%7.50%7.07%7.08%7.43%
Rate of compensation increase3.51%4.50%3.50%n/an/an/a
(a)The expected return on plan assets listed in the table above is a pre-tax rate of return based on our targeted portfolio of investments. For the OPEB assets subject to unrelated business income taxes (UBIT), we utilize an after-tax expected return on plan assets to determine our benefit costs, which is based on a UBIT rate of 21% for 2016, 2015 and 2014.

For years prior to 2016, we selected our discount rates by matching the timing and amount of our expected future benefit payments for our pension and other postretirement benefit obligations to the average yields of various high-quality bonds with corresponding maturities. Effective January 1, 2016, we changed our estimate of the service and interest cost components of net periodic benefit cost (credit) for our pension and other postretirement benefit plans. The new estimate utilizes a full yield curve approach in the estimation of these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to their underlying projected cash flows. The new estimate provides a more precise measurement of service and interest costs by improving the correlation between projected benefit cash flows and their corresponding spot rates. The change did not affect the measurement of our pension and postretirement benefit obligations and it was accounted for as a change in accounting estimate, which was applied prospectively. The expected long-term rates of return on plan assets were determined by combining a review of the historical returns realized within the portfolio, the investment strategy included in the plans’ investment policy, and capital market projections for the asset classes in which the portfolio is invested and the target weightings of each asset class.

Actuarial estimates for our OPEB plans assumed a weighted-average annual rate of increase in the per capita cost of covered health care benefits of 9.30%, gradually decreasing to 4.54% by the year 2038. Assumed health care cost trends have a

significant effect on the amounts reported for OPEB plans. A one-percentage point change in assumed health care cost trends would have the following effects as of December 31, 2016 and 2015 (in millions):

20162015
One-percentage point increase:
Aggregate of service cost and interest cost$1$2
Accumulated postretirement benefit obligation2731
One-percentage point decrease:
Aggregate of service cost and interest cost$(1)$(1)
Accumulated postretirement benefit obligation(23)(27)

Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income. For each of the years ended December 31, the components of net benefit cost and other amounts recognized in pre-tax other comprehensive income related to our pension and OPEB plans are as follows (in millions):

Pension BenefitsOPEB
201620152014201620152014
Components of net benefit cost:
Service cost$36$33$21$1$—$—
Interest cost8999112162125
Expected return on assets(151)(172)(171)(19)(23)(24)
Amortization of prior service cost (credit)1——(3)(3)(2)
Amortization of net actuarial loss (gain)355——1(1)
Net benefit (credit) cost(a)10(35)(38)(5)(4)(2)
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
Net loss (gain) arising during period116267285(48)(49)10
Prior service cost (credit) arising during period——————
Amortization or settlement recognition of net actuarial loss(34)(5)——(1)—
Amortization of prior service credit———111
Exchange rate changes1—————
Total recognized in total other comprehensive (income) loss83262285(47)(49)11
Total recognized in net benefit cost (credit) and other comprehensive (income) loss$93$227$247$(52)$(53)$9
(a)2016 OPEB amount includes $4 million of net benefit credits related to plans that we sponsor that are associated with employee services provided to unconsolidated joint ventures. We charge or refund these costs or credits associated with these plans to the joint venture as an offset to our net benefit cost or credit and receive our proportionate share of these costs or credits through our share of the equity investee’s earnings.

Multiemployer Plans

We participate in several multi-employer pension plans for the benefit of employees who are union members. We do not administer these plans and contribute to them in accordance with the provisions of negotiated labor contracts. Other benefits include a self-insured health and welfare insurance plan and an employee health plan where employees may contribute for their dependents’ health care costs. Amounts charged to expense for these plans were approximately $8 million, $10 million and $13 million for the years ended December 31, 2016, 2015 and 2014, respectively. We consider the overall multi-employer pension plan liability exposure to be minimal in relation to the value of its total consolidated assets and net income.

  1. Stockholders’ Equity

Common Equity

As of December 31, 2016, our common equity consisted of our Class P common stock.

During the years 2014 through 2015, as authorized by our board of directors under various repurchase programs, we repurchased shares and warrants. As of December 31, 2016, we had $90 million of availability to repurchase warrants. During the years ended December 31, 2015 and 2014, we paid a total of $12 million and $98 million, respectively, for the repurchase of warrants. During the year ended December 31, 2014, we repurchased $94 million of our Class P shares.

On December 19, 2014, we entered into an equity distribution agreement authorizing us to issue and sell through or to the managers party thereto, as sales agents and/or principals, shares of our Class P common stock having an aggregate offering of up to $5.0 billion from time to time during the term of this agreement. During the year ended December 31, 2015, we issued and sold 102,614,508 shares of our Class P common stock pursuant to the equity distribution agreement resulting in net proceeds of $3.9 billion.

Common Dividends

Holders of our common stock participate in any dividend declared by our board of directors, subject to the rights of the holders of any outstanding preferred stock. The following table provides information about our per share dividends:

Year Ended December 31,
201620152014
Per common share cash dividend declared for the period$0.50$1.605$1.74
Per common share cash dividend paid in the period0.501.931.70

On January 18, 2017, our board of directors declared a cash dividend of $0.125 per common share for the quarterly period ended December 31, 2016, which is payable on February 15, 2017 to shareholders of record as of February 1, 2017.

Warrants

Each of our warrants entitles the holder to purchase one share of our common stock for an exercise price of $40 per share, payable in cash or by cashless exercise, at any time until May 25, 2017. The table below sets forth the changes in our outstanding warrants:

Warrants
201620152014
Beginning balance293,263,797298,135,976347,933,107
Warrants issued with conversions of EP Trust I Preferred securities(a)—1,293,6154,315
Warrants exercised—(71,268)(18,040)
Warrants repurchased and canceled—(6,094,526)(49,783,406)
Ending balance293,263,797293,263,797298,135,976
(a)See Note 9.

Mandatory Convertible Preferred Stock

On October 30, 2015, we completed an offering of 32,000,000 depositary shares, each of which represents a 1/20th interest in a share of our 1,600,000 shares of 9.75% Series A mandatory convertible preferred stock, with a liquidating preference of $1,000 per share (equal to a $50 liquidation preference per depositary share). Net proceeds, after underwriting discount and expenses, from the depositary share offering were approximately $1,541 million. The proceeds from the offering were used to repay borrowings under our revolving credit facility and commercial paper debt and for general corporate purposes.

Unless converted earlier at the option of the holders, on or around October 26, 2018, each share of convertible preferred stock will automatically convert into between 30.8800 and 36.2840 shares of our common stock (and, correspondingly, each

depositary share will convert into between 1.5440 and 1.8142 shares of our common stock), subject to customary anti-dilution adjustments. The conversion range depends on the volume-weighted average price of our common stock over a 20 trading day averaging period immediately prior to that date (Applicable Market Value). If the Applicable Market Value for our common stock is greater than $32.38 or less than $27.56, the conversion rate per preferred stock will be 30.8800 or 36.2840, respectively. If the Applicable Market Value is between $32.38 and $27.56, the conversion rate per preferred stock will be between 30.8800 and 36.2840.

Preferred Dividends

Dividends on our mandatory convertible preferred stock are payable on a cumulative basis when, as and if declared by our board of directors (or an authorized committee thereof) at an annual rate of 9.75% of the liquidation preference of $1,000 per share on January 26, April 26, July 26 and October 26 of each year, commencing on January 26, 2016 to, and including, October 26, 2018. We may pay dividends in cash or, subject to certain limitations, in shares of common stock or any combination of cash and shares of common stock. The terms of the mandatory convertible preferred stock provide that, unless full cumulative dividends have been paid or set aside for payment on all outstanding mandatory convertible preferred stock for all prior dividend periods, no dividends may be declared or paid on common stock.

On October 19, 2016, our board of directors declared a cash dividend of $24.375000 per share of our mandatory convertible preferred stock (equivalent of $1.218750 per depositary share) for the period from and including October 26, 2016 through and including January 25, 2017, which was paid on January 26, 2017 to mandatory convertible preferred shareholders of record as of January 11, 2017.

Noncontrolling Interests

Contributions

Prior to the completion of the Merger Transactions on November 26, 2014, contributions from our noncontrolling interests consisted primarily of equity issuances to the public of common units or shares by KMP, EPB and KMR. Each of these subsidiaries had an equity distribution agreement in place which allowed the subsidiary to sell its equity interests from time to time through a designated sales agent. The equity distribution agreement provided the subsidiary with the right, but not the obligation to offer and sell its equity units or shares, at prices to be determined by market conditions. For the period from January 1, 2014 to November 26, 2014, KMP, EPB and KMR made equity issuances of 30 million units or shares, resulting in net proceeds of $1,695 million. These equity issuances had the associated effects of increasing our (i) noncontrolling interests by $1,640 million; (ii) accumulated deferred income taxes by $19 million; and (iii) additional paid-in capital by $36 million.

Distributions

The following table provides information about distributions from our noncontrolling interests (in millions except per unit and i-unit distribution amounts):

Year Ended December 31, 2014
KMP(a)
Per unit cash distribution declared for the period$4.17
Per unit cash distribution paid in the period$5.53
Cash distributions paid in the period to the public$1,654
EPB(a)
Per unit cash distribution declared for the period$1.95
Per unit cash distribution paid in the period$2.60
Cash distributions paid in the period to the public$347
KMR(a)(b)
Share distributions paid in the period to the public7,794,183
(a)As a result of the Merger Transactions, no distribution was declared starting with the fourth quarter of 2014.
(b)KMR’s distributions were paid in the form of additional shares or fractions thereof calculated by dividing the KMP cash distribution per common unit by the average of the market closing prices of a KMR share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for the shares. Represents share distributions made in the period to noncontrolling interests and excludes 1,127,712 of shares distributed in 2014 on KMR shares we directly and indirectly owned.
  1. Related Party Transactions

Affiliate Balances

The following tables summarize our affiliate balance sheet balances and income statement activity (in millions):

December 31,
20162015
Balance sheet location
Accounts receivable, net$37$25
Other current assets—36
Deferred charges and other assets10—
$47$61
Current portion of debt$6$6
Accounts payable2822
Other current liabilities910
Long-term debt161167
Other long-term liabilities and deferred credits29—
$233$205
Year Ended December 31,
201620152014
Income statement location
Revenues
Services$71$72$29
Product sales and other717186
$142$143$115
Operating Costs, Expenses and Other
Costs of sales$38$60$74
Other operating expenses755557

Notes Receivable

Plantation

In March 2016, we received the final principal payment of $35 million for our proportionate share of a note receivable due from Plantation. We own a 51.17% equity interest in Plantation and the $35 million note receivable balance for our proportionate share of the note was included within “Other current assets” on our accompanying consolidated balance sheet as of December 31, 2015.

Subsequent Event

MEP Loan Agreement

On February 3, 2017 we renewed our $40 million loan agreement for an additional one-year term with MEP, our 50%-owned equity investee. The loan agreement allows us, at our sole option, to make loans from time to time to MEP to fund its working capital needs and for other LLC purposes. Borrowings under the loan agreement bear interest at a rate of one month LIBOR plus 1.50%, and all borrowings can be prepaid before maturity without penalty or premium. As of both December 31, 2016 and 2015 there was no amount outstanding pursuant to this loan agreement.

  1. Commitments and Contingent Liabilities

Leases and Rights-of-Way Obligations

The table below depicts future gross minimum rental commitments under our operating leases and rights-of-way obligations as of December 31, 2016 (in millions):

YearCommitment
2017$106
201894
201986
202075
202161
Thereafter342
Total minimum payments$764

The remaining terms on our operating leases, including probable elections to exercise renewal options, range from one to forty-one years. Total lease and rental expenses were $138 million, $143 million and $114 million for the years ended December 31, 2016, 2015 and 2014, respectively. The amount of capital leases included within “Property, plant and equipment, net” in our accompanying consolidated balance sheets as of December 31, 2016 and 2015 is not material to our consolidated balance sheets.

Contingent Debt

Our contingent debt disclosures pertain to certain types of guarantees or indemnifications we have made and cover certain types of guarantees included within debt agreements, even if the likelihood of requiring our performance under such guarantee is remote.

As of December 31, 2016 and 2015, our contingent debt obligations, as well as our obligations with respect to related letters of credit, totaled $1,179 million and $1,202 million, respectively. Both December 31, 2016 and 2015 amounts are primarily represented by our proportional share of the debt obligations of two equity investees. Under such guarantees we are severally liable for our percentage ownership share of these equity investees’ debt issued in the event of their non-performance. Also included in our contingent debt obligations is a guarantee of the debt obligations of our 50%-owned investee, Cortez Pipeline Company. We are severally liable for 50% (our percentage ownership share) of the Cortez Pipeline Company debt which includes a $50 million credit facility and $100 million in bonds. In addition, we are liable for 100% of the debt issued by one of Cortez Pipeline Company’s subsidiaries in the event of their non-performance which has a $100 million credit facility and $120 million private placement note to fund an expansion project.

Guarantees and Indemnifications

We are involved in joint ventures and other ownership arrangements that sometimes require financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. We also periodically provide indemnification arrangements related to assets or businesses we have sold. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes and environmental matters.

While many of these agreements may specify a maximum potential exposure, or a specified duration to the indemnification obligation, there are also circumstances where the amount and duration are unlimited. Currently, we are not subject to any material requirements to perform under quantifiable arrangements, and we expect future requirements to perform under quantifiable arrangements will be immaterial. We are unable to estimate a maximum exposure for our guarantee and indemnification agreements that do not provide for limits on the amount of future payments due to the uncertainty of these exposures.

See Note 17 “Litigation, Environmental and Other Contingencies” for a description of matters that we have identified as contingencies requiring accrual of liabilities and/or disclosure, including any such matters arising under guarantee or indemnification agreements.

Commitment for Jones Act Trade Fleet Expansion

Under an August 2015 definitive construction agreement with Philly Tankers LLC, we are expected to have four more Jones Act tankers delivered by the end of 2017. Our obligation for payments due under the terms of this agreement total $383 million in 2017, of which, approximately $195 million relates to work not yet performed as of December 31, 2016.

  1. Risk Management

Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, NGL and crude oil. We also have exposure to interest rate and foreign currency risk as a result of the issuance of our debt obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to certain of these risks. In addition, prior to May 2016, we had power forward and swap contracts related to legacy operations of acquired businesses.

Energy Commodity Price Risk Management

As of December 31, 2016, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:

Net open position long/(short)
Derivatives designated as hedging contracts
Crude oil fixed price(19.7)MMBbl
Crude oil basis(1.3)MMBbl
Natural gas fixed price(38.4)Bcf
Natural gas basis(19.3)Bcf
Derivatives not designated as hedging contracts
Crude oil fixed price(1.7)MMBbl
Crude oil basis(0.1)MMBbl
Natural gas fixed price(5.2)Bcf
Natural gas basis(1.4)Bcf
NGL and other fixed price(5.0)MMBbl

As of December 31, 2016, the maximum length of time over which we have hedged, for accounting purposes, our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2020.

Interest Rate Risk Management

As of December 31, 2016, we had a combined notional principal amount of $9,775 million of fixed-to-variable interest rate swap agreements, all of which were designated as fair value hedges. As of December 31, 2015, we had a combined notional principal amount of $11,000 million of fixed-to-variable interest rate swap agreements, of which $9,700 million were designated as fair value hedges. All of our swap agreements effectively convert the interest expense associated with certain series of senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread and have termination dates that correspond to the maturity dates of the related series of senior notes. As of December 31, 2016, the maximum length of time over which we have hedged a portion of our exposure to the variability in the value of this debt due to interest rate risk is through March 15, 2035.

Foreign Currency Risk Management

In connection with the issuance of our Euro denominated senior notes in March 2015 (see Note 9), we entered into $1,358 million of cross-currency swap agreements to manage the related foreign currency risk by effectively converting all of the fixed-rate Euro denominated debt, including annual interest payments and the payment of principal at maturity, to U.S. dollar denominated debt at fixed rates equivalent to approximately 3.79% and 4.67% for the 7-year and 12-year senior notes, respectively. These cross-currency swaps are accounted for as cash flow hedges. The terms of the cross-currency swap agreements correspond to the related hedged senior notes, and such agreements have the same maturities as the hedged senior notes.

Fair Value of Derivative Contracts

The following table summarizes the fair values of our derivative contracts included on our accompanying consolidated balance sheets (in millions):

Fair Value of Derivative Contracts
Asset derivativesLiability derivatives
December 31,December 31,
2016201520162015
LocationFair valueFair value
Derivatives designated as hedging contracts
Natural gas and crude derivative contractsFair value of derivative contracts/(Other current liabilities)$101$359$(57)$(13)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)70244(24)—
Subtotal171603(81)(13)
Interest rate swap agreementsFair value of derivative contracts/(Other current liabilities)94111——
Deferred charges and other assets/(Other long-term liabilities and deferred credits)206273(57)(9)
Subtotal300384(57)(9)
Cross-currency swap agreementsFair value of derivative contracts/(Other current liabilities)——(7)(6)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)——(24)(46)
Subtotal——(31)(52)
Total471987(169)(74)
Derivatives not designated as hedging contracts
Natural gas, crude, NGL and other derivative contractsFair value of derivative contracts/(Other current liabilities)335(29)(1)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)——(1)—
Subtotal335(30)(1)
Interest rate swap agreementsFair value of derivative contracts/(Other current liabilities)—1—(11)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)———(5)
Subtotal—1—(16)
Power derivative contractsFair value of derivative contracts/(Other current liabilities)—1—(17)
Subtotal—1—(17)
Total337(30)(34)
Total derivatives$474$1,024$(199)$(108)

Effect of Derivative Contracts on the Income Statement

The following tables summarize the impact of our derivative contracts on our accompanying consolidated statements of income (in millions):

Derivatives in fair value hedging relationshipsLocationGain/(loss) recognized in income on derivatives and related hedged item
Year Ended December 31,
201620152014
Interest rate swap agreementsInterest, net$(180)$25$207
Hedged fixed rate debtInterest, net$160$(33)$(204)
Derivatives in cash flow hedging relationshipsGain/(loss) recognized in OCI on derivative (effective portion)(a)LocationGain/(loss) reclassified from Accumulated OCI into income (effective portion)(b)LocationGain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)
Year EndedYear EndedYear Ended
December 31,December 31,December 31,
201620152014201620152014201620152014
Energy commodity derivative contracts$(115)$201$424Revenues—Natural gas sales$15$54$(1)Revenues—Natural gas sales$—$—$—
Revenues—Product sales and other14823626Revenues—Product sales and other(12)211
Costs of sales(17)(15)4Costs of sales———
Interest rate swap agreements(c)(2)(4)(15)Interest, net(3)(3)(4)Interest, net———
Cross-currency swap13(33)—Other, net(27)——Other, net———
Total$(104)$164$409Total$116$272$25Total$(12)$2$11
(a)We expect to reclassify an approximate $8 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balances as of December 31, 2016 into earnings during the next twelve months (when the associated forecasted transactions are also expected to occur), however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.
(b)Amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).
(c)Amounts represent our share of an equity investee’s accumulated other comprehensive loss.
Derivatives not designated as accounting hedgesLocationGain/(loss) recognized in income on derivatives
Year Ended December 31,
201620152014
Energy commodity derivative contractsRevenues—Natural gas sales$(10)$17$(7)
Revenues—Product sales and other(26)17620
Costs of sales3(2)—
Other (income) expense, net——(2)
Interest rate swap agreementsInterest, net63(15)—
Total(a)$30$176$11

(a) For the years ended December 31, 2016 and 2015, includes an approximate gain of $73 million and $31 million, respectively, associated with natural gas, crude and NGL derivative contract settlements.

Credit Risks

In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of December 31, 2016 and 2015, we had $0 million and $2 million, respectively, of outstanding letters of credit supporting our commodity price risk management program. As of December 31, 2016, we had cash margins of $37 million posted by us with our counterparties as collateral and no amounts posted by our counterparties as collateral. As of December 31, 2015, we had no cash margins posted by us as collateral and cash margins of $37 million posted by our counterparties as collateral. We also use industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we generally utilize netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty.

We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in our credit rating. As of December 31, 2016, based on our current mark to market positions and posted collateral, we estimate that if our credit rating were downgraded one notch we would be required to post $10 million of additional collateral and no additional collateral beyond this $10 million if we were downgraded two notches.

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss

Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Stockholders’ Equity” in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows (in millions):

Net unrealized gains/(losses) on cash flow hedge derivativesForeign currency translation adjustmentsPension and other postretirement liability adjustmentsTotal Accumulated other comprehensive loss
Balance as of December 31, 2013$(3)$2$(23)$(24)
Other comprehensive gain (loss) before reclassifications254(68)(212)(26)
Gains reclassified from accumulated other comprehensive loss(22)—(1)(23)
Impact of Merger Transactions (See Note 1)98(42)—56
Net current-period other comprehensive income (loss)330(110)(213)7
Balance as of December 31, 2014327(108)(236)(17)
Other comprehensive gain (loss) before reclassifications164(214)(122)(172)
Gains reclassified from accumulated other comprehensive loss(272)——(272)
Net current-period other comprehensive loss(108)(214)(122)(444)
Balance as of December 31, 2015219(322)(358)(461)
Other comprehensive (loss) gain before reclassifications(104)34(14)(84)
Gains reclassified from accumulated other comprehensive loss(116)——(116)
Net current-period other comprehensive (loss) income(220)34(14)(200)
Balance as of December 31, 2016$(1)$(288)$(372)$(661)
  1. Fair Value of Financial Instruments

The fair values of our financial instruments are separated into three broad levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Each fair value measurement must be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety.

The three broad levels of inputs defined by the fair value hierarchy are as follows:

•Level 1 Inputs—quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date;
•Level 2 Inputs—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and
•Level 3 Inputs—unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data).

Fair Value of Derivative Contracts

The following two tables summarize the fair value measurements of our (i) energy commodity derivative contracts; (ii) interest rate swap agreements; and (iii) cross-currency swap agreements, based on the three levels established by the Codification (in millions). The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements.

Balance sheet asset fair value measurements by level
Level 1Level 2Level 3Gross amountContracts available for nettingCash collateral held(b)Net amount
As of December 31, 2016
Energy commodity derivative contracts(a)$6$168$—$174$(43)$—$131
Interest rate swap agreements$—$300$—$300$(18)$—$282
As of December 31, 2015
Energy commodity derivative contracts(a)$48$589$2$639$(12)$(37)$590
Interest rate swap agreements$—$385$—$385$(8)$—$377
Balance sheet liability fair value measurements by level
Level 1Level 2Level 3Gross amountContracts available for nettingCollateral posted(c)Net amount
As of December 31, 2016
Energy commodity derivative contracts(a)$(29)$(82)$—$(111)$43$37$(31)
Interest rate swap agreements$—$(57)$—$(57)$18$—$(39)
Cross-currency swap agreements$—$(31)$—$(31)$—$—$(31)
As of December 31, 2015
Energy commodity derivative contracts(a)$(4)$(10)$(17)$(31)$12$—$(19)
Interest rate swap agreements$—$(25)$—$(25)$8$—$(17)
Cross-currency swap agreements$—$(52)$—$(52)$—$—$(52)
(a)Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps and options and NGL swaps. Level 3 consists primarily of power derivative contracts.
(b)Cash margin deposits held by us associated with our energy commodity contract positions and OTC swap agreements and reported within “Other current liabilities” on our accompanying consolidated balance sheets.
(c)Cash margin deposits posted by us associated with our energy commodity contract positions and OTC swap agreements and reported within “Restricted Deposits” on our accompanying consolidated balance sheets.

The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts (in millions):

Significant unobservable inputs (Level 3)
Year Ended December 31,
20162015
Derivatives-net asset (liability)
Beginning of period$(15)$(61)
Total gains or (losses) included in earnings(9)(13)
Settlements2459
End of period$—$(15)
The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or (losses) relating to assets held at the reporting date$—$—

As of December 31, 2015, our Level 3 derivative assets and liabilities consisted primarily of power derivative contracts (which expired in April 2016), where a significant portion of fair value is calculated from underlying market data that is not readily observable. The derived values use industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in management’s best estimate of fair value and management does not expect materially different valuation results were we to use different input amounts within reasonable ranges.

Fair Value of Debt

The carrying value and estimated fair value of our outstanding debt balances is disclosed below (in millions):

December 31, 2016December 31, 2015
Carrying valueEstimated fair valueCarrying valueEstimated fair value
Total debt$40,050$41,015$43,227$37,481

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both December 31, 2016 and 2015.

  1. Reportable Segments

Our reportable business segments are:

•Natural Gas Pipelines—the ownership and operation of (i) major interstate and intrastate natural gas pipeline and storage systems; (ii) natural gas and crude oil gathering systems and natural gas processing and treating facilities; (iii) NGL fractionation facilities and transportation systems; and (iv) LNG facilities;
•CO2—(i) the production, transportation and marketing of CO2 to oil fields that use CO2 as a flooding medium for recovering crude oil from mature oil fields to increase production; (ii) ownership interests in and/or operation of oil fields and gas processing plants in West Texas; and (iii) the ownership and operation of a crude oil pipeline system in West Texas;
•Terminals—(i) the ownership and/or operation of liquids and bulk terminal facilities located throughout the U.S. and portions of Canada that transload and store refined petroleum products, crude oil, chemicals, and ethanol and bulk products, including coal, petroleum coke, fertilizer, steel and ores and (ii) Jones Act tankers;
•Products Pipelines—the ownership and operation of refined petroleum products, NGL and crude oil and condensate pipelines that primarily deliver, among other products, gasoline, diesel and jet fuel, propane, crude oil and condensate to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities; and
•Kinder Morgan Canada—the ownership and operation of the Trans Mountain pipeline system that transports crude oil and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia, Canada and the state of Washington, plus the Jet Fuel aviation turbine fuel pipeline that serves the Vancouver (Canada) International Airport.

We evaluate performance principally based on each segment’s EBDA, which excludes general and administrative expenses, interest expense, net, and income tax expense. Our reportable segments are strategic business units that offer different products and services, and they are structured based on how our chief operating decision makers organize their operations for optimal performance and resource allocation. Each segment is managed separately because each segment involves different products and marketing strategies.

Segment results for the years ended December 31, 2015 and 2014 have been retrospectively adjusted to reflect the elimination of the Other segment as a reportable segment. The activities that previously comprised the Other segment are now presented within the Corporate non-segment activities in reconciling to the consolidated totals in the respective segment reporting tables. The Other segment had historically been comprised primarily of legacy operations of acquired businesses not associated with our ongoing operations. These business activities have since been sold or have otherwise ceased. In addition, the Other segment included certain company owned real estate assets which are primarily leased to our operating subsidiaries

as well as third party tenants. This activity is now reflected within Corporate activity. In addition, the portions of interest income and income tax expense previously allocated to our business segments is now included in “Interest expense, net” and “Income tax expense” for all periods presented in the following tables.

We consider each period’s earnings before all non-cash DD&A expenses to be an important measure of business segment performance for our reporting segments. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value.

During 2016, 2015 and 2014, we did not have revenues from any single external customer that exceeded 10% of our consolidated revenues.

Financial information by segment follows (in millions):

Year Ended December 31,
201620152014
Revenues
Natural Gas Pipelines
Revenues from external customers$7,998$8,704$10,153
Intersegment revenues72115
CO21,2211,6991,960
Terminals
Revenues from external customers1,9211,8781,717
Intersegment revenues111
Products Pipelines
Revenues from external customers1,6311,8282,068
Intersegment revenues183—
Kinder Morgan Canada253260291
Corporate and intersegment eliminations(a)8921
Total consolidated revenues$13,058$14,403$16,226
Year Ended December 31,
201620152014
Operating expenses(b)
Natural Gas Pipelines$4,393$4,738$6,241
CO2399432494
Terminals768836746
Products Pipelines5737721,258
Kinder Morgan Canada8787106
Corporate and intersegment eliminations2268
Total consolidated operating expenses$6,222$6,891$8,853
Year Ended December 31,
201620152014
Other expense (income)(c)
Natural Gas Pipelines$199$1,269$5
CO219606243
Terminals9919029
Products Pipelines762(3)
Kinder Morgan Canada—(1)—
Corporate(7)—1
Total consolidated other expense (income)$386$2,066$275
Year Ended December 31,
201620152014
DD&A
Natural Gas Pipelines$1,041$1,046$897
CO2446556570
Terminals435433337
Products Pipelines221206166
Kinder Morgan Canada444651
Corporate222219
Total consolidated DD&A$2,209$2,309$2,040
Year Ended December 31,
201620152014
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments
Natural Gas Pipelines$(269)$285$279
CO222(5)26
Terminals191718
Products Pipelines563637
Corporate——1
Total consolidated equity earnings$(172)$333$361
Year Ended December 31,
201620152014
Other, net-income (expense)
Natural Gas Pipelines$19$24$24
Terminals4812
Products Pipelines24(1)
Kinder Morgan Canada15815
Corporate4(1)30
Total consolidated other, net-income (expense)$44$43$80
Year Ended December 31,
201620152014
Segment EBDA(d)
Natural Gas Pipelines$3,211$3,067$4,264
CO28276581,248
Terminals1,078878973
Products Pipelines1,0671,106856
Kinder Morgan Canada181182200
Total segment EBDA6,3645,8917,541
DD&A(2,209)(2,309)(2,040)
Amortization of excess cost of equity investments(59)(51)(45)
General and administrative expenses(669)(690)(610)
Interest expense, net(1,806)(2,051)(1,798)
Corporate(a)17(18)43
Income tax expense(917)(564)(648)
Total consolidated net income$721$208$2,443
Year Ended December 31,
201620152014
Capital expenditures
Natural Gas Pipelines$1,227$1,642$935
CO2276725792
Terminals9838471,049
Products Pipelines244524680
Kinder Morgan Canada124142156
Corporate28165
Total consolidated capital expenditures$2,882$3,896$3,617
20162015
Investments at December 31
Natural Gas Pipelines$6,185$5,080
Terminals252306
Products Pipelines566641
Kinder Morgan Canada2010
Corporate43
Total consolidated investments$7,027$6,040
20162015
Assets at December 31
Natural Gas Pipelines$50,428$53,704
CO24,0654,706
Terminals9,7259,083
Products Pipelines8,3298,464
Kinder Morgan Canada1,5721,434
Corporate assets(e)6,1086,694
Assets held for sale7819
Total consolidated assets$80,305$84,104
(a)Includes a management fee for services we perform as operator of an equity investee.
(b)Includes natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
(c)Includes loss on impairment of goodwill, loss on impairments and divestitures, net and other (income) expense, net.
(d)Includes revenues, earnings from equity investments, other, net, less operating expenses, and other (income) expense, net, loss on impairment of goodwill, and loss on impairments and divestitures, net and loss on impairments and divestitures of equity investments, net.
(e)Includes cash and cash equivalents, margin and restricted deposits, unallocable interest receivable, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to debt fair value adjustments, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy operations) not allocated to the reportable segments.

We do not attribute interest and debt expense to any of our reportable business segments.

Following is geographic information regarding the revenues and long-lived assets of our business segments (in millions):

Year Ended December 31,
201620152014
Revenues from external customers
U.S.$12,459$13,797$15,605
Canada483479437
Mexico116127184
Total consolidated revenues from external customers$13,058$14,403$16,226
December 31,
201620152014
Long-term assets, excluding goodwill and other intangibles
U.S.$49,125$51,679$49,992
Canada2,3992,1932,268
Mexico826781
Total consolidated long-lived assets$51,606$53,939$52,341
  1. Litigation, Environmental and Other Contingencies

We and our subsidiaries are parties to various legal, regulatory and other matters arising from the day-to-day operations of our businesses or certain predecessor operations that may result in claims against the Company. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves and insurance, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position, results of operations or dividends to our shareholders. We believe we have meritorious defenses to the matters to which we are a party and intend to vigorously defend the Company. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low

end of the range. We disclose contingencies where an adverse outcome may be material, or in the judgment of management, we conclude the matter should otherwise be disclosed.

Federal Energy Regulatory Commission Proceedings

SFPP

The tariffs and rates charged by SFPP are subject to a number of ongoing proceedings at the FERC, including the complaints and protests of various shippers the most recent of which was filed in late 2015 with the FERC (docketed at OR16-6) challenging SFPP’s filed East Line rates. In general, these complaints and protests allege the rates and tariffs charged by SFPP are not just and reasonable under the Interstate Commerce Act (ICA). In some of these proceedings shippers have challenged the overall rate being charged by SFPP, and in others the shippers have challenged SFPP’s index-based rate increases. If the shippers prevail on their arguments or claims, they are entitled to seek reparations (which may reach back up to two years prior to the filing date of their complaints) or refunds of any excess rates paid, and SFPP may be required to reduce its rates going forward. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts. The issues involved in these proceedings include, among others, whether indexed rate increases are justified, and the appropriate level of return and income tax allowance SFPP may include in its rates. On March 22, 2016, the D.C. Circuit issued a decision in United Airlines, Inc. v. FERC remanding to FERC for further consideration of two issues: (1) the appropriate data to be used to determine the return on equity for SFPP in the underlying docket, and (2) the just and reasonable return to be provided to a tax pass-through entity that includes an income tax allowance in its underlying cost of service. With respect to the various SFPP related complaints and protest proceedings at the FERC, we estimate that the shippers are seeking approximately $40 million in annual rate reductions and approximately $190 million in refunds. Management believes SFPP has meritorious arguments supporting SFPP’s rates and intends to vigorously defend SFPP against these complaints and protests. However, to the extent the shippers are successful in one or more of the complaints or protest proceedings, SFPP estimates that applying the principles of FERC precedent, as applicable, to pending SFPP cases would result in rate reductions and refunds substantially lower than those sought by the shippers.

EPNG

The tariffs and rates charged by EPNG are subject to two ongoing FERC proceedings (the “2008 rate case” and the “2010 rate case”). With respect to the 2008 rate case, the FERC issued its decision (Opinion 517-A) in July 2015. The FERC generally upheld its prior determinations, ordered refunds to be paid within 60 days, and stated that it will apply its findings in Opinion 517-A to the same issues in the 2010 rate case. EPNG has sought federal appellate review of Opinion 517-A and oral argument is scheduled for February 15, 2017. With respect to the 2010 rate case, the FERC issued its decision (Opinion 528-A) on February 18, 2016. The FERC generally upheld its prior determinations, affirmed prior findings of an Administrative Law Judge that certain shippers qualify for lower rates, and required EPNG to file revised pro forma recalculated rates consistent with the terms of Opinions 517-A and 528-A. EPNG and two intervenors sought rehearing of certain aspects of the decision, and the judicial review sought by certain intervenors has been delayed until the FERC issues an order on rehearing. All refund obligations related to the 2008 rate case were satisfied during calendar year 2015. With respect to the 2010 rate case, EPNG believes it has an appropriate reserve related to the findings in Opinions 517-A and 528-A.

NGPL and WIC

On January 19, 2017, NGPL and WIC were notified by the FERC of rate proceedings against them pursuant to section 5 of the Natural Gas Act (the “Orders”). Each respective proceeding will set the matter for hearing and determine whether NGPL’s and WIC’s current rates remain just and reasonable. A proceeding under section 5 of the Natural Gas Act is prospective in nature such that a change in rates charged to customers, if any, would likely only occur after the FERC has issued a final order. Unless a settlement is reached sooner, an initial Administrative Law Judge decision is anticipated in late February, 2018, with a final FERC decision anticipated by the third quarter, 2018. We do not believe that the ultimate resolution of these proceedings will have a material adverse impact on our results of operations or cash flows from operations.

Other Commercial Matters

Union Pacific Railroad Company Easements & Related Litigation

SFPP and Union Pacific Railroad Company (UPRR) are engaged in a proceeding to determine the extent, if any, to which the rent payable by SFPP for the use of pipeline easements on rights-of-way held by UPRR should be adjusted pursuant to existing contractual arrangements for the ten-year period beginning January 1, 2004 (Union Pacific Railroad Company v. Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. “D”, Kinder Morgan G.P., Inc., et al., Superior Court of

the State of California for the County of Los Angeles, filed July 28, 2004). In September 2011, the trial judge determined that the annual rent payable as of January 1, 2004 was $14 million, subject to annual consumer price index increases. SFPP appealed the judgment.

By notice dated October 25, 2013, UPRR demanded the payment of $22.3 million in rent for the first year of the next ten-year period beginning January 1, 2014, which SFPP rejected.

On November 5, 2014, the Court of Appeals issued an opinion which reversed the judgment, including the award of prejudgment interest, and remanded the matter to the trial court for a determination of UPRR’s property interest in its right-of-way, including whether UPRR has sufficient interest to grant SFPP’s easements. UPRR filed a petition for review to the California Supreme Court which was denied. The trial court has not set a date for the retrial.

After the above-referenced decision by the California Court of Appeals which held that UPRR does not own the subsurface rights to grant certain easements and may not be able to collect rent from those easements, a purported class action lawsuit was filed in 2015 in the U.S. District Court for the Southern District of California by private landowners in California who claim to be the lawful owners of subsurface real property allegedly used or occupied by UPRR or SFPP. Substantially similar follow-on lawsuits were filed and are pending in federal courts by landowners in Nevada, Arizona and New Mexico. These suits, which are brought purportedly as class actions on behalf of all landowners who own land in fee adjacent to and underlying the railroad easement under which the SFPP pipeline is located in those respective states, assert claims against UPRR, SFPP, KMGP, and Kinder Morgan Operating L.P. “D” for declaratory judgment, trespass, ejectment, quiet title, unjust enrichment, accounting, and alleged unlawful business acts and practices arising from defendants’ alleged improper use or occupation of subsurface real property. SFPP views these cases as primarily a dispute between UPRR and the plaintiffs. UPRR purported to grant SFPP a network of subsurface pipeline easements along UPRR’s railroad right-of-way. SFPP relied on the validity of those easements and paid rent to UPRR for the value of those easements. We believe we have recorded a right-of-way liability sufficient to cover our potential obligation, if any, for back rent.

SFPP and UPRR have engaged in multiple disputes over the circumstances under which SFPP must pay for relocations of its pipeline within the UPRR right-of-way and the safety standards that govern relocations. In 2006, following a bench trial regarding the circumstances under which SFPP must pay for relocations, the judge determined that SFPP must pay for any relocations resulting from any legitimate business purpose of the UPRR. The decision was affirmed on appeal. In addition, UPRR contends that SFPP must comply with the more expensive American Railway Engineering and Maintenance-of-Way Association (AREMA) standards in determining when relocations are necessary and in completing relocations. Each party has sought declaratory relief with respect to its positions regarding the application of these standards with respect to relocations. In 2011, a jury verdict was reached that SFPP was obligated to comply with AREMA standards in connection with a railroad project in Beaumont Hills, California. In 2014, the trial court entered judgment against SFPP, consistent with the jury’s verdict. On June 29, 2015, the parties entered into a confidential settlement of all of the claims relating to the project in Beaumont Hills and the case was dismissed.

Since SFPP does not know UPRR’s plans for projects or other activities that would cause pipeline relocations, it is difficult to quantify the effects of the outcome of these cases on SFPP. Even if SFPP is successful in advancing its positions, significant relocations for which SFPP must nonetheless bear the cost (i.e., for railroad purposes, with the standards in the federal Pipeline Safety Act applying) could have an adverse effect on our financial position, results of operations, cash flows, and our dividends to our shareholders. These effects could be even greater in the event SFPP is unsuccessful in one or more of these lawsuits.

Gulf LNG Facility Arbitration

On March 1, 2016, Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) received a Notice of Disagreement and Disputed Statements and a Notice of Arbitration from Eni USA Gas Marketing LLC (Eni USA), one of two companies that entered into a terminal use agreement for capacity of the Gulf LNG Facility in Mississippi for an initial term that is not scheduled to expire until the year 2031. Eni USA is an indirect subsidiary of Eni S.p.A., a multi-national integrated energy company headquartered in Milan, Italy. Pursuant to its Notice of Arbitration, Eni USA seeks declaratory and monetary relief based upon its assertion that (i) the terminal use agreement should be terminated because changes in the U.S. natural gas market since the execution of the agreement in December 2007 have “frustrated the essential purpose” of the agreement and (ii) activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC “in connection with a plan to convert the LNG Facility into a liquefaction/export facility have given rise to a contractual right on the part of Eni USA to terminate” the agreement. As set forth in the terminal use agreement, disputes are meant to be resolved by final and binding arbitration. A three-member arbitration panel conducted an arbitration hearing in January 2017. We expect the arbitration panel will issue its decision within approximately six months. Eni USA has indicated that it will continue to pay the amounts claimed to be due

pending resolution of the dispute. The successful assertion by Eni USA of its claim to terminate or amend its payment obligations under the agreement prior to the expiration of its initial term could have an adverse effect on the business, financial position, results of operations, or cash flows of GLNG and distributions to KMI, a 50% shareholder of GLNG. We view the demand for arbitration to be without merit, and we intend to contest it vigorously.

Plains Gas Solutions, LLC v. Tennessee Gas Pipeline Company, L.L.C. et al.

On October 16, 2013, Plains Gas Solutions, LLC (Plains) filed a petition in the 151st Judicial District Court for Harris County, Texas (Case No. 62528) against TGP, Kinetica Partners, LLC and two other Kinetica entities. The suit arose from the sale by TGP of the Cameron System in Louisiana to Kinetica Partners, LLC on September 1, 2013. Plains alleged that defendants breached a straddle agreement requiring that gas on the Cameron System be committed to Plains’ Grand Chenier gas-processing facility, that requisite daily volume reports were not provided, that TGP improperly assigned its obligations under the straddle agreement to Kinetica, and that defendants interfered with Plains’ contracts with producers. The petition alleged damages of at least $100 million. Under the Amended and Restated Purchase and Sale Agreement with Kinetica, Kinetica is obligated to defend and indemnify TGP in connection with the gas commitment and reporting claims. After agreeing initially to defend and indemnify TGP against such claims, Kinetica withdrew its defense, disputed its indemnity obligation, and settled with Plains. On January 20, 2017, Plains and TGP agreed to release and dismiss their claims and causes of action in the lawsuit with prejudice.

Brinckerhoff v. El Paso Pipeline GP Company, LLC., et al.

In December 2011 (Brinckerhoff I), March 2012, (Brinckerhoff II), May 2013 (Brinckerhoff III) and June 2014 (Brinckerhoff IV), derivative lawsuits were filed in Delaware Chancery Court against El Paso Corporation, El Paso Pipeline GP Company, L.L.C., the general partner of EPB, and the directors of the general partner at the time of the relevant transactions. EPB was named in these lawsuits as a “Nominal Defendant.” The lawsuits arise from the March 2010, November 2010, May 2012 and June 2011 drop-down transactions involving EPB’s purchase of SLNG, Elba Express, CPG and interests in SNG and CIG. The lawsuits allege various conflicts of interest and that the consideration paid by EPB was excessive. Brinckerhoff I and II were consolidated into one proceeding. Motions to dismiss were filed in Brinckerhoff III and Brinckerhoff IV, and such motions remain pending. On June 12, 2014, defendants’ motion for summary judgment was granted in Brinckerhoff I, dismissing the case in its entirety. Defendants’ motion for summary judgment in Brinckerhoff II was granted in part, dismissing certain claims and allowing the matter to go to trial in late 2014 on the remaining claims. On April 20, 2015, the Court issued a post-trial memorandum opinion (Memorandum Opinion) in Brinckerhoff II entering judgment in favor of all of the defendants other than the general partner of EPB, but finding the general partner liable for breach of contract in connection with EPB’s purchase of 49% interests in Elba and SLNG and a 15% interest in SNG in a $1.13 billion drop-down transaction that closed on November 19, 2010 (Fall Dropdown), prior to our acquisition of El Paso Corporation in 2012. In its Memorandum Opinion, the Court determined that EPB suffered damages of $171 million from the Fall Dropdown, which the Court determined to be the amount that EPB overpaid for Elba. We believe the claim is derivative in nature and was extinguished by our acquisition on November 26, 2014, pursuant to a merger agreement, of all of the outstanding common units of EPB that we did not already own. On December 2, 2015, the Court denied our motion to dismiss the remaining claims in Brinckerhoff II based upon our acquisition of all of the outstanding common units of EPB, and held that damages should be calculated by considering the unaffiliated unitholders’ ownership percentage as of the effective date of the merger. Based on this ruling, the Court entered judgment on February 4, 2016 in the amount of $100.2 million plus interest at the legal rate for the period from November 15, 2010 until the date of payment, if any payment is ultimately required. We filed an appeal to the Delaware Supreme Court and Brinckerhoff filed a cross-appeal challenging the dismissal of Brinckerhoff I. On December 20, 2016, the Delaware Supreme Court issued an opinion reversing the trial court’s December 2, 2015 decision, finding that the claims were derivative in nature and that Brinckerhoff lost standing to continue both the appeal and cross-appeal when the merger closed. Because its holding terminates the litigation, the Supreme Court did not reach the other issues raised by the parties. On January 5, 2017, the Supreme Court issued a mandate to the trial court reversing the February 4, 2016 judgment in its entirety. On January 30, 2017, the trial court dismissed the case. We continue to believe the transactions at issue were appropriate and in the best interests of EPB. We believe the remaining lawsuits (Brinckerhoff III and IV) should be dismissed on the same grounds, among others, as Brinckerhoff I and II and we intend to continue to defend such lawsuits vigorously.

Price Reporting Litigation

Beginning in 2003, several lawsuits were filed by purchasers of natural gas against El Paso Corporation, El Paso Marketing L.P. and numerous other energy companies based on a claim under state antitrust law that such defendants conspired to manipulate the price of natural gas by providing false price information to industry trade publications that published gas indices. Several of the cases have been settled or dismissed. The remaining cases, which are pending in Nevada federal court, were dismissed, but the dismissal was reversed by the 9th Circuit Court of Appeals. The U.S. Supreme Court affirmed the 9th

Circuit Court of Appeals in a decision dated April 21, 2015, and the cases were then remanded to the Nevada federal court for further consideration and trial, if necessary, of numerous remaining issues. On May 24, 2016, the Court granted a motion for summary judgment dismissing a lawsuit brought by an industrial consumer in Kansas in which approximately $500 million in damages has been alleged. That ruling has been appealed to the 9th Circuit Court of Appeals. Tentative settlements have been reached in class actions originally filed in Kansas and Missouri, which settlements are subject to court approval. In the remaining case, a Wisconsin class action, approximately $300 million in damages have been alleged against all defendants. There remains significant uncertainty regarding the validity of the causes of action, the damages asserted and the level of damages, if any, which may be allocated to us in the remaining lawsuits and therefore, our legal exposure, if any, and costs are not currently determinable.

Kinder Morgan, Inc. Corporate Reorganization Litigation

Certain unitholders of KMP and EPB filed five putative class action lawsuits in the Court of Chancery of the State of Delaware in connection with our November 26, 2014 acquisition, pursuant to three separate merger agreements, of all of the outstanding common units of KMP and EPB and all of the outstanding shares of KMR that we did not already own. The lawsuits were consolidated under the caption In re Kinder Morgan, Inc. Corporate Reorganization Litigation (Consolidated Case No. 10093-VCL). On December 12, 2014, the plaintiffs filed a Verified Second Consolidated Amended Class Action Complaint, which purported to assert claims on behalf of both the former EPB unitholders and the former KMP unitholders. The EPB plaintiff alleged that (i) El Paso Pipeline GP Company, L.L.C. (EPGP), the general partner of EPB, and the directors of EPGP breached duties under the EPB partnership agreement, including the implied covenant of good faith and fair dealing, by entering into the EPB Transaction; (ii) EPB, E Merger Sub LLC, KMI and individual defendants aided and abetted such breaches; and (iii) EPB, E Merger Sub LLC, KMI, and individual defendants tortiously interfered with the EPB partnership agreement by causing EPGP to breach its duties under the EPB partnership agreement.

The KMP plaintiffs alleged that (i) KMR, KMGP, and individual defendants breached duties under the KMP partnership agreement, including the implied duty of good faith and fair dealing, by entering into the KMP Transaction and by failing to adequately disclose material facts related to the transaction; (ii) KMI aided and abetted such breach; and (iii) KMI, KMP, KMR, P Merger Sub LLC, and individual defendants tortiously interfered with the rights of the plaintiffs and the putative class under the KMP partnership agreement by causing KMGP to breach its duties under the KMP partnership agreement. The complaint sought declaratory relief that the transactions were unlawful and unenforceable, reformation, rescission, rescissory or compensatory damages, interest, and attorneys’ and experts’ fees and costs. On December 30, 2014, the defendants moved to dismiss the complaint. On April 2, 2015, the EPB plaintiff and the defendants submitted a stipulation and proposed order of dismissal, agreeing to dismiss all claims brought by the EPB plaintiff with prejudice as to the EPB lead plaintiff and without prejudice to all other members of the putative EPB class. The Court entered such order on April 2, 2015.

On August 24, 2015, the Court issued an order granting the defendants’ motion to dismiss the remaining counts of the complaint for failure to state a claim. On September 21, 2015, plaintiffs filed a notice of appeal to the Supreme Court of the State of Delaware, captioned Haynes Family Trust et al. v. Kinder Morgan G.P., Inc. et al. (Case No. 515). On March 10, 2016, the Delaware Supreme Court affirmed the dismissal of all claims on appeal and this matter is now concluded.

Pipeline Integrity and Releases

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

General

As of December 31, 2016 and 2015, our total reserve for legal matters was $407 million and $463 million, respectively. The reserve primarily relates to various claims from regulatory proceedings arising in our products and natural gas pipeline segments and certain corporate matters.

Environmental Matters

We and our subsidiaries are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a

liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and CO2 field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us.

We are currently involved in several governmental proceedings involving alleged violations of environmental and safety regulations, including alleged violations of the Risk Management Program and leak detection and repair requirements of the Clean Air Act. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. These alleged violations may result in fines and penalties, but we do not believe any such fines and penalties, individually or in the aggregate, will be material. We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under administrative orders or related state remediation programs. We have established a reserve to address the costs associated with the cleanup.

In addition, we are involved with and have been identified as a potentially responsible party in several federal and state superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, NGL, natural gas and CO2.

Portland Harbor Superfund Site, Willamette River, Portland, Oregon

In December 2000, the EPA issued General Notice letters to potentially responsible parties including GATX Terminals Corporation (n/k/a KMLT). At that time, GATX owned two liquids terminals along the lower reach of the Willamette River, an industrialized area known as Portland Harbor. Portland Harbor is listed on the National Priorities List and is designated as a Superfund Site under CERCLA. A group of potentially responsible parties formed what is known as the Lower Willamette Group (LWG), of which KMLT is a non-voting member and pays a minimal fee to be part of the group. The LWG agreed to conduct the remedial investigation and feasibility study (RI/FS) leading to the proposed remedy for cleanup of the Portland Harbor site. After a dispute with the EPA concerning certain provision of the FS, the parties agreed that the EPA would complete the FS and that the LWG may dispute the FS within 14 days of the publication of the proposed remedy for cleanup. EPA issued the FS and the Proposed Plan on June 8, 2016. The EPA’s Proposed Plan included a combination of dredging, capping, and enhanced natural recovery. Comments on the FS and the Proposed Plan were submitted by the LWG and on our own behalf on September 7, 2016. On January 6, 2017, the EPA issued its Record of Decision (ROD) for the final cleanup plan. The final remedy is more stringent than the remedy proposed in the EPA’s Proposed Plan. The estimated cost has increased from approximately $750 million to approximately $1.1 billion and active cleanup is now expected to take as long as 13 years to complete. KMLT and 90 other parties are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs. We are participating in the allocation process on behalf of KMLT and KMBT in connection with their current or former ownership or operation of four facilities located in Portland Harbor. Our share of responsibility for Portland Harbor Superfund Site costs will not be determined until the ongoing non-judicial allocation process is concluded in several years or a lawsuit is filed that results in a judicial decision allocating responsibility. Until the allocation process is completed, we are unable to reasonably estimate the extent of our liability for the costs related to the design of the proposed remedy and cleanup of the site.

Roosevelt Irrigation District v. Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P. , U.S. District Court, Arizona

The Roosevelt Irrigation District sued KMGP, KMEP and others under CERCLA for alleged contamination of the water purveyor’s wells. The First Amended Complaint sought $175 million in damages from approximately 70 defendants. On August 6, 2013 plaintiffs filed their Second Amended Complaint seeking monetary damages in unspecified amounts and reducing the number of defendants to 26 including KMEP and SFPP. The claims now presented against KMEP and SFPP are related to alleged releases from a specific parcel within the SFPP Phoenix Terminal and the alleged impact of such releases on water wells owned by the plaintiffs and located in the vicinity of the Terminal. We have filed an answer, general denial, and affirmative defenses in response to the Second Amended Complaint and fact discovery is proceeding.

Mission Valley Terminal Lawsuit

In August 2007, the City of San Diego, on its own behalf and purporting to act on behalf of the People of the State of California, filed a lawsuit against us and several affiliates seeking injunctive relief and unspecified damages allegedly resulting

from hydrocarbon and methyl tertiary butyl ether (MTBE) impacted soils and groundwater beneath the City’s stadium property in San Diego arising from historic operations at the Mission Valley terminal facility. The case was filed in the Superior Court of California, San Diego County and was removed in 2007 to the U.S. District Court, Southern District of California (Case No. 07CV1883WCAB). The City disclosed in discovery that it was seeking approximately $170 million in damages for alleged lost value/lost profit from the redevelopment of the City’s property and alleged lost use of the water resources underlying the property. Later, in 2010, the City amended its initial disclosures to add claims for restoration of the site as well as a number of other claims that increased its claim for damages to approximately $365 million.

On November 29, 2012, the Court issued a Notice of Tentative Rulings on the parties’ summary adjudication motions. The Court tentatively granted our partial motions for summary judgment on the City’s claims for water and real estate damages and the State’s claims for violations of California Business and Professions Code § 17200, tentatively denied the City’s motion for summary judgment on its claims of liability for nuisance and trespass, and tentatively granted our cross motion for summary judgment on such claims. On January 25, 2013, the Court rendered judgment in favor of all defendants on all claims asserted by the City.

On February 20, 2013, the City of San Diego filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit. On May 21, 2015, the Court of Appeals issued a memorandum decision which affirmed the District Court’s summary judgment in our favor with respect to the City’s claim under California Safe Drinking Water and Toxic Enforcement Act, but reversed both the District Court’s summary judgment decision in our favor on the City’s remaining claims and the District Court’s decision to exclude the City’s expert testimony. The Court of Appeals issued a mandate returning the case to the U.S. District Court.

On June 17, 2016, the parties entered into a settlement resolving all claims related to the historical contamination at the City’s stadium property. The settlement provides for a $20 million payment to the City, a waiver and release by the City of all claims which were asserted or could have been asserted in the litigation, and an agreement by defendants to indemnify the City for additional, incremental costs, if any, incurred by the City in the redevelopment of the stadium property or the development of groundwater beneath the stadium property, that would not have been incurred but for the historical releases from the Mission Valley Terminal. By Order dated June 17, 2016, the District Court granted dismissal of the litigation.

This site remains under the regulatory oversight and order of the California Regional Water Quality Control Board (RWQCB). SFPP completed the soil and groundwater remediation at the City of San Diego’s stadium property site and conducted quarterly sampling and monitoring through 2015 as part of the compliance evaluation required by the RWQCB. The RWQCB issued a notice of no further action with respect to the stadium property site on May 4, 2016. SFPP’s remediation effort is now focused on its adjacent Mission Valley Terminal site.

Uranium Mines in Vicinity of Cameron, Arizona

In the 1950s and 1960s, Rare Metals Inc., a historical subsidiary of EPNG, mined approximately twenty uranium mines in the vicinity of Cameron, Arizona, many of which are located on the Navajo Indian Reservation. The mining activities were in response to numerous incentives provided to industry by the U.S. to locate and produce domestic sources of uranium to support the Cold War-era nuclear weapons program. In May 2012, EPNG received a general notice letter from the EPA notifying EPNG of the EPA’s investigation of certain sites and its determination that the EPA considers EPNG to be a potentially responsible party within the meaning of CERCLA. In August 2013, EPNG and the EPA entered into an Administrative Order on Consent and Scope of Work pursuant to which EPNG is conducting a radiological assessment of the surface of the mines. On September 3, 2014, EPNG filed a complaint in the U.S. District Court for the District of Arizona (Case No. 3:14-08165-DGC) seeking cost recovery and contribution from the applicable federal government agencies toward the cost of environmental activities associated with the mines, given the pervasive control of such federal agencies over all aspects of the nuclear weapons program. Defendants filed an answer and counterclaims seeking contribution and recovery of response costs allegedly incurred by the federal agencies in investigating uranium impacts on the Navajo Reservation. The counterclaim of defendant EPA has been settled, and no viable claims for reimbursement by the other defendants are known to exist.

Lower Passaic River Study Area of the Diamond Alkali Superfund Site, Essex, Hudson, Bergen and Passaic Counties, New Jersey

EPEC Polymers, Inc. (EPEC Polymers) and EPEC Oil Company Liquidating Trust (EPEC Oil Trust), former El Paso Corporation entities now owned by KMI, are involved in an administrative action under CERCLA known as the Lower Passaic River Study Area Superfund Site (Site) concerning the lower 17-mile stretch of the Passaic River. It has been alleged that EPEC Polymers and EPEC Oil Trust may be potentially responsible parties (PRPs) under CERCLA based on prior ownership and/or operation of properties located along the relevant section of the Passaic River. EPEC Polymers and EPEC Oil Trust entered into

two Administrative Orders on Consent (AOCs) which obligate them to investigate and characterize contamination at the Site. They are also part of a joint defense group (JDG) of approximately 70 cooperating parties which have entered into AOCs and are directing and funding the work required by the EPA. Under the first AOC, draft remedial investigation and feasibility studies (RI/FS) of the Site were submitted to the EPA in 2015, and comments from the EPA remain pending. Under the second AOC, the JDG members conducted a CERCLA removal action at the Passaic River Mile 10.9, and the group is currently conducting EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with the AOCs.

On April 11, 2014, the EPA announced the issuance of its Focused Feasibility Study (FFS) for the lower eight miles of the Passaic River Study Area, and its proposed plan for remedial alternatives to address the dioxin sediment contamination from the mouth of Newark Bay to River Mile 8.3. The EPA estimates the cost for the alternatives will range from $365 million to $3.2 billion. The EPA’s preferred alternative would involve dredging the river bank-to-bank and installing an engineered cap at an estimated cost of $1.7 billion. On March 4, 2016, the EPA issued its ROD for the lower 8.3 miles of the Passaic River Study area. The final cleanup plan in the ROD is substantially similar to the EPA’s preferred alternative announced on April 11, 2014. On October 5, 2016, the EPA entered into an AOC with one member of the PRP group requiring such member to spend $165 million to perform engineering and design work necessary to begin the cleanup of the lower 8.3 miles of the Passaic River. The design work is expected to take four years to complete and the cleanup is expected to take six years to complete.

In addition to the AOC with one member of the PRP group described above, the EPA has notified over 80 other PRPs, including EPEC Polymers and EPEC Oil Trust (the Notice), that the EPA intends to pursue additional agreements with other “major PRPs” and initiate negotiations over cash buyouts with parties whom the EPA does not consider “major PRPs.” The Notice creates significant uncertainty as to the implementation and associated costs of the remedy set forth in the FFS and ROD, and provides no guidance as to the EPA’s definition of a “major PRP” or the potential amount or range of cash buyouts. There is also uncertainty as to the impact of the RI/FS that the CPG is currently preparing for portions of the Site. The draft RI/FS was submitted by the CPG earlier in 2015 and proposes a different remedy than the FFS announced by the EPA. Therefore, the scope of potential EPA claims for the lower eight miles of the Passaic River is not reasonably estimable at this time.

Southeast Louisiana Flood Protection Litigation

On July 24, 2013, the Board of Commissioners of the Southeast Louisiana Flood Protection Authority - East (SLFPA) filed a petition for damages and injunctive relief in state district court for Orleans Parish, Louisiana (Case No. 13-6911) against TGP, SNG and approximately 100 other energy companies, alleging that defendants’ drilling, dredging, pipeline and industrial operations since the 1930’s have caused direct land loss and increased erosion and submergence resulting in alleged increased storm surge risk, increased flood protection costs and unspecified damages to the plaintiff. The SLFPA asserts claims for negligence, strict liability, public nuisance, private nuisance, and breach of contract. Among other relief, the petition seeks unspecified monetary damages, attorney fees, interest, and injunctive relief in the form of abatement and restoration of the alleged coastal land loss including but not limited to backfilling and re-vegetation of canals, wetlands and reef creation, land bridge construction, hydrologic restoration, shoreline protection, structural protection, and bank stabilization. On August 13, 2013, the suit was removed to the U.S. District Court for the Eastern District of Louisiana. On February 13, 2015, the Court granted defendants’ motion to dismiss the suit for failure to state a claim, and issued an order dismissing the SLFPA’s claims with prejudice. The SLFPA filed a notice of appeal on February 20, 2015. The U.S. Court of Appeals for the Fifth Circuit heard oral argument on February 29, 2016 and we await the Court’s decision.

Plaquemines Parish Louisiana Coastal Zone Litigation

On November 8, 2013, the Parish of Plaquemines, Louisiana filed a petition for damages in the state district court for Plaquemines Parish, Louisiana (Docket No. 60-999) against TGP and 17 other energy companies, alleging that defendants’ oil and gas exploration, production and transportation operations in the Bastian Bay, Buras, Empire and Fort Jackson oil and gas fields of Plaquemines Parish caused substantial damage to the coastal waters and nearby lands (Coastal Zone) within the Parish, including the erosion of marshes and the discharge of oil waste and other pollutants which detrimentally affected the quality of state waters and plant and animal life, in violation of the State and Local Coastal Resources Management Act of 1978 (Coastal Zone Management Act). As a result of such alleged violations of the Coastal Zone Management Act, Plaquemines Parish seeks, among other relief, unspecified monetary relief, attorney fees, interest, and payment of costs necessary to restore the allegedly affected Coastal Zone to its original condition, including costs to clear, vegetate and detoxify the Coastal Zone. In connection with this suit, TGP has made two tenders for defense and indemnity: (1) to Anadarko, as successor to the entity that purchased TGP’s oil and gas assets in Bastian Bay, and (2) to Kinetica, which purchased TGP’s pipeline assets in Bastian Bay in 2013. Anadarko has accepted TGP’s tender (limited to oil and gas assets), and Kinetica rejected TGP’s tender. TGP responded to Kinetica by reasserting TGP’s demand for defense and indemnity and reserving its rights. On November 12, 2015, the Plaquemines Parish Council adopted a resolution directing its legal counsel in all its Coastal Zone cases to take all

actions necessary to cause the dismissal of all such cases. On April 14, 2016, following interventions in the suit by the Louisiana Department of Natural Resources and Attorney General, the Parish Council passed a resolution rescinding its November 12, 2015 resolution that had directed its counsel to dismiss the suit. We intend to continue to vigorously defend the suit.

Vermilion Parish Louisiana Coastal Zone Litigation

On July 28, 2016, the District Attorney for the 15th Judicial District of Louisiana, purporting to act on behalf of Vermilion Parish and the State of Louisiana, filed suit in the state district court for Vermilion Parish, Louisiana against TGP and 52 other energy companies, alleging that the defendants’ oil and gas and transportation operations associated with the development of several fields in Vermilion Parish (Operational Areas) were conducted in violation of the Coastal Zone Management Act. The suit alleges such operations caused substantial damage to the coastal waters and nearby lands (Coastal Zone) of Vermilion Parish, resulting in the release of pollutants and contaminants into the environment, improper discharge of oil field wastes, the improper use of waste pits and failure to close such pits, and the dredging of canals, which resulted in degradation of the Operational Areas, including erosion of marshes and degradation of terrestrial and aquatic life therein. As a result of such alleged violations of the Coastal Zone Management Act, the suit seeks a judgment against the defendants awarding all appropriate damages, the payment of costs to clear, revegetate, detoxify and otherwise restore the Vermilion Parish Coastal Zone, actual restoration of the affected Coastal Zone to its original condition, and reasonable costs and attorney fees. On September 2, 2016, the case was removed to the United States District Court for the Western District of Louisiana. On September 20, 2016, the plaintiffs filed a motion to remand the case back to the state district court. A hearing on this motion has been continued until a decision has been reached by the U.S. Court of Appeals for the Fifth Circuit in the Southeast Louisiana Flood Protection Litigation discussed above.

Vintage Assets, Inc. Coastal Erosion Litigation

On December 18, 2015, Vintage Assets, Inc. filed a petition in the 25th Judicial District Court for Plaquemines Parish, Louisiana alleging that its 5,000 acre property is composed of coastal wetlands, and that SNG, TGP, and certain other defendants failed to maintain pipeline canals and banks, causing widening of the canals, land loss, and damage to the ecology and hydrology of the marsh, in breach of right of way agreements, prudent operating practices, and Louisiana law. The suit also claims that defendants’ alleged failure to maintain pipeline canals and banks constitutes negligence and has resulted in encroachment of the canals, constituting trespass. The suit seeks in excess of $80 million in money damages, including recovery of litigation costs, damages for trespass, and money damages associated with an alleged loss of natural resources and projected reconstruction cost of replacing or restoring wetlands. The suit was removed to the U.S. District Court for the Eastern District of Louisiana. The SNG assets at issue were sold to Highpoint Gas Transmission, LLC in 2011, which was subsequently purchased by American Midstream Partners, LP. In response to SNG’s demand for defense and indemnity, American Midstream Partners agreed to pay 50% of joint defense costs and expenses, with a percentage of indemnity to be determined upon final resolution of the suit. On October 20, 2016, plaintiffs filed an amended complaint naming Highpoint Gas Transmission, LLC as an additional defendant. A non-jury trial is scheduled to begin on September 11, 2017 and we intend to vigorously defend the suit.

General

Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we and our subsidiaries are a party, will not have a material adverse effect on our business, financial position, results of operations or cash flows. As of December 31, 2016 and 2015, we have accrued a total reserve for environmental liabilities in the amount of $302 million and $284 million, respectively. In addition, as of December 31, 2016 and 2015, we have recorded a receivable of $13 million for expected cost recoveries that have been deemed probable.

  1. Recent Accounting Pronouncements

Accounting Standards Updates

Topic 606

On May 28, 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” followed by a series of related accounting standard updates (collectively referred to as “Topic 606”). Topic 606 is designed to create greater revenue recognition and disclosure comparability in financial statements. The provisions of Topic 606 include a five-step process by which an entity will determine revenue recognition, depicting the transfer of goods or services to customers in amounts

reflecting the payment to which an entity expects to be entitled in exchange for those goods or services. Topic 606 requires certain disclosures about contracts with customers and provides more comprehensive guidance for transactions such as service revenue, contract modifications, and multiple-element arrangements.

We are in the process of comparing our current revenue recognition policies to the requirements of Topic 606 for each of our revenue categories. While we have not identified any material differences in the amount and timing of revenue recognition for the categories we have reviewed to date, our evaluation is not complete and we have not concluded on the overall impacts of adopting Topic 606. Topic 606 will require that our revenue recognition policy disclosure include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers. Topic 606 will also require disclosure of significant changes in contract asset and contract liability balances period to period and the amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) as of the end of the reporting period, as applicable. We will adopt Topic 606 effective January 1, 2018. Topic 606 provides for adoption either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. We plan to make a determination as to our method of adoption once we more fully complete our evaluation of the impacts of the standard on our revenue recognition and we are better able to evaluate the cost-benefit of each method.

ASU No. 2014-15

On August 27, 2014, the FASB issued ASU No. 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.” This ASU provides guidance about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures if management concludes that substantial doubt exists or that its plans alleviate substantial doubt that was raised. We adopted ASU 2014-15 for the year ended December 31, 2016 with no impact to our financial statements.

ASU No. 2015-02

On February 18, 2015, the FASB issued ASU No. 2015-02, “Consolidation (Topic 810) - Amendments to the Consolidated Analysis.” This ASU focuses on the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. We adopted ASU No. 2015-02 effective January 1, 2016 with no impact to our financial statements.

ASU No. 2015-11

On July 22, 2015, the FASB issued ASU No. 2015-11, “Inventory (Topic 330): Simplifying the Measurement of Inventory.” This ASU requires entities to subsequently measure inventory at the lower of cost and net realizable value, and defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. ASU No. 2015-11 was effective January 1, 2017. We do not expect the effect of ASU No. 2015-11 to have a material impact on our financial statements.

ASU No. 2016-02

On February 25, 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” This ASU requires that lessees will be required to recognize assets and liabilities on the balance sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months. The ASU also will require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. ASU 2016-02 will be effective for us as of January 1, 2019. We are currently reviewing the effect of ASU No. 2016-02.

ASU No. 2016-05

On March 10, 2016, the FASB issued ASU 2016-05, “Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships.” This ASU clarifies that for the purposes of applying the guidance in Topic 815, a change in the counterparty to a derivative instrument that has been designated as the hedging instrument in an existing hedging relationship would not, in and of itself, be considered a termination of the derivative instrument. We adopted ASU 2016-05 in the first quarter of 2016 with no material impact to our financial statements.

ASU No. 2016-09

On March 30, 2016, the FASB issued ASU 2016-09, “Compensation - Stock Compensation (Topic 718).” This ASU was issued as part of the FASB’s simplification initiative and affects all entities that issue share-based payment awards to their employees. This ASU covers accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. ASU No. 2016-09 was effective January 1, 2017. We do not expect the effect of ASU No. 2016-09 to have a material impact on our financial statements.

ASU No. 2016-13

On June 16, 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This ASU modifies the impairment model to utilize an expected loss methodology in place of the currently used incurred loss methodology, which will result in the more timely recognition of losses. ASU No. 2016-13 will be effective for us as of January 1, 2020. We are currently reviewing the effect of ASU No. 2016-13.

ASU No. 2016-15

On August 26, 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments (Topic 230).” This ASU is intended to reduce the diversity in practice around how certain transactions are classified within the statement of cash flows. We adopted ASU No. 2016-15 in the third quarter of 2016 with no material impact to our financial statements.

ASU No. 2016-18

On November 17, 2016, the FASB issued ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force).” This ASU requires the statement of cash flows to explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are to be included with cash and cash equivalents when reconciling the beginning of period and end of period amounts shown on the statement of cash flows. ASU No. 2016-18 will be effective for us as of January 1, 2018. We are currently reviewing the effect of this ASU to our financial statements.

ASU No. 2017-04

On January 26, 2017, the FASB issued ASU 2017-04, “ASU 2017-04 Simplifying the Test for Goodwill Impairment (Topic 350)” to simplify the accounting for goodwill impairment. The guidance removes Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. ASU No. 2017-04 will be effective for us as of January 1, 2020. We are currently reviewing the effect of this ASU to our financial statements.

  1. Guarantee of Securities of Subsidiaries

KMI, along with its direct subsidiary KMP, are issuers of certain public debt securities. KMI, KMP and substantially all of KMI’s wholly owned domestic subsidiaries, are parties to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement. Accordingly, with the exception of certain subsidiaries identified as Subsidiary Non-Guarantors, the parent issuer, subsidiary issuer and other subsidiaries are all guarantors of each series of public debt. As a result of the cross guarantee agreement, a holder of any of the guaranteed public debt securities issued by KMI or KMP are in the same position with respect to the net assets, income and cash flows of KMI and the Subsidiary Issuer and Guarantors. The only amounts that are not available to the holders of each of the guaranteed public debt securities to satisfy the repayment of such securities are the net assets, income and cash flows of the Subsidiary Non-Guarantors.

In lieu of providing separate financial statements for subsidiary issuer and guarantor, we have included the accompanying condensed consolidating financial statements based on Rule 3-10 of the SEC’s Regulation S-X. We have presented each of the parent and subsidiary issuer in separate columns in this single set of condensed consolidating financial statements.

On September 30, 2016, Copano (previously reflected as a Subsidiary Issuer and Guarantor) repaid the $332 million principal amount of its 7.125% senior notes due 2021. Copano continues to be a subsidiary guarantor under the cross guarantee

agreement mentioned above. For all periods presented, financial statement balances and activities for Copano are now reflected within the Subsidiary Guarantor column, and the Subsidiary Issuer and Guarantor-Copano column has been eliminated.

On September 1, 2016, we sold a 50% equity interest in SNG (see further details discussed in Note 3, “Acquisitions and Divestitures”). Subsequent to the transaction, we deconsolidated SNG and now account for our equity interest in SNG as an equity investment. Our wholly owned subsidiary which holds our interest in SNG is reflected within the Subsidiary Guarantors column of these condensed consolidating financial statements.

Excluding fair value adjustments, as of December 31, 2016, Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, and Subsidiary Guarantors had $14,235 million, $19,485 million, and $4,191 million of Guaranteed Notes outstanding, respectively. Included in the Subsidiary Guarantors debt balance as presented in the accompanying December 31, 2016 condensed consolidating balance sheets are approximately $169 million of capitalized lease debt that is not subject to the cross guarantee agreement.

The accounts within the Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, Subsidiary Guarantors and Subsidiary Non-Guarantors are presented using the equity method of accounting for investments in subsidiaries, including subsidiaries that are guarantors and non-guarantors, for purposes of these condensed consolidating financial statements only. These intercompany investments and related activity eliminate in consolidation and are presented separately in the accompanying condensed consolidating balance sheets and statements of income and cash flows.

A significant amount of each Issuers’ income and cash flow is generated by its respective subsidiaries. As a result, the funds necessary to meet its debt service and/or guarantee obligations are provided in large part by distributions or advances it receives from its respective subsidiaries. We utilize a centralized cash pooling program among our majority-owned and consolidated subsidiaries, including the Subsidiary Issuers and Guarantors and Subsidiary Non-Guarantors. The following Condensed Consolidating Statements of Cash Flows present the intercompany loan and distribution activity, as well as cash collection and payments made on behalf of our subsidiaries, as cash activities.

Condensed Consolidating Statements of Income and Comprehensive Income for the Year Ended December 31, 2016 (In Millions)
Parent Issuer and GuarantorSubsidiary Issuer and Guarantor - KMPSubsidiary GuarantorsSubsidiary Non-GuarantorsConsolidating AdjustmentsConsolidated KMI
Total Revenues$34$—$11,572$1,511$(59)$13,058
Operating Costs, Expenses and Other
Costs of sales——3,245266(13)3,498
Depreciation, depletion and amortization18—1,872319—2,209
Other operating expenses725(36)2,390746(46)3,779
Total Operating Costs, Expenses and Other743(36)7,5071,331(59)9,486
Operating (Loss) Income(709)364,065180—3,572
Other Income (Expense)
Earnings from consolidated subsidiaries2,9482,82624559(6,078)—
Losses from equity investments——(113)——(113)
Interest, net(696)90(1,149)(51)—(1,806)
Amortization of excess cost of equity investments and other, net——(20)5—(15)
Income Before Income Taxes1,5432,9523,028193(6,078)1,638
Income Tax Expense(835)(5)(33)(44)—(917)
Net Income7082,9472,995149(6,078)721
Net Income Attributable to Noncontrolling Interests————(13)(13)
Net Income Attributable to Controlling Interests7082,9472,995149(6,091)708
Preferred Stock Dividends(156)————(156)
Net Income Available to Common Stockholders$552$2,947$2,995$149$(6,091)$552
Net Income$708$2,947$2,995$149$(6,078)$721
Total other comprehensive (loss) income(200)(341)(352)55638(200)
Comprehensive income5082,6062,643204(5,440)521
Comprehensive income attributable to noncontrolling interests————(13)(13)
Comprehensive income attributable to controlling interests$508$2,606$2,643$204$(5,453)$508
Condensed Consolidating Statements of Income and Comprehensive Income for the Year Ended December 31, 2015 (In Millions)
Parent Issuer and GuarantorSubsidiary Issuer and Guarantor - KMPSubsidiary GuarantorsSubsidiary Non-GuarantorsConsolidating AdjustmentsConsolidated KMI
Total Revenues$37$—$12,840$1,575$(49)$14,403
Operating Costs, Expenses and Other
Costs of sales——3,74736714,115
Depreciation, depletion and amortization22—1,929358—2,309
Other operating expenses71384,714759(50)5,532
Total Operating Costs, Expenses and Other933810,3901,484(49)11,956
Operating (Loss) Income(56)(38)2,45091—2,447
Other Income (Expense)
Earnings (losses) from consolidated subsidiaries1,4301,643118(30)(3,161)—
Earnings from equity investments——384——384
Interest, net(686)23(1,345)(43)—(2,051)
Amortization of excess cost of equity investments and other, net—1(17)8—(8)
Income Before Income Taxes6881,6291,59026(3,161)772
Income Tax Expense(435)(4)(6)(119)—(564)
Net Income (Loss)2531,6251,584(93)(3,161)208
Net Loss Attributable to Noncontrolling Interests————4545
Net Income (Loss) Attributable to Controlling Interests253$1,625$1,584$(93)$(3,116)$253
Preferred Stock Dividends(26)$—$—$—$—$(26)
Net Income (Loss) Available to Common Stockholders$227$1,625$1,584$(93)$(3,116)$227
Net Income (Loss)$253$1,625$1,584$(93)$(3,161)$208
Total other comprehensive loss(444)(460)(325)(326)1,111(444)
Comprehensive (loss) income(191)1,1651,259(419)(2,050)(236)
Comprehensive loss attributable to noncontrolling interests————4545
Comprehensive (loss) income attributable to controlling interests$(191)$1,165$1,259$(419)$(2,005)$(191)
Condensed Consolidating Statements of Income and Comprehensive Income for the Year Ended December 31, 2014 (In Millions)
Parent Issuer and GuarantorSubsidiary Issuer and Guarantor - KMPSubsidiary GuarantorsSubsidiary Non-GuarantorsConsolidating AdjustmentsConsolidated KMI
Total Revenues$36$—$14,575$1,621$(6)$16,226
Operating Costs, Expenses and Other
Costs of sales——5,738498426,278
Depreciation, depletion and amortization21—1,686333—2,040
Other operating expenses3052,972501(48)3,460
Total Operating Costs, Expenses and Other51510,3961,332(6)11,778
Operating (Loss) Income(15)(5)4,179289—4,448
Other Income (Expense)
Earnings from consolidated subsidiaries2,0803,9774431,120(7,620)—
Earnings (losses) from equity investments——407(1)—406
Interest, net(513)(111)(1,084)(90)—(1,798)
Amortization of excess cost of equity investments and other, net——(13)48—35
Income Before Income Taxes1,5523,8613,9321,366(7,620)3,091
Income Tax Expense(278)(7)(71)(292)—(648)
Net Income1,2743,8543,8611,074(7,620)2,443
Net Income Attributable to Noncontrolling Interests(248)(211)——(958)(1,417)
Net Income Attributable to Controlling Interests$1,026$3,643$3,861$1,074$(8,578)$1,026
Net Income$1,274$3,854$3,861$1,074$(7,620)$2,443
Total other comprehensive (loss) income(24)275288(168)(351)20
Comprehensive income1,2504,1294,149906(7,971)2,463
Comprehensive income attributable to noncontrolling interests(273)(203)——(1,010)(1,486)
Comprehensive income attributable to controlling interests$977$3,926$4,149$906$(8,981)$977
Condensed Consolidating Balance Sheets as of December 31, 2016 (In Millions)
Parent Issuer and GuarantorSubsidiary Issuer and Guarantor - KMPSubsidiary GuarantorsSubsidiary Non-GuarantorsConsolidating AdjustmentsConsolidated KMI
ASSETS
Cash and cash equivalents$471$—$9$205$(1)$684
Other current assets - affiliates5,7391,99913,207655(21,600)—
All other current assets2691391,935205(3)2,545
Property, plant and equipment, net242—30,7957,668—38,705
Investments66526,236124—7,027
Investments in subsidiaries26,90729,4214,3074,028(64,663)—
Goodwill13,789225,1673,174—22,152
Notes receivable from affiliates51621,6081,132412(23,668)—
Deferred income taxes6,647———(2,295)4,352
Other non-current assets722064,455107—4,840
Total assets$55,317$53,397$67,243$16,578$(112,230)$80,305
LIABILITIES AND STOCKHOLDERS’ EQUITY
Liabilities
Current portion of debt$1,286$600$687$123$—$2,696
Other current liabilities - affiliates3,55113,2994,197553(21,600)—
All other current liabilities4323622,016422(4)3,228
Long-term debt13,30819,2774,095674—37,354
Notes payable to affiliates1,53344820,5201,167(23,668)—
Deferred income taxes——6811,614(2,295)—
Other long-term liabilities and deferred credits776111821517—2,225
Total liabilities20,88634,09733,0175,070(47,567)45,503
Stockholders’ equity
Total KMI equity34,43119,30034,22611,508(65,034)34,431
Noncontrolling interests————371371
Total stockholders’ equity34,43119,30034,22611,508(64,663)34,802
Total liabilities and stockholders’ equity$55,317$53,397$67,243$16,578$(112,230)$80,305
Condensed Consolidating Balance Sheets as of December 31, 2015 (In Millions)
Parent Issuer and GuarantorSubsidiary Issuer and Guarantor - KMPSubsidiary GuarantorsSubsidiary Non-GuarantorsConsolidating AdjustmentsConsolidated KMI
ASSETS
Cash and cash equivalents$123$—$12$142$(48)$229
Other current assets - affiliates2,2331,6009,410688(13,931)—
All other current assets1261192,161195(6)2,595
Property, plant and equipment, net252—33,0327,263—40,547
Investments1625,906116—6,040
Investments in subsidiaries27,40128,0383,4933,320(62,252)—
Goodwill15,089225,5083,171—23,790
Notes receivable from affiliates85021,3192,092358(24,619)—
Deferred income taxes7,501———(2,178)5,323
Other non-current assets2153074,951107—5,580
Total assets$53,806$51,407$66,565$15,360$(103,034)$84,104
LIABILITIES AND STOCKHOLDERS’ EQUITY
Liabilities
Current portion of debt$67$500$132$122$—$821
Other current liabilities - affiliates1,3288,6823,210711(13,931)—
All other current liabilities3214581,992527(54)3,244
Long-term debt13,84520,0537,825683—42,406
Notes payable to affiliates2,40444820,4621,305(24,619)—
Deferred income taxes——5961,582(2,178)—
All other long-term liabilities and deferred credits722193909406—2,230
Total liabilities18,68730,33435,1265,336(40,782)48,701
Stockholders’ equity
Total KMI equity35,11921,07331,43910,024(62,536)35,119
Noncontrolling interests————284284
Total stockholders’ equity35,11921,07331,43910,024(62,252)35,403
Total liabilities and stockholders’ equity$53,806$51,407$66,565$15,360$(103,034)$84,104
Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2016 (In Millions)
Parent Issuer and GuarantorSubsidiary Issuer and Guarantor - KMPSubsidiary GuarantorsSubsidiary Non-GuarantorsConsolidating AdjustmentsConsolidated KMI
Net cash (used in) provided by operating activities$(3,989)$4,980$11,641$885$(8,730)$4,787
Cash flows from investing activities
Acquisitions of assets and investments, net of cash acquired(2)—(331)——(333)
Capital expenditures(27)—(2,258)(597)—(2,882)
Proceeds from sale of equity interests in subsidiaries, net——1,401——1,401
Sales of property, plant and equipment, investments and other net assets, net of removal costs6—326(2)—330
Contributions to investments(343)—(54)(11)—(408)
Distributions from equity investments in excess of cumulative earnings2,417298190—(2,674)231
Funding to affiliates(2,820)(535)(5,062)(727)9,144—
Other, net—(73)39(10)—(44)
Net cash used in investing activities(769)(310)(5,749)(1,347)6,470(1,705)
Cash flows from financing activities
Issuances of debt8,255—374——8,629
Payments of debt(7,322)(500)(2,227)(11)—(10,060)
Debt issue costs(16)—(2)(1)—(19)
Cash dividends - common shares(1,118)————(1,118)
Cash dividends - preferred shares(154)————(154)
Funding from affiliates5,4611,1161,959608(9,144)—
Contributions from parents——117—(117)—
Contributions from noncontrolling interests————117117
Distributions to parents—(5,286)(6,116)(73)11,475—
Distributions to noncontrolling interests————(24)(24)
Net cash provided by (used in) financing activities5,106(4,670)(5,895)5232,307(2,629)
Effect of exchange rate changes on cash and cash equivalents———2—2
Net increase (decrease) in cash and cash equivalents348—(3)6347455
Cash and cash equivalents, beginning of period123—12142(48)229
Cash and cash equivalents, end of period$471$—$9$205$(1)$684
Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2015 (In Millions)
Parent Issuer and GuarantorSubsidiary Issuer and Guarantor - KMPSubsidiary GuarantorsSubsidiary Non-GuarantorsConsolidating AdjustmentsConsolidated KMI
Net cash (used in) provided by operating activities$(4,218)$6,824$11,039$347$(8,689)$5,303
Cash flows from investing activities
Acquisitions of assets and investments(1,843)—(236)——(2,079)
Capital expenditures(10)—(3,555)(331)—(3,896)
Sales of property, plant and equipment, investments and other net assets, net of removal costs——39——39
Contributions to investments(21)—(70)(10)5(96)
Distributions from equity investments in excess of cumulative earnings2,653—143—(2,568)228
Investment in KMP(159)———159—
Funding to affiliates(3,204)(8,388)(7,980)(779)20,351—
Other, net—241658—98
Net cash used in investing activities(2,584)(8,364)(11,643)(1,062)17,947(5,706)
Cash flows from financing activities
Issuances of debt14,316————14,316
Payments of debt(14,048)(675)(383)(10)—(15,116)
Debt issue costs(24)————(24)
Issuances of common shares3,870————3,870
Issuance of mandatory convertible preferred stock1,541————1,541
Cash dividends - common shares(4,224)————(4,224)
Repurchases of shares and warrants(12)————(12)
Merger Transactions costs(2)————(2)
Funding from affiliates5,5026,9897,112748(20,351)—
Contributions from parents—156316(175)—
Contributions from noncontrolling interests————1111
Distributions to parents—(4,944)(6,133)(166)11,243—
Distributions to noncontrolling interests————(34)(34)
Other, net2(1)———1
Net cash provided by financing activities6,9211,525599588(9,306)327
Effect of exchange rate changes on cash and cash equivalents———(10)—(10)
Net increase (decrease) in cash and cash equivalents119(15)(5)(137)(48)(86)
Cash and cash equivalents, beginning of period41517279—315
Cash and cash equivalents, end of period$123$—$12$142$(48)$229
Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2014 (In Millions)
Parent Issuer and GuarantorSubsidiary Issuer and Guarantor - KMPSubsidiary GuarantorsSubsidiary Non-GuarantorsConsolidating AdjustmentsConsolidated KMI
Net cash provided by operating activities$1,419$3,810$6,059$641$(7,462)$4,467
Cash flows from investing activities
Acquisitions of assets and investments——(1,370)(18)—(1,388)
Capital expenditures(1)—(2,911)(705)—(3,617)
Sales of property, plant and equipment, investments, and other net assets, net of removal costs——(9)14—5
Contributions to investments—(189)(389)—189(389)
Distributions from equity investments in excess of cumulative earnings93440183—(534)182
Investment in KMP(550)———550—
Drop down assets to KMP875(875)————
Funding to affiliates(1,949)(6,644)(3,826)(784)13,203—
Other, net—2729(60)1(3)
Net cash used in investing activities(1,532)(7,241)(8,293)(1,553)13,409(5,210)
Cash flows from financing activities
Issuances of debt10,59413,979———24,573
Payments of debt(5,479)(12,171)(142)(9)—(17,801)
Debt issue costs(74)(15)———(89)
Cash dividends - common shares(1,760)————(1,760)
Repurchases of shares and warrants(192)————(192)
Cash consideration of Merger Transactions(3,937)————(3,937)
Merger Transactions costs(74)————(74)
Funding from affiliates9564,1297,241877(13,203)—
Contributions from parents—1,91253364(2,509)—
Contributions from noncontrolling interests————1,7671,767
Distributions to parents—(4,475)(5,398)(138)10,011—
Distributions to noncontrolling interests————(2,013)(2,013)
Other, net—(1)(2)——(3)
Net cash provided by financing activities343,3582,232794(5,947)471
Effect of exchange rate changes on cash and cash equivalents——1(12)—(11)
Net decrease in cash and cash equivalents(79)(73)(1)(130)—(283)
Cash and cash equivalents, beginning of period838818409—598
Cash and cash equivalents, end of period$4$15$17$279$—$315
Supplemental Selected Quarterly Financial Data (Unaudited)
Quarters Ended
March 31June 30September 30December 31
(In millions, except per share amounts)
2016
Revenues$3,195$3,144$3,330$3,389
Operating Income816940882934
Net Income (Loss)314375(183)215
Net Income (Loss) Attributable to Kinder Morgan, Inc.315372(188)209
Net Income (Loss) Available to Common Stockholders276333(227)170
Basic and Diluted Earnings (Loss) Per Common Share0.120.15(0.10)0.08
2015
Revenues$3,597$3,463$3,707$3,636
Operating Income (Loss)1,078892721(244)
Net Income (Loss)419342183(736)
Net Income (Loss) Attributable to Kinder Morgan, Inc.429333186(695)
Net Income (Loss) Available to Common Stockholders429333186(721)
Basic and Diluted Earnings (Loss) Per Common Share0.200.150.08(0.32)

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