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 77.
(3)Exhibits
Exhibit NumberDescription
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., and P Merger Sub LLC (schedules omitted pursuant to Item 601(b)(2) of Regulation S-K) (filed as Exhibit 2.1 to Kinder Morgan, Inc.’s Current Report on Form 8-K (File No. 1-35081), filed August 12, 2014)
2.2*Agreement and Plan of Merger, dated as of August 9, 2014, by and among Kinder Morgan Management, LLC, Kinder Morgan, Inc., and R Merger Sub LLC (schedules omitted pursuant to Item 601(b)(2) of Regulation S-K) (filed as Exhibit 2.2 to Kinder Morgan, Inc.’s Current Report on Form 8-K (File No. 1-35081), filed August 12, 2014)
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., Kinder Morgan, Inc., and E Merger Sub LLC (schedules omitted pursuant to Item 601(b)(2) of Regulation S-K) (filed as Exhibit 2.3 to Kinder Morgan, Inc.’s Current Report on Form 8-K (File No. 1-35081), filed August 12, 2014)
3.1Certificate of Incorporation of Kinder Morgan, Inc. as amended by the Certificate of Amendment to the Certificate of Incorporation
3.2Amended and Restated Bylaws of Kinder Morgan, Inc. as amended by the Amendment No. 1 to the Amended and Restated Bylaws
4.1*Form of certificate representing Class P common shares of Kinder Morgan, Inc. (filed as Exhibit 4.1 to Kinder Morgan, Inc.’s Registration Statement on Form S-1 filed on January 18, 2011 (File No. 333-170773))
4.2*Shareholders Agreement among Kinder Morgan, Inc. and certain holders of common stock (filed as Exhibit 4.2 to the KMI 10-Q)
4.3*Amendment No. 1 to the Shareholders Agreement among Kinder Morgan, Inc. and certain holders of common stock (filed as Exhibit 4.3 Kinder Morgan, Inc.’s Current Report on Form 8-K filed on May 30, 2012 (File No. 1-35081))
4.4*Amendment No. 2 to the Shareholders Agreement among Kinder Morgan, Inc. and certain holders of common stock (filed as Exhibit 4.1 to Kinder Morgan, Inc.’s Current Report on Form 8-K filed on December 3, 2014 (File No. 1-35081))
4.5*Warrant Agreement, dated as of May 25, 2012, among Kinder Morgan, Inc., Computershare Trust Company, N.A. and Computershare Inc., as Warrant Agent (filed as Exhibit 4.1 to Kinder Morgan Inc.’s Current Report on Form 8-K filed on May 30, 2012 (File No. 1-35081))
10.1*Kinder Morgan, Inc. 2011 Stock Incentive Plan (filed as Exhibit 10.1 to the KMI 10-Q)
10.2*Form of Restricted Stock Agreement (filed as Exhibit 10.2 to the KMI 10-Q)
10.3*Kinder Morgan, Inc. Stock Compensation Plan for Non-Employee Directors (filed as Exhibit 10.4 to the KMI 10-Q)
10.4*Form of Non-Employee Director Stock Compensation Agreement (filed as Exhibit 10.3 to the KMI 10-Q)
10.5*Kinder Morgan, Inc. Employees Stock Purchase Plan (filed as Exhibit 10.5 to the KMI 10-Q)
10.6*Kinder Morgan, Inc. Annual Incentive Plan (filed as Exhibit 10.6 to the KMI 10-Q)
10.7*Employment Agreement dated October 7, 1999, between K N Energy, Inc. and Richard D. Kinder (filed as Exhibit 99.D of the Schedule 13D filed by Mr. Kinder on November 16, 1999 (File No. 5-06259))
10.8*Credit Agreement, dated as of May 30, 2007, among Kinder Morgan Kansas, Inc. and Kinder Morgan Acquisition Co., as the borrower, the several lenders from time to time parties thereto, and Citibank, N.A., as administrative agent and collateral agent (filed as Exhibit 10.10 to Kinder Morgan, Inc.’s Registration Statement on Form S-1 filed on December 30, 2010 (File No. 333-170773))
10.9*Registration Rights Agreement among Kinder Morgan Management, LLC, Kinder Morgan Energy Partners, L.P. and Kinder Morgan Kansas, Inc. dated May 18, 2001 (filed as Exhibit 4.7 to Kinder Morgan Kansas, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 1-06446))
10.10*Form of Indenture dated as of August 27, 2002 between Kinder Morgan Kansas, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100338))
10.11*Form of First Supplemental Indenture dated as of December 6, 2002 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-4 filed on January 31, 2003 (File No. 333-102873))
10.12*Form of 6.50% Note due 2012 (included in the Indenture filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100338))
10.13*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))
10.14*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))
10.15*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))
10.16*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))
10.17*Form of Indemnification Agreement between Kinder Morgan Kansas, Inc. and each member of the Special Committee of the Board of Directors formed in connection with the Going Private Transaction (filed as Exhibit 10.1 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on June 16, 2006 (File No. 1-06446))
10.18*Delegation of Control Agreement among Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan Energy Partners, L.P. and its operating partnerships (filed as Exhibit 10.1 to the Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2001 (File No. 1-11234))
10.19*Amendment No. 1 to Delegation of Control Agreement, dated as of July 20, 2007, among Kinder Morgan G.P., Inc., Kinder Morgan Management, LLC, Kinder Morgan Energy Partners, L.P. and its operating partnerships (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.’s Current Report on Form 8-K on July 20, 2007 (File No. 1-11234))
10.20*Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2001 (File No. 1-11234))
10.21*Amendment No. 1 dated November 19, 2004 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed November 22, 2004 (File No. 1-11234))
10.22*Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed May 5, 2005 (File No. 1-11234))
10.23*Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed April 21, 2008 (File No. 1-11234))
10.24*Amendment No. 4 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.5 to Kinder Morgan Energy Partners, L.P. Form 10-K 2012 (File No. 1-11234))
10.25*Credit Agreement dated as of June 23, 2010 among Kinder Morgan Energy Partners, L.P., Kinder Morgan Operating L.P. “B”, the lenders party thereto, Wells Fargo Bank, National Association as Administrative Agent, Bank of America, N.A., Citibank, N.A., JPMorgan Chase Bank, N.A., and DnB NOR Bank ASA (filed as exhibit 10.1 to Kinder Morgan Energy Partners, L.P. Current Report on Form 8-K filed June 24, 2010 (File No. 1-11234))
10.26*First Amendment to Credit Agreement, dated as of July 1, 2011, among Kinder Morgan Energy Partners, L.P., Kinder Morgan Operating L.P. “B”, the lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 1-11234))
10.27*Indenture dated as of January 29, 1999 among Kinder Morgan Energy Partners, L.P., the guarantors listed on the signature page thereto and U.S. Trust Company of Texas, N.A., as trustee, relating to Senior Debt Securities (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Current Report on Form 8-K filed February 16, 1999 (File No. 1-11234))
10.28*Indenture dated November 8, 2000 between Kinder Morgan Energy Partners, L.P. and First Union National Bank, as Trustee (filed as Exhibit 4.8 to Kinder Morgan Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2001 (File No. 1-11234))
10.29*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. Annual Report on Form 10-K for the year ended December 31, 2000 (File No. 1-11234))
10.30*Certificate of Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 6.75% Notes due March 15, 2011 and the 7.40% Notes due March 15, 2031 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Current Report on Form 8-K filed on March 14, 2001 (File No. 1-11234))
10.31*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. Current Report on Form 8-K filed on March 14, 2001(File No. 1-11234))
10.32*Certificate of Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 7.125% Notes due March 15, 2012 and the 7.750% Notes due March 15, 2032 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended March 31, 2002 (File No. 1-11234))
10.33*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. Quarterly Report on Form 10-Q for the quarter ended March 31, 2002 (File No. 1-11234))
10.34*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 the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346))
10.35*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. Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346))
10.36*Form of 7.30% Note (contained in the Indenture filed as Exhibit 4.1 to the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346))
10.37*Senior Indenture dated January 31, 2003 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association (filed as Exhibit 4.2 to the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102961))
10.38*Form of Senior Note of Kinder Morgan Energy Partners, L.P. (included in the Form of Senior Indenture filed as Exhibit 4.2 to the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102961))
10.39*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. Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 (File No. 1-11234))
10.40*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. Annual Report on Form 10-K for the year ended December 31, 2006 (File No. 1-11234))
10.41*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. Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 1-11234))
10.42*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. Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 1-11234))
10.43*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. Annual Report on Form 10-K for the year ended December 31, 2008 (File No. 1-11234))
10.44*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 5.625% Senior Notes due 2015, and the 6.85% Senior Notes due 2020 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended June 30, 2009 (File No. 1-11234))
10.45*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. Quarterly Report on Form 10-Q for the quarter ended September 30, 2009 (File No. 1-11234))
10.46*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. Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 (File No. 1-11234))
10.47*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))
10.48*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))
10.49*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 3.500% Senior Notes due 2016, and 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))
10.50*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))
10.51*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))
10.52*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))
10.53Certificate of the Vice President and Treasurer and the Vice President and Secretary of Kinder Morgan, Inc. 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
10.54*Debt Commitment Letter between Kinder Morgan, Inc. and Barclays Capital PLC, dated as of October 16, 2011 (filed as Exhibit 10.71 to Kinder Morgan, Inc.’s Registration Statement on Form S-4 filed on December 14, 2011 (File No. 333-177895))
10.55*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 Kinder Morgan, Inc.’s Current Report on Form 8-K (File No. 1-35081), filed August 12, 2014)
10.56*Bridge Credit Agreement, dated September 19, 2014 among Kinder Morgan, Inc., as borrower, Barclays Bank PLC, as administrative agent, and the lenders party thereto (filed as Exhibit 10.1 to Kinder Morgan, Inc.’s Current Report on Form 8-K (File No. 1-35081), filed September 25, 2014)
10.57*Revolving Credit Agreement, dated September 19, 2014 among Kinder Morgan, Inc., as borrower, Barclays Bank PLC, as administrative agent, and the lenders and issuing banks party thereto (filed as Exhibit 10.2 to Kinder Morgan, Inc.’s Current Report on Form 8-K (File No. 1-35081), filed September 25, 2014)
10.58Cross Guarantee Agreement, dated as of November 26, 2014 among Kinder Morgan, Inc. and certain of its subsidiaries with schedules updated as of February 13, 2015
12.1Statement re: computation of ratio of earnings to fixed charges
21.1Subsidiaries of Kinder Morgan, Inc.
23.1Consent of PricewaterhouseCoopers LLP
23.2Consent of Netherland, Sewell & Associates, Inc.
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
99.1Netherland, Sewell & Associates, Inc.’s report of estimates of the net reserves and future net revenues, as of December 31, 2014, related to Kinder Morgan CO2 Company, L.P.’s interest in certain oil and gas properties located in the state of Texas
101Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Statements of Income for the years ended December 31, 2014, 2013, and 2012; (ii) our Consolidated Statements of Comprehensive Income for the years ended December 31, 2014, 2013, and 2012; (iii) our Consolidated Balance Sheets as of December 31, 2014 and 2013; (iv) our Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013, and 2012; (v) our Consolidated Statement of Stockholders’ Equity as of and for the years ended December 31, 2014, 2013, and 2012; 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 Firm78
Consolidated Statements of Income for the years ended December 31, 2014, 2013 and 201279
Consolidated Statements of Comprehensive Income for the years ended December 31, 2014, 2013 and 201281
Consolidated Balance Sheets as of December 31, 2014 and 201382
Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 201284
Consolidated Statement of Stockholders’ Equity as of and for the years ended December 31, 2014, 2013 and 201286
Notes to Consolidated Financial Statements87

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, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 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, 2014, 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 2014 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 23, 2015

KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In Millions, Except Per Share Amounts)
Year Ended December 31,
201420132012
Revenues
Natural gas sales$4,115$3,605$2,511
Services7,6506,6775,013
Product sales and other4,4613,7882,449
Total Revenues16,22614,0709,973
Operating Costs, Expenses and Other
Costs of sales6,2785,2533,057
Operations and maintenance2,1572,1121,702
Depreciation, depletion and amortization2,0401,8061,419
General and administrative610613929
Taxes, other than income taxes418395286
Loss on impairments of long-lived assets272——
Other expense (income), net3(99)(13)
Total Operating Costs, Expenses and Other11,77810,0807,380
Operating Income4,4483,9902,593
Other Income (Expense)
Earnings from equity investments406327153
Amortization of excess cost of equity investments(45)(39)(23)
Interest, net(1,798)(1,675)(1,399)
Gain on remeasurement of previously held equity investments to fair value (Note 3)—558—
Gain on sale of investments in Express pipeline system (Note 3)—224—
Other, net805319
Total Other Income (Expense)(1,357)(552)(1,250)
Income from Continuing Operations Before Income Taxes3,0913,4381,343
Income Tax Expense(648)(742)(139)
Income from Continuing Operations2,4432,6961,204
Discontinued Operations (Note 3)
Income from operations of the FTC Natural Gas Pipelines disposal group and other, net of tax——160
Loss on sale and the remeasurement of the FTC Natural Gas Pipelines disposal group to fair value, net of tax—(4)(937)
Loss from Discontinued Operations, Net of Tax—(4)(777)
Net Income2,4432,692427
Net Income Attributable to Noncontrolling Interests(1,417)(1,499)(112)
Net Income Attributable to Kinder Morgan, Inc.$1,026$1,193$315
KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (continued) (In Millions, Except Per Share Amounts)
Year Ended December 31,
201420132012
Class P Shares
Basic and Diluted Earnings Per Common Share From Continuing Operations$0.89$1.15$0.56
Basic and Diluted Loss Per Common Share From Discontinued Operations——(0.21)
Total Basic and Diluted Earnings Per Common Share$0.89$1.15$0.35
Class A Shares
Basic and Diluted Earnings Per Common Share From Continuing Operations$0.47
Basic and Diluted Loss Per Common Share From Discontinued Operations(0.21)
Total Basic and Diluted Earnings Per Common Share$0.26
Basic Weighted-Average Number of Shares Outstanding
Class P Shares1,1371,036461
Class A Shares446
Diluted Weighted-Average Number of Shares Outstanding
Class P Shares1,1371,036908
Class A Shares446
Dividends Per Common Share Declared for the Period$1.74$1.60$1.40

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In Millions)

Year Ended December 31,
201420132012
Kinder Morgan, Inc.
Net income$1,026$1,193$315
Other comprehensive income (loss), net of tax
Change in fair value of derivatives utilized for hedging purposes (net of tax (expense) benefit of $(150), $6 and $(19), respectively)254(14)32
Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of $13, $(2) and $3, respectively)(22)4(5)
Foreign currency translation adjustments (net of tax benefit (expense) of $41, $22, and $(8), respectively)(68)(49)14
Benefit plan adjustments (net of tax benefit (expense) of $125, $(88) and $30, respectively)(213)153(44)
Total other comprehensive (loss) income(49)94(3)
Total comprehensive income9771,287312
Noncontrolling Interests
Net income1,4171,499112
Other comprehensive income (loss), net of tax
Change in fair value of derivatives utilized for hedging purposes (net of tax (expense) benefit of $(13), $4 and $(7), respectively)155(24)50
Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of $-, $(1) and $-, respectively)(3)7(3)
Foreign currency translation adjustments (net of tax benefit (expense) of $7, $9 and $(2), respectively)(70)(54)18
Benefit plan adjustments (net of tax benefit (expense) of $1, $(3) and $-, respectively)(13)179
Total other comprehensive income (loss)69(54)74
Total comprehensive income1,4861,445186
Total
Net income2,4432,692427
Other comprehensive income (loss), net of tax
Change in fair value of derivatives utilized for hedging purposes (net of tax (expense) benefit of $(163), $10 and $(26), respectively)409(38)82
Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of $13, $(3) and $3, respectively)(25)11(8)
Foreign currency translation adjustments (net of tax benefit (expense) of $48, $31 and $(10), respectively)(138)(103)32
Benefit plan adjustments (net of tax benefit (expense) of $126, $(91) and $30, respectively)(226)170(35)
Total other comprehensive income204071
Total comprehensive income$2,463$2,732$498

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,
20142013
ASSETS
Current assets
Cash and cash equivalents$315$598
Accounts receivable, net1,6411,721
Fair value of derivative contracts535116
Inventories459430
Deferred income taxes56567
Other current assets746436
Total current assets3,7523,868
Property, plant and equipment, net38,56435,847
Investments6,0365,951
Goodwill24,65424,504
Other intangibles, net2,3022,438
Deferred income taxes5,651—
Deferred charges and other assets2,2392,577
Total Assets$83,198$75,185
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of debt$2,717$2,306
Accounts payable1,5881,676
Accrued interest637565
Accrued contingencies383584
Other current liabilities1,037944
Total current liabilities6,3626,075
Long-term liabilities and deferred credits
Long-term debt
Outstanding38,21231,810
Preferred interest in general partner of KMP100100
Debt fair value adjustments1,9341,977
Total long-term debt40,24633,887
Deferred income taxes—4,651
Other long-term liabilities and deferred credits2,1642,287
Total long-term liabilities and deferred credits42,41040,825
Total Liabilities$48,772$46,900
KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (continued) (In Millions, Except Share and Per Share Amounts)
December 31,
20142013
Commitments and contingencies (Notes 8, 12 and 16)
Stockholders’ Equity
Class P shares, $0.01 par value, 4,000,000,000 and 2,000,000,000 shares, respectively, authorized, 2,125,147,116 and 1,030,677,076 shares, respectively, issued and outstanding$21$10
Preferred stock, $0.01 par value, 10,000,000 shares authorized, none outstanding——
Additional paid-in capital36,17814,479
Retained deficit(2,106)(1,372)
Accumulated other comprehensive loss(17)(24)
Total Kinder Morgan, Inc.’s stockholders’ equity34,07613,093
Noncontrolling interests35015,192
Total Stockholders’ Equity34,42628,285
Total Liabilities and Stockholders’ Equity$83,198$75,185

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,
201420132012
Cash Flows From Operating Activities
Net income$2,443$2,692$427
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization2,0401,8061,426
Deferred income taxes61564047
Amortization of excess cost of equity investments453923
Loss on impairments of long-lived assets272——
(Gain) loss from the remeasurement of net assets to fair value and the sale of discontinued operations (net of cash selling expenses), net of tax (Note 3)—(556)859
Gain from sale of investments in Express pipeline system (Note 3)—(224)—
Loss on early extinguishment of debt——82
Noncash compensation expense on settlement of EP stock awards——87
Earnings from equity investments(406)(327)(223)
Distributions from equity investment earnings381398381
Proceeds from termination of interest rate swap agreements—9653
Pension contributions and noncash pension benefit credits(88)(120)(31)
Changes in components of working capital, net of the effects of acquisitions
Accounts receivable(84)(131)(231)
Income tax receivable(195)——
Inventories(30)(53)(92)
Other current assets(31)(24)32
Accounts payable(1)(36)70
Accrued interest7542(26)
Accrued contingencies and other current liabilities108(100)(68)
Rate reparations, refunds and other litigation reserve adjustments(280)174(39)
Other, net(397)(194)31
Net Cash Provided by Operating Activities4,4674,1222,808
Cash Flows From Investing Activities
Acquisition of EP, net of $6,581 cash acquired (Note 3)——(4,970)
Acquisitions of other assets and investments, net of cash acquired(1,388)(292)(83)
Proceeds from sales of assets and investments—490—
Proceeds from disposal of discountinued operations (Note 3)——1,791
Capital expenditures(3,617)(3,369)(2,022)
Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs587154
Contributions to investments(389)(217)(192)
Distributions from equity investments in excess of cumulative earnings182185200
Other, net(3)(6)25
Net Cash Used in Investing Activities(5,210)(3,122)(5,097)
Cash Flows From Financing Activities
Issuance of debt24,57313,58118,148
Payment of debt(17,801)(12,393)(14,755)
Debt issue costs(89)(38)(111)
Cash dividends (Note 10)(1,760)(1,622)(1,184)
Repurchases of shares and warrants(192)(637)(157)
Cash consideration of Merger Transactions (Note 1)(3,937)——
Merger Transactions costs(74)——
Contributions from noncontrolling interests1,7671,7061,939
Distributions to noncontrolling interests(2,013)(1,692)(1,219)
Other, net(3)—(77)
Net Cash Provided by (Used in) Financing Activities471(1,095)2,584
Effect of Exchange Rate Changes on Cash and Cash Equivalents(11)(21)8
Net (decrease) increase in Cash and Cash Equivalents(283)(116)303
Cash and Cash Equivalents, beginning of period598714411
Cash and Cash Equivalents, end of period$315$598$714

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

(In Millions)

Year Ended December 31,
201420132012
Noncash Investing and Financing Activities
Net assets and liabilities or noncontrolling interests acquired by the issuance of shares and warrants (Notes 1 and 3)$16,023$—$11,454
Assets acquired by the assumption or incurrence of liabilities1061,510—
Assets acquired or liabilities settled by contributions from noncontrolling interests—3,733306
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)1,7181,6521,349
Cash paid during the period for income taxes (net of refunds)22767182

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In Millions)

Par value of common sharesAdditional paid-in capitalRetained deficitAccumulated other comprehensive lossStockholders’ equity attributable to KMINon-controlling interestsTotal
Balance at December 31, 2011$8$3,431$(3)$(115)$3,321$5,247$8,568
Issuance of shares for EP acquisition310,59810,60110,601
Issuance of warrants for EP acquisition863863863
Acquisition of EP noncontrolling interests—3,7973,797
Warrants repurchased(157)(157)(157)
EP Trust I Preferred security conversions141414
Class A, Class B and Class C share conversions(1)1(71)(71)(71)
Amortization of restricted shares141414
Impact from equity transactions of KMP, EPB and KMR6464(102)(38)
Tax impact on stock based compensation909090
Net income315315112427
Distributions—(1,219)(1,219)
Contributions—2,3292,329
Cash dividends(1,184)(1,184)(1,184)
Other(1)(1)(4)(5)
Other comprehensive (loss) income(3)(3)7471
Balance at December 31, 20121014,917(943)(118)13,86610,23424,100
Shares repurchased(172)(172)(172)
Warrants repurchased(465)(465)(465)
Warrants exercised111
EP Trust I Preferred security conversions333
Amortization of restricted shares353535
Impact from equity transactions of KMP, EPB and KMR161161(254)(93)
Net income1,1931,1931,4992,692
Distributions—(1,692)(1,692)
Contributions—5,4395,439
KMP’s acquisition of Copano noncontrolling interests—1717
Cash dividends(1,622)(1,622)(1,622)
Other(1)(1)32
Other comprehensive income9494(54)40
Balance at December 31, 20131014,479(1,372)(24)13,09315,19228,285
Impact of Merger Transactions1121,88021,891(15,936)5,955
Merger Transactions costs(75)(75)(75)
Shares repurchased(94)(94)(94)
Warrants repurchased(98)(98)(98)
Amortization of restricted shares575757
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
Cash dividends(1,760)(1,760)(1,760)
Other(7)(7)(4)(11)
Other comprehensive (loss) income(49)(49)6920
Impact of Merger Transactions on Accumulated other comprehensive loss5656(87)(31)
Balance at December 31, 2014$21$36,178$(2,106)$(17)$34,076$350$34,426

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 the largest energy infrastructure and the third largest energy company in North America with an enterprise value of more than $125 billion and unless the context requires otherwise, references to “we,” “us,” “our,” or “KMI” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries. We own an interest in or operate approximately 80,000 miles of pipelines and 180 terminals. 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 coal, petroleum coke and steel. We are also the leading producer and transporter of CO2, for enhanced oil recovery projects in North America.

On November 26, 2014, we completed our acquisition, pursuant to three separate merger agreements, of all of the outstanding common units of Kinder Morgan Energy Partners, L.P. (NYSE: KMP) and El Paso Pipeline Partners, L.P. (NYSE: EPB) and all of the outstanding shares of Kinder Morgan Management, LLC (NYSE: KMR) that we did not already own. The transactions, valued at approximately $77 billion, are referred to collectively as the “Merger Transactions.”

Upon completion of the Merger Transactions: (i) each publicly held KMR share received 2.4849 shares of KMI common stock; (ii) through the election and proration mechanisms in the KMP merger agreement, on average, each common unit held by a public KMP unitholder received 2.1931 shares of KMI common stock and $10.77 in cash; and (iii) through the election and proration mechanisms in the EPB merger agreement, on average, each common unit held by a public EPB unitholder received 0.9451 shares of KMI common stock and $4.65 in cash. The cash payments to the public unitholders of KMP and EPB totaled approximately $3.9 billion.

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 resulting from the Merger Transactions. After closing the KMR Merger Transaction, KMR was merged with and into KMI. On January 1, 2015, EPB and its subsidiary, EPPOC merged with and into KMP and were dissolved.

Prior to November 26, 2014, 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 was eliminated.

The equity interests in KMP, EPB and KMR (which are all consolidated in our financial statements) owned by the public prior to November 26, 2014 are reflected within “Noncontrolling interests” in our accompanying December 31, 2013 consolidated balance sheet. The earnings recorded by KMP, EPB and KMR that are attributed to their units and shares, respectively, held by the public prior to November 26, 2014 are reported as “Net income attributable to noncontrolling interests” in our accompanying consolidated statements of income.

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.

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 disclosure of 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.

In addition, we believe that 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 cash of $118 million and $75 million as of December 31, 2014 and 2013, respectively is included in “Other current assets.”

Accounts Receivable

The amounts reported as “Accounts receivable, net” on our accompanying consolidated balance sheets as of December 31, 2014 and 2013 primarily consist of amounts due from customers.

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.

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 these assets at the lower of weighted-average cost or market. 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 the lower of cost or market or index prices. As of December 31, 2014 and 2013, our gas imbalance receivables—including both trade and related party receivables—totaled $103 million and $83 million, respectively, and we included these amounts within “Other current assets” on our accompanying consolidated balance sheets. As of December 31, 2014 and 2013, our gas imbalance payables—consisting of only trade payables—totaled $36 million and $34 million, respectively, and we included these amounts within “Other current liabilities” on our accompanying consolidated balance sheets.

Property, Plant and Equipment

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 0.9% 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 and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates included 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 acquisition cost of the CO2 associated with enhanced recovery is capitalized as part of our development costs when it is injected. The acquisition cost 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 rate is determined by field.

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.

Impairments

We review long-lived assets for impairment whenever events or changes in circumstances indicate that our carrying amount of an asset 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.

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 and possible reserves. For the purpose of impairment testing, adjustments for the inclusion of risk-adjusted probable and possible reserves, as well as forward curve pricing, will cause impairment calculation cash flows to differ from the amounts presented in our supplemental information on oil and gas producing activities disclosed in “Supplemental Information on Oil and Gas Producing Activities (Unaudited).”

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.

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, 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.

Equity method of accounting

We account for investments—which we do not control, but do have the ability to exercise significant influence—by 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.

Goodwill

Goodwill represents the excess of the cost of an acquisition price over the fair value of the acquired net assets, and such amounts are reported separately on our consolidated balance sheets. As of December 31, 2014 and 2013 our total goodwill was $24,654 million and $24,504 million, respectively. Goodwill is not amortized, but instead is tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We perform our goodwill impairment test on May 31 of each year. There were no impairment charges resulting from our May 31, 2014 or 2013 impairment testing, and no event indicating an impairment has occurred subsequent to May 31, 2014 other than as described below.

If a significant portion of one of our business segments is disposed of (that also constitutes a business), we allocate goodwill based on the relative fair values of the portion of the segment being disposed of and the portion of the segment remaining. During 2014, we recorded a $29 million write-down associated with a pending sale of certain terminals to a third-party, including $2 million of goodwill.

Revenue Recognition Policies

We recognize revenues as services are rendered or goods are delivered and, if applicable, title has passed. We recognize natural gas sales revenues and NGL sales revenue when the natural gas or NGL is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured. Our sales and purchases of natural gas and NGL are primarily accounted for on a gross basis as natural gas sales or product sales, as applicable, and cost of sales.

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 title 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.

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 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 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 to be recognized as a component of benefit expense.

Noncontrolling Interests

Noncontrolling interests represents the outstanding ownership 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 attributable to noncontrolling interests.” In our accompanying consolidated balance sheets, noncontrolling interests represents the ownership interests in our consolidated subsidiaries’ net assets held by parties other than us. It 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. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit we do not expect to be realized.

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, including our investment in KMP as the KMP partnership remains in place following the Merger Transactions.

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.”

Comprehensive Income

For each of the years ended December 31, 2014, 2013 and 2012, the difference between our net income and our comprehensive income resulted from (i) unrealized gains or losses on derivative contracts accounted for as cash flow hedges; (ii) foreign currency translation adjustments; and (iii) unrealized gains or losses related to changes in pension and other postretirement benefit plan liabilities. For more information on our risk management activities, see Note 13.

Risk Management Activities

We utilize energy commodity derivative contracts for the purpose of mitigating our risk resulting from fluctuations in the market price of 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 measure our derivative contracts at fair value and we report them on our balance sheet as either an asset or liability. If the derivative transaction qualifies for and is designated as a normal purchase and sale, it is exempted from fair value accounting and is accounted for using traditional accrual accounting.

Furthermore, changes in our derivative contracts’ fair values are recognized currently in earnings unless hedge accounting is applied. If a derivative contract meets specific accounting criteria, the contract’s gains and losses are allowed to offset related results on the hedged item in our income statement, and we may formally designate the derivative contract as a hedge and document and assess the effectiveness of the contract associated with the transaction that receives hedge accounting. Only designated qualifying items that are effectively offset by changes in fair value or cash flows during the term of the hedge are eligible to use the special accounting for hedging.

Our derivative contracts that hedge our energy commodity price risks involve our normal business activities, which include the purchase and sale of natural gas, NGL and crude oil, and we may designate these derivative contracts as cash flow hedges—derivative contracts that hedge exposure to variable cash flows of forecasted transactions—and the effective portion of these derivative contracts’ gain or loss is initially reported as a component of other comprehensive income (outside earnings) and subsequently reclassified into earnings when the forecasted transactions affect earnings. The ineffective portion of the gain or loss is reported in earnings immediately.

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. As of December 31, 2014, the recovery period for these regulatory assets was approximately one year to forty-two years.

The following table summarizes our regulatory asset and liability balances as of December 31, 2014 and 2013 (in millions):

December 31,
20142013
Current regulatory assets$81$91
Non-current regulatory assets406446
Total regulatory assets$487$537
Current regulatory liabilities$189$135
Non-current regulatory liabilities290397
Total regulatory liabilities$479$532

On July 26, 2012, TGP filed an application with the FERC seeking authority to abandon by sale certain natural gas facilities located offshore in the Gulf of Mexico and onshore in the state of Louisiana, as well as a related offer of settlement that addressed the proposed rate and accounting treatment associated with the sale. The offer of settlement provided for a rate adjustment to TGP’s maximum tariff rates upon the transfer of the assets and established a regulatory asset for a portion of the unrecovered net book value of the facilities to be sold. Effective September 1, 2013, following the FERC’s approval of both the requested abandonment authorization and the offer of settlement, TGP sold these assets, and in 2013, TGP recognized both a $93 million increase in regulatory assets and a $36 million gain from the sale of assets.

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

For the years ended December 31, 2014 and 2013, earnings per share was calculated 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 do not participate in excess distributions over earnings.

The following table sets forth the allocation of net income available to shareholders for Class P shares and for participating securities (in millions):

Year Ended December 31,
20142013
Class P$1,015$1,187
Participating securities(a)116
Net Income Attributable to Kinder Morgan, Inc.$1,026$1,193
(a)Participating securities are unvested restricted stock awards issued to management employees that contain non-forfeitable rights to dividend equivalent payments.

The following 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,
20142013
Unvested restricted stock awards74
Outstanding warrants to purchase our Class P shares(a)312401
Convertible trust preferred securities1010
(a)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.

On December 26, 2012, the remaining series of our Class A, Class B, and Class C shares were fully-converted and as a result, only our Class P common stock was outstanding as of December 31, 2012 (see Note 10).

For the year ended December 31, 2012, earnings per share was calculated using the two-class method. Earnings were allocated to each class of common stock based on the amount of dividends paid in the current period for each class of stock 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. For the investor retained stock, the allocation of undistributed earnings or excess distributions over earnings was in direct proportion to the maximum number of Class P shares into which it could convert.

For the Class P diluted earnings per share computations, total net income attributable to Kinder Morgan, Inc. was divided by the adjusted weighted-average shares outstanding during the period, including all potential common stock equivalents. This included, for the periods prior to December 26, 2012, the Class P shares into which the investor retained stock (collectively, our Class A, Class B and Class C common stocks) was convertible. The number of Class P shares on a fully-converted basis was the same before and after any conversion of our investor retained stock. Each time one Class P share was issued upon conversion of investor retained stock, the number of Class P shares went up by one, and the number of Class P shares into which the investor retained stock was convertible went down by one. Accordingly, there was no difference between Class P basic and diluted earnings per share because the conversion of Class A, Class B, and Class C shares into Class P shares did not impact the number of Class P shares on a fully-converted basis. Commencing with the acquisition of EP, potential common stock equivalents also included the Class P shares issuable in connection with the warrants and the trust preferred securities (see Note 10). As no securities were convertible into Class A shares, the basic and diluted earnings per share computations for Class A shares were the same. For the year ended December 31, 2012, the following potential Class P common stock equivalents were antidilutive and, accordingly, were excluded from the determination of diluted earnings per share; (i) 451 million related to outstanding warrants to purchase our Class P shares; and (ii) 11 million related to convertible trust preferred securities.

The following tables set forth the computation of basic and diluted earnings per share from continuing operations for the year ending December 31, 2012 (in millions, except per share amounts):

Year ended December 31, 2012
Income from Continuing Operations Available to Shareholders
Class PClass AParticipating Securities(a)Total
Income from continuing operations$1,204
Less: income from continuing operations attributable to noncontrolling interests(696)
Income from continuing operations attributable to KMI508
Dividends paid in the period$601$542$41(1,184)
Excess distributions over earnings(344)(331)(1)$(676)
Income from continuing operations attributable to shareholders$257$211$40$508
Basic earnings per share from continuing operations
Basic weighted-average number of shares outstanding461446N/A
Basic earnings per common share from continuing operations(b)$0.56$0.47N/A
Diluted earnings per share from continuing operations
Income from continuing operations attributable to shareholders and assumed conversions(c)$508$211N/A
Diluted weighted-average number of shares908446N/A
Diluted earnings per common share from continuing operations(b)$0.56$0.47N/A

The following tables set forth the computation of basic and diluted earnings per share for the year ended December 31, 2012 (in millions, except per share amounts):

Year ended December 31, 2012
Net Income Available to Shareholders
Class PClass AParticipating Securities(a)Total
Net income attributable to KMI$315
Dividends paid in the period$601$542$41(1,184)
Excess distributions over earnings(441)(426)(2)$(869)
Net income attributable to shareholders$160$116$39$315
Basic earnings per share
Basic weighted-average number of shares outstanding461446N/A
Basic earnings per common share(b)$0.35$0.26N/A
Diluted earnings per share
Net income attributable to shareholders and assumed conversions(c)$315$116N/A
Diluted weighted-average number of shares908446N/A
Diluted earnings per common share(b)$0.35$0.26N/A
(a)Participating securities are unvested restricted stock awards issued to management employees that contain non-forfeitable rights to dividend equivalents payments.
(b)The Class A shares earnings per share as compared to the Class P shares earnings per share were reduced due to the sharing of economic benefits (including dividends) amongst the Class A, B, and C shares. Class A, B and C shares owned by Richard Kinder, the sponsor investors, the original shareholders, and other management were referred to as “investor retained stock,” and were convertible into a fixed number of Class P shares. In the aggregate, our investor retained stock was entitled to receive a dividend per share on a fully-converted basis equal to the dividend per share on our common stock. The conversion of shares of investor retained stock into Class P shares did not increase our total fully-converted shares outstanding, impact the aggregate dividends we paid or the dividends we paid per share on our Class P common stock.
(c)For the diluted earnings per share calculation, total net income attributable to each class of common stock was divided by the adjusted weighted-average shares outstanding during the period, including all potential common stock equivalents.
  1. Acquisitions and Divestitures

Business Combinations and Acquisitions of Investments

During 2014, 2013 and 2012, we completed the following significant acquisitions accounted for in accordance with the “Business Combinations” Topic of the Codification.

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. Additionally, we adjust goodwill as a result of applying the look-through method of recording deferred taxes on the outside book tax basis differences in our investments without regard to non-tax deductible goodwill. We do not expect our recorded goodwill to be deductible for tax purposes.

The following table discloses our assignment of the purchase price for each of our significant acquisitions (in millions):

Assignment of Purchase Price
Ref.DateAcquisitionPurchase priceCurrent assetsProperty plant & equipmentDeferred charges & otherGoodwillLong-term debtOther liabilitiesNon-controlling interestPreviously held equity interest
(1)11/14Pennsylvania and Florida Jones Act Tankers$270$—$270$8$25$—$(33)$—$—
(2)1/14American Petroleum Tankers and State Class Tankers9616951664—(66)——
(3)6/13Goldsmith-Landreth Field Unit280—298———(18)——
(4)5/13Copano3,7332182,7881,973963(1,252)(236)(17)(704)
(5)5/12EP22,9287,17512,9215,71818,562(13,417)(4,234)(3,797)—

(1) 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 table above includes an allocation of deferred taxes of $8 million as a decrease to “Goodwill” and an increase to “Deferred charges & other” for the portion of our outside basis difference associated with the underlying goodwill. “Other liabilities” includes (i) $8 million of contingent consideration and (ii) $25 million associated with unfavorable customer contracts representing the amount, on a present value basis, by which the customer contracts were below market day rates at the time of the acquisition. The unfavorable contracts liability is being amortized as a noncash adjustment to revenue over the remaining contract period. 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 the Terminals business segment. The acquired vessels will continue to be operated by Crowley.

(2) 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). The table above includes an allocation of deferred taxes of $6 million as a decrease to “Goodwill” and an increase to “Deferred charges & other” for the portion of our outside basis difference associated with the underlying goodwill. “Other liabilities” includes $61 million of unfavorable customer contracts representing the amount, on a present value basis, by which the customer contracts were below market day rates at the time of acquisition. This amount is being amortized as a noncash adjustment to revenue over the remaining contract period.

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. APT’s vessels are operated by Crowley.

SCT has commissioned the construction of four medium range Jones Act qualified product tankers, each with 330 MBbl of cargo capacity. The SCT vessels are scheduled to be delivered in 2015 and 2016 and are being constructed by General Dynamics’ NASSCO shipyard. We expect to invest approximately $276 million, including capitalized interest, to complete the construction of these four SCT vessels, and upon delivery, the vessels will be operated pursuant to long-term time charters with a major integrated oil company. Each of the time charters has 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 the Terminals business segment.

(3) Goldsmith Landreth Field Unit

On June 1, 2013, we acquired certain oil and gas properties, rights, and related assets in the Permian Basin of West Texas from Legado Resources LLC for an aggregate consideration of $298 million consisting of $280 million in cash and assumed liabilities of $18 million (including $12 million of long-term asset retirement obligations). The acquisition of the Goldsmith Landreth San Andres oil field unit includes more than 6,000 acres located in Ector County, Texas. The acquired oil field is in the early stages of CO2 flood development and includes a residual oil zone along with a classic San Andres waterflood. As part of the transaction, we obtained a long-term supply contract for up to 150 MMcf/d of CO2. The acquisition complemented our existing oil and gas producing assets in the Permian Basin, and we included the acquired assets as part of the CO2 business segment.

(4) Copano

Effective May 1, 2013, we acquired all of Copano’s outstanding units for a total purchase price of approximately $5.2 billion (including assumed debt and all other assumed liabilities). The transaction was a 100% unit for unit transaction with an exchange ratio of 0.4563 of KMP’s common units for each Copano common unit. KMP issued 43,371,210 of its common units valued at $3,733 million as consideration for the Copano acquisition (based on the $86.08 closing market price of a common unit on the NYSE on the May 1, 2013 issuance date). Due to the fact that our acquisition included the remaining 50% interest in Eagle Ford Gathering LLC (Eagle Ford) that we did not already own, we remeasured the carrying value ($146 million) of our existing 50% equity investment in Eagle Ford to its fair value ($704 million) as of the May 1, 2013 acquisition date. As a result of this remeasurement, we recognized a $558 million non-cash gain and we reported this gain within “Gain on remeasurement of previously held equity investments to fair value” in our accompanying consolidated statement of income for the year ended December 31, 2013.

(5) EP

Effective on May 25, 2012, we acquired all of the outstanding shares of EP for an aggregate consideration of approximately $22.9 billion (excluding assumed debt, but including payments of $87 million for share based awards expensed in the post-combination period). In total, EP shareholders received (i) $11.6 billion in cash; (ii) 330 million KMI Class P shares with a fair value of $10.6 billion (based on the $32.11 closing market price of a Class P share on May 24, 2012); and (iii) 505 million KMI warrants with a fair value of $863 million (based on a fair value of $1.71 per warrant as of May 24, 2012). The warrants have an exercise price of $40 per share and a 5-year term.

During the year 2012, we incurred $463 million, net of legal recoveries, of pre-tax expenses associated with the EP acquisition, including (i) $160 million in employee severance, retention and bonus costs; (ii) $87 million of accelerated EP stock based compensation allocated to the post-combination period under applicable GAAP rules; (iii) $37 million in advisory

fees; (iv) $68 million for legal fees and reserves, net of legal recoveries; (v) a $108 million write-off (due to debt repayments) or amortization of capitalized financing fees associated with the EP acquisition financing; and less (vi) a $29 million benefit associated with pension income.

Pro Forma Information

The following summarized unaudited pro forma consolidated income statement information for the years ended December 31, 2014 and 2013, assumes that the Crowley, APT, Copano and the Goldsmith Landreth field unit acquisitions had occurred as of January 1, 2013. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma financial results may not be indicative of the results that would have occurred if these acquisitions had been completed as of January 1, 2013 or the results that will be attained in the future. Amounts presented below are in millions, except for the per share amounts:

Pro Forma
Year Ended December 31,
20142013
(Unaudited)
Revenues$16,260$14,911
Income from continuing operations2,4482,665
Income from discontinued operations, net of tax—(4)
Net income2,4482,661
Net income attributable to noncontrolling interests(1,419)(1,490)
Net income attributable to Kinder Morgan, Inc.1,0291,171
Diluted earnings per common share
Class P shares$0.90$1.12

Acquisitions Subsequent to December 31, 2014

On February 13, 2015, we acquired Hiland Partners, LP, a privately held Delaware limited partnership (Hiland) for an aggregate consideration of $3,058 million consisting of $1,715 million in cash and $1,343 million of assumed debt, of which approximately $368 million was immediately paid down after closing. The cash requirements associated with the acquisition were funded primarily from borrowings under a six-month bridge facility, discussed in Note 8 “Debt,” and with proceeds from sales of our Class P shares issued under our equity distribution agreement. Hiland’s assets consist primarily of crude oil gathering and transportation pipelines and gas gathering and processing systems, primarily serving production from the Bakken Formation in North Dakota and Montana.

On February 9, 2015, we announced the acquisition of three U.S. terminals and one undeveloped site from Royal Vopak for approximately $158 million. The acquisition covers (i) a 36-acre, 1,069,500-barrel storage complex at Galena Park, Texas that handles base oils, biodiesel and crude oil and is immediately adjacent to our Galena Park terminal complex; (ii) two terminals in North Carolina, one terminal in North Wilmington that handles chemicals and black oil and one terminal in South Wilmington that is not currently operating; and (iii) an undeveloped site at Perth Amboy, New Jersey, with waterfront access that can be developed. The transaction, subject to customary approvals, is expected to close during the first quarter of 2015.

Drop-down Assets

In periods prior to the Merger Transactions, we completed the following drop-down transactions to KMP and EPB.

•Effective August 1, 2012, KMP acquired from us a 100% ownership interest in TGP and an initial 50% ownership interest in EPNG, referred to in this report as the August 2012 drop-down transaction;
•Effective March 1, 2013, KMP acquired from us the remaining 50% ownership interest it did not already own in both EPNG and the EP midstream assets (see “—KMP Previously Held Investment in El Paso Midstream Investment Company, LLC” following), referred to in this report as the March 2013 drop-down transaction; and
•On May 2, 2014, EPB acquired from us our 50% equity interest in Ruby Pipeline Holding Company, L.L.C. (Ruby), our indirect 50% equity interest in Gulf LNG Holdings Group, L.L.C. (Gulf LNG) and our indirect 47.5% equity interest in Young Gas Storage Company, Ltd., referred to in this report as the May 2014 drop-down transaction.

In this report, we refer to these acquisitions of assets by KMP from us as the drop-down transactions. These drop-down transactions were accounted for as transfers of net assets between entities under common control. Specifically, KMP reflected the acquired assets and assumed liabilities at our carrying value, including our EP purchase accounting adjustments as of May 25, 2012; however our consolidated financial statements were not affected.

KMP Previously Held Investment in El Paso Midstream Investment Company, LLC

Effective June 1, 2012, KMP acquired a 50% ownership interest in El Paso Midstream Investment Company, LLC (EP Midstream) for an aggregate consideration of $289 million in common units. EP Midstream is a joint venture that owns gas gathering, processing and treating assets located in the Uinta Basin in Utah and a natural gas and oil gathering system located in the Eagle Ford shale formation in South Texas, collectively referred to in this report as the EP midstream assets.

Since we owned the remaining 50% of the EP Midstream assets, we consolidated EP Midstream in the accompanying consolidated financial statements effective June 1, 2012. The operating results of the EP midstream assets are included in the Natural Gas Pipelines business segment. No gain or loss on the previously held equity investment was recognized as the fair value of the initial equity investment acquired through our EP acquisition was determined to equal the $289 million purchase price paid by KMP for its 50% interest. As such, the fair value of 100% of EP Midstream was determined to be $578 million.

We measured the identifiable intangible assets acquired at fair value on the acquisition date, and as a result, we recognized $50 million in “Deferred charges and other assets,” representing the fair value of separate and identifiable relationships with existing customers. We estimated the remaining useful life of these existing customer relationships to be approximately 10 years. After measuring all of the identifiable tangible and intangible assets acquired and liabilities assumed at fair value on the acquisition date, we recognized $248 million of “Goodwill.” We believe the primary item that generated the goodwill is our ability to grow the business by leveraging our pre-existing natural gas operations, and we believe that this value contributed to our acquisition price exceeding the fair value of acquired identifiable net assets and liabilities. This goodwill is not deductible for tax purposes.

Income Tax Impact of the Drop-Down of EP Assets to KMP

For income tax purposes, the March 2013 drop-down transaction was treated as a contribution and the August 2012 drop-down transaction was treated as a partial sale, and a partial contribution. As a result of the drop-down transactions, a deferred tax liability arose related to the portion of the outside basis difference associated with the underlying goodwill that was contributed to KMP by us. However, since the drop-downs were transactions between entities under common control, we recognized an offsetting deferred charge of $448 million for the August 2012 and $53 million for the March 2013 drop-down transactions. These balances were being amortized to income tax expense over the remaining useful lives of the transferred assets of approximately 25 years. For the years ended December 31, 2014 and 2013 and the period subsequent to the August 2012 drop-down through December 31, 2012, total income tax expense related to the amortization of the deferred charges was approximately $18 million, $20 million and $7 million, respectively. As a result of the tax impact of the Merger Transactions, the unamortized balance of the deferred charge of $456 million was reversed.

Divestitures

The FTC Natural Gas Pipelines Disposal Group – Discontinued Operations

Following our March 2012 agreement with the U.S. FTC to divest certain assets in order to receive regulatory approval for our EP acquisition, we began accounting for the FTC Natural Gas Pipelines disposal group as discontinued operations (prior to our sale announcement, we included the disposal group in the Natural Gas Pipelines business segment). The FTC Natural Gas Pipelines disposal group’s assets consisted of some natural gas pipeline systems and a natural gas processing operation located in the rocky mountain region. Effective November 1, 2012, we sold the FTC Natural Gas Pipelines disposal group to Tallgrass Energy Partners, LP (now known as Tallgrass Development, LP) (Tallgrass), and we received proceeds of $1,791 million (before cash selling expenses) which we reported separately as “Proceeds from disposal of discontinued operations” within the investing section of our accompanying consolidated statement of cash flows for the year ended December 31, 2012. In November 2012, we also paid selling expenses of $78 million (consisting of certain required tax payments to joint venture partners).

Additionally, we recognized (i) a $4 million loss for the year ended December 31, 2013, for the true up of the final consideration and certain incremental selling expenses and (ii) a combined remeasurement loss of $937 million for the year ended December 31, 2012, to reflect our assessment of fair value of the disposal group’s net assets as a result of the FTC

mandated sale requirement. We reported these loss amounts separately as “Loss on sale and the remeasurement of the FTC Natural Gas Pipelines disposal group to fair value, net of tax” within the discontinued operations section of our consolidated statements of income for the years ended December 31, 2013 and 2012.

Summarized financial information for the FTC Natural Gas Pipelines disposal group is as follows (in millions):

Year Ended December 31, 2012(a)
Operating revenues$227
Operating expenses(131)
Depreciation and amortization(7)
Other expense(1)
Earnings from equity investments70
Interest income and Other, net2
Income from operations of the FTC Natural Gas Pipelines disposal group$160
(a)2012 amounts represent financial information for the ten month period ended October 31, 2012. We sold the FTC Natural Gas Pipelines disposal group effective November 1, 2012.

Express Pipeline System

Effective March 14, 2013, we sold both our one-third equity ownership interest in the Express pipeline system and our subordinated debenture investment in Express to Spectra Energy Corp. we received net cash proceeds of $402 million (after paying both a final working capital settlement and certain transaction related selling expenses), and we reported the net cash proceeds received from the sale separately as “Proceeds from sales of assets and investments” within the investing section of our accompanying consolidated statement of cash flows for the year ended December 31, 2013. Additionally, we recognized a combined $224 million pre-tax gain with respect to this sale, and we reported this gain amount separately as “Gain on sale of investments in Express pipeline system” on our accompanying consolidated statement of income for the year ended December 31, 2013. We also recorded an income tax expense of $84 million related to this gain on sale, and we included this expense within “Income Tax Expense.” As of the date of sale, our equity investment in Express totaled $67 million and the note receivable due from Express totaled $110 million.

  1. Income Taxes

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

Year Ended December 31,
201420132012
U.S.$2,941$3,107$1,246
Foreign15033197
Total Income from Continuing Operations Before Income Taxes$3,091$3,438$1,343

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

Year Ended December 31,
201420132012
Current tax expense
Federal$(16)$57$48
State363634
Foreign13910
Total3310292
Deferred tax expense
Federal57261249
State14—4
Foreign2928(6)
Total61564047
Total tax provision$648$742$139

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,
201420132012
Federal income tax$1,08235.0%$1,20335.0%$47035.0%
Increase (decrease) as a result of:
State deferred tax rate change——%(21)(0.6)%201.5%
Taxes on foreign earnings401.3%1123.3%(6)(0.5)%
Net effects of consolidating KMP’s and EPB’s U.S. income tax provision(433)(14.0)%(488)(14.2)%(288)(21.5)%
State income tax, net of federal benefit371.2%451.3%211.6%
Dividend received deduction(50)(1.6)%(54)(1.6)%(32)(2.4)%
Adjustments to uncertain tax positions(5)(0.2)%(87)(2.5)%(72)(5.3)%
Valuation allowance on Investment in NGPL612.0%——%——%
Disposition of certain international holdings(112)(3.6)%——%——%
Other280.9%320.9%261.9%
Total$64821.0%$74221.6%$13910.3%

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

December 31,
20142013
Deferred tax assets
Employee benefits$329$238
Accrued expenses123136
Net operating loss, capital loss, tax credit carryforwards778673
Derivative instruments and interest rate and currency swaps4368
Debt fair value adjustment102112
Investments4,858—
Other3143
Valuation allowances(154)(95)
Total deferred tax assets6,1101,175
Deferred tax liabilities
Property, plant and equipment373351
Investments—4,888
Other3020
Total deferred tax liabilities4035,259
Net deferred tax assets (liabilities)$5,707$(4,084)
Current deferred tax asset$56$567
Non-current deferred tax assets (liabilities)5,651(4,651)
Net deferred tax assets (liabilities)$5,707$(4,084)

Deferred Tax Assets and Valuation Allowances: As a result of the Merger Transactions, we acquired directly or indirectly all of the equity interests of KMP, KMR and EPB that we and our subsidiaries did not already own. In exchange for their interests in KMP and EPB, we paid stock and cash with a fair market value of approximately $64 billion to the limited partner unit holders. This represents a taxable exchange for which we received a step-up in tax basis in the underlying assets acquired (our investment in KMP and EPB). A deferred tax asset of approximately $10.3 billion related to the book tax basis difference in this investment has been recorded, computed as $64 billion tax basis in excess of $36 billion book basis at our statutory tax rate of 36.48%.

In accordance with ASC 810-10-45-23, if changes in a parent’s ownership interest do not result in a change in its controlling financial interest in its subsidiary, those changes should be accounted for as equity transactions. No gain or loss is recognized in consolidated net income or comprehensive income. The carrying amount of the noncontrolling interest is adjusted to reflect the change in ownership interest in the subsidiary. Any difference between the fair value of the consideration received or paid and the amount by which the noncontrolling interest is adjusted is recognized in equity attributable to the parent. Therefore, because the transaction conforms to the conditions set forth in ASC 810-10-45-23, we have concluded that the increase in the deferred tax assets should be recorded with the offset to equity rather than the income statement.

The step-up in tax basis results in a deferred tax asset of approximately $4.9 billion primarily related to our investment in KMP and EPB. As book earnings from our investment in KMP and EPB 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 and EPB is expected to be fully realized.

We recorded a full valuation allowance of $61 million against the deferred tax asset related to our investment in NGPL as we no longer have viable means by which we reasonably expect to recover this asset.

We have deferred tax assets of $466 million related to net operating loss carryovers, $312 million related to alternative minimum and foreign tax credits, and $93 million of valuation allowances related to deferred tax assets at December 31, 2014. As of December 31, 2013, we had deferred tax assets of $354 million related to net operating loss carryovers, $11 million related to capital loss carryovers, $308 million related to alternative minimum and foreign tax credits, and valuation allowances

related to deferred tax assets of $95 million. We expect to generate taxable income beginning in 2016 and utilize all federal net operating loss carryforwards and alternative minimum tax carryforwards by the end of 2018.

Expiration Periods for Deferred Tax Assets: As of December 31, 2014, we have U.S. federal net operating loss carryforwards of $906 million, which will expire from 2018 - 2034; state losses of $1.9 billion which will expire from 2014 - 2034; and foreign losses of $213 million, of which approximately $124 million carries over indefinitely and $89 million expires from 2028 - 2035. We also have $300 million of federal alternative minimum tax credits which do not expire; and approximately $11 million of foreign tax credits, the majority of which will expire from 2016 - 2024. Use 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.

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,
201420132012
Balance at beginning of period$209$269$57
Uncertain tax positions of EP—4289
Subtotal209273346
Additions based on current year tax positions121111
Additions based on prior year tax positions—261
Reductions based on prior year tax positions(3)——
Reductions based on settlements with taxing authority(24)(86)(55)
Reductions due to lapse in statute of limitations(5)(15)(34)
Balance at end of period$189$209$269

We recognize interest and/or penalties related to income tax matters in income tax expense. As of December 31, 2014, 2013, and 2012, we had $28 million, $29 million and $28 million of accrued interest and $2 million, $2 million and $2 million in accrued penalties, respectively. All of the $189 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 $1 million during the next year to approximately $190 million.

We are subject to taxation, and have tax years open to examination for the periods 2012-2013 in the U.S., 1999-2013 in various states and 2004-2013 in various foreign jurisdictions.

  1. Property, Plant and Equipment

Classes and Depreciation

As of December 31, 2014 and 2013, our property, plant and equipment consisted of the following (in millions):

December 31,
20142013
Natural gas, liquids, crude oil and CO2 pipelines$18,119$17,399
Natural gas, liquids, CO2, and terminals station equipment21,23317,960
Natural gas, liquids (including linefill), and transmix processing520259
Other3,9643,656
Accumulated depreciation, depletion and amortization(8,369)(6,757)
35,46732,517
Land and land rights-of-way1,3241,158
Construction work in process1,7732,172
Property, plant and equipment, net$38,564$35,847

As of December 31, 2014 and 2013, property, plant and equipment included $15,026 million and $14,957 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 $1,862 million, $1,663 million, and $1,324 million for the years ended December 31, 2014, 2013, and 2012, respectively.

Asset Retirement Obligations

As of December 31, 2014 and 2013, we recognized asset retirement obligations in the aggregate amount of $192 million and $204 million, respectively, of which $7 million and $25 million , respectively, were classified as current. 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.

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.

Impairments

During 2014, continued deteriorating commodity prices for crude oil that is produced by the CO2 segment’s working interest in the Katz Strawn unit caused us to evaluate the carrying value of this oil producing field. The estimated fair value on these assets was based on the future discounted cash flows using the forward WTI crude oil price curve. We recognized a $235 million non-cash, pre-tax impairment charge to write-down this asset to its estimated fair value.

  1. Investments

Our investments primarily consist of equity investments where we hold significant influence over investee actions and which we account for under the equity method of accounting. As of December 31, 2014 and 2013 our investments consisted of the following (in millions):

December 31,
20142013
Citrus Corporation$1,805$1,875
Ruby Pipeline Holding Company, L.L.C.1,1231,153
Midcontinent Express Pipeline LLC748602
Gulf LNG Holdings Group, LLC547578
EagleHawk337272
Plantation Pipe Line Company303307
Red Cedar Gathering Company184176
Double Eagle Pipeline LLC150144
Parkway Pipeline LLC144131
Fayetteville Express Pipeline LLC130144
Watco Companies, LLC103103
Fort Union Gas Gathering L.L.C.70161
Sierrita Pipeline LLC6319
Cortez Pipeline Company1712
All others304266
Total equity investments6,0285,943
Bond investments88
Total investments$6,036$5,951

As shown in the table above, our significant equity investments, as of December 31, 2014 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 and owns the remaining 50% interest;
•Ruby Pipeline Holding Company, L.L.C.—We operate and own a 50% interest in Ruby Pipeline Holding Company, L.L.C., the sole owner of Ruby Pipeline natural gas transmission system. The remaining 50% interest is owned by a subsidiary of Veresen Inc. as convertible preferred interests;
•Midcontinent Express Pipeline LLC—We operate 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 Regency Energy Partners L.P.;
•Gulf LNG Holdings Group, LLC—We operate 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% ownership interests are wholly and partially owned by subsidiaries of GE Financial Services and The Blackstone Group L.P.;
•BHP Billiton Petroleum (Eagle Ford Gathering) LLC, f/k/a EagleHawk Field Services LLC and referred to in this report as 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 operates EagleHawk and owns the remaining 75% ownership interest;
•Plantation—We operate 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;
•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;
•Double Eagle Pipeline LLC - We owns a 50% equity interest in Double Eagle Pipeline LLC. The remaining 50% interest is owned by Magellan Midstream Partners;
•Parkway Pipeline LLC —We operate and own 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;
•Fayetteville Express Pipeline LLC —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 Fayetteville Express Pipeline LLC;
•Watco Companies, LLC—We hold a preferred equity investment in Watco Companies, LLC, the largest privately held short line railroad company in the U.S. We own 100,000 Class A preferred shares and pursuant to the terms of the investment, receive priority, cumulative cash distributions from the preferred shares at a rate of 3.25% per quarter, and participates partially in additional profit distributions at a rate equal to 0.5%. The preferred shares have no conversion features and hold no voting powers, but do provide us certain approval rights, including the right to appoint one of the members to Watco’s Board of Managers;
•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, owns 37.04%; WPX Energy Rocky Mountain, 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;
•Sierrita Pipeline LLC — We operate and own a 35% equity interest in the Sierrita 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%;
•Cortez Pipeline Company—We operate and own a 50% interest in the Cortez Pipeline Company, the sole owner of the Cortez carbon dioxide pipeline system. A subsidiary of Exxon Mobil Corporation owns a 37% interest and Cortez Vickers Pipeline Company owns the remaining 13% interest; and
•NGPL Holdco LLC— We operate and own a 20% interest in NGPL Holdco LLC, the owner of NGPL and certain affiliates, collectively referred to in this report as NGPL, a major interstate natural gas pipeline and storage system.

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

Year Ended December 31,
201420132012
Citrus Corporation(a)$97$84$53
Fayetteville Express Pipeline LLC555555
Gulf LNG Holdings Group, LLC(a)484722
Midcontinent Express Pipeline LLC454042
Red Cedar Gathering Company333132
Plantation Pipe Line Company293532
Cortez Pipeline Company252425
Fort Union Gas Gathering L.L.C.(b)1611—
Ruby Pipeline Holding Company, L.L.C.(a)15(6)(5)
Watco Companies, LLC131313
Parkway Pipeline LLC81—
Sierrita Pipeline LLC3——
NGPL Holdco LLC(c)—(66)(198)
Double Eagle Pipeline LLC(b)(1)1—
EagleHawk(7)911
All others274871
Total$406$327$153
Amortization of excess costs$(45)$(39)$(23)
(a)2012 amounts are for the period from May 25, 2012 through December 31, 2012.
(b)2013 amounts are for the period from May 1, 2013 through December 31, 2013.
(c)2013 and 2012 amounts include non-cash investment impairment charges, which we recorded in the amount of $65 million and $200 million (pre-tax), respectively.

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 Statement201420132012
Revenues$3,829$3,615$3,681
Costs and expenses3,0632,8033,194
Net income (loss)$766$812$487
December 31,
Balance Sheet20142013
Current assets$943$950
Non-current assets20,63020,782
Current liabilities1,6431,451
Non-current liabilities10,84111,351
Partners’/owners’ equity9,0898,930
  1. Goodwill and Other Intangibles

Goodwill and Excess Investment Cost

We record the excess of the cost of an acquisition price over the fair value of acquired net assets as an asset on our balance sheet. This amount is referred to and reported separately as “Goodwill” in our accompanying consolidated balance sheets. 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. During the quarter ended June 30, 2013, we created the Natural Gas Pipelines Non-Regulated reporting unit to include the non-regulated businesses we acquired from Copano on May 1, 2013 as well as other non-regulated businesses that were historically part of the former Natural Gas Pipelines reporting unit (now the Natural Gas Pipelines Regulated reporting unit). We then allocated goodwill between these two reporting units based on the relative fair values of the reporting units.

There were no impairment charges resulting from our May 31, 2014 impairment testing, and no event indicating an impairment has occurred subsequent to that date. We determined the fair value of each reporting unit as of May 31, 2014 based on a market approach utilizing an average dividend/distribution yield of comparable companies. The value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and represented the price estimated to be received in a sale of the unit as a whole in an orderly transaction between market participants at the measurement date.

Changes in the gross amounts of our goodwill and accumulated impairment losses for each of the years ended December 31, 2014 and 2013 are summarized as follows (in millions):

Natural Gas PipelinesCO2Products PipelinesTerminalsKinder Morgan CanadaTotal
Historical Goodwill$22,276$1,528$2,129$1,484$626$28,043
Accumulated impairment losses(2,090)—(1,267)(677)(377)(4,411)
Balance as of December 31, 201220,1861,52886280724923,632
Acquisitions(a)888————888
Currency translation adjustments————(16)(16)
Balance as of December 31, 201321,0741,52886280723324,504
Acquisitions(a)(b)82——89—171
Currency translation adjustments————(19)(19)
Impairment———(2)—(2)
Balance as of December 31, 2014$21,156$1,528$862$894$214$24,654
(a)2014 and 2013 Natural Gas Pipelines acquisition amounts include $82 million and $881 million, respectively, relating to the May 1, 2013 Copano acquisition as discussed in Note 3. 2013 Natural Gas Pipelines acquisition amount also includes $7 million relating to other EP acquisition assets.
(b)2014 Terminals acquisition amount includes $64 million related to the January 17, 2014 APT acquisition and $25 million related to the November 5, 2014 Crowley acquisition.

For more information on our accounting for goodwill, see Note 2.

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 $746 million and $809 million as of December 31, 2014 and 2013, respectively. In almost all instances, this differential, relating to the discrepancy between our share of the investee’s recognized net assets at book values and at current fair values, represents our share of undervalued depreciable assets, and since those assets (other than land) are subject to depreciation, we amortize this portion of our investment cost against our share of investee earnings. As of December 31, 2014, this excess investment cost is being amortized over a weighted average life of approximately thirteen years.

The second differential, representing total unamortized excess cost over underlying fair value of net assets acquired (equity method goodwill) totaled $138 million as of both December 31, 2014 and 2013. This differential is not subject to amortization but rather to impairment testing. Accordingly, in addition to our annual impairment test of goodwill, we periodically reevaluate the amount at which we carry the excess of cost over fair value of net assets accounted for under the equity method, as well as the amortization period for such assets, to determine whether current events or circumstances warrant adjustments to our carrying value and/or revised estimates of useful lives. Our impairment test considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. As of December 31, 2014, we believed no such impairment had occurred and no reduction in estimated useful lives was warranted.

Other Intangibles

Excluding goodwill, our other intangible assets include customer contracts, relationships and agreements, lease value, and technology-based assets. As of December 31, 2014 and 2013, these intangible assets totaled $2,302 million and $2,438 million, respectively, and 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, coal, petroleum coke, fertilizer, 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, 2014, 2013 and 2012, the amortization expense on our intangibles totaled $143 million , $125 million and $86 million, respectively. Our estimated amortization expense for our intangible assets for each of the next five fiscal years (2015 – 2019) is approximately $142 million, $133 million, $129 million, $126 million, and $125 million , respectively. As of December 31, 2014, the weighted average amortization period for our intangible assets was approximately nineteen years.

  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 using the effective interest rate method. 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 and premiums (in millions):

December 31,
20142013
KMI and Subsidiaries
Senior term loan facilities, variable rate, due May 24, 2015 and May 6, 2017(a)$—$1,528
Senior notes and debentures, 2.00% through 8.25%, due 2014 through 2098(b)(c)(d)11,4385,645
Credit facility due November 26, 2019(e)(f)850175
Commercial paper borrowings(e)(f)386—
KMP
Senior notes, 2.65% through 9.00%, due 2014 through 2044(b)17,80015,600
Commercial paper borrowings(g)(h)—979
Credit facility due May 1, 2018(g)——
TGP senior notes, 7.00% through 8.375%, due 2016 through 2037(b)1,7901,790
EPNG senior notes, 5.95% through 8.625%, due 2017 through 2032(b)1,1151,115
Copano senior notes, 7.125% due April 1, 2021(b)332332
EPB
EPPOC senior notes, 4.10% through 7.50%, due 2015 through 2042(b)(i)2,8602,260
Credit facility due May 27, 2016(g)——
CIG, senior notes, 5.95% through 6.85%, due 2015 through 2037(b)(j)475475
SLNG senior notes, 9.50% through 9.75%, due 2014 through 2016(b)(k)—135
SNG notes, 4.40% through 8.00%, due 2017 through 2032(b)(l)1,2111,211
Other Subsidiary Borrowings (as obligor)
Kinder Morgan Finance Company, LLC, senior notes, 5.70% through 6.40%, due 2016 through 2036(b)1,6361,636
EPC Building, LLC, promissory note, 3.967%, due 2014 through 2035453461
Preferred securities, 4.75%, due March 31, 2028(d)(m)280280
KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock(n)100100
Other miscellaneous debt(o)303494
Total debt – KMI and Subsidiaries41,02934,216
Less: Current portion of debt(p)2,7172,306
Total long-term debt – KMI and Subsidiaries(q)$38,312$31,910
(a)The senior secured term loan facility, due May 24, 2015, was repaid and replaced in May 2014 with a new unsecured senior term loan facility due May 6, 2017. The unsecured senior term loan facility was repaid in November 2014 (see “—Credit Facilities and Restrictive Covenants” below).
(b)Notes provide for the redemption at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make whole premium.
(c)Includes $6.0 billion of senior notes issued on November 26, 2014 as a result of the Merger Transactions (see “—Debt Issuances and Repayments” below).
(d)On June 30, 2014, El Paso Issuing Corporation, a wholly-owned subsidiary of El Paso Holdco LLC and the corporate co-issuer under certain guaranteed notes, merged with and into El Paso Holdco LLC, a wholly-owned subsidiary of KMI, and immediately thereafter, El Paso Holdco LLC merged with and into KMI pursuant to an internal restructuring transaction. KMI succeeded El Paso Holdco LLC as issuer with respect to these debt obligations. Consequently, El Paso Holdco LLC ceased to be an obligor with respect to approximately $3.6 billion of outstanding senior notes.
(e)As of December 31, 2014 and 2013, the weighted average interest rates on our credit facility borrowings, including commercial paper borrowings in 2014, were 1.54% and 2.67%, respectively.
(f)On November 26, 2014, we entered into a $4 billion replacement credit facility and a commercial paper program of up to $4 billion of unsecured notes (see “—Credit Facilities and Restrictive Covenants” below).
(g)On November 26, 2014, in conjunction with the Merger Transactions, KMP’s and EPB’s credit facility and KMP’s commercial paper program were terminated.
(h)As of December 31, 2013, the average interest rate on KMP’s outstanding commercial paper borrowings was 0.28%. The borrowings under KMP’s commercial paper program were used principally to finance the acquisitions and capital expansions it made during 2014 and 2013.
(i)EPPOC’s operating assets are its investments in WIC, CIG, SLNG, Elba Express, SNG, SLC, CPG, EP Ruby, LLC, Southern Gulf LNG Company, L.L.C. and CIG Gas Storage Company LLC. There are no significant restrictions on EPPOC’s ability to access the net assets or cash flows related to its controlling interests in the operating companies either through dividend or loan. The restrictive covenants

under these debt obligations are no more restrictive than the restrictive covenants under our credit facility. (See also “—Debt Issuances and Repayments” below.)

(j)CIG is subject to a number of restrictions and covenants under its debt obligation. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions.
(k)The SLNG senior notes were repaid on November 26, 2014.
(l)Under its indentures, SNG is subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens. Southern Natural Issuing Corporation (SNIC) is a wholly owned finance subsidiary of SNG and is the co-issuer of certain of SNG’s outstanding debt securities. SNIC has no material assets, operations, revenues or cash flows other than those related to its service as a co-issuer of the debt securities. Accordingly, it has no ability to service obligations on the debt securities.
(m)Capital Trust I (Trust I), is a 100%-owned business trust that as of December 31, 2014, had $5.6 million of 4.75% trust convertible preferred securities outstanding (referred to as the EP 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 EP 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 EP 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 EP Trust I Preferred Securities into debt and equity components and as of December 31, 2014, the outstanding balance of $280 million (of which $141 million is classified as current) was bifurcated between debt ($248 million) and equity ($32 million). During the years ended December 31, 2014 and 2013, 3,923 and 107,618 EP Trust I Preferred Securities had been converted into (i) 2,820 and 77,442 shares of our Class P common stock; (ii) approximately $99,000 and $3 million in cash; and (iii) 4,315 and 118,377 in warrants, respectively.
(n)As of December 31, 2014, 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 (see “—KMGP Preferred Shares” below).
(o)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. EPB reflected the payments made by their joint venture partner as other long-term liabilities on the balance sheet during construction and upon project completion, the advances were converted into a financing obligation to WYCO. Upon placing these projects in service, EPB transferred its title in the projects to WYCO and leased the assets back. Although EPB transferred the title in these projects to WYCO, the transfer did not qualify for sale leaseback accounting because of EPB’s continuing involvement through its equity investment in WYCO. As such, the costs of the facilities remain on our balance sheets and the advanced payments received from EPB’s 50% joint venture partner were converted into a financing obligation due to WYCO. As of December 31, 2014, the principal amounts of the Totem and High Plains financing obligations were $73 million and $100 million, respectively, which will be paid in monthly installments through 2039 based on the initial lease term. At the expiration of the initial lease term, the lease agreement shall be extended automatically for the term of related firm service agreements. The interest rate on these obligations is 15.5%, payable on a monthly basis.
(p)Includes commercial paper borrowings.
(q)Excludes debt fair value adjustments. As of December 31, 2014 and December 31, 2013, our total “Debt fair value adjustments” increased our combined debt carrying amounts by $1,934 million and $1,977 million, respectively. In addition to all unamortized debt discount/premium amounts and purchase accounting on our debt balances, our debt fair value adjustments also include (i) amounts associated with the offsetting entry for hedged debt and (ii) 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 Note 13.

After the consummation of the Merger Transactions, KMI, KMP and EPB and substantially all of their respective wholly owned subsidiaries with debt entered into a cross guarantee agreement with respect to the existing debt of KMI, KMP, EPB and such subsidiaries, so that KMI and those subsidiaries are liable for the debt of KMI, KMP, EPB and such subsidiaries. Also, see Note 18.

Credit Facilities and Restrictive Covenants

On September 19, 2014, we entered into a new five-year $4.0 billion revolving credit agreement with a syndicate of lenders, which can be increased to $5.0 billion if certain conditions are met. The new revolving credit agreement was effective upon the closing of the Merger Transactions on November 26, 2014 and replaced the prior KMI credit agreement, the KMP credit agreement and the EPB credit agreement. On November 26, 2014, we entered into 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. Similarly, our 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, 2014, we were in compliance with all required financial covenants (described following).

Our credit facility included the following restrictive covenants as of December 31, 2014:

•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, 2014, we had $850 million outstanding under our credit facility, $386 million outstanding under our commercial paper program and $223 million in letters of credit. Our availability under this facility as of December 31, 2014 was $2,541 million.

Subsequent Event

On February 4, 2015, in connection with the Hiland acquisition, we entered into and made borrowings of $1,641 million under a new six-month bridge credit facility with UBS AG, Stamford Branch. The credit facility bears interest at the same rate as our $4.0 billion revolving credit facility and the borrowing capacity is reduced by any payments made. As of the date of this filing, we had $1,516 million outstanding under this credit facility.

Copano Debt Acquired

As of the May 1, 2013 Copano acquisition date, KMP assumed the following outstanding Copano debt amounts (i) $404 million of outstanding borrowings under Copano’s revolving credit facility due June 10, 2016; (ii) $249 million aggregate principal amount of Copano’s 7.75% unsecured senior notes due June 1, 2018; and (iii) $510 million aggregate principal amount of Copano’s 7.125% unsecured senior notes due April 1, 2021.

Debt Issuances and Repayments

Apart from the assumption of the Copano debt discussed above, following are significant long-term debt issuances and repayments made during 2014 and 2013:

20142013
Issuances$650 million senior term loan facility due 2017$750 million 5.00% notes due 2021
$500 million 2.00% notes due 2017(b)$750 million 5.625% notes due 2023
$1,500 million 3.05% notes due 2019(b)$251 million EPC Building, LLC 3.967% promissory notes(a)
$1,500 million 4.30% notes due 2025(b)$600 million 3.50% notes due 2023
$750 million 5.30% notes due 2034(b)$700 million 5.00% notes due 2043
$1,750 million 5.55% notes due 2045(b)$800 million 2.65% notes due 2019
$750 million 3.50% notes due 2021$650 million 4.15% notes due 2024
$750 million 5.50% notes due 2044
$650 million 4.25% notes due 2024
$550 million 5.40% notes due 2044
$600 million 4.30% notes due 2024
Repayments$500 million 5.125% notes due 2014$500 million 5.00% notes due 2013
$1,528 million senior term loan facility due 2015$1,186 million senior term loan facility due 2015
$650 million senior term loan facility due 2017(b)$88 million 8.00% notes due 2013
$207 million 6.875% notes due 2014$249 million 7.75% notes due 2018(c)
$178 million portion of 7.125% notes due 2021(d)
(a)In December 2012, our subsidiary, EPC Building, LLC had issued $468 million of 3.967% amortizing promissory notes with payments due 2013 through 2035, of which $217 million was issued to third parties and the remaining $251 million was held by KMI until they were sold to third parties in April of 2013.

(b) Debt issued or repaid associated with the Merger Transactions.

(c) KMP paid $259 million (based on a price of 103.875% of the principal amount) to fully redeem and retire the 7.75% series of senior notes in accordance with the terms and conditions of the indenture governing the notes.

(d) KMP paid $191 million for the partial redemption of the 7.125% senior notes.

KMGP Preferred Shares

The following table provides information about KMGP’s distributions on 100,000 shares of its Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock:

Year Ended December 31,
20142013
Per share cash distribution declared for the period(a)$41.860$42.101
Per share cash distribution paid in the period$41.877$42.169
(a)On January 21, 2015, KMGP declared a distribution for the three months ended December 31, 2014, of $10.553 per share, which was paid on February 18, 2015 to shareholders of record as of February 2, 2015.

Maturities of Debt

The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2014, are summarized as follows (in millions):

YearTotal
2015$2,717
20161,684
20173,059
20182,328
20192,819
Thereafter28,422
Total$41,029

Interest Rates, Interest Rate Swaps and Contingent Debt

The weighted average interest rate on all of our borrowings was 5.02% during 2014 and 5.08% during 2013. Information on our interest rate swaps is contained in Note 13. For information about our contingent debt agreements, see Note 12.

Subsequent Event

Subsequent to December 31, 2014, additional EP Trust I Preferred Securities were converted, primarily consisting of 969,117 EP Trust I Preferred Securities converted on January 14, 2015, into (i) 697,473 of our Class P common stock; (ii) approximately $24 million in cash; and (iii) 1,066,028 in warrants.

  1. Share-based Compensation and Employee Benefits

Share-based Compensation

Kinder Morgan, Inc.

Class P Shares

Stock Compensation Plan for Non-Employee Directors

We have a 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 2014, 2013 and 2012, we made restricted Class P common stock grants to our non-employee directors of 6,210, 5,710 and 5,520, respectively. These grants were valued at time of issuance at $220,000, $210,000 and $185,000, respectively. All of the restricted stock grants made to non-employee directors vest during a six-month period.

Restricted Stock and Long-term Incentive Retention Award Plan

Upon our initial public offering, our restricted stock compensation program replaced our Long-term Incentive Retention Award Plan (discussed below). Our restricted stock compensation program is available to employees eligible under the former Long-term Incentive Retention Award Plan. The following table sets forth a summary of activity and related balances of our restricted stock excluding that issued to non-employee directors (in millions, except share amounts):

Year Ended December 31, 2014Year Ended December 31, 2013Year Ended December 31, 2012
SharesWeighted Average Grant Date Fair ValueSharesWeighted Average Grant Date Fair ValueSharesWeighted Average Grant Date Fair Value
Outstanding at beginning of period6,382,885$2392,154,022$691,163,090$33
Granted1,694,668614,563,4951811,463,38851
Vested(460,032)(14)(83,444)(3)(102,033)(3)
Forfeited(244,227)(9)(251,188)(8)(370,423)(12)
Outstanding at end of period7,373,294$2776,382,885$2392,154,022$69
Intrinsic value of restricted stock vested during the period$17$3$4

Restricted stock grants 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 grants:

YearVesting of Restricted Shares
2015713,675
20161,337,884
20171,653,507
20181,111,830
20191,720,568
2020580,759
2021199,725
202355,346
Total Outstanding7,373,294

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

During 2014, 2013 and 2012, we recorded $57 million, $35 million and $14 million, respectively, in expense related to restricted stock grants. At December 31, 2014 and 2013, unrecognized restricted stock compensation expense, less estimated forfeitures, was approximately $170 million and $177 million, respectively.

From 2006 until our initial public offering, we elected not to make any restricted stock awards as a result of a 2007 going private transaction. To ensure that certain key employees who had previously received restricted stock and restricted stock unit awards continued under a long-term retention and incentive program, we implemented the Long-term Incentive Retention Award plan. The plan provided cash awards approved by our compensation committees which were granted in July of each year to recommended key employees. Senior management was not eligible for these awards. These grants required the employee to sign a grant agreement. The grants vested 100% after the third year anniversary of the grant provided the employee remained with us. The last grants made under this plan were made in July of 2010. During the years ended December 31, 2013 and 2012, we expensed $2 million and $7 million, respectively, related to these grants.

Pension and Other Postretirement Benefit Plans

Overview of Retirement 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. In connection with the EP acquisition, we assumed EP’s defined contribution savings plan which was merged into our savings plan during 2012. In connection with the Copano acquisition, we assumed Copano’s defined contribution savings plan which was merged into our savings plan during 2013. The total amount charged to expense for our savings plan was approximately $42 million, $40 million, and $32 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Pension Plans

Our 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.

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. Medical benefits for these closed groups of retirees 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 plan was 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, 2014 and 2013 (in millions):

Pension BenefitsOPEB
2014201320142013
Change in benefit obligation:
Benefit obligation at beginning of period$2,563$2,792$631$720
Service cost2125——
Interest cost112922523
Actuarial loss (gain)294(132)15(38)
Benefits paid(186)(239)(52)(54)
Participant contributions——311
Medicare Part D subsidy receipts——26
Plan amendments—25—(37)
Benefit obligation at end of period2,8042,563624631
Change in plan assets:
Fair value of plan assets at beginning of period2,3332,240380341
Actual return on plan assets1802543240
Employer contributions50782642
Participant contributions——311
Benefits paid(186)(239)(52)(54)
Fair value of plan assets at end of period2,3772,333389380
Funded status - net liability at December 31,$(427)$(230)$(235)$(251)

Components of Funded Status. The following table details the amounts recognized in our balance sheet at December 31, 2014 and 2013 related to our pension and OPEB plans (in millions):

Pension BenefitsOPEB
2014201320142013
Non-current benefit asset$—$—$173$224
Current benefit liability——(22)(32)
Non-current benefit liability(427)(230)(386)(443)
Funded status - net liability at December 31,$(427)$(230)$(235)$(251)

Components of Accumulated Other Comprehensive Income (Loss). The following table details the amounts of pre-tax accumulated other comprehensive income (loss) at December 31, 2014 and 2013 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
2014201320142013
Unrecognized net actuarial loss$(296)$(10)$(27)$(17)
Unrecognized prior service (cost) credit(4)(5)2021
Accumulated other comprehensive (loss) income$(300)$(15)$(7)$4

We anticipate that approximately $2 million of pre-tax accumulated other comprehensive loss will be recognized as part of our net periodic benefit cost in 2015, including approximately $3 million of unrecognized net actuarial loss and approximately $1 million of unrecognized prior service credit.

Our accumulated benefit obligation for our pension plans was $2,719 million and $2,516 million at December 31, 2014 and 2013, respectively.

Our accumulated postretirement benefit obligation for our OPEB plans, whose accumulated postretirement benefit obligations exceeded the fair value of plan assets, was $553 million and $534 million at December 31, 2014 and 2013, respectively. The fair value of these plans’ assets was approximately $145 million and $60 million at December 31, 2014 and 2013, respectively.

Plan Assets. The investment policies and strategies for the assets of each of the pension and OPEB plans are established by the Fiduciary Committee (the “Committee”), which is responsible for investment decisions and management oversight of each plan. The stated philosophy of the Committee 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 Committee recognizes 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 Committee has adopted a strategy of using multiple asset classes.

As of December 31, 2014, the allowable range for target asset allocations in effect for the pension plan were 34% to 58%, equity, 40% to 50% 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, 2014, the target asset allocations in effect for the retiree medical and retiree life insurance plans were 70% equity and 30% fixed income.

Below are the details of our pension and OPEB plan assets classified by level 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, dollar-denominated money market funds, common and preferred stock, exchange traded mutual funds and 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 money market funds, common/collective trust funds, mutual funds, limited partnerships, trusts, fixed income and other securities. Money market funds are valued at amortized cost, which approximates fair value. The common/collective trust funds’, mutual funds’, limited partnerships’ and trusts’ fair values are based on the net asset value as reported by the issuer, which is determined based on the fair value of the underlying securities as of the valuation date. 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.
•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 and are also subject to certain restrictions associated with the timing of redemption which extend beyond 90 days as of December 31. Included in this level are insurance contracts, mutual funds with significant redemption restrictions, limited partnerships and private equity. Insurance contracts are valued at contract value, which approximates fair value. The mutual funds’ fair values are primarily based on the net asset value as reported by the issuer, which is determined based on the fair value of the underlying securities as of the valuation date. The limited partnerships’ and private equity investments’ fair values are primarily based on the securities’ value as reported by the issuer, which may be determined utilizing discounted present value.

Listed below are the fair values of our pension and OPEB plans’ assets that are recorded at fair value classified in each level at December 31, 2014 and 2013 (in millions):

Pension Assets
20142013
Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Cash and money market funds$5$91$—$96$—$20$—$20
Common/collective trusts(a)—863—863—920—920
Insurance contracts——1515——1515
Mutual funds(b)71198—26992134—226
Common and preferred stocks(c)459——459498——498
Corporate bonds—247—247—220—220
U.S. government securities—190—190—120—120
Asset backed securities—28—28—29—29
Limited partnerships——1616——2828
Equity trusts—199—199—235—235
Private equity——1010——99
Other—(15)—(15)—13—13
Total asset fair value(c)$535$1,801$41$2,377$590$1,691$52$2,333
(a)For 2014, this category includes common/collective trust funds which are invested in approximately 47% fixed income and 53% equity. For 2013, this category includes common/collective trusts funds which are invested in approximately 36% fixed income, 62% equity and 2% short term securities.
(b)For 2014, this category includes mutual funds which are invested in approximately 74% fixed income and 26% equity. For 2013, this category includes mutual funds which are invested in approximately 60% fixed income, 40% equity and other investments.
(c)Plan assets include $252 million and $229 million of KMI Class P common stock for 2014 and 2013, respectively.
OPEB Assets
20142013
Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Cash and money market funds$23$—$—$23$—$—$—$—
Domestic equity securities25——2513——13
Common/collective trusts(a)—71—71—85—85
Fixed income trusts—63—6365——65
Limited partnerships7679—1559272—164
Insurance contracts——4949——4646
Mutual funds3——37——7
Total asset fair value$127$213$49$389$177$157$46$380
(a)For 2014, this category includes common/collective trust funds which are invested in approximately 67% equity and 33% fixed income securities. For 2013, this category includes common/collective trust funds which are invested in approximately 70% equity and 30% fixed income securities.

The following tables present the changes in our pension and OPEB plans’ assets included in Level 3 for the years ended December 31, 2014 and 2013 (in millions):

Pension Assets
Balance at Beginning of PeriodTransfers In (Out)Realized and Unrealized Gains (Losses), netPurchases (Sales), netBalance at End of Period
2014
Insurance contracts$15$—$—$—$15
Limited partnerships28—5(17)16
Private equity9—2(1)10
Total$52$—$7$(18)$41
2013
Insurance contracts$14$—$—$1$15
Mutual funds40——(40)—
Limited partnerships24—3128
Private equity9—1(1)9
Total$87$—$4$(39)$52
OPEB Assets
Balance at Beginning of PeriodTransfers In (Out)Realized and Unrealized Gains (Losses), netPurchases (Sales), netBalance at End of Period
2014
Insurance contracts$46$—$(3)$6$49
Total$46$—$(3)$6$49
2013
Insurance contracts$44$—$—$2$46
Total$44$—$—$2$46

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, 2014 and 2013.

Expected Payment of Future Benefits and Employer Contributions. As of December 31, 2014, we expect to make the following benefit payments under our plans (in millions):

Fiscal yearPension BenefitsOPEB(a)
2015$190$46
201619346
201719345
201819545
201919544
2020-2024965209
(a)Includes a reduction of approximately $2 million in each of the years 2015 - 2019 and approximately $12 million in aggregate for 2020 - 2024 for an expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.

In 2015, we expect to contribute $50 million to our pension plan and approximately $14 million, net of anticipated subsidies, to our 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 2014, 2013 and 2012:

Pension BenefitsOPEB
201420132012201420132012
Assumptions related to benefit obligations:
Discount rate3.66%4.45%3.40%3.56%4.34%3.34%
Rate of compensation increase4.50%3.50%3.00%n/an/an/a
Assumptions related to benefit costs:
Discount rate(a)4.45%3.40%4.22%4.34%3.62%4.11%
Expected return on plan assets(b)(c)7.50%8.00%8.44%7.43%7.35%8.21%
Rate of compensation increase3.50%3.00%3.50%n/an/an/a
(a)The discount rate related to pension benefit cost was 4.50% for the period from January 1, 2012 to May 24, 2012, and 4.03% for the period from May 25, 2012 to December 31, 2012 (the period subsequent to the EP acquisition). The discount rate related to other postretirement benefit cost was 3.34% for the period from January 1, 2013 to July 31, 2013 (the period prior to an OPEB plan amendment that resulted in a remeasurement) and 4.00% for the period from August 1, 2013 to December 31, 2013, and 4.25% for the period from January 1, 2012 to May 24, 2012 and 4.01% for the period from May 25, 2012 to December 31, 2012.
(b)The expected return on plan assets related to pension cost was 8.90% for the period from January 1, 2012 to May 24, 2012, and 8.11% for the period from May 25, 2012 to December 31, 2012 (the period subsequent to the EP acquisition). The expected return on plan assets related to other postretirement benefit cost was 8.90% for the period from January 1, 2012 to May 24, 2012, and 7.72% for the period from May 25, 2012 to December 31, 2012.
(c)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 assumed EP OPEB plans, we utilize an after-tax expected return on plan assets to determine our benefit costs, which is based on unrelated business income taxes at a rate of 21% and 24% for 2014 and 2013, respectively.

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 7.00%, gradually decreasing to 4.50% by the year 2031. 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, 2014 and 2013 (in millions):

20142013
One-percentage point increase:
Aggregate of service cost and interest cost$2$2
Accumulated postretirement benefit obligation4745
One-percentage point decrease:
Aggregate of service cost and interest cost$(2)$(1)
Accumulated postretirement benefit obligation(40)(39)

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 (including amounts associated with the EP Pension and OPEB plans since the May 25, 2012 acquisition date) recognized in pre-tax other comprehensive income related to our pension and OPEB plans are as follows (in millions):

Pension BenefitsOPEB
201420132012201420132012
Components of net benefit cost:
Service cost$21$25$18$—$—$—
Interest cost1129267252318
Expected return on assets(171)(175)(110)(24)(22)(15)
Amortization of prior service (credit) cost——(1)(2)(1)(1)
Amortization of net actuarial loss (gain)——10(1)34
Curtailment and settlement gain—(3)(2)——(1)
Net benefit (credit) cost(38)(61)(18)(2)35
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
Net (gain) loss arising during period285(211)8510(50)25
Prior service cost (credit) arising during period—25(17)—(18)(4)
Amortization or settlement recognition of net actuarial gain (loss)—3(10)—(3)(5)
Amortization of prior service credit——1111
Total recognized in total other comprehensive income loss285(183)5911(70)17
Total recognized in net benefit (credit) cost and other comprehensive (income) loss$247$(244)$41$9$(67)$22

Other Plans

Plans Associated with Foreign Operations

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 Trans Mountain pipeline system 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. These subsidiaries also provide postretirement benefits other than pensions for retired employees. Our combined net periodic benefit costs for these Trans Mountain pension and other postretirement benefit plans for the years ended December 31, 2014, 2013 and 2012 was $10 million, $11 million and $11 million, respectively, recognized ratably over each year. As of December 31, 2014, we estimate the overall net periodic pension and other postretirement benefit costs for these plans for the year 2015 will be approximately $14 million, although this estimate could change if there is a significant event, such as a plan amendment or a plan curtailment, which would require a remeasurement of liabilities. Furthermore, we expect to contribute approximately $11 million to these benefit plans in 2015.

Multiemployer Plans

As a result of acquiring several terminal operations, primarily the acquisition of Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, 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 $13 million, $11 million and $11 million for the years ended December 31, 2014, 2013 and 2012, 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

Kinder Morgan, Inc. – Equity Interests

Common Equity

During the years 2012 through 2014, as authorized by our board of directors under various repurchase programs, we repurchased shares and warrants. As of December 31, 2014, we had $2 million available for repurchases under the 2014 repurchase program. During the years ended December 31, 2014, 2013 and 2012, we paid a total of $98 million, $465 million and $157 million, respectively, for the repurchase of warrants. During the years ended December 31, 2014 and 2013, we repurchased $94 million and $172 million respectively, of our Class P shares.

The following table sets forth the changes in our outstanding shares:

Class PClass AClass BClass C
Balance at December 31, 2011170,921,140535,972,38794,132,5962,318,258
Shares issued for EP acquisition (see Note 3)330,154,610———
Shares issued with conversions of EP Trust I Preferred securities562,521———
Shares converted535,972,387(535,972,387)(94,132,596)(2,318,258)
Shares canceled(2,049,615)———
Restricted shares vested107,553———
Balance at December 31, 20121,035,668,596———
Shares issued for EP acquisition(a)53
Shares repurchased and canceled(5,175,055)
Shares issued with conversions of EP Trust I Preferred securities77,442
Shares issued for exercised warrants16,886
Restricted shares vested89,154
Balance at December 31, 20131,030,677,076
Shares issued for Merger Transactions1,096,910,451
Shares repurchased and canceled(2,780,337)
Shares issued with conversions of EP Trust I Preferred securities2,820
Shares issued for exercised warrants12,402
Restricted shares vested324,704
Balance at December 31, 20142,125,147,116

(a) Represents Class P shares issued upon the settlement of an EP dissenter. The settlement of the dissenter’s 128 EP shares was determined based on the same conversion of EP shares into cash, KMI Class P shares and KMI warrants that was received by other EP shareholders at the time of the acquisition.

As of January 1, 2012, the “Investors” (as defined hereinafter) owned all of our outstanding Class A shares, Class B shares and Class C shares, which are sometimes referred to in this report as the “investor retained stock.” The Investors were Richard D. Kinder, our Chairman and Chief Executive Officer; the Sponsor Investors; Fayez Sarofim, one of our directors, and investment entities affiliated with him, and an investment entity affiliated with Michael C. Morgan, another of our directors and William V. Morgan, one of our founders, whom we refer to collectively as the “Original Stockholders”; and a number of other members of our management, who are referred to collectively as “Other Management.” Our Class A shares represented the total capital contributed by the Investors (and a notional amount of capital allocated to the contribution of the holders of the Class C shares) at the time of a 2007 going private transaction. The Class B shares and Class C shares represented incentive compensation that were held by members of our management, including Mr. Kinder only in the case of the Class B shares.

During the year ended December 31, 2012, certain of the Sponsor Investors (the Selling Stockholders) completed underwritten public offerings (the Offerings) of an aggregate of 198,996,921 shares of our Class P common stock (including 8,700,000 shares that were the subject of an underwriters’ option to purchase additional shares). Neither we nor our management sold any shares of common stock in the Offerings, and we did not receive any of the proceeds from the Offerings of shares by the Selling Stockholders. As a result of these offerings, the Sponsor Investors advised by or affiliated with

Goldman Sachs & Co., The Carlyle Group, and Riverstone Holdings LLC no longer own any of our shares, and representatives of these Sponsor Investors are no longer on our board.

On December 26, 2012, the remaining series of the Class A, Class B and Class C shares held by the Investors automatically converted into shares of Class P common stock upon the election of the holders of at least two-thirds of the shares of each such series of Class A common stock and the holders of at least two-thirds of the shares of each such series of Class B common stock. Subsequent to these conversions, all our Class A, Class B and Class C shares were fully converted and as a result, only our Class P common stock was outstanding as of December 31, 2012. Additionally, as Class A, Class B and Class C shares converted, certain holders of Class P shares were paid out in cash and their Class P shares were immediately canceled. During the year ended December 31, 2012 approximately 2 million Class P shares were canceled resulting in payments totaling approximately $71 million to the holders of those shares.

Equity Issuances Subsequent to December 31, 2014

On December 19, 2014, we entered into an equity distribution agreement with UBS Securities LLC, referred to as UBS, with Citigroup Global Markets Inc., Credit Suisse Securities (U.S.A.) LLC, Deutsche Bank Securities Inc., J.P. Morgan Securities LLC and Mitsubishi UFJ Securities (U.S.A.), Inc. (each a “Manager” and, collectively, the “Managers”). We propose to issue and sell through or to the Managers, as sales agents and/or principals, shares of the our Class P common stock, par value $0.01 per share having an aggregate offering price of up to $5,000 million from time to time during the term of this Agreement. Subsequent to December 31, 2014, we had equity issuances of 20,363,204 shares of our Class P common stock.

Dividends

Holders of our common stock share equally 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,
201420132012
Per common share cash dividend declared for the period$1.74$1.60$1.40
Per common share cash dividend paid in the period1.701.561.34

On January 21, 2015, our board of directors declared a cash dividend of $0.45 per share for the quarterly period ended December 31, 2014. This dividend was paid on February 17, 2015 to shareholders of record as of February 2, 2015. Since this dividend was declared after the end of the quarter, no amount is shown in our accompanying December 31, 2014 consolidated balance sheet as a dividend payable.

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
201420132012
Beginning balance347,933,107439,809,442—
Warrants issued in EP acquisition(a)—81504,598,883
Warrants issued with conversions of EP Trust I Preferred securities(b)4,315118,377859,796
Warrants exercised(18,040)(21,208)—
Warrants repurchased and canceled(49,783,406)(91,973,585)(65,649,237)
Ending balance298,135,976347,933,107439,809,442
(a)See Note 3. 2013 amount represents warrants issued upon the settlement of an EP dissenter. The settlement of the dissenter’s 128 EP shares was determined based on the same conversion of EP shares into cash, KMI Class P shares and KMI warrants that was received by other EP shareholders at the time of the acquisition.
(b)See Note 8.

Noncontrolling Interests

The caption “Noncontrolling interests” in our accompanying consolidated balance sheets consists of interests that we do not own in the following subsidiaries (in millions):

December 31,
20142013
KMP$—$7,642
EPB—4,122
KMR—3,142
Other350286
$350$15,192

At December 31, 2014, as a result of the Merger Transactions, we owned all of the outstanding common units of KMP and EPB and all of the outstanding shares of KMR that we or our subsidiaries did not already own.

At December 31, 2013, we owned, directly, and indirectly in the form of i-units corresponding to the number of shares of KMR we owned, approximately 43 million limited partner units of KMP. These units, which consisted of 22 million common units, 5 million Class B units and 16 million i-units, represented approximately 9.8% of the total outstanding limited partner interests of KMP. In addition, we indirectly own all the common equity of the general partner of KMP, which holds an effective 2% interest in KMP and its operating partnerships. Together, at December 31, 2013, our limited partner and general partner interests represented approximately 11.6% of KMP’s total equity interests and represented an approximate 50% economic interest in KMP. This difference resulted from the existence of incentive distribution rights (IDRs) previously held by KMGP, the general partner of KMP.

As of December 31, 2013, we owned approximately 90 million limited partner units of EPB, representing approximately 41% of the total equity interests of EPB. In addition, we were the sole owner of the general partner of EPB, which held an effective 2% interest in EPB.

At December 31, 2013, we owned approximately 16 million KMR shares representing approximately 13.0% of KMR’s outstanding shares.

Contributions

Prior to the completion of the Merger Transactions on November 26, 2014, contributions from our noncontrolling interests consisted primarily of equity issuances 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 terms of each agreement were substantially similar. Sales of the subsidiary’s equity interests were made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between the subsidiary equity issuer and its sales agent. The subsidiary equity issuer could also sell its equity interests to its sales agent as principal for the sales agent’s own account at a price agreed upon at the time of the sale. Any sale of the subsidiary’s equity interests to the sales agent as principal would be pursuant to the terms of a separate agreement between the subsidiary equity issuer and its 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. The subsidiary retained at all times complete control over the amount and the timing of sales under its respective equity distribution agreement, and it designated the maximum number of equity units or shares to be sold through its sales agent, on a daily basis or otherwise as the subsidiary equity issuer and its sales agent agreed.

The table below shows significant issuances to the public of common units or shares, the net proceeds from the issuances and the use of the proceeds during the years ended December 31, 2014 and 2013 by KMP, EPB and KMR (dollars in millions and shares in thousands):

IssuancesCommon units/sharesNet proceedsUse of proceeds
(in thousands)(in millions)
KMP
Issued under Equity Distribution Agreement(a)
20145,513$441Reduced borrowings under KMP’s commercial paper program
201310,814$900Reduced borrowings under KMP’s commercial paper program
Other issuances
February 20147,935$603Reduced borrowings under KMP’s commercial paper program that were used to fund KMP’s APT acquisition in January 2014
February 20134,600$385Issued to pay a portion of the purchase price for the March 2013 drop-down transaction
May 201343,371$—(b)Issued to Copano unitholders as KMP’s purchase price for Copano
EPB
Issued under Equity Distribution Agreement(c)
20147,314$275General partnership purposes
20132,038$85General partnership purposes
Other issuances
May 20147,820$242Issued to pay a portion of the purchase price for the May 2014 drop-down transaction
KMR
Issued under Equity Distribution Agreement(d)
20141,735$134Purchased additional KMP i-units; KMP then used proceeds to reduce borrowings under its commercial paper program
20132,640$210Purchased additional KMP i-units; KMP then used proceeds to reduce borrowings under its commercial paper program
(a)Prior to the completion of the Merger Transactions on November 26, 2014, KMP was a party to two equity distribution agreements with UBS Securities LLC (UBS), one of which allowed the aggregate offering price of KMP’s common units of up to $2.175 billion, and a second separate equity distribution agreement which allowed the aggregate offering price of up to $1.9 billion.
(b)KMP valued these units at $3,733 million based on the $86.08 closing market price of a KMP common unit on the NYSE on May 1, 2013.
(c)Prior to the completion of the Merger Transactions on November 26, 2014, EPB was a party to an equity distribution agreement with Citigroup. Pursuant to the provisions of EPB’s equity distribution agreement, EPB could sell from time to time through Citigroup, as its sales agent, EPB’s common units representing limited partner interests having an aggregate offering price of up to $500 million.
(d)Prior to the completion of the Merger Transactions on November 26, 2014, KMR was a party to an equity distribution agreement with Credit Suisse Securities (U.S.A.) LLC (Credit Suisse). Pursuant to the provisions of KMR’s equity distribution agreement, it could sell from time to time through Credit Suisse, as its sales agent, KMR shares having an aggregate offering price of up to $500 million.

The above equity issuances by KMP, EPB and KMR during the periods ended November 25, 2014 and December 31, 2013 had the associated effects of increasing our (i) noncontrolling interests by $1,640 million and $5,059 million, respectively; (ii) accumulated deferred income taxes by $19 million and $93 million, respectively; and (iii) additional paid-in capital by $36 million and $161 million, respectively.

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,
201420132012
KMP(a)
Per unit cash distribution declared for the period$4.17$5.33$4.98
Per unit cash distribution paid in the period$5.53$5.26$4.85
Cash distributions paid in the period to the public$1,654$1,372$1,081
EPB(a)(b)
Per unit cash distribution declared for the period$1.95$2.55$1.74
Per unit cash distribution paid in the period$2.60$2.51$1.13
Cash distributions paid in the period to the public$347$318$137
KMR(a)(c)
Share distributions paid in the period to the public7,794,1836,588,4775,586,579
(a)As a result of the Merger Transactions, no distribution was declared for the fourth quarter of 2014.
(b)Represents distribution information since the May 2012 EP acquisition.
(c)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, 976,723 and 902,367 of shares distributed in 2014, 2013 and 2012, respectively, on KMR shares we directly and indirectly owned.
  1. Related Party Transactions

Affiliated Balances

The following table summarizes our balance sheet affiliate balances (in millions):

December 31,
20142013
Balance sheet location
Accounts receivable, net$31$19
Other current assets33
Deferred charges and other assets4647
$80$69
Current portion of debt(a)$6$6
Accounts payable229
Long-term debt(a)172169
$200$184
(a)Includes financing obligations payable to WYCO (See Note 8).

Notes Receivable

Plantation

We and ExxonMobil have a term loan agreement covering a note receivable due from Plantation. We own a 51.17% equity interest in Plantation and our proportionate share of the outstanding principal amount of the note receivable was $47 million and $48 million as of December 31, 2014 and 2013, respectively. The note bears interest at the rate of 4.25% per annum and provides for semiannual payments of principal and interest on December 31 and June 30 each year, with a final principal

payment of $45 million (for our portion of the note) due on July 20, 2016. We included $1 million of the note receivable balance within “Other current assets” and we included the remaining outstanding balance within “Deferred charges and other assets” on our accompanying consolidated balance sheets as of both December 31, 2014 and 2013.

Gulf LNG Holdings Group, LLC

In conjunction with the acquisition of EP, KMI acquired a long-term note receivable, bearing interest at 12% per annum, that was due from Gulf LNG Holdings Group, LLC, a 50% equity investee, with a remaining principal amount of $85 million. Subsequent to the EP acquisition and through the end of 2012, we received payments on this note totaling $75 million. We received payments for the remaining note balance of $10 million during the first quarter of 2013.

Subsequent Event

MEP

On February 3, 2015 we renewed our 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. Each individual loan must be in an amount not less than $2 million, and the aggregate loan balance outstanding must not exceed $40 million. Borrowings under the loan agreement bear interest at a rate of one month LIBOR plus 1.75%, and all borrowings can be prepaid before maturity without penalty or premium. As of both December 31, 2014 and 2013 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, 2014 (in millions):

YearCommitment
2015$97
201685
201775
201867
201965
Thereafter289
Total minimum payments$678

The remaining terms on our operating leases, including probable elections to exercise renewal options, range from one to thirty-nine years. Total lease and rental expenses were $114 million, $126 million and $94 million for the years ended December 31, 2014, 2013 and 2012, respectively. The amount of capital leases included within “Property, plant and equipment, net” in our accompanying consolidated balance sheets as of December 31, 2014 and 2013 is not material to our consolidated balance sheets.

Commitments

Capital Contributions for Elba Liquefaction Project

In January 2013, SLC, our subsidiary, and Shell U.S. Gas and Power, LLC (Shell G&P), a subsidiary of Royal Dutch Shell plc (Shell), formed ELC, an equity method investment, to develop and own a natural gas liquefaction plant at SLNG’s existing Elba Island LNG terminal. In connection with the formation of ELC, SLC and Shell G&P entered into a LLC agreement in which SLC owns 51% of ELC and Shell G&P owns the remaining membership interest. Under the terms of the LLC agreement, SLC and Shell G&P are both obligated to make certain capital contributions in proportion to their membership interests in ELC to fund the construction of the liquefaction facilities. Our investment at the terminal, including both the liquefaction facilities and SLNG ancillary facilities, is estimated to be approximately $1.3 billion.

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, 2014 and 2013, our contingent debt obligations, as well as our obligations with respect to related letters of credit, totaled $1,069 million and $74 million, respectively. The December 31, 2014 amount is 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 its percentage ownership share (50%) of the Cortez Pipeline Company debt and 100% of the debt issued by one of its subsidiaries in the event of their non-performance) which has a $200 million credit facility 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.

Our potential exposure under guarantee and indemnification agreements can range from a specified to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. While many of these agreements may specify a maximum potential exposure, or a specified duration to the indemnification obligation, there are circumstances where the amount and duration are unlimited. Those arrangements with a specified dollar amount have a maximum stated value of approximately $688 million, which primarily represents indemnification agreements associated with EP’s prior discontinued and foreign operations. 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.

  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 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.

As part of the EP acquisition, we acquired power forward and swap contracts. We have entered into offsetting positions that eliminate the price risks associated with our power contracts.

As of December 31, 2014, we discontinued hedge accounting on certain of our crude derivative contracts as we do not expect them to be highly effective, for accounting purposes, in offsetting the variability in cash flows. This was caused primarily by volatility in basis differentials. As the forecasted transactions are still probable, accumulated gains and losses remain in other comprehensive income until earnings are impacted by the forecasted transactions. Future changes in the derivative contracts’ fair value subsequent to the discontinuance of hedge accounting will be reported in earnings. We may re-designate certain of these hedging relationships if their expected effectiveness improves.

Energy Commodity Price Risk Management

As of December 31, 2014, we had entered into 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(10.9)MMBbl
Crude oil basis(10.8)MMBbl
Natural gas fixed price(27.2)Bcf
Natural gas basis(8.0)Bcf
Derivatives not designated as hedging contracts
Crude oil fixed price(14.9)MMBbl
Natural gas fixed price2.0Bcf
Natural gas basis6.5Bcf
NGL fixed price(2.1)MMBbl

As of December 31, 2014, 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 2017. We have additional economic hedge contracts through December 2018.

Interest Rate Risk Management

As of December 31, 2014 and 2013, we had a combined notional principal amount of $9,200 million and $5,400 million, respectively, of fixed-to-variable interest rate swap agreements, effectively converting 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. All of our swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes and, as of December 31, 2014, 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.

In February 2014, we entered into four separate fixed-to-variable interest rate swap agreements having a combined notional principal amount of $500 million. These agreements effectively convert a portion of the interest expense associated with our 3.50% senior notes due March 1, 2021, from a fixed rate to a variable rate. In September 2014, we entered into five separate fixed-to-variable interest rate swap agreements having a combined notional principal amount of $600 million. These agreements effectively convert a portion of the interest expense associated with our 4.25% senior notes due September 1, 2024, from a fixed rate to a variable rate. Additionally, in November 2014, we entered into twenty-one separate fixed-to-variable interest rate swap agreements having a combined notional principal amount of $3,000 million. These agreements effectively convert a portion of the interest expense associated with our 4.30% senior notes due June 1, 2025 and 3.05% senior notes due December 1, 2019, from a fixed rate to a variable rate.

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,
2014201320142013
Balance sheet locationFair valueFair value
Derivatives designated as hedging contracts
Natural gas and crude derivative contractsOther current assets/(Other current liabilities)$309$18$(34)$(33)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)658—(30)
Subtotal31576(34)(63)
Interest rate swap agreementsOther current assets/(Other current liabilities)14387——
Deferred charges and other assets/(Other long-term liabilities and deferred credits)260172(53)(116)
Subtotal403259(53)(116)
Total718335(87)(179)
Derivatives not designated as hedging contracts
Natural gas, crude and NGL derivative contractsOther current assets/(Other current liabilities)734(2)(5)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)196———
Subtotal2694(2)(5)
Power derivative contractsOther current assets/(Other current liabilities)107(57)(54)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)—11(16)(73)
Subtotal1018(73)(127)
Total27922(75)(132)
Total derivatives$997$357$(162)$(311)

Debt Fair Value Adjustments

The offsetting entry to adjust the carrying value of the debt securities whose fair value was being hedged is included within “Debt fair value adjustments” on our accompanying consolidated balance sheets. Our “Debt fair value adjustments” also include all unamortized debt discount/premium amounts, purchase accounting on our debt balances, and any unamortized portion of proceeds received from the early termination of interest rate swap agreements. As of December 31, 2014 and 2013, these fair value adjustments to our debt balances included (i) $1,221 million and $1,379 million, respectively, associated with fair value adjustments to our debt previously recorded in purchase accounting; (ii) $347 million and $143 million, respectively, associated with the offsetting entry for hedged debt; (iii) $454 million and $517 million respectively, associated with unamortized premium from the termination of interest rate swap agreements; and offset by (iv) $88 million and $62 million, respectively, associated with unamortized debt discount amounts. As of December 31, 2014, the weighted-average amortization period of the unamortized premium from the termination of the interest rate swaps was approximately 16 years.

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 relationshipsLocation of gain/(loss)recognized in income on derivativesAmount of gain/(loss)recognized in income on derivatives and related hedged item
Year Ended December 31,
201420132012
Interest rate swap agreementsInterest expense$207$(425)$55
Total$207$(425)$55
Fixed rate debtInterest expense$(204)$425$(55)
Total$(204)$425$(55)
Derivatives in cash flow hedging relationshipsAmount of gain/(loss) recognized in OCI on derivative (effective portion)(a)Location of gain/(loss) reclassified from Accumulated OCI into income (effective portion)Amount of gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b)Location of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)Amount of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)
Year EndedYear EndedYear Ended
December 31,December 31,December 31,
201420132012201420132012201420132012
Energy commodity derivative contracts$423$(45)$87Revenues—Natural gas sales$(1)$—$4Revenues—Natural gas sales$—$—$—
Revenues—Product sales and other26(13)(15)Revenues—Product sales and other113(11)
Costs of sales4—17Costs of sales———
Interest rate swap agreements(15)7(5)Interest expense(4)22Interest expense———
Total$408$(38)$82Total$25$(11)$8Total$11$3$(11)
(a)We expect to reclassify an approximate $208 million gain associated with energy commodity price risk management activities included in our accumulated other comprehensive loss balance as of December 31, 2014 into earnings during the next twelve months (when the associated forecasted sales and purchases are also expected to occur), however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.
(b)Amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).
Derivatives not designated as accounting hedgesLocation of gain/(loss) recognized in income on derivativesAmount of gain/(loss) recognized in income on derivatives
Year Ended December 31,
201420132012
Energy commodity derivative contractsRevenues—Natural gas sales$(7)$—$1
Revenues—Product sales and other20(10)(4)
Costs of sales—2—
Other expense (income)(2)(2)—
Total$11$(10)$(3)

Credit Risks

We have counterparty credit risk as a result of our use of financial derivative contracts. Our counterparties consist primarily of financial institutions, major energy companies, natural gas and electric utilities and local distribution companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include (i) an evaluation of potential counterparties’ financial condition (including credit ratings); (ii) collateral requirements under certain circumstances; and (iii) the use of standardized agreements which allow for netting of positive and negative exposure associated with a single counterparty. Based on our policies, exposure, credit and other reserves, our management does not anticipate a material adverse effect on our financial position, results of operations, or cash flows as a result of counterparty performance.

Our OTC swaps and options are entered into with counterparties outside central trading organizations such as futures, options or stock exchanges. These contracts are with a number of parties, all of which have investment grade credit ratings. While we enter into derivative transactions with investment grade counterparties and actively monitor their ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future.

In conjunction with the purchase of exchange-traded derivative contracts or when the market value of our derivative contracts with specific counterparties exceeds established limits, 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, 2014 and 2013, we had $20 million and $167 million, respectively, of outstanding letters of credit supporting our commodity price risks associated with the sale of power.

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, 2014, we estimate that if our credit rating was downgraded one or two notches, we would be required to post no additional collateral to our counterparties.

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income

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 income/(loss)
Balance as of December 31, 2011$(20)$37$(132)$(115)
Other comprehensive income before reclassifications3214(53)(7)
Amounts reclassified from accumulated other comprehensive loss(5)—94
Net current-period other comprehensive income2714(44)(3)
Balance as of December 31, 2012751(176)(118)
Other comprehensive income before reclassifications(14)(49)15188
Amounts reclassified from accumulated other comprehensive loss4—26
Net current-period other comprehensive income(10)(49)15394
Balance as of December 31, 2013(3)2(23)(24)
Other comprehensive income before reclassifications254(68)(212)(26)
Amounts reclassified from accumulated other comprehensive loss(22)—(1)(23)
Impact of Merger Transactions (See Note 1)98(42)—56
Net current-period other comprehensive income330(110)(213)7
Balance as of December 31, 2014$327$(108)$(236)$(17)
  1. Fair Value

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 and (ii) interest rate swap agreements, based on the three levels established by the Codification (in millions). Certain of our derivative contracts are subject to master netting agreements.

Balance sheet asset fair value measurements usingAmounts not offset in the balance sheet
Level 1Level 2Level 3Gross amountFinancial instrumentsCash collateral held(b)Net amount
As of December 31, 2014
Energy commodity derivative contracts(a)$49$533$12$594$(46)$(13)$535
Interest rate swap agreements$—$403$—$403$(44)$—$359
As of December 31, 2013
Energy commodity derivative contracts(a)$4$46$48$98$(62)$—$36
Interest rate swap agreements$—$259$—$259$(28)$—$231
Balance sheet liability fair value measurements usingAmounts not offset in the balance sheet
Level 1Level 2Level 3Gross amountFinancial instrumentsCash collateral posted(c)Net amount
As of December 31, 2014
Energy commodity derivative contracts(a)$(25)$(11)$(73)$(109)$46$47$(16)
Interest rate swap agreements$—$(53)$—$(53)$44$—$(9)
As of December 31, 2013
Energy commodity derivative contracts(a)$(6)$(31)$(158)$(195)$62$17$(116)
Interest rate swap agreements$—$(116)$—$(116)$28$—$(88)
(a)Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps and options. 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 “Other current assets” 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,
20142013
Derivatives-net asset (liability)
Beginning of period$(110)$(155)
Transfers out(a)(88)—
Total gains or (losses)
Included in earnings22(5)
Included in other comprehensive loss78(1)
Purchases(b)—17
Settlements3734
End of period$(61)$(110)
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$1$(8)

(a) On December 31, 2014, we transferred WTI options from Level 3 to Level 2 due to increased observability of significant inputs in their valuations.

(b) 2013 amount represents the purchase of Level 3 energy commodity derivative contracts associated with our May 1, 2013 Copano acquisition.

As of December 31, 2014, our Level 3 derivative assets and liabilities consisted primarily of power derivative contracts, 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.

Fair Value of Financial Instruments

The estimated fair value of our outstanding debt balances (the carrying amounts below include both short-term and long-term and debt fair value adjustments), is disclosed below (in millions):

December 31, 2014December 31, 2013
Carrying valueEstimated fair valueCarrying valueEstimated fair value
Total debt$42,963$43,582$36,193$36,248

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both December 31, 2014 and 2013.

  1. Reportable Segments

We divide our operations into the following reportable business segments. These segments and their principal sources of revenues are as follows:

•Natural Gas Pipelines—(i) the ownership and operation of major interstate and intrastate natural gas pipeline and storage systems; (ii) the ownership and/or operation of associated natural gas and crude oil gathering systems and natural gas processing and treating facilities; and (iii) the ownership and/or operation of NGL fractionation facilities and transportation systems;
•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 and rail transloading and materials handling facilities located throughout the U.S. and portions of Canada that transload and store refined petroleum products, crude oil, condensate, and bulk products, including coal, petroleum coke, cement, alumina, salt and other bulk chemicals and (ii) the ownership and operation of our Jones Act tankers;
•Products Pipelines—the ownership and operation of refined petroleum products and crude oil and condensate pipelines that deliver refined petroleum products (gasoline, diesel fuel and jet fuel), NGL, crude oil, condensate and bio-fuels to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities;
•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; and
•Other—primarily includes other miscellaneous assets and liabilities purchased in our 2012 EP acquisition including (i) our corporate headquarters in Houston, Texas; (ii) several physical natural gas contracts with power plants associated with EP’s legacy trading activities; and (iii) other miscellaneous EP assets and liabilities.

We evaluate performance principally based on each segment’s EBDA (including amortization of excess cost of equity investments), which excludes general and administrative expenses, third-party debt costs and interest expense, unallocable interest income, and unallocable 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.

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 2014, 2013 and 2012, 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,
201420132012
Revenues
Natural Gas Pipelines(a)
Revenues from external customers$10,153$8,613$5,230
Intersegment revenues154—
CO21,9601,8571,677
Terminals
Revenues from external customers1,7171,4081,356
Intersegment revenues123
Products Pipelines2,0681,8531,370
Kinder Morgan Canada291302311
Other11(6)
Total segment revenues16,20614,0409,941
Other revenues(b)363635
Less: Total intersegment revenues(16)(6)(3)
Total consolidated revenues$16,226$14,070$9,973
Year Ended December 31,
201420132012
Operating expenses(c)
Natural Gas Pipelines(a)$6,241$5,235$3,111
CO2494439381
Terminals746657685
Products Pipelines1,2581,295759
Kinder Morgan Canada106110103
Other24305
Total segment operating expenses8,8697,7665,044
Other operating expenses——4
Less: Total intersegment operating expenses(16)(6)(3)
Total consolidated operating expenses$8,853$7,760$5,045
Year Ended December 31,
201420132012
Other expense (income)
Natural Gas Pipelines(a)$5$(24)$14
CO2(d)243—(7)
Terminals29(74)(14)
Products Pipelines(3)6(5)
Other1(7)(1)
Total consolidated other expense (income)$275$(99)$(13)
Year Ended December 31,
201420132012
DD&A
Natural Gas Pipelines(a)$897$797$478
CO2570533494
Terminals337247236
Products Pipelines166155143
Kinder Morgan Canada515456
Other192012
Total consolidated DD&A$2,040$1,806$1,419
Year Ended December 31,
201420132012
Earnings from equity investments
Natural Gas Pipelines(a)(e)$318$232$52
CO2252425
Terminals182221
Products Pipelines444539
Kinder Morgan Canada—45
Other1—11
Total consolidated equity earnings$406$327$153
Year Ended December 31,
201420132012
Amortization of excess cost of equity investments
Natural Gas Pipelines(a)$39$32$17
CO2(1)22
Products Pipelines754
Total consolidated amortization of excess cost of equity investments$45$39$23
Year Ended December 31,
201420132012
Interest income
Natural Gas Pipelines$1$—$18
Products Pipelines222
Kinder Morgan Canada—314
Other683
Total segment interest income91337
Unallocated interest income—2(9)
Total consolidated interest income$9$15$28
Year Ended December 31,
201420132012
Other, net-income (expense)
Natural Gas Pipelines(f)$24$578$4
CO2——(1)
Terminals1212
Products Pipelines(1)19
Kinder Morgan Canada(g)152463
Other3092
Total consolidated other, net-income (expense)$80$835$19
Year Ended December 31,
201420132012
Income tax benefit (expense)
Natural Gas Pipelines$(6)$(9)$(5)
CO2(8)(7)(5)
Terminals(29)(14)(3)
Products Pipelines(2)22
Kinder Morgan Canada(18)(21)(1)
Total segment income tax expense(63)(49)(12)
Unallocated income tax expense(585)(693)(127)
Total consolidated income tax expense$(648)$(742)$(139)
Year Ended December 31,
201420132012
Segment EBDA(h)
Natural Gas Pipelines(a)$4,259$4,207$2,174
CO21,2401,4351,322
Terminals944836708
Products Pipelines856602668
Kinder Morgan Canada182424229
Other13(5)7
Total segment EBDA7,4947,4995,108
Total segment DD&A(2,040)(1,806)(1,419)
Total segment amortization of excess cost of equity investments(45)(39)(23)
Other revenues363635
General and administrative expenses(i)(610)(613)(929)
Interest expense, net of unallocable interest income(j)(1,807)(1,688)(1,441)
Unallocable income tax expense(585)(693)(127)
Loss from discontinued operations, net of tax(k)—(4)(777)
Total consolidated net income$2,443$2,692$427
Year Ended December 31,
201420132012
Capital expenditures
Natural Gas Pipelines(a)$935$1,085$499
CO2792667453
Terminals1,0491,108707
Products Pipelines680416307
Kinder Morgan Canada1567716
Other51640
Total consolidated capital expenditures$3,617$3,369$2,022
20142013
Investments at December 31
Natural Gas Pipelines(a)5,174$5,130
CO21712
Terminals219196
Products Pipelines624611
Kinder Morgan Canada11
Other11
Total consolidated investments$6,036$5,951
20142013
Assets at December 31
Natural Gas Pipelines$52,523$52,357
CO25,2274,708
Terminals8,8506,888
Products Pipelines7,1796,648
Kinder Morgan Canada1,5931,677
Other459568
Total segment assets75,83172,846
Corporate assets(l)7,3112,339
Assets held for sale56—
Total consolidated assets$83,198$75,185
(a)The Copano acquisition was effective May 1, 2013 and the EP acquisition was effective May 25, 2012 (see Note 3).
(b)Includes a management fee for services we perform for NGPL Holdco LLC.
(c)Includes natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
(d)2014 amount includes an impairment charge of $235 million primarily related to the Katz Strawn unit.
(e)2013 and 2012 amounts include impairment charges of $65 million and $200 million, respectively, to reduce the carrying value of our equity investment in NGPL Holdco LLC.
(f)2013 amount includes a $558 million gain from the remeasurement of our previously held 50% equity interest in Eagle Ford to fair value (See Note 3).
(g)2013 amount includes a $224 million pre-tax gain from the sale of our equity and debt investments in the Express pipeline system (See Note 3).
(h)Includes revenues, earnings from equity investments, allocable interest income, and other, net, less operating expenses, allocable income taxes, and other expense (income).
(i)2012 amount includes $366 million of pre-tax expense associated with the EP acquisition and EP Energy sale.
(j)Includes (i) interest expense and (ii) miscellaneous other income and expenses not allocated to business segments. 2012 amount includes $108 million of expense for capitalized financing fees associated with the EP acquisition financing that were written-off (primarily due to debt repayments) or amortized.
(k)Represents loss from sale of the FTC Natural Gas Pipelines disposal group and other, net of tax (see Note 3).
(l)Includes cash and cash equivalents, margin and restricted deposits, unallocable interest receivable, prepaid assets and deferred charges, risk management assets related to debt fair value adjustments and miscellaneous corporate assets (such as information technology and telecommunications equipment) not allocated to individual segments.

We do not attribute interest and debt expense to any of our reportable business segments. For each of the years ended December 31, 2014, 2013 and 2012, we reported total consolidated interest expense of $1,807 million, $1,690 million, and $1,427 million, respectively.

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

Year Ended December 31,
201420132012
Revenues from external customers
U.S.$15,605$13,656$9,488
Canada437398407
Mexico1841678
Total consolidated revenues from external customers$16,226$14,070$9,973
201420132012
Long-lived assets at December 31(a)
U.S.$50,141$42,080$37,651
Canada2,2682,2142,035
Mexico818182
Total consolidated long-lived assets$52,490$44,375$39,768

(a) Long-lived assets exclude goodwill and other intangibles, net.

  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 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, 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. 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 late June of 2014, certain shippers filed additional complaints with the FERC (docketed at OR14-35 and OR14-36) challenging SFPP’s adjustments to its rates in 2012 and 2013 for inflation under the FERC’s indexing regulations. If the shippers are successful in proving these claims or other of their claims, they are entitled to seek reparations (which may reach back up to two years prior to the filing 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 we

may include in our rates. With respect to all of the SFPP proceedings at the FERC, we estimate that the shippers are seeking approximately $20 million in annual rate reductions and approximately $100 million in refunds. However, applying the principles of several recent FERC decisions in SFPP cases, as applicable, to pending cases would result in substantially lower rate reductions and refunds than those sought by the shippers. We do not expect refunds in these cases to have an impact on our dividends to our shareholders.

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) in May 2012. EPNG implemented certain aspects of that decision and believes it has an appropriate reserve related to the findings in Opinion 517. EPNG has sought rehearing on Opinion 517. With respect to the 2010 rate case, the FERC issued its decision (Opinion 528) on October 17, 2013. EPNG sought rehearing on certain issues in Opinion 528. As required by Opinion 528, EPNG filed revised pro forma recalculated rates consistent with the terms of Opinion 528. The FERC also required an Administrative Law Judge (ALJ) to conduct an additional hearing concerning one of the issues in Opinion 528. On September 17, 2014, the ALJ issued an initial decision finding certain shippers qualify for lower rates under a prior settlement. EPNG has sought FERC review of the ALJ decision and believes it has an appropriate reserve related to the findings in Opinion 528.

California Public Utilities Commission Proceedings

We have previously reported ratemaking and complaint proceedings against SFPP pending with the CPUC. The ratemaking and complaint cases generally involve challenges to rates charged by SFPP for intrastate transportation of refined petroleum products through its pipeline system in the state of California and request prospective rate adjustments and refunds with respect to tariffed and previously untariffed charges for certain pipeline transportation and related services.

On October 3, 2014, SFPP and its shippers executed a global settlement resolving all pending CPUC proceedings and submitted the proposed settlement to the CPUC for its consideration and approval. The settlement included refunds in the amount of $319 million, which was consistent with our established reserve amounts. It also included a three year moratorium on new rate filings or complaints and established current rates consistent with the revenues recognized by SFPP in 2014. On December 18, 2014, the CPUC issued its Decision No. 14-12-057 approving and adopting the global settlement, thereby resolving and closing all previously pending SFPP rate proceedings. On December 29, 2014, SFPP certified to the CPUC that it made all required settlement payments. Accordingly, SFPP filed with the CPUC a request to eliminate the previously imposed CPUC requirement that SFPP maintain a letter of credit in the amount of $100 million to secure SFPP’s payment obligation for refunds related to the now-resolved CPUC rate proceedings. A decision from the CPUC is expected in the first quarter of 2015.

Other Commercial Matters

Union Pacific Railroad Company Easements

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. Judgment was entered by the Superior Court on May 29, 2012 and SFPP appealed the judgment.

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 rehearing with the Court of Appeals, which was denied on December 5, 2014. UPRR filed a petition for review to the California Supreme Court, which was denied on January 21, 2015. UPRR is expected to seek further appellate review by the U.S. Supreme Court. We believe we have recorded a right-of-way liability consistent with the Court of Appeals’ decision and sufficient to cover our potential liability for back rent.

By notice dated October 25, 2013, UPRR demanded the payment of $22.25 million in rent for the first year of the next ten-year period beginning January 1, 2014. SFPP rejected the demand and the parties are pursuing the dispute resolution procedure in their contract to determine the rental adjustment, if any, for such period.

SFPP and UPRR are also engaged in multiple disputes over the circumstances under which SFPP must pay for a relocation of its pipeline within the UPRR right-of-way and the safety standards that govern relocations. In July 2006, a trial before a judge regarding the circumstances under which SFPP must pay for relocations concluded, and the judge determined that SFPP must pay for any relocations resulting from any legitimate business purpose of the UPRR. SFPP appealed this decision, and in December 2008, the appellate court affirmed the decision. 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 is seeking declaratory relief with respect to its positions regarding the application of these standards with respect to relocations. A trial occurred in the fourth quarter of 2011, with a verdict having been reached that SFPP was obligated to comply with AREMA standards in connection with a railroad project in Beaumont Hills, California. On June 13, 2014, the trial court issued a statement of decision addressing all of the causes of action and defenses and resolved those matters against SFPP, consistent with the jury’s verdict. The judgment was signed on July 15, 2014. SFPP filed a notice of appeal on October 30, 2014. If the judgment is affirmed on appeal, SFPP will be required to pay a judgment of $42.5 million plus any accrued post judgment interest.

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 expense (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.

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 arises from the sale by TGP of the Cameron System in Louisiana to Kinetica Partners, LLC on September 1, 2013. Plains alleges 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 alleges 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 and disputed its indemnity obligation. We intend to vigorously defend the suit and pursue Kinetica, if necessary, for indemnity and costs of defense.

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, 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 have been consolidated into one proceeding. 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 on the remaining claims. Trial was held in late 2014 and a decision is expected during the first half of 2015. Motions to dismiss have been filed in Brinckerhoff III and Brinckerhoff IV. Defendants continue to believe these lawsuits are without merit and intend to defend against them vigorously.

Allen v. El Paso Pipeline GP Company, L.L.C., et al.

In May 2012, a unitholder of EPB filed a purported class action in Delaware Chancery Court, alleging both derivative and non derivative claims, against EPB, and EPB’s general partner and its board. EPB was named in the lawsuit as both a “Class Defendant” and a “Derivative Nominal Defendant.” The complaint alleges a breach of the duty of good faith and fair dealing in connection with the March 2011 sale to EPB of a 25% ownership interest in SNG. On June 20, 2014, defendants’ motion for summary judgment was granted, dismissing the case in its entirety. Plaintiff filed a notice of appeal to the Delaware Supreme Court, which will hear oral argument on February 25, 2015.

Price Reporting Litigation

Beginning in 2003, several lawsuits were filed against El Paso Marketing L.P. (EPM) alleging that EP, EPM and other energy companies 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 were pending in Nevada federal court, were dismissed, but the dismissal was reversed by the 9th Circuit Court of Appeals. A petition for certiorari was granted by the U.S. Supreme Court. Oral argument was heard on January 12, 2015 and the matter is stayed pending appeal. Although damages in excess of $140 million have been alleged in total against all defendants in one of the remaining lawsuits where a damage number is provided, there remains significant uncertainty regarding the validity of the causes of action, the damages asserted and the level of damages, if any, that may be allocated to us. Therefore, our costs and legal exposure related to the remaining outstanding lawsuits and claims 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 the Merger Transactions, which the Court consolidated under the caption In re Kinder Morgan, Inc. Corporate Reorganization Litigation (Consolidated Case No. 10093-VCL). The plaintiffs originally sought to enjoin one or more of the proposed Merger Transactions, which relief the Court denied on November 5, 2014. On December 12, 2014, the plaintiffs filed a Verified Second Consolidated Amended Class Action Complaint, which purports to assert claims on behalf of both the former EPB unitholders and the former KMP unitholders. The EPB plaintiff alleges 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 allege 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 seeks 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.

The defendants believe the allegations against them lack merit, and they intend to vigorously defend these lawsuits.

Kinder Morgan Energy Partners, L.P. Capex Litigation

Putative class action and derivative complaints were filed in the Court of Chancery in the State of Delaware against defendants KMI, KMGP and nominal defendant KMEP on February 5, 2014 and March 27, 2014 captioned Slotoroff v. Kinder Morgan, Inc., Kinder Morgan G.P., Inc. et al (Case No. 9318) and Burns et al v. Kinder Morgan, Inc., Kinder Morgan G.P., Inc. et al (Case No. 9479) respectively. The cases were consolidated on April 8, 2014 (Consolidated Case No. 9318). The consolidated suit seeks to assert claims both individually and on behalf of a putative class consisting of all public holders of KMEP units during the period of February 5, 2011 through the date of the filing of the complaints. The suit alleges direct and derivative causes of action for breach of the partnership agreement, breach of the duty of good faith and fair dealing, aiding and abetting, and tortious interference. Among other things, the suit alleges that defendants made a bad faith allocation of capital expenditures to expansion capital expenditures rather than maintenance capital expenditures for the alleged purpose of “artificially” inflating KMEP’s distributions and growth rate. The suit seeks disgorgement of any distributions to KMGP, KMI and any related entities, beyond amounts that would have been distributed in accordance with a “good faith” allocation of maintenance capital expenses, together with other unspecified monetary damages including punitive damages and attorney fees. Defendants believe this suit is without merit and intend to defend it vigorously.

Walker v. Kinder Morgan, Inc., Kinder Morgan G.P., Inc. et al

On March 6, 2014, a putative class action and derivative complaint was filed in the District Court of Harris County, Texas (Case No. 2014-11872 in the 215th Judicial District) against KMI, KMGP, KMR, Richard D. Kinder, Steven J. Kean, Ted A. Gardner, Gary L. Hultquist, Perry M. Waughtal and nominal defendant KMEP. The suit was filed by Kenneth Walker, a purported unit holder of KMEP, and alleges derivative causes of action for alleged violation of duties owed under the

partnership agreement, breach of the implied covenant of good faith and fair dealing, “abuse of control” and “gross mismanagement” in connection with the calculation of distributions and allocation of capital expenditures to expansion capital expenditures and maintenance capital expenditures. The suit seeks unspecified money damages, interest, punitive damages, attorney and expert fees, costs and expenses, unspecified equitable relief, and demands a trial by jury. Defendants believe this suit is without merit and intend to defend it vigorously. By agreement of the parties, the case is stayed pending further resolution of the Kinder Morgan Energy Partners, L.P. Capex Litigation described above.

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, 2014 and 2013, our total reserve for legal matters was $400 million and $624 million, respectively. The reserve primarily relates to various claims from regulatory proceedings arising from our products pipeline and natural gas pipeline transportation rates. The overall decrease in the reserve from December 31, 2013 was primarily due to the settlement refunds associated with our SFPP rate proceedings.

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 law 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. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. We do not believe that these alleged violations will have a material adverse effect on our business, financial position, results of operations or dividends to our shareholders.

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. Once the EPA determines the cleanup remedy from the remedial investigations and feasibility studies conducted during the last decade at the site, it will issue a Record of Decision. Currently, KMLT and 90 other parties are involved in an

allocation process to determine each party’s respective share of the cleanup costs. This is a non-judicial allocation process. 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. We expect the allocation process to conclude in 2015. We also expect the LWG to complete the RI/FS process in 2015, after which the EPA is expected to develop a proposed plan leading to a Record of Decision targeted for 2017. We anticipate that the cleanup activities will begin within one year of the issuance of the Record of Decision.

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 against 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. Our motion to dismiss the suit was denied on August 19, 2014 and we have filed an answer to the Second Amended Complaint.

Paulsboro, New Jersey Liquids Terminal Consent Judgment

On June 25, 2007, the New Jersey Department of Environmental Protection (NJDEP) and the Administrator of the New Jersey Spill Compensation Fund, referred to collectively as the plaintiffs, filed a complaint in Gloucester County, New Jersey against ExxonMobil and KMLT, formerly known as GATX Terminals Corporation, alleging natural resource damages related to historic contamination at the Paulsboro, New Jersey liquids terminal owned by ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corporation from 1989 through September 2000, and later owned by Support Terminals and Pacific Atlantic Terminals, LLC. The terminal is now owned by Plains Products, which was also joined as a party to the lawsuit.

In mid 2011, KMLT and Plains Products entered into a settlement agreement and subsequent Consent Judgment with the NJDEP which resolved the state’s alleged natural resource damages claim. The natural resource damage settlement includes a monetary award of $1 million and a series of remediation and restoration activities at the terminal site. KMLT and Plains Products have joint responsibility for this settlement. Simultaneously, KMLT and Plains Products entered into an agreement that settled each party’s relative share of responsibility (50/50) to the NJDEP under the Consent Judgment noted above. The Consent Judgment is now entered with the Court and the settlement is final. According to the agreement, Plains will conduct remediation activities at the site and KMLT will provide oversight and 50% of the costs. We are awaiting approval from the NJDEP in order to begin remediation activities.

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 (Case No. 37-2007-00073033). On September 26, 2007, we removed the case to the U.S. District Court, Southern District of California (Case No. 07CV1883WCAB). The City disclosed in discovery that it is 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, which heard oral argument on February 3, 2015. The appeal remains pending.

This site has been, and currently is, under the regulatory oversight and order of the California Regional Water Quality Control Board (RWQCB). SFPP has completed the soil and groundwater remediation at the City of San Diego’s stadium property site and conducted quarterly sampling and monitoring through 2014 as part of the compliance evaluation required by the RWQCB. SFPP’s remediation effort is now focused on its adjacent Mission Valley Terminal site.

On May 7, 2013, the City of San Diego petitioned the California Superior Court for a writ of mandamus seeking an order setting aside the RWQCB’s approval of an amendment to our permit request to increase the discharge of water from our groundwater treatment system to the City of San Diego’s municipal storm sewer system. On October 10, 2014, the court ruled that the City’s petition was moot and dismissed the case because the amendment to the permit was no longer required and had been rescinded by the RWQCB at the request of SFPP upon SFPP’s completion of soil and groundwater remediation at the City’s stadium property site.

Uranium Mines in Vicinity of Cameron, Arizona

In the 1950s and 1960s, Rare Metals Inc., a historical subsidiary of EPNG, operated 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 will conduct 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.

PHMSA Inspection of Carteret Terminal, Carteret, New Jersey

On April 4, 2013, the PHMSA, Office of Pipeline Safety issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (NOPV) arising from an inspection at the KMLT, Carteret, New Jersey location on March 15, 2011 following a release and fire that occurred during maintenance activity on March 14, 2011. On July 17, 2013, KMLT entered into a Consent Agreement and Order with the PHMSA, pursuant to which KMLT paid a penalty of $63,100 and is required to complete ongoing pipeline integrity testing and other corrective measures by November 30, 2015.

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 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 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 of approximately 70 cooperating parties (CPG) which have entered into AOCs and are directing and funding the work required by the EPA. Under the first AOC, a remedial investigation and feasibility study of the Site is presently estimated to be completed by 2015. Under the second AOC, the CPG members are conducting a CERCLA removal action at the Passaic River Mile 10.9, including the dredging of sediment in mud flats at this location of the river to a depth of two feet and installation of a cap. The dredging was completed in 2013 and capping work was completed in June 2014. 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. In its FFS, the EPA stated that it has identified over 100 industrial facilities as potentially responsible parties and it is likely that there are hundreds more private and public entities that could be named in any litigation concerning responsibility for the Site contamination.

No final remedy for this portion of the Site will be selected until the public comment and response period for the FFS is completed and the Record of Decision (ROD) is issued by EPA, which is expected in September 2015. Until the ROD is issued there is uncertainty about what remedy will be implemented and the extent of potential costs. There is also uncertainty as to the impact of the RI/FS that the CPG is currently preparing for portions of the Site. 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 September 10, 2013, the SLFPA filed a motion to remand the case to the state district court for Orleans Parish. The Court denied the remand motion on June 27, 2014. Louisiana Act 544 (the Act) went into effect on June 6, 2014 and specified the political entities authorized to institute litigation for environmental damage in the coastal zone. Under the Act, which was specifically made retroactive, we contend the SLFPA is not a valid plaintiff, whereas the SLFPA contends the Act is unconstitutional. The parties filed numerous cross motions seeking a ruling on the enforceability of the Act and other potentially dispositive legal issues. On February 13, 2015, the Court granted defendants’ motion to dismiss the suit for failure to state a claim, and issued an order dismissing plaintiffs’ claims with prejudice.

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. On December 18, 2013, defendants removed the case to the U.S. District Court for the Eastern District of Louisiana. On January 14, 2014, the plaintiff filed a motion to remand the case to state court. On August 11, 2014, the court entered an order suspending a ruling on the remand motion and administratively closing the case, pending a ruling on plaintiff’s remand motion in another substantially similar case in the same federal court to which TGP is not a party. On December 1, 2014, the remand motion in the substantially similar case was granted. On February 3, 2015, TGP and other defendants filed a motion to re-open its case for the purpose of further proceedings, including the court’s consideration of whether remand is required. 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 we await Kinetica’s response to TGP’s tender.

Pennsylvania Department of Environmental Protection Notice of Alleged Violations

The Pennsylvania Department of Environmental Protection (PADEP) notified TGP of alleged violations of certain conditions to the construction permits issued to TGP for the construction of TGP’s 300 Line Project in 2011. The alleged violations arise from field inspections performed by county conservation districts, as delegates of the PADEP, during construction. The PADEP alleges that TGP failed to implement and maintain best practices to achieve sufficient erosion and sediment controls, stabilization of the right-of-way, and prevention of potential discharge of sediment into the waters of the Commonwealth of Pennsylvania during construction, before placing the line into service, and in connection with the occurrence of 100 year storm events. On December 22, 2014, TGP entered into a consent order and agreement with the PADEP pursuant to which TGP agreed to pay a civil penalty of $210,000, $50,000 in costs, and $540,000 to fund community environmental programs in Pike, Potter, Susquehanna, and Wayne counties in Pennsylvania to generally improve water quality in such counties and help restore third party dump sites unrelated to TGP’s construction or other activities.

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, 2014 and 2013, we have accrued a total reserve for environmental liabilities in the amount of $340 million and $378 million, respectively. In addition, as of both December 31, 2014 and 2013, we have recorded a receivable of $14 million, for expected cost recoveries that have been deemed probable.

  1. Recent Accounting Pronouncements

Accounting Standards Updates

On May 28, 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” This ASU is designed to create greater comparability for financial statement users across industries and jurisdictions. The provisions of ASU No. 2014-09 include a five-step process by which entities will recognize revenue to depict the transfer of goods or services to customers in amounts that reflect the payment to which an entity expects to be entitled in exchange for those goods or services. The standard also will require enhanced disclosures, provide more comprehensive guidance for transactions such as service revenue and contract modifications, and enhance guidance for multiple-element arrangements. ASU No. 2014-09 will be effective for U.S. public companies for annual reporting periods beginning after December 15, 2016, including interim reporting periods (January 1, 2017 for us). Early adoption is not permitted. We are currently reviewing the effect of ASU No. 2014-09 on our revenue recognition.

  1. Guarantee of Securities of Subsidiaries

KMI, along with its direct and indirect subsidiaries KMP, EPB and Copano, are issuers of certain public debt securities. After the completion of the Merger Transactions, KMI and substantially all of its wholly owned domestic subsidiaries, including KMP, Copano and EPB, entered into 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 Non-Guarantor Subsidiaries, the parent issuer, subsidiary issuers 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, KMP, Copano or EPB are in the same position with respect to the net assets, income and cash flows of KMI and the Subsidiary Issuers 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 each 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 issuers in separate columns in this single set of condensed consolidating financial statements.

Excluding fair value adjustments, as of December 31, 2014, Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, Subsidiary Issuer and Guarantor-Copano, Subsidiary Issuer and Guarantor-EPB and Subsidiary Guarantors had $12,674 million, $17,800 million, $332 million, $2,860 million and $6,463 million of Guaranteed Notes outstanding, respectively. Included in the Subsidiary Guarantors debt balance as presented in the accompanying December 31, 2014 condensed

consolidating balance sheet is approximately $178 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 Issuer and Guarantor-Copano, Subsidiary Issuer and Guarantor-EPB, 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 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 Non-Guarantor Subsidiaries. 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.

Effective November 26, 2014, the KMI Transactions close date, KMR was dissolved and its assets merged into KMI. Therefore, for all periods presented KMR’s financial statement balances and activities are reflected within the Parent Issuer and Guarantor column.

On January 1, 2015, EPB and its subsidiary, EPPOC merged with and into KMP and were dissolved. As a result of such merger, all of the subsidiaries of EPPOC are wholly owned subsidiaries of KMP and effective January 1, 2015, EPPOC is no longer a Subsidiary Issuer and Guarantor.

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 Issuer and Guarantor - CopanoSubsidiary Issuer and Guarantor - EPBSubsidiary GuarantorsSubsidiary Non-GuarantorsConsolidating AdjustmentsConsolidated KMI
Total Revenues$36$—$—$—$14,310$1,886$(6)$16,226
Operating costs, expenses and other
Costs of sales————5,737499426,278
Depreciation, depletion and amortization21———1,655364—2,040
Other operating expenses30—3252,927514(48)3,460
Total operating costs, expenses and other51—32510,3191,377(6)11,778
Operating (loss) income(15)—(32)(5)3,991509—4,448
Other income (expense)
Earnings from consolidated subsidiaries1,9483,2352247422,2591,120(9,528)—
Earnings from equity investments————407(1)—406
Interest, net(493)41(46)(171)(1,040)(89)—(1,798)
Amortization of excess cost of equity investments and other, net————(13)48—35
Income from continuing operations before income taxes1,4403,2761465665,6041,587(9,528)3,091
Income tax expense(166)(7)——(183)(292)—(648)
Net income1,2743,2691465665,4211,295(9,528)2,443
Net income attributable to noncontrolling interests(248)———(211)—(958)(1,417)
Net income attributable to controlling interests$1,026$3,269$146$566$5,210$1,295$(10,486)$1,026
Net Income$1,274$3,269$146$566$5,421$1,295$(9,528)$2,443
Total other comprehensive (loss) income(24)287—(10)386(168)(451)20
Comprehensive income1,2503,5561465565,8071,127(9,979)2,463
Comprehensive income attributable to noncontrolling interests(273)———(203)—(1,010)(1,486)
Comprehensive income attributable to controlling interests$977$3,556$146$556$5,604$1,127$(10,989)$977
Condensed Consolidating Statements of Income and Comprehensive Income for the Year Ended December 31, 2013 (In Millions)
Parent Issuer and GuarantorSubsidiary Issuer and Guarantor - KMPSubsidiary Issuer and Guarantor - CopanoSubsidiary Issuer and Guarantor - EPBSubsidiary GuarantorsSubsidiary Non-GuarantorsConsolidating AdjustmentsConsolidated KMI
Total Revenues$36$—$—$—$12,511$1,512$11$14,070
Operating costs, expenses and other
Costs of sales————4,739468465,253
Depreciation, depletion and amortization20———1,466320—1,806
Other operating expenses22—3882,325663(35)3,021
Total operating costs, expenses and other42—3888,5301,4511110,080
Operating (loss) income(6)—(38)(8)3,98161—3,990
Other income (expense)
Earnings from consolidated subsidiaries2,0253,2511637591,9861,755(9,939)—
Earnings from equity investments————3234—327
Interest, net(539)41(36)(157)(949)(35)—(1,675)
Amortization of excess cost of equity investments and other, net(1)—(1)—549249—796
Income from continuing operations before income taxes1,4793,292885945,8902,034(9,939)3,438
Income tax (expense) benefit(41)(11)——50(740)—(742)
Income from continuing operations1,4383,281885945,9401,294(9,939)2,696
Loss from discontinued operations————(4)——(4)
Net income1,4383,281885945,9361,294(9,939)2,692
Net income attributable to noncontrolling interests(245)———(236)—(1,018)(1,499)
Net income attributable to controlling interests$1,193$3,281$88$594$5,700$1,294$(10,957)$1,193
Net Income$1,438$3,281$88$594$5,936$1,294$(9,939)$2,692
Total other comprehensive income (loss)81(135)——(145)(172)41140
Comprehensive income1,5193,146885945,7911,122(9,528)2,732
Comprehensive income attributable to noncontrolling interests(232)———(237)—(976)(1,445)
Comprehensive income attributable to controlling interests$1,287$3,146$88$594$5,554$1,122$(10,504)$1,287
Condensed Consolidating Statements of Income and Comprehensive Income for the Year Ended December 31, 2012 (In Millions)
Parent Issuer and GuarantorSubsidiary Issuer and Guarantor - KMPSubsidiary Issuer and Guarantor - CopanoSubsidiary Issuer and Guarantor - EPBSubsidiary GuarantorsSubsidiary Non-GuarantorsConsolidating AdjustmentsConsolidated KMI
Total Revenues$35$—$—$—$8,651$1,265$22$9,973
Operating costs, expenses and other
Costs of sales————2,761271253,057
Depreciation, depletion and amortization19———1,091309—1,419
Other operating expenses295——22,172438(3)2,904
Total operating costs, expenses and other314——26,0241,018227,380
Operating (loss) income(279)——(2)2,627247—2,593
Other income (expense)
Earnings from consolidated subsidiaries8421,351—4368151,466(4,910)—
Earnings from equity investments————206(53)—153
Interest, net(630)41—(69)(757)16—(1,399)
Amortization of excess cost of equity investments and other, net(1)———(21)18—(4)
(Loss) income from continuing operations before income taxes(68)1,392—3652,8701,694(4,910)1,343
Income tax benefit (expense)392(9)——98(620)—(139)
Income from continuing operations3241,383—3652,9681,074(4,910)1,204
Loss from discontinued operations(14)———(2)(761)—(777)
Net income3101,383—3652,966313(4,910)427
Net loss (income) attributable to noncontrolling interests5———(168)—51(112)
Net income attributable to controlling interests$315$1,383$—$365$2,798$313$(4,859)$315
Net Income$310$1,383$—$365$2,966$313$(4,910)$427
Total other comprehensive income12165—1020096(412)71
Comprehensive income3221,548—3753,166409(5,322)498
Comprehensive income attributable to noncontrolling interests(10)———(174)—(2)(186)
Comprehensive income attributable to controlling interests$312$1,548$—$375$2,992$409$(5,324)$312
Condensed Consolidating Balance Sheets as of December 31, 2014 (In Millions)
Parent Issuer and GuarantorSubsidiary Issuer and Guarantor - KMPSubsidiary Issuer and Guarantor - CopanoSubsidiary Issuer and Guarantor - EPBSubsidiary GuarantorsSubsidiary Non-GuarantorsConsolidating AdjustmentsConsolidated KMI
ASSETS
Cash and cash equivalents$4$15$—$—$17$279$—$315
Other current assets - affiliates1,8701,33211111,575403(15,192)—
All other current assets397151312,547358(20)3,437
Property, plant and equipment, net263—5—29,4908,806—38,564
Investments16——15,910109—6,036
Investments in subsidiaries31,36427,2641,9116,15016,3873,337(86,413)—
Goodwill15,087—920225,4193,206—24,654
Notes receivable from affiliates4,45919,824—83,621496(28,408)—
Deferred tax assets————9,251—(3,600)5,651
Other non-current assets287341—193,782112—4,541
Total assets$53,747$48,927$2,850$6,202$87,999$17,106$(133,633)$83,198
LIABILITIES AND STOCKHOLDERS’ EQUITY
Liabilities
Current portion of debt$1,486$324$—$375$381$151$—$2,717
Other current liabilities - affiliates70911,926115231,553866(15,192)—
All other current liabilities31846312341,8141,024(20)3,645
Long-term debt11,86218,1973862,4786,609714—40,246
Notes payable to affiliates2,6191537531,20622,4371,240(28,408)—
Deferred income taxes2,094—2——1,504(3,600)—
All other long-term liabilities and deferred credits583782—987514—2,164
Total liabilities19,67131,1411,2704,11633,7816,013(47,220)48,772
Stockholders’ equity
Total KMI equity34,07617,7861,5802,08654,21811,093(86,763)34,076
Noncontrolling interests——————350350
Total stockholders’ equity34,07617,7861,5802,08654,21811,093(86,413)34,426
Total liabilities and stockholders’ equity$53,747$48,927$2,850$6,202$87,999$17,106$(133,633)$83,198
Condensed Consolidating Balance Sheets as of December 31, 2013 (In Millions)
Parent Issuer and GuarantorSubsidiary Issuer and Guarantor - KMPSubsidiary Issuer and Guarantor - CopanoSubsidiary Issuer and Guarantor - EPBSubsidiary GuarantorsSubsidiary Non-GuarantorsConsolidating AdjustmentsConsolidated KMI
ASSETS
Cash and cash equivalents$83$10$1$78$17$409$—$598
Other current assets - affiliates287751—1810,992220(12,268)—
All other current assets6571362—2,184302(11)3,270
Property, plant and equipment, net284—170—26,6988,695—35,847
Investments17———5,822112—5,951
Investments in subsidiaries13,61826,5554,4304,4453,5843,839(56,471)—
Goodwill15,099—813225,3173,253—24,504
Notes receivable from affiliates—17,284——3,087511(20,882)—
Other non-current assets455233—203,866441—5,015
Total assets$30,500$44,969$5,416$4,583$61,567$17,782$(89,632)$75,185
LIABILITIES AND STOCKHOLDERS’ EQUITY
Liabilities
Current portion of debt$575$1,504$—$—$77$150$—$2,306
Other current liabilities - affiliates37910,4535519823539(12,268)—
All other current liabilities7239441301,7281,515(11)3,769
Long-term debt7,77515,6443932,2537,101721—33,887
Notes payable to affiliates1,993—9071,14315,5991,240(20,882)—
Deferred income taxes2,022—2—1,1421,485—4,651
Other long-term liabilities and deferred credits384173——1,023707—2,287
Total liabilities13,20028,1681,3983,44527,4936,357(33,161)46,900
Stockholders’ equity
Total KMI equity13,09316,8014,0181,13831,02511,478(64,460)13,093
Noncontrolling interests4,207———3,049(53)7,98915,192
Total stockholders’ equity17,30016,8014,0181,13834,07411,425(56,471)28,285
Total liabilities and stockholders’ equity$30,500$44,969$5,416$4,583$61,567$17,782$(89,632)$75,185
Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2014 (In Millions)
Parent Issuer and GuarantorSubsidiary Issuer and Guarantor - KMPSubsidiary Issuer and Guarantor - CopanoSubsidiary Issuer and Guarantor - EPBSubsidiary GuarantorsSubsidiary Non-GuarantorsConsolidating AdjustmentsConsolidated KMI
Net cash provided by (used in) operating activities$1,426$3,998$(77)$885$6,345$1,174$(9,284)$4,467
Cash flows from investing activities
Funding to affiliates(1,756)(6,559)—(1,252)(4,706)(1,088)15,361—
Capital expenditures(1)—(63)—(3,050)(705)202(3,617)
Sale, casualty and transfer of property, plant and equipment, investments and other net assets, net of removal costs——202—(9)14(202)5
Contributions to investments———(189)(594)—394(389)
Investments in KMP and EPB(550)—————550—
Acquisitions of assets and investments————(1,370)(18)—(1,388)
Drop down assets to EPB875———(875)———
Distributions from equity investments in excess of cumulative earnings93——440183—(534)182
Other, net—29——27(60)1(3)
Net cash (used in) provided by investing activities(1,339)(6,530)139(1,001)(10,394)(1,857)15,772(5,210)
Cash flows from financing activities
Issuance of debt10,59413,057—922———24,573
Payment of debt(5,479)(11,849)—(322)(142)(9)—(17,801)
Funding from (to) affiliates7563,823(63)7869,138921(15,361)—
Debt issuance costs(74)(11)—(4)———(89)
Cash dividends(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)
Contributions from parents—1,178—2051,26764(2,714)—
Contributions from noncontrolling interests——————1,7671,767
Distributions to parents—(3,660)—(1,549)(6,213)(411)11,833—
Distributions to noncontrolling interests——————(2,013)(2,013)
Other, net—(1)——(2)——(3)
Net cash (used in) provided by financing activities(166)2,537(63)384,048565(6,488)471
Effect of exchange rate changes on cash and cash equivalents————1(12)—(11)
Net (decrease) increase in cash and cash equivalents(79)5(1)(78)—(130)—(283)
Cash and cash equivalents, beginning of period831017817409—598
Cash and cash equivalents, end of period$4$15$—$—$17$279$—$315
Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2013 (In Millions)
Parent Issuer and GuarantorSubsidiary Issuer and Guarantor - KMPSubsidiary Issuer and Guarantor - CopanoSubsidiary Issuer and Guarantor - EPBSubsidiary GuarantorsSubsidiary Non-GuarantorsConsolidating AdjustmentsConsolidated KMI
Net cash provided by (used in) operating activities$1,775$4,173$(408)$64$5,491$769$(7,742)$4,122
Cash flows from investing activities
Funding to affiliates(402)(7,145)(1)(661)(4,270)(1,332)13,811—
Capital expenditures(6)—(141)—(2,418)(804)—(3,369)
Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs————87——87
Proceeds from sale of assets and investments————118372—490
Contributions to investments(6)——(52)(218)—59(217)
Investments in KMP and EPB(68)—————68—
Acquisitions of assets and investments——5—(297)——(292)
Drop down assets to KMP994———(994)———
Distributions from equity investments in excess of cumulative earnings41——296183—(335)185
Other, net—(12)——18(12)—(6)
Net cash provided by (used in) investing activities553(7,157)(137)(417)(7,791)(1,776)13,603(3,122)
Cash flows from financing activities
Issuance of debt3,02810,213—8714239—13,581
Payment of debt(3,624)(7,627)(854)(175)(106)(7)—(12,393)
Funding from affiliates5761,9711,4001,3327,740792(13,811)—
Debt issuance costs(15)(22)———(1)—(38)
Cash dividends(1,622)——————(1,622)
Repurchases of shares and warrants(637)——————(637)
Contributions from parents—1,533—1162132(1,828)—
Contributions from noncontrolling interests——————1,7061,706
Distributions to parents—(3,168)—(924)(5,522)(150)9,764—
Distributions to noncontrolling interests——————(1,692)(1,692)
Other, net1(1)——————
Net cash (used in) provided by financing activities(2,293)2,8995463212,2881,005(5,861)(1,095)
Effect of exchange rate changes on cash and cash equivalents————1(22)—(21)
Net increase (decrease) in cash and cash equivalents35(85)1(32)(11)(24)—(116)
Cash and cash equivalents, beginning of period4895—11028433—714
Cash and cash equivalents, end of period$83$10$1$78$17$409$—$598
Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2012 (In Millions)
Parent Issuer and GuarantorSubsidiary Issuer and Guarantor - KMPSubsidiary Issuer and Guarantor - CopanoSubsidiary Issuer and Guarantor - EPBSubsidiary GuarantorsSubsidiary Non-GuarantorsConsolidating AdjustmentsConsolidated KMI
Net cash provided by (used in) operating activities$657$3,867$—$(151)$3,095$941$(5,601)$2,808
Cash flows from investing activities
Funding (to) from affiliates(857)(5,521)—42(3,515)(1,448)11,299—
Capital expenditures(5)———(1,423)(594)—(2,022)
Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs————6490—154
Acquisition of EP(5,212)817091—(4,970)
Contributions to investments(15)——(454)(206)—483(192)
Investments in KMP and EPB(94)—————94—
Acquisitions of assets and investments————(83)——(83)
Drop down assets to KMP3,485———(3,485)———
Distributions from equity investments in excess of cumulative earnings16——106184—(106)200
Proceeds from disposal of discontinued operations————1,791——1,791
Other, net—(15)——121(81)—25
Net cash used in investing activities(2,682)(5,536)—(225)(6,482)(1,942)11,770(5,097)
Cash flows from financing activities
Issuance of debt8,0019,270—658—219—18,148
Payment of debt(5,692)(8,003)—(855)(205)——(14,755)
Funding from affiliates1,2681,360—1,0496,6121,010(11,299)—
Debt issuance costs(91)(16)—(4)———(111)
Cash dividends(1,184)——————(1,184)
Repurchases of shares and warrants(157)——————(157)
Contributions from parents—1,681—2976330(2,503)—
Contributions from noncontrolling interests——————1,9391,939
Distributions to parents—(2,528)—(391)(3,763)(231)6,913—
Distributions to noncontrolling interests——————(1,219)(1,219)
Other, net(74)(1)——(2)——(77)
Net cash provided by financing activities2,0711,763—4863,4051,028(6,169)2,584
Effect of exchange rate changes on cash and cash equivalents—————8—8
Net increase in cash and cash equivalents4694—1101835—303
Cash and cash equivalents, beginning of period21——10398—411
Cash and cash equivalents, end of period$48$95$—$110$28$433$—$714
Supplemental Selected Quarterly Financial Data (Unaudited)
Quarters Ended
March 31June 30September 30December 31
(In millions, except per share amounts)
2014
Revenues$4,047$3,937$4,291$3,951
Operating Income1,1471,0131,332956
Net Income601497779566
Net Income Attributable to Kinder Morgan, Inc.287284329126
Basic and Diluted Earnings Per Common Share0.280.270.320.08
2013
Revenues$3,060$3,382$3,756$3,872
Operating Income1,0177721,0411,160
Net Income656781551704
Net Income Attributable to Kinder Morgan, Inc.292277286338
Basic and Diluted Earnings Per Common Share0.280.270.270.33

Supplemental Information on Oil and Gas Producing Activities (Unaudited)

Operating statistics from our oil and gas producing activities for each of the years ended December 31, 2014, 2013 and 2012 are shown in the following table:

Results of Operations for Oil and Gas Producing Activities – Unit Prices and Costs
Year Ended December 31,
201420132012
Consolidated Companies(a)
Production costs per barrel of oil equivalent(b)(c)(d)$20.55$18.81$16.44
Crude oil production (MBbl/d)40.837.635.0
SACROC crude oil production (MBbl/d)27.625.524.1
Yates crude oil production (MBbl/d)8.89.09.3
NGL production (MBbl/d)(d)4.24.13.9
NGL production from gas plants(MBbl/d)(e)5.95.85.6
Total NGL production(MBbl/d)10.19.99.5
SACROC NGL production (MBbl/d)(d)3.93.83.7
Yates NGL production (MBbl/d)(d)0.20.20.2
Natural gas production (MMcf/d)(d)(f)1.01.11.2
Natural gas production from gas plants(MMcf/d)(e)(f)1.21.70.7
Total natural gas production(MMcf/d)(f)2.22.81.9
Yates natural gas production (MMcf/d)(d)(f)1.01.11.1
Average sales prices including hedge gains/losses:
Crude oil price per Bbl(g)$88.41$92.70$87.72
NGL price per Bbl(d)(g)$42.61$46.11$51.79
Natural gas price per Mcf(d)(h)$4.04$3.23$2.58
Total NGL price per Bbl(e)$41.87$46.43$50.95
Total natural gas price per Mcf(e)$3.91$3.21$2.72
Average sales prices excluding hedge gains/losses:
Crude oil price per Bbl(g)$86.48$94.94$89.91
NGL price per Bbl(g)$42.61$46.11$51.79
Natural gas price per Mcf(h)$4.04$3.23$2.58
(a)Amounts relate to KMCO2 and its consolidated subsidiaries.
(b)Computed using production costs, excluding transportation costs, as defined by the SEC. Natural gas volumes were converted to barrels of oil equivalent using a conversion factor of six Mcf of natural gas to one barrel of oil.
(c)Production costs include labor, repairs and maintenance, materials, supplies, fuel and power, and general and administrative expenses directly related to oil and gas producing activities.
(d)Includes only production attributable to leasehold ownership.
(e)Includes production attributable to our ownership in processing plants and third party processing agreements.
(f)Excludes natural gas production used as fuel.
(g)Hedge gains/losses for crude oil and NGL are included with crude oil.
(h)Natural gas sales were not hedged.

The following three tables provide supplemental information on oil and gas producing activities, including (i) capitalized costs related to oil and gas producing activities; (ii) costs incurred for the acquisition of oil and gas producing properties and for exploration and development activities; and (iii) the results of operations from oil and gas producing activities.

Our capitalized costs consisted of the following (in millions):

Capitalized Costs Related to Oil and Gas Producing Activities
As of December 31,
201420132012
Consolidated Companies(a)
Wells and equipment, facilities and other$4,937$4,432$3,927
Leasehold658660428
Total proved oil and gas properties5,5955,0924,355
Unproved property(b)103388
Accumulated depreciation and depletion(c)(4,226)(3,520)(3,072)
Net capitalized costs$1,472$1,610$1,291
(a)Amounts relate to KMCO2 and its consolidated subsidiaries. Includes capitalized asset retirement costs and associated accumulated depreciation.
(b)As of December 31, 2014, capitalized costs related to the unproved property for the Residual Oil Zone (ROZ) unproved exploration property was $100 million and other miscellaneous unproved property was $3 million.
(c)2014 amount includes an impairment charge of $234 million on the Katz Strawn unit and $1 million on other miscellaneous property.

For each of the years ended December 31, 2014 , 2013 and 2012, our costs incurred for property acquisition, development and exploration were as follows (in millions):

Costs Incurred in Exploration, Property Acquisitions and Development
Year Ended December 31,
201420132012
Consolidated Companies
Acquisitions(a)$—$285$—
Development(b)481471310
Exploration(c)9511—
(a)Acquisition of Goldsmith Landreth San Andres Unit effective June 1, 2013.
(b)Amounts relate to KMCO2 and its consolidated subsidiaries.
(c)Amounts relate to exploration wells drilled in the Residual Oil Zone (ROZ) for $87 million and the Yates Wolfcamp for $8 million.

Our results of operations from oil and gas producing activities for each of the years ended December 31, 2014, 2013 and 2012 are shown in the following table (in millions):

Results of Operations for Oil and Gas Producing Activities
Year Ended December 31,
201420132012
Consolidated Companies(a)
Revenues(b)$1,412$1,376$1,235
Expenses:
Production costs403344288
Other operating expenses(c)999577
Exploration expense(d)8——
Impairment(e)235——
DD&A expenses430415387
Total expenses1,175854752
Results of operations for oil and gas producing activities$237$522$483
(a)Amounts relate to KMCO2 and its consolidated subsidiaries.
(b)Revenues include a gain attributable to our hedging contracts of $28 million, for the year ended December 31, 2014 and losses of $31 million and $28 million for each of the years, 2013 and 2012, respectively.
(c)Consists primarily of CO2 expense.
(d)Exploration charge for Yates Wolfcamp.
(e)Impairment charge of $234 million on the Katz Strawn unit and $1 million on other miscellaneous property.

Supplemental information is also provided for the following three items (i) estimated quantities of proved oil and gas reserves; (ii) the standardized measure of discounted future net cash flows associated with proved oil and gas reserves; and (iii) a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil and gas reserves.

The technical persons responsible for preparing the reserves estimates presented in this Supplemental Information meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the standards pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. They are independent petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in our oil and gas properties; and we do not employ them on a contingent basis.

The reserves estimates shown herein have been independently evaluated by Netherland, Sewell & Associates, Inc. (NSAI), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Derek Newton and Mr. Mike Norton. Mr. Newton, a Licensed Professional

Engineer in the State of Texas (No. 97689), has been practicing consulting petroleum engineering at NSAI since 1997 and has over 14 years of prior industry experience. He graduated from University College, Cardiff, Wales, in 1983 with a Bachelor of Science Degree in Mechanical Engineering and from Strathclyde University, Scotland, in 1986 with a Master of Science Degree in Petroleum Engineering. Mr. Norton, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1989 and has over 10 years of prior industry experience. He graduated from Texas A&M University in 1978 with a Bachelor of Science Degree in Geology. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Our employee who is primarily responsible for overseeing NSAI’s preparation of the reserves estimates is a registered Professional Engineer in the states of Texas and Kansas with a Doctorate of Engineering from the University of Kansas. He is a member of the Society of Petroleum Engineers and has over 30 years of professional engineering experience. We believe the geologic and engineering data examined provides reasonable assurance that the proved reserves are recoverable in future years

from known reservoirs under existing economic and operating conditions. Estimates of proved reserves are subject to change, either positively or negatively, as additional information become available and contractual and economic conditions change.

Furthermore, our management is responsible for establishing and maintaining adequate internal control over financial reporting, which includes the estimation of our oil and gas reserves. We maintain internal controls and guidance to ensure the reliability of our crude oil, NGL and natural gas reserves estimations, as follows:

•no employee’s compensation is tied to the amount of recorded reserves;
•we follow comprehensive SEC compliant internal policies to determine and report proved reserves, and our reserve estimates are made by experienced oil and gas reservoir engineers or under their direct supervision;
•we review our reported proved reserves at each year-end, and at each year-end, the CO2 business segment managers and the Vice President (President, CO2) review all significant reserves changes and all new proved developed and undeveloped reserves additions; and
•the CO2 business segment reports independently of our five remaining reportable business segments.

For more information on our controls and procedures, see Item 9A “Controls and Procedures-Management’s Report on Internal Control Over Financial Reporting” included in our Annual Report on Form 10-K for the year ended December 31, 2014.

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and NGL which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, that is, current prices and costs calculated as of the date the estimate is made. Pricing is applied based upon the twelve month unweighted arithmetic average of the first day of the month price for the year. Future development and production costs are determined based upon actual cost at year-end. Proved developed reserves are the quantities of crude oil, NGL and natural gas expected to be recovered through existing investments in wells and field infrastructure under current operating conditions. Proved undeveloped reserves require additional investments in wells and related infrastructure in order to recover the production.

As of December 31, 2012, we had 53.0 MMBbl of crude oil and 2.4 MMBbl of NGL classified as proved developed reserves. Also, as of year end 2012, we had 28.9 MMBbl of crude oil and 3.5 MMBbl of NGL classified as proved undeveloped reserves. Total proved reserves as of December 31, 2012, were 82.0 MMBbl of crude oil and 6.0 MMBbl of NGL.

During 2013, production from the fields totaled 13.7 MMBbl of crude oil and 1.5 MMBbl of NGL. For 2013, we incurred $452 million in capital costs, and this capital investment resulted in the development of 11.0 MMBbl of crude oil and 1.3 MMBbl of NGL and their transfer from the proved undeveloped category to the proved developed category. During 2013, we acquired the Goldsmith Landreth San Andres Field Unit which increased proved developed reserves by 15.5 MMBbl of crude oil and 3.9 MMBbl of NGL. The reclassifications from proved undeveloped to proved developed reserves reflect the transfer of 38.1% of crude oil and 37.5% of NGL from the proved undeveloped reserves reported as of December 31, 2012 to the proved developed classification of reserves reported as of December 31, 2013. The developed reserves for the Goldsmith Landreth San Andres Field Unit represent 25.9% of proved developed reserves.

Also during 2013, previous estimates of proved developed reserves were revised upward by 1.7 MMBbl of crude oil and 0.6 MMBbl of NGL, and proved undeveloped reserves were revised downward by 4.3 MMBbl of crude oil and 0.65 MMBbl of NGL. These revisions are mainly attributed to the elimination of uneconomic proved developed nonproducing reserves and proved undeveloped reserves in Katz due to higher operating costs. The proved developed reserves for Katz represent 6.3% of proved developed reserves.

These revisions to our previous estimates, as well as the transfer of proved undeveloped reserves to the proved developed category as discussed above, resulted in the percentage of proved undeveloped reserves increasing from 36.4% at year end 2012 to 39.0% at year end 2013. After giving effect to production and revisions to previous estimates during 2013, total proved reserves of crude oil increased by 25.1 MMBbl and total proved reserves of NGL increased by 8.8 MMBbl.

As of December 31, 2013, we had 67.4 MMBbl of crude oil and 6.7 MMBbl of NGL classified as proved developed reserves. Also, as of year end 2013, we had 39.6 MMBbl of crude oil and 8.0 MMBbl of NGL classified as proved undeveloped reserves. Total proved reserves as of December 31, 2013, were 107.0 MMBbl of crude oil and 14.8 MMBbl of NGL.

During 2014, production from the fields totaled 14.8 MMBbl of crude oil and 1.5 MMBbl of NGL. For 2014, we incurred $502 million in capital costs, and this capital investment resulted in the development of 5.7 MMBbl of crude oil and their

transfer from the proved undeveloped category to the proved developed category. The reclassifications from proved undeveloped to proved developed reserves reflect the transfer of 14.5% of crude oil from the proved undeveloped reserves reported as of December 31, 2013 to the proved developed classification of reserves reported as of December 31, 2014. Revisions to previous transfers of NGL’s resulted a downward revision of 0.1 MMBbl for NGL‘s in the proved developed category that have been reclassified to the proved undeveloped category as of December 31, 2014. This reclassification reflects the transfer of 1.8% of proved developed NGL’s reported as of December 31, 2013 to the proved undeveloped classification of reserves reported as of December 31, 2014.

Also during 2014, previous estimates of proved developed reserves were revised upward by 2.0 MMBbl of crude oil and downward 0.5 MMBbl of NGL, and proved undeveloped reserves were revised upward by 3.4 MMBbl of crude oil and downward 1.9 MMBbl of NGL. These revisions are mainly attributed to the addition of projects and the use of higher projected oil recoveries resulting from updated performance at SACROC used to calculate reserves. The proved developed reserves for SACROC represent 32.5% of proved developed reserves. The Katz Strawn Unit also received an addition of proved developed nonproducing reserves volumes. The proved developed reserves for Katz Strawn Unit represent 12.3% of proved developed reserves. Contrarily, there was also a decrease of proved developed producing reserves and proved undeveloped reserves in Goldsmith due to higher operating costs and lower well performance. The proved developed reserves for Goldsmith represent 13.4% of proved developed reserves.

These revisions to our previous estimates, as well as the transfer of proved undeveloped reserves to the proved developed category as discussed above, resulted in the percentage of proved undeveloped reserves increasing from 39.0% at year end 2013 to 40.0% at year end 2014. After giving effect to production and revisions to previous estimates during 2014, total proved reserves of crude oil decreased by 9.5 MMBbl and total proved reserves of NGL decreased by 4.0 MMBbl.

As of December 31, 2014, we had 60.3 MMBbl of crude oil and 4.6 MMBbl of NGL classified as proved developed reserves. Also, as of year end 2014, we had 37.3 MMBbl of crude oil and 6.2 MMBbl of NGL classified as proved undeveloped reserves. Total proved reserves as of December 31, 2014, were 97.6 MMBbl of crude oil and 10.8 MMBbl of NGL. We currently expect that the proved undeveloped reserves we report as of December 31, 2014 will be developed within the next five years.

During 2014, we filed estimates of our oil and gas reserves for the year 2013 with the Energy Information Administration of the U. S. Department of Energy on Form EIA-23. The data on Form EIA-23 was presented on a different basis, and included 100% of the oil and gas volumes from our operated properties only, regardless of our net interest. The difference between the oil and gas reserves reported on Form EIA-23 and those reported in this Supplemental Information exceeds 5%.

The following Reserve Quantity Information table discloses estimates, as of December 31, 2014, of proved crude oil, NGL and natural gas reserves, prepared by Netherland, Sewell & Associates, Inc. (independent oil and gas consultants), of KMCO2 and its consolidated subsidiaries’ interests in oil and gas properties, all of which are located in the state of Texas. This data has been prepared using current prices and costs, as discussed above, and the estimates of reserves and future revenues in this Supplemental Information conform to the guidelines of the SEC.

Reserve Quantity Information
Consolidated Companies(a)
Crude Oil (MBbl)NGL (MBbl)Natural Gas (MMcf)(b)
Proved developed and undeveloped reserves:
As of December 31, 201179,4474,1453,241
Revisions of previous estimates(c)15,5403,2854,881
Extensions and discoveries26——
Sales of reserves in place(239)(38)(143)
Production(12,824)(1,416)(440)
As of December 31, 201281,9505,9767,539
Revisions of previous estimates(d)(2,573)(43)(5,063)
Purchases of reserves in place(e)41,38910,347—
Production(13,735)(1,499)(406)
As of December 31, 2013107,03114,7812,070
Revisions of previous estimates(f)5,378(2,419)372
Production(14,852)(1,542)(373)
As of December 31, 201497,55710,8202,069
Proved developed reserves:
As of December 31, 201253,0062,4337,539
As of December 31, 201367,4366,7332,070
As of December 31, 201460,2524,5842,069
Proved undeveloped reserves:
As of December 31, 201228,9443,543—
As of December 31, 201339,5958,048—
As of December 31, 201437,3056,236—
(a)Amounts relate to KMCO2 and its consolidated subsidiaries.
(b)Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.
(c)Predominantly due to higher CO2 flood recoveries based on updated performance at the SACROC Unit.
(d)Predominantly due to higher operating costs at the Katz Strawn Unit.
(e)Represents volumes added with acquisition of the Goldsmith Landreth San Andres Unit in June 2013.
(f)Predominately due to the addition of projects and redefined original oil in place values at SACROC, the addition of proved developed nonproducing reserves volumes in the Katz Strawn Unit offset by decreased expected oil recoveries in the Goldsmith Landreth San Andres Unit based on higher operating costs and lower well performance.

The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year-to-year are prepared in accordance with the “Extractive Activities—Oil and Gas” Topic of the Codification. The assumptions that underly the computation of the standardized measure of discounted cash flows, presented in the table below, may be summarized as follows:

•the standardized measure includes our estimate of proved crude oil, NGL and natural gas reserves and projected future production volumes based upon year-end economic conditions;
•pricing is applied based upon the 12 month unweighted arithmetic average of the first day of the month price for the year;
•future development and production costs are determined based upon actual cost at year-end;
•the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and
•a discount factor of 10% per year is applied annually to the future net cash flows.

The standardized measure of discounted future net cash flows from proved reserves were as follows (in millions):

Standardized Measure of Discounted Future Net Cash Flows From Proved Oil and Gas Reserves
As of December 31,
201420132012
Consolidated Companies(a)
Future cash inflows from production$9,406$10,945$7,807
Future production costs(4,294)(4,214)(2,923)
Future development costs(b)(2,113)(1,948)(1,011)
Undiscounted future net cash flows2,9994,7833,873
10% annual discount(1,089)(2,096)(1,168)
Standardized measure of discounted future net cash flows(c)$1,910$2,687$2,705
(a)Amounts relate to KMCO2 and its consolidated subsidiaries.
(b)Includes abandonment costs.
(c)Standardized Measure of discounted future net cash flows as of December 31, 2013 includes $843 million attributable to the Goldsmith Landreth San Andres Unit acquired in June 2013.

The following table represents our estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in millions):

Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Oil and Gas Reserves
As of December 31,
201420132012
Consolidated Companies(a)
Present value as of January 1$2,687$2,705$2,194
Changes during the year:
Revenues less production and other costs(b)(880)(965)(895)
Net changes in prices, production and other costs(504)258(88)
Development costs incurred502452353
Net changes in future development costs(479)(629)64
Improved recovery———
Extensions and discoveries(c)——5
Sales of reserves in place(d)——(5)
Revisions of previous quantity estimates(e)329(114)871
Purchase of reserves in place(f)—683—
Accretion of discount255297206
Net change for the year(777)(18)511
Present value as of December 31$1,910$2,687$2,705
(a)Amounts relate to KMCO2 and its consolidated subsidiaries.
(b)Excludes a gain attributable to our hedging contracts of $28 million for the year ended December 31, 2014 and losses of $31 million and $28 million for the years 2013 and 2012, respectively.
(c)Primarily due to the extension of the SACROC unit.
(d)Sale of the Claytonville field unit.
(e)2014 revisions were primarily due to, increases due to the addition of projects and redefined original oil in place values at SACROC, additional proved developed nonproducing reserves volumes in the Katz Strawn Unit offset by decreased oil recoveries and higher operating costs for the Goldsmith Landreth San Andres Unit. 2013 revisions were primarily due to increased operating costs at the Katz Strawn Unit. 2012 revisions were primarily due to higher projected CO2 flood recoveries resulting from updated performance at SACROC and the addition of proved undeveloped reserve volumes at the Katz Strawn Unit CO2 flood.
(f)Acquisition of the Goldsmith Landreth San Andres Unit in June 2013.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

KINDER MORGAN, INC. Registrant
By: /s/ KIMBERLY A. DANG
Kimberly A. Dang Vice President and Chief Financial Officer (principal financial and accounting officer)
Date:February 23, 2015

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.

SignatureTitleDate
/s/ KIMBERLY A. DANGVice President and Chief Financial Officer (principal financial officer and principal accounting officer)February 23, 2015
Kimberly A. Dang
/s/ RICHARD D. KINDERDirector, Chairman and Chief Executive Officer (principal executive officer)February 23, 2015
Richard D. Kinder
/s/ TED A. GARDNERDirectorFebruary 23, 2015
Ted A. Gardner
/s/ ANTHONY W. HALL, JR.DirectorFebruary 23, 2015
Anthony W. Hall, Jr.
/s/ GARY L. HULTQUISTDirectorFebruary 23, 2015
Gary L. Hultquist
/s/ STEVEN J. KEANDirectorFebruary 23, 2015
Steven J. Kean
/s/ RONALD L. KUEHN, JR.DirectorFebruary 23, 2015
Ronald L. Kuehn, Jr.
/s/ DEBORAH A. MACDONALDDirectorFebruary 23, 2015
Deborah A. Macdonald
/s/ MICHAEL J. MILLERDirectorFebruary 23, 2015
Michael J. Miller
/s/ MICHAEL C. MORGANDirectorFebruary 23, 2015
Michael C. Morgan
/s/ ARTHUR C. REICHSTETTERDirectorFebruary 23, 2015
Arthur C. Reichstetter
/s/ FAYEZ SAROFIMDirectorFebruary 23, 2015
Fayez Sarofim
/s/ C. PARK SHAPERDirectorFebruary 23, 2015
C. Park Shaper
/s/ WILLIAM A. SMITHDirectorFebruary 23, 2015
William A. Smith
/s/ JOEL V. STAFFDirectorFebruary 23, 2015
Joel V. Staff
/s/ ROBERT F. VAGTDirectorFebruary 23, 2015
Robert F. Vagt
/s/ PERRY M. WAUGHTALDirectorFebruary 23, 2015
Perry M. Waughtal

Previous: Item 14. Principal Accounting Fees and Services.