Kinder Morgan
Annual Report 2014

Plain-text annual report

Table of Contents UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 _____________ Form 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2014 or [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _____to_____ Commission file number: 001-35081 Kinder Morgan, Inc. (Exact name of registrant as specified in its charter) Delaware (State or other jurisdiction of incorporation or organization) 80-0682103 (I.R.S. Employer Identification No.) 1001 Louisiana Street, Suite 1000, Houston, Texas 77002 (Address of principal executive offices) (zip code) Registrant’s telephone number, including area code: 713-369-9000 ____________ Securities registered pursuant to Section 12(b) of the Act: Title of each class Class P Common Stock Warrants to Purchase Class P Common Stock Name of each exchange on which registered New York Stock Exchange New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933. Yes No Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934. Yes No Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes No Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K(§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Large accelerated filer Accelerated filer Non-accelerated filer Smaller reporting company Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes No Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on closing prices in the daily composite list for transactions on the New York Stock Exchange on June 30, 2014 was approximately $24,279,037,627. As of February 2, 2015, the registrant had 2,130,052,022 Class P shares outstanding. Table of Contents KINDER MORGAN, INC. AND SUBSIDIARIES TABLE OF CONTENTS Page Number Glossary Information Regarding Forward-Looking Statements PART I Items 1. and 2. Business and Properties General Development of Business Organizational Structure Recent Developments Financial Information about Segments Narrative Description of Business Business Strategy Business Segments Natural Gas Pipelines CO2 Terminals Products Pipelines Kinder Morgan Canada Other Major Customers Regulation Environmental Matters Other Financial Information about Geographic Areas Available Information Risk Factors Unresolved Staff Comments Legal Proceedings Mine Safety Disclosures PART II Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Selected Financial Data Management’s Discussion and Analysis of Financial Condition and Results of Operations General Critical Accounting Policies and Estimates Results of Operations Income Taxes—Continuing Operations Liquidity and Capital Resources Recent Accounting Pronouncements 2 Item 1A. Item 1B. Item 3. Item 4. Item 5. Item 6. Item 7. 4 5 6 7 7 7 11 12 12 12 12 15 18 19 19 20 20 20 24 26 27 27 27 36 36 36 37 38 39 39 42 45 61 61 67 Table of Contents KINDER MORGAN, INC. AND SUBSIDIARIES TABLE OF CONTENTS (continued) Item 7A. Quantitative and Qualitative Disclosures About Market Risk Energy Commodity Market Risk Interest Rate Risk Financial Statements and Supplementary Data Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Controls and Procedures Other Information PART III Directors, Executive Officers and Corporate Governance Executive Compensation Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Certain Relationships and Related Transactions, and Director Independence Principal Accounting Fees and Services Item 8. Item 9. Item 9A. Item 9B. Item 10. Item 11. Item 12. Item 13. Item 14. PART IV Item 15. Exhibits, Financial Statement Schedules Index to Financial Statements Signatures 67 67 69 70 70 70 71 71 71 71 71 71 71 77 169 3 Table of Contents KINDER MORGAN, INC. AND SUBSIDIARIES GLOSSARY Company Abbreviations BOSTCO Calnev CIG Copano CPG El Paso = Battleground Oil Specialty Terminal Company LLC KMCO2 = Calnev Pipe Line LLC KMEP = Kinder Morgan CO2 Company, L.P. = Kinder Morgan Energy Partners, L.P. = Colorado Interstate Gas Company, L.L.C. = Copano Energy, L.L.C. = Cheyenne Plains Gas Pipeline Company, L.L.C. = El Paso Holdco LLC KMGP = Kinder Morgan G.P., Inc. KMI = Kinder Morgan Inc. and its majority-owned and/or controlled subsidiaries KMP = Kinder Morgan Energy Partners, L.P. and its Elba Express = Elba Express Company, L.L.C. majority-owned and controlled subsidiaries = Elba Liquefaction Company, L.L.C. KMR = Kinder Morgan Management, LLC = El Paso Corporation and its its majority-owned and MEP controlled subsidiaries = El Paso Pipeline Partners, L.P. and its majority- owned and controlled subsidiaries = El Paso Natural Gas Company, L.L.C. = El Paso Pipeline Partners Operating Company, L.L.C. NGPL SFPP SLC SLNG SNG TGP WIC = Midcontinent Express Pipeline LLC = Natural Gas Pipeline Company of America LLC = SFPP, L.P. = Southern Liquefaction Company, L.L.C. = Southern LNG Company, L.L.C. = Southern Natural Gas Company, L.L.C. = Tennessee Gas Pipeline Company, L.L.C. = Wyoming Interstate Company, L.L.C. FEP = Fayetteville Express Pipeline LLC KinderHawk = KinderHawk Field Services LLC WYCO = WYCO Development L.L.C. Unless the context otherwise requires, references to “we,” “us,” or “our,” are intended to mean Kinder Morgan, Inc. and its its majority- owned and/or controlled subsidiaries. AFUDC = allowance for funds used during construction LIBOR = London Interbank Offered Rate Common Industry and Other Terms BBtu/d Bcf/d = billion British Thermal Units per day = billion cubic feet per day CERCLA = Comprehensive Environmental Response, Compensation and Liability Act = carbon dioxide or our CO2 business segment = California Public Utilities Commission = distributable cash flow = depreciation, depletion and amortization = General Corporation Law of the state of Delaware LLC LNG MBbl/d MDth/d MLP = limited liability company = liquefied natural gas = thousands of barrels per day = thousand of dekatherm per day = master limited partnership MMBbl/d = millions barrels per day MMcf/d = million cubic feet per day NEB NGL = National Energy Board = natural gas liquids = dekatherm NYMEX = New York Mercantile Exchange = earnings before depreciation, depletion and amortization expenses, including amortization of NYSE OTC = New York Stock Exchange = over-the-counter excess cost of equity investments PHMSA = United States Department of Transportation = United States Environmental Protection Agency Pipeline and Hazardous Materials Safety = Financial Accounting Standards Board Administration = Federal Energy Regulatory Commission SEC = United States Securities and Exchange = Federal Trade Commission Commission = United States Generally Accepted Accounting Principles TBtu WTI = trillion British Thermal Units = West Texas Intermediate ELC EP EPB EPNG EPPOC CO2 CPUC DCF DD&A DGCL Dth EBDA EPA FASB FERC FTC GAAP When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch. 4 Table of Contents Information Regarding Forward-Looking Statements This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “position,” “continue,” “estimate,” “expect,” “may,” or the negative of those terms or other variations of them or comparable terminology. In particular, expressed or implied, statements concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow or to service debt or to pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors which could cause actual results to differ from those in the forward-looking statements include: • • • • • • • • • • • • • • • the timing and extent of changes in price trends and overall demand for NGL, refined petroleum products, oil, CO2, natural gas, electricity, coal, steel and other bulk materials and chemicals and certain agricultural products in North America; economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand; changes in our tariff rates required by the FERC, the CPUC, Canada’s NEB or another regulatory agency; our ability to acquire new businesses and assets and integrate those operations into our existing operations, and make cost-saving changes in operations, particularly if we undertake multiple acquisitions in a relatively short period of time, as well as our ability to expand our facilities; our ability to safely operate and maintain our existing assets and to access or construct new pipeline, gas processing and NGL fractionation capacity; our ability to attract and retain key management and operations personnel; difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from our terminals or pipelines; shut-downs or cutbacks at major refineries, petrochemical or chemical plants, natural gas processing plants, ports, utilities, military bases or other businesses that use our services or provide services or products to us; changes in crude oil and natural gas production (and the NGL content of natural gas production) from exploration and production areas that we serve, such as the Permian Basin area of West Texas, the shale plays in Oklahoma, Ohio, Pennsylvania and Texas, and the U.S. Rocky Mountains and the Alberta, Canada oil sands; changes in laws or regulations, third-party relations and approvals, and decisions of courts, regulators and governmental bodies that may adversely affect our business or our ability to compete; interruptions of electric power supply to our facilities due to natural disasters, power shortages, strikes, riots, terrorism (including cyber attacks), war or other causes; the uncertainty inherent in estimating future oil, natural gas, and CO2 production or reserves that we may experience; the ability to complete expansion projects and construction of our vessels on time and on budget; the timing and success of our business development efforts, including our ability to renew long-term customer contracts; changes in accounting pronouncements that impact the measurement of our results of operations, the timing of when such measurements are to be made and recorded, and the disclosures surrounding these activities; • changes in tax law; 5 Table of Contents • • • • • • • • • • • • • our ability to offer and sell debt securities, or obtain debt financing in sufficient amounts and on acceptable terms to implement that portion of our business plan that contemplates growth through acquisitions of operating businesses and assets and expansions of our facilities; our indebtedness, which could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, place us at a competitive disadvantage compared to our competitors that have less debt, or have other adverse consequences; our ability to obtain insurance coverage without significant levels of self-retention of risk; acts of nature, sabotage, terrorism (including cyber attacks) or other similar acts or accidents causing damage to our properties greater than our insurance coverage limits; possible changes in our and our subsidiaries credit ratings; capital and credit markets conditions, inflation and fluctuations in interest rates; the political and economic stability of the oil producing nations of the world; national, international, regional and local economic, competitive and regulatory conditions and developments; our ability to achieve cost savings and revenue growth; foreign exchange fluctuations; the extent of our success in developing and producing CO2 and oil and gas reserves, including the risks inherent in development drilling, well completion and other development activities; engineering and mechanical or technological difficulties that we may experience with operational equipment, in well completions and workovers, and in drilling new wells; and unfavorable results of litigation and the outcome of contingencies referred to in Note 16 “Litigation, Environmental and Other” to our consolidated financial statements. The foregoing list should not be construed to be exhaustive. We believe the forward-looking statements in this report are reasonable. However, there is no assurance that any of the actions, events or results of the forward-looking statements will occur, or if any of them do, what impact they will have on our results of operations or financial condition. Because of these uncertainties, you should not put undue reliance on any forward-looking statements. See Item 1A “Risk Factors” for a more detailed description of these and other factors that may affect the forward-looking statements. When considering forward-looking statements, one should keep in mind the risk factors described in Item 1A “Risk Factors.” The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation, other than as required by applicable law, and described below under Items 1 and 2, “Business and Properties —(a) General Development of Business—Recent Developments—2015 Outlook”, to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments. Items 1 and 2. Business and Properties. PART I We are the largest energy infrastructure and the third largest energy company in North America with an enterprise value of more than $125 billion. 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, which is utilized for enhanced oil recovery projects in North America. Our common stock trades on the NYSE under the symbol “KMI.” 6 Table of Contents (a) General Development of Business Organizational Structure 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. Additionally, 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 EPB and EPPOC are wholly owned subsidiaries of KMP. 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. Historically, most of our operating assets were owned and most of our investments were conducted by KMP and EPB. 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. You should read the following in conjunction with our audited consolidated financial statements and the notes thereto. We have prepared our accompanying consolidated financial statements under GAAP and the rules and regulations of the SEC. Our accounting records are maintained in U.S. dollars and all references to dollars in this report are to U.S. dollars, except where stated otherwise. Our consolidated financial statements include our accounts and those of our majority-owned and/or controlled subsidiaries, and all significant intercompany items have been eliminated in consolidation. The address of our principal executive offices is 1001 Louisiana Street, Suite 1000, Houston, Texas 77002, and our telephone number at this address is (713) 369-9000. Recent Developments The following is a brief listing of significant developments and updates related to our major projects since December 31, 2013. Additional information regarding most of these items may be found elsewhere in this report. “Capital Scope” is estimated for our share of the entire project which may include portions not yet completed. 7 Table of Contents Asset or project Description Activity Capital Scope Acquired February 2015. Plant placed in service third quarter 2014. Compression placed in service fourth quarter 2014. Placed in service April 2014. First portion placed in service September and December 2014, expected second phase in service 2016. Acquired July 2014. Natural Gas Pipelines - Placed in service or acquisitions Hiland Partners Assets consist 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. DK Expansion Construction of the second of two 400,000 Mcf/d cryogenic unit expansions and compression to support volume growth in the Eagle Ford shale. Expansion project that provides 500,000 Dth/d incremental natural gas transportation capacity, from Utica south to the Tennessee Zone 1 area. Expansion project provides 150,000 Dth/d of service to PEMEX Gas y Petroquímica Básica on an interim basis and is part of a larger project that is supported by three customers in Mexico that entered into long-term firm transportation contracts. Multi-cycle gas storage facility in West Texas near the WAHA Hub that connects to EPNG and two other interstate pipelines and has 8.5 Bcf of total storage capacity. TGP Utica Backhaul KM Texas and Mier- Monterrey pipelines expansion Keystone Storage TGP Rose Lake Sierrita Gas Pipeline Located in northeastern Pennsylvania, fully subscribed for 10-year terms by South Jersey Resources and Statoil and provides an additional 230,000 Dth/d per day of capacity. Placed in service November 2014. The 60-mile pipeline provides 200 MMcf/d of capacity and extends from near Tucson to the U.S.-Mexico border near Sasabe, Arizona. Placed in service October 2014. Natural Gas Pipelines - Other announcements TGP Northeast Energy Direct Elba Liquefaction Development of a 171-mile supply path that will extend from the Marcellus supply area in Pennsylvania to a point near Wright, New York, the market path will consist of 188 miles of mainline from Wright to Dracut, Massachusetts. Building of new natural gas liquefaction and export facilities at our SLNG natural gas terminal on Elba Island, near Savannah, Ga., with a total capacity of 2.5 million tonnes per year of LNG, equivalent to 350 MMcf/d of natural gas. Expected in service November 2018. Planning and engineering activities continue, expected full in service 2018. TGP Broad Run Flexibility and Broad Run Expansion Modification to existing pipelines to create 790,000 Dth/d of north-to-south gas transportation capacity from a receipt point in West Virginia to delivery points in Mississippi and Louisiana. Final facility design, expected in service November 2015 and November 2017. EPNG upstream Sierrita Elba Express Company and SNG expansion TGP South System Flexibility Texas Intrastate SK Freeport LNG Expansion projects to provide 550,000 Dth/d firm natural gas transport capacity, which involves a first phase of system improvements to deliver volumes to the Sierrita Pipeline, and the second phase that will result in incremental deliveries of natural gas to Arizona and California. Expansion project that provides 854,000 Dth/d incremental natural gas transportation service supporting the needs of customers in Georgia, South Carolina and northern Florida, and also serving Elba Liquefaction. Expansion project that provides more than 900 miles of north-to-south transportation capacity of 500,000 Dth/d on our TGP system from Tennessee to South Texas and expands our transportation service to Mexico. Entered into a 20-year firm transportation services agreement with SK E&S LNG, LLC in December 2014. We will provide more than 320,000 Dth/d of firm natural gas transportation services. Phase one placed in service October 2014, phase two expected fully in service October 2020. Expected in service 2016 (first phase) and 2017. Initial volume placed into service January 2015, with the remainder expected December 2016. Completion expected third quarter 2019. KMLP Magnolia LNG Liquefaction Transport Upgrades to this existing pipeline system to provide 700,000 Dth/d capacity to serve Magnolia LNG in the Lake Charles, La., area. Precedent agreement executed. Expected in service third quarter 2018. 8 $3.0 billion $236 million $175 million $105 million $92 million $74 million $66 million $4.5 to $5.5 billion $1.3 billion $751 million $529 million $282 million $187 million $153 million $143 million Table of Contents Asset or project Description Activity Capital Scope Natural Gas Pipelines - Other announcements continued TGP Susquehanna West Expansion project that provides 145,000 Dth/d incremental natural gas transportation capacity, serving the northeast Marcellus to points of liquidity. TGP Cameron LNG Compressor station modifications and new pipeline laterals for enhanced supply access to the Perryville Hub, for a capacity of 900,000 Dth/d. TGP Marcellus to Milford An expansion project to provide additional firm capacity from the Marcellus supply basin to TGP’s interconnection with Columbia Gas Transmission in Pike County, Pennsylvania. The capacity of this expansion will be at least 135,000 Dth/d. Capacity awarded. Precedent agreement executed. Expected in service November 2017. Precedent agreements executed. Expected in service fourth quarter 2018. Precedent agreements executed. Expected in service June 2018. TGP Lone Star Two greenfield compressor stations to provide supply to the Corpus Christi LNG liquefaction project, for a capacity of 300,000 Dth/d. Capacity awarded. Precedent agreement executed. Expected in service July 2019. TGP Connecticut Expansion Expansion project that provides 72,100 Dth/d incremental natural gas transportation capacity, serving the New England market. Precedent agreements executed. Expected in service November 2016. Texas Intrastate Cheniere Corpus Christi LNG Project provides 250,000 Dth/d of firm natural gas transportation service, as well as 3 Bcf of natural gas storage capacity, to serve the LNG export facility. Entered into 15-year firm transportation and multi-year storage agreements with Cheniere Energy, through its subsidiary, Corpus Christi Liquefaction. Agreements signed December 2014. Startup expected fourth quarter 2018. CO2 - Placed in service Yellow Jacket Central Facility expansion CO2 - Other announcements St. Johns Development Cow Canyon development Cortez Pipeline expansion - phase 1 A booster compression project at the McElmo Dome source field in southwestern Colorado that will increase CO2 production by up to 90 MMcf/d. Placed in service September 2014. Developing an additional 300 MMcf/d and building a new pipeline (Lobos) to transport CO2 from our St. Johns source field in Apache County, Arizona. An expansion project that will increase CO2 production in the Cow Canyon area of the McElmo Dome source field by 200 MMcf/d. Project will increase capacity from 1.35 Bcf/d to 1.7 Bcf/d on this existing pipeline. This pipeline will transport CO2 from southwestern Colorado to eastern New Mexico and west Texas for use in enhanced oil recovery projects. Expected in service 2018. Expected full in service fourth quarter 2015. Expected full in service fourth quarter 2015. Terminals - Placed in service or acquisitions American Petroleum Tankers and State Class Tankers Purchase of five on-the-water Jones Act tankers, each operating pursuant to long-term time charters with high quality counterparties, and assumption of a contract to receive four more tankers currently under construction, which will be operated pursuant to long-term time charters with a major integrated oil company. Edmonton Terminal expansion—Phases 1 and 2 A two-phase expansion project that adds 4.6 million barrels of storage capacity to our Edmonton terminal for crude oil and refined petroleum products, supported by long-term contracts with major producers and refiners. BOSTCO expansion— Phases 1 and 2 Pennsylvania and Florida Jones Act Tankers A two-phase greenfield joint venture terminal development that adds 7.1 million barrels of distillate, residual fuel and other black oil product storage at the Houston Ship Channel site, fully subscribed and supported by long-term contracts with major oil companies. Purchase from Crowley Maritime of two Jones Act tankers, engaging in the marine transportation of crude oil, condensate, and refined products in the U.S, both supported by long-term time charters with major shippers. Acquired January 2014. Placed in service first quarter 2014 (phase 1) and fourth quarter 2014 (phase 2). Placed in service second quarter 2014 (phase 1) and third quarter 2014 (phase 2). Acquired November 2014. 9 $143 million $138 million $129 million $123 million $82 million $77 million $214 million $982 million $344 million $233 million $961 million $402 million $305 million $270 million Construction completed third quarter of 2014. Construction completed second half of 2014. Capital Scope $184 million $85 million Construction completed first quarter of 2014. $64 million Expected in service first quarter 2015. $249 million Table of Contents Asset or project Description Activity Terminals - Placed in service or acquisitions continued Deepwater Coal Handling (Deer Park, TX) Expansion project at our multi-purpose Deepwater Terminal along the Houston Ship Channel adds 10 million tons per year of coal export capacity secured by long-term take-or-pay volume commitments. Lousiana Chemical Tankage Expansion International Marine Terminal Phase 3 In two separate projects added additional chemical storage to our Harvey, LA terminal and storage and various marine, truck, and rail infrastructure improvements in support of Methanex Corporation's relocated production plant. Phase 3 expansion at the joint venture International Marine Terminal in Louisiana adds additional export coal capacity supported by long-term take-or-pay volume commitments. Terminals - Other announcements Edmonton Rail Terminal Announced expansion increases capacity to over 210,000 bpd at the joint venture crude rail terminal in Edmonton. The facility, supported by long-term customer contracts, will be connected via pipeline to the Trans Mountain pipeline and be capable of sourcing all crude streams handled by Kinder Morgan for delivery by rail to North American markets and refineries. Pasadena and Galena Park Infrastructure Improvements and Greensport Ship Dock 2 Construction of 2.1 million barrels of storage between the Pasadena and Galena Park terminals, a new ship dock, and various other infrastructure improvements providing enhanced product export capabilities, supported by long- term customer contracts. Phase into service in 2016 and 2017. Expected in service first quarter 2017. Final three tanks expected in service first quarter 2015; barge dock expected in service fourth quarter 2015. In service July 2014. In service September 2014. Houston Export Terminal Royal Vopak U.S. Terminal acquisition Galena Park Tank Project and Pasadena Barge Dock Brownfield expansion along Houston Ship Channel will add 1.5 million barrels of liquids storage capacity and a new ship dock that will handle ocean going vessels, supported by a long-term contract with a major ship channel refiner. Announced purchase of three U.S. Terminals and one undeveloped site. Expected acquisition close first quarter 2015. Construction of nine storage tanks with total shell capacity of 1.2 million barrels and a new barge dock at Pasadena, supported by long-term customer contracts. Products Pipelines - Placed in service Cochin Reversal project KM Crude & Condensate Helena Extension Conversion of the line to northbound condensate service to serve oilsands producers’ needs in western Canada, supported by long-term customer contracts. Constructed 30 miles of new pipeline from Helena to Dewitt, the Helena pump station, two new tanks and a four lane truck offload system, supported by long-term customer contracts. Products Pipelines - Other announcements Palmetto Pipeline Cochin Utopia East KM Condensate Processing Facility KM Crude and Condensate Pipeline/ Double Eagle Pipeline Construction of new pipeline, underpinned by long-term customer contracts, to move gasoline, diesel and ethanol from Louisiana, Mississippi and South Carolina to points in South Carolina, Georgia and Florida. Building of new 240 mile pipeline, supported by long-term customer contracts, to transport ethane and ethane-propane mixtures from the prolific Utica Shale, with an initial design capacity of 50,000 bpd, expandable to more than 75,000 bpd. Project includes building two separate units to split condensate into various components and construct storage tanks totaling almost 2 million barrels to support the processing operation, supported by long-term customer contracts. Project will provide transportation of Eagle Ford crude and condensate to the Houston Ship Channel. Close of successful binding open season November 2014, expected in service July 2017. Work continues, expected in service January 2018. Construction continues, expected in service March 2015 (phase 1) and July 2015 (phase 2). Continues to see strong interest, expected in service second quarter 2015. 10 $238 million $172 million $158 million $124 million $301 million $99 million $778 million $507 million $383 million $235 million Table of Contents Asset or project Description Activity Capital Scope Products Pipelines - Other announcements continued Utica Marcellus Texas Pipeline Project involves the abandonment and conversion of over 1,000 miles of natural gas service on TGP, the construction of approximately 200 miles of new pipeline from Louisiana to Texas and 155 miles of new laterals in Pennsylvania, Ohio and West Virginia. Pending customer commitments, expected in service 2018. still developing Kinder Morgan Canada Trans Mountain Expansion Project _______ Financings An increase of capacity on our Trans Mountain pipeline system from approximately 300,000 to 890,000 barrels per day, underpinned by long-term take-or-pay contracts. Currently engaged in final approval process with the NEB, expected in service third quarter 2018. $5.4 billion • For information about our 2014 debt offerings and retirements, see Note 8 “Debt” to our consolidated financial statements. For information about our 2014 equity offerings, see Note 10 “Stockholders’ Equity —Non-Controlling Interests—Contributions” to our consolidated financial statements. 2015 Outlook • We expect to declare dividends of $2.00 per share for 2015, a 15% increase over our 2014 declared dividend of $1.74 per share. Growth in 2015 cash dividends is expected to be driven by continued high demand for North American energy infrastructure, including the transportation and storage of natural gas, NGL, crude oil and refined products. Additionally, growth is expected to be driven by contributions from our expansion projects across our business units. We expect that a full-year of contributions from our 2014 acquisitions and expansions, including cash tax benefits from the Merger Transactions, along with partial-year contributions from our anticipated 2015 expansion investments, as described above under —Recent Developments, will help drive earnings and cash flow growth in 2015 and beyond. Generally, our base cash flows (that is, cash flows not attributable to acquisitions or expansions) are relatively stable from year to year and are largely supported by multi-year, fee-based customer arrangements. The overwhelming majority of cash generated by our assets is fee-based and is not sensitive to commodity prices. We do have some commodity price sensitivity, primarily in our CO2 segment, and hedge the majority of our next twelve months of oil production to minimize this sensitivity. For 2015, we estimate that every $1 per barrel change in average WTI crude oil price impacts distributable cash flow by approximately $10 million (budget assumes average WTI price of $70 per barrel), and each $0.10 per MMBtu change in the average price of natural gas impacts distributable cash flow by approximately $3 million (budget assumes average natural gas price of $3.80 per MMBtu). This assumes we do not add additional hedges during the year which could reduce these sensitivities. These sensitivities compare to total anticipated segment earnings before DD&A in 2015 of approximately $8 billion (adding back our share of joint venture DD&A). In addition, our expectations for 2015 discussed above involve risks, uncertainties and assumptions, and are not guarantees of performance. Many of the factors that will determine these expectations are beyond our ability to control or predict, and because of these uncertainties, it is advisable to not put undue reliance on any forward-looking statement. Please read our Item 1A “Risk Factors” below for more information. Furthermore, we plan to provide updates to our 2015 expectations when we believe previously disclosed expectations no longer have a reasonable basis. (b) Financial Information about Segments For financial information on our six reportable business segments, see Note 15 “Reportable Segments” to our consolidated financial statements. 11 (c) Narrative Description of Business Business Strategy Our business strategy is to: • • • focus on stable, fee-based energy transportation and storage assets that are central to the energy infrastructure of growing markets within North America; increase utilization of our existing assets while controlling costs, operating safely, and employing environmentally sound operating practices; leverage economies of scale from incremental acquisitions and expansions of assets that fit within our strategy and are accretive to cash flow; and • maintain a strong balance sheet and return value to our stockholders. It is our intention to carry out the above business strategy, modified as necessary to reflect changing economic conditions and other circumstances. However, as discussed under Item 1A. “Risk Factors” below, there are factors that could affect our ability to carry out our strategy or affect its level of success even if carried out. We regularly consider and enter into discussions regarding potential acquisitions and are currently contemplating potential acquisitions. Any such transaction would be subject to negotiation of mutually agreeable terms and conditions, receipt of fairness opinions, and approval of our board of directors, if applicable. While there are currently no unannounced purchase agreements for the acquisition of any material business or assets, such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations. Business Segments We operate the following reportable business segments. These segments and their principal sources of revenues are as follows: • Natural Gas Pipelines—(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. Natural Gas Pipelines Our Natural Gas Pipelines segment includes interstate and intrastate pipelines and our LNG terminals, and includes both FERC regulated and non-FERC regulated assets. 12 Table of Contents Our primary businesses in this segment consist of natural gas sales, transportation, storage, gathering, processing and treating, and the terminaling of LNG. Within this segment, are: (i) approximately 48,000 miles of natural gas pipelines and (ii) our equity interests in entities that have approximately 19,000 miles of natural gas pipelines, along with associated storage and supply lines for these transportation networks, which are strategically located throughout the North American natural gas pipeline grid. Our transportation network provides access to the major natural gas supply areas and consumers in the western U.S., Louisiana, Texas, the Midwest, Northeast, Rocky Mountain, Midwest and Southeastern regions. Our LNG storage and regasification terminals also serve natural gas supply areas in the southeast. The following tables summarize our significant Natural Gas Pipelines segment assets, as of December 31, 2014. The Design Capacity represents either transmission or gathering capacity depending on the nature of the asset. Ownership Interest % Miles of Pipeline Natural Gas Pipelines TGP EPNG/Mojave pipeline system NGPL SNG Florida Gas Transmission (Citrus) CIG WIC Ruby pipeline MEP CPG TransColorado Gas WYCO Elba Express FEP KM Louisiana Sierrita pipeline Young Gas Storage Keystone Gas Storage Gulf LNG Holdings Bear Creek Storage 100 100 20 100 50 100 100 50 50 100 100 50 100 50 100 35 48 100 50 100 Design (Bcf/d) [Storage (Bcf)] Capacity 9.00 [97] 5.65 [44] 6.20 [288] 3.90 [68] Supply and Market Region South Texas and Gulf of Mexico to northeast and southeast U.S.; Haynesville, Marcellus, Utica, and Eagle Ford shale formations Northern New Mexico, Texas, Oklahoma, to California, connects to San Juan, Permian, and Anadarko basins Chicago and other Midwest markets and all central U.S. supply basins Texas, Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee; basins in Texas, Louisiana, Mississippi and Alabama 11,900 10,700 9,200 6,900 5,300 3.60 Texas to Florida; basins along Louisiana and Texas Gulf Coast, Mobile Bay and offshore Gulf of Mexico 4,300 850 680 510 410 310 224 200 185 135 60 17 12 5 — 5.20 [43] 3.90 1.50 1.80 1.20 1.00 1.20 [7] 0.95 2.00 3.20 0.20 [6] [9] [7] Colorado and Wyoming; Rocky Mountains and the Anadarko Basin Wyoming, Colorado, and Utah; Overthrust, Piceance, Uinta, Powder River and Green River Basins Wyoming to Oregon; Rocky Mountain basins Oklahoma and north Texas supply basins to interconnects with deliveries to interconnects with Transco, Columbia Gulf and various other pipelines Colorado and Kansas, natural gas basins in the Central Rocky Mountain area Colorado and New Mexico; connects to San Juan, Paradox and Piceance basins Northeast Colorado; connects with High Plains Georgia; connects to SNG (Georgia), Transco (Georgia/South Carolina) and CGT (Georgia). Arkansas to Mississippi; connects to NGPL, Trunkline Gas Company, Texas Gas Transmission, and ANR Pipeline Company sources gas from Cheniere Sabine Pass LNG terminal to interconnects with Columbia Gulf, ANR and various other pipelines near Tucson, Arizona, to the U.S.-Mexico border near Sasabe, Arizona; connects to EPNG and via a new international border crossing with a new natural gas pipeline in Mexico Morgan County, Colorado, capacity is committed to CIG and Colorado Springs Utilities. located in the Permian Basin and near the WAHA natural gas trading hub in West Texas. near Pascagoula, Mississippi; connects to four interstate pipelines and natural gas processing plant [59] 50% SNG and 50% TGP 13  Ownership Interest % 100 Table of Contents SLNG ELC Midstream group KM Texas and Tejas pipelines(a) Mier-Monterrey pipeline KM North Texas pipeline Copano Oklahoma Southern Dome Copano Oklahoma System Copano South Texas Webb/Duval gas gathering system Copano South Texas System EagleHawk KM Altamont Red Cedar Copano Rocky Mountain Fort Union Bighorn KinderHawk Copano North Texas Endeavor Camino Real - Gas KM Treating Copano Liquids Liberty Pipeline Copano Liquids Assets Camino Real - Oil _______ Competition 51 100 100 100 70 100 63 100 25 100 49 37 51 100 100 40 100 100 50 100 100 Design (Bcf/d) [Storage (Bcf)] Capacity [12] Miles of Pipeline — — Supply and Market Region Georgia; connects to Elba Express, SNG and CGT not in service until 2017 - 2018 5,800 95 80 — 3,500 6.20 [120] 0.65 0.33 0.03 0.38 Texas Gulf Coast. Starr County, Texas to Monterrey, Mexico; connects to Pemex NG Transportation system and a 1,000-megawatt power plant interconnect from NGPL; connects to 1,750-megawatt Forney, Texas, power plant and a 1,000-megawatt Paris, Texas, power plant propane refrigeration plant in the southern portion of Oklahoma county Hunton Dewatering, Woodford Shale, and Mississippi Lime 145 0.15 South Texas 1,255 1.88 Eagle Ford shale formation, Woodbine and Eaglebine (Texas) 860 790 750 310 290 500 400 100 70 — 87 313 70 1.00 0.08 0.70 1.25 0.60 2.00 0.14 0.12 0.15 — (MBbl/d) 170 115 110 South Texas, Eagle Ford shale formation Utah, Uinta Basin La Plata County, Colorado, Ignacio Blanco Field Powder River Basin (Wyoming) Powder River Basin (Wyoming) Northwest Louisiana, Haynesville and Bossier shale formations North Barnett Shale Combo East Texas, Cotton Valley Sands and Haynesville/ Bossier Shale horizontal well developments South Texas, Eagle Ford shale formation Odessa, Texas, other locations in Tyler and Victoria, Texas Houston Central complex to the Texas Gulf Coast Houston Central complex to the Texas Gulf Coast South Texas, Eagle Ford shale formation The market for supply of natural gas is highly competitive, and new pipelines, storage facilities, treating facilities, and facilities for related services are currently being built to serve the growing demand for natural gas in each of the markets served by the pipelines in our Natural Gas Pipelines business segment. These operations compete with interstate and intrastate 14 Table of Contents pipelines, and their shippers, for connections to new markets and supplies and for transportation, processing and treating services. We believe the principal elements of competition in our various markets are location, rates, terms of service and flexibility and reliability of service. From time to time, other projects are proposed that would compete with us. We do not know whether or when any such projects would be built, or the extent of their impact on our operations or profitability. Shippers on our natural gas pipelines compete with other forms of energy available to their natural gas customers and end users, including electricity, coal, propane and fuel oils. Several factors influence the demand for natural gas, including price changes, the availability of natural gas and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the ability to convert to alternative fuels and weather. CO2 Our CO2 business segment produces, transports, and markets CO2 for use in enhanced oil recovery projects as a flooding medium for recovering crude oil from mature oil fields. Our CO2 pipelines and related assets allow us to market a complete package of CO2 supply, transportation and technical expertise to our customers. We also hold ownership interests in several oil-producing fields and own a crude oil pipeline, all located in the Permian Basin region of West Texas. Oil and Gas Producing Activities Oil Producing Interests Our ownership interests in oil-producing fields located in the Permian Basin of West Texas, include the following: SACROC Yates Goldsmith Landreth San Andres(a) Katz Strawn Sharon Ridge H.T. Boyd(b) MidCross Reinecke(c) _______ (a) Acquired June 1, 2013 (b) Net profits interest (c) Working interest less than 1 percent. Working Interest % 97 KM Gross Developed Acres 49,156 50 99 99 14 21 13 — 9,576 6,166 7,194 2,619 n/a 320 80 The following table sets forth productive wells, service wells and drilling wells in the oil and gas fields in which we owned interests as of December 31, 2014. The oil and gas producing fields in which we own interests are located in the Permian Basin area of West Texas. When used with respect to acres or wells, “gross” refers to the total acres or wells in which we have a working interest, and “net” refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by us: Crude Oil Natural Gas Total Wells Productive Wells(a) Net Gross Service Wells(b) Net Gross Drilling Wells(c) Net Gross 2,164 5 2,169 1,381 2 1,383 1,152 — 1,152 903 — 903 2 — 2 2 — 2 _______ (a) Includes active wells and wells temporarily shut-in. As of December 31, 2014, we did not operate any productive wells with multiple completions. (b) Consists of injection, water supply, disposal wells and service wells temporarily shut-in. A disposal well is used for disposal of salt water into an underground formation; and an injection well is a well drilled in a known oil field in order to inject liquids and/or gases that enhance recovery. (c) Consists of development wells in the process of being drilled as of December 31, 2014. A development well is a well drilled in an already discovered oil field. 15 Table of Contents The following table reflects our net productive wells that were completed in each of the years ended December 31, 2014, 2013 and 2012: Year Ended December 31, 2013 2012 2014 Productive Development Exploratory Total Productive Dry Exploratory Total Wells 83 26 109 1 110 51 4 55 — 55 59 — 59 — 59 _______ Note: The above table includes wells that were completed during each year regardless of the year in which drilling was initiated, and does not include any wells where drilling operations were not completed as of the end of the applicable year. A development well is a well drilled in an already discovered oil field. The following table reflects the developed and undeveloped oil and gas acreage that we held as of December 31, 2014: Developed Acres Undeveloped Acres Total Gross Net 75,111 17,603 92,714 71,919 15,369 87,288 _______ Note: As of December 31, 2014, we have no material amount of acreage expiring in the next three years. See “Supplemental Information on Oil and Gas Activities (Unaudited)” for additional information with respect to operating statistics and supplemental information on our oil and gas producing activities. Gas and Gasoline Plant Interests Operated gas plants in the Permian Basin of West Texas: Snyder gasoline plant(a) Diamond M gas plant North Snyder plant Ownership Interest % Source 22 The SACROC unit and neighboring CO2 projects, specifically the Sharon Ridge and Cogdell units 51 100 Snyder gasoline plant Snyder gasoline plant _______ (a) This is a working interest, in addition, we have a 28% net profits interest. The average net to us does not include the value associated with the net profits interest. 16 Table of Contents Sales and Transportation Activities CO2 Segment Storage and Sales Our principal market for CO2 is for injection into mature oil fields in the Permian Basin, where industry demand is expected to remain strong for the next several years. Our ownership of CO2 reserves as of December 31, 2014 includes: Ownership Interest % Recoverable CO2 (Bcf) Compression Capacity (Bcf/d) Location Recoverable CO2 McElmo Dome unit(a) St. Johns CO2 source field and related assets(b) Doe Canyon Deep unit(a) Bravo Dome unit 45 100 87 11 5,900 1,660 832 702 1.4 Colorado 0.3 Apache County, Arizona, and Catron County, New Mexico 0.2 Colorado 0.3 New Mexico _______ (a) We also operate. (b) Compression installation planned for the fourth quarter of 2018. CO2 Segment Pipelines The principal market for transportation on our CO2 pipelines is to customers, including ourselves, using CO2 for enhanced recovery operations in mature oil fields in the Permian Basin, where industry demand is expected to remain stable for the next several years. The tariffs charged by our CO2 pipelines are not regulated; however, the tariff charged on the Cortez pipeline is based on a consent decree. The tariffs charged on the Wink pipeline system are regulated by both the FERC and the Texas Railroad Commission. Our ownership of CO2 and crude oil pipelines as of December 31, 2014 includes: Ownership Interest % Miles of Pipeline Transport Capacity (Bcf/d) Supply and Market Region CO2 pipelines Cortez pipeline Central Basin pipeline Bravo pipeline(a) Canyon Reef Carriers pipeline Centerline CO2 pipeline Eastern Shelf CO2 pipeline Pecos pipeline Goldsmith Landreth Crude oil pipeline Wink pipeline _______ (a) We do not operate Bravo pipeline. Competition 50 100 13 98 100 100 69 99 565 323 218 162 112 91 25 3 1.2 McElmo Dome and Doe Canyon source fields to the Denver City, Texas hub 0.7 Cortez, Bravo, Sheep Mountain, Canyon Reef Carriers, and Pecos pipelines 0.4 Bravo Dome to the Denver City, Texas hub 0.3 McCamey, Texas, to the SACROC, Sharon Ridge, Cogdell and Reinecke units 0.3 0.1 between Denver City, Texas and Snyder, Texas between Snyder, Texas and Knox City, Texas 0.1 McCamey, Texas, to Iraan, Texas, delivers to the Yates unit 0.2 Goldsmith Landreth San Andres field in the Permian Basin of West Texas (MBbl/d) 100 453 145 West Texas to Western Refining’s refinery in El Paso, Texas Our primary competitors for the sale of CO2 include suppliers that have an ownership interest in McElmo Dome, Bravo Dome and Sheep Mountain CO2 resources, and Oxy U.S.A., Inc., which controls waste CO2 extracted from natural gas production in the Val Verde Basin of West Texas. Our ownership interests in the Central Basin, Cortez and Bravo pipelines are 17 Table of Contents in direct competition with other CO2 pipelines. We also compete with other interest owners in the McElmo Dome unit and the Bravo Dome unit for transportation of CO2 to the Denver City, Texas market area. Terminals Our Terminals segment includes the operations of our petroleum, chemical, ethanol and other liquids terminal facilities (other than those included in the Products Pipelines segment) and all of our coal, petroleum coke, fertilizer, steel, ores and other dry-bulk material services facilities, including all transload, engineering, conveying and other in-plant services. Our terminals are located throughout the U.S. and in portions of Canada. We believe the location of our facilities and our ability to provide flexibility to customers help attract new and retain existing customers at our terminals and provide us opportunities for expansion. We often classify our terminal operations based on the handling of either liquids or dry-bulk material products. In addition, we have Jones Act qualified product tankers that provide marine transportation of crude oil, condensate and refined products in the U.S. The following summarizes our Terminals segment assets, as of December 31, 2014: Liquids terminals Bulk terminals Materials Services locations Jones Act qualified tankers Competition Number 39 Capacity (MMBbl) 78.0 78 8 7 n/a n/a 2.3 We are one of the largest independent operators of liquids terminals in the U.S, based on barrels of liquids terminaling capacity. Our liquids terminals compete with other publicly or privately held independent liquids terminals, and terminals owned by oil, chemical and pipeline companies. Our bulk terminals compete with numerous independent terminal operators, terminals owned by producers and distributors of bulk commodities, stevedoring companies and other industrial companies opting not to outsource terminal services. In some locations, competitors are smaller, independent operators with lower cost structures. Our rail transloading (material services) operations compete with a variety of single- or multi-site transload, warehouse and terminal operators across the U.S. Our Jones Act qualified product tankers compete with other Jones Act qualified vessel fleets. 18 Table of Contents Products Pipelines Our Products Pipelines segment consists of our refined petroleum products, crude oil and condensate, and NGL pipelines and associated terminals, Southeast terminals, and our transmix processing facilities. The following summarizes our significant Products Pipelines segment assets we own and operate as of December 31, 2014: Plantation pipeline Ownership Interest % 51 Miles of Pipeline 3,182 West Coast Products Pipelines(b) Pacific (SFPP) Calnev West Coast Terminals Cochin pipeline KM Crude & Condensate pipeline Central Florida pipeline Double Eagle pipeline Parkway Cypress pipeline Southeast Terminals Kinder Morgan Assessment Protocol (KMAP) Transmix Operations 2,823 570 43 1,877 252 206 194 140 104 100 100 100 100 100 100 50 50 50 100 100 100 Number of Terminals (a) or locations Terminal Capacity (MMBbl) Supply and Market Region Louisiana to Washington D.C. 13 15.3 six western states 2 6 5 2 2 28 6 2.1 Colton, CA to Las Vegas, NV; Mojave region 9.2 1.1 Seattle, Portland, San Francisco and Los Angeles areas three provinces in Canada and seven states in the U.S. 1.2 Eagle Ford shale field in South Texas (Dewitt County) to the Houston ship channel refining complex 2.5 Tampa to Orlando 0.4 Live Oak County, Texas; Corpus Christi, Texas; Karnes County, Texas; and LaSalle County interconnect at Collins with Plantation and Plantation markets Mont Belvieu, Texas to Lake Charles, Louisiana 9.1 from Mississippi through Virginia, including Tennessee pipeline integrity analysis protocol for KM and outside customers 1.5 Colton, California; Richmond, Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; St. Louis, Missouri; and Greensboro, North Carolina _______ (a) The terminals provide services including short-term product storage, truck loading, vapor handling, additive injection, dye injection and ethanol blending. (b) Our West Coast Products Pipelines assets include interstate common carrier pipelines rate-regulated by the FERC, intrastate pipelines in the state of California rate-regulated by the CPUC, and certain non rate-regulated operations and terminal facilities. Competition Our Products Pipelines’ pipeline operations compete against proprietary pipelines owned and operated by major oil companies, other independent products pipelines, trucking and marine transportation firms (for short-haul movements of products) and railcars. Our Products Pipelines’ terminal operations compete with proprietary terminals owned and operated by major oil companies and other independent terminal operators, and our transmix operations compete with refineries owned by major oil companies and independent transmix facilities. Kinder Morgan Canada Our Kinder Morgan Canada business segment includes our 100% owned and operated Trans Mountain pipeline system and a 25-mile Jet Fuel pipeline system. Trans Mountain Pipeline System The Trans Mountain pipeline system originates at Edmonton, Alberta and transports crude oil and refined petroleum products to destinations in the interior and on the west coast of British Columbia. The Trans Mountain pipeline is 713 miles in length. We also own and operate a connecting pipeline that delivers crude oil to refineries in the state of Washington. The 19 Table of Contents capacity of the line at Edmonton ranges from 300 MBbl/d when heavy crude oil represents 20% of the total throughput (which is a historically normal heavy crude oil percentage), to 400 MBbl/d with no heavy crude oil. Jet Fuel Pipeline System We also own and operate the approximate 25-mile aviation fuel pipeline that serves the Vancouver International Airport, located in Vancouver, British Columbia, Canada. The turbine fuel pipeline is referred to in this report as the Jet Fuel pipeline system. In addition to its receiving and storage facilities located at the Westridge Marine terminal, located in Port Metro Vancouver, the Jet Fuel pipeline system’s operations include a terminal at the Vancouver airport that consists of five jet fuel storage tanks with an overall capacity of 15 MBbl. Competition Trans Mountain is one of several pipeline alternatives for western Canadian crude oil and refined petroleum production, and it competes against other pipeline providers; however, it is the sole pipeline carrying crude oil and refined petroleum products from Alberta to the west coast. Furthermore, as demonstrated by our previously announced expansion proposal, discussed above in “—(a) General Development of Business—Recent Developments—Kinder Morgan Canada,” we believe that the Trans Mountain pipeline facilities provide us the opportunity to execute on capacity expansions to the west coast as the market for offshore exports continues to develop. In December 2013, the British Columbia Ministry of Environment granted approval for a new, airport fuel consortium owned, jet fuel terminal to be located near the Vancouver International Airport. The impact of this facility on our existing Jet Fuel pipeline system is uncertain at this time. Other During 2014, our other segment activity 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. Major Customers Our revenue is derived from a wide customer base. For each of the years ended December 31, 2014, 2013 and 2012, no revenues from transactions with a single external customer accounted for 10% or more of our total consolidated revenues. Our Texas intrastate natural gas pipeline group buys and sells significant volumes of natural gas within the state of Texas, and, to a far lesser extent, the CO2 business segment also sells natural gas. Combined, total revenues from the sales of natural gas from the Natural Gas Pipelines and CO2 business segments in 2014, 2013 and 2012 accounted for 25%, 28% and 28%, respectively, of our total consolidated revenues. To the extent possible, we attempt to balance the pricing and timing of our natural gas purchases to our natural gas sales, and these contracts are often settled in terms of an index price for both purchases and sales. We do not believe that a loss of revenues from any single customer would have a material adverse effect on our business, financial position, results of operations or cash flows. Regulation Interstate Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation - U.S. Operations Some of our U.S. refined petroleum products and crude oil pipelines are interstate common carrier pipelines, subject to regulation by the FERC under the Interstate Commerce Act, or ICA. The ICA requires that we maintain our tariffs on file with the FERC. Those tariffs set forth the rates we charge for providing transportation services on our interstate common carrier pipelines as well as the rules and regulations governing these services. The ICA requires, among other things, that such rates on interstate common carrier pipelines be “just and reasonable” and nondiscriminatory. The ICA permits interested persons to challenge newly proposed or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained during the two years prior to the filing of a complaint. 20 On October 24, 1992, Congress passed the Energy Policy Act of 1992. The Energy Policy Act deemed petroleum products pipeline tariff rates that were in effect for the 365-day period ending on the date of enactment or that were in effect on the 365th day preceding enactment and had not been subject to complaint, protest or investigation during the 365-day period to be just and reasonable or “grandfathered” under the ICA. The Energy Policy Act also limited the circumstances under which a complaint can be made against such grandfathered rates. Certain rates on our Pacific operations’ pipeline system were subject to protest during the 365-day period established by the Energy Policy Act. Accordingly, certain of the Pacific pipelines’ rates have been, and continue to be, the subject of complaints with the FERC, as is more fully described in Note 16 “Litigation, Environmental and Other” to our consolidated financial statements. Petroleum products pipelines may change their rates within prescribed ceiling levels that are tied to an inflation index. Shippers may protest rate increases made within the ceiling levels, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs from the previous year. A pipeline must, as a general rule, utilize the indexing methodology to change its rates. Cost-of-service ratemaking, market-based rates and settlement rates are alternatives to the indexing approach and may be used in certain specified circumstances to change rates. Common Carrier Pipeline Rate Regulation - Canadian Operations The Canadian portion of our crude oil and refined petroleum products pipeline systems is under the regulatory jurisdiction of the NEB. The National Energy Board Act gives the NEB power to authorize pipeline construction and to establish tolls and conditions of service. Our subsidiary Trans Mountain Pipeline, L.P. is the sole owner of our Trans Mountain crude oil and refined petroleum products pipeline system. The toll charged for the portion of Trans Mountain’s pipeline system located in the U.S. falls under the jurisdiction of the FERC. For further information, see “—Interstate Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation - U.S. Operations” above. Interstate Natural Gas Transportation and Storage Regulation Posted tariff rates set the general range of maximum and minimum rates we charge shippers on our interstate natural gas pipelines. Within that range, each pipeline is permitted to charge discounted rates to meet competition, so long as such discounts are offered to all similarly situated shippers and granted without undue discrimination. Apart from discounted rates offered within the range of tariff maximums and minimums, the pipeline is permitted to offer negotiated rates where the pipeline and shippers want rate certainty, irrespective of changes that may occur to the range of tariff-based maximum and minimum rate levels. Negotiated rates provide certainty to the pipeline and the shipper of a fixed rate during the term of the transportation agreement, regardless of changes to the posted tariff rates. There are a variety of rates that different shippers may pay, and while rates may vary by shipper and circumstance, the terms and conditions of pipeline transportation and storage services are not generally negotiable. The FERC regulates the rates, terms and conditions of service, construction and abandonment of facilities by companies performing interstate natural gas transportation services, including storage services, under the Natural Gas Act of 1938. To a lesser extent, the FERC regulates interstate transportation rates, terms and conditions of service under the Natural Gas Policy Act of 1978. Beginning in the mid-1980’s, through the mid-1990’s, the FERC initiated a number of regulatory changes intended to create a more competitive environment in the natural gas marketplace. Among the most important of these changes were: • Order No. 436 (1985) which required open-access, nondiscriminatory transportation of natural gas; • Order No. 497 (1988) which set forth new standards and guidelines imposing certain constraints on the interaction between interstate natural gas pipelines and their marketing affiliates and imposing certain disclosure requirements regarding that interaction; and • Order No. 636 (1992) which required interstate natural gas pipelines that perform open-access transportation under blanket certificates to “unbundle” or separate their traditional merchant sales services from their transportation and storage services and to provide comparable transportation and storage services with respect to all natural gas supplies. Natural gas pipelines must now separately state the applicable rates for each unbundled service they provide (i.e., for the natural gas commodity, transportation and storage). The FERC standards of conduct address and clarify multiple issues, including (i) the definition of transmission function and transmission function employees; (ii) the definition of marketing function and marketing function employees; (iii) the definition of transmission function information; (iv) independent functioning; (v) transparency; and (vi) the interaction of 21 FERC standards with the North American Energy Standards Board business practice standards. The FERC also promulgates certain standards of conduct that apply uniformly to interstate natural gas pipelines and public utilities. In light of the changing structure of the energy industry, these standards of conduct govern employee relationships-using a functional approach-to ensure that natural gas transmission is provided on a nondiscriminatory basis. Pursuant to the FERC’s standards of conduct, a natural gas transmission provider is prohibited from disclosing to a marketing function employee non-public information about the transmission system or a transmission customer. Additionally, no-conduit provisions prohibit a transmission function provider from disclosing non-public information to marketing function employees by using a third party conduit. Rules also require that a transmission provider provide annual training on the standards of conduct to all transmission function employees, marketing function employees, officers, directors, supervisory employees, and any other employees likely to become privy to transmission function information. In addition to regulatory changes initiated by the FERC, the U.S. Congress passed the Energy Policy Act of 2005. Among other things, the Energy Policy Act amended the Natural Gas Act to: (i) prohibit market manipulation by any entity; (ii) direct the FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce; and (iii) significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations or orders thereunder. CPUC Rate Regulation The intrastate common carrier operations of our Pacific operations’ pipelines in California are subject to regulation by the CPUC under a “depreciated book plant” methodology, which is based on an original cost measure of investment. Intrastate tariffs filed by us with the CPUC have been established on the basis of revenues, expenses and investments allocated as applicable to the California intrastate portion of the Pacific operations’ business. Tariff rates with respect to intrastate pipeline service in California are subject to challenge by complaint by interested parties or by independent action of the CPUC. A variety of factors can affect the rates of return permitted by the CPUC, and certain other issues similar to those which have arisen with respect to our FERC regulated rates also could arise with respect to its intrastate rates. The intrastate rates for movements in California on our SFPP and Calnev systems have been, and may in the future be, subject to complaints before the CPUC, as is more fully described in Note 16 “Litigation, Environmental and Other” to our consolidated financial statements. Texas Railroad Commission Rate Regulation The intrastate operations of our crude oil pipelines and natural gas pipelines and storage facilities in Texas are subject to regulation with respect to such intrastate transportation by the Texas Railroad Commission. The Texas Railroad Commission has the authority to regulate our rates, though it generally has not investigated the rates or practices of our intrastate pipelines in the absence of shipper complaints. Mexico - Energy Regulating Commission The Mier-Monterrey Pipeline has a natural gas transportation permit granted by the Energy Regulating Commission (the Commission) that defines the conditions for the pipeline to carry out activity and provide natural gas transportation service. This permit expires in 2032. This permit establishes certain restrictive conditions, including without limitations (i) compliance with the general conditions for the provision of natural gas transportation service; (ii) compliance with certain safety measures, contingency plans, maintenance plans and the official Mexican standards regarding safety; (iii) compliance with the technical and economic specifications of the natural gas transportation system authorized by the Commission; (iv) compliance with certain technical studies established by the Commission; and (v) compliance with a minimum contributed capital not entitled to withdrawal of at least the equivalent of 10% of the investment proposed in the project. Safety Regulation We are also subject to safety regulations imposed by PHMSA, including those requiring us to develop and maintain pipeline Integrity Management programs to comprehensively evaluate areas along our pipelines and take additional measures to protect pipeline segments located in what are referred to as High Consequence Areas, or HCAs, where a leak or rupture could potentially do the most harm. The ultimate costs of compliance with pipeline Integrity Management rules are difficult to predict. Changes such as advances of in-line inspection tools, identification of additional integrity threats and changes to the amount of pipe determined 22 to be located in HCAs can have a significant impact on costs to perform integrity testing and repairs. We plan to continue our pipeline integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by PHMSA regulations. These tests could result in significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines. The President signed into law new pipeline safety legislation in January 2012, The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which increased penalties for violations of safety laws and rules and may result in the imposition of more stringent regulations in the next few years. In 2012, PHMSA issued an Advisory Bulletin which, among other things, advises pipeline operators that if they are relying on design, construction, inspection, testing, or other data to determine maximum pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities to meet the demands of such pressures, could significantly increase our costs. Additionally, failure to locate such records to verify maximum pressures could result in reductions of allowable operating pressures, which would reduce available capacity on our pipelines. There can be no assurance as to the amount or timing of future expenditures for pipeline Integrity Management regulation, and actual expenditures may be different from the amounts we currently anticipate. Regulations, changes to regulations or an increase in public expectations for pipeline safety may require additional reporting, the replacement of some of our pipeline segments, addition of monitoring equipment and more frequent inspection or testing of our pipeline facilities. Repair, remediation, and preventative or mitigating actions may require significant capital and operating expenditures. From time to time, our pipelines may experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties. We are also subject to the requirements of the Occupational Safety and Health Administration (OSHA) and other federal and state agencies that address employee health and safety. In general, we believe current expenditures are addressing the OSHA requirements and protecting the health and safety of our employees. Based on new regulatory developments, we may increase expenditures in the future to comply with higher industry and regulatory safety standards. However, such increases in our expenditures, and the extent to which they might be offset, cannot be estimated at this time. State and Local Regulation Our activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies, governing a wide variety of matters, including marketing, production, pricing, pollution, protection of the environment, and human health and safety. Marine Operations The operation of tankers and marine equipment create maritime obligations involving property, personnel and cargo under General Maritime Law. These obligations create a variety of risks including, among other things, the risk of collision, which may precipitate claims for personal injury, cargo, contract, pollution, third party claims and property damages to vessels and facilities. We are subject to the Jones Act and other federal laws that restrict maritime transportation (between U.S. departure and destination points) to vessels built and registered in the U.S. and owned and manned by U.S. citizens. As a result, we monitor the foreign ownership of our common stock. If we do not comply with such requirements, we would be prohibited from operating our vessels in U.S. coastwise trade, and under certain circumstances we would be deemed to have undertaken an unapproved foreign transfer, resulting in severe penalties, including permanent loss of U.S. coastwise trading rights for our vessels, fines or forfeiture of the vessels. Furthermore, from time to time, legislation has been introduced unsuccessfully in Congress to amend the Jones Act to ease or remove the requirement that vessels operating between U.S. ports be built and registered in the U.S. and owned and manned by U.S. citizens. If the Jones Act were amended in such fashion, we could face competition from foreign flagged vessels. In addition, the U.S. Coast Guard and the American Bureau of Shipping maintain the most stringent regime of vessel inspection in the world, which tends to result in higher regulatory compliance costs for U.S.-flag operators than for owners of vessels registered under foreign flags of convenience. The Jones Act and General Maritime Law also provide damage remedies for crew members injured in the service of the vessel arising from employer negligence or vessel unseaworthiness. 23 The Merchant Marine Act of 1936 is a federal law that provides, upon proclamation by the U.S. President of a national emergency or a threat to the national security, the U.S. Secretary of Transportation the authority to requisition or purchase any vessel or other watercraft owned by U.S. citizens (including us, provided that we are considered a U.S. citizen for this purpose). If one of our vessels were purchased or requisitioned by the U.S. government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, we would not be entitled to compensation for any consequential damages suffered as a result of such purchase or requisition. Environmental Matters Our business operations are subject to federal, state, provincial and local laws and regulations relating to environmental protection, pollution and human health and safety in the U.S. and Canada. For example, if an accidental leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines, or at or from our storage or other facilities, we may experience significant operational disruptions, and we may have to pay a significant amount to clean up the leak, release or spill, pay for government penalties, address natural resource damages, compensate for human exposure or property damage, install costly pollution control equipment or a combination of these and other measures. Furthermore, new projects may require approvals and environmental analysis under federal and state laws, including the National Environmental Policy Act and the Endangered Species Act. The resulting costs and liabilities could materially and negatively affect our business, financial condition, results of operations and cash flows. In addition, emission controls required under federal, state and provincial environmental laws could require significant capital expenditures at our facilities. Environmental and human health and safety laws and regulations are subject to change. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, wildlife, natural resources and human health. There can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows. In accordance with GAAP, we accrue liabilities for environmental matters when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or previously disposed. We have accrued liabilities for estimable and probable environmental remediation obligations at various sites, including multi-party sites where the EPA, or similar state or Canadian agency has identified us as one of the potentially responsible parties. The involvement of other financially responsible companies at these multi-party sites could increase or mitigate our actual joint and several liability exposures. We believe that the ultimate resolution of these environmental matters will not have a material adverse effect on our business, financial position, results of operations or cash flows. However, it is possible that our ultimate liability with respect to these environmental matters could exceed the amounts accrued in an amount that could be material to our business, financial position, results of operations or cash flows in any particular reporting period. We have accrued an environmental reserve in the amount of $340 million as of December 31, 2014. Our reserve estimates range in value from approximately $340 million to approximately $514 million, and we recorded our liability equal to the low end of the range, as we did not identify any amounts within the range as a better estimate of the liability. For additional information related to environmental matters, see Note 16 “Litigation, Environmental and Other” to our consolidated financial statements. Hazardous and Non-Hazardous Waste We generate both hazardous and non-hazardous wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act and comparable state and Canadian statutes. From time to time, the EPA and state and Canadian regulators consider the adoption of stricter disposal standards for that some wastes that are currently classified as non-hazardous, which could include wastes currently generated during our pipeline or liquids or bulk terminal operations, may in the future be designated as hazardous wastes. Hazardous wastes are subject to more rigorous and costly handling and disposal requirements than non-hazardous wastes. Such changes in the regulations may result in additional capital expenditures or operating expenses for us. waste. Furthermore, it is possible 24 Superfund The CERCLA or the Superfund law, and analogous state laws, impose joint and several liability, without regard to fault or the legality of the original conduct, on certain classes of potentially responsible persons for releases of hazardous substances into the environment. These persons include the owner or operator of a site and companies that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur, in addition to compensation for natural resource damages, if any. Although petroleum is excluded from CERCLA’s definition of a hazardous substance, in the course of our ordinary operations, we have and will generate materials that may fall within the definition of hazardous substance. By operation of law, if we are determined to be a potentially responsible person, we may be responsible under CERCLA for all or part of the costs required to clean up sites at which such materials are present, in addition to compensation for natural resource damages, if any. Clean Air Act Our operations are subject to the Clean Air Act, its implementing regulations, and analogous state and Canadian statutes and regulations. We believe that the operations of our pipelines, storage facilities and terminals are in substantial compliance with such statutes. The EPA regulations under the Clean Air Act contain requirements for the monitoring, reporting, and control of greenhouse gas emissions from stationary sources. For further information, see “—Climate Change” below. Clean Water Act Our operations can result in the discharge of pollutants. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and controls regarding the discharge of pollutants into waters of the U.S. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by applicable federal, state or Canadian authorities. The Oil Pollution Act was enacted in 1990 and amends provisions of the Clean Water Act pertaining to prevention and response to oil spills. Spill prevention control and countermeasure requirements of the Clean Water Act and some state and Canadian laws require containment and similar structures to help prevent contamination of navigable waters in the event of an overflow or release of oil. Climate Change Studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases, may be contributing to warming of the Earth’s atmosphere. Methane, a primary component of natural gas, and CO2, which is naturally occurring and also a byproduct of the burning of natural gas, are examples of greenhouse gases. Various laws and regulations exist or are under development that seek to regulate the emission of such greenhouse gases, including the EPA programs to control greenhouse gas emissions and state actions to develop statewide or regional programs. The U.S. Congress is considering legislation to reduce emissions of greenhouse gases. Beginning in December 2009, EPA published several findings and rulemakings under the Clean Air Act requiring the permitting and reporting of certain greenhouse gases including CO2 and methane. Our facilities are subject to and in substantial compliance with these requirements. Operational and/or regulatory changes could require additional facilities to comply with greenhouse gas emissions reporting and permitting requirements. Additionally, the EPA has announced that it will propose new regulations of greenhouse gases addressing emission of greenhouse gases with a renewed focus on emissions of methane which may impose further requirements, including emission control requirements, on Kinder Morgan facilities. At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas “cap and trade” programs. Although many of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions, such as electric power plants, it is possible that sources such as our gas-fired compressors and processing plants could become subject to related state regulations. Various states are also proposing or have implemented more strict regulations for greenhouse gases that go beyond the requirements of the EPA. Depending on the particular program, we could be required to conduct monitoring, do additional emissions reporting and/or purchase and surrender emission allowances. Because our operations, including the compressor stations and processing plants, emit various types of greenhouse gases, primarily methane and CO2, such new legislation or regulation could increase the costs related to operating and maintaining the facilities. Depending on the particular law, regulation or program, we or our subsidiaries could be required to incur capital 25 expenditures for installing new monitoring equipment of emission controls on the facilities, acquire and surrender allowances for the greenhouse gas emissions, pay taxes related to the greenhouse gas emissions and administer and manage a greenhouse gas emissions program. We are not able at this time to estimate such increased costs; however, as is the case with similarly situated entities in the industry they could be significant to us. While we may be able to include some or all of such increased costs in the rates charged by our or our subsidiaries pipelines, such recovery of costs in all cases is uncertain and may depend on events beyond their control including the outcome of future rate proceedings before the FERC or other regulatory bodies and the provisions of any final legislation or other regulations. Any of the foregoing could have an adverse effect on our business, financial position, results of operations and prospects. Some climatic models indicate that global warming is likely to result in rising sea levels, increased intensity of hurricanes and tropical storms, and increased frequency of extreme precipitation and flooding. We may experience increased insurance premiums and deductibles, or a decrease in available coverage, for our assets in areas subject to severe weather. To the extent these phenomena occur, they could damage our physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone regions. However, the timing and location of these climate change impacts is not known with any certainty and, in any event, these impacts are expected to manifest themselves over a long time horizon. Thus, we are not in a position to say whether the physical impacts of climate change pose a material risk to our business, financial position, results of operations or cash flows. Because natural gas emits less greenhouse gas emissions per unit of energy than competing fossil fuels, cap-and-trade legislation or EPA regulatory initiatives could stimulate demand for natural gas by increasing the relative cost of fuels such as coal and oil. In addition, we anticipate that greenhouse gas regulations will increase demand for carbon sequestration technologies, such as the techniques we have successfully demonstrated in our enhanced oil recovery operations within our CO2 business segment. However, these positive effects on our markets may be offset if these same regulations also cause the cost of natural gas to increase relative to competing non-fossil fuels. Although we currently cannot predict the magnitude and direction of these impacts, greenhouse gas regulations could have material adverse effects on our business, financial position, results of operations or cash flows. Department of Homeland Security The Department of Homeland Security, referred to in this report as the DHS, has regulatory authority over security at certain high-risk chemical facilities. The DHS has promulgated the Chemical Facility Anti-Terrorism Standards and required all high-risk chemical and industrial facilities, including oil and gas facilities, to comply with the regulatory requirements of these standards. This process includes completing security vulnerability assessments, developing site security plans, and implementing protective measures necessary to meet DHS-defined, risk based performance standards. The DHS has not provided final notice to all facilities that it determines to be high risk and subject to the rule; therefore, neither the extent to which our facilities may be subject to coverage by the rules nor the associated costs to comply can currently be determined, but it is possible that such costs could be substantial. Other Employees We employed 11,535 full-time people at December 31, 2014, including approximately 828 full-time hourly personnel at certain terminals and pipelines covered by collective bargaining agreements that expire between 2015 and 2018. We consider relations with our employees to be good. Most of our employees are employed by a limited number of our subsidiaries and provide services to one or more of our business units. The direct costs of compensation, benefits expenses, employer taxes and other employer expenses for these employees are allocated to our subsidiaries. Our human resources department provides the administrative support necessary to implement these payroll and benefits services, and the related administrative costs are allocated to our subsidiaries pursuant to our board-approved expense allocation policy. The effect of these arrangements is that each business unit bears the direct compensation and employee benefits costs of its assigned or partially assigned employees, as the case may be, while also bearing its allocable share of administrative costs. Properties We believe that we generally have satisfactory title to the properties we own and use in our businesses, subject to liens for current taxes, liens incident to minor encumbrances, and easements and restrictions, which do not materially detract from the value of such property, the interests in those properties or the use of such properties in our businesses. Our terminals, storage 26 Table of Contents facilities, treating and processing plants, regulator and compressor stations, oil and gas wells, offices and related facilities are located on real property owned or leased by us. In some cases, the real property we lease is on federal, state, provincial or local government land. We generally do not own the land on which our pipelines are constructed. Instead, we obtain the right to construct and operate the pipelines on other people’s land for a period of time. Substantially all of our pipelines are constructed on rights-of- way granted by the apparent record owners of such property. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. In some cases, not all of the apparent record owners have joined in the right-of-way grants, but in substantially all such cases, signatures of the owners of a majority of the interests have been obtained. Permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets and state highways, and in some instances, such permits are revocable at the election of the grantor, or, the pipeline may be required to move its facilities at its own expense. Permits also have been obtained from railroad companies to run along or cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election. Some such permits require annual or other periodic payments. In a few minor cases, property for pipeline purposes was purchased in fee. (d) Financial Information about Geographic Areas For geographic information concerning our assets and operations, see Note 15 “Reportable Segments” to our consolidated financial statements. (e) Available Information We make available free of charge on or through our internet website, at www.kindermorgan.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The information contained on or connected to our internet Website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC. Item 1A. Risk Factors. You should carefully consider the risks described below, in addition to the other information contained in this document. Realization of any of the following risks could have a material adverse effect on our business, financial condition, cash flows and results of operations. Risks Related to Our Business Our pipelines business is dependent on the supply of and demand for the commodities transported by our pipelines. Our pipelines depend on production of natural gas, oil and other products in the areas served by our pipelines. Without reserve additions, production will decline over time as reserves are depleted and production costs may rise. Producers may shut down production at lower product prices or higher production costs, especially where the existing cost of production exceeds other extraction methodologies, such as in the Alberta oil sands. Producers in areas served by us may not be successful in exploring for and developing additional reserves, and our gas plants and pipelines may not be able to maintain existing volumes of throughput. Commodity prices and tax incentives may not remain at levels that encourage producers to explore for and develop additional reserves, produce existing marginal reserves or renew transportation contracts as they expire. Changes in the business environment, such as the recent sharp decline in crude oil prices, an increase in production costs from higher feedstock prices, supply disruptions, or higher development costs, could result in a slowing of supply from oil and natural gas producing areas. In addition, changes in the regulatory environment or governmental policies may have an impact on the supply of crude oil and natural gas. Each of these factors impacts our customers shipping through our pipelines, which in turn could impact the prospects of new transportation contracts or renewals of existing contracts. Throughput on our crude oil, natural gas and refined petroleum products pipelines also may decline as a result of changes in business conditions. Over the long term, business will depend, in part, on the level of demand for oil, natural gas and refined petroleum products in the geographic areas in which deliveries are made by pipelines and the ability and willingness of shippers having access or rights to utilize the pipelines to supply such demand. 27 Table of Contents The implementation of new regulations or the modification of existing regulations affecting the oil and gas industry could reduce demand for natural gas, crude oil and refined petroleum products, increase our costs and have a material adverse effect on our results of operations and financial condition. We cannot predict the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce the demand for natural gas, crude oil and refined petroleum products. We may face competition from other pipelines and other forms of transportation into the areas we serve as well as with respect to the supply for our pipeline systems. Any current or future pipeline system or other form of transportation that delivers crude oil, petroleum products or natural gas into the areas that our pipelines serve could offer transportation services that are more desirable to shippers than those we provide because of price, location, facilities or other factors. To the extent that an excess of supply into these areas is created and persists, our ability to recontract for expiring transportation capacity at favorable rates or otherwise to retain existing customers could be impaired. We also could experience competition for the supply of petroleum products or natural gas from both existing and proposed pipeline systems. Several pipelines access many of the same areas of supply as our pipeline systems and transport to destinations not served by us. Our growth strategy may cause difficulties integrating acquisitions and constructing new facilities, and we may not be able to achieve the expected benefits from any future acquisitions or expansions. Part of our business strategy includes acquiring additional businesses, expanding existing assets and constructing new facilities. If we do not successfully integrate acquisitions, expansions or newly constructed facilities, we may not realize anticipated operating advantages and cost savings. The integration of acquired companies or new assets involves a number of risks, including (i) demands on management related to the increase in our size; (ii) the diversion of management’s attention from the management of daily operations; (iii) difficulties in implementing or unanticipated costs of accounting, estimating, reporting and other systems; (iv) difficulties in the assimilation and retention of necessary employees; and (v) potential adverse effects on operating results. We may not be able to maintain the levels of operating efficiency that acquired companies have achieved or might achieve separately. Successful integration of each acquisition, expansion or construction project will depend upon our ability to manage those operations and to eliminate redundant and excess costs. Difficulties in integration may be magnified if we make multiple acquisitions over a relatively short period of time. Because of difficulties in combining and expanding operations, we may not be able to achieve the cost savings and other size-related benefits that we hoped to achieve after these acquisitions and expansions, which would harm our financial condition and results of operations. Our substantial debt could adversely affect our financial health and make us more vulnerable to adverse economic conditions. As of December 31, 2014, we had approximately $41 billion of consolidated debt (excluding debt fair value adjustments). Additionally, in connection with the Merger Transactions, we and substantially all of our wholly owned subsidiaries entered into a cross guarantee agreement whereby each party to the agreement unconditionally guarantees the indebtedness of each other party to the agreement, thereby causing us to become liable for the debt of each of such subsidiaries. This level of debt and the cross guarantee agreement could have important consequences, such as (i) limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements or potential growth or for other purposes; (ii) increasing the cost of our future borrowings; (iii) limiting our ability to use operating cash flow in other areas of our business or to pay dividends because we must dedicate a substantial portion of these funds to make payments on our debt; (iv) placing us at a competitive disadvantage compared to competitors with less debt; and (v) increasing our vulnerability to adverse economic and industry conditions. Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond our control. If our operating results are not sufficient to service our indebtedness, including the cross-guaranteed debt, and any future indebtedness that we incur, we will be forced to take actions, which may include reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to affect any of these actions on satisfactory terms or at all. For more information about our debt, see Note 8 “Debt” to our consolidated financial statements. 28 Table of Contents New regulations, rulemaking and oversight, as well as changes in regulations, by regulatory agencies having jurisdiction over our operations could adversely impact our income and operations. Our assets and operations are subject to regulation and oversight by federal, state, provincial and local regulatory authorities. Regulatory actions taken by these agencies have the potential to adversely affect our profitability. Regulation affects almost every part of our business and extends to such matters as (i) rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for), operating terms and conditions of service; (ii) the types of services we may offer to our customers; (iii) the contracts for service entered into with our customers; (iv) the certification and construction of new facilities; (v) the integrity, safety and security of facilities and operations; (vi) the acquisition of other businesses; (vii) the acquisition, extension, disposition or abandonment of services or facilities; (viii) reporting and information posting requirements; (ix) the maintenance of accounts and records; and (x) relationships with affiliated companies involved in various aspects of the natural gas and energy businesses. Should we fail to comply with any applicable statutes, rules, regulations, and orders of such regulatory authorities, we could be subject to substantial penalties and fines. Furthermore, new laws or regulations sometimes arise from unexpected sources. New laws or regulations, or different interpretations of existing laws or regulations, including unexpected policy changes, applicable to us or our assets could have a material adverse impact on our business, financial condition and results of operations. For more information, see Items 1 and 2 “Business and Properties—(c) Narrative Description of Business— Regulation.” The FERC, the CPUC, or the NEB may establish pipeline tariff rates that have a negative impact on us. In addition, the FERC, the CPUC, the NEB, or our customers could file complaints challenging the tariff rates charged by our pipelines, and a successful complaint could have an adverse impact on us. The profitability of our regulated pipelines is influenced by fluctuations in costs and our ability to recover any increases in our costs in the rates charged to our shippers. To the extent that our costs increase in an amount greater than what we are permitted by the FERC, the CPUC, or the NEB to recover in our rates, or to the extent that there is a lag before we can file for and obtain rate increases, such events can have a negative impact upon our operating results. Our existing rates may also be challenged by complaint. Regulators and shippers on our pipelines have rights to challenge, and have challenged, the rates we charge under certain circumstances prescribed by applicable regulations. Some shippers on our pipelines have filed complaints with the regulators that seek substantial refunds for alleged overcharges during the years in question and prospective reductions in the tariff rates. Further, the FERC may continue to initiate investigations to determine whether interstate natural gas pipelines have over-collected on rates charged to shippers. We may face challenges, similar to those described in Note 16 to our consolidated financial statements, to the rates we charge on our pipelines. Any successful challenge to our rates could materially adversely affect our future earnings, cash flows and financial condition. Energy commodity transportation and storage activities involve numerous risks that may result in accidents or otherwise adversely affect our operations. There are a variety of hazards and operating risks inherent to natural gas transmission and storage activities and refined petroleum products and CO2 transportation activities-such as leaks, explosions and mechanical problems-that could result in substantial financial losses. In addition, these risks could result in serious injury and loss of human life, significant damage to property and natural resources, environmental pollution and impairment of operations, any of which also could result in substantial financial losses. For pipeline and storage assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks may be greater. Incidents that cause an interruption of service, such as when unrelated third party construction damages a pipeline or a newly completed expansion experiences a weld failure, may negatively impact our revenues and earnings while the affected asset is temporarily out of service. In addition, losses in excess of our insurance coverage could have a material adverse effect on our business, financial condition and results of operations. Increased regulatory requirements relating to the integrity of our pipelines may require us to incur significant capital and operating expense outlays to comply. We are subject to extensive laws and regulations related to pipeline integrity. There are, for example, federal guidelines for the DOT and pipeline companies in the areas of testing, education, training and communication. The ultimate costs of compliance with the integrity management rules are difficult to predict. The majority of compliance costs relate to pipeline integrity testing and repairs. Technological advances in in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipeline determined to be located in “High Consequence Areas” can have a 29 Table of Contents significant impact on integrity testing and repair costs. We plan to continue our integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by the DOT rules. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines. Further, additional laws and regulations that may be enacted in the future or a new interpretation of existing laws and regulations could significantly increase the amount of these expenditures. There can be no assurance as to the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not deemed by regulators to be fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects. Environmental, health and safety laws and regulations could expose us to significant costs and liabilities. Our operations are subject to federal, state, provincial and local laws, regulations and potential liabilities arising under or relating to the protection or preservation of the environment, natural resources and human health and safety. Such laws and regulations affect many aspects of our present and future operations, and generally require us to obtain and comply with various environmental registrations, licenses, permits, inspections and other approvals. Liability under such laws and regulations may be incurred without regard to fault under CERCLA, the Resource Conservation and Recovery Act, the Federal Clean Water Act or analogous state or provincial laws for the remediation of contaminated areas. Private parties, including the owners of properties through which our pipelines pass, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with such laws and regulations or for personal injury or property damage. Our insurance may not cover all environmental risks and costs and/or may not provide sufficient coverage in the event an environmental claim is made against us. Failure to comply with these laws and regulations also may expose us to civil, criminal and administrative fines, penalties and/or interruptions in our operations that could influence our business, financial position, results of operations and prospects. For example, if an accidental leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines or our storage or other facilities, we may experience significant operational disruptions and we may have to pay a significant amount to clean up or otherwise respond to the leak, release or spill, pay for government penalties, address natural resource damage, compensate for human exposure or property damage, install costly pollution control equipment or undertake a combination of these and other measures. The resulting costs and liabilities could materially and negatively affect our level of earnings and cash flows. In addition, emission controls required under the Federal Clean Air Act and other similar federal, state and provincial laws could require significant capital expenditures at our facilities. We own and/or operate numerous properties that have been used for many years in connection with our business activities. While we have utilized operating, handling, and disposal practices that were consistent with industry practices at the time, hydrocarbons or other hazardous substances may have been released at or from properties owned, operated or used by us or our predecessors, or at or from properties where our or our predecessors’ wastes have been taken for disposal. In addition, many of these properties have been owned and/or operated by third parties whose management, handling and disposal of hydrocarbons or other hazardous substances were not under our control. These properties and the hazardous substances released and wastes disposed on them may be subject to laws in the U.S. such as CERCLA, which impose joint and several liability without regard to fault or the legality of the original conduct. Under the regulatory schemes of the various Canadian provinces, such as British Columbia’s Environmental Management Act, Canada has similar laws with respect to properties owned, operated or used by us or our predecessors. Under such laws and implementing regulations, we could be required to remove or remediate previously disposed wastes or property contamination, including contamination caused by prior owners or operators. Imposition of such liability schemes could have a material adverse impact on our operations and financial position. Further, we cannot ensure that such existing laws and regulations will not be revised or that new laws or regulations will not be adopted or become applicable to us. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects. For more information, see Items 1 and 2 “Business and Properties—(c) Narrative Description of Business—Environmental Matters.” 30 Table of Contents Climate change regulation at the federal, state, provincial or regional levels could result in significantly increased operating and capital costs for us. Methane, a primary component of natural gas, and CO2, which is naturally occurring and also a byproduct of the burning of natural gas, are examples of greenhouse gases. The EPA regulates greenhouse gas emissions and requires the reporting of greenhouse gas emissions in the U.S. for emissions from specified large greenhouse gas emission sources, fractionated NGL, and the production of naturally occurring CO2, like our McElmo Dome CO2 field, even when such production is not emitted to the atmosphere. Because our operations, including our compressor stations and natural gas processing plants in our Natural Gas Pipelines segment, emit various types of greenhouse gases, primarily methane and CO2, such regulation could increase our costs related to operating and maintaining our facilities and could require us to install new emission controls on our facilities, acquire allowances for our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program, and such increased costs could be significant. Recovery of such increased costs from our customers is uncertain in all cases and may depend on events beyond our control, including the outcome of future rate proceedings before the FERC. Any of the foregoing could have adverse effects on our business, financial position, results of operations or cash flows. For more information about climate change regulation, see Items 1 and 2 “Business and Properties— (c) Narrative Description of Business—Environmental Matters—Climate Change.” Increased regulation of exploration and production activities, including hydraulic fracturing, could result in reductions or delays in drilling and completing new oil and natural gas wells, as well as reductions in production from existing wells, which could adversely impact the volumes of natural gas transported on our or our joint ventures’ natural gas pipelines and our own oil and gas development and production activities. Oil and gas development and production activities are subject to numerous federal, state, provincial and local laws and regulations relating to environmental quality and pollution control. The oil and gas industry is increasingly relying on supplies of hydrocarbons from unconventional sources, such as shale, tight sands and coal bed methane. The extraction of hydrocarbons from these sources frequently requires hydraulic fracturing. Hydraulic fracturing involves the pressurized injection of water, sand, and chemicals into the geologic formation to stimulate gas production and is a commonly used stimulation process employed by oil and gas exploration and production operators in the completion of certain oil and gas wells. There have been initiatives at the federal and state levels to regulate or otherwise restrict the use of hydraulic fracturing. Adoption of legislation or regulations placing restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on exploration and production operators, which could reduce their production of natural gas and, in turn, adversely affect our revenues and results of operations by decreasing the volumes of natural gas transported on our or our joint ventures’ natural gas pipelines, several of which gather gas from areas in which the use of hydraulic fracturing is prevalent. In addition, many states are promulgating stricter requirements not only for wells but also compressor stations and other facilities in the oil and gas industry sector. These laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation. Specifically, these activities are subject to laws and regulations regarding the acquisition of permits before drilling, restrictions on drilling activities and location, emissions into the environment, water discharges, transportation of hazardous materials, and storage and disposition of wastes. In addition, legislation has been enacted that requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities. These laws and regulations may adversely affect our oil and gas development and production activities. Our acquisition strategy and expansion programs require access to new capital. Limitations on our access to capital would impair our ability to grow. We rely on external financing sources, including commercial borrowings and issuances of debt and equity securities, to fund our acquisition and growth capital expenditures. However, to the extent we are unable to continue to finance growth externally, our cash distribution policy will significantly impair our ability to grow. We may need new capital to finance these activities. Limitations on our access to capital, whether due to tightened capital markets, more expensive capital or otherwise, will impair our ability to execute this strategy. Our large amount of variable rate debt makes us vulnerable to increases in interest rates. As of December 31, 2014, approximately $11 billion of our approximately $41 billion of consolidated debt (excluding debt fair value adjustments) was subject to variable interest rates, either as short-term or long-term debt of variable rate debt obligations, or as long-term fixed-rate debt effectively converted to variable rates through the use of interest rate swaps. 31 Table of Contents Should interest rates increase, the amount of cash required to service this debt would increase and our earnings could be adversely affected. For more information about our interest rate risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.” Our debt instruments may limit our financial flexibility and increase our financing costs. The instruments governing our debt contain restrictive covenants that may prevent us from engaging in certain transactions that we deem beneficial and that may be beneficial to us. Some of the agreements governing our debt generally require us to comply with various affirmative and negative covenants, including the maintenance of certain financial ratios and restrictions on (i) incurring additional debt; (ii) entering into mergers, consolidations and sales of assets; (iii) granting liens; and (iv) entering into sale-leaseback transactions. The instruments governing any future debt may contain similar or more restrictive restrictions. Our ability to respond to changes in business and economic conditions and to obtain additional financing, if needed, may be restricted. Our business, financial condition and operating results may be affected adversely by increased costs of capital or a reduction in the availability of credit. Adverse changes to the availability, terms and cost of capital, interest rates or our credit ratings could cause our cost of doing business to increase by limiting our access to capital, limiting our ability to pursue acquisition opportunities and reducing our cash flows. Our credit ratings may be impacted by our leverage, liquidity, credit profile and potential transactions. Also, disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations on favorable terms. A significant reduction in the availability of credit could materially and adversely affect business, financial condition and results of operations. In addition, any reduction in our credit ratings could negatively impact the credit ratings of our subsidiaries, which could increase their cost of capital and negatively affect their business and operating results. Although the ratings from credit agencies are not recommendations to buy, sell or hold our securities, our credit ratings will generally affect the market value of our and our subsidiaries’ debt securities. Cost overruns and delays on our expansion and new build projects could adversely affect our business. We regularly undertake major construction projects to expand our existing assets and to construct new assets. A variety of factors outside of our control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as performance by third-party contractors, has resulted in, and may continue to result in, increased costs or delays in construction. Significant cost overruns or delays in completing a project could have a material adverse effect on our return on investment, results of operations and cash flows. We must either obtain the right from landowners or exercise the power of eminent domain in order to use most of the land on which our pipelines are constructed, and we are subject to the possibility of increased costs to retain necessary land use. We obtain the right to construct and operate pipelines on other owners’ land for a period of time. If we were to lose these rights or be required to relocate our pipelines, our business could be negatively affected. In addition, we are subject to the possibility of increased costs under our rental agreements with landowners, primarily through rental increases and renewals of expired agreements. Whether we have the power of eminent domain for our pipelines, other than interstate natural gas pipelines, varies from state to state depending upon the type of pipeline-petroleum liquids, natural gas, CO2, or crude oil-and the laws of the particular state. Our interstate natural gas pipelines have federal eminent domain authority. In either case, we must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. Our inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipelines are located. Current or future distressed financial conditions of our customers could have an adverse impact on us in the event these customers are unable to pay us for the products or services we provide. Some of our customers are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. We cannot provide assurance that one or more of our financially distressed customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations or future cash flows. Furthermore, the bankruptcy of one or more 32 Table of Contents of our customers, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. In addition, such events might force such customers to reduce or curtail their future use of our products and services, which could have a material adverse effect on our results of operations, financial condition, and cash flows. Our operating results may be adversely affected by unfavorable economic and market conditions. Economic conditions worldwide have from time to time contributed to slowdowns in several industries, including the oil and gas industry, the steel industry and in specific segments and markets in which we operate, resulting in reduced demand and increased price competition for our products and services. Our operating results in one or more geographic regions also may be affected by uncertain or changing economic conditions within that region, such as the challenges that are currently affecting economic conditions in the U.S. and Canada. Volatility in commodity prices might have an impact on many of our customers, which in turn could have a negative impact on their ability to meet their obligations to us. In addition, decreases in the prices of crude oil and NGL will have a negative impact on the results of our CO2 business segment. If global economic and market conditions (including volatility in commodity markets), or economic conditions in the U.S. or other key markets, remain uncertain or persist, spread or deteriorate further, we may experience material impacts on our business, financial condition and results of operations. Terrorist attacks or “cyber security” events, or the threat of them, may adversely affect our business. The U.S. government has issued public warnings that indicate that pipelines and other assets might be specific targets of terrorist organizations or “cyber security” events. These potential targets might include our pipeline systems or operating systems and may affect our ability to operate or control our pipeline assets, our operations could be disrupted and/or customer information could be stolen. The occurrence of one of these events could cause a substantial decrease in revenues, increased costs to respond or other financial loss, damage to reputation, increased regulation or litigation or inaccurate information reported from our operations. There is no assurance that adequate sabotage and terrorism insurance will be available at rates we believe are reasonable in the near future. These developments may subject our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations and financial condition. Hurricanes, earthquakes and other natural disasters could have an adverse effect on our business, financial condition and results of operations. Some of our pipelines, terminals and other assets are located in areas that are susceptible to hurricanes, earthquakes and other natural disasters. These natural disasters could potentially damage or destroy our pipelines, terminals and other assets and disrupt the supply of the products we transport through our pipelines. Natural disasters can similarly affect the facilities of our customers. In either case, losses could exceed our insurance coverage and our business, financial condition and results of operations could be adversely affected, perhaps materially. The future success of our oil and gas development and production operations depends in part upon our ability to develop additional oil and gas reserves that are economically recoverable. The rate of production from oil and natural gas properties declines as reserves are depleted. Without successful development activities, the reserves and revenues of the oil and gas producing assets within our CO2 business segment will decline. We may not be able to develop or acquire additional reserves at an acceptable cost or have necessary financing for these activities in the future. Additionally, if we do not realize production volumes greater than, or equal to, our hedged volumes, we may suffer financial losses not offset by physical transactions. The development of oil and gas properties involves risks that may result in a total loss of investment. The business of developing and operating oil and gas properties involves a high degree of business and financial risk that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Acquisition and development decisions generally are based on subjective judgments and assumptions that, while they may be reasonable, are by their nature speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, the successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational and market-related factors, including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions, may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable. A 33 Table of Contents productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of oil and/or gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances. The volatility of oil and natural gas prices could have a material adverse effect on our CO2 and natural gas pipeline business segments. The revenues, profitability and future growth of our CO2 and natural gas pipeline business segments and the carrying value of its oil, NGL and natural gas properties depend to a large degree on prevailing oil and gas prices. For 2015, we estimate that every $1 change in the average WTI crude oil price per barrel would impact our distributable cash flow by approximately $10 million and each $0.10 per MMBtu change in the average price of natural gas impacts distributable cash flow by approximately $3 million. Prices for oil, NGL and natural gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil, NGL and natural gas, uncertainties within the market and a variety of other factors beyond our control. These factors include, among other things (i) weather conditions and events such as hurricanes in the U.S.; (ii) the condition of the U.S. economy; (iii) the activities of the Organization of Petroleum Exporting Countries; (iv) governmental regulation; (v) political stability in the Middle East and elsewhere; (vi) the foreign supply of and demand for oil and natural gas; (vii) the price of foreign imports; and (viii) the availability of alternative fuel sources. A sharp decline in the prices of oil, NGL or natural gas would result in a commensurate reduction in our revenues, income and cash flows from the production of oil, NGL, and natural gas and could have a material adverse effect on the carrying value of our proved reserves. In the event prices fall substantially, we may not be able to realize a profit from our production and would operate at a loss. In recent decades, there have been periods of both worldwide overproduction and underproduction of hydrocarbons and periods of both increased and relaxed energy conservation efforts. Such conditions have resulted in periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis. These periods have been followed by periods of short supply of, and increased demand for, crude oil and natural gas. The excess or short supply of crude oil or natural gas has placed pressures on prices and has resulted in dramatic price fluctuations even during relatively short periods of seasonal market demand. These fluctuations impact the accuracy of assumptions used in our budgeting process. For more information about our energy and commodity market risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Energy Commodity Market Risk.” Our use of hedging arrangements could result in financial losses or reduce our income. We engage in hedging arrangements to reduce our exposure to fluctuations in the prices of oil and natural gas. These hedging arrangements expose us to risk of financial loss in some circumstances, including when production is less than expected, when the counterparty to the hedging contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the hedging agreement and the actual price received. In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in prices for oil and natural gas. The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions (for example, to mitigate our exposure to fluctuations in commodity prices or currency exchange rates or to balance our exposure to fixed and variable interest rates) that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at the dates of those statements. In addition, it is not always possible for us to engage in hedging transactions that completely mitigate our exposure to commodity prices. Our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge. For more information about our hedging activities, see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Hedging Activities” and Note 13 “Risk Management” to our consolidated financial statements. The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to hedge risks associated with our business. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the OTC derivatives market and entities that participate in that market. The CFTC has proposed new rules pursuant to the Dodd-Frank Act that would institute broad new aggregate position limits for OTC swaps and futures and options traded on regulated exchanges. As the law favors exchange trading and clearing, the Dodd-Frank Act also may require us to move certain derivatives transactions to exchanges where no trade credit is provided and also comply with margin requirements in connection with our derivatives activities that are not exchange traded, although the application of those provisions to us is uncertain at this time. The Dodd-Frank Act also requires many counterparties to our derivatives instruments 34 Table of Contents to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty, or cause the entity to comply with the capital requirements, which could result in increased costs to counterparties such as us. The Dodd-Frank Act and any related regulations could (i) significantly increase the cost of derivative contracts (including those requirements to post collateral, which could adversely affect our available liquidity); (ii) reduce the availability of derivatives to protect against risks we encounter; and (iii) reduce the liquidity of energy related derivatives. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial condition and results of operations. The Jones Act includes restrictions on ownership by non-U.S. citizens of our vessels, and failure to comply with the Jones Act, or changes to or repeal of the Jones Act, could limit our ability to operate our vessels in the U.S. coastwise trade or result in the forfeiture of our vessels otherwise adversely impact our income and operations. Following our 2014 acquisitions of American Petroleum Tankers, State Class Tankers, and the Pennsylvania and Florida Jones Act tankers from Crowley Maritime Corporation Tankers, we are subject to the Jones Act, which generally restricts U.S. point-to-point maritime shipping to vessels operating under the U.S. flag, built in the U.S., owned and operated by U.S.- organized companies that are controlled and at least 75% owned by U.S. citizens and manned by predominately U.S. crews. Our business would be adversely affected if we fail to comply with the Jones Act provisions on coastwise trade. If we do not comply with any of these requirements, we would be prohibited from operating our vessels in the U.S. coastwise trade and, under certain circumstances, we could be deemed to have undertaken an unapproved transfer to non-U.S. citizens that could result in severe penalties, including permanent loss of U.S. coastwise trading rights for our vessels, fines or forfeiture of vessels. Our business could be adversely affected if the Jones Act were to be modified or repealed so as to permit foreign competition that is not subject to the same U.S. government imposed burdens. Our business requires the retention and recruitment of a skilled workforce and the loss of such workforce could result in the failure to implement our business plans. Our operations and management require the retention and recruitment of a skilled workforce, including engineers, technical personnel and other professionals. We and our affiliates compete with other companies in the energy industry for this skilled workforce. In addition, many of our current employees are retirement eligible and have significant institutional knowledge that must be transferred to other employees. If we are unable to (i) retain current employees; (ii) successfully complete the knowledge transfer; and/or (iii) recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased allocated costs to retain and recruit these professionals. If we are unable to retain our chairman or executive officers, our growth may be hindered. Our success depends in part on the performance of and our ability to retain our chairman and our executive officers, particularly our Chairman and current Chief Executive Officer, Richard D. Kinder, who is also one of our founders, and our current President and Chief Operating Officer, Steve Kean, who will assume the Chief Executive Officer position in June of 2015. Along with the other members of our senior management, Mr. Kinder and Mr. Kean have been responsible for developing and executing our growth strategy. If we are not successful in retaining Mr. Kinder, Mr. Kean or our other executive officers or replacing them, our business, financial condition or results of operations could be adversely affected. We do not maintain key personnel insurance. Our Kinder Morgan Canada segment is subject to U.S. dollar/Canadian dollar exchange rate fluctuations. We are a U.S. dollar reporting company. As a result of the operations of our Kinder Morgan Canada business segment, a portion of our consolidated assets, liabilities, revenues and expenses are denominated in Canadian dollars. Fluctuations in the exchange rate between U.S. and Canadian dollars could expose us to reductions in the U.S. dollar value of our earnings and cash flows and a reduction in our stockholders’ equity under applicable accounting rules. 35 Table of Contents Risks Related to the Ownership of Our Common Stock The price of our common stock may be volatile, and holders of our common stock could lose a significant portion of their investments. The market price of our common stock could be volatile, and our stockholders may not be able to resell their common stock at or above the price at which they purchased it due to fluctuations in its market price, including changes in price caused by factors unrelated to our operating performance or prospects. Specific factors that may have a significant effect on the market price for our common stock include: (i) changes in stock market analyst recommendations or earnings estimates regarding our common stock, other companies comparable to us or companies in the industries we serve; (ii) actual or anticipated fluctuations in our operating results or future prospects; (iii) reaction to our public announcements; (iv) strategic actions taken by us or our competitors, such as acquisitions or restructurings; (v) the recruitment or departure of key personnel; (vi) new laws or regulations or new interpretations of existing laws or regulations applicable to our business and operations; (vii) changes in tax or accounting standards, policies, guidance, interpretations or principles; (viii) adverse conditions in the financial markets or general U.S. or international economic conditions, including those resulting from war, incidents of terrorism and responses to such events; and (ix) sales of common stock by us, members of our management team or significant stockholders. Non-U.S. holders of our common stock may be subject to U.S. federal income tax with respect to gain on the disposition of our common stock. If we are or have been a “U.S. real property holding corporation’’ within the meaning of the Code at any time within the shorter of (i) the five-year period preceding a disposition of our common stock by a non-U.S. holder or (ii) such holder’s holding period for such common stock, and assuming our common stock is “regularly traded,’’ as defined by applicable U.S. Treasury regulations, on an established securities market, the non-U.S. holder may be subject to U.S. federal income tax with respect to gain on such disposition if it held more than 5% of our common stock during the shorter of periods (i) and (ii) above. We believe we are, or may become, a U.S. real property holding corporation. The guidance we provide for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business. We disclose in this report and elsewhere our expected cash dividends. This reflects our current judgment, but as with any estimate, it may be affected by inaccurate assumptions and known and unknown risks and uncertainties, many of which are beyond our control. See “Information Regarding Forward-Looking Statements.” If the payment of dividends at the anticipated level would leave us with insufficient cash to take timely advantage of growth opportunities (including through acquisitions), to meet any large unanticipated liquidity requirements, to fund our operations, or otherwise to address properly our business prospects, our business would be harmed. Conversely, a decision to address such needs might lead to the payment of dividends below the anticipated level. As events present themselves or become reasonably foreseeable, our board of directors, which determines our business strategy and our dividends, might have to choose between addressing those matters or reducing our anticipated dividends. Alternatively, because there is nothing in our governing documents or credit agreements that prohibits us from borrowing to pay dividends, our board of directors may choose to cause us to incur debt to enable us to pay our anticipated dividends. This would add to our substantial debt discussed above under “-Risks Related to Our Business-Our substantial debt could adversely affect our financial health and make us more vulnerable to adverse economic consequences.” Item 1B. Unresolved Staff Comments. None. Item 3. Legal Proceedings. See Note 16 “Litigation, Environmental and Other” to our consolidated financial statements. Item 4. Mine Safety Disclosures. The information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd- Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is in exhibit 95.1 to this annual report. 36 Table of Contents PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. On December 26, 2012, the remaining outstanding shares of our Class A, Class B, and Class C common stock were converted into Class P shares and as of December 31, 2012 only our Class P common stock was outstanding. Our Class P common stock is listed for trading on the NYSE under the symbol “KMI.” During the period that our Class A, Class B, and Class C common stock was outstanding, none were traded on a public trading market. The high and low sale prices per Class P share as reported on the NYSE and the dividends declared per share by period for 2014, 2013 and 2012, are provided below. 2014 First Quarter Second Quarter Third Quarter Fourth Quarter 2013 First Quarter Second Quarter Third Quarter Fourth Quarter 2012 First Quarter Second Quarter Third Quarter Fourth Quarter Price Range Low High Declared Cash Dividends(a) $ 30.81 $ 36.45 $ 32.10 35.20 33.25 36.50 42.49 43.18 $ 35.74 $ 38.80 $ 35.52 34.54 32.30 41.49 40.45 36.68 $ 31.76 $ 39.25 $ 30.51 32.03 31.93 40.25 36.63 36.50 0.42 0.43 0.44 0.45 0.38 0.40 0.41 0.41 0.32 0.35 0.36 0.37 _______ (a) Dividend information is for dividends declared with respect to that quarter. Generally, our declared dividends are paid on or about the 16th day of each February, May, August and November. As of February 2, 2015, we had 12,483 holders of our Class P common stock, which does not include beneficial owners whose shares are held by a clearing agency, such as a broker or bank. For information on our equity compensation plans, see Note 9 “Share-based Compensation and Employee Benefits— Share-based Compensation—Kinder Morgan, Inc.” to our consolidated financial statements. Our Purchases of Our Class P Shares and Warrants Period October 1 to October 31, 2014 November 1 to November 30, 2014 December 1 to December 31, 2014 Total number of securities purchased Average price paid per security — $ — $ — $ — — — Total number of securities purchased as part of publicly announced plans Maximum number (or approximate dollar value) of securities that may yet be purchased under the plans or programs(a) — $ — $ — $ 2,452,606 2,452,606 2,452,606 $ 2,452,606 _______ (a) Remaining amount available under a $100 million share and warrant repurchase program approved by our board of directors on March 4, 2014. 37 Table of Contents Item 6. Selected Financial Data. The following table sets forth, for the periods and at the dates indicated, our summary historical financial data. The table is derived from our consolidated financial statements and notes thereto, and should be read in conjunction with those audited financial statements. See also Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this report for more information. Five-Year Review Kinder Morgan, Inc. and Subsidiaries As of or for the Year Ended December 31, 2014 2013 2012 2011 2010 (In millions, except per share and ratio data) Income and Cash Flow Data: Revenues Operating income Earnings (loss) from equity investments Income from continuing operations (Loss) income from discontinued operations, net of tax Net income Net income (loss) attributable to Kinder Morgan, Inc. Class P Shares $ 16,226 $ 14,070 $ 9,973 $ 7,943 $ 4,448 406 2,443 — 2,443 1,026 3,990 327 2,696 (4) 2,692 1,193 2,593 153 1,204 (777) 427 315 7,852 1,133 (274) 64 236 300 (41) Basic and Diluted Earnings Per Common Share From Continuing Operations Basic and Diluted (Loss) Earnings Per Common Share From Discontinued Operations Total Basic and Diluted Earnings Per Common Share $ $ 0.89 $ 1.15 $ 0.56 $ — — (0.21) 0.89 $ 1.15 $ 0.35 $ Class A Shares Basic and Diluted Earnings Per Common Share From Continuing Operations Basic and Diluted (Loss) Earnings Per Common Share From Discontinued Operations Total Basic and Diluted Earnings Per Common Share Basic Weighted Average Number of Shares Outstanding: Class P shares Class A shares Diluted Weighted Average Number of Shares Outstanding: Class P shares Class A shares $ $ 0.47 $ (0.21) 0.26 $ 1,137 1,036 1,137 1,036 461 446 908 446 Dividends per common share declared for the period(a)(b) $ Dividends per common share paid in the period(a) $ 1.74 1.70 $ 1.60 1.56 $ 1.40 1.34 1,423 226 449 211 660 594 0.70 0.04 0.74 0.64 0.04 0.68 118 589 708 589 1.05 0.74 Balance Sheet Data (at end of period): Net property, plant and equipment $ 38,564 $ 35,847 $ 30,996 $ 17,926 $ Total assets Long-term debt(c) 83,198 38,312 75,185 31,910 68,245 29,409 30,717 13,261 17,071 28,908 13,219 _______ (a) Dividends for the fourth quarter of each year are declared and paid during the first quarter of the following year. (b) 2011 declared dividend per share was prorated for the portion of the first quarter we were a public company ($0.14 per share). If we had been a public company for the entire year, the 2011 declared dividend would have been $1.20 per share. (c) Excludes debt fair value adjustments. Increases to long-term debt for debt fair value adjustments totaled $1,934 million, $1,977 million, $2,591 million, $1,095 million and $594 million as of December 31, 2014, 2013, 2012, 2011, and 2010, respectively. 38 Table of Contents Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto. We prepared our consolidated financial statements in accordance with GAAP. Additional sections in this report which should be helpful to the reading of our discussion and analysis include the following: (i) a description of our business strategy found in Items 1 and 2 “Business and Properties—(c) Narrative Description of Business—Business Strategy;” (ii) a description of developments during 2014, found in Items 1 and 2 “Business and Properties—(a) General Development of Business—Recent Developments;” and (iii) a description of risk factors affecting us and our business, found in Item 1A “Risk Factors.” Inasmuch as the discussion below and the other sections to which we have referred you pertain to management’s comments on financial resources, capital spending, our business strategy and the outlook for our business, such discussions contain forward-looking statements. These forward-looking statements reflect the expectations, beliefs, plans and objectives of management about future financial performance and assumptions underlying management’s judgment concerning the matters discussed, and accordingly, involve estimates, assumptions, judgments and uncertainties. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to any differences include, but are not limited to, those discussed below and elsewhere in this report, particularly in Item 1A “Risk Factors” and at the beginning of this report in “Information Regarding Forward-Looking Statements.” General Our business model, through our ownership and operation of energy related assets, is built to support two principal objectives: • helping customers by providing safe and reliable energy, bulk commodity and liquids products transportation, storage and distribution; and • creating long-term value for our shareholders. To achieve these objectives, we focus on providing fee-based services to customers from a business portfolio consisting of energy-related pipelines, natural gas storage, processing and treating facilities, and bulk and liquids terminal facilities. We also produce and sell crude oil. Our reportable business segments are based on the way our management organizes our enterprise, and each of our business segments represents a component of our enterprise that engages in a separate business activity and for which discrete financial information is available. Our reportable business segments are: • Natural Gas Pipelines—(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; 39 Table of Contents • 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. As an energy infrastructure owner and operator in multiple facets of the various U.S. and Canadian energy industries and markets, we examine a number of variables and factors on a routine basis to evaluate our current performance and our prospects for the future. With respect to our interstate natural gas pipelines and related storage facilities, the revenues from these assets are primarily received under contracts with terms that are fixed for various and extended periods of time. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate risk of reduced volumes and prices by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. These long-term contracts are typically structured with a fixed-fee reserving the right to transport natural gas and specify that we receive the majority of our fee for making the capacity available, whether or not the customer actually chooses to utilize the capacity. Similarly, the Texas Intrastate Natural Gas Group, currently derives approximately 75% of its sales and transport margins from long-term transport and sales contracts that include requirements with minimum volume payment obligations. As contracts expire, we have additional exposure to the longer term trends in supply and demand for natural gas. As of December 31, 2014, the remaining average contract life of our natural gas transportation contracts (including intrastate pipelines’ purchase and sales contracts) was approximately six years. Our midstream group, which is within our Natural Gas Pipelines Segment, provides gathering and processing services primarily through our (i) EP midstream asset operations, which we acquired 50% from KKR effective June 1, 2012, and 50% from the May 25, 2012 EP acquisition, (ii) our Copano operations, which included the remaining 50% ownership interest in Eagle Ford Gathering LLC (Eagle Ford) that we did not already own and which was acquired effective May 1, 2013 and (iii) our KinderHawk operation, which gathers and treats natural gas in the Haynesville and Bossier shale gas formations located in northwest Louisiana. These substantially fee-based gathering, processing and fractionation assets, along with our financial strength and extensive pipeline transportation and storage assets, provide an excellent platform to further grow our midstream group services footprint. The revenues and earnings we realize from gathering natural gas, processing natural gas in order to remove NGL from the natural gas stream, and fractionating NGL into their base components, are also affected by the volumes of natural gas made available to our systems, which are primarily driven by levels of natural gas drilling activity. Our midstream group services are provided pursuant to a variety of arrangements, generally categorized (by the nature of the commodity price risk) as fee-based, percent-of-proceeds, percent-of-index and keep-whole. Contracts may rely solely on a single type of arrangement, but more often they combine elements of two or more of the above, which helps us and our counterparties manage the extent to which each shares in the potential risks and benefits of changing commodity prices. In February 2015, we acquired Hiland Partners (Hiland) for a total purchase price of approximately $3 billion (including assumption of debt). Hiland’s assets consist 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. Most of Hiland’s operations will be included in our midstream group within our Natural Gas Pipelines segment. The CO2 source and transportation business primarily has third-party contracts with minimum volume requirements, which as of December 31, 2014, had a remaining average contract life of approximately ten years. CO2 sales contracts vary from customer to customer and have evolved over time as supply and demand conditions have changed. Our recent contracts have generally provided for a delivered price tied to the price of crude oil, but with a floor price. On a volume-weighted basis, for third-party contracts making deliveries in 2015, and utilizing the average oil price per barrel contained in our 2015 budget, approximately 86% of our revenue is based on a fixed fee or floor price, and 14% fluctuates with the price of oil. In the long- term, our success in this portion of the CO2 business segment is driven by the demand for CO2. However, short-term changes in the demand for CO2 typically do not have a significant impact on us due to the required minimum sales volumes under many of our contracts. In the CO2 business segment’s oil and gas producing activities, we monitor the amount of capital we expend in relation to the amount of production that we expect to add. In that regard, our production during any period is an important measure. In addition, the revenues we receive from our crude oil, NGL and CO2 sales are affected by the prices we realize from the sale of these products. Over the long-term, we will tend to receive prices that are dictated by the demand and overall market price for these products. In the shorter term, however, market prices are likely not indicative of the revenues we will receive due to our risk management, or hedging, program, in which the prices to be realized for certain of our future sales 40 Table of Contents quantities are fixed, capped or bracketed through the use of financial derivative contracts, particularly for crude oil. The realized weighted average crude oil price per barrel, with all hedges allocated to oil, was $88.41 per barrel in 2014, $92.70 per barrel in 2013 and $87.72 per barrel in 2012. Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $86.48 per barrel in 2014, $94.94 per barrel in 2013 and $89.91 per barrel in 2012. The factors impacting our Terminals business segment generally differ depending on whether the terminal is a liquids or bulk terminal, and in the case of a bulk terminal, the type of product being handled or stored. As with our refined petroleum products pipeline transportation business, the revenues from our bulk terminals business are generally driven by the volumes we handle and/or store, as well as the prices we receive for our services, which in turn are driven by the demand for the products being shipped or stored. While we handle and store a large variety of products in our bulk terminals, the primary products are coal, petroleum coke, and steel. For the most part, we have contracts for this business that have minimum volume guarantees and are volume based above the minimums. Because these contracts are volume based above the minimums, our profitability from the bulk business can be sensitive to economic conditions. Our liquids terminals business generally has longer-term contracts that require the customer to pay regardless of whether they use the capacity. Thus, similar to our natural gas pipeline business, our liquids terminals business is less sensitive to short-term changes in supply and demand. Therefore, the extent to which changes in these variables affect our terminals business in the near term is a function of the length of the underlying service contracts (which on average is approximately four years), the extent to which revenues under the contracts are a function of the amount of product stored or transported, and the extent to which such contracts expire during any given period of time. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate the risk of reduced volumes and pricing by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. In addition, weather-related factors such as hurricanes, floods and droughts may impact our facilities and access to them and, thus, the profitability of certain terminals for limited periods of time or, in relatively rare cases of severe damage to facilities, for longer periods. Our seven Jones Act qualified tankers operate in the marine transportation of crude oil, condensate and refined products in the U.S. and are currently operating pursuant to multi-year charters with major integrated oil companies, major refiners and the U.S. Military Sealift Command. The profitability of our refined petroleum products pipeline transportation business is generally driven by the volume of refined petroleum products that we transport and the prices we receive for our services. Transportation volume levels are primarily driven by the demand for the refined petroleum products being shipped or stored. Demand for refined petroleum products tends to track in large measure demographic and economic growth, and with the exception of periods of time with very high product prices or recessionary conditions, demand tends to be relatively stable. Because of that, we seek to own refined petroleum products pipelines located in, or that transport to, stable or growing markets and population centers. The prices for shipping are generally based on regulated tariffs that are adjusted annually based on changes in the U.S. Producer Price Index. Our 2015 budget, and related announced expectation to declare dividends of $2.00 per share for 2015, assumes an average WTI crude oil price of approximately $70 per barrel and an average natural gas price of $3.80 per MMBtu in 2015. For 2015, we estimate that every $1 change in the average WTI crude oil price per barrel will impact our distributable cash flow by approximately $10 million (approximately $7 million of which is attributable to our CO2 business segment), and each $0.10 per MMBtu change in the average price of natural gas will impact distributable cash flow by approximately $3 million. This assumes we do not add additional hedges during the year which could reduce these sensitivities. These sensitivities compare to total anticipated segment earnings before DD&A in 2015 of approximately $8 billion (adding back our share of joint venture DD&A). Even adjusting for current commodity prices we expect to have significant excess coverage in 2015. The amount that we are able to increase dividends to our shareholders will, to some extent, be a function of our ability to complete successful acquisitions and expansions. We believe we will continue to have opportunities for expansion of our facilities in many markets, and we have budgeted approximately $4.4 billion for our 2015 capital expansion program (including small acquisitions and investment contributions, but excluding our recent acquisition of Hiland Partners, LP). We consider and enter into discussions regarding potential acquisitions and are currently contemplating potential acquisitions. Based on our historical record and because there is continued demand for energy infrastructure in the areas we serve, we expect to continue to have such opportunities in the future, although the level of such opportunities is difficult to predict. While there are currently no unannounced purchase agreements for the acquisition of any material business or assets, such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations. Furthermore, our ability to make accretive acquisitions is a function of the availability of suitable acquisition candidates at the right cost, and includes factors over which we have limited or no control. Thus, we have no way to determine the number or size of accretive acquisition candidates in the future, or whether we will complete the acquisition of any such candidates. 41 Table of Contents Our ability to make accretive acquisitions or expand our assets is impacted by our ability to maintain adequate liquidity and to raise the necessary capital needed to fund such acquisitions. Our dividend policy is to distribute most of our available cash, and we intend to continue accessing capital markets to fund acquisitions and asset expansions. Historically, we have succeeded in raising necessary capital in order to fund our acquisitions and expansions, and although we cannot predict future changes in the overall equity and debt capital markets (in terms of tightening or loosening of credit), we believe that our stable cash flows, credit ratings, and historical records of successfully accessing both equity and debt funding sources should allow us to continue to execute our current investment, dividend and acquisition strategies, as well as refinance maturing debt when required. For a further discussion of our liquidity, including our and our subsidiaries’ public debt and equity offerings in 2014, please see “—Liquidity and Capital Resources” below. In our discussions of the operating results of individual businesses that follow (see “—Results of Operations” below), we generally identify the important fluctuations between periods that are attributable to acquisitions and dispositions separately from those that are attributable to businesses owned in both periods. In addition, a portion of our business portfolio (including the Kinder Morgan Canada business segment, the Canadian portion of the Cochin Pipeline, and the bulk and liquids terminal facilities located in Canada) use the local Canadian dollar as the functional currency for its Canadian operations and we enter into foreign currency-based transactions, both of which affect segment results due to the inherent variability in U.S. - Canadian dollar exchange rates. To help understand our reported operating results, all of the following references to “foreign currency effects” or similar terms in this section represent our estimates of the changes in financial results, in U.S. dollars, resulting from fluctuations in the relative value of the Canadian dollar to the U.S. dollar. The references are made to facilitate period-to-period comparisons of business performance and may not be comparable to similarly titled measures used by other registrants. Critical Accounting Policies and Estimates Accounting standards require information in financial statements about the risks and uncertainties inherent in significant estimates, and the application of GAAP involves the exercise of varying degrees of judgment. Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for our assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements. We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates, and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. In preparing our consolidated financial statements and related disclosures, examples of certain areas that require more judgment relative to others include our use of estimates in determining: (i) the economic useful lives of our assets and related depletion rates; (ii) the fair values used to assign purchase price from business combinations, determine possible asset impairment charges, and calculate the annual goodwill impairment test; (iii) reserves for environmental claims, legal fees, transportation rate cases and other litigation liabilities; (iv) provisions for uncollectible accounts receivables; (v) exposures under contractual indemnifications; and (vi) unbilled revenues. For a summary of our significant accounting policies, see Note 2 “Summary of Significant Accounting Policies” to our consolidated financial statements. We believe that certain accounting policies are of more significance in our consolidated financial statement preparation process than others, which policies are discussed as follows. Acquisition Method of Accounting For acquired businesses, we generally recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition. Determining the fair value of these items requires management’s judgment, the utilization of independent valuation experts and involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The judgments made in the determination of the estimated fair value assigned to the assets acquired, the liabilities assumed and any noncontrolling interest in the investee, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. For more information on our acquisitions and application of the acquisition method, see Note 3 “Acquisitions and Divestitures” to our consolidated financial statements. 42 Table of Contents Environmental Matters With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. We expense or capitalize, as appropriate, environmental expenditures that relate to current operations, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, we do not discount environmental liabilities to a net present value, and we recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We record at fair value, where appropriate, environmental liabilities assumed in a business combination. Our recording of our environmental accruals often coincides with our completion of a feasibility study or our commitment to a formal plan of action, but generally, we recognize and/or adjust our environmental liabilities following routine reviews of potential environmental issues and claims that could impact our assets or operations. These adjustments may result in increases in environmental expenses and are primarily related to quarterly reviews of potential environmental issues and resulting environmental liability estimates. In making these liability estimations, we consider the effect of environmental compliance, pending legal actions against us, and potential third party liability claims. For more information on environmental matters, see Items 1 and 2 “Business and Properties—(c) Narrative Description of Business—Environmental Matters”. For more information on our environmental disclosures, see Note 16 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements. Legal Matters Many of our operations are regulated by various U.S. and Canadian regulatory bodies and we are subject to legal and regulatory matters as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. In general, we expense legal costs as incurred. When we identify contingent liabilities, we identify a range of possible costs expected to be required to resolve the matter. Generally, if no amount within this range is a better estimate than any other amount, we record a liability equal to the low end of the range. Any such liability recorded is revised as better information becomes available. Accordingly, to the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. For more information on legal proceedings, see Note 16 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements. Intangible Assets Intangible assets are those assets which provide future economic benefit but have no physical substance. Identifiable intangible assets having indefinite useful economic lives, including goodwill, are not subject to regular periodic amortization, and such assets are not to be amortized until their lives are determined to be finite. Instead, the carrying amount of a recognized intangible asset with an indefinite useful life must be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We evaluate our goodwill for impairment on May 31 of each year. 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, other than $2 million associated with a pending asset divestiture. Furthermore, our analysis as of that date did not reflect any reporting units at risk, and subsequent to that date, no event has occurred indicating that the implied fair value of each of our reporting units is less than the carrying value of its net assets. For more information on our goodwill, see Notes 2 “Summary of Significant Accounting Policies” and 7 “Goodwill and Other Intangibles” to our consolidated financial statements. Excluding goodwill, our other intangible assets include customer contracts, relationships and agreements, lease value, and technology-based assets. These intangible assets have definite lives, are being amortized in a systematic and rational manner over their estimated useful lives, and are reported separately as “Other intangibles, net” in our accompanying consolidated balance sheets. For more information on our amortizable intangibles, see Note 7 “Goodwill and Other Intangibles” to our consolidated financial statements. Estimated Net Recoverable Quantities of Oil and Gas We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved reserves, both developed and undeveloped. The existence and the estimated amount of proved reserves affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depleted or amortized into income, and the presentation of supplemental information on oil and gas producing 43 Table of Contents activities. The expected future cash flows to be generated by oil and gas producing properties used in testing for impairment of such properties also rely in part on estimates of net recoverable quantities of oil and gas. Proved reserves are the estimated quantities of oil and gas that geologic and engineering data demonstrates with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. For more information on our ownership interests in the net quantities of proved oil and gas reserves and our measures of discounted future net cash flows from oil and gas reserves, please see “Supplemental Information on Oil and Gas Producing Activities (Unaudited)”. The quantities of our proved oil and gas reserves and the measures of discounted future net cash flows from those oil and gas reserves as of December 31, 2014 are based on the 12 month unweighted average of the first day of the month price realized in 2014. Commodity prices fell substantially toward the end of 2014 and therefore, unless commodity prices recover in the next 12 months, the amount of our proved oil and gas reserves and the measures of discounted future net cash flows from those oil and gas reserves could be negatively impacted in 2015. Any resulting reductions in our proved oil and gas reserves due to lower commodity pricing may increase our DD&A expense. Sustained lower commodity prices may also negatively impact forward curve pricing that is used in testing for impairment, estimated total proved and risk-adjusted probable and possible oil and gas reserves, and related expected future cash flows, which may result in impairment of our oil producing interests. Hedging Activities We engage in a hedging program that utilizes derivative contracts to mitigate (offset) our exposure to fluctuations in energy commodity prices and to balance our exposure to fixed and variable interest rates, and we believe that these hedges are generally effective in realizing these objectives. According to the provisions of GAAP, to be considered effective, changes in the value of a derivative contract or its resulting cash flows must substantially offset changes in the value or cash flows of the item being hedged, and any ineffective portion of the hedge gain or loss and any component excluded from the computation of the effectiveness of the derivative contract must be reported in earnings immediately. We may or may not apply hedge accounting to our derivative contracts depending on the circumstances. All of our derivative contracts are recorded at estimated fair value. Since it is not always possible for us to engage in a hedging transaction that completely mitigates our exposure to unfavorable changes in commodity prices-a perfectly effective hedge-we often enter into hedges that are not completely effective in those instances where we believe to do so would be better than not hedging at all. But because the part of such hedging transactions that is not effective in offsetting undesired changes in commodity prices (the ineffective portion) is required to be recognized currently in earnings, our financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge. For example, when we purchase a commodity at one location and sell it at another, we may be unable to hedge completely our exposure to a differential in the price of the product between these two locations; accordingly, our financial statements may reflect some volatility due to these hedges. For more information on our hedging activities, see Note 13 “Risk Management” to our consolidated financial statements. Employee Benefit Plans We reflect an asset or liability for our pension and other postretirement benefit plans based on their overfunded or underfunded status. As of December 31, 2014, our pension plans were underfunded by $427 million and our other postretirement benefits plans were underfunded by $235 million. Our pension and other postretirement benefit obligations and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the rate at which we expect the compensation of our employees to increase over the plan term, the estimated cost of health care when benefits are provided under our plan and other factors. A significant assumption we utilize is the discount rate used in calculating our benefit obligations. We select our discount rates by matching the timing and amount of our expected future benefit payments for our pension and other postretirement benefit obligations to the average yields of various high-quality bonds with corresponding maturities. The selection of these assumptions is further discussed in Note 9 “Share-based Compensation and Employee Benefits” to our consolidated financial statements. Actual results may differ from the assumptions included in these calculations, and as a result, our estimates associated with our pension and other postretirement benefits can be, and often are, revised in the future. The income statement impact of the changes in the assumptions on our related benefit obligations are deferred and amortized into income over either the period of 44 Table of Contents expected future service of active participants, or over the expected future lives of inactive plan participants. We record these deferred amounts as either accumulated other comprehensive income (loss) or as a regulatory asset or liability for certain of our regulated operations. As of December 31, 2014, we had deferred net losses of approximately $323 million in pretax accumulated other comprehensive loss and noncontrolling interests related to our pension and other postretirement benefits. The following table shows the impact of a 1% change in the primary assumptions used in our actuarial calculations associated with our pension and other postretirement benefits for the year ended December 31, 2014: Pension Benefits Change in funded status and pretax accumulated other comprehensive income (loss) Net benefit cost (income) Other Postretirement Benefits Change in funded status and pretax accumulated other comprehensive income (loss) Net benefit cost (income) (In millions) $ 260 $ — (13) — (312) — 12 — $ 10 (23) 2 — (11) 23 (1) — $ 2 (4) — 4 — 4 — (2) 55 — — (47) (65) — — 40 One percent increase in: Discount rates Expected return on plan assets Rate of compensation increase Health care cost trends One percent decrease in: Discount rates Expected return on plan assets Rate of compensation increase Health care cost trends _______ Income Taxes We record a valuation allowance to reduce our deferred tax assets to an amount that is more likely than not to be realized. While we have considered estimated future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance, any change in the amount that we expect to ultimately realize will be included in income in the period in which such a determination is reached. In addition, we do business in a number of states with differing laws concerning how income subject to each state’s tax structure is measured and at what effective rate such income is taxed. Therefore, we must make estimates of how our income will be apportioned among the various states in order to arrive at an overall effective tax rate. Changes in our effective rate, including any effect on previously recorded deferred taxes, are recorded in the period in which the need for such change is identified. In determining the deferred income tax asset and liability balances attributable to our investments, we have applied an accounting policy that looks through our investments. The application of this policy resulted in no deferred income taxes being provided on the difference between the book and tax basis on the non-tax-deductible goodwill portion of our investments. Results of Operations Non-GAAP Measures The non-GAAP financial measures, DCF before certain items and segment EBDA before certain items are presented below under “—Distributable Cash Flow” and “—Consolidated Earnings Results,” respectively. Certain items are items that are required by GAAP to be reflected in net income, but typically either do not have a cash impact, or by their nature are separately identifiable from our normal business operations and, in our view, are likely to occur only sporadically. Our non-GAAP measures described below should not be considered as an alternative to GAAP net income or any other GAAP measure. DCF before certain items and segment EBDA before certain items are not financial measures in accordance with GAAP and have important limitations as analytical tools. You should not consider either of these non-GAAP measures in 45 Table of Contents isolation or as substitutes for an analysis of our results as reported under GAAP. Because DCF before certain items excludes some but not all items that affect net income and because DCF measures are defined differently by different companies in our industry, our DCF before certain items may not be comparable to DCF measures of other companies. Our computation of segment EBDA before certain items has similar limitations. Management compensates for the limitations of these non-GAAP measures by reviewing our comparable GAAP measures, understanding the differences between the measures and taking this information into account in its analysis and its decision making processes. Distributable Cash Flow DCF before certain items is an overall performance metric we use to estimate the ability of our assets to generate cash flows on an ongoing basis and as a measure of cash available to pay dividends. We believe the primary measure of company performance used by us, investors and industry analysts is cash generation performance. Therefore, we believe DCF before certain items is an important measure to evaluate our operating and financial performance and to compare it with the performance of other publicly traded companies within the industry. For a discussion of our anticipated dividends for 2015, see “—Financial Condition—Cash Flows—KMI Dividends.” The table below details the reconciliation of Net Income to DCF before certain items: 2014 Year Ended December 31, 2013 (In millions) 2,692 $ $ 2,443 2012 Net Income Add/(Subtract): Certain items before book tax(a) Book tax certain items Certain items after book tax Net income before certain items Add/(Subtract): Net income attributable to third-party noncontrolling interests(b) Depreciation, depletion and amortization(c) Book taxes(d) Cash taxes(d) Declared distributions to noncontrolling interests(e) Sustaining capital expenditures(f) Other, net(g) Subtotal DCF before certain items Weighted Average Shares Outstanding for Dividends(h) DCF per share before certain items Declared dividend per common share $ $ $ 14 (117) (103) 2,340 (12) 2,390 840 (448) (2,000) (509) 17 278 2,618 1,312 2.00 1.74 $ $ (609) (39) (648) 2,044 (5) 2,142 847 (552) (2,355) (414) 6 (331) 1,713 1,040 1.65 1.60 $ $ 427 1,692 (412) 1,280 1,707 (1) 1,678 584 (460) (1,797) (393) 93 (296) 1,411 908 1.55 1.40 _______ (a) Consists of certain items summarized in footnotes (b) through (e) to the “—Consolidated Earnings Results” table included below, and described in more detail below in the footnotes to tables included in both our management’s discussion and analysis of segment results and “—General and Administrative, Interest, and Noncontrolling Interests.” (b) Represents net income allocated to third-party ownership interests in consolidated subsidiaries other than our former Master Limited Partnerships. (c) Includes DD&A, amortization of excess cost of equity investments and our share of equity method investee’s DD&A of $305 million, $297 million and $236 million in 2014, 2013 and 2012, respectively. (d) Includes our share of equity method investee’s book or cash income taxes. (e) Represents distributions to KMP and EPB limited partner units formerly owned by the public. (f) Includes our share of equity method investee’s sustaining capital expenditures of $(59) million, $(48) million and $(51) million in 2014, 2013 and 2012, respectively. (g) Consists primarily of book to cash timing differences related to certain defined benefit plans and other items, and for periods prior to fourth quarter 2014 includes differences between earnings and cash from our former Master Limited Partnerships. 46 Table of Contents (h) Includes restricted shares that participate in dividends. 2014 includes the shares issued on November 26, 2014 for the Merger Transactions as if outstanding for the entire fourth quarter which differs from our GAAP presentation on our Consolidated Statement of Income. Consolidated Earnings Results With regard to our reportable business segments, we consider segment earnings before all DD&A expenses, and amortization of excess cost of equity investments (defined in the “—Results of Operations” tables below and sometimes referred to in this report as EBDA) to be an important measure of our success in maximizing returns to our shareholders. We also use segment EBDA internally as a measure of profit and loss used for evaluating segment performance and for deciding how to allocate resources to our six reportable business segments. EBDA may not be comparable to measures used by other companies. Additionally, EBDA should be considered in conjunction with net income and other performance measures such as operating income, income from continuing operations or operating cash flows. Certain items included in EBDA are either not allocated to business segments or are not considered by management in its evaluation of business segment performance. In general, the items not included in segment results are interest expense, general and administrative expenses, DD&A and unallocable income taxes. These items are not controllable by our business segment operating managers and therefore are not included when we measure business segment operating performance. Our general and administrative expenses include such items as employee benefits insurance, rentals, unallocated litigation and environmental expenses, and shared corporate services-including accounting, information technology, human resources and legal services. We currently evaluate business segment performance primarily based on segment EBDA in relation to the level of capital employed. We consider each period’s EBDA to be an important measure of business segment performance for our segments. We account for intersegment sales at market prices. 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 income statement of the combined entity. Year Ended December 31, 2014 2013 2012 (In millions) Segment EBDA(a) Natural Gas Pipelines CO2 Terminals Products Pipelines Kinder Morgan Canada Other Total Segment EBDA(b) DD&A expense Amortization of excess cost of equity investments Other revenues General and administrative expenses(c) Interest expense, net of unallocable interest income(d) Income from continuing operations before unallocable income taxes Unallocable income tax expense Income from continuing operations Loss from discontinued operations, net of tax(e) Net income Net income attributable to noncontrolling interests Net income attributable to Kinder Morgan, Inc. $ 47 $ 4,259 $ 4,207 $ 1,240 944 856 182 13 7,494 (2,040) (45) 36 (610) (1,807) 3,028 (585) 2,443 — 2,443 (1,417) 1,026 $ 1,435 836 602 424 (5) 7,499 (1,806) (39) 36 (613) (1,688) 3,389 (693) 2,696 (4) 2,692 (1,499) 1,193 $ 2,174 1,322 708 668 229 7 5,108 (1,419) (23) 35 (929) (1,441) 1,331 (127) 1,204 (777) 427 (112) 315 Table of Contents _______ (a) Includes revenues, earnings from equity investments, allocable interest income and other, net, less operating expenses, allocable income taxes, and other income (expense). Operating expenses include natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes. Allocable income tax expenses included in segment earnings for the years ended December 31, 2014, 2013 and 2012 were $63 million, $49 million and $12 million, respectively. Certain item footnotes (b) 2014, 2013 and 2012 amounts include decrease in earnings of $45 million, increase in earnings of $573 million, and decrease in earnings of $295 million, respectively, related to the combined effect from all of the 2014, 2013 and 2012 certain items impacting continuing operations and disclosed below in our management discussion and analysis of segment results. (c) 2014 and 2013 amounts include decrease to expense of $28 million and $8 million, and 2012 amount includes increase in expense of $366 million, respectively, related to the combined effect from all of the 2014, 2013 and 2012 certain items related to general and administrative expenses disclosed below in “—General and Administrative, Interest, and Noncontrolling Interests.” (d) 2014 and 2013 amounts include decrease in expense of $3 million and $32 million and 2012 amount includes increase in expense of $87 million, respectively, related to the combined effect from all of the 2014, 2013 and 2012 certain items related to interest expense, net of unallocable interest income disclosed below in “—General and Administrative, Interest, and Noncontrolling Interests.” (e) 2013 amount represents an incremental loss related to the sale of our FTC Natural Gas Pipelines disposal group effective November 1, 2012. 2012 amount includes a combined $937 million loss from the remeasurement of net assets to fair value and the sale of our disposal group and DD&A expense of $7 million. Year Ended December 31, 2014 vs. 2013 The certain items described in footnotes (b), (c) and (d) to the tables above accounted for $627 million decrease in income from continuing operations before unallocable income taxes in 2014, when compared to 2013 (combining to decrease total income from continuing operations before unallocable income taxes by $14 million for 2014 and increase total income from continuing operations before unallocable income taxes by $613 million for 2013). The $266 million (10%) period-to-period increase in income from continuing operations before unallocable income taxes remaining, after giving effect to these certain items, reflects better overall performance primarily from our Natural Gas Pipelines, Products Pipelines and Terminals segments in 2014. Year Ended December 31, 2013 vs. 2012 The certain items described in footnotes (b), (c) and (d) to the tables above accounted for $1,361 million increase in income from continuing operations before unallocable income taxes in 2013, when compared to 2012 (combining to increase total income from continuing operations before unallocable income taxes by $613 million for 2013 and decrease total income from continuing operations before unallocable income taxes by $748 million for 2012). The $697 million (34%) period-to- period increase in income from continuing operations before unallocable income taxes remaining, after giving effect to these certain items, reflects better overall performance from our segments in 2013 driven by our Natural Gas Pipelines segment (primarily due to a full year of contributions from the EP operations). 48 Table of Contents Natural Gas Pipelines Revenues(a)(c) Operating expenses Other income (expense) Earnings from equity investments Interest income and Other, net Income tax expense EBDA from continuing operations(b) Discontinued operations(c) Certain items(a)(b)(c) EBDA before certain items Change from prior period Revenues before certain items(a) EBDA before certain items Natural gas transport volumes (BBtu/d)(d) Natural gas sales volumes (BBtu/d)(e) Natural gas gathering volumes (BBtu/d)(f) Year Ended December 31, 2014 2013 2012 (In millions, except operating statistics) $ $ $ $ 10,168 (6,241) (5) 318 25 (6) 4,259 — (190) 4,069 $ $ $ 8,617 (5,235) 24 232 578 (9) 4,207 (4) (486) 3,717 $ Increase/(Decrease) 1,339 352 $ $ 32,627 2,334 3,080 3,176 1,174 30,647 2,458 2,959 5,230 (3,111) (14) 52 22 (5) 2,174 (770) 1,139 2,543 31,650 2,402 2,996 _______ Certain item footnotes (a) 2014 amount includes a $198 million increase in revenue and earnings associated with the early termination charge of a long-term natural gas transportation contract from a certain customer on our Kinder Morgan Louisiana pipeline system. 2014 and 2013 amounts include $2 million and $16 million decreases, respectively, related to derivative contracts used to hedge forecasted natural gas, NGL and crude oil sales. (b) 2014 and 2013 amounts include $190 million and $490 million increases in earnings and 2012 amount includes a $202 million decrease in earnings, respectively, related to the combined effect from certain items. 2014 amount consists of (i) $198 million increase in earnings related to the early termination of a natural gas transportation contact, as described in footnote (a); (ii) $3 million loss related to sale of certain Gulf Coast offshore and onshore TGP supply facilities; and (iii) a combined $5 million decrease in earnings from other certain items. 2013 amount consists of (i) a $558 million gain from the remeasurement of a previously held 50% equity interest in Eagle Ford to fair value; (ii) a $36 million gain from the sale of certain Gulf Coast offshore and onshore TGP supply facilities; (iii) a $16 million decrease in earnings related to derivative contracts, as described in footnote (a); and (iv) a combined $23 million decrease in earnings from other certain items. 2013 and 2012 amounts include $65 million and $200 million, respectively, non-cash equity investment impairment charges related to our 20% ownership interest in NGPL Holdco LLC. 2012 amount also consists of a combined $2 million decrease in earnings from other certain items. (c) Represents EBDA attributable to the FTC Natural Gas Pipelines disposal group. 2013 amount represents a loss from the sale of net assets. 2012 amount includes (i) a combined loss of $937 million from the remeasurement of net assets to fair value and the sale of net assets; (ii) $167 million of EBDA (which included revenues of $227 million); and (iii) $7 million of DD&A expense from discontinued operations. Other footnotes (d) Includes pipeline volumes for TransColorado Gas Transmission Company LLC, MEP, Kinder Morgan Louisiana Pipeline LLC, FEP, TGP, EPNG, Copano South Texas, the Texas intrastate natural gas pipeline group, CIG, WIC, CPG, SNG, Elba Express, NGPL, Citrus and Ruby Pipeline, L.L.C. Volumes for acquired pipelines are included for all periods. However, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition. (e) Represents volumes for the Texas intrastate natural gas pipeline group. (f) Includes Copano operations, EP midstream assets operations, KinderHawk, Endeavor, Bighorn Gas Gathering L.L.C., Webb Duval Gatherers, Fort Union Gas Gathering L.L.C., EagleHawk, and Red Cedar Gathering Company throughput volumes. Joint venture throughput is reported at our ownership share. Volumes for acquired pipelines are included for all periods. 49 Table of Contents Following is information, including discontinued operations, related to the increases and decreases in both EBDA and revenues before certain items in 2014 and 2013, when compared with the respective prior year: Year Ended December 31, 2014 versus Year Ended December 31, 2013 Copano operations (including Eagle Ford)(a) $ TGP EPNG Ruby(b) Citrus(b) Texas Intrastate Natural Gas Pipeline Group WIC SNG All others (including eliminations) Total Natural Gas Pipelines $ EBDA increase/(decrease) Revenues increase/(decrease) (In millions, except percentages) 163 121 37 18 13 11 (24) (17) 30 352 n/a 15% 10% 199% 15% 3% (17)% (4)% 3% 9% $ $ 998 151 59 n/a n/a 432 (26) (25) (250) 1,339 n/a 14% 11% n/a n/a 12% (15)% (4)% (24)% 16% _______ n/a - not applicable (a) On May 1, 2013, as part of Copano acquisition, we acquired the remaining 50% interest of Eagle Ford. Prior to that date, we recorded earnings from Eagle Ford under the equity method of accounting, but we received distributions in amounts essentially equal to equity earnings plus our share of depreciation and amortization expenses less our share of sustaining capital expenditures (those capital expenditures which do not increase the capacity or throughput). (b) Equity investment. The significant changes in our Natural Gas Pipelines business segment’s EBDA before certain items in the comparable years of 2014 and 2013 included the following: • • • • • • • • increase of $163 million from full year ownership of our Copano operations, which we acquired effective May 1, 2013, including benefits from higher gathering volumes from the Eagle Ford Shale; increase of $121 million (15%) from TGP primarily due to higher revenues from (i) firm transportation and storage services due largely to new expansion projects placed in service in the latter part of 2013 and during 2014 and (ii) usage and interruptible transportation services due to weather-related demand relative to 2013. Partially offsetting the increase in 2014 revenues were higher operating and franchise tax expenses in 2014, and a favorable operational sales margin in 2013; increase of $37 million (10%) from EPNG, primarily driven by higher transportation revenues and throughput due to increased deliveries to California for storage refill and increased demand in Mexico. The increase in revenues was partially offset by higher field operation and maintenance expenses; increase of $18 million (199%) from Ruby due largely to higher contracted firm transportation revenues and lower interest expense; increase of $13 million (15%) from Citrus assets, primarily due to higher transportation revenues and reduction in property taxes; increase of $11 million (3%) from Texas Intrastate Natural Gas Pipeline Group (including the operations of its Kinder Morgan Tejas, Border, Kinder Morgan Texas, North Texas and Mier-Monterrey Mexico pipeline systems), due largely to higher natural gas sales and transportation margins driven by higher volumes, additional customer contracts and colder weather in the first quarter of 2014, which were offset by lower processing margin due to non-renewal of a certain contract; decrease of $24 million (17%) from WIC, primarily due to lower reservation revenue as a result of rate reductions pursuant to its FERC Section 5 rate settlement effective November 1, 2013 and lower rates on contract renewals; and decrease of $17 million (4%) from SNG, driven by lower reservation and usage revenues due to rate reductions pursuant to its rate case settlement effective September 1, 2013; partially offset by incremental revenues from increased firm transportation services and revenue related to an expansion project that was placed in service in late 2013. 50 Table of Contents Year Ended December 31, 2013 versus Year Ended December 31, 2012 TGP $ Copano operations (including Eagle Ford)(a) EPNG SNG CIG SLNG WIC EP midstream asset operations Elba Express CPG Citrus(b) All others (including eliminations) Total Natural Gas Pipelines - continuing operations Discontinued operations(c) Total Natural Gas Pipelines - including discontinued operations EBDA increase/(decrease) Revenues increase/(decrease) (In millions, except percentages) $ 358 289 151 129 129 66 54 46 43 35 32 9 1,341 (167) 81% n/a 68% 40% 78% 82% 61% 118% 122% 75% 62% 1% 56% (100)% 440 1,538 217 239 165 65 53 81 43 40 n/a 522 3,403 (227) 73% n/a 72% 67% 71% 62% 43% 89% 111% 65% n/a 350% 65% (100)% $ 1,174 46% $ 3,176 58% _______ n/a – not applicable (a) On May 1, 2013, as part of our Copano acquisition, we acquired the remaining 50% interest of Eagle Ford. Prior to that date, we recorded earnings from Eagle Ford under the equity method of accounting, but we received distributions in amounts essentially equal to equity earnings plus our share of depreciation and amortization expenses less our share of sustaining capital expenditures (those capital expenditures which do not increase the capacity or throughput). (b) Equity investment. (c) Represents amounts attributable to the FTC Natural Gas Pipelines disposal group. The significant changes in the Natural Gas Pipelines business segment’s EBDA before certain items in the comparable years of 2013 and 2012 included the following: • • incremental earnings of $1,043 million associated with full-year contributions from assets acquired from EP, which was acquired effective May 25, 2012, including earnings from TGP, EPNG, SNG, CIG, SLNG, WIC, EP midstream asset operations, Elba Express, CPG and Citrus; and incremental earnings of $289 million from the Copano operations, which we acquired effective May 1, 2013. The period-to-period decreases in EBDA from discontinued operations were due to the sale of the FTC Natural Gas Pipelines disposal group effective November 1, 2012. For further information about this sale, see Note 3 “Acquisitions and Divestitures—Divestitures—FTC Natural Gas Pipelines Disposal Group—Discontinued Operations” to our consolidated financial statements. 51 Table of Contents CO2 Revenues(a) Operating expenses Other (loss) income Earnings from equity investments Interest income and Other, net Income tax expense EBDA(b) Certain items(a)(b) EBDA before certain items Change from prior period Revenues before certain items(a) EBDA before certain items Southwest Colorado CO2 production (gross) (Bcf/d)(c) Southwest Colorado CO2 production (net) (Bcf/d)(c) SACROC oil production (gross)(MBbl/d)(d) SACROC oil production (net)(MBbl/d)(e) Yates oil production (gross)(MBbl/d)(d) Yates oil production (net)(MBbl/d)(e) Katz oil production (gross)(MBbl/d)(d) Katz oil production (net)(MBbl/d)(e) Goldsmith Landreth oil production (gross)(MBbl/d)(d) Goldsmith Landreth oil production (net)(MBbl/d)(e) NGL sales volumes (net)(MBbl/d)(e) Realized weighted-average oil price per Bbl(f) Realized weighted-average NGL price per Bbl(g) $ $ $ $ $ $ Year Ended December 31, 2014 2013 2012 (In millions, except operating statistics) $ 1,960 (494) (243) 25 — (8) 1,240 218 1,458 $ 1,857 (439) — 24 — (7) 1,435 (3) 1,432 $ $ Increase/(Decrease) 81 26 $ $ 166 106 1.2 0.5 30.7 25.5 20.4 9.0 2.7 2.2 0.7 0.6 9.9 1.3 0.5 33.2 27.6 19.5 8.8 3.6 3.0 1.3 1.1 10.1 88.41 41.87 $ $ 1,677 (381) 7 25 (1) (5) 1,322 4 1,326 1.2 0.5 29.0 24.1 20.8 9.3 1.7 1.4 — — 9.5 92.70 46.43 $ $ 87.72 50.95 _______ Certain item footnotes (a) 2014 and 2013 amounts include unrealized gains of $25 million and $3 million, and 2012 amount includes unrealized losses of $11 million, respectively, all relating to derivative contracts used to hedge forecasted crude oil sales. (b) 2014 amount includes certain items of a $218 million decrease in earnings (consists of impairment charge of $235 million related primarily to the Katz Strawn unit, an exploration charge of $8 million related to our Wolfcamp operation and a $25 million gain discussed in footnote (a) above). 2013 amount includes a $3 million increase in earnings discussed in footnote (a) above. 2012 amount includes $4 million decrease in earnings (consists of $11 million loss discussed in footnote (a) above and $7 million gain from the sale of our ownership interest in the Claytonville oil field unit), respectively. Other footnotes (c) Includes McElmo Dome and Doe Canyon sales volumes. (d) Represents 100% of the production from the field. We own approximately 97% working interest in the SACROC unit, an approximately 50% working interest in the Yates unit, an approximately 99% working interest in the Katz unit and a 99% working interest in the Goldsmith Landreth unit. (e) Net after royalties and outside working interests. (f) Includes all crude oil production properties. (g) Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements. 52 Table of Contents The CO2 business segment’s primary businesses involve the production, marketing and transportation of both CO2 and crude oil, and the production and marketing of natural gas and NGL. We refer to the segment’s two primary businesses as its Oil and Gas Producing Activities and its Source and Transportation Activities for each of these two primary businesses, following is information related to the increases and decreases in both EBDA and revenues before certain items in 2014 and 2013, when compared with the respective prior year: Year Ended December 31, 2014 versus Year Ended December 31, 2013 Source and Transportation Activities Oil and Gas Producing Activities Intrasegment eliminations Total CO2 _______ EBDA increase/(decrease) Revenues increase/(decrease) (In millions, except percentages) $ $ 56 (30) — 26 14% (3)% —% 2% $ $ 59 26 (4) 81 13% 2% 5% 4% The primary increases in the source and transportation activities’ EBDA and revenues before certain items in the comparable years of 2014 and 2013 included the following: • EBDA increase of $56 million (14%) driven primarily by higher revenues (described following), partly offset by • higher labor costs, power costs, property taxes and severance taxes; and a revenue increase of $59 million (13%) driven primarily by an increase of 8% in average CO2 contract prices. The increase in contract prices were due primarily to two factors: (i) a change in the mix of contracts resulting in more CO2 being delivered under higher price contracts and (ii) heavier weighting of new CO2 contract prices to the price of crude oil. CO2 volumes were also higher by 7% when compared to the period in 2013, primarily due to expansion projects at our Doe Canyon field placed in service in the fourth quarter of 2013. The primary changes in the oil and gas producing activities’ EBDA and revenues before certain items in the comparable years of 2014 and 2013 included the following: • EBDA decrease of $30 million (3%) driven by higher operating expenses as a result of (i) incremental well work costs at our recently acquired Goldsmith Landreth unit; (ii) increased power costs; and (iii) higher property and severance tax expenses related to higher revenues (described following). Also contributing to lower EBDA for the comparable period was lower crude oil and NGL prices, which were offset by improved net crude oil production of 8%; and a $26 million (2%) increase in revenues, driven primarily by an 8% increase in crude oil sales volumes. The increase in sales volumes was due primarily to higher production at the Katz unit, incremental production from the Goldsmith Landreth unit (acquired effective June 1, 2013), and higher production at the SACROC unit (volumes presented in the results of operations table above). The increase in revenues was offset in part by a 5% decrease in the realized weighted average price per barrel of crude oil and a 10% decrease in NGL prices. • Year Ended December 31, 2013 versus Year Ended December 31, 2012 Oil and Gas Producing Activities Source and Transportation Activities Intrasegment Eliminations Total CO2 _______ EBDA increase/(decrease) Revenues increase/(decrease) (In millions, except percentages) $ $ 74 32 — 106 8% 9% — 8% $ $ 144 40 (18) 166 11% 10% (23)% 10% The primary increases in the oil and gas producing activities’ EBDA and revenues before certain items in the comparable years of 2013 and 2012 included the following: • EBDA increase of $74 million (8%) was driven by (i) a $144 million (11%) increase in crude oil sales revenues, due primarily to higher average realized sales prices for U.S. crude oil and partly due to higher oil sales volumes. Our realized weighted average price per barrel of crude oil increased 6% in 2013 versus 2012. The overall increase in oil sales revenues were also favorably impacted by a 7% increase in crude oil sales volumes, due primarily to both higher 53 Table of Contents production from the Katz and SACROC field units, and to incremental production from the Goldsmith Landreth unit, which we acquired effective June 1, 2013 (volumes presented in the results of operations table above); (ii) a $65 million (20%) increase in operating expenses resulting primarily from higher fuel and power expenses, and higher maintenance and well workover expenses, all related to both increased drilling activity in 2013 and incremental expenses associated with the Goldsmith Landreth field unit; and (iii) a $9 million decrease in natural gas plant products sales due to a 9% decrease in our realized weighted average price per barrel of NGL, partially offset by a 4% increase in sales volumes. The primary increases in the source and transportation activities’ EBDA and revenues before certain items in the comparable years of 2013 and 2012 included the following: • EBDA increase of $32 million (9%) and revenue increase of $40 million (10%) were primarily driven by (i) higher CO2 sales revenues, due to an almost 10% increase in average sales prices; (ii) higher reimbursable project revenues, largely related to the completion of prior expansion projects on the Central Basin pipeline system; and (iii) higher third party storage revenues at the Yates field unit. Terminals Revenues(a) Operating expenses Other (expense) income Earnings from equity investments Interest income and Other, net Income tax expense EBDA(a) Certain items, net(a) EBDA before certain items Change from prior period Revenues before certain items(a) EBDA before certain items Bulk transload tonnage (MMtons)(b) Ethanol (MMBbl) Liquids leaseable capacity (MMBbl) Liquids utilization %(c) $ $ $ $ Year Ended December 31, 2014 2013 2012 (In millions, except operating statistics) 1,718 (746) (29) 18 12 (29) 944 35 979 $ $ 298 181 $ $ 88.0 71.8 78.0 95.3% $ $ 1,359 (685) 14 21 2 (3) 708 44 752 1,410 (657) 74 22 1 (14) 836 (38) 798 43 46 89.9 65.0 68.0 94.6% 97.5 65.3 60.4 92.8% Increase/(Decrease) _______ Certain item footnotes (a) 2014 amount includes (i) an $18 million increase in revenues from the amortization of deferred credits (associated with below market contracts assumed upon acquisition) from our Jones Act tankers acquired effective January 17, 2014 (APT acquisition); (ii) a $29 million write-down associated with a pending sale of certain terminals to a third-party; (iii) a $12 million increase in expenses due to hurricane clean-up and repair activities at our New York Harbor and Mid-Atlantic terminals; and (iv) a $12 million increase in expense associated with a liability adjustment related to a certain litigation matter. 2013 amount includes (i) a $109 million increase in earnings from casualty indemnification gains; (ii) a $59 million increase in clean-up and repair expense, all related to 2012 hurricane activity at the New York Harbor and Mid-Atlantic terminals; and (iii) a combined $12 million decrease of earnings from other certain items (which includes a $8 million increase in revenues related to hurricane reimbursements). 2012 amount includes a $51 million increase in expense related to hurricanes Sandy and Isaac clean-up and repair activities and the associated write-off of damaged assets, a $12 million casualty indemnification gain related to a 2010 casualty at the Myrtle Grove, Louisiana, International Marine Terminal facility and a combined $5 million decrease of earnings from other certain items. Other footnotes (b) Volumes for acquired terminals are included for all periods and include our proportionate share of joint venture tonnage. (c) The ratio of our actual leased capacity to its estimated potential capacity. 54 Table of Contents The Terminals business segment includes the transportation, transloading and storing of petroleum products, crude oil, condensate (other than those included in the Products Pipelines segment), and bulk products, including coal, petroleum coke, cement, alumina, salt and other bulk chemicals. The bulk and liquids terminal operations are grouped into regions based on geographic location and/or primary operating function. This structure allows the management to organize and evaluate segment performance and to help make operating decisions and allocate resources. Following is information related to the increases and decreases in both EBDA and revenues before certain items in 2014 and 2013, when compared with the respective prior year: Year Ended December 31, 2014 versus Year Ended December 31, 2013 Acquired assets and businesses West Gulf Central Gulf Liquids Gulf Bulk All others (including intrasegment eliminations and unallocated income tax expenses) Total Terminals $ $ EBDA increase/(decrease) Revenues increase/(decrease) (In millions, except percentages) 66 32 30 20 19 14 181 n/a 45% 213% 10% 25% 3% 23% $ $ 109 49 51 22 26 41 298 n/a 38% 663% 8% 19% 5% 21% The primary changes in the Terminals business segment’s EBDA before certain items in the comparable years of 2014 and 2013 included the following: • • • • • • increase of $66 million from acquired assets and businesses, primarily the acquisition of the Jones Act tankers; increase of $32 million (45%) from our West region terminals, driven by the completion of Edmonton expansion projects; increase of $30 million (213%) from our Gulf Central terminals, driven by higher earnings from our 55% owned Battleground Oil Specialty Terminal Company LLC (BOSTCO) oil terminal joint venture, which is located on the Houston Ship Channel and began operations in October 2013; increase of $20 million (10%) from our Gulf Liquids terminals, due to higher liquids warehousing revenues from our Pasadena and Galena Park liquids facilities located along the Houston Ship Channel. The facilities benefited from high gasoline export demand, increased rail services and new and incremental customer agreements at higher rates, due in part to new tankage from completed expansion projects; increase of $19 million (25%) from our Gulf Bulk terminals, driven by increased revenue from take-or-pay coal contracts and higher petcoke period-to-period volumes in 2014, due largely to refinery and coker shutdowns in 2013 as a result of turnarounds taken; and increase of $14 million (3%) from the rest of the terminal operations was driven primarily by increased shortfall revenue recognized on take-or-pay contracts at out International Marine Terminal in Myrtle Grove, Louisiana and earnings from the BP Whiting terminal in Whiting, Indiana which was placed in service in the third quarter of 2013. Year Ended December 31, 2013 versus Year Ended December 31, 20 EBDA increase/(decrease) Revenues increase/(decrease) (In millions, except percentages) 21 15 9 1 46 11% 24% 18% —% 6% $ $ 34 7 14 (12) 43 14% 5% 11% 1% 3% Gulf Liquids Rivers Midwest All others (including intrasegment eliminations and unallocated income tax expenses) Total Terminals _______ $ $ 55 Table of Contents The primary changes in the Terminals business segment’s EBDA before certain items in the comparable years of 2013 and 2012 included the following: • • • increase of $21 million (11%) from our Gulf Liquids terminals, primarily due to higher liquids revenues from our Pasadena and Galena Park liquids facilities located along the Houston Ship Channel. The facilities benefited from high gasoline export demand, increased rail services, and new and incremental customer agreements at higher rates. For all terminals included in the Terminals business segment, total liquids leaseable capacity increased to 68.0 MMBbl at year-end 2013, up 12.6% from a capacity of 60.4 MMBbl at the end of 2012. The increase in capacity was mainly due to the acquisition of Norfolk and Chesapeake, Virginia facilities from Allied Terminals in June 2013 (incremental contributions from these two terminals are included within the “All others” line in the table above), and the partial in- service of BOSTCO and Edmonton Tank expansion projects. At the same time, Terminals’ overall liquids utilization rate increased 1.8% since the end of 2012; increase of $15 million (24%) from our Rivers region terminals due to the IMT Phase I and II expansion projects at International Marine Terminal (located at Myrtle Grove, Louisiana, near the mouth of the Mississippi River) being placed in service in March 2013. The region also benefited from lower operating and maintenance costs; and increase of $9 million (18%) from our Midwest region terminals, primarily driven by the opening of the BP Whiting terminal (Whiting Indiana) in August 2013. Salt and ethanol volumes increases also contributed to the overall improvement. Year Ended December 31, 2014 2013 2012 (In millions, except operating statistics) Products Pipelines Revenues Operating expenses Other income (expense) Earnings from equity investments Interest income and Other, net Income tax (expense) benefit EBDA(a) Certain items, net(a) EBDA before certain items Change from prior period Revenues EBDA before certain items $ $ $ $ $ 2,068 (1,258) 3 44 1 (2) 856 4 860 $ Increase/(Decrease) 215 76 $ $ Gasoline (MMBbl) (b) Diesel fuel (MMBbl) Jet fuel (MMBbl) Total refined product volumes (MMBbl)(c) NGL (MMBbl)(d) Condensate (MMBbl)(e) Total delivery volumes (MMBbl) Ethanol (MMBbl)(f) 451.8 151.5 113.3 716.6 35.2 36.8 788.6 41.6 423.4 142.4 110.6 676.4 37.3 12.6 726.3 38.7 _______ Certain item footnote (a) 2014 amount includes a $4 million increase in expense associated with a certain Pacific operations litigation matter. 2013 amount includes (i) a $162 million increase in expense associated with rate case liability adjustments; (ii) a $15 million increase in expense associated with a legal liability adjustment related to a certain West Coast terminal environmental matter; and (iii) $5 million loss from the write-off of assets at our Los Angeles Harbor West Coast terminal. 2012 amount includes a $32 million increase in expense associated with environmental liability and environmental recoverable receivable adjustments and a combined $3 million decrease in earnings from other certain items. 56 1,853 (1,295) (6) 45 3 2 602 182 784 483 81 $ $ 1,370 (759) 5 39 11 2 668 35 703 395.3 141.5 110.6 647.4 31.7 1.4 680.5 33.1 Table of Contents Other footnotes (b) Volumes include ethanol pipeline volumes. (c) Includes Pacific, Plantation Pipe Line Company, Calnev, Central Florida and Parkway pipeline volumes. (d) Includes Cochin and Cypress pipeline volumes. (e) Includes Kinder Morgan Crude & Condensate and Double Eagle Pipeline LLC pipeline volumes. (f) Represents total ethanol volumes, including ethanol pipeline volumes included in gasoline volumes above. Following is information related to the increases and decreases in both EBDA and revenues before certain items in 2014 and 2013, when compared with the respective prior year: Year Ended December 31, 2014 versus Year Ended December 31, 2013 Crude & Condensate Pipeline Pacific operations Transmix operations All others (including eliminations) Total Products Pipelines _______ EBDA increase/(decrease) Revenues increase/(decrease) (In millions, except percentages) 67 36 (19) (8) 76 320% 13% (44)% (2)% 10% $ $ 89 25 92 9 215 402% 6% 10% 2% 12% $ $ The primary changes in the Products Pipelines business segment’s EBDA before certain items in the comparable years of 2014 and 2013 included the following: • • • increase of $67 million (320%) from Kinder Morgan Crude & Condensate Pipeline, driven primarily by an increase of pipeline throughput volumes to 81.0 MBbl/d as compared to 24.1 MBbl/d in 2013 (236%); increase of $36 million (13%) from our Pacific operations, due to higher service revenues driven by higher volumes and margins and lower operating expenses primarily due to lower rights-of-way expenses; and decrease of $19 million (44%) from our transmix processing operations, primarily driven by unfavorable inventory pricing. Year Ended December 31, 2013 versus Year Ended December 31, 2012 Transmix operations Cochin Pipeline Crude & Condensate Pipeline All others (including eliminations) Total Products Pipelines _______ n/a - not applicable EBDA increase/(decrease) Revenues increase/(decrease) (In millions, except percentages) $ $ 27 25 14 15 81 174% 34% n/a 2% 12% $ $ 406 33 19 25 483 82% 42% n/a 3% 35% The primary changes in the Products Pipelines business segment’s EBDA before certain items in 2013 compared to 2012 were attributable to the following: • • a $27 million (174%) increase from our transmix processing operations due to higher margins on processing volumes, incremental earnings from third-party sales of excess renewable identification numbers (RINS) (generated through its ethanol blending operations), and the recognition of unfavorable net carrying value adjustments to product inventory recognized in 2012. The period-to-period increases in revenues were mainly due to the expiration of certain transmix fee-based processing agreements since the end of the third quarter of 2012. Due to the expiration of these contracts, we now directly purchase incremental transmix volumes and sell incremental volumes of refined products, resulting in both higher revenues and higher costs of sales expenses; a $25 million (34%) increase from Cochin Pipeline primarily due to higher transportation revenues, driven by an overall 33% increase in pipeline throughput volumes, partly attributable to incremental ethane/propane volumes as a result of pipeline modification projects completed in June 2012; 57 Table of Contents • • incremental earnings of $14 million from Kinder Morgan Crude & Condensate Pipeline, which began transporting crude oil and condensate volumes from the Eagle Ford shale gas formation to multiple terminaling facilities along the Texas Gulf Coast in October 2012; and a $15 million (2%) increase from all other represents a number of small increases at various locations. Kinder Morgan Canada Revenues Operating expenses Earnings from equity investments Interest income and Other, net Income tax expense EBDA(a) Certain items, net(a) EBDA before certain items Change from prior period Revenues EBDA before certain items Year Ended December 31, 2014 2013 2012 (In millions, except operating statistics) $ 291 (106) — 15 (18) 182 — 182 $ 302 (110) 4 249 (21) 424 (224) 200 $ $ 311 (103) 5 17 (1) 229 — 229 Increase/(Decrease) (11) $ (18) $ (9) (29) $ $ $ $ Transport volumes (MMBbl)(b) 106.8 101.1 106.1 ______ Certain item footnote (a) 2013 amount includes a $224 million pre-tax gain from the sale of our equity and debt investments in the Express pipeline system. Other footnote (b) Represents Trans Mountain pipeline system volumes. The Kinder Morgan Canada business segment includes the operations of the Trans Mountain and Jet Fuel pipeline systems and until March 14, 2013, the effective date of sale, our one-third ownership interest in the Express crude oil pipeline system. Following is information related to increases and decreases in both EBDA and revenues before certain items in 2014 and 2013, when compared with the respective prior year: Year Ended December 31, 2014 versus Year Ended December 31, 2013 EBDA increase/(decrease) Revenues increase/(decrease) Express Pipeline(a) Trans Mountain Pipeline Total Kinder Morgan Canada $ $ (6) (12) (18) (44)% (In millions, except percentages) n/a (11) (11) (9)% (6)% $ $ n/a (4)% (4)% _______ n/a - not applicable (a) Amount consists of unrealized foreign currency gains/losses, net of book tax, on outstanding, short-term intercompany borrowings that were repaid in December 2014. We sold our debt and equity investments in Express Pipeline on March 14, 2013. For the comparable years of 2014 and 2013, the Trans Mountain Pipeline had a decrease in earnings of $12 million (6%) which was driven primarily by an unfavorable impact from foreign currency translation. Due to the weakening of the Canadian dollar since the end of the third quarter of 2013, we translated Canadian denominated income and expense amounts into fewer U.S. dollars in 2014. 58 Table of Contents Year Ended December 31, 2013 versus Year Ended December 31, 2012 EBDA increase/(decrease) Revenues increase/(decrease) Trans Mountain Pipeline Express Pipeline(a) Total Kinder Morgan Canada $ $ (24) (5) (29) (11)% (In millions, except percentages) (9) n/a (9) (13)% (28)% $ $ (3)% n/a (3)% ______ n/a - not applicable (a) We sold our debt and equity investments in Express Pipeline on March 14, 2013. Prior to the sale, the earnings from Express Pipeline were recorded under the equity method of accounting. The period-to-period decreases in EBDA from Express were primarily due to both lower equity earnings and lower interest income resulting from the sale of our equity and debt investments in Express effective March 14, 2013. The decreases in Trans Mountain’s earnings were driven by (i) higher income tax expenses (due largely to general increases in British Columbia’s income tax rates since the end of the third quarter of 2012); (ii) unfavorable impacts from foreign currency translation (due to the weakening of the Canadian dollar since the end of 2012, we translated Canadian denominated income and expense amounts into less U.S. dollars in 2013); and (iii) lower management incentive fees earned from the operation of the Express pipeline system (due to its sale in March 2013). The period-to-period decreases in Trans Mountain’s earnings were partially offset by incremental non-operating income from allowances for funds used during construction (representing an estimate of the cost of capital funded by equity contributions). Other Our other segment results are driven by activities from other miscellaneous assets and liabilities purchased in our 2012 EP acquisition that were not allocated to the above segments. This segment contributed earnings of $13 million, a loss of $5 million and earnings of $7 million for the years ended 2014, 2013 and 2012, respectively. However, 2014 and 2012 earnings include a certain item of $22 million increase in earnings and $10 million decrease in earnings, respectively, primarily related to our foreign operations. After taking into effect the certain item, the earnings for 2014 and 2013 decreased by $4 million and $22 million, respectively, when compared with the respective prior year. General and Administrative, Interest, and Noncontrolling Interests General and administrative expense(a)(c) Certain items(a) Management fee reimbursement(c) General and administrative expense before certain items Unallocable interest expense net of interest income and other, net(b) Certain items(b) Unallocable interest expense net of interest income and other, net, before certain items Net income attributable to noncontrolling interests Year Ended December 31, 2014 2013 2012 (In millions) 610 $ 613 $ 28 (36) 602 1,807 3 1,810 1,417 $ $ $ $ 8 (36) 585 1,688 32 1,720 1,499 $ $ $ $ $ $ $ $ $ 929 (366) (35) 528 1,441 (87) 1,354 112 _______ Certain item footnotes (a) 2014 amount includes a decrease in expense of $39 million related to pension credit income and a net increase of $11 million in expense for various other certain items. 2013 amount includes a decrease in expense of $59 million related to EP post-merger pension credits, partially offset by increases in expense of (i) $41 million related to asset and business acquisition costs and unallocated legal expenses and (ii) combined $10 million from other certain items primarily related to the EP acquisition. 2012 amount includes $366 million increase of pre-tax expense associated with the EP acquisition and EP Energy sale, which includes (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 recoveries; 59 Table of Contents (v) $29 million of other EP acquisition expenses; and (vi) a combined $14 million increase in expense from other certain items; partially offset by a $29 million benefit associated with pension income. (b) 2014, 2013 and 2012 amounts include $9 million, $21 million and $108 million of amortization of capitalized financing fees, almost all of which was associated with the EP acquisition financing. 2012 also includes amounts written-off due to debt repayment. 2014, 2013 and 2012 amounts include (i) $12 million, $14 million and $9 million, respectively, of interest expense on margin for marketing contracts and (ii) $65 million, $67 million and $29 million, respectively, of decreased interest expense related to debt fair value adjustments associated with the EP and Copano acquisitions. 2014 amount includes (i) $27 million of interest expense related to the Merger Transactions; and (ii) an increase in interest expense of $15 million associated with a certain Pacific operations litigation matter. 2014 and 2012 also include $1 million and $1 million decreases in expense, respectively, related to the combined effect from other certain items. Other footnote (c) 2014, 2013 and 2012 amounts include NGPL Holdco LLC general and administrative reimbursements of $36 million, $36 million and $35 million, respectively. These amounts were recorded to the “Product sales and other” caption in our accompanying consolidated statements of income with the offsetting expenses primarily included in the “General and administrative” expense caption in our accompanying consolidated statements of income. Items not attributable to any segment include general and administrative expenses, unallocable interest income and income tax expense, interest expense, and net income attributable to noncontrolling interests. Our general and administrative expenses include such items as unallocated salaries and employee-related expenses, employee benefits, payroll taxes, insurance, office supplies and rentals, unallocated litigation and environmental expenses, and shared corporate services including accounting, information technology, human resources and legal services. These expenses are generally not controllable by our business segment operating managers and therefore are not included when we measure business segment operating performance. For this reason, we do not specifically allocate our general and administrative expenses to the business segments. As discussed previously, we use segment EBDA internally as a measure of profit and loss to evaluate segment performance, and each of our segment’s EBDA includes all costs directly incurred by that segment. The increase in general and administrative expenses before certain items of $17 million and $57 million in 2014 and 2013 when compared with the respective prior year was primarily driven by the acquisition of Copano (effective May 1, 2013) and EP (effective May 25, 2012). Additional drivers were higher benefit costs, payroll taxes and segment labor expenses partially offset by lower costs on our corporate headquarters building and insurance costs. In the table above, we report our interest expense as “net,” meaning that we have subtracted unallocated interest income and capitalized interest from our total interest expense to arrive at one interest amount. Our consolidated interest expense net of interest income and other, net before certain items, increased $90 million and $366 million in 2014 and 2013, respectively, when compared with the respective prior year. The increase in interest expense in 2014 as compared to 2013 was primarily due to higher average debt balances as a result of capital expenditures, joint venture contributions and acquisitions that were made during 2014 and issuing $6 billion of debt primarily related to the Merger Transactions in November 2014. In addition, the increase was impacted by the refinancing of the short-term KMI credit facility debt with a $1.5 billion long-term debt issuance in November 2013, which had a higher interest rate. This increase in interest expense was partially offset by (i) lower average balances outstanding on our EP acquisition term loan as a result of its termination in November 2014 and (ii) lower interest rates on our credit facility and EP acquisition term loan as a result of the refinancing of these facilities in 2014. The increase in interest expense in 2013 as compared to respective prior year was primarily due to interest expense incurred from EP acquisition debt, debt assumed in the EP acquisition, and other business acquisitions, see Notes 3 “Acquisition and Divestitures” and Note 8 “Debt” to our consolidated financial statements. Also contributed to the increase in 2013 as compared to 2012 were higher effective interest rates and higher average borrowings which were largely due to the capital expenditures and joint venture contributions. For more information on the capital expenditures and capital contributions see “—Liquidity and Capital Resources.” We use interest rate swap agreements to transform a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of December 31, 2014, approximately 26% of our debt balances (excluding debt fair value adjustments) were subject to variable interest rates-either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. As of December 31, 2013, approximately 25% of our debt balances (excluding debt fair value adjustments) were subject to variable interest rates. For more information on our interest rate swaps, see Note 13 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements. Net income attributable to noncontrolling interests, represents the allocation of our consolidated net income attributable to all outstanding ownership interests in our consolidated subsidiaries that are not held by us. The $82 million decrease (5%) for 2014 as compared to 2013 was primarily due to our noncontrolling interests’ portion of (i) our 2013 $558 million pre-tax gain 60 Table of Contents from the remeasurement of our previously held 50% equity interest in Eagle Ford to fair value; and (ii) our 2013 $140 million after-tax gain on the sale of our investments in the Express pipeline system; which was partially offset by our noncontrolling interests’ portion of our 2014 $198 million pre-tax increase associated with the early termination of a long-term natural gas transportation contract on our Kinder Morgan Louisiana pipeline system and an increase in income allocated to noncontolling interests during the fourth quarter 2014 due to the elimination of the incentive distribution rights as a result of the Merger Transactions. The $1,387 million (1,238%) increase for 2013 as compared to 2012 was primarily due to our noncontrolling interests’ portion of (i) our 2013 $558 million gain from the remeasurement of our previously held 50% equity interest in Eagle Ford to fair value; (ii) our 2013 $140 million after-tax gain on the sale of our investments in the Express pipeline system; (iii) additional income from EP assets acquired in 2012; (iv) additional income from our 2013 acquisition of Copano; and (v) the 2012 non-cash loss of $937 million net of tax loss from both costs to sell and the remeasurement of FTC Natural Gas Pipeline disposal group net assets to fair value. Subsequent to the Merger Transactions, net income attributable to noncontrolling interests represents net income allocated to third-party ownership interests in consolidated subsidiaries. Prior to the Merger Transactions it also included net income allocated to KMP and EPB limited partner units formerly owned by the public. Income Taxes—Continuing Operations Year Ended December 31, 2014 versus Year Ended December 31, 2013 Our tax expense for income from continuing operations for the year ended December 31, 2014 was $648 million, as compared with 2013 income tax expense of $742 million. The $94 million decrease in tax expense is due primarily to (i) the tax impact of significantly lower pretax earnings in 2014 associated with our investment in KMP (primarily as a result of KMP’s 2014 recognition of a $235 million impairment of its CO2 assets compared to gains it recognized in 2013 of $558 million on remeasurement to fair value of its initial 50% interest in the Eagle Ford joint venture and $224 million on the sale of its one-third interest in the Express pipeline system); (ii) a 2014 worthless stock deduction related to our Brazil operations; and (iii) a 2013 decrease in our share of non tax-deductible goodwill associated with our investment in KMP (as a result of our change in ownership primarily due to KMP’s acquisition of Copano). These decreases are partially offset by (i) the tax benefit in 2013 of a decrease in the deferred state tax rate as a result of the drop-down of our 50% ownership interest in EPNG and midstream assets and KMP’s acquisition of Copano; (ii) 2013 adjustments to our income tax reserve for uncertain tax positions as a result of the settlement of legacy EP Internal Revenue Service audits; and (iii) the 2014 recording of a valuation allowance related to our investment in NGPL. Year Ended December 31, 2013 versus Year Ended December 31, 2012 Our tax expense for income from continuing operations for the year ended December 31, 2013 was $742 million, as compared with 2012 income tax expense of $139 million. The $603 million increase in tax expense is due primarily to (i) higher income in 2013 attributable to our investments in KMP and EPB as compared to 2012 and (ii) tax expense as a result of KMP’s 2013 sale of its one-third interest in the Express pipeline system. These increases are partially offset by a decrease in the deferred state tax rate as a result of the March 2013 drop-down transaction and KMP’s Copano acquisition. Liquidity and Capital Resources General As of December 31, 2014, we had a combined $315 million of “Cash and cash equivalents,” on our consolidated balance sheet, a decrease of $283 million (47%) from December 31, 2013. We believe our cash position and remaining borrowing capacity (discussed below in “—Short-term Liquidity”), and our access to financial resources are adequate to allow us to manage our day-to-day cash requirements and anticipated obligations. Our primary cash requirements, in addition to normal operating expenses, are for debt service, sustaining capital expenditures, expansion capital expenditures and quarterly dividends to our common shareholders. In general, we expect to fund: • cash dividends and sustaining capital expenditures with existing cash and cash flows from operating activities; • expansion capital expenditures and working capital deficits with retained cash, proceeds from divestitures, additional borrowings (including commercial paper issuances), and the issuance of additional common stock; • interest payments with cash flows from operating activities; and 61 Table of Contents • debt principal payments, as such debt principal payments become due, with proceeds from divestitures, additional borrowings or by the issuance of additional common stock. In addition to our results of operations, our debt and capital balances are affected by our financing activities, as discussed below in “—Financing Activities.” Cash provided from our operations is fairly stable across periods since a majority of our cash generated is fee based from a diversified portfolio of assets and is not sensitive to commodity prices. However, in our CO2 business segment, while we hedge the majority of our oil production, we do have exposure to unhedged volumes, a significant portion of which are NGL. Historically, our distributions to noncontrolling interests were primarily comprised of distributions made by KMP and EPB on their common units that were not owned by us. With the closing of the Merger Transactions, all the previously held equity securities of KMP, EPB and KMR are now owned by us. As partial consideration for the KMP, EPB and KMR equity securities that we did not already own as of the Merger Transactions date, we issued approximately 1,097 million KMI Class P common shares. We expect that dividends on KMI’s Class P common stock will be $2.00 per share for 2015. Also, see “— KMI Dividends.” Credit Ratings and Capital Market Liquidity Based on our historical record, we believe that our capital structure will continue to allow us to achieve our business objectives. We expect that our short-term liquidity needs will be met primarily through short-term borrowings. We are subject, however, to conditions in the equity and debt markets and there can be no assurance we will be able or willing to access the public or private markets for equity and/or long-term senior notes in the future. If we were unable or unwilling to access the capital markets, we would be required to either restrict expansion capital expenditures and/or potential future acquisitions or pursue debt financing alternatives, some of which could involve higher costs or negatively affect our and/or our subsidiaries’ credit ratings. Our short-term corporate debt rating is A-3, Prime-3 and F3 at Standard and Poor’s, Moody’s Investor Services and Fitch Ratings, Inc., respectively. The following table represents KMI’s and KMP’s senior unsecured debt ratings as of December 31, 2014. Rating agency Standard and Poor’s Moody’s Investor Services Fitch Ratings, Inc. _______ Short-term Liquidity Senior debt rating BBB- Baa3 BBB- Date of last change Outlook November 20, 2014 November 21, 2014 November 20, 2014 Stable Stable Stable As of December 31, 2014 our principal sources of short-term liquidity are (i) our $4.0 billion revolving credit facility and associated $4.0 billion commercial paper program (discussed following); and (ii) cash from operations. The loan commitments under our revolving credit facility can be used to fund borrowings for working capital and other general corporate purposes and also serve as a backup for our commercial paper program. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facility and have consistently generated strong cash flow from operations, providing a source of funds of $4,467 million and $4,122 million in 2014 and 2013, respectively (the year-to-year increase is discussed below in “Cash Flows—Operating Activities”). Effective upon the closing of the Merger Transactions on November 26, 2014, we replaced the prior KMI credit agreement, the KMP credit agreement and the EPB credit agreement with a 5-year, $4 billion revolving credit facility with a syndicate of lenders, which can be increased to $5 billion if certain circumstances are met. On November 26, 2014, we entered into a $4.0 billion commercial paper program. Borrowings under our commercial paper program and letters of credit reduce borrowings allowed under our credit facility. For additional information on our credit facility and commercial paper program, see Note 8 “Debt” to our consolidated financial statements. 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 62 Table of Contents 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. Our short-term debt as of December 31, 2014 was $2,717 million, primarily consisting of (i) $1,236 million combined outstanding borrowings under our $4 billion credit facility and $4 billion commercial paper program; (ii) $375 million in principal amount of 4.10% senior notes that mature November 15, 2015; (iii) $340 million in principal amount of 6.80% senior notes that mature November 15, 2015; (iv) $300 million in principal amount of 5.625% senior notes that mature February 15, 2015; and (v) $250 million in principal amount of 5.15% senior notes that mature March 1, 2015. We intend to refinance our short-term debt through additional credit facility borrowings, commercial paper borrowings, issuing new long-term debt, or with proceeds from asset sales. Our combined balance of short-term debt as of December 31, 2013 was $2,306 million. We had working capital (defined as current assets less current liabilities) deficits of $2,610 million and $2,207 million as of December 31, 2014 and 2013, respectively. Our current liabilities include short-term borrowings used to finance our expansion capital expenditures which are periodically replaced with long-term financing. The overall $403 million (18%) unfavorable change from year-end 2013 was primarily due to (i) a net increase in KMI’s credit facility and commercial paper borrowings; (ii) lower cash balances (described above); and (iii) an increase in the current portion of long-term debt. The overall increase in our working capital deficit was partially offset by the repayment of KMP’s commercial paper borrowings and the subsequent termination of the program. Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts, and changes in our combined cash and cash equivalent balances as a result of our equity issuances and our or our subsidiaries’ debt issuances (discussed below in “—Long-term Financing” and “— Capital Expenditures”). We employ a centralized cash management program for our U.S.-based bank accounts that concentrates the cash assets of our subsidiaries, their operating partnerships and their wholly-owned subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing. These programs provide that funds in excess of the daily needs of our subsidiaries, their operating partnerships and their wholly-owned subsidiaries are concentrated, consolidated or otherwise made available for use by other entities within the consolidated group. We place no material restrictions on the ability to move cash between entities, payment of intercompany balances or the ability to upstream dividends to parent companies other than restrictions that may be contained in agreements governing the indebtedness of those entities. Certain of our operating subsidiaries are subject to FERC-enacted reporting requirements for oil and natural gas pipeline companies that participate in cash management programs. FERC-regulated entities subject to these rules must, among other things, place their cash management agreements in writing, maintain current copies of the documents authorizing and supporting their cash management agreements, and file documentation establishing the cash management program with the FERC. Long-term Financing In addition to our principal sources of short-term liquidity listed above, we could meet our cash requirements through the issuance of long-term securities or additional common shares. Our equity offerings consist of the issuance of additional Class P common stock with a par value of $0.01 per share. Through an equity distribution agreement, we can issue and sell through or to our sales agents and/or principals shares of our Class P common stock from time to time up to an aggregate offering price of $5 billion. For more information on our equity issuances during 2014 and our equity distribution agreement, see Note 10, “Stockholders’ Equity” to our consolidated financial statements. From time to time, we issue long-term debt securities, often referred to as senior notes. All of our senior notes issued to date, other than those issued by certain of our subsidiaries, generally have very similar terms, except for interest rates, maturity dates and prepayment premiums. All of our fixed rate senior notes provide that the notes may be redeemed at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date, and, in most cases, plus a make-whole premium. As of December 31, 2014 and 2013, the aggregate principal amount outstanding of the various series of KMI’s senior notes (excluding our subsidiaries’ senior borrowings discussed below) was $11,438 million (including $6 billion issued in 2014 to fund the cash portion of consideration of the Merger Transactions), and $5,645 million, respectively. In addition, from time to time our subsidiaries, including KMP, TGP, EPNG, CIG, SNG and Copano, have issued long- term debt securities, often referred to as their senior notes. Most of the debt of our subsidiaries is unsecured; however a modest amount of secured debt has been incurred by our subsidiaries. As of December 31, 2014 and 2013, the total liability balance due on the various borrowings of our subsidiaries (including senior notes issued by KMP, TGP, EPNG, CIG, SNG and Copano) was $28,355 million and $25,889 million, respectively. 63 Table of Contents Furthermore, we and almost all of our direct and indirect wholly-owned domestic subsidiaries, are parties to a cross guaranty wherein we each guarantee the debt of each other. See Note 18 “Guarantee of Securities of Subsidiaries” to our consolidated financial statements. To date, our and our subsidiaries’ debt balances have not adversely affected our operations, our ability to grow or our ability to repay or refinance our indebtedness. For additional information about our debt-related transactions in 2014, see Note 8 “Debt” to our consolidated financial statements. For information about our interest rate risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.” Capital Structure We finance our expansion capital expenditures and acquisitions with a combination of equity and debt in order to maintain an approximate net debt to EBITDA ratio between 5.0 and 5.5. In the short-term, we may fund these expenditures from borrowings under our credit facility until the amount borrowed is of a sufficient size to cost effectively offer either debt, equity, or both. We achieve our variable rate exposure primarily by issuing long-term fixed rate debt and then swapping the fixed rate interest payments for variable rate interest payments and through the issuance of commercial paper or credit facility borrowings. Capital Expenditures We account for our capital expenditures in accordance with GAAP. We also distinguish between capital expenditures that are maintenance/sustaining capital expenditures and those that are expansion capital expenditures (which we also refer to as discretionary capital expenditures). Expansion capital expenditures are those expenditures which increase throughput or capacity from that which existed immediately prior to the addition or improvement, and are not deducted in calculating DCF (see “Results of Operations—Distributable Cash Flow”). With respect to our oil and gas producing activities, we classify a capital expenditure as an expansion capital expenditure if it is expected to increase capacity or throughput (i.e. production capacity) from the capacity or throughput immediately prior to the making or acquisition of such additions or improvements. Maintenance capital expenditures are those which maintain throughput or capacity. The distinction between maintenance and expansion capital expenditures is a physical determination rather than an economic one, irrespective of the amount by which the throughput or capacity is increased. Budgeting of maintenance capital expenditures is done annually on a bottom-up basis. For each of our assets, we budget for and make those maintenance capital expenditures that are necessary to maintain safe and efficient operations, meet customer needs and comply with our operating policies and applicable law. We may budget for and make additional maintenance capital expenditures that we expect to produce economic benefits such as increasing efficiency and/or lowering future expenses. Budgeting and approval of expansion capital expenditures are generally made periodically throughout the year on a project-by-project basis in response to specific investment opportunities identified by our business segments from which we generally expect to receive sufficient returns to justify the expenditures. Generally, the determination of whether a capital expenditure is classified as maintenance/sustaining or as expansion capital expenditures is made on a project level. The classification of our capital expenditures as expansion capital expenditures or as maintenance capital expenditures is made consistent with our accounting policies and is generally a straightforward process, but in certain circumstances can be a matter of management judgment and discretion . The classification has an impact on cash available to pay dividends because capital expenditures that are classified as expansion capital expenditures are not deducted from DCF, while those classified as maintenance capital expenditures are. See “—KMI Dividends.” Our capital expenditures for the year ended December 31, 2014, and the amount we expect to spend for 2015 to sustain and grow our business are as follows (in millions): Sustaining capital expenditures(a) Discretionary capital expenditures(b)(c) 2014 Expected 2015 $ $ 509 3,580 $ $ 586 4,381 _______ (a) 2014 and Expected 2015 amounts include $57 million and $82 million, respectively, for our proportionate share of sustaining capital expenditures of certain unconsolidated joint ventures. 64 Table of Contents (b) 2014 amount (i) includes $533 million of discretionary capital expenditures of unconsolidated joint ventures and acquisitions and (ii) excludes a combined $118 million net change from accrued capital expenditures, contractor retainage and amounts primarily related to contributions from noncontrolling interests to fund a portion of certain capital projects (c) Expected 2015 includes our contributions to certain unconsolidated joint ventures and small acquisitions, net of contributions estimated from unaffiliated joint venture partners for consolidated investments. Off Balance Sheet Arrangements We have invested in entities that are not consolidated in our financial statements. For information on our obligations with respect to these investments, as well as our obligations with respect to related letters of credit, see Note 12 “Commitments and Contingent Liabilities” to our consolidated financial statements. Additional information regarding the nature and business purpose of our investments is included in Note 6 “Investments” to our consolidated financial statements. Contractual Obligations and Commercial Commitments Payments due by period Total Less than 1 year 2-3 years 4-5 years (In millions) More than 5 years Contractual obligations: Debt borrowings-principal payments $ 41,029 $ 2,717 $ 4,743 $ 5,147 $ Interest payments(a) 29,438 2,203 4,077 3,512 Leases and rights-of-way obligations(b) Pension and postretirement welfare plans(c) Transportation, volume and storage agreements(d) Other obligations(e) Total Other commercial commitments: Standby letters of credit(f) Capital expenditures(g) 678 862 1,189 402 73,598 381 1,026 $ $ $ $ $ $ 97 75 162 153 5,407 350 1,026 $ $ $ 160 47 277 112 9,416 31 $ $ — $ 28,422 19,646 289 692 501 112 132 48 249 25 9,113 $ 49,662 — $ — $ — — _______ (a) Interest payment obligations exclude adjustments for interest rate swap agreements and assume no change in variable interest rates from those in effect at December 31, 2014. (b) Represents commitments pursuant to the terms of operating lease agreements and liabilities for rights-of-way. (c) Represents the amount by which the benefit obligations exceeded the fair value of fund assets for pension and other postretirement benefit plans at year-end. The payments by period include expected contributions to funded plans in 2015 and estimated benefit payments for unfunded plans in all years. (d) Primarily represents transportation agreements of $305 million, volume agreements of $498 million and storage agreements for capacity on third party and an affiliate pipeline systems of $257 million. (e) Primarily includes environmental liabilities related to sites that we own or have a contractual or legal obligation with a regulatory agency or property owner upon which we will perform remediation activities. These liabilities are included within “Other long-term liabilities and deferred credits” in our consolidated balance sheets. (f) The $381 million in letters of credit outstanding as of December 31, 2014 consisted of the following (i) $20 million under four letters of credit related to power and marketing purposes; (ii) $86 million under fourteen letters of credit for insurance purposes; (iii) a $100 million letter of credit that supports certain proceedings with the CPUC involving refined products tariff charges on the intrastate common carrier operations of our Pacific operations’ pipelines in the state of California; (iv) our $30 million guarantee under letters of credit totaling $46 million supporting our International Marine Terminals Partnership Plaquemines, Louisiana Port, Harbor, and Terminal Revenue Bonds; (v) a $34 million letter of credit supporting our pipeline and terminal operations in Canada; (vi) a $25 million letter of credit supporting our Kinder Morgan Liquids Terminals LLC New Jersey Economic Development Revenue Bonds; (vii) a $24 million letter of credit supporting our Kinder Morgan Operating L.P. “B” tax-exempt bonds; (viii) a $13 million letter of credit supporting Nassau County, Florida Ocean Highway and Port Authority tax-exempt bonds; and (ix) a combined $33 million in twenty-four letters of credit supporting environmental and other obligations of us and our subsidiaries. (g) Represents commitments for the purchase of plant, property and equipment as of December 31, 2014. 65 Table of Contents Cash Flows Operating Activities The net increase of $345 (8%) million in cash provided by operating activities in 2014 compared to 2013 was primarily attributable to: • • • • a $984 million increase in cash from overall higher net income after adjusting our period-to-period $249 million decrease in net income for non-cash items primarily consisting of the following: (i) 2013 gain on the remeasurement of our previous 50% equity investment in Eagle Ford; (ii) 2013 gain on sale of our investments in the Express pipeline system (see the discussion of these investments in Note 3 “Acquisitions and Divestitures” to our consolidated financial statements); (iii) 2014 loss on impairments on both our CO2 and terminal long-lived assets; (iv) DD&A expenses (including amortization of excess cost of equity investments); (v) deferred income tax expenses; (vi) gains from the sale or casualty of property, plant and equipment (see discussion above in “—Results of Operations”); (vii) the net activity of our equity method investees; and (viii) adjustments to accrued transportation rate case and legal liabilities; a $315 million decrease in cash associated with rate case reserve payments primarily driven by the 2014 CPUC settlement and refund payments; a $228 million decrease in cash associated with net changes in working capital items and non-current assets and liabilities. The decrease was primarily driven by a $195 million use of cash for income tax payments made during the first three quarters of 2014 (due to discrete events in the fourth quarter, we received a refund for these payments in the first quarter of 2015); lower cash flows from both natural gas storage and pipeline transportation system balancing, and lower net dock premiums and toll collections received from our Trans Mountain pipeline system customers. These decreases were partially offset by, among other things, higher cash inflows from favorable changes in the collection and payment of trade and related party receivables and payables (due primarily to the timing of invoices received from customers and paid to vendors and suppliers), and favorable changes in previously deferred reimbursable costs; and a $96 million decrease in cash from interest rate swap termination payments received. In 2013, we terminated, in three separate transactions, three existing fixed-to-variable interest rate swap agreements prior to their contractual maturity dates. Investing Activities The $2,088 million net increase in cash used in investing activities in 2014 compared to 2013 was primarily attributable to: • • • • a $1,096 million decrease in cash due to higher expenditures for acquisitions. The increase in acquisition expenditures was primarily related to the $1,231 million we paid in 2014 for our APT and Crowley tanker acquisitions, versus the $280 million we paid in 2013 to acquire the Goldsmith Landreth San Andres oil field unit (both discussed in Note 3 “Acquisitions and Divestitures”); a combined $490 million decrease in cash due to proceeds received in 2013 from divestitures, primarily consisting of our sale of the investments in the Express pipeline system; a $248 million decrease in cash due to higher capital expenditures in 2014 primarily reflecting higher investment undertaken to expand and improve our Products Pipelines and CO2 business segments; and a $172 million decrease in cash due to higher capital contributions, driven by a $175 million contribution we made in 2014 to MEP, our 50%-owned joint venture, to fund our share of the joint venture’s repayment of $350 million of senior notes that matured on September 15, 2014. Financing Activities The net increase of $1,566 million in cash from financing activities in 2014 compared to 2013 was primarily attributable to: • • • a $5,533 million net increase in cash from overall debt financing activities. The increase was driven by, among other things, a $5,259 million increase in cash due to the issuance of our senior notes, including proceeds of $5,987 million received in 2014 from the series of senior notes we issued to fund our Merger Transactions, and a net increase of $583 million in cash from both our commercial paper and revolving credit facilities programs (reflecting an increase in issuances of $5,733 million, partially offset by an increase in payments of $5,150 million). Further information regarding the debt related to our Merger Transactions is discussed in Note 8 “Debt” to our consolidated financial statements; a $445 million increase in cash due to lower combined repurchases of shares and warrants; a $3,937 million decrease in cash resulting from the cash portion of consideration for the Merger Transactions; 66 Table of Contents • • a $321 million decrease in cash associated with distributions to noncontrolling interests, primarily reflecting increased distributions to common unit owners of KMP and EPB prior to the Merger Transactions offset by no distribution being paid for the fourth quarter of 2014 since the closing date of the Merger Transactions occurred prior to KMP or EPB declaring any additional distributions; and a $138 million decrease in cash due to higher dividend payments. KMI Dividends The table below reflects the payment of cash dividends of $1.74 per common share for 2014, a 9% increase over our 2013 dividends of $1.60 per common share. Three months ended March 31, 2014 June 30, 2014 September 30, 2014 December 31, 2014 _______ Total quarterly dividend per share for the period $ $ $ $ 0.42 0.43 0.44 0.45 Date of declaration April 16, 2014 July 16, 2014 October 15, 2014 January 21, 2015 Date of record April 30, 2014 July 31, 2014 Date of dividend May 16, 2014 August 15, 2014 October 31, 2014 November 17, 2014 February 17, 2015 February 2, 2015 As disclosed elsewhere in this report, we expect to pay cash dividends totaling $2.00 per share on our common stock for 2015. There is nothing in our governing documents or credit agreements that prohibits us from borrowing to pay dividends. The actual amount of dividends to be paid on our capital stock will depend on many factors, including our financial condition and results of operations, liquidity requirements, business prospects, capital requirements, legal, regulatory and contractual constraints, tax laws, Delaware laws and other factors. See Item 1A. “Risk Factors—The guidance we provide for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.” All of these matters will be taken into consideration by our board of directors in declaring dividends. Our dividends are not cumulative. Consequently, if dividends on our common stock are not paid at the intended levels, our common stockholders are not entitled to receive those payments in the future. Our dividends generally will be paid on or about the 16th day of each February, May, August and November. Recent Accounting Pronouncements Please refer to Note 17 “Recent Accounting Pronouncements” to our consolidated financial statements for information concerning recent accounting pronouncements. Item 7A. Quantitative and Qualitative Disclosures About Market Risk. Generally, our market risk sensitive instruments and positions have been determined to be “other than trading.” Our exposure to market risk as discussed below includes forward-looking statements and represents an estimate of possible changes in fair value or future earnings that would occur assuming hypothetical future movements in energy commodity prices or interest rates. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated based on actual fluctuations in energy commodity prices or interest rates and the timing of transactions. Energy Commodity Market Risk We are exposed to energy commodity market risk and other external risks in the ordinary course of business. However, we take steps to hedge, or limit our exposure to, these risks by executing a hedging strategy that seeks to protect us financially against adverse price movements and serves to minimize potential losses. Our strategy involves the use of certain energy commodity derivative contracts to reduce and minimize the risks associated with unfavorable changes in the market price of natural gas, NGL and crude oil. The derivative contracts that we use include energy products traded on the NYMEX and OTC markets, including, but not limited to, futures and options contracts, fixed price swaps and basis swaps. 67 Table of Contents 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. None of these derivatives are designated as accounting hedges. Fundamentally, our hedging strategy involves taking a simultaneous financial position in the futures market that is equal and opposite to our physical position, or anticipated position, in the cash market (or physical product) in order to minimize the risk of financial loss from an adverse price change. For example, as sellers of crude oil and natural gas, we often enter into fixed price swaps and/or futures contracts to guarantee or lock-in the sale price of our crude oil or the margin from the sale and purchase of our natural gas at the time of market delivery, thereby in whole or in part offsetting any change in prices, either positive or negative. A hedge is successful to the extent gains or losses in the cash market are neutralized by losses or gains in the futures transaction. Our policies require that derivative contracts are only entered into with carefully selected major financial institutions or similar counterparties based upon their credit ratings and other factors, and we maintain strict dollar and term limits that correspond to our counterparties’ credit ratings. While it is our policy to enter into derivative transactions principally with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that losses will result from counterparty credit risk in the future. The credit ratings of the primary parties from whom we transact in energy commodity derivative contracts (based on contract market values) are as follows (credit ratings per Standard & Poor’s Rating Service): Bank of America / Merrill Lynch J. Aron & Company / Goldman Sachs J.P. Morgan Morgan Stanley Macquarie _______ Credit Rating A- A- A A- BBB As discussed above, the principal use of energy commodity derivative contracts is to mitigate the market price risk associated with anticipated transactions for the purchase and sale of natural gas, NGL and crude oil. Using derivative contracts for this purpose helps provide increased certainty with regard to operating cash flows which helps us to undertake further capital improvement projects, attain budget results and meet dividend targets. We may categorize such use of energy commodity derivative contracts as cash flow hedges because the derivative contract is used to hedge the anticipated future cash flow of a transaction that is expected to occur but which value is uncertain. Cash flow hedges are defined as hedges made with the intention of decreasing the variability in cash flows related to future transactions, as opposed to the value of an asset, liability or firm commitment, and we are allowed special hedge accounting treatment for such derivative contracts. In accounting for cash flow hedges, gains and losses on the derivative contracts are reported in other comprehensive income, outside “Net Income” reported in our consolidated statements of income, but only to the extent that the gains and losses from the change in value of the derivative contracts can later offset the loss or gain from the change in value of the hedged future cash flows during the period in which the hedged cash flows affect net income. That is, for cash flow hedges, all effective components of the derivative contracts’ gains and losses are recorded in other comprehensive income, pending occurrence of the expected transaction. Other comprehensive income consists of those financial items that are within “Accumulated other comprehensive loss” in our accompanying consolidated balance sheets but not included in our net income (portions attributable to our noncontrolling interests are within “Noncontrolling interests” and are not included in our net income). Thus, in highly effective cash flow hedges, where there is no ineffectiveness, other comprehensive income changes by exactly as much as the derivative contracts and there is no impact on earnings until the expected transaction occurs. All remaining gains and losses on the derivative contracts (the ineffective portion and those contracts not designated as hedges) are included in current net income. The ineffective portion of the gain or loss on the derivative contracts is the difference between the gain or loss from the change in value of the derivative contract and the effective portion of that gain or loss. In addition, when the hedged forecasted transaction does take place and affects earnings, the effective part of the hedge is also recognized in the income statement, and the earlier recognized effective amounts are removed from “Accumulated other comprehensive loss” (and “Noncontrolling interests”) and are transferred to the income statement as well, effectively offsetting the changes in cash flows stemming from the hedged risk. If the forecasted transaction results in an asset or liability, amounts 68 Table of Contents should be reclassified into earnings when the asset or liability affects earnings through cost of sales, depreciation, interest expense, etc. We measure the risk of price changes in the natural gas, NGL, crude oil and power derivative instruments portfolios utilizing a sensitivity analysis model. The sensitivity analysis applied to each portfolio measures the potential income or loss (i.e., the change in fair value of the derivative instrument portfolio) based upon a hypothetical 10% movement in the underlying quoted market prices. In addition to these variables, the fair value of each portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. As of December 31, 2014 and 2013, a hypothetical 10% movement in underlying commodity natural gas prices would affect the estimated fair value of natural gas derivatives by $9 million and $15 million, respectively. As of December 31, 2014 and 2013, a hypothetical 10% movement in underlying commodity crude oil prices would affect the estimated fair value of crude oil derivative by $146 million and $201 million, respectively. As of December 31, 2014 and 2013, a hypothetical 10% movement in underlying commodity NGL prices would affect the estimated fair value of our NGL derivatives by $0.3 million and $5 million, respectively. As of both December 31, 2014 and 2013, a hypothetical 10% movement in underlying commodity electricity prices would not affect the estimated fair value of our power derivatives. As discussed above, we enter into derivative contracts largely for the purpose of mitigating the risks that accompany certain of our business activities and, therefore both in the sensitivity analysis model and in reality, the change in the market value of the derivative contracts portfolio is offset largely by changes in the value of the underlying physical transactions. Our sensitivity analysis represents an estimate of the reasonably possible gains and losses that would be recognized on the natural gas, NGL, crude oil and power portfolios of derivative contracts (including commodity futures and options contracts, fixed price swaps and basis swaps) assuming hypothetical movements in future market rates and is not necessarily indicative of actual results that may occur. It does not represent the maximum possible loss or any expected loss that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ from estimates due to actual fluctuations in market rates, operating exposures and the timing thereof, as well as changes in our portfolio of derivatives during the year. Interest Rate Risk In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt. The market risk inherent in our debt instruments and positions is the potential change arising from increases or decreases in interest rates as discussed below. For fixed rate debt, changes in interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows. Generally, there is not an obligation to prepay fixed rate debt prior to maturity and, as a result, interest rate risk and changes in fair value should not have a significant impact on the fixed rate debt until we would be required to refinance such debt. As of December 31, 2014 and 2013, the carrying values of the fixed rate debt (including the debt fair value adjustments) were $41,538 million and $33,129 million, respectively. These amounts compare to, as of December 31, 2014 and 2013, fair values of $42,164 million and $33,185 million, respectively. Fair values were determined using quoted market prices, where applicable, or future cash flow discounted at market rates for similar types of borrowing arrangements. A hypothetical 10% change in the average interest rates applicable to such debt for 2014 and 2013, would result in changes of approximately $1,539 million and $1,185 million, respectively, in the fair values of these instruments. The carrying value of the variable rate debt (which approximates the fair value), excluding the value of interest rate swap agreements (discussed following), was $1,425 million and $3,064 million as of December 31, 2014 and 2013, respectively. As of December 31, 2014 and 2013 we were party to interest rate swap agreements with notional principal amounts of $9,200 million and $5,400 million, respectively. An interest rate swap agreement is a contractual agreement entered into between two counterparties under which each agrees to make periodic interest payments to the other for an agreed period of time based upon a predetermined amount of principal, which is called the notional principal amount. Normally at each payment or settlement date, the party who owes more pays the net amount; so at any given settlement date only one party actually makes a payment. The principal amount is notional because there is no need to exchange actual amounts of principal. A hypothetical 10% change in the weighted average interest rate on all of our borrowings (approximately 50 basis points in 2014 and approximately 51 basis points in 2013) when applied to our outstanding balance of variable rate debt as of December 31, 2014 and 2013, including adjustments for the notional swap amounts described above, would result in changes of approximately $53 million and $43 million, respectively, in our 2014 and 2013 annual pre-tax earnings. 69 Table of Contents Interest rate swap agreements are entered into for the purpose of transforming a portion of the underlying cash flows related to long-term fixed rate debt securities into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. Since the fair value of fixed rate debt varies with changes in the market rate of interest, swap agreements are entered into to receive a fixed and pay a variable rate of interest. Such swap agreements result in future cash flows that vary with the market rate of interest, and therefore hedge against changes in the fair value of the fixed rate debt due to market rate changes. We monitor the mix of fixed rate and variable rate debt obligations in light of changing market conditions and from time to time, may alter that mix by, for example, refinancing outstanding balances of variable rate debt with fixed rate debt (or vice versa) or by entering into interest rate swap agreements or other interest rate hedging agreements. As of December 31, 2014, approximately 26% is variable rate debt. For more information on our interest rate risk management and on our interest rate swap agreements, see Note 13 “Risk Management” to our consolidated financial statements. Item 8. Financial Statements and Supplementary Data. The information required in this Item 8 is in this report as set forth in the “Index to Financial Statements” on page 77. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. None. Item 9A. Controls and Procedures. Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures As of December 31, 2014, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 (b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Management’s Report on Internal Control Over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. 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. Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an assessment of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, our management concluded that our internal control over financial reporting was effective as of December 31, 2014. The effectiveness of our internal control over financial reporting as of December 31, 2014, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their audit report, which appears herein. Changes in Internal Control Over Financial Reporting There has been no change in our internal control over financial reporting during the fourth quarter of 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. 70 Table of Contents Item 9B. Other Information. None. PART III Item 10. Directors, Executive Officers and Corporate Governance. The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2015 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2015. Item 11. Executive Compensation. The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2015 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2015. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2015 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2015. Item 13. Certain Relationships and Related Transactions, and Director Independence. The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2015 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2015. Item 14. Principal Accounting Fees and Services. The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2015 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2015. PART IV 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 Number Description 2.1 * Agreement and Plan of Merger, dated as of August 9, 2014, by and among Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Management, LLC, Kinder Morgan, Inc., 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) 3.1 Certificate of Incorporation of Kinder Morgan, Inc. as amended by the Certificate of Amendment to the Certificate of Incorporation 71 Table of Contents 3.2 Amended 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)) 72 Table of Contents 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 * 10.28 * 10.29 * 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)) 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)) 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)) 73 Table of Contents 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)) 74 Table of Contents 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)) 10.53 Certificate 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) 10.58 12.1 21.1 23.1 23.2 31.1 31.2 Cross 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 Statement re: computation of ratio of earnings to fixed charges Subsidiaries of Kinder Morgan, Inc. Consent of PricewaterhouseCoopers LLP Consent of Netherland, Sewell & Associates, Inc. Certification 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 Certification 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 75 Table of Contents 32.1 32.2 95.1 99.1 101 Certification 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 Certification 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 Mine Safety Disclosures Netherland, 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 Interactive 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. 76 Table of Contents KINDER MORGAN, INC. AND SUBSIDIARIES INDEX TO FINANCIAL STATEMENTS Report of Independent Registered Public Accounting Firm Consolidated Statements of Income for the years ended December 31, 2014, 2013 and 2012 Consolidated Statements of Comprehensive Income for the years ended December 31, 2014, 2013 and 2012 Consolidated Balance Sheets as of December 31, 2014 and 2013 Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012 Consolidated Statement of Stockholders’ Equity as of and for the years ended December 31, 2014, 2013 and 2012 Notes to Consolidated Financial Statements Page Number 78 79 81 82 84 86 87 77 Table of Contents 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 78 Table of Contents KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In Millions, Except Per Share Amounts) Year Ended December 31, 2013 2012 2014 Revenues Natural gas sales Services Product sales and other Total Revenues Operating Costs, Expenses and Other Costs of sales Operations and maintenance Depreciation, depletion and amortization General and administrative Taxes, other than income taxes Loss on impairments of long-lived assets Other expense (income), net Total Operating Costs, Expenses and Other Operating Income Other Income (Expense) Earnings from equity investments Amortization of excess cost of equity investments Interest, net Gain on remeasurement of previously held equity investments to fair value (Note 3) Gain on sale of investments in Express pipeline system (Note 3) Other, net Total Other Income (Expense) $ $ 4,115 7,650 4,461 16,226 $ 3,605 6,677 3,788 14,070 2,511 5,013 2,449 9,973 6,278 2,157 2,040 610 418 272 3 11,778 5,253 2,112 1,806 613 395 — (99) 10,080 3,057 1,702 1,419 929 286 — (13) 7,380 4,448 3,990 2,593 406 (45) (1,798) — — 80 (1,357) 327 (39) (1,675) 558 224 53 (552) 153 (23) (1,399) — — 19 (1,250) Income from Continuing Operations Before Income Taxes 3,091 3,438 1,343 Income Tax Expense Income from Continuing Operations Discontinued Operations (Note 3) Income from operations of the FTC Natural Gas Pipelines disposal group and other, net of tax Loss on sale and the remeasurement of the FTC Natural Gas Pipelines disposal group to fair value, net of tax Loss from Discontinued Operations, Net of Tax Net Income (648) (742) (139) 2,443 2,696 1,204 — — — — (4) (4) 2,443 2,692 160 (937) (777) 427 Net Income Attributable to Noncontrolling Interests (1,417) (1,499) (112) Net Income Attributable to Kinder Morgan, Inc. $ 1,026 $ 1,193 $ 315 79 Table of Contents KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (continued) (In Millions, Except Per Share Amounts) Year Ended December 31, 2013 2012 2014 Class P Shares Basic and Diluted Earnings Per Common Share From Continuing Operations Basic and Diluted Loss Per Common Share From Discontinued Operations Total Basic and Diluted Earnings Per Common Share $ $ 0.89 — 0.89 $ $ 1.15 — 1.15 Class A Shares Basic and Diluted Earnings Per Common Share From Continuing Operations Basic and Diluted Loss Per Common Share From Discontinued Operations Total Basic and Diluted Earnings Per Common Share Basic Weighted-Average Number of Shares Outstanding Class P Shares Class A Shares Diluted Weighted-Average Number of Shares Outstanding Class P Shares Class A Shares 1,137 1,036 1,137 1,036 $ $ $ $ 0.56 (0.21) 0.35 0.47 (0.21) 0.26 461 446 908 446 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. 80 Table of Contents KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (In Millions) Kinder Morgan, Inc. Net income 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) Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of $13, $(2) and $3, respectively) Foreign currency translation adjustments (net of tax benefit (expense) of $41, $22, and $(8), respectively) Benefit plan adjustments (net of tax benefit (expense) of $125, $(88) and $30, respectively) Total other comprehensive (loss) income Total comprehensive income Noncontrolling Interests Net income 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) Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of $-, $(1) and $-, respectively) Foreign currency translation adjustments (net of tax benefit (expense) of $7, $9 and $(2), respectively) Benefit plan adjustments (net of tax benefit (expense) of $1, $(3) and $-, respectively) Total other comprehensive income (loss) Total comprehensive income Total Net income 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) Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of $13, $(3) and $3, respectively) Foreign currency translation adjustments (net of tax benefit (expense) of $48, $31 and $(10), respectively) Benefit plan adjustments (net of tax benefit (expense) of $126, $(91) and $30, respectively) Total other comprehensive income Total comprehensive income Year Ended December 31, 2014 2013 2012 $ 1,026 $ 1,193 $ 315 254 (14) (22) 4 (68) (213) (49) 977 (49) 153 94 1,287 32 (5) 14 (44) (3) 312 1,417 1,499 112 155 (24) (3) (70) (13) 69 7 (54) 17 (54) 1,486 1,445 50 (3) 18 9 74 186 2,443 2,692 427 409 (38) (25) 11 (138) (226) 20 (103) 170 40 $ 2,463 $ 2,732 $ 82 (8) 32 (35) 71 498 The accompanying notes are an integral part of these consolidated financial statements. 81 Table of Contents KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Millions, Except Share and Per Share Amounts) ASSETS December 31, 2014 2013 Current assets Cash and cash equivalents Accounts receivable, net Fair value of derivative contracts Inventories Deferred income taxes Other current assets Total current assets Property, plant and equipment, net Investments Goodwill Other intangibles, net Deferred income taxes Deferred charges and other assets Total Assets LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities Current portion of debt Accounts payable Accrued interest Accrued contingencies Other current liabilities Total current liabilities Long-term liabilities and deferred credits Long-term debt Outstanding Preferred interest in general partner of KMP Debt fair value adjustments Total long-term debt Deferred income taxes Other long-term liabilities and deferred credits Total long-term liabilities and deferred credits Total Liabilities $ $ $ $ 315 1,641 535 459 56 746 3,752 38,564 6,036 24,654 2,302 5,651 2,239 83,198 2,717 1,588 637 383 1,037 6,362 38,212 100 1,934 40,246 — 2,164 42,410 48,772 $ $ $ $ 598 1,721 116 430 567 436 3,868 35,847 5,951 24,504 2,438 — 2,577 75,185 2,306 1,676 565 584 944 6,075 31,810 100 1,977 33,887 4,651 2,287 40,825 46,900 82 Table of Contents KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (continued) (In Millions, Except Share and Per Share Amounts) December 31, 2014 2013 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 $ Preferred stock, $0.01 par value, 10,000,000 shares authorized, none outstanding Additional paid-in capital Retained deficit Accumulated other comprehensive loss Total Kinder Morgan, Inc.’s stockholders’ equity Noncontrolling interests Total Stockholders’ Equity $ 21 — 36,178 (2,106) (17) 34,076 350 34,426 Total Liabilities and Stockholders’ Equity $ 83,198 $ 10 — 14,479 (1,372) (24) 13,093 15,192 28,285 75,185 The accompanying notes are an integral part of these consolidated financial statements. 83 Table of Contents KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In Millions) Year Ended December 31, 2014 2013 2012 Cash Flows From Operating Activities Net income Adjustments to reconcile net income to net cash provided by operating activities Depreciation, depletion and amortization Deferred income taxes Amortization of excess cost of equity investments Loss on impairments of long-lived assets (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) Gain from sale of investments in Express pipeline system (Note 3) Loss on early extinguishment of debt Noncash compensation expense on settlement of EP stock awards Earnings from equity investments Distributions from equity investment earnings Proceeds from termination of interest rate swap agreements Pension contributions and noncash pension benefit credits Changes in components of working capital, net of the effects of acquisitions Accounts receivable Income tax receivable Inventories Other current assets Accounts payable Accrued interest Accrued contingencies and other current liabilities Rate reparations, refunds and other litigation reserve adjustments Other, net Net Cash Provided by Operating Activities Cash Flows From Investing Activities Acquisition of EP, net of $6,581 cash acquired (Note 3) Acquisitions of other assets and investments, net of cash acquired Proceeds from sales of assets and investments Proceeds from disposal of discountinued operations (Note 3) Capital expenditures Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs Contributions to investments Distributions from equity investments in excess of cumulative earnings Other, net Net Cash Used in Investing Activities Cash Flows From Financing Activities Issuance of debt Payment of debt Debt issue costs Cash dividends (Note 10) Repurchases of shares and warrants Cash consideration of Merger Transactions (Note 1) Merger Transactions costs Contributions from noncontrolling interests Distributions to noncontrolling interests Other, net Net Cash Provided by (Used in) Financing Activities $ 2,443 $ 2,692 $ 2,040 615 45 272 — — — — (406) 381 — (88) (84) (195) (30) (31) (1) 75 108 (280) (397) 4,467 — (1,388) — — (3,617) 5 (389) 182 (3) (5,210) 24,573 (17,801) (89) (1,760) (192) (3,937) (74) 1,767 (2,013) (3) 471 1,806 640 39 — (556) (224) — — (327) 398 96 (120) (131) — (53) (24) (36) 42 (100) 174 (194) 4,122 — (292) 490 — (3,369) 87 (217) 185 (6) (3,122) 13,581 (12,393) (38) (1,622) (637) — — 1,706 (1,692) — (1,095) Effect of Exchange Rate Changes on Cash and Cash Equivalents Net (decrease) increase in Cash and Cash Equivalents Cash and Cash Equivalents, beginning of period Cash and Cash Equivalents, end of period (11) (283) 598 315 $ (21) (116) 714 598 $ $ The accompanying notes are an integral part of these consolidated financial statements. 84 427 1,426 47 23 — 859 — 82 87 (223) 381 53 (31) (231) — (92) 32 70 (26) (68) (39) 31 2,808 (4,970) (83) — 1,791 (2,022) 154 (192) 200 25 (5,097) 18,148 (14,755) (111) (1,184) (157) — — 1,939 (1,219) (77) 2,584 8 303 411 714 Table of Contents KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (continued) (In Millions) Noncash Investing and Financing Activities Net assets and liabilities or noncontrolling interests acquired by the issuance of shares and warrants (Notes 1 and 3) Assets acquired by the assumption or incurrence of liabilities Assets acquired or liabilities settled by contributions from noncontrolling interests Supplemental Disclosures of Cash Flow Information Cash paid during the period for interest (net of capitalized interest) Cash paid during the period for income taxes (net of refunds) Year Ended December 31, 2014 2013 2012 $ 16,023 $ — $ 11,454 106 — 1,718 227 1,510 3,733 1,652 67 — 306 1,349 182 The accompanying notes are an integral part of these consolidated financial statements. 85 Table of Contents KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (In Millions) Par value of common shares Additional paid-in capital Retained deficit Accumulated other comprehensive loss Stockholders’ equity attributable to KMI $ (3) $ (115) $ $ 8 3 3,431 10,598 863 Balance at December 31, 2011 $ Issuance of shares for EP acquisition Issuance of warrants for EP acquisition Acquisition of EP noncontrolling interests Warrants repurchased EP Trust I Preferred security conversions Class A, Class B and Class C share conversions (1) Amortization of restricted shares Impact from equity transactions of KMP, EPB and KMR Tax impact on stock based compensation Net income Distributions Contributions Cash dividends Other Other comprehensive (loss) income Balance at December 31, 2012 Shares repurchased Warrants repurchased Warrants exercised EP Trust I Preferred security conversions Amortization of restricted shares Impact from equity transactions of KMP, EPB and KMR Net income Distributions Contributions KMP’s acquisition of Copano noncontrolling interests Cash dividends Other Other comprehensive income Balance at December 31, 2013 Impact of Merger Transactions Merger Transactions costs Shares repurchased Warrants repurchased Amortization of restricted shares Impact from equity transactions of KMP, EPB and KMR Net income Distributions Contributions Cash dividends Other 10 10 11 (71) 315 (1,184) (943) 1,193 (1,622) (1,372) (157) 14 1 14 64 90 (1) 14,917 (172) (465) 1 3 35 161 (1) 14,479 21,880 (75) (94) (98) 57 36 1,026 (1,760) (7) (3) (118) 94 (24) Non- controlling interests $ 5,247 3,797 (102) 112 (1,219) 2,329 (4) 74 10,234 (254) 1,499 (1,692) 5,439 17 3 (54) 15,192 (15,936) (55) 1,417 (2,013) 1,767 (4) 69 Total $ 8,568 10,601 863 3,797 (157) 14 (71) 14 (38) 90 427 (1,219) 2,329 (1,184) (5) 71 24,100 (172) (465) 1 3 35 (93) 2,692 (1,692) 5,439 17 (1,622) 2 40 28,285 5,955 (75) (94) (98) 57 (19) 2,443 (2,013) 1,767 (1,760) (11) 20 3,321 10,601 863 — (157) 14 (71) 14 64 90 315 — — (1,184) (1) (3) 13,866 (172) (465) 1 3 35 161 1,193 — — — (1,622) (1) 94 13,093 21,891 (75) (94) (98) 57 36 1,026 — — (1,760) (7) (49) Other comprehensive (loss) income Impact of Merger Transactions on Accumulated other comprehensive loss Balance at December 31, 2014 $ 21 $ 36,178 $ (2,106) $ (49) 56 (17) $ 56 34,076 $ (87) 350 (31) $34,426 The accompanying notes are an integral part of these consolidated financial statements. 86 Table of Contents 1. General KINDER MORGAN, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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.” 2. 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. 87 Table of Contents 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- 88 Table of Contents 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. 89 Table of Contents 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 90 Table of Contents 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. 91 Table of Contents 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. 92 Table of Contents The following table summarizes our regulatory asset and liability balances as of December 31, 2014 and 2013 (in millions): Current regulatory assets Non-current regulatory assets Total regulatory assets Current regulatory liabilities Non-current regulatory liabilities Total regulatory liabilities _______ December 31, 2014 2013 $ $ $ $ 81 406 487 189 290 479 $ $ $ $ 91 446 537 135 397 532 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): Class P Participating securities(a) Net Income Attributable to Kinder Morgan, Inc. Year Ended December 31, 2014 2013 $ $ 1,015 11 1,026 $ $ 1,187 6 1,193 _______ (a) Participating securities are unvested restricted stock awards issued to management employees that contain non-forfeitable rights to dividend equivalent payments. 93 Table of Contents 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): Unvested restricted stock awards Outstanding warrants to purchase our Class P shares(a) Convertible trust preferred securities Year Ended December 31, 2014 2013 7 312 10 4 401 10 _______ (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. 94 Table of Contents 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): Income from continuing operations Less: income from continuing operations attributable to noncontrolling interests Income from continuing operations attributable to KMI Dividends paid in the period Excess distributions over earnings Income from continuing operations attributable to shareholders Basic earnings per share from continuing operations Basic weighted- average number of shares outstanding Basic earnings per common share from continuing operations(b) Diluted earnings per share from continuing operations Income from continuing operations attributable to shareholders and assumed conversions(c) Diluted weighted-average number of shares Diluted earnings per common share from continuing operations(b) _______ Year ended December 31, 2012 Income from Continuing Operations Available to Shareholders Class P Class A Participating Securities(a) Total $ 1,204 $ 601 (344) $ 542 (331) 257 $ 211 $ 41 (1) $ 40 $ (696) 508 (1,184) (676) 508 461 0.56 $ $ 508 908 0.56 $ 446 0.47 211 446 0.47 N/A N/A N/A N/A N/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 P Class A Participating Securities(a) Total Net income attributable to KMI Dividends paid in the period Excess distributions over earnings Net income attributable to shareholders Basic earnings per share Basic weighted-average number of shares outstanding Basic earnings per common share(b) Diluted earnings per share Net income attributable to shareholders and assumed conversions(c) Diluted weighted-average number of shares Diluted earnings per common share(b) $ $ $ $ $ 601 (441) 160 $ $ 461 0.35 $ 315 908 0.35 $ $ 542 (426) 116 $ $ 446 0.26 116 446 0.26 N/A N/A N/A N/A N/A $ 41 (2) $ $ 39 315 (1,184) (869) 315 _______ (a) Participating securities are unvested restricted stock awards issued to management employees that contain non-forfeitable rights to dividend equivalents payments. 95 Table of Contents (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. 3. 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): Ref. Date Acquisition (1) 11/14 Pennsylvania and Florida Jones Act Tankers (2) 1/14 American Petroleum Tankers and State Class Tankers (3) (4) (5) 6/13 Goldsmith-Landreth Field Unit 5/13 Copano 5/12 EP Assignment of Purchase Price Purchase price Current assets Property plant & equipment Deferred charges & other Goodwill Long- term debt Other liabilities Non- controlling interest Previously held equity interest $ 270 $ — $ 270 $ 8 $ 25 $ — $ (33) $ — $ 961 280 3,733 6 — 218 22,928 7,175 951 298 2,788 12,921 6 — 1,973 5,718 64 — 963 — — (1,252) (66) (18) (236) 18,562 (13,417) (4,234) — — (17) (3,797) — — — (704) — (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. 96 Table of Contents (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 97 Table of Contents 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: Revenues Income from continuing operations Income from discontinued operations, net of tax Net income Net income attributable to noncontrolling interests Net income attributable to Kinder Morgan, Inc. Diluted earnings per common share Class P shares _______ Acquisitions Subsequent to December 31, 2014 Pro Forma Year Ended December 31, 2014 2013 (Unaudited) $ 16,260 $ 14,911 2,448 — 2,448 (1,419) 1,029 2,665 (4) 2,661 (1,490) 1,171 $ 0.90 $ 1.12 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. 98 Table of Contents 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 99 Table of Contents 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): Operating revenues Operating expenses Depreciation and amortization Other expense Earnings from equity investments Interest income and Other, net Income from operations of the FTC Natural Gas Pipelines disposal group Year Ended December 31, 2012(a) $ $ 227 (131) (7) (1) 70 2 160 _______ (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. 4. Income Taxes The components of “Income from Continuing Operations Before Income Taxes” are as follows (in millions): U.S. Foreign Total Income from Continuing Operations Before Income Taxes _______ Year Ended December 31, 2014 2013 2012 $ $ 2,941 150 3,091 $ $ 3,107 331 3,438 $ $ 1,246 97 1,343 100 Components of the income tax provision applicable to continuing operations for federal, foreign and state taxes are as follows (in millions): Current tax expense Federal State Foreign Total Deferred tax expense Federal State Foreign Total Total tax provision _______ Year Ended December 31, 2014 2013 2012 $ $ (16) $ 36 13 33 572 14 29 615 648 $ 57 36 9 102 612 — 28 640 742 $ 48 34 10 92 49 4 (6) 47 $ 139 The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows (in millions, except percentages): Federal income tax $ 1,082 35.0 % $ 1,203 35.0 % $ 470 35.0 % Year Ended December 31, 2014 2013 2012 Increase (decrease) as a result of: State deferred tax rate change Taxes on foreign earnings Net effects of consolidating KMP’s and EPB’s U.S. income tax provision State income tax, net of federal benefit Dividend received deduction Adjustments to uncertain tax positions Valuation allowance on Investment in NGPL Disposition of certain international holdings Other Total _______ — 40 — % 1.3 % (21) 112 (0.6)% 3.3 % 20 (6) 1.5 % (0.5)% (433) (14.0)% (488) (14.2)% (288) (21.5)% 37 (50) (5) 61 (112) 28 648 $ 1.2 % (1.6)% (0.2)% 2.0 % (3.6)% 0.9 % 45 (54) (87) — — 32 1.3 % (1.6)% (2.5)% — % — % 0.9 % 21 (32) (72) — — 26 21.0 % $ 742 21.6 % $ 139 1.6 % (2.4)% (5.3)% — % — % 1.9 % 10.3 % 101 Deferred tax assets and liabilities result from the following (in millions): Deferred tax assets Employee benefits Accrued expenses Net operating loss, capital loss, tax credit carryforwards Derivative instruments and interest rate and currency swaps Debt fair value adjustment Investments Other Valuation allowances Total deferred tax assets Deferred tax liabilities Property, plant and equipment Investments Other Total deferred tax liabilities Net deferred tax assets (liabilities) Current deferred tax asset Non-current deferred tax assets (liabilities) Net deferred tax assets (liabilities) _______ December 31, 2014 2013 329 123 778 43 102 4,858 31 (154) 6,110 373 — 30 403 5,707 56 5,651 5,707 $ $ $ $ 238 136 673 68 112 — 43 (95) 1,175 351 4,888 20 5,259 (4,084) 567 (4,651) (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 102 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): Balance at beginning of period Uncertain tax positions of EP Subtotal Additions based on current year tax positions Additions based on prior year tax positions Reductions based on prior year tax positions Reductions based on settlements with taxing authority Reductions due to lapse in statute of limitations Balance at end of period _______ Year Ended December 31, 2014 2013 2012 $ 209 $ 269 $ — 209 12 — (3) (24) (5) 189 $ 4 273 11 26 — (86) (15) 209 $ $ 57 289 346 11 1 — (55) (34) 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. 103 Table of Contents 5. 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): Natural gas, liquids, crude oil and CO2 pipelines Natural gas, liquids, CO2, and terminals station equipment Natural gas, liquids (including linefill), and transmix processing Other Accumulated depreciation, depletion and amortization Land and land rights-of-way Construction work in process Property, plant and equipment, net _______ December 31, 2014 2013 $ 18,119 $ 21,233 520 3,964 (8,369) 35,467 1,324 1,773 17,399 17,960 259 3,656 (6,757) 32,517 1,158 2,172 $ 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. 104 Table of Contents 6. 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): Citrus Corporation Ruby Pipeline Holding Company, L.L.C. Midcontinent Express Pipeline LLC Gulf LNG Holdings Group, LLC EagleHawk Plantation Pipe Line Company Red Cedar Gathering Company Double Eagle Pipeline LLC Parkway Pipeline LLC Fayetteville Express Pipeline LLC Watco Companies, LLC Fort Union Gas Gathering L.L.C. Sierrita Pipeline LLC Cortez Pipeline Company All others Total equity investments Bond investments Total investments _______ December 31, 2014 2013 $ 1,805 $ 1,123 1,875 1,153 748 547 337 303 184 150 144 130 103 70 63 17 304 6,028 8 $ 6,036 $ 602 578 272 307 176 144 131 144 103 161 19 12 266 5,943 8 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; 105 Table of Contents • 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. 106 Table of Contents Our earnings (losses) from equity investments were as follows (in millions): Citrus Corporation(a) Fayetteville Express Pipeline LLC Gulf LNG Holdings Group, LLC(a) Midcontinent Express Pipeline LLC Red Cedar Gathering Company Plantation Pipe Line Company Cortez Pipeline Company Fort Union Gas Gathering L.L.C.(b) Ruby Pipeline Holding Company, L.L.C.(a) Watco Companies, LLC Parkway Pipeline LLC Sierrita Pipeline LLC NGPL Holdco LLC(c) Double Eagle Pipeline LLC(b) EagleHawk All others Total Amortization of excess costs Year Ended December 31, 2014 2013 2012 $ $ 97 55 48 45 33 29 25 16 15 13 8 3 — (1) (7) 27 $ 84 55 47 40 31 35 24 11 (6) 13 1 — (66) 1 9 48 $ $ 406 $ (45) $ 327 $ (39) $ 53 55 22 42 32 32 25 — (5) 13 — — (198) — 11 71 153 (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): Income Statement Revenues Costs and expenses Net income (loss) _______ Balance Sheet Current assets Non-current assets Current liabilities Non-current liabilities Partners’/owners’ equity _______ Year Ended December 31, 2013 2012 2014 $ $ 3,829 3,063 766 $ $ 3,615 2,803 812 $ $ 3,681 3,194 487 December 31, 2014 2013 $ 943 $ 20,630 1,643 10,841 9,089 950 20,782 1,451 11,351 8,930 107 Table of Contents 7. 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 Pipelines CO2 Products Pipelines Terminals Kinder Morgan Canada Total Historical Goodwill $ 22,276 $ 1,528 $ Accumulated impairment losses Balance as of December 31, 2012 Acquisitions(a) Currency translation adjustments (2,090) 20,186 888 — — 1,528 — — Balance as of December 31, 2013 21,074 1,528 Acquisitions(a)(b) Currency translation adjustments Impairment 82 — — — — — — — 862 — — — Balance as of December 31, 2014 $ 21,156 $ 1,528 $ 862 $ 626 (377) 249 $ 28,043 (4,411) 23,632 — (16) 233 — (19) — 214 888 (16) 24,504 171 (19) (2) $ 24,654 — — 807 89 — (2) 894 $ $ 2,129 (1,267) 862 $ 1,484 (677) 807 _______ (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 108 Table of Contents 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. 109 Table of Contents 8. 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): KMI and Subsidiaries Senior term loan facilities, variable rate, due May 24, 2015 and May 6, 2017(a) Senior notes and debentures, 2.00% through 8.25%, due 2014 through 2098(b)(c)(d) Credit facility due November 26, 2019(e)(f) Commercial paper borrowings(e)(f) KMP Senior notes, 2.65% through 9.00%, due 2014 through 2044(b) Commercial paper borrowings(g)(h) Credit facility due May 1, 2018(g) TGP senior notes, 7.00% through 8.375%, due 2016 through 2037(b) EPNG senior notes, 5.95% through 8.625%, due 2017 through 2032(b) Copano senior notes, 7.125% due April 1, 2021(b) EPB EPPOC senior notes, 4.10% through 7.50%, due 2015 through 2042(b)(i) Credit facility due May 27, 2016(g) CIG, senior notes, 5.95% through 6.85%, due 2015 through 2037(b)(j) SLNG senior notes, 9.50% through 9.75%, due 2014 through 2016(b)(k) SNG notes, 4.40% through 8.00%, due 2017 through 2032(b)(l) Other Subsidiary Borrowings (as obligor) December 31, 2014 2013 $ — $ 1,528 5,645 175 — 11,438 850 386 17,800 — — 1,790 1,115 332 2,860 — 475 — 1,211 15,600 979 — 1,790 1,115 332 2,260 — 475 135 1,211 Kinder Morgan Finance Company, LLC, senior notes, 5.70% through 6.40%, due 2016 through 2036(b) EPC Building, LLC, promissory note, 3.967%, due 2014 through 2035 Preferred securities, 4.75%, due March 31, 2028(d)(m) KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock(n) Other miscellaneous debt(o) Total debt – KMI and Subsidiaries Less: Current portion of debt(p) Total long-term debt – KMI and Subsidiaries(q) _______ (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 1,636 453 280 100 303 41,029 2,717 $ 38,312 1,636 461 280 100 494 34,216 2,306 $ 31,910 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 110 Table of Contents 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 111 Table of Contents 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. 112 Table of Contents 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: 2014 2013 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 $650 million senior term loan facility due 2017(b) $1,186 million senior term loan facility due 2015 $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: Per share cash distribution declared for the period(a) Per share cash distribution paid in the period Year Ended December 31, 2014 2013 $ $ 41.860 41.877 $ $ 42.101 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. 113 Table of Contents 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): Year 2015 2016 2017 2018 2019 Thereafter Total _______ $ Total 2,717 1,684 3,059 2,328 2,819 28,422 $ 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. 9. 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. 114 Table of Contents 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, 2014 Year Ended December 31, 2013 Year Ended December 31, 2012 Weighted Average Grant Date Fair Value Shares Weighted Average Grant Date Fair Value Shares Weighted Average Grant Date Fair Value Shares Outstanding at beginning of period 6,382,885 $ 239 2,154,022 $ 69 1,163,090 $ Granted Vested Forfeited 1,694,668 (460,032) (244,227) Outstanding at end of period 7,373,294 Intrinsic value of restricted stock vested during the period $ $ 61 4,563,495 181 1,463,388 (14) (83,444) (9) (251,188) 277 6,382,885 17 $ $ (3) (8) (102,033) (370,423) 239 2,154,022 3 $ $ 33 51 (3) (12) 69 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: Year 2015 2016 2017 2018 2019 2020 2021 2023 Total Outstanding _______ Vesting of Restricted Shares 713,675 1,337,884 1,653,507 1,111,830 1,720,568 580,759 199,725 55,346 7,373,294 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. 115 Table of Contents 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. 116 Table of Contents 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 Benefits OPEB 2014 2013 2014 2013 Change in benefit obligation: Benefit obligation at beginning of period $ 2,563 $ 2,792 $ 631 $ Service cost Interest cost Actuarial loss (gain) Benefits paid Participant contributions Medicare Part D subsidy receipts Plan amendments Benefit obligation at end of period Change in plan assets: Fair value of plan assets at beginning of period Actual return on plan assets Employer contributions Participant contributions Benefits paid Fair value of plan assets at end of period Funded status - net liability at December 31, $ _______ 21 112 294 (186) — — — 25 92 (132) (239) — — 25 2,804 2,563 2,333 180 50 — (186) 2,377 (427) $ 2,240 254 78 — (239) 2,333 (230) $ — 25 15 (52) 3 2 — 624 380 32 26 3 (52) 389 (235) $ 720 — 23 (38) (54) 11 6 (37) 631 341 40 42 11 (54) 380 (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): Non-current benefit asset Current benefit liability Non-current benefit liability Funded status - net liability at December 31, Pension Benefits OPEB 2014 2013 2014 2013 $ $ — $ — (427) (427) $ — $ — (230) (230) $ $ 173 (22) (386) (235) $ 224 (32) (443) (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 Benefits OPEB 2014 2013 2014 2013 Unrecognized net actuarial loss $ Unrecognized prior service (cost) credit Accumulated other comprehensive (loss) income $ (296) $ (4) (300) $ (10) $ (5) (15) $ (27) $ 20 (7) $ (17) 21 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. 117 Table of Contents 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. 118 Table of Contents 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 2014 2013 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Cash and money market funds $ 5 $ 91 $ — $ 96 $ — $ 20 $ — $ Common/collective trusts(a) Insurance contracts Mutual funds(b) Common and preferred stocks(c) Corporate bonds U.S. government securities Asset backed securities Limited partnerships Equity trusts Private equity Other — — 71 459 — — — — — — — 863 — 198 — 247 190 28 — 199 — (15) Total asset fair value(c) $ 535 $ 1,801 $ — 15 — — — — — 16 — 10 — 41 863 15 269 459 247 190 28 16 199 10 (15) — — 92 498 — — — — — — — 920 — 134 — 220 120 29 — 235 — 13 $ 2,377 $ 590 $ 1,691 $ — 15 — — — — — 28 — 9 — 52 20 920 15 226 498 220 120 29 28 235 9 13 $ 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 2014 2013 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total $ — $ — $ $ — $ — $ — $ — Cash and money market funds $ Domestic equity securities Common/collective trusts(a) Fixed income trusts Limited partnerships Insurance contracts Mutual funds 23 25 — — 76 — 3 — 71 63 79 — — 23 25 71 63 155 49 3 — — — — 49 — 49 13 — 65 92 — 7 — 85 — 72 — — — — — — 46 — 46 13 85 65 164 46 7 $ 380 Total asset fair value $ 127 $ 213 $ $ 389 $ 177 $ 157 $ _______ (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. 119 Table of Contents 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): Balance at Beginning of Period Transfers In (Out) Pension Assets Realized and Unrealized Gains (Losses), net Purchases (Sales), net Balance at End of Period $ $ $ $ 15 28 9 52 14 40 24 9 87 $ $ $ $ — $ — $ — — — $ 5 2 7 $ — $ — $ — — — — $ — 3 1 4 $ — $ (17) (1) (18) $ $ 1 (40) 1 (1) (39) $ 15 16 10 41 15 — 28 9 52 Balance at Beginning of Period Transfers In (Out) OPEB Assets Realized and Unrealized Gains (Losses), net Purchases (Sales), net Balance at End of Period $ $ $ $ 46 46 44 44 $ $ $ $ — $ — $ — $ — $ (3) $ (3) $ — $ — $ 6 6 2 2 $ $ $ $ 49 49 46 46 2014 Insurance contracts Limited partnerships Private equity Total 2013 Insurance contracts Mutual funds Limited partnerships Private equity Total _______ 2014 Insurance contracts Total 2013 Insurance contracts Total _______ 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 year 2015 2016 2017 2018 2019 2020-2024 $ Pension Benefits OPEB(a) $ 190 193 193 195 195 965 46 46 45 45 44 209 _______ (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. 120 Table of Contents 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: Assumptions related to benefit obligations: Discount rate Rate of compensation increase Assumptions related to benefit costs: Discount rate(a) Expected return on plan assets(b)(c) Rate of compensation increase Pension Benefits 2014 2013 2012 2014 OPEB 2013 2012 3.66% 4.45% 3.40% 3.56% 4.34% 3.34% 4.50% 3.50% 3.00% n/a n/a n/a 4.45% 3.40% 4.22% 4.34% 3.62% 4.11% 7.50% 8.00% 8.44% 7.43% 7.35% 8.21% 3.50% 3.00% 3.50% n/a n/a n/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): One-percentage point increase: Aggregate of service cost and interest cost Accumulated postretirement benefit obligation One-percentage point decrease: Aggregate of service cost and interest cost Accumulated postretirement benefit obligation 2014 2013 $ $ $ 2 47 (2) $ (40) 2 45 (1) (39) 121 Table of Contents 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 Benefits 2014 2013 2012 2014 OPEB 2013 2012 $ 21 $ 25 $ 18 $ — $ — $ 112 (171) — — — (38) 285 — — — 92 (175) — — (3) (61) (211) 25 3 — 285 (183) 67 (110) (1) 10 (2) (18) 85 (17) (10) 1 59 25 (24) (2) (1) — (2) 10 — — 1 11 23 (22) (1) 3 — 3 (50) (18) (3) 1 (70) $ 247 $ (244) $ 41 $ 9 $ (67) $ — 18 (15) (1) 4 (1) 5 25 (4) (5) 1 17 22 Components of net benefit cost: Service cost Interest cost Expected return on assets Amortization of prior service (credit) cost Amortization of net actuarial loss (gain) Curtailment and settlement gain Net benefit (credit) cost Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss: Net (gain) loss arising during period Prior service cost (credit) arising during period Amortization or settlement recognition of net actuarial gain (loss) Amortization of prior service credit Total recognized in total other comprehensive income loss Total recognized in net benefit (credit) cost and other comprehensive (income) loss 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. 122 Table of Contents 10. 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: Balance at December 31, 2011 Class P Class A Class B Class C 170,921,140 535,972,387 94,132,596 2,318,258 — — (2,318,258) — — — Shares issued for EP acquisition (see Note 3) 330,154,610 — — — (535,972,387) — — (94,132,596) — — — — — Shares issued with conversions of EP Trust I Preferred securities 562,521 Shares converted Shares canceled Restricted shares vested Balance at December 31, 2012 Shares issued for EP acquisition(a) Shares repurchased and canceled Shares issued with conversions of EP Trust I Preferred securities Shares issued for exercised warrants Restricted shares vested Balance at December 31, 2013 Shares issued for Merger Transactions Shares repurchased and canceled Shares issued with conversions of EP Trust I Preferred securities Shares issued for exercised warrants Restricted shares vested Balance at December 31, 2014 535,972,387 (2,049,615) 107,553 1,035,668,596 53 (5,175,055) 77,442 16,886 89,154 1,030,677,076 1,096,910,451 (2,780,337) 2,820 12,402 324,704 2,125,147,116 _______ (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 123 Table of Contents 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: Per common share cash dividend declared for the period $ Per common share cash dividend paid in the period _______ Year Ended December 31, 2014 2013 2012 $ 1.74 1.70 $ 1.60 1.56 1.40 1.34 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: Beginning balance Warrants issued in EP acquisition(a) Warrants issued with conversions of EP Trust I Preferred securities(b) Warrants exercised Warrants repurchased and canceled Ending balance 2014 Warrants 2013 2012 347,933,107 439,809,442 — — 81 504,598,883 4,315 (18,040) (49,783,406) 298,135,976 118,377 (21,208) (91,973,585) 347,933,107 859,796 — (65,649,237) 439,809,442 _______ (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. 124 Table of Contents 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, 2014 2013 KMP EPB KMR Other _______ $ $ — $ — — 350 350 7,642 4,122 3,142 286 $ 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. 125 Table of Contents 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): Issuances Common units/shares Net proceeds (in thousands) (in millions) Use of proceeds KMP Issued under Equity Distribution Agreement(a) 2014 2013 5,513 10,814 $ $ Other issuances February 2014 7,935 $ February 2013 May 2013 4,600 43,371 EPB Issued under Equity Distribution Agreement(c) Other issuances 2014 2013 May 2014 7,314 2,038 7,820 KMR Issued under Equity Distribution Agreement(d) $ $ $ $ $ 2014 2013 1,735 $ 2,640 $ 441 900 603 385 Reduced borrowings under KMP’s commercial paper program Reduced borrowings under KMP’s commercial paper program Reduced borrowings under KMP’s commercial paper program that were used to fund KMP’s APT acquisition in January 2014 Issued to pay a portion of the purchase price for the March 2013 drop-down transaction — (b) Issued to Copano unitholders as KMP’s purchase price for Copano 275 85 242 134 210 General partnership purposes General partnership purposes Issued to pay a portion of the purchase price for the May 2014 drop-down transaction Purchased additional KMP i-units; KMP then used proceeds to reduce borrowings under its commercial paper program Purchased 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. 126 Table of Contents Distributions The following table provides information about distributions from our noncontrolling interests (in millions except per unit and i-unit distribution amounts): KMP(a) Per unit cash distribution declared for the period Per unit cash distribution paid in the period Cash distributions paid in the period to the public EPB(a)(b) Per unit cash distribution declared for the period Per unit cash distribution paid in the period Cash distributions paid in the period to the public KMR(a)(c) Year Ended December 31, 2014 2013 2012 $ $ $ $ $ $ 4.17 5.53 1,654 1.95 2.60 347 $ $ $ $ $ $ 5.33 5.26 1,372 2.55 2.51 318 $ $ $ $ $ $ 4.98 4.85 1,081 1.74 1.13 137 Share distributions paid in the period to the public 7,794,183 6,588,477 5,586,579 _______ (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. 11. Related Party Transactions Affiliated Balances The following table summarizes our balance sheet affiliate balances (in millions): Balance sheet location Accounts receivable, net Other current assets Deferred charges and other assets Current portion of debt(a) Accounts payable Long-term debt(a) _______ (a) Includes financing obligations payable to WYCO (See Note 8). Notes Receivable Plantation December 31, 2014 2013 31 3 46 80 6 22 172 200 $ $ $ $ 19 3 47 69 6 9 169 184 $ $ $ $ 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 127 Table of Contents 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. 12. 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): Year 2015 2016 2017 2018 2019 Thereafter Total minimum payments _______ Commitment $ $ 97 85 75 67 65 289 678 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. 128 Table of Contents 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. 13. 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. 129 Table of Contents 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 Crude oil basis Natural gas fixed price Natural gas basis Derivatives not designated as hedging contracts Crude oil fixed price Natural gas fixed price Natural gas basis NGL fixed price _______ (10.9) MMBbl (10.8) MMBbl (27.2) Bcf (8.0) Bcf (14.9) MMBbl 2.0 Bcf 6.5 Bcf (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. 130 Table of Contents 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 Derivatives designated as hedging contracts Balance sheet location Asset derivatives December 31, 2013 2014 Fair value Liability derivatives December 31, 2013 2014 Fair value Natural gas and crude derivative Other current assets/(Other current contracts liabilities) $ 309 $ 18 $ (34) $ (33) Deferred charges and other assets/ (Other long-term liabilities and deferred credits) Subtotal Interest rate swap agreements liabilities) Other current assets/(Other current Deferred charges and other assets/ (Other long-term liabilities and deferred credits) Subtotal Total Derivatives not designated as hedging contracts Natural gas, crude and NGL derivative Other current assets/(Other current contracts liabilities) Deferred charges and other assets/ (Other long-term liabilities and deferred credits) Subtotal Power derivative contracts liabilities) Other current assets/(Other current Deferred charges and other assets/ (Other long-term liabilities and deferred credits) Subtotal Total Total derivatives _______ Debt Fair Value Adjustments 6 315 143 260 403 718 73 196 269 10 — 10 279 997 $ 58 76 87 172 259 335 4 — 4 7 11 18 22 $ 357 $ — (34) — (53) (53) (87) (2) — (2) (30) (63) — (116) (116) (179) (5) — (5) (57) (54) (16) (73) (75) (162) $ (73) (127) (132) (311) 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. 131 Table of Contents 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 relationships Location of gain/(loss) recognized in income on derivatives Interest rate swap agreements Interest expense Total Fixed rate debt Total _______ Interest expense Amount of gain/(loss)recognized in income on derivatives and related hedged item Year Ended December 31, 2014 2013 2012 $ $ $ $ 207 207 $ $ (204) $ (204) $ (425) $ (425) $ 425 425 $ $ 55 55 (55) (55) Derivatives in cash flow hedging relationships Energy commodity derivative contracts Amount of gain/(loss) recognized in OCI on derivative (effective portion)(a) Year Ended December 31, 2014 2013 2012 $423 $ (45) $ 87 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) Year Ended December 31, 2013 2012 2014 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 Ended December 31, 2013 2014 2012 Revenues— Natural gas sales Revenues— Product sales and other Costs of sales $ (1) $ — $ 4 Revenues— Natural gas sales 26 (13) 4 — Revenues— Product sales and other (15) 17 Costs of sales $ — $ — $ — 11 — 3 — (11) — Interest rate swap agreements Total (15) $408 7 $ (38) $ Interest expense (5) 82 Total (4) $ 25 2 $ (11) $ Interest expense 2 8 Total — $ 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). 132 Table of Contents Derivatives not designated as accounting hedges Energy commodity derivative contracts Total Credit Risks Location of gain/(loss) recognized in income on derivatives Amount of gain/(loss) recognized in income on derivatives Revenues—Natural gas sales Revenues—Product sales and other Costs of sales Other expense (income) Year Ended December 31, 2014 2013 2012 $ $ (7) $ 20 — (2) 11 $ — $ (10) 2 (2) (10) $ 1 (4) — — (3) 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. 133 Table of Contents 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 derivatives Foreign currency translation adjustments Pension and other postretirement liability adjustments Total Accumulated other comprehensive income/(loss) Balance as of December 31, 2011 Other comprehensive income before reclassifications $ (20) $ 32 $ (132) $ (53) Amounts reclassified from accumulated other comprehensive loss Net current-period other comprehensive income Balance as of December 31, 2012 Other comprehensive income before reclassifications Amounts reclassified from accumulated other comprehensive loss Net current-period other comprehensive income Balance as of December 31, 2013 Other comprehensive income before reclassifications Amounts reclassified from accumulated other comprehensive loss Impact of Merger Transactions (See Note 1) Net current-period other comprehensive income Balance as of December 31, 2014 $ (5) 27 7 (14) 4 (10) (3) 254 (22) 98 330 327 _______ 14. Fair Value 37 14 — 14 51 (49) — (49) 2 (68) — (42) (110) (108) $ $ 9 (44) (176) 151 2 153 (23) (212) (1) — (213) (236) $ (115) (7) 4 (3) (118) 88 6 94 (24) (26) (23) 56 7 (17) 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). 134 Table of Contents 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 using Amounts not offset in the balance sheet Level 1 Level 2 Level 3 Gross amount Financial instruments Cash collateral held(b) Net amount As of December 31, 2014 Energy commodity derivative contracts(a) $ Interest rate swap agreements $ As of December 31, 2013 Energy commodity derivative contracts(a) $ Interest rate swap agreements $ 49 $ — $ 4 $ — $ 533 403 46 259 $ $ $ $ 12 $ — $ 48 $ — $ 594 403 98 259 $ $ $ $ (46) $ (44) $ (62) $ (28) $ (13) $ — $ — $ — $ 535 359 36 231 _______ Balance sheet liability fair value measurements using Amounts not offset in the balance sheet Level 1 Level 2 Level 3 Gross amount Financial instruments Cash collateral posted(c) Net amount As of December 31, 2014 Energy commodity derivative contracts(a) $ (25) $ Interest rate swap agreements $ — $ (11) $ (53) $ (73) $ — $ (109) $ (53) $ As of December 31, 2013 Energy commodity derivative contracts(a) $ Interest rate swap agreements $ (6) $ — $ (31) $ (116) $ (158) $ — $ (195) $ (116) $ 46 44 62 28 $ $ $ $ 47 $ — $ (16) (9) 17 $ (116) — $ (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. 135 Table of Contents 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) Derivatives-net asset (liability) Beginning of period Transfers out(a) Total gains or (losses) Included in earnings Included in other comprehensive loss Purchases(b) Settlements End of period 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 Year Ended December 31, 2014 2013 $ $ $ (110) $ (88) 22 78 — 37 (61) $ 1 $ (155) — (5) (1) 17 34 (110) (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): Total debt _______ December 31, 2014 December 31, 2013 Carrying value Estimated fair value Carrying value Estimated fair value $ 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. 15. 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 136 Table of Contents 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. 137 Table of Contents Financial information by segment follows (in millions): Revenues Natural Gas Pipelines(a) Revenues from external customers Intersegment revenues CO2 Terminals Revenues from external customers Intersegment revenues Products Pipelines Kinder Morgan Canada Other Total segment revenues Other revenues(b) Less: Total intersegment revenues Total consolidated revenues Operating expenses(c) Natural Gas Pipelines(a) CO2 Terminals Products Pipelines Kinder Morgan Canada Other Total segment operating expenses Other operating expenses Less: Total intersegment operating expenses Total consolidated operating expenses Other expense (income) Natural Gas Pipelines(a) CO2(d) Terminals Products Pipelines Other Total consolidated other expense (income) 138 Year Ended December 31, 2014 2013 2012 $ 10,153 $ 8,613 $ 15 1,960 1,717 1 2,068 291 1 4 1,857 1,408 2 1,853 302 1 16,206 36 (16) 16,226 $ 14,040 36 (6) 14,070 $ $ 5,230 — 1,677 1,356 3 1,370 311 (6) 9,941 35 (3) 9,973 Year Ended December 31, 2014 2013 2012 $ 6,241 $ 5,235 $ 3,111 494 746 1,258 106 24 8,869 — (16) 8,853 $ 439 657 1,295 110 30 7,766 — (6) 7,760 $ 381 685 759 103 5 5,044 4 (3) 5,045 Year Ended December 31, 2014 2013 2012 5 $ 243 29 (3) 1 275 $ (24) $ — (74) 6 (7) (99) $ 14 (7) (14) (5) (1) (13) $ $ $ Table of Contents DD&A Natural Gas Pipelines(a) CO2 Terminals Products Pipelines Kinder Morgan Canada Other Year Ended December 31, 2014 2013 2012 $ $ 897 570 337 166 51 19 $ 797 533 247 155 54 20 478 494 236 143 56 12 Total consolidated DD&A $ 2,040 $ 1,806 $ 1,419 Earnings from equity investments Natural Gas Pipelines(a)(e) CO2 Terminals Products Pipelines Kinder Morgan Canada Other Total consolidated equity earnings Amortization of excess cost of equity investments Natural Gas Pipelines(a) CO2 Products Pipelines Year Ended December 31, 2014 2013 2012 $ 318 $ 232 $ 25 18 44 — 1 24 22 45 4 — 52 25 21 39 5 11 406 $ 327 $ 153 Year Ended December 31, 2014 2013 2012 $ $ 39 (1) 7 45 $ $ 32 $ 2 5 39 $ Total consolidated amortization of excess cost of equity investments $ Interest income Natural Gas Pipelines Products Pipelines Kinder Morgan Canada Other Total segment interest income Unallocated interest income Total consolidated interest income Year Ended December 31, 2014 2013 2012 $ $ 1 2 — 6 9 — 9 $ $ — $ 2 3 8 13 2 15 $ 139 17 2 4 23 18 2 14 3 37 (9) 28 Table of Contents Other, net-income (expense) Natural Gas Pipelines(f) CO2 Terminals Products Pipelines Kinder Morgan Canada(g) Other Total consolidated other, net-income (expense) Income tax benefit (expense) Natural Gas Pipelines CO2 Terminals Products Pipelines Kinder Morgan Canada Total segment income tax expense Unallocated income tax expense Total consolidated income tax expense Segment EBDA(h) Natural Gas Pipelines(a) CO2 Terminals Products Pipelines Kinder Morgan Canada Other Total segment EBDA Total segment DD&A Total segment amortization of excess cost of equity investments Other revenues General and administrative expenses(i) Interest expense, net of unallocable interest income(j) Unallocable income tax expense Loss from discontinued operations, net of tax(k) Total consolidated net income $ 140 $ $ $ $ Year Ended December 31, 2014 2013 2012 24 — 12 (1) 15 30 80 $ 578 $ — 1 1 246 9 $ 835 $ Year Ended December 31, 2014 2013 2012 (6) $ (8) (29) (2) (18) (63) (585) (648) $ (9) $ (7) (14) 2 (21) (49) (693) (742) $ Year Ended December 31, 2014 2013 2012 4 (1) 2 9 3 2 19 (5) (5) (3) 2 (1) (12) (127) (139) $ 4,259 $ 4,207 $ 1,240 944 856 182 13 7,494 (2,040) (45) 36 (610) (1,807) (585) — 2,443 $ 1,435 836 602 424 (5) 7,499 (1,806) (39) 36 (613) (1,688) (693) (4) 2,692 $ 2,174 1,322 708 668 229 7 5,108 (1,419) (23) 35 (929) (1,441) (127) (777) 427 Table of Contents Capital expenditures Natural Gas Pipelines(a) CO2 Terminals Products Pipelines Kinder Morgan Canada Other Year Ended December 31, 2014 2013 2012 $ 935 792 1,049 680 156 5 $ 1,085 $ 667 1,108 416 77 16 499 453 707 307 16 40 Total consolidated capital expenditures $ 3,617 $ 3,369 $ 2,022 Investments at December 31 Natural Gas Pipelines(a) CO2 Terminals Products Pipelines Kinder Morgan Canada Other 2014 2013 5,174 $ 5,130 17 219 624 1 1 12 196 611 1 1 Total consolidated investments $ 6,036 $ 5,951 Assets at December 31 Natural Gas Pipelines CO2 Terminals Products Pipelines Kinder Morgan Canada Other Total segment assets Corporate assets(l) Assets held for sale 2014 2013 $ 52,523 $ 52,357 5,227 8,850 7,179 1,593 459 75,831 7,311 56 4,708 6,888 6,648 1,677 568 72,846 2,339 — 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). 141 Table of Contents (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): Revenues from external customers U.S. Canada Mexico Total consolidated revenues from external customers _______ Long-lived assets at December 31(a) U.S. Canada Mexico Total consolidated long-lived assets _______ (a) Long-lived assets exclude goodwill and other intangibles, net. 16. Litigation, Environmental and Other Contingencies Year Ended December 31, 2014 2013 2012 15,605 $ 13,656 $ 437 184 398 16 16,226 $ 14,070 $ 9,488 407 78 9,973 2014 2013 2012 50,141 $ 42,080 $ 2,268 81 2,214 81 37,651 2,035 82 52,490 $ 44,375 $ 39,768 $ $ $ $ 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 142 Table of Contents 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. 143 Table of Contents 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. 144 Table of Contents 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 145 Table of Contents 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 146 Table of Contents 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. 147 Table of Contents 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. 148 Table of Contents 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. 149 Table of Contents 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. 17. 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. 18. 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 150 Table of Contents 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. 151 Condensed Consolidating Statements of Income and Comprehensive Income for the Year Ended December 31, 2014 (In Millions) Parent Issuer and Guarantor 36 $ Subsidiary Issuer and Guarantor - KMP Subsidiary Issuer and Guarantor - Copano Subsidiary Issuer and Guarantor - EPB $ — $ — $ — $ Subsidiary Guarantors 14,310 Subsidiary Non- Guarantors 1,886 $ Consolidating Adjustments $ (6) $ Consolidated KMI Total Revenues Operating costs, expenses and other Costs of sales Depreciation, depletion and amortization Other operating expenses Total operating costs, expenses and other Operating (loss) income Other income (expense) Earnings from consolidated subsidiaries Earnings from equity investments Interest, net Amortization of excess cost of equity investments and other, net Income from continuing operations before income taxes Income tax expense Net income Net income attributable to noncontrolling interests Net income attributable to controlling interests Net Income Total other comprehensive (loss) income Comprehensive income Comprehensive income attributable to noncontrolling interests $ $ 42 — (48) (6) — (9,528) — — — — 21 30 51 (15) 1,948 — (493) — 1,440 (166) 1,274 (248) 1,026 1,274 (24) 1,250 (273) $ $ — — — — — 3,235 — 41 — 3,276 (7) 3,269 — 3,269 3,269 287 3,556 — $ $ — — 32 32 (32) 224 — (46) — 146 — 146 — 146 146 — 146 — $ $ — — 5 5 5,737 1,655 2,927 10,319 (5) 3,991 742 — (171) — 566 — 566 — 566 566 (10) 556 — $ $ 2,259 407 (1,040) (13) 5,604 (183) 5,421 (211) 5,210 5,421 386 5,807 (203) $ $ 499 364 514 1,377 509 1,120 (1) (89) 48 1,587 (292) 1,295 — 1,295 1,295 (168) 1,127 (9,528) 3,091 — (9,528) (958) (10,486) $ (9,528) $ (451) (9,979) $ $ — (1,010) 16,226 6,278 2,040 3,460 11,778 4,448 — 406 (1,798) 35 (648) 2,443 (1,417) 1,026 2,443 20 2,463 (1,486) 977 Comprehensive income attributable to controlling interests $ 977 $ 3,556 $ 146 $ 556 $ 5,604 $ 1,127 $ (10,989) $ 152 Condensed Consolidating Statements of Income and Comprehensive Income for the Year Ended December 31, 2013 (In Millions) Parent Issuer and Guarantor 36 $ Subsidiary Issuer and Guarantor - KMP Subsidiary Issuer and Guarantor - Copano Subsidiary Issuer and Guarantor - EPB $ — $ — $ — $ Subsidiary Guarantors 12,511 Subsidiary Non- Guarantors 1,512 $ Consolidating Adjustments 11 $ Consolidated KMI $ 14,070 Total Revenues Operating costs, expenses and other Costs of sales Depreciation, depletion and amortization Other operating expenses Total operating costs, expenses and other Operating (loss) income Other income (expense) Earnings from consolidated subsidiaries Earnings from equity investments Interest, net Amortization of excess cost of equity investments and other, net Income from continuing operations before income taxes Income tax (expense) benefit Income from continuing operations Loss from discontinued operations Net income Net income attributable to noncontrolling interests Net income attributable to controlling interests Net Income Total other comprehensive income (loss) Comprehensive income Comprehensive income attributable to noncontrolling interests $ $ — 20 22 42 (6) 2,025 — (539) (1) 1,479 (41) 1,438 — 1,438 (245) 1,193 1,438 81 1,519 (232) $ $ — — — — — 3,251 — 41 — 3,292 (11) 3,281 — 3,281 — 3,281 3,281 (135) 3,146 — $ $ Comprehensive income attributable to controlling interests $ 1,287 $ 3,146 $ 153 — — 38 38 (38) 163 — (36) (1) 88 — 88 — 88 — 88 88 — 88 — 88 $ $ $ — — 8 8 (8) 759 — (157) — 594 — 594 — 594 — 594 594 — 594 — 4,739 1,466 2,325 8,530 3,981 1,986 323 (949) 549 5,890 50 468 320 663 1,451 61 1,755 4 (35) 249 2,034 (740) 46 — (35) 11 — (9,939) — — — (9,939) — 5,940 1,294 (9,939) (4) 5,936 (236) 5,700 5,936 (145) 5,791 (237) $ $ — 1,294 — 1,294 1,294 (172) 1,122 — $ $ — (9,939) (1,018) (10,957) $ (9,939) $ 411 (9,528) (976) $ $ 594 $ 5,554 $ 1,122 $ (10,504) $ 5,253 1,806 3,021 10,080 3,990 — 327 (1,675) 796 3,438 (742) 2,696 (4) 2,692 (1,499) 1,193 2,692 40 2,732 (1,445) 1,287 Condensed Consolidating Statements of Income and Comprehensive Income for the Year Ended December 31, 2012 (In Millions) Subsidiary Issuer and Guarantor - KMP Subsidiary Issuer and Guarantor - Copano Subsidiary Issuer and Guarantor - EPB $ — $ — $ — $ Subsidiary Guarantors 8,651 Subsidiary Non- Guarantors 1,265 $ Consolidating Adjustments 22 $ Consolidated KMI $ 9,973 Total Revenues Operating costs, expenses and other Costs of sales Depreciation, depletion and amortization Other operating expenses Total operating costs, expenses and other Operating (loss) income Other income (expense) Earnings from consolidated subsidiaries Earnings from equity investments Interest, net Amortization of excess cost of equity investments and other, net Parent Issuer and Guarantor 35 $ — 19 295 314 (279) 842 — (630) (1) — — — — — 1,351 — 41 — (Loss) income from continuing operations before income taxes (68) 1,392 Income tax benefit (expense) Income from continuing operations Loss from discontinued operations Net income Net loss (income) attributable to noncontrolling interests Net income attributable to controlling interests Net Income Total other comprehensive income Comprehensive income Comprehensive income attributable to noncontrolling interests $ $ 392 324 (14) 310 5 315 310 12 322 (10) $ $ (9) 1,383 — 1,383 — 1,383 1,383 165 1,548 — $ $ — — — — — — — — — — — — — — — — $ — $ — — — — — 2 2 (2) 436 — (69) — 365 — 365 — 365 — 365 365 10 375 — 2,761 1,091 2,172 6,024 2,627 815 206 (757) (21) 271 309 438 1,018 247 1,466 (53) 16 18 25 — (3) 22 — (4,910) — — — 3,057 1,419 2,904 7,380 2,593 — 153 (1,399) (4) 2,870 1,694 (4,910) 1,343 98 (620) — (139) 2,968 1,074 (4,910) 1,204 (2) (761) — $ $ $ $ 2,966 (168) 2,798 2,966 200 3,166 (174) $ $ 313 — 313 313 96 409 — (4,910) 51 (4,859) $ (4,910) $ (412) (5,322) (2) (777) 427 (112) 315 427 71 498 (186) 312 Comprehensive income attributable to controlling interests $ 312 $ 1,548 $ — $ 375 $ 2,992 $ 409 $ (5,324) $ 154 Condensed Consolidating Balance Sheets as of December 31, 2014 (In Millions) Parent Issuer and Guarantor Subsidiary Issuer and Guarantor - KMP Subsidiary Issuer and Guarantor - Copano Subsidiary Issuer and Guarantor - EPB Subsidiary Guarantors Subsidiary Non- Guarantors Consolidating Adjustments Consolidated KMI $ $ $ $ $ $ 4 1,870 397 263 16 31,364 15,087 4,459 — 287 53,747 1,486 709 318 11,862 2,619 2,094 583 19,671 34,076 — 34,076 $ $ $ 15 1,332 151 — — 27,264 — 19,824 — 341 48,927 324 11,926 463 18,197 153 — 78 31,141 17,786 — 17,786 — $ 11 3 5 — 1,911 920 — — — 2,850 $ — $ 115 12 386 753 2 2 1,270 1,580 — 1,580 — $ 1 1 — 1 6,150 22 8 — 19 6,202 $ $ 375 23 34 2,478 1,206 — — 4,116 2,086 — 2,086 $ $ $ 17 11,575 2,547 29,490 5,910 16,387 5,419 3,621 9,251 3,782 87,999 381 1,553 1,814 6,609 22,437 — 987 33,781 54,218 — 54,218 279 403 358 8,806 109 3,337 3,206 496 — 112 17,106 151 866 1,024 714 1,240 1,504 514 6,013 11,093 — 11,093 $ — $ (15,192) (20) — — (86,413) — (28,408) (3,600) — $ (133,633) $ $ — $ (15,192) (20) — (28,408) (3,600) — (47,220) (86,763) 350 (86,413) 315 — 3,437 38,564 6,036 — 24,654 — 5,651 4,541 83,198 2,717 — 3,645 40,246 — — 2,164 48,772 34,076 350 34,426 $ 53,747 $ 48,927 $ 2,850 $ 6,202 $ 87,999 $ 17,106 $ (133,633) $ 83,198 ASSETS Cash and cash equivalents Other current assets - affiliates All other current assets Property, plant and equipment, net Investments Investments in subsidiaries Goodwill Notes receivable from affiliates Deferred tax assets Other non-current assets Total assets LIABILITIES AND STOCKHOLDERS’ EQUITY Liabilities Current portion of debt Other current liabilities - affiliates All other current liabilities Long-term debt Notes payable to affiliates Deferred income taxes All other long-term liabilities and deferred credits Total liabilities Stockholders’ equity Total KMI equity Noncontrolling interests Total stockholders’ equity Total liabilities and stockholders’ equity 155 Condensed Consolidating Balance Sheets as of December 31, 2013 (In Millions) Parent Issuer and Guarantor Subsidiary Issuer and Guarantor - KMP Subsidiary Issuer and Guarantor - Copano Subsidiary Issuer and Guarantor - EPB Subsidiary Guarantors Subsidiary Non- Guarantors Consolidating Adjustments Consolidated KMI ASSETS Cash and cash equivalents $ 83 $ 10 $ Other current assets - affiliates All other current assets Property, plant and equipment, net Investments Investments in subsidiaries Goodwill Notes receivable from affiliates Other non-current assets 287 657 284 17 13,618 15,099 — 455 751 136 — — 26,555 — 17,284 233 $ 1 — 2 170 — 4,430 813 — — 78 18 — — — 4,445 22 — 20 $ 17 $ 10,992 2,184 26,698 5,822 3,584 5,317 3,087 3,866 409 220 302 8,695 112 3,839 3,253 511 441 $ — $ (12,268) (11) — — (56,471) — (20,882) — Total assets $ 30,500 $ 44,969 $ 5,416 $ 4,583 $ 61,567 $ 17,782 $ (89,632) $ LIABILITIES AND STOCKHOLDERS’ EQUITY Liabilities Current portion of debt $ Other current liabilities - affiliates All other current liabilities Long-term debt Notes payable to affiliates Deferred income taxes Other long-term liabilities and deferred credits Total liabilities Stockholders’ equity Total KMI equity Noncontrolling interests Total stockholders’ equity Total liabilities and stockholders’ equity 575 379 72 7,775 1,993 2,022 384 13,200 13,093 4,207 17,300 $ 1,504 $ — $ — $ 77 $ 10,453 394 15,644 — — 173 28,168 16,801 — 16,801 55 41 393 907 2 — 1,398 4,018 — 4,018 19 30 2,253 1,143 — — 3,445 1,138 — 1,138 823 1,728 7,101 15,599 1,142 1,023 27,493 31,025 3,049 34,074 150 539 1,515 721 1,240 1,485 707 6,357 11,478 (53) 11,425 $ — $ (12,268) (11) — (20,882) — — (33,161) (64,460) 7,989 (56,471) $ 30,500 $ 44,969 $ 5,416 $ 4,583 $ 61,567 $ 17,782 $ (89,632) $ 75,185 156 598 — 3,270 35,847 5,951 — 24,504 — 5,015 75,185 2,306 — 3,769 33,887 — 4,651 2,287 46,900 13,093 15,192 28,285 Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2014 (In Millions) Parent Issuer and Guarantor 1,426 $ Subsidiary Issuer and Guarantor - KMP Subsidiary Issuer and Guarantor - Copano Subsidiary Issuer and Guarantor - EPB $ 3,998 $ (77) $ 885 Subsidiary Guarantors 6,345 $ Subsidiary Non- Guarantors 1,174 $ Consolidating Adjustments $ (9,284) $ Consolidated KMI (1,756) (1) (6,559) — — (63) (1,252) — Net cash provided by (used in) operating activities Cash flows from investing activities Funding to affiliates Capital expenditures Sale, casualty and transfer of property, plant and equipment, investments and other net assets, net of removal costs Contributions to investments Investments in KMP and EPB Acquisitions of assets and investments Drop down assets to EPB Distributions from equity investments in excess of cumulative earnings Other, net Net cash (used in) provided by investing activities Cash flows from financing activities Issuance of debt Payment of debt Funding from (to) affiliates Debt issuance costs Cash dividends Repurchases of shares and warrants Cash consideration of Merger Transactions Merger Transactions costs Contributions from parents Contributions from noncontrolling interests Distributions to parents Distributions to noncontrolling interests Other, net Net cash (used in) provided by financing activities Effect of exchange rate changes on cash and cash equivalents Net (decrease) increase in cash and cash equivalents Cash and cash equivalents, beginning of period Cash and cash equivalents, end of period $ — — (550) — 875 93 — (1,339) 10,594 (5,479) 756 (74) (1,760) (192) (3,937) (74) — — — — — (166) — (79) 83 4 $ — — — — — — 29 (6,530) 13,057 (11,849) 3,823 (11) — — — — 1,178 — (3,660) — (1) 2,537 — 5 10 15 202 — — — — — — 139 — — (63) — — — — — — — — — — (63) — (1) 1 — $ $ 157 (4,706) (3,050) (9) (594) — (1,370) (875) 183 27 (10,394) — (142) 9,138 — — — — — 1,267 — (6,213) — (2) 4,048 — (189) — — — 440 — (1,001) 922 (322) 786 (4) — — — — 205 — (1,549) — — 38 — (78) 78 — $ 1 — 17 17 $ (1,088) (705) 15,361 202 14 — — (18) — — (60) (1,857) — (9) 921 — — — — — 64 — (411) — — 565 (12) (130) 409 279 (202) 394 550 — — (534) 1 15,772 — — (15,361) — — — — — (2,714) 1,767 11,833 (2,013) — (6,488) — — — — $ $ 4,467 — (3,617) 5 (389) — (1,388) — 182 (3) (5,210) 24,573 (17,801) — (89) (1,760) (192) (3,937) (74) — 1,767 — (2,013) (3) 471 (11) (283) 598 315 Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2013 (In Millions) Parent Issuer and Guarantor 1,775 $ Subsidiary Issuer and Guarantor - KMP Subsidiary Issuer and Guarantor - Copano Subsidiary Issuer and Guarantor - EPB $ 4,173 $ (408) $ 64 Subsidiary Guarantors 5,491 $ Subsidiary Non- Guarantors 769 $ Consolidating Adjustments $ (7,742) $ Consolidated KMI Net cash provided by (used in) operating activities Cash flows from investing activities Funding to affiliates Capital expenditures Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs Proceeds from sale of assets and investments Contributions to investments Investments in KMP and EPB Acquisitions of assets and investments Drop down assets to KMP Distributions from equity investments in excess of cumulative earnings Other, net Net cash provided by (used in) investing activities Cash flows from financing activities Issuance of debt Payment of debt Funding from affiliates Debt issuance costs Cash dividends Repurchases of shares and warrants Contributions from parents Contributions from noncontrolling interests Distributions to parents Distributions to noncontrolling interests Other, net Net cash (used in) provided by financing activities Effect of exchange rate changes on cash and cash equivalents Net increase (decrease) in cash and cash equivalents Cash and cash equivalents, beginning of period Cash and cash equivalents, end of period $ (402) (6) — — (6) (68) — 994 41 — 553 3,028 (3,624) 576 (15) (1,622) (637) — — — — 1 (2,293) (7,145) — (1) (141) — — — — — — — (12) (7,157) 10,213 (7,627) 1,971 (22) — — 1,533 — (3,168) — (1) 2,899 — — — — 5 — — — (137) — (854) 1,400 — — — — — — — — 546 (661) — — — (52) — — — 296 — (417) 87 (175) 1,332 — — — 1 — (924) — — 321 (4,270) (2,418) (1,332) (804) 13,811 — 87 118 (218) — (297) (994) 183 18 (7,791) 14 (106) 7,740 — — — 162 — (5,522) — — 2,288 — 372 — — — — — (12) (1,776) 239 (7) 792 (1) — — 132 — (150) — — 1,005 — — 59 68 — — (335) — 13,603 — — (13,811) — — — (1,828) 1,706 9,764 (1,692) — (5,861) — 35 48 83 $ — (85) 95 10 $ — 1 — 1 $ — (32) 110 78 $ 1 (11) 28 17 $ (22) (24) 433 409 $ — — — — $ 158 4,122 — (3,369) 87 490 (217) — (292) — 185 (6) (3,122) 13,581 (12,393) — (38) (1,622) (637) — 1,706 — (1,692) — (1,095) (21) (116) 714 598 Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2012 (In Millions) Subsidiary Issuer and Guarantor - KMP Subsidiary Issuer and Guarantor - Copano Subsidiary Issuer and Guarantor - EPB $ 3,867 $ — $ (151) $ Subsidiary Guarantors 3,095 Subsidiary Non- Guarantors 941 $ Consolidating Adjustments $ (5,601) $ Consolidated KMI Net cash provided by (used in) operating activities Cash flows from investing activities Funding (to) from affiliates Capital expenditures Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs Acquisition of EP Contributions to investments Investments in KMP and EPB Acquisitions of assets and investments Drop down assets to KMP Distributions from equity investments in excess of cumulative earnings Proceeds from disposal of discontinued operations Other, net Net cash used in investing activities Cash flows from financing activities Issuance of debt Payment of debt Funding from affiliates Debt issuance costs Cash dividends Repurchases of shares and warrants Contributions from parents Contributions from noncontrolling interests Distributions to parents Distributions to noncontrolling interests Other, net Net cash provided by financing activities Parent Issuer and Guarantor 657 $ (857) (5) — (5,212) (15) (94) — 3,485 16 — — (2,682) 8,001 (5,692) 1,268 (91) (1,184) (157) — — — — (74) 2,071 Effect of exchange rate changes on cash and cash equivalents Net increase in cash and cash equivalents Cash and cash equivalents, beginning of period Cash and cash equivalents, end of period — 46 2 48 $ $ — — — — — — — — — — — — — — — — — — — — — — — — — — — $ 42 — — 81 (454) — — — 106 — — (225) 658 (855) 1,049 (4) — — 29 — (391) — — 486 — 110 — 110 (3,515) (1,423) 64 70 (206) — (83) (3,485) 184 1,791 121 (6,482) — (205) 6,612 — — — 763 — (3,763) — (2) 3,405 — 18 10 28 $ $ (1,448) (594) 11,299 — 90 91 — — — — — — (81) (1,942) 219 — 1,010 — — — 30 — (231) — — 1,028 8 35 398 433 — — 483 94 — — (106) — — 11,770 — — (11,299) — — — (2,503) 1,939 6,913 (1,219) — (6,169) — — — — $ $ (5,521) — — — — — — — — (15) (5,536) 9,270 (8,003) 1,360 (16) — — 1,681 — (2,528) — (1) 1,763 — 94 1 95 $ 159 2,808 — (2,022) 154 (4,970) (192) — (83) — 200 1,791 25 (5,097) 18,148 (14,755) — (111) (1,184) (157) — 1,939 — (1,219) (77) 2,584 8 303 411 714 Table of Contents Supplemental Selected Quarterly Financial Data (Unaudited) 2014 Revenues Operating Income Net Income Net Income Attributable to Kinder Morgan, Inc. Basic and Diluted Earnings Per Common Share 2013 Revenues Operating Income Net Income Net Income Attributable to Kinder Morgan, Inc. Basic and Diluted Earnings Per Common Share Quarters Ended March 31 June 30 September 30 December 31 (In millions, except per share amounts) $ 4,047 $ 3,937 $ 4,291 $ 3,951 1,147 601 287 0.28 1,013 497 284 0.27 1,332 779 329 0.32 $ 3,060 $ 3,382 $ 3,756 $ 1,017 656 292 0.28 772 781 277 0.27 1,041 551 286 0.27 956 566 126 0.08 3,872 1,160 704 338 0.33 160 Table of Contents 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, 2014 2013 2012 Consolidated Companies(a) Production costs per barrel of oil equivalent(b)(c)(d) $ 20.55 $ 18.81 $ 16.44 Crude oil production (MBbl/d) SACROC crude oil production (MBbl/d) Yates crude oil production (MBbl/d) NGL production (MBbl/d)(d) NGL production from gas plants(MBbl/d)(e) Total NGL production(MBbl/d) SACROC NGL production (MBbl/d)(d) Yates NGL production (MBbl/d)(d) Natural gas production (MMcf/d)(d)(f) Natural gas production from gas plants(MMcf/d)(e)(f) Total natural gas production(MMcf/d)(f) Yates natural gas production (MMcf/d)(d)(f) Average sales prices including hedge gains/losses: Crude oil price per Bbl(g) NGL price per Bbl(d)(g) Natural gas price per Mcf(d)(h) Total NGL price per Bbl(e) Total natural gas price per Mcf(e) Average sales prices excluding hedge gains/losses: Crude oil price per Bbl(g) NGL price per Bbl(g) Natural gas price per Mcf(h) 40.8 27.6 8.8 4.2 5.9 10.1 3.9 0.2 1.0 1.2 2.2 1.0 37.6 25.5 9.0 4.1 5.8 9.9 3.8 0.2 1.1 1.7 2.8 1.1 $ $ $ $ $ $ $ $ 88.41 42.61 4.04 41.87 3.91 86.48 42.61 4.04 $ $ $ $ $ $ $ $ 92.70 46.11 3.23 46.43 3.21 94.94 46.11 3.23 $ $ $ $ $ $ $ $ 35.0 24.1 9.3 3.9 5.6 9.5 3.7 0.2 1.2 0.7 1.9 1.1 87.72 51.79 2.58 50.95 2.72 89.91 51.79 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. 161 Table of Contents 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 Consolidated Companies(a) Wells and equipment, facilities and other Leasehold Total proved oil and gas properties Unproved property(b) Accumulated depreciation and depletion(c) Net capitalized costs As of December 31, 2014 2013 2012 $ 4,937 $ 4,432 $ 658 5,595 103 (4,226) 1,472 $ 660 5,092 38 (3,520) 1,610 $ $ 3,927 428 4,355 8 (3,072) 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 Consolidated Companies Acquisitions(a) Development(b) Exploration(c) Year Ended December 31, 2014 2013 2012 $ — $ 481 95 $ 285 471 11 — 310 — _______ (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. 162 Table of Contents 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 Consolidated Companies(a) Revenues(b) Expenses: Production costs Other operating expenses(c) Exploration expense(d) Impairment(e) DD&A expenses Total expenses Year Ended December 31, 2014 2013 2012 $ 1,412 $ 1,376 $ 1,235 403 99 8 235 430 1,175 344 95 — — 415 854 522 $ 288 77 — — 387 752 483 Results of operations for oil and gas producing activities $ 237 $ _______ (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 163 Table of Contents 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 164 Table of Contents 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%. 165 Table of Contents 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) NGL (MBbl) Natural Gas (MMcf)(b) Crude Oil (MBbl) Proved developed and undeveloped reserves: As of December 31, 2011 Revisions of previous estimates(c) Extensions and discoveries Sales of reserves in place Production As of December 31, 2012 Revisions of previous estimates(d) Purchases of reserves in place(e) Production As of December 31, 2013 Revisions of previous estimates(f) Production As of December 31, 2014 Proved developed reserves: As of December 31, 2012 As of December 31, 2013 As of December 31, 2014 Proved undeveloped reserves: As of December 31, 2012 As of December 31, 2013 As of December 31, 2014 79,447 15,540 26 (239) (12,824) 81,950 (2,573) 41,389 (13,735) 107,031 5,378 (14,852) 97,557 53,006 67,436 60,252 28,944 39,595 37,305 4,145 3,285 — (38) (1,416) 5,976 (43) 10,347 (1,499) 14,781 (2,419) (1,542) 10,820 2,433 6,733 4,584 3,543 8,048 6,236 3,241 4,881 — (143) (440) 7,539 (5,063) — (406) 2,070 372 (373) 2,069 7,539 2,070 2,069 — — — _______ (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; 166 Table of Contents • • • • 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 Consolidated Companies(a) Future cash inflows from production Future production costs Future development costs(b) Undiscounted future net cash flows 10% annual discount Standardized measure of discounted future net cash flows(c) As of December 31, 2014 2013 2012 $ $ 9,406 (4,294) (2,113) 2,999 (1,089) 1,910 $ $ 10,945 (4,214) (1,948) 4,783 (2,096) 2,687 $ $ 7,807 (2,923) (1,011) 3,873 (1,168) 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 Consolidated Companies(a) Present value as of January 1 Changes during the year: Revenues less production and other costs(b) Net changes in prices, production and other costs Development costs incurred Net changes in future development costs Improved recovery Extensions and discoveries(c) Sales of reserves in place(d) Revisions of previous quantity estimates(e) Purchase of reserves in place(f) Accretion of discount Net change for the year Present value as of December 31 167 As of December 31, 2014 2013 2012 $ 2,687 $ 2,705 $ 2,194 (880) (504) 502 (479) — — — 329 — 255 (777) 1,910 $ $ (965) 258 452 (629) — — — (114) 683 297 (18) 2,687 (895) (88) 353 64 — 5 (5) 871 — 206 511 $ 2,705 Table of Contents _______ (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. 168 Table of Contents 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 169 Table of Contents 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. Signature Title Date /s/ KIMBERLY A. DANG Kimberly A. Dang /s/ RICHARD D. KINDER Richard D. Kinder /s/ TED A. GARDNER Ted A. Gardner /s/ ANTHONY W. HALL, JR. Anthony W. Hall, Jr. /s/ GARY L. HULTQUIST Gary L. Hultquist /s/ STEVEN J. KEAN Steven J. Kean /s/ RONALD L. KUEHN, JR. Ronald L. Kuehn, Jr. /s/ DEBORAH A. MACDONALD Deborah A. Macdonald /s/ MICHAEL J. MILLER Michael J. Miller /s/ MICHAEL C. MORGAN Michael C. Morgan /s/ ARTHUR C. REICHSTETTER Arthur C. Reichstetter /s/ FAYEZ SAROFIM Fayez Sarofim /s/ C. PARK SHAPER C. Park Shaper /s/ WILLIAM A. SMITH William A. Smith /s/ JOEL V. STAFF Joel V. Staff /s/ ROBERT F. VAGT Robert F. Vagt /s/ PERRY M. WAUGHTAL Perry M. Waughtal Vice President and Chief Financial Officer (principal financial officer and principal accounting officer) February 23, 2015 Director, Chairman and Chief Executive Officer (principal executive officer) February 23, 2015 February 23, 2015 February 23, 2015 February 23, 2015 February 23, 2015 February 23, 2015 February 23, 2015 February 23, 2015 February 23, 2015 February 23, 2015 February 23, 2015 February 23, 2015 February 23, 2015 February 23, 2015 February 23, 2015 February 23, 2015 Director Director Director Director Director Director Director Director Director Director Director Director Director Director Director 170 Exhibit 3.1 CERTIFICATE OF INCORPORATION OF KINDER MORGAN, INC. The undersigned, acting as an incorporator of a corporation (hereinafter called the “Company”) under the General Corporation Law of the State of Delaware (“DGCL”), hereby adopts the following Certificate of Incorporation for the Company: FIRST: The name of the Company is Kinder Morgan, Inc. SECOND: The registered office of the Company in the State of Delaware is located at Corporation Service Company, 2711 Centerville Road, Suite 400, Wilmington, DE 19808, County of New Castle. The name of the registered agent of the Company at such address is Corporation Service Company. THIRD: The purpose for which the Company is organized is to engage in any and all lawful act and activity for which corporations may be organized under the DGCL. The Company will have perpetual existence. FOURTH: A. Authorized Shares The total number of shares of capital stock which the Company shall have authority to issue is 2,819,462,927 shares, of which 10,000,000 shares shall be preferred stock, par value $0.01 per share (the “Preferred Stock”), and 2,809,462,927 shares shall be common stock, par value $0.01 per share (the “Common Stock”), consisting of: (1) 2,000,000,000 shares of Class P Common Stock (the “Class P Common Stock”); (2) 707,000,000 shares of Class A Convertible Common Stock (the “Class A Common Stock”), which shall be divided into nine (9) different series (each, a “Class A Series”), as follows: (a) 143,074,656 shares of Class A Common Stock shall be designated as Series A-1 Stock (the “Series A-1 Stock”); (b) 35,390,780 shares of Class A Common Stock shall be designated as Series A-2 Stock (the “Series A-2 Stock”); (c) 112,870,410 shares of Class A Common Stock shall be designated as Series A-3 Stock (the “Series A-3 Stock”); (d) 78,821,388 shares of Class A Common Stock shall be designated as Series A-4 Stock (the “Series A-4 Stock”); Exhibit 3.1 (e) 78,821,388 shares of Class A Common Stock shall be designated as Series A-5 Stock (the “Series A-5 Stock”); (f) 216,538,834 shares of Class A Common Stock shall be designated as Series A-6 Stock (the “Series A-6 Stock”); (g) 5,761,863 shares of Class A Common Stock shall be designated as Series A-7 Stock (the “Series A-7 Stock”); (h) 31,178,252 shares of Class A Common Stock shall be designated as Series A-8 Stock (the “Series A-8 Stock”); and (i) 4,542,429 shares of Class A Common Stock shall be designated as Series A-9 Stock (the “Series A-9 Stock”). (3) 100,000,000 shares of Class B Convertible Common Stock (the “Class B Common Stock”), which shall be divided into nine (9) different series (each, a “Class B Series”), as follows: (a) 20,236,868 shares of Class B Common Stock shall be designated as Series B-1 Stock (the “Series B-1 Stock”); (b) 5,005,768 shares of Class B Common Stock shall be designated as Series B-2 Stock (the “Series B-2 Stock”); (c) 15,964,697 shares of Class B Common Stock shall be designated as Series B-3 Stock (the “Series B-3 Stock”); (d) 11,148,711 shares of Class B Common Stock shall be designated as Series B-4 Stock (the “Series B-4 Stock”); (e) 11,148,711 shares of Class B Common Stock shall be designated as Series B-5 Stock (the “Series B-5 Stock”); (f) 30,627,841 shares of Class B Common Stock shall be designated as Series B-6 Stock (the “Series B-6 Stock”); (g) 814,974 shares of Class B Common Stock shall be designated as Series B-7 Stock (the “Series B-7 Stock”); (h) 4,409,937 shares of Class B Common Stock shall be designated as Series B-8 Stock (the “Series B-8 Stock”); and (i) 642,493 shares of Class B Common Stock shall be designated as Series B-9 Stock (the “Series B-9 Stock”). Each Class B Series will be deemed to correspond to the Class A Series and the Class C Series designated by the same number, such that the Series B-1 Stock will be deemed to correspond to the Exhibit 3.1 Series A-1 Stock and the Series C-1 Stock, and each subsequently-numbered Class B Series will be deemed to correspond to the Class A Series and the Class C Series bearing the corresponding number. (4) 2,462,927 shares of Class C Convertible Common Stock (the “Class C Common Stock”), which shall be divided into nine (9) different series (each, a “Class C Series”), as follows: (a) 498,419 shares of Class C Common Stock shall be designated as Series C-1 Stock (the “Series C-1 Stock”); (b) 123,288 shares of Class C Common Stock shall be designated as Series C-2 Stock (the “Series C-2 Stock”); (c) 393,199 shares of Class C Common Stock shall be designated as Series C-3 Stock (the “Series C-3 Stock”); (d) 274,585 shares of Class C Common Stock shall be designated as Series C-4 Stock (the “Series C-4 Stock”); (e) 274,585 shares of Class C Common Stock shall be designated as Series C-5 Stock (the “Series C-5 Stock”); (f) 754,341 shares of Class C Common Stock shall be designated as Series C-6 Stock (the “Series C-6 Stock”); (g) 20,072 shares of Class C Common Stock shall be designated as Series C-7 Stock (the “Series C-7 Stock”); (h) 108,614 shares of Class C Common Stock shall be designated as Series C-8 Stock (the “Series C-8 Stock”); and (i) 15,824 shares of Class C Common Stock shall be designated as Series C-9 Stock (the “Series C-9 Stock”). Each Class C Series will be deemed to correspond to the Class A Series and the Class B Series designated by the same number, such that the Series C-1 Stock will be deemed to correspond to the Series A-1 Stock and the Series B-1 Stock, and each subsequently-numbered Class C Series will be deemed to correspond to the Class A Series and the Class B Series bearing the corresponding number. Certain capitalized terms used in this Certificate of Incorporation are defined in Section B of this Article Fourth. The shares of Common Stock shall have the rights, preferences and limitations set forth in Sections C, D, E and F of this Article Fourth. Except as otherwise set forth in Section D.2 (a)(x) of this Article Fourth, references to the holders of shares of Common Stock shall mean the holders of shares of Common Stock as reflected on the books of the Company as of a specific date. Exhibit 3.1 Shares of Preferred Stock may be issued from time to time in one or more series of any number of shares as may be determined from time to time by the board of directors, provided that the aggregate number of shares issued and not cancelled of any and all such series shall not exceed the total number of shares of Preferred Stock authorized by this Certificate of Incorporation. Each series of Preferred Stock shall be distinctly designated. All shares of a series of Preferred Stock shall be alike in every particular, except that shares of any one series issued at different times may differ as to the dates from which dividends thereon shall be cumulative. The voting powers, if any, of each such series and the preferences and relative, participating, optional and other special rights of each such series and the qualifications, limitations and restrictions thereof, if any, may differ from those of any and all other series at any time outstanding; and the board of directors is hereby expressly granted authority to fix, in the resolution or resolutions providing for the issue of a particular series of Preferred Stock, the voting powers, if any, of each such series and the designations, preferences and relative, participating, optional and other special rights of each such series and the qualifications, limitations and restrictions thereof to the full extent now or hereafter permitted by this Certificate of Incorporation and the laws of the State of Delaware. B. Certain Definitions As used in this Article Fourth and elsewhere in this Certificate of Incorporation, the following terms shall have the following meanings: “10%-20% Automatic Conversion Percentage” shall mean, for any Class B Series, as of the time of determination thereof, with respect to any conversion of shares of such Class B Series referenced in Section D.2(b)(ii) of this Article Fourth, the number (expressed as a percentage) equal to the sum of (i) 10% and (ii) the product of (a) 10% and (b) a fraction (no greater than one (1)), the numerator of which is the amount, if any, by which Total Value for the Related Series (determined, for this purpose, by taking into account the Class P Shares received upon such conversion of shares of such Class B Series) would exceed 200% of the Aggregate Base Amount for the Related Series, and the denominator of which is 200% of the Aggregate Base Amount for the Related Series. “10%-20% Distribution Percentage” shall mean, for any Series, as of the time of determination thereof, with respect to any Distribution referenced in Section C.2(e), C.3(e) or C.4(e) of this Article Fourth to the holders of shares of such Series, the number (expressed as a percentage) equal to the sum of (i) 10% and (ii) the product of (a) 10% and (b) a fraction (no greater than one (1)), the numerator of which is the amount, if any, by which the Total Value for such Series exceeds 200% of the Aggregate Base Amount for such Series, and the denominator of which is 200% of the Aggregate Base Amount for such Series. “10%-20% Mandatory Conversion Percentage” shall mean, for any Class B Series, as of the Mandatory Conversion Date, the number (expressed as a percentage) equal to the sum of (i) 10% and (ii) the product of (a) 10% and (b) a fraction (no greater than one (1)), the numerator of which is the amount, if any, by which the sum of (x) the Total Value for the Related Series, (y) the amounts, if any, described in clauses (i) through (iv) of the definition of Class A Maximum Amount and (z) the amounts, if any, described in clauses (i) through (iv) of the definition of Class B Maximum Amount (which sum of the values described in clauses (x), (y) and (z) shall not exceed the lesser of (A) 400% of the Aggregate Base Amount for the Related Series and (B) the Aggregate Amount Exhibit 3.1 with respect to the Related Series) would exceed 200% of the Aggregate Base Amount for the Related Series, and the denominator of which is 200% of the Aggregate Base Amount for the Related Series; provided, however, that if the sum of the values contained in clauses (x), (y) and (z) above is less than 200% of the Aggregate Base Amount for the Related Series, the 10%-20% Mandatory Conversion Percentage shall be zero. “100% Threshold” shall mean, for any Series, the Series A Total Value being equal to 100% of the Base Amount for the Class A Series included in such Series. “150% Threshold” shall mean, for any Series, the Total Value being equal to 150% of the Aggregate Base Amount for such Series. “200% Threshold” shall mean, for any Series, the Total Value being equal to 200% of the Aggregate Base Amount for such Series. “400% Threshold” shall mean, for any Series, the Total Value being equal to 400% of the Aggregate Base Amount for such Series. “Affiliate” of any Person shall mean any other Person that directly or indirectly, through one or more intermediaries, Controls, is Controlled by, or is under common Control with, such first Person. “Aggregate Amount” shall mean, with respect to any particular Series, an amount equal to the sum of the Mandatory Conversion Date Value and the Total Value, in each case for such Series. “Aggregate Base Amount” shall mean, with respect to any particular Series, the sum of (x) the Base Amount for such Class A Series and (y) the Notional Base Amount for the corresponding Class C Series. “All Cash Sale” shall have the meaning set forth in Section D.2(a)(i) of this Article Fourth. “All Cash Tender Offer” shall have the meaning set forth in Section D.2(a)(i) of this Article Fourth. “Annual Class B Priority Dividend Period” shall mean any of the following: (i) the period including the first, second, third and fourth calendar quarters during the Class B Priority Dividend Period, (ii) the period including the fifth, sixth, seventh and eighth calendar quarters during the Class B Priority Dividend Period, (iii) the period including the ninth, tenth, eleventh and twelfth calendar quarters during the Class B Priority Dividend Period or (iv) the period including the thirteenth, fourteenth, fifteenth and sixteenth calendar quarters during the Class B Priority Dividend Period. “Annual Class B Priority Dividend Shortfall” shall mean an amount, if any, equal to (x) the Annual Maximum Class B Priority Dividend Amount for the immediately preceding Annual Class B Priority Dividend Period less (y) the aggregate amount of Distributions received by all Class B Shareholders pursuant to Section C.3(a) of this Article Fourth during such immediately preceding Annual Class B Priority Dividend Period; provided, that if the Annual Class B Priority Dividend Shortfall is greater than zero for two Annual Class B Priority Dividend Periods, then the amount of the Annual Class B Priority Dividend Shortfall shall equal zero for each subsequent Annual Class B Priority Dividend Period, if any. Exhibit 3.1 “Annual Maximum Class B Priority Dividend Amount” shall mean, (i) with respect to the first Annual Class B Priority Dividend Period, $50,000,000 and (ii) with respect to the second, third and fourth Annual Class B Priority Dividend Periods, an amount equal to (A) $50,000,000 plus (B) the lesser of (x) the Annual Class B Priority Dividend Shortfall or (y) the actual amount of Distributions received by all Class B Shareholders pursuant to Section C.3(a) of this Article Fourth for the first calendar quarter of the Annual Class B Priority Dividend Period with respect to which the Annual Maximum Class B Priority Dividend Amount is being calculated. “Appraisal Procedure” shall require that, with respect to any dispute that this Article Fourth provides will be the subject of the Appraisal Procedure, each of the two designated parties to such dispute selects one (1) independent, nationally recognized investment banking firm within four (4) calendar days after delivery of the applicable notice of objection, such that two (2) independent, nationally recognized investment banking firms are selected. If such firms shall agree upon the determination that is the subject of such dispute, such determination shall be final, binding and conclusive with respect to the subject of such dispute. If within five (5) calendar days after appointment of the two (2) independent, nationally recognized investment banking firms, such firms are unable to agree upon the determination that is the subject of the dispute, a third independent, nationally recognized investment banking firm shall be chosen within four (4) calendar days thereafter by the mutual consent of such first two investment banking firms or, if such first two investment banking firms fail to agree upon the appointment of a third investment banking firm, such appointment shall be made by the American Arbitration Association, or any organization successor thereto. The written determination of such third independent, nationally recognized investment banking firm so appointed and chosen shall be given within five (5) calendar days after its appointment, and shall be final, binding and conclusive with respect to the subject of such dispute. If a designated party to the Appraisal Procedure does not deliver a notice of its selection of an independent, nationally recognized investment banking firm by the applicable deadline, such party shall have waived its right of selection and shall be bound by the determination of the independent, nationally recognized investment banking firm selected by the other designated party. The costs of conducting the dispute resolution contemplated by the Appraisal Procedure, including the fees of all appointed independent, nationally recognized investment banking firms, shall be borne by the Company. Each of the deadlines provided for in the Appraisal Procedure may be extended by mutual agreement of the parties to such Appraisal Procedure. For the avoidance of doubt, GS shall not be considered an independent investment banking firm, and GS and its Affiliates may not be appointed pursuant to the foregoing procedure as the independent, nationally recognized investment banking firm for any party. “Base Amount” shall mean, for any Class A Series, the dollar amount specified below for such series: Exhibit 3.1 Series A-1 $1,601,620,180 Series A-2 $396,174,908 Series A-3 $1,263,504,879 Series A-4 $882,350,016 Series A-5 $882,350,016 Series A-6 $2,424,000,000 Series A-7 Series A-8 $64,500,000 $349,018,612 Series A-9 $50,849,302 “Base Distribution Percentage” shall mean, for any Class A Series, the percentage set forth below for such series: Series A-1 20.2369% Series A-2 5.0058% Series A-3 15.9647% Series A-4 11.1487% Series A-5 11.1487% Series A-6 30.6278% Series A-7 0.8150% Series A-8 4.4099% Series A-9 0.6425% “Business Day” shall mean a day except a Saturday, a Sunday or other day on which banks in New York, New York or Houston, Texas are authorized or required by law to be closed. “Carlyle” shall mean (i) Carlyle Partners IV Knight, L.P. and CP IV Coinvestment, L.P., (ii) any investment funds or other entities sponsored, managed or owned directly or indirectly by Carlyle Investment Management L.L.C. or its Affiliates collectively d/b/a “The Carlyle Group” or “Carlyle”, Exhibit 3.1 or otherwise under common control with the entities listed in clause (i) or their successors (by merger, consolidation, acquisition of substantially all assets or similar transaction) or with any entity then included in clause (ii), to which any entity previously included in the definition of Carlyle transferred, directly or indirectly (including through a series of transfers), Class A Shares after the Initial Public Offering or Related Shares after a Mandatory Conversion Date, and (iii) any successors (by merger, consolidation, acquisition of substantially all assets or similar transaction) of the foregoing. For the avoidance of doubt, “Carlyle” shall be deemed not to include (A) Riverstone or any portfolio companies of any of the entities contained in clauses (i), (ii) or (iii) or (B) any entity that is not a party to the Shareholders Agreement. “Change of Control” shall mean any merger, amalgamation, consolidation or other business combination or similar transaction or series of transactions involving the Company pursuant to which all of the Class P Shares issued and outstanding immediately prior to the consummation of such transaction or transactions would be exchanged for cash, securities or other property. “Change of Control Determinations” shall have the meaning set forth in Section D.1(e)(ii) of this Article Fourth. “Change of Control Mandatory Acceleration Date” shall mean the date on which a Change of Control occurs. “Change of Control Notice” shall have the meaning set forth in Section D.1(e)(ii) of this Article Fourth. “Change of Control Objection Notice” shall have the meaning set forth in Section D.1(e)(iii) of this Article Fourth. “Class A Common Stock” shall have the meaning set forth in Section A.2 of this Article Fourth. “Class A Conversion Amount” shall mean, with respect to shares of a Class A Series held by a given holder prior to the applicable Voluntary Conversion of shares of such Class A Series (other than shares of Series A-9 Stock) or a conversion of shares of Series A-9 Stock resulting from such Voluntary Conversion, the product of (i) the aggregate number of Class A Shares of such Class A Series held by all holders of such Class A Series immediately prior to such conversion, (ii) a fraction, the numerator of which is the number of Class P Shares to be issued to all holders of shares of the Related Series pursuant to or resulting from such conversion of shares of such Class A Series and the denominator of which is the Total Number of Conversion Shares for the Related Series (immediately prior to the applicable conversion) and (iii) a fraction, the numerator of which is the number of Class P Shares to be issued to such given holder pursuant to or resulting from such conversion of shares of such Class A Series and the denominator of which is the aggregate number of Class P Shares to be issued to all Class A Shareholders of such Class A Series pursuant to or resulting from such conversion of shares of such Class A Series. “Class A Maximum Amount” shall mean, with respect to a particular Class A Series, an amount equal to the excess of (x) the sum of the amounts, if any, in clauses (i) through (v) below, over (y) the Class C Maximum Amount for the corresponding Class C Series: Exhibit 3.1 (i) 100% of the amount, if any, by which (A) the lesser of (1) the sum of 100% of the Base Amount for such Class A Series and the aggregate amount of Class B Priority Distributions paid in respect of shares of the corresponding Class B Series, and (2) the Aggregate Amount with respect to the Related Series exceeds (B) the Total Value with respect to the Related Series; (ii) 100% of the amount, if any, by which (A) the lesser of (1) the sum of 150% of the Aggregate Base Amount for the Related Series and the aggregate amount of Class B Priority Distributions paid in respect of shares of the corresponding Class B Series, and (2) the Aggregate Amount with respect to the Related Series exceeds (B) the greater of (1) the sum of 100% of the Base Amount for such Class A Series and the aggregate amount of Class B Priority Distributions paid in respect of shares of the corresponding Class B Series and (2) the Total Value with respect to the Related Series; (iii) 95% of the amount, if any, by which (A) the lesser of (1) 200% of the Aggregate Base Amount for the Related Series and (2) the Aggregate Amount with respect to the Related Series exceeds (B) the greater of (1) the sum of 150% of the Aggregate Base Amount for the Related Series and the First Catch-Up Amount for the corresponding Class B Series, and (2) the Total Value with respect to the Related Series; (iv) an amount equal to the excess, if any, of (A) (x) the lesser of (1) 400% of the Aggregate Base Amount for the Related Series and (2) the Aggregate Amount with respect to the Related Series minus (y) the greater of (1) the sum of 200% of the Aggregate Base Amount for the Related Series and the Second Catch-Up Amount for the corresponding Class B Series and (2) the Total Value with respect to the Related Series over (B) the amount, if any, described in clause (iv) of the definition of Class B Maximum Amount; and (v) 80% of the amount, if any, by which (A) the Aggregate Amount with respect to the Related Series exceeds (B) the greater of (1) 400% of the Aggregate Base Amount for the Related Series and (2) the Total Value with respect to the Related Series. “Class A Percentage” shall mean, with respect to a particular Class A Series, a number (expressed as a percentage) equal to the quotient obtained by dividing (x) the Base Amount for such Class A Exhibit 3.1 Series by (y) the Aggregate Base Amount for such Class A Series and the corresponding Class C Series. “Class A Series” shall have the meaning set forth in Section A.2 of this Article Fourth. “Class A Shareholder” shall mean a holder of Class A Shares. “Class A Shares” shall mean the shares of Class A Common Stock. “Class B Common Stock” shall have the meaning set forth in Section A.3 of this Article Fourth. “Class B Conversion Amount” shall mean, with respect to shares of a Class B Series held by a given holder prior to the conversion in question, the product of (i) the number of shares of such Class B Series held by such holder immediately prior to such conversion, and (ii) a fraction, the numerator of which is the number of Class P Shares to be issued to all holders of shares of such Class B Series pursuant to conversion of shares of such Class B Series and the denominator of which is the Total Number of Conversion Shares with respect to the Related Series (immediately prior to the applicable conversion). “Class B Fraction” shall mean, with respect to a holder of shares of a Class B Series, at the time of determination thereof, a fraction, the numerator of which is the number of shares of such Class B Series held by such holder and the denominator of which is the total number of shares of such Class B Series (in each case, immediately prior to the applicable conversion) issued and outstanding at such time of determination. “Class B Maximum Amount” shall mean, with respect to a particular Class B Series, an amount equal to the sum of: (i) 100% of the amount, if any, by which (A) the lesser of (1) the sum of 150% of the Aggregate Base Amount for the Related Series and the First Catch-Up Amount for such Class B Series, and (2) the Aggregate Amount with respect to the Related Series exceeds (B) the greater of (1) the sum of 150% of the Aggregate Base Amount for the Related Series and the aggregate amount of Class B Priority Distributions received in respect of shares of such Class B Series, and (2) the Total Value with respect to the Related Series; (ii) 5% of the amount, if any, by which (A) the lesser of (1) 200% of the Aggregate Base Amount for the Related Series and (2) the Aggregate Amount with respect to the Related Series exceeds (B) the greater of (1) the sum of 150% of the Aggregate Base Amount for the Related Series and the First Catch-Up Amount for such Class B Series, and (2) the Total Value with respect to the Related Series; Exhibit 3.1 (iii) 100% of the amount, if any, by which (A) the lesser of (1) the sum of 200% of the Aggregate Base Amount for the Related Series and the Second Catch-Up Amount for such Class B Series and (2) the Aggregate Amount with respect to the Related Series exceeds (B) the greater of (1) 200% of the Aggregate Base Amount for the Related Series and (2) the Total Value with respect to the Related Series; (iv) an amount, if any, such that the sum of the Series B Total Value and the amounts, if any, described in clauses (i) through (iii) of this definition and this clause (iv) equals the product of (A) the excess of, if any, (1) the sum of the Total Value for the Related Series and the amounts, if any, described in clauses (i) through (iv) of the definition of Class A Maximum Amount, clauses (i) through (iii) of this definition and this clause (iv) (which sum shall not exceed the lesser of (x) 400% of the Aggregate Base Amount for the Related Series and (y) the Aggregate Amount with respect to the Related Series) over (2) the Aggregate Base Amount for the Related Series and (B) the 10%-20% Mandatory Conversion Percentage; and (v) 20% of the amount, if any, by which (A) the Aggregate Amount with respect to the Related Series exceeds (B) the greater of (1) 400% of the Aggregate Base Amount for the Related Series and (2) the Total Value with respect to the Related Series. “Class B Priority Distributions” shall mean, as of the date of determination, any Distributions received in respect of Class B Shares pursuant to Section C.3(a) of this Article Fourth. For the avoidance of doubt, any Class B Priority Distribution shall be, and shall be treated as, a Distribution for all purposes under this Article Fourth. “Class B Priority Dividend Period” shall mean the period of sixteen (16) consecutive calendar quarters beginning with the calendar quarter in which the first quarterly dividend is declared after the Initial Public Offering. “Class B Series” shall have the meaning set forth in Section A.3 of this Article Fourth. “Class B Shareholder” shall mean a holder of Class B Shares. “Class B Shares” shall mean the shares of Class B Common Stock. “Class C Common Stock” shall have the meaning set forth in Section A.4 of this Article Fourth. “Class C Conversion Amount” shall mean, with respect to shares of a Class C Series held by a given holder prior to the conversion in question, the product of (i) the number of shares of such Class C Series held by such holder immediately prior to such conversion, and (ii) a fraction, the numerator of which is the number of Class P Shares to be issued to all holders of shares of such Class C Series pursuant to such conversion of shares of such Class C Series and the denominator of which is the Exhibit 3.1 Total Number of Conversion Shares with respect to the Related Series (immediately prior to the applicable conversion). “Class C Fraction” shall mean, with respect to a holder of shares of a Class C Series, at the time of determination thereof, a fraction, the numerator of which is the number of shares of such Class C Series held by such holder and the denominator of which is the total number of shares of such Class C Series (in each case, immediately prior to the applicable conversion) issued and outstanding at such date. “Class C Maximum Amount” shall mean, with respect to a particular Class C Series, an amount equal to the product of (x) the Class C Percentage for such Class C Series and (y) the sum of the amounts, if any, described in clauses (ii) through (v) of the definition of Class A Maximum Amount for the corresponding Class A Series. “Class C Percentage” shall mean, with respect to a particular Class C Series, a number (expressed as a percentage) equal to the quotient obtained by dividing (x) the Notional Base Amount for such Class C Series by (y) the Aggregate Base Amount for such Class C Series and the corresponding Class A Series. “Class C Series” shall have the meaning set forth in Section A.4 of this Article Fourth. “Class C Shareholder” shall mean a holder of Class C Shares. “Class C Shares” shall mean the shares of Class C Common Stock. “Class P Common Stock” shall have the meaning set forth in Section A.1 of this Article Fourth. “Class P Distribution Percentage” shall mean, as of the time of determination thereof, the number (expressed as a percentage) equal to the quotient obtained by dividing (i) the total number of Class P Shares then outstanding, by (ii) the sum of (x) the total number of Class P Shares then outstanding and (y) the sum of the Total Number of Conversion Shares for all Series in the aggregate. “Class P Shareholder” shall mean a holder of Class P Shares. “Class P Shares” shall mean the shares of Class P Common Stock. “Classes A/B/C Distribution Percentage” shall mean, as of the time of determination thereof, the number (expressed as a percentage) equal to (i) 100% (1) minus (ii) the Class P Distribution Percentage. “Common Stock” shall have the meaning set forth in Section A of this Article Fourth. “Company” shall have the meaning set forth in the preamble to this Certificate of Incorporation. “Control” shall mean the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise. For purposes of determining whether any Person is an Affiliate of any Investor Exhibit 3.1 Shareholder, a Person that either (x) holds less than one-third (1/3) of the voting power of a second Person or (y) is entitled to designate less than one-third (1/3) of the members of the board of directors (or similar governing body) of a second Person shall not be deemed to Control such second Person solely as a result of such ownership or designation rights. “Conversion Instructions” shall have the meaning set forth in Section D.2(a)(ii) of this Article Fourth. “Conversion Notice” shall have the meaning set forth in Section D.2(a)(i) of this Article Fourth. “Conversion Share Minimum Threshold” shall mean, for any Series, a Total Number of Conversion Shares that equals one-half of one percent (.5%) of the aggregate number of Class P Shares initially listed for such Series in the definition of “Total Number of Conversion Shares” (which, for the avoidance of doubt, shall be the maximum number of Class P Shares that may be issued upon conversion of Class A Shares, Class B Shares and Class C Shares of such Series prior to the conversion of any Class A Shares into Class P Shares); provided, that for purposes of this definition any adjustments to the Total Number of Conversion Shares in respect of such Series pursuant to Section F.1 of this Article Fourth shall be applied to the aggregate number of Class P Shares so initially listed. “Converting Holder” shall have the meaning set forth in Section D.2(a)(i) of this Article Fourth. “DGCL” shall have the meaning set forth in the preamble to this Certificate of Incorporation. “Directed Opportunity” shall have the meaning set forth in Article Eleventh. “Disinterested Director” shall have the meaning set forth in Section C of Article Ninth. “Distribution” shall mean any distribution made to holders of shares of Common Stock, whether in cash, property or securities and whether by dividend, Liquidation or otherwise; provided, however, that the term “Distribution” shall not be deemed to include a stock split or a dividend to the extent payable in additional Class P Shares. Whenever a Distribution provided for in this Article Fourth is payable in property other than cash, the value of such Distribution shall be deemed to be the Fair Market Value of such property. For purposes of this Article Fourth, a Distribution shall be considered paid on the date on which such Distribution is paid by the Company to the Class P Shareholders and prior to the closing or consummation of any All Cash Sale, Non-Cash Sale, Investor Distribution, All Cash Tender Offer or Non-Cash Tender Offer that occurs on the same date as such payment. “Excess Class P Share Notice” shall have the meaning set forth in Section D.2(a)(viii) of this Article Fourth. “Excess Class P Shares” shall have the meaning set forth in Section D.2(a)(viii) of this Article Fourth. “Fair Market Value” shall mean: Exhibit 3.1 (i) with respect to any security or other non-cash property (in each case, other than a security that is publicly traded), the fair market value of such security or other non-cash property as determined by the Company, which determination shall be final, binding and conclusive unless a notice of objection is delivered in accordance with the last paragraph of this definition (or unless a Change of Control Objection Notice is delivered in accordance with Section D.1(e) of this Article Fourth); and (ii) with respect to any security that is publicly traded and (A) is distributed pursuant to a Distribution, the Fair Market Value of such security shall be the VWAP of such security over the ten (10) trading days ending on the close of business on the trading day immediately preceding the date of such Distribution, (B) constitutes consideration in a Change of Control, the Fair Market Value of such security shall be the VWAP of such security over the ten (10) trading days ending on the close of business on the trading day immediately preceding the date of consummation of the Change of Control or (C) constitutes consideration in either a Non-Cash Sale or a Non-Cash Tender Offer, the Fair Market Value of such security shall be the VWAP of such security over the ten (10) trading days ending on the close of business on the trading day immediately preceding the date of the delivery of a Conversion Notice with respect to the Voluntary Conversion implemented to effect such Non-Cash Sale or Non-Cash Tender Offer. In the case of the Company’s determination of Fair Market Value of Illiquid Consideration as set forth in its written notice to the Converting Holder and the Class B Shareholders pursuant to Section D.2(a)(ii) of this Article Fourth, the Converting Holder and/or the Class B Shareholders representing a majority of the Class B Shares then issued and outstanding may give to the Company a notice of objection in writing to such determination prior to the close of business on the first (1st) Business Day following receipt of such Company written notice. If the Converting Holder and the Class B Shareholders representing a majority of the Class B Shares then issued and outstanding are unable to agree upon the Fair Market Value of such Illiquid Consideration within two (2) calendar days after delivery of such notice of objection to the Company, then (i) the Converting Holder and (ii) the Class B Shareholders representing a majority of the Class B Shares then issued and outstanding shall each select one (1) independent, nationally recognized appraiser having experience in the valuation of illiquid assets, within four (4) calendar days after delivery of such notice of objection, such that two (2) independent, nationally recognized appraisers are selected. If such firms shall agree upon the Fair Market Value of such Illiquid Consideration, such determination shall be final, binding and conclusive. If within five (5) calendar days after appointment of the two appraisers, they are unable to agree upon the Fair Market Value of such Illiquid Consideration, a third independent, nationally recognized appraiser having experience in the valuation of illiquid assets shall be chosen within four (4) calendar days thereafter by the mutual consent of such first two appraisers or, if such first two appraisers fail to agree upon the appointment of a third appraiser, such appointment shall be made by the American Arbitration Association, or any organization successor thereto. The written determination of the Fair Market Value of such Illiquid Consideration by the third appraiser so appointed and chosen shall be given within five (5) calendar days after its appointment, and shall be final, binding and conclusive. If a party to the appraisal procedure does not select an appraiser by the applicable deadline, such party shall have waived its right of selection and shall be bound by the determination of the appraiser selected by the other party. The costs of conducting such dispute resolution, including the fees of all appointed appraisers, shall be borne Exhibit 3.1 by the Company. Each of the deadlines provided for in the above procedure may be extended by mutual agreement of the parties to such procedure. For the avoidance of doubt, GS shall not be considered an independent appraiser, and GS and its Affiliates may not be appointed pursuant to the foregoing procedure as the independent, nationally recognized appraiser for any party. “Final Conversion Date” shall mean (i) if the requisite Class A Shareholders or the requisite Class B Shareholders do not deliver a Mandatory Conversion Date Objection Notice pursuant to Section D.1(a) of this Article Fourth, the Business Day immediately following the day on which the Company delivers the Mandatory Conversion Date Notice pursuant to Section D.1(a) of this Article Fourth, (ii) if the requisite Class A Shareholders and/or the requisite Class B Shareholders deliver a Mandatory Conversion Date Objection Notice pursuant to Section D.1(a) of this Article Fourth but the relevant parties reach agreement on the Mandatory Conversion Date Determinations as contemplated by Section D.1(a) of this Article Fourth within two (2) calendar days after delivery of such Mandatory Conversion Date Objection Notice, the Business Day immediately following such agreement by such relevant parties and (iii) if the requisite Class A Shareholders and/or the requisite Class B Shareholders deliver a Mandatory Conversion Date Objection Notice pursuant to Section D.1(a) of this Article Fourth and clause (ii) above does not apply, the Business Day on which the Mandatory Conversion Date Determinations are finally determined pursuant to the Appraisal Procedure. “Final Mandatory Conversion Date” shall mean May 31, 2015. “Final Mandatory Conversion Date Calculation Period” shall mean the period covering each of the trading days during the regular director and officer blackout period for the Company’s first quarterly periodic report for the 2015 calendar year. “First Catch-Up Amount” shall mean, with respect to a particular Class B Series, an amount equal to the product of 0.02631579 and the Aggregate Base Amount with respect to the Related Series. “First Catch-Up Threshold” shall mean, with respect to a particular Series, the Series B Total Value being equal to the First Catch-Up Amount. “Fund Indemnitors” shall have the meaning set forth in Section F.2 of Article Ninth. “Governmental Entity” shall mean any court, administrative agency, regulatory body, commission or other governmental authority, board, bureau or instrumentality, domestic or foreign and any subdivision thereof. “GS” shall mean (i) GS Capital Partners V Fund, L.P., a Delaware limited partnership; GS Capital Partners V Institutional, L.P., a Delaware limited partnership; GS Capital Partners VI Fund, L.P., a Delaware limited partnership; GS Capital Partners VI Parallel, L.P., a Delaware limited partnership; Goldman Sachs KMI Investors, L.P., a Delaware limited partnership; GSCP KMI Investors, L.P., a Delaware limited partnership; GSCP KMI Investors Offshore, L.P., a Cayman Islands exempted limited partnership; GS Global Infrastructure Partners I, L.P., a Delaware limited partnership; GS Institutional Infrastructure Partners I, L.P., a Delaware limited partnership; GSCP V Offshore Knight Exhibit 3.1 Holdings, L.P., a Delaware limited partnership, GSCP V Germany Knight Holdings, L.P., a Delaware limited partnership; GSCP VI Offshore Knight Holdings, L.P., a Delaware limited partnership; GSCP VI Germany Knight Holdings, L.P., a Delaware limited partnership; and GS Infrastructure Knight Holdings, L.P., a Delaware limited partnership, (ii) any investment funds or other entities sponsored, managed or owned directly or indirectly by the Merchant Banking Division of Goldman, Sachs & Co., or otherwise under common control with the entities listed in clause (i) or their successors (by merger, consolidation, acquisition of substantially all assets or similar transaction) or with any entity then included in clause (ii), to which any of the entities previously included in the definition of “GS” transferred, directly or indirectly (including through a series of transfers), Class A Shares after the Initial Public Offering or Related Shares after a Mandatory Conversion Date, and (iii) any successors (by merger, consolidation, acquisition of substantially all assets or similar transaction) of the foregoing. For the avoidance of doubt, “GS” shall be deemed not to include (A) any portfolio companies of any of the entities contained in clauses (i), (ii) or (iii) or (B) any entity that is not a party to the Shareholders Agreement. “Highstar” shall mean (i) Highstar II Knight Acquisition Sub, L.P., Highstar III Knight Acquisition Sub, L.P., Highstar Knight Partners, L.P. and Highstar KMI Blocker LLC, (ii) any investment funds or other entities sponsored, managed or owned directly or indirectly by Highstar Capital LP or one of its controlled Affiliates, or otherwise under common control with the entities listed in clause (i) or their successors (by merger, consolidation, acquisition of substantially all assets or similar transaction) or with any entity then included in clause (ii), to which any entity previously included in the definition of “Highstar” transferred, directly or indirectly (including through a series of transfers), Class A Shares after the Initial Public Offering or Related Shares after a Mandatory Conversion Date, and (iii) any successors (by merger, consolidation, acquisition of substantially all assets or similar transaction) of the foregoing. For the avoidance of doubt, “Highstar” shall be deemed not to include (A) any portfolio companies of any of the entities contained in clauses (i), (ii) or (iii) or (B) any entity that is not a party to the Shareholders Agreement. “Illiquid Consideration” shall have the meaning set forth in Section D.2(a)(i) of this Article Fourth. “Incentive Pool Threshold” shall mean an amount equal to $64,000,000. “Independent Counsel” shall have the meaning set forth in Section C of Article Ninth. “Initial Public Offering” shall mean the closing of the initial public offering of Class P Shares of the Company. “Investor Distribution” shall mean (i) a bona fide distribution of Class P Shares by an Investor Shareholder entity (including through intermediate entities) to its investors or partners; provided that a meaningful amount of such distribution shall be received by such investors or partners who are bona fide non-Affiliate investors or partners, (ii) a bona fide donative transfer of Class P Shares by any holder of shares of Series A-6 Stock to the Kinder Foundation (as defined in the Shareholders Agreement) or (iii) a bona fide donative transfer of Class P Shares by any holder of shares of Series A-7 Stock or Series A-8 Stock to a foundation or similar entity established by such holder for the purpose of serving charitable goals or to any other charitable foundation or organization, including any organization described in Section 501(c)(3) of the Internal Revenue Code of 1986, as amended, Exhibit 3.1 or any similar provision of state, local or foreign law. For the avoidance of doubt, as of the date hereof GS Capital Partners V Fund, L.P. and GS Capital Partners VI Fund, L.P. have a meaningful amount of interests owned by bona fide non-Affiliate investors or partners. “Investor Distribution Per Share Value” shall mean, with respect to an Investor Distribution, the VWAP of one (1) Class P Share over the ten (10) trading days ending on the close of business on the trading day immediately preceding the delivery of a Conversion Notice by a Class A Shareholder pursuant to Section D.2(a) of this Article Fourth with respect to such Investor Distribution. “Investor Distribution Value” shall mean the product of (i) the number of Class P Shares Transferred or transferred by a Class A Shareholder pursuant to an Investor Distribution, and (ii) the Investor Distribution Per Share Value for such Investor Distribution. “Investor Party” shall have the meaning set forth in Article Eleventh. “Investor Shareholder” shall mean each of GS, Highstar, Carlyle and Riverstone. “Liquidation” shall mean any voluntary or involuntary liquidation, dissolution or winding up of the affairs of the Company; provided, that neither the consolidation nor merger of the Company into or with any other entity, nor the sale or transfer by the Company of all or any part of its assets, nor the reduction of the capital stock of the Company, shall be deemed a Liquidation. “Mandatory Conversion Date” shall mean, with respect to shares of a Series, the earlier to occur of (i) the Change of Control Mandatory Acceleration Date, (ii) the Minimum Threshold Mandatory Conversion Date with respect to such Series, (iii) the Final Mandatory Conversion Date or (iv) the Specified Accelerated Conversion Date with respect to such Series. “Mandatory Conversion Date Determinations” shall have the meaning set forth in Section D.1(a) of this Article Fourth. “Mandatory Conversion Date Notice” shall have the meaning set forth in Section D.1(a) of this Article Fourth. “Mandatory Conversion Date Objection Notice” shall have the meaning set forth in Section D.1(a) of this Article Fourth. “Mandatory Conversion Date Per Share Value” shall mean: (i) with respect to the Change of Control Mandatory Acceleration Date, the sum of (A) the per share cash consideration in respect of the Class P Shares in the Change of Control and (B) the Fair Market Value (measured as of the close of business on the trading day immediately preceding the date of the consummation of the Change of Control) of the per share non-cash consideration in respect of Class P Shares in the Change of Control; (ii) with respect to a Minimum Threshold Mandatory Conversion Date, (A) the weighted average per share Net Sale Proceeds set forth in the Conversion Notice pursuant to Section D.2(a) of this Article Fourth for the related voluntary conversion that causes the occurrence of the Minimum Exhibit 3.1 Threshold Mandatory Conversion Date or (B) the Investor Distribution Per Share Value set forth in the Conversion Notice pursuant to Section D.2(a) of this Article Fourth for the related voluntary conversion that causes the occurrence of the Minimum Threshold Mandatory Conversion Date; (iii) with respect to the Final Mandatory Conversion Date, the VWAP of one (1) Class P Share over the Final Mandatory Conversion Date Calculation Period; (iv) with respect to the Specified Accelerated Conversion Date, the VWAP of one (1) Class P Share over the thirty (30) consecutive day period through and including the second (2nd) trading day immediately prior to a Specified Accelerated Conversion Date (or such other period as may be agreed by the holders of shares of the applicable Class A Series and corresponding Class B Series in accordance with the approval thresholds described in the definition of “Specified Accelerated Conversion Date” and specified in the written notice of such holders delivered to the Company at least one (1) Business Day immediately prior to the Specified Accelerated Conversion Date). “Mandatory Conversion Date Value” shall mean, with respect to a Series, the product of (i) the Total Number of Conversion Shares with respect to such Series immediately prior to the Mandatory Conversion Date and (ii) the Mandatory Conversion Date Per Share Value. “Maximum Class B Priority Distributions” shall mean, as of the date of determination, the product of (x) $12,500,000 and (y) the number of calendar quarters that have elapsed (counting the calendar quarter to which the current Distribution relates as having elapsed for this purpose) from and including the calendar quarter in which the first quarterly dividend is paid after the Initial Public Offering; provided, that the aggregate amount of Distributions received in respect of Class B Shares pursuant to Section C.3(a) of this Article Fourth shall not exceed (i) $200,000,000 during the Class B Priority Dividend Period or (ii) the Annual Maximum Class B Priority Dividend Amount with respect to an Annual Class B Priority Dividend Period. “Minimum Threshold Mandatory Conversion Date” shall mean the date on which the Total Number of Conversion Shares for a Series falls below the Conversion Share Minimum Threshold for such Series. “Net Sale Proceeds” with respect to Class P Shares shall mean the net proceeds (net of discounts and commissions, but not other expenses) received on the Transfer of the applicable Class P Shares. In the case of any non-cash consideration received on the Transfer of such applicable Class P Shares, the Net Sale Proceeds shall be based upon the Fair Market Value of such non-cash consideration (net of discounts and commissions, but not other expenses). “Non-Cash Change of Control” shall mean a Change of Control that does not constitute a merger, amalgamation, consolidation or other business combination or similar transaction or series of transactions involving the Company pursuant to which all of the Class P Shares issued and outstanding immediately prior to the consummation of such transaction or transactions would be exchanged for cash. “Non-Cash Conversion Instructions” shall have the meaning set forth in Section D.2(a)(ii) of this Article Fourth. Exhibit 3.1 “Non-Cash Sale” shall have the meaning set forth in Section D.2(a)(i) of this Article Fourth. “Non-Cash Tender Offer” shall have the meaning set forth in Section D.2(a)(i) of this Article Fourth. “Notional Base Amount” shall mean, for any Class C Series, the dollar amount specified below for such series: Series C-1 $5,579,453.42 Series C-2 $1,380,127.12 Series C-3 $4,401,584.54 Series C-4 $3,073,781.71 Series C-5 $3,073,781.71 Series C-6 $8,444,321.11 Series C-7 $224,694.19 Series C-8 $1,215,851.99 Series C-9 $177,140.20 “Periodic Sales Pre-Clearance Period” shall have the meaning set forth in Section D.2(a)(ii)(C) of this Article Fourth. “Periodic Sales Pre-Clearance Request” shall mean a written request delivered by a holder of shares of a Class A Series (the “Requesting Holder”) to the Company and the Transfer Agent pursuant to Section D.2(a)(ii)(C) of this Article Fourth, which request shall set forth (i) such Requesting Holder’s proposed Pre-Cleared Prices and (ii) with respect to each Pre-Cleared Price, the proposed corresponding maximum number of Class P Shares to be Transferred or transferred pursuant to an Investor Distribution by holders of shares of such Requesting Holder’s Class A Series in connection with Voluntary Conversions of Class A Shares of such Class A Series pursuant to Section D.2(a) of this Article Fourth during the applicable Periodic Sales Pre-Clearance Period (with respect to each Pre-Cleared Price, each a “Pre-Cleared Number of Shares”); provided, that a Pre-Cleared Number of Shares corresponding to a Pre-Cleared Price shall be limited to a number of Class P Shares such Exhibit 3.1 that the Transfer or Investor Distribution by holders of Class A Shares of such Requesting Holder’s Class A Series of a number of shares equal to such Pre-Cleared Number of Shares pursuant to Section D.2(a) of this Article Fourth at the weighted average per share Net Sales Proceeds or the Investor Distribution Per Share Value equal to the highest amount of such Pre-Cleared Price would (assuming the Transfer or Investor Distribution of the Pre-Cleared Number of Shares corresponding to such Pre-Cleared Price) not, as of the date of determination, cause the Total Number of Conversion Shares for the Related Series to fall below the Conversion Share Minimum Threshold for the Related Series (after taking into account the number of Class P Shares into which the corresponding Class B Series would be entitled to convert in accordance with Section D.2(b) of this Article Fourth and the number of Class P Shares into which the corresponding Class C Series would be entitled to convert in accordance with Section D.2(d) of this Article Fourth, in each case as a result of such Transfer or Investor Distribution). “Person” shall mean any individual, corporation, company, firm, partnership, joint venture, limited liability company, estate, trust, business association, organization, Governmental Entity or other entity. “Pre-Clearance Objection” shall have the meaning set forth in Section D.2(a)(ii)(C) of this Article Fourth. “Pre-Cleared Number of Shares” shall have the meaning given such term in the definition of Periodic Sales Pre-Clearance Request. “Pre-Cleared Prices” shall mean various ranges (as specified in the applicable Periodic Sales Pre- Clearance Request) of weighted average Investor Distribution Per Share Value and per share Net Sale Proceeds for all Investor Distributions and Transfers (considered as a group) pursuant to Section D.2(a) of this Article Fourth during a Periodic Sales Pre-Clearance Period, in such increments as proposed in the applicable Periodic Sales Pre-Clearance Request. Each such proposed range (e.g., $5.01-$6.00 inclusive, or $4.51-$5.00 inclusive) shall be referred to as a Pre-Cleared Price. “Pre-Incorporation Distribution Amount” shall mean, for any Class A Series, the dollar amount specified below for such series: Exhibit 3.1 Series A-1 $303,498,072 Series A-2 $77,577,870 Series A-3 $233,421,964 Series A-4 $163,006,790 Series A-5 $163,006,790 Series A-6 $413,475,850 Series A-7 $11,002,142 Series A-8 $59,534,145 Series A-9 $8,673,663 “Preferred Stock” shall have the meaning set forth in Section A of this Article Fourth. “Referential Class A Series” shall have the meaning given such term in Section D.2(a)(vi) of this Article Fourth. “Referential Conversion Percentage” shall have the meaning given such term in Section D.2(a)(vi) of this Article Fourth. “Referential Per Share Value” shall have the meaning given such term in Section D.2(a)(vi) of this Article Fourth. “Related Series” shall mean, with respect to a particular Class A Series, Class B Series or Class C Series, the Series that includes such Class A Series, Class B Series and Class C Series. “Related Shares” shall mean Class P Shares received by a Class A Shareholder upon conversion of such holder’s Class A Shares as the result of the occurrence of a Mandatory Conversion Date for the Related Series. “Replicated Change of Control” shall have the meaning given such term in Section 3.6(h) of the Shareholders Agreement. Exhibit 3.1 “Requesting Holder” shall have the meaning given such term in the definition of Periodic Sales Pre-Clearance Request. “Riverstone” shall mean (i) Carlyle/Riverstone Knight Investment Partnership, L.P., C/R Knight Partners, L.P., C/R Energy III Knight Non-U.S. Partnership, L.P.; Carlyle Energy Coinvestment III, L.P. and Riverstone Energy Coinvestment III, L.P., (ii) any investment funds or other entities sponsored, managed or owned directly or indirectly by Riverstone Holdings, LLC or one of its controlled Affiliates or otherwise under common control with the entities listed in clause (i) or their successors (by merger, consolidation, acquisition of substantially all assets or similar transaction) or with any entity then included in clause (ii), to which any entity previously included in the definition of “Riverstone” transferred, directly or indirectly (including through a series of transfers), Class A Shares after the Initial Public Offering or Related Shares after a Mandatory Conversion Date, and (iii) any successors (by merger, consolidation, acquisition of substantially all assets or similar transaction) of the foregoing. For the avoidance of doubt, “Riverstone” shall be deemed not to include (A) Carlyle or any portfolio companies of any of the entities contained in clauses (i), (ii) or (iii) or (B) any entity that is not a party to the Shareholders Agreement. “Second Catch-Up Amount” shall mean, with respect to a particular Class B Series, an amount equal to the product of 0.05902849 and the Aggregate Base Amount with respect to the Related Series. “Second Catch-Up Threshold” shall mean, with respect to a particular Series, the Series B Total Value being equal to the sum of (a) the Second Catch-Up Amount and (b) the product of 5% and the Aggregate Base Amount for such Series. “Securities Act” shall mean the Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute, and the rules and regulations promulgated thereunder. “Series” means, as applicable, a Class A Series, a Class B Series and a Class C Series bearing the same number (e.g., Series A-1 Stock, Series B-1 Stock and Series C-1 Stock). “Series A Distribution Percentage” shall mean, as of the time of determination thereof, with respect to a particular Class A Series, the number (expressed as a percentage) equal to the product of: (i) the Classes A/B/C Distribution Percentage, (ii) the quotient obtained by dividing (A) the Total Number of Conversion Shares for the Related Series, by (B) the sum of the Total Number of Conversion Shares for all Series in the aggregate and (iii) the Class A Percentage for such Class A Series. “Series A Total Value” shall mean, as applicable: Exhibit 3.1 (i) with respect to any particular Class A Series (other than the Series A-9 Stock), as of the time of determination thereof, the sum of (a) the amount of all Distributions paid in cash and the Fair Market Value of all Distributions paid in property other than cash that previously were paid (other than the Pre-Incorporation Distribution Amount) or are paid concurrently on shares of such Class A Series pursuant to Section C.2 of this Article Fourth (including, in the case of the Series A-6 Stock, any amounts of cash or non-cash Distributions not paid to holders as a result of the application of Section C.2(g) of this Article Fourth), (b) the amount of all Net Sale Proceeds that previously were received or are received concurrently by the Converting Holder in connection with the Transfer of Class P Shares into which shares of such Class A Series have been converted pursuant to a Voluntary Conversion, (c) the amount of all Investor Distribution Value that previously was received or is received concurrently on the Investor Distribution of Class P Shares into which shares of such Class A Series have been converted pursuant to a Voluntary Conversion, (d) the Pre- Incorporation Distribution Amount with respect to such Class A Series and (e) the Series C Total Value for the corresponding Class C Series; and (ii) with respect to Series A-9 Stock, as of the time of determination thereof, the sum of (a) the amount of all Distributions paid in cash and the Fair Market Value of all Distributions paid in property other than cash that previously were paid (other than the Pre- Incorporation Distribution Amount) or are paid concurrently on shares of Series A-9 Stock pursuant to Section C.2 of this Article Fourth; (b) with respect to each prior Transfer or Investor Distribution of Class P Shares that resulted in an automatic conversion of shares of Series A-9 Stock pursuant to Section D.2(c) of this Article Fourth, the product of (x) the applicable Referential Per Share Value for such Transfer or Investor Distribution, and (y) the number of Class P Shares that were received by the holders of shares of Series A-9 Stock as a result of such automatic conversion; and (c) with respect to a concurrent Transfer or Investor Distribution of Class P Shares that results in the automatic conversion of shares of Series A-9 Stock pursuant to Section D.2(c) of this Article Fourth, the product of (x) the applicable Referential Per Share Value for such concurrent Transfer or Investor Distribution, and (y) the number of Class P Shares that are to be received by the holders of shares of Series A-9 Stock as a result of such automatic conversion; (d) the Pre-Incorporation Distribution Amount with respect to such Series A-9 Stock; and (e) the Series C Total Value for the Series C-9 Stock. “Series A-1 Stock” shall have the meaning set forth in Section A.2 of this Article Fourth. “Series A-2 Stock” shall have the meaning set forth in Section A.2 of this Article Fourth. “Series A-3 Stock” shall have the meaning set forth in Section A.2 of this Article Fourth. “Series A-4 Stock” shall have the meaning set forth in Section A.2 of this Article Fourth. “Series A-5 Stock” shall have the meaning set forth in Section A.2 of this Article Fourth. “Series A-6 Stock” shall have the meaning set forth in Section A.2 of this Article Fourth. “Series A-7 Stock” shall have the meaning set forth in Section A.2 of this Article Fourth. Exhibit 3.1 “Series A-8 Stock” shall have the meaning set forth in Section A.2 of this Article Fourth. “Series A-9 Stock” shall have the meaning set forth in Section A.2 of this Article Fourth. “Series A-9 Stock Conversion Percentage” shall mean a quotient, expressed as a percentage, obtained by dividing (A) the aggregate number of Class P Shares issued to holders of shares of Series A-9 Stock as of the date of the notice delivered pursuant to Section D.2(a)(vi) of this Article Fourth by (B) the Total Number of Conversion Shares set forth opposite the Series A-9 Stock in the second sentence of the definition of “Total Number of Conversion Shares,” (taking into account any adjustments to the Total Number of Conversion Shares in respect of the Series A-9 Stock pursuant to Section F.1 of this Article Fourth). “Series B Total Value” shall mean, as applicable: (i) with respect to any particular Class B Series (other than the Series B-9 Stock), as of the time of determination thereof, the sum of (a) the amount of all Distributions paid in cash and the Fair Market Value of all Distributions paid in property other than cash that previously were paid or are paid concurrently on such Class B Series pursuant to Section C.3 of this Article Fourth and (b) in a case where shares of such Class B Series previously were converted into Class P Shares due to a Voluntary Conversion by a holder of the corresponding Class A Series, an amount equal to the product of the number of Class P Shares received by holders of shares of such Class B Series in such conversion and (1) the weighted average per share Net Sale Proceeds received by the holder of such Class A Series on the Transfer of the Class P Shares received upon such Voluntary Conversion as set forth in the related Conversion Notice or Conversion Instructions, as applicable, or (2) the Investor Distribution Per Share Value in connection with an Investor Distribution of the Class P Shares received upon such Voluntary Conversion as set forth in the related Conversion Notice or Conversion Instructions, as applicable; and (ii) with respect to Series B-9 Stock, as of the time of determination thereof, the sum of (a) the amount of all Distributions paid in cash and the Fair Market Value of all Distributions paid in property other than cash that previously were paid or are paid concurrently on such Series B-9 Stock pursuant to Section C.3 of this Article Fourth and (b) in a case where shares of Series B-9 Stock were previously converted into Class P Shares due to an automatic conversion of shares of Series A-9 Stock pursuant to Section D.2(c) of this Article Fourth, an amount equal to the product of the number of Class P Shares received by holders of shares of Series B-9 Stock in each such conversion and the applicable Referential Per Share Value for the applicable previous Transfer or Investor Distribution of Class P Shares that resulted in such automatic conversion of shares of Series A-9 Stock pursuant to Section D.2(c) of this Article Fourth. “Series B-1 Stock” shall have the meaning set forth in Section A.3 of this Article Fourth. “Series B-2 Stock” shall have the meaning set forth in Section A.3 of this Article Fourth. “Series B-3 Stock” shall have the meaning set forth in Section A.3 of this Article Fourth. “Series B-4 Stock” shall have the meaning set forth in Section A.3 of this Article Fourth. Exhibit 3.1 “Series B-5 Stock” shall have the meaning set forth in Section A.3 of this Article Fourth. “Series B-6 Stock” shall have the meaning set forth in Section A.3 of this Article Fourth. “Series B-7 Stock” shall have the meaning set forth in Section A.3 of this Article Fourth. “Series B-8 Stock” shall have the meaning set forth in Section A.3 of this Article Fourth. “Series B-9 Stock” shall have the meaning set forth in Section A.3 of this Article Fourth. “Series C Distribution Percentage” shall mean, as of the time of determination thereof, with respect to a particular Class C Series, the number (expressed as a percentage) equal to the product of: (i) the Classes A/B/C Distribution Percentage, (ii) the quotient obtained by dividing (A) the Total Number of Conversion Shares for the Related Series, by (B) the sum of the Total Number of Conversion Shares for all Series in the aggregate and (iii) the Class C Percentage for such Class C Series. “Series C Total Value” shall mean, with respect to any particular Class C Series, as of the time of determination thereof, the sum of (a) the amount of all Distributions paid in cash and the Fair Market Value of all Distributions paid in property other than cash that previously were paid or are paid concurrently on such Class C Series pursuant to Section C.4 of this Article Fourth; (b) in each case where shares of such Class C Series previously were converted into Class P Shares due to a Voluntary Conversion by a holder of the corresponding Class A Series, an amount equal to the product of the number of Class P Shares received by holders of shares of such Class C Series in each such conversion and (1) the weighted average per share Net Sale Proceeds received by the holder of such Class A Series on the Transfer of the Class P Shares received upon the applicable Voluntary Conversion as set forth in the related Conversion Notice or Conversion Instructions, as applicable, or (2) the Investor Distribution Per Share Value in connection with an Investor Distribution of the Class P Shares received upon the applicable Voluntary Conversion as set forth in the related Conversion Notice or Conversion Instructions, as applicable; and (c) in each case where shares of Class C Series are concurrently being converted into Class P Shares due to a Voluntary Conversion by a holder of the corresponding Class A Series, an amount equal to the product of the number of Class P Shares received by holders of shares of such Class C Series in such conversion and (1) the weighted average per share Net Sale Proceeds received by the holder of such Class A Series on the Transfer of the Class P Shares received upon such Voluntary Conversion as set forth in the related Conversion Notice or Conversion Instructions, as applicable, or (2) the Investor Distribution Per Share Value in connection with an Investor Distribution of the Class P Shares received upon such Voluntary Conversion as set forth in the related Conversion Notice or Conversion Instructions, as applicable, as the case may be. “Series C-1 Stock” shall have the meaning set forth in Section A.4 of this Article Fourth. “Series C-2 Stock” shall have the meaning set forth in Section A.4 of this Article Fourth. “Series C-3 Stock” shall have the meaning set forth in Section A.4 of this Article Fourth. Exhibit 3.1 “Series C-4 Stock” shall have the meaning set forth in Section A.4 of this Article Fourth. “Series C-5 Stock” shall have the meaning set forth in Section A.4 of this Article Fourth. “Series C-6 Stock” shall have the meaning set forth in Section A.4 of this Article Fourth. “Series C-7 Stock” shall have the meaning set forth in Section A.4 of this Article Fourth. “Series C-8 Stock” shall have the meaning set forth in Section A.4 of this Article Fourth. “Series C-9 Stock” shall have the meaning set forth in Section A.4 of this Article Fourth. “Shareholders Agreement” shall mean the Shareholders Agreement dated as of February 10, 2011, among the Company and the holders of shares of Common Stock specified therein, as may be amended from time to time in accordance therewith. “Specified Accelerated Conversion Date” shall mean, for any Series, the date (which shall be a Business Day) selected by the holders of shares of such Class A Series and Class B Series representing two-thirds of the Class A Shares then issued and outstanding for such Class A Series and two-thirds of the Class B Shares then issued and outstanding for such Class B Series, respectively, to be the Mandatory Conversion Date for purposes of Section D.1 of this Article Fourth, as set forth in the written notice of such holders delivered to the Company at least one (1) Business Day immediately prior to such selected date; provided, that in no event shall there be a Specified Accelerated Conversion Date in respect of the Series A-6 Stock prior to the earlier of (x) the time that a Specified Accelerated Conversion Date has occurred (or is occurring concurrently) in respect of at least two (2) of the following clauses: (i) Series A-1 Stock and/or Series A-2 Stock, (ii) Series A-3 Stock, (iii) Series A-4 Stock and (iv) Series A-5 Stock or (y) the time that all Class A Shares have been voluntarily converted in accordance with Section D.2(a) of this Article Fourth in respect of the following: (i) Series A-1 Stock, (ii) Series A-2 Stock, (iii) Series A-3 Stock, (iv) Series A-4 Stock and (v) Series A-5 Stock. “Subject Class A Shares” shall have the meaning set forth in Section D.2(a)(x) of this Article Fourth. “Subject Class P Shares” shall have the meaning set forth in Section D.2(a)(x) of this Article Fourth. “Subject Distribution” shall have the meaning set forth in Section D.2(a)(x) of this Article Fourth. “Tender Offer Consideration Event” shall have the meaning set forth in Section D.2(a)(v) of this Article Fourth. “Total Number of Conversion Shares” shall mean, as of the time of determination thereof, and subject to increase pursuant to Section D.2(a)(viii) of this Article Fourth, the aggregate number of Class P Shares that may be issued upon conversion in full of all shares of a particular Series that are outstanding as of such date. The Total Number of Conversion Shares for each Series initially Exhibit 3.1 shall be the number set forth below and shall be reduced by the cumulative number of Class P Shares that are issued upon conversion of any shares of such Series in accordance with the provisions of Section D of this Article Fourth: Series A-1, B-1, C-1 Series A-2, B-2, C-2 Series A-3, B-3, C-3 Series A-4, B-4, C-4 Series A-5, B-5, C-5 Series A-6, B-6, C-6 Series A-7, B-7, C-7 Series A-8, B-8, C-8 Series A-9, B-9, C-9 143,074,656 shares 35,390,780 shares 112,870,410 shares 78,821,388 shares 78,821,388 shares 216,538,834 shares 5,761,863 shares 31,178,252 shares 4,542,429 shares “Total Value” shall mean, with respect to any particular Series, as of the time of determination thereof, the sum of the Series A Total Value and the Series B Total Value, in each case with respect to such Series. “Transfer” shall mean, as a verb, to sell for value in public or private transactions, including, without limitation, by selling in underwritten or other public offerings, by engaging in privately -negotiated or open market sales, or in any tender offer, and, as a noun, shall have a correlative meaning. “Transfer Agent” shall mean ComputerShare Trust Co. or any successor thereto or any other transfer agent approved by the board of directors of the Company. “Voluntary Conversion” shall mean a conversion of Class A Shares into Class P Shares pursuant to Section D.2(a) of this Article Fourth prior to the Mandatory Conversion Date. “VWAP” shall mean the volume weighted average price, calculated to the nearest one-hundredth of one cent ($0.0001), of the applicable security on the primary national securities exchange on which such security is listed for trading (based on “regular way” trading on such primary exchange only, as reported by Bloomberg L.P. or, if not reported thereby, by another authoritative source mutually agreed by the parties). C. Distributions 1. Distributions on Common Stock Exhibit 3.1 When and if declared by the board of directors of the Company out of assets legally available therefor, and subject to any prior rights of Preferred Stock, the Class P Shareholders shall be entitled to receive, as a class, the percentage of any Distribution equal to the Class P Distribution Percentage as of the record date for such Distribution. The amount of any such Distribution to be received by the Class P Shareholders shall be distributed ratably, among the Class P Shareholders as of the record date for such Distribution, on a per share basis. When and if declared by the board of directors of the Company out of assets legally available therefor, and subject to any prior rights of Preferred Stock, the Class A Shareholders, Class B Shareholders and Class C Shareholders shall be entitled to receive, collectively, the percentage of any Distribution equal to the Classes A/B/C Distribution Percentage as of the record date for such Distribution, which shall be distributed to the Class A Shareholders, Class B Shareholders and Class C Shareholders as set forth in Sections C.2, C.3 and C.4 of this Article Fourth. 2. Class A Common Stock Holders of shares of each Class A Series shall be entitled to receive the portion of any Distribution determined in accordance with paragraphs (a) through (f) of this Section C.2, beginning with paragraph (a); provided, that holders of shares of Series A-6 Stock shall also be subject to paragraph (g). For example, if a Distribution would result in the payment of amounts to a Class A Shareholder under both paragraph (c) and (d) of this Section C.2, then such Class A Shareholder shall first receive any Distributions payable under paragraph (c) and shall next receive any Distributions payable under paragraph (d). (a) Unless and until the 100% Threshold has been satisfied for the Related Series, the holders of shares of such Class A Series shall be entitled to receive, as a series, the percentage of such Distribution equal to the sum of (x) the Series A Distribution Percentage for such Class A Series and (y) the Series C Distribution Percentage for the corresponding Class C Series, in each case as of the record date for such Distribution; provided, however, that holders of shares of such Class A Series shall not receive any Distributions under this Section C.2(a) during the Class B Priority Dividend Period until the holders of shares of the corresponding Class B Series shall have received a cumulative amount of Distributions during the Class B Priority Dividend Period equal to the product of (i) the Maximum Class B Priority Distributions and (ii) the Base Distribution Percentage for such Class A Series. The amount of such Distribution, if any, to be received by the holders of shares of such Class A Series pursuant to this paragraph (a) shall be distributed ratably, among such holders as of the record date for such Distribution, on a per share basis. (b) Once the 100% Threshold has been satisfied for the Related Series (and unless and until the 150% Threshold has been satisfied for the Related Series), the holders of shares of such Class A Series shall be entitled to receive, as a series, the percentage of such Distribution (to the extent, if any, not previously distributed) equal to the Series A Distribution Percentage for such Class A Series as of the record date for such Distribution; provided, however, that holders of shares of such Class Exhibit 3.1 A Series shall not receive any Distributions under this Section C.2(b) during the Class B Priority Dividend Period until the holders of shares of the corresponding Class B Series shall have received a cumulative amount of Distributions during the Class B Priority Dividend Period equal to the product of (i) the Maximum Class B Priority Distributions and (ii) the Base Distribution Percentage for such Class A Series. The amount of such Distribution, if any, to be received by the holders of shares of such Class A Series pursuant to this paragraph (b) shall be distributed ratably, among such holders as of the record date for such Distribution, on a per share basis. (c) Once the 150% Threshold has been satisfied for the Related Series (and unless and until the Series A Total Value for the Related Series equals or exceeds 150% of the Aggregate Base Amount for the Related Series), the holders of shares of such Class A Series shall be entitled to receive, as a series, the percentage of such Distribution (to the extent, if any, not previously distributed) equal to the Series A Distribution Percentage for such Class A Series as of the record date for such Distribution. The amount of such Distribution, if any, to be received by the holders of shares of such Class A Series pursuant to this paragraph (c) shall be distributed ratably, among such holders as of the record date for such Distribution, on a per share basis. Once the Series A Total Value for the Related Series equals or exceeds 150% of the Aggregate Base Amount for the Related Series, the holders of shares of such Class A Series shall not be entitled to receive any portion of any further Distribution, to the extent such Distribution would cause the Series A Total Value for the Related Series to exceed 150% of the Aggregate Base Amount for the Related Series, until the First Catch-Up Threshold for the corresponding Class B Series has been satisfied. (d) Once the Series A Total Value for the Related Series equals or exceeds 150% of the Aggregate Base Amount for the Related Series and the First Catch-Up Threshold has been satisfied for the corresponding Class B Series (and unless and until the 200% Threshold has been satisfied for the Related Series), the holders of shares of such Class A Series shall be entitled to receive, as a series, the percentage of such Distribution (to the extent, if any, not previously distributed) equal to 95% of the Series A Distribution Percentage for such Class A Series as of the record date for such Distribution. The amount of such Distribution to be received by the holders of shares of such Class A Series pursuant to this paragraph (d) shall be distributed ratably, among such holders as of the record date for such Distribution, on a per share basis. Once the 200% Threshold has been satisfied for the Related Series, the holders of shares of such Class A Series shall not be entitled to receive any portion of any further Distribution, to the extent such Distribution would cause the Total Value for the Related Series to exceed 200% of the Aggregate Base Amount for the Related Series, until the Second Catch-Up Threshold for the corresponding Class B Series has been satisfied. Exhibit 3.1 (e) Once the 200% Threshold has been satisfied for the Related Series, and the Second Catch-Up Threshold has been satisfied for the corresponding Class B Series (and unless and until the 400% Threshold has been satisfied for the Related Series), the holders of shares of such Class A Series shall be entitled to receive, as a series, the portion of such Distribution (to the extent, if any, not previously distributed) equal to the excess of (i) the product of the amount of such Distribution and the Series A Distribution Percentage for such Class A Series as of the record date for such Distribution over (ii) the amount of such Distribution to which the holders of shares of the corresponding Class B Series are entitled pursuant to Section C.3 (e)(i) of this Article Fourth. The amount of such Distribution to be received by the holders of shares of such Class A Series pursuant to this paragraph (e) shall be distributed ratably, among such holders as of the record date for such Distribution, on a per share basis. (f) Once the 400% Threshold has been satisfied for the Related Series, the holders of shares of such Class A Series shall be entitled to receive, as a series, the percentage of such Distribution (to the extent, if any, not previously distributed) equal to 80% of the Series A Distribution Percentage for such Class A Series as of the record date for such Distribution. The amount of such Distribution to be received by the holders of shares of such Class A Series pursuant to this paragraph (f) shall be distributed ratably, among such holders as of the record date for such Distribution, on a per share basis. (g) Notwithstanding the other provisions of this Section C.2, the holders of shares of Series A-6 Stock shall not be entitled to receive any Distributions unless and until the aggregate amount of Distributions payable in cash and the Fair Market Value of all distributions payable in property other than cash that would be received by such holders pursuant to this Section C.2 (but for this paragraph (g)) equals or exceeds the Incentive Pool Threshold. 3. Class B Common Stock Holders of shares of each Class B Series shall be entitled to receive the portion of any Distribution determined in accordance with paragraphs (a) through (f) of this Section C.3, beginning with paragraph (a). For example, if a Distribution would result in the payment of amounts to a Class B Shareholder under both paragraph (c) and (d) of this Section C.3, then such Class B Shareholder shall first receive any Distributions payable under paragraph (c) and shall next receive any Distributions payable under paragraph (d). (a) Unless and until the 150% Threshold has been satisfied for the Related Series, if such Distribution is paid during the Class B Priority Dividend Period, the holders of shares of such Class B Series shall be entitled to receive, as a series, the percentage of such Distribution equal to the sum of (x) the Series A Distribution Percentage for such Class A Series and (y) the Series C Distribution Percentage for such Class C Series, each as of the record date for such Distribution; provided, however, that the amount of Distributions that the holders of shares of such Class B Exhibit 3.1 Series shall be entitled to receive pursuant to this Section C.3(a) during the Class B Priority Dividend Period, when aggregated with all Class B Priority Distributions previously received by holders of shares of such Class B Series, shall not exceed a cumulative amount equal to the product of (i) the Maximum Class B Priority Distributions and (ii) the Base Distribution Percentage for such Class A Series. The amount of such Distribution to be received by the holders of shares of such Class B Series pursuant to this paragraph (a) shall be distributed ratably, among such holders as of the record date for such Distribution, on a per share basis. Once the 150% Threshold has been satisfied for the Related Series, the holders of shares of such Class B Series shall not be entitled to receive any portion of any further Distribution until the Series A Total Value for the Related Series equals or exceeds 150% of the Aggregate Base Amount for the Related Series. (b) Once the Series A Total Value for the Related Series equals or exceeds 150% of the Aggregate Base Amount for the Related Series, but the First Catch-Up Threshold has not been satisfied for such Class B Series, the holders of shares of such Class B Series shall be entitled to receive, as a series, the percentage of such Distribution (to the extent, if any, not previously distributed) equal to the sum of (x) the Series A Distribution Percentage for such Class A Series and (y) the Series C Distribution Percentage for such Class C Series, each as of the record date for such Distribution until the First Catch-Up Threshold has been satisfied for such Class B Series. The amount of such Distribution to be received by the holders of shares of such Class B Series pursuant to this paragraph (b) shall be distributed ratably, among such holders as of the record date for such Distribution, on a per share basis. (c) Once the 150% Threshold has been satisfied for the Related Series and the First Catch-Up Threshold has been satisfied for such Class B Series (and unless and until the 200% Threshold has been satisfied for the Related Series), the holders of shares of such Class B Series shall be entitled to receive, as a series, the percentage of such Distribution (to the extent, if any, not previously distributed) equal to 5% of the sum of (x) the Series A Distribution Percentage for such Class A Series and (y) the Series C Distribution Percentage for such Class C Series, each as of the record date for such Distribution. The amount of such Distribution to be received by the holders of shares of such Class B Series pursuant to this paragraph (c) shall be distributed ratably, among such holders as of the record date for such Distribution, on a per share basis. (d) Once the 200% Threshold has been satisfied for the Related Series, but the Second Catch-Up Threshold has not been satisfied for such Class B Series, the holders of shares of such Class B Series shall be entitled to receive, as a series, the percentage of such Distribution (to the extent, if any, not previously distributed) equal to the sum of (x) the Series A Distribution Percentage for such Class A Series and (y) the Series C Distribution Percentage for such Class C Series, each as of the record date for such Distribution until the Second Catch-Up Threshold has been Exhibit 3.1 satisfied for such Class B Series. The amount of such Distribution to be received by the holders of shares of such Class B Series pursuant to this paragraph (d) shall be distributed ratably, among such holders as of the record date for such Distribution, on a per share basis. (e) Once the 200% Threshold has been satisfied for the Related Series and the Second Catch-Up Threshold has been satisfied for such Class B Series (and unless and until the 400% Threshold has been satisfied for the Related Series), the holders of shares of such Class B Series shall be entitled to receive, asa series, a percentage of such Distribution (to the extent, if any, not previously distributed) such that the Series B Total Value equals the sum of (i) the product of (A) the excess of the Total Value for the Related Series over the Aggregate Base Amount for the Related Series and (B) the 10%-20% Distribution Percentage and (C) the Class A Percentage, as of the record date for such Distribution and (ii) the product of (A) the excess of the Total Value for the Related Series over the Aggregate Base Amount for the Related Series and (B) the 10%-20% Distribution Percentage and (C) the Class C Percentage, as of the record date for such Distribution. The amount of such Distribution to be received by the holders of shares of such Class B Series pursuant to this paragraph (e) shall be distributed ratably, among such holders as of the record date for such Distribution, on a per share basis. (f) Once the 400% Threshold has been satisfied for the Related Series, the holders of shares of such Class B Series shall be entitled to receive, as a series, the percentage of such Distribution (to the extent, if any, not previously distributed) that equals 20% of the sum of (x) the Series A Distribution Percentage with respect to such Class A Series and (y) the Series C Distribution Percentage with respect to such Class C Series, each as of the record date for such Distribution. The amount of such Distribution to be received by the holders of shares of such Class B Series pursuant to this paragraph (f) shall be distributed ratably, among such holders as of the record date for such Distribution, on a per share basis. 4. Class C Common Stock Holders of shares of each Class C Series shall be entitled to receive the portion of any Distribution determined in accordance with paragraphs (a) through (f) of this Section C.4, beginning with paragraph (a). For example, if a Distribution would result in the payment of amounts to a Class C Shareholder under both paragraph (c) and (d) of this Section C.4, then such Class C Shareholder shall first receive any Distributions payable under paragraph (c) and shall next receive any Distributions payable under paragraph (d). (a) Unless and until the 100% Threshold has been satisfied for the Related Series, the holders of shares of such Class C Series shall not be entitled to receive any Distributions. (b) Once the 100% Threshold has been satisfied for the Related Series (and unless and until the 150% Threshold has been satisfied for the Related Series), the Exhibit 3.1 holders of shares of such Class C Series shall be entitled to receive, as a series, the percentage of such Distribution (to the extent, if any, not previously distributed) equal to the Series C Distribution Percentage for such Class C Series as of the record date for such Distribution; provided, however, that holders of shares of such Class C Series shall not receive any Distributions under this Section C.4(b) during the Class B Priority Dividend Period until the holders of shares of the corresponding Class B Series shall have received a cumulative amount of Distributions during the Class B Priority Dividend Period equal to the product of (i) the Maximum Class B Priority Distributions and (ii) the Base Distribution Percentage for the corresponding Class A Series. The amount of such Distribution, if any, to be received by the holders of shares of such Class C Series pursuant to this paragraph (b) shall be distributed ratably, among such holders as of the record date for such Distribution, on a per share basis. (c) Once the 150% Threshold has been satisfied for the Related Series (and unless and until the Series A Total Value for the Related Series equals or exceeds 150% of the Aggregate Base Amount for the Related Series), the holders of shares of such Class C Series shall be entitled to receive, as a series, the percentage of such Distribution (to the extent, if any, not previously distributed) equal to the Series C Distribution Percentage for such Class C Series as of the record date for such Distribution. The amount of such Distribution, if any, to be received by the holders of shares of such Class C Series pursuant to this paragraph (c) shall be distributed ratably, among such holders as of the record date for such Distribution, on a per share basis. Once the Series A Total Value for the Related Series equals or exceeds 150% of the Aggregate Base Amount for the Related Series, the holders of shares of such Class C Series shall not be entitled to receive any portion of any further Distribution, to the extent such Distribution would cause the Series A Total Value for the Related Series to exceed 150% of the Aggregate Base Amount for the Related Series, until the First Catch-Up Threshold for the corresponding Class B Series has been satisfied. (d) Once the Series A Total Value for the Related Series equals or exceeds 150% of the Aggregate Base Amount for the Related Series and the First Catch-Up Threshold has been satisfied for the corresponding Class B Series (and unless and until the 200% Threshold has been satisfied for the Related Series), the holders of shares of such Class C Series shall be entitled to receive, as a series, the percentage of such Distribution (to the extent, if any, not previously distributed) equal to 95% of the Series C Distribution Percentage for such Class C Series as of the record date for such Distribution. The amount of such Distribution to be received by the holders of shares of such Class C Series pursuant to this paragraph (d) shall be distributed ratably, among such holders as of the record date for such Distribution, on a per share basis. Once the 200% Threshold has been satisfied for the Related Series, the holders of shares of such Class C Series shall not be entitled to receive any portion of any further Distribution, to the extent such Distribution would cause the Total Value for the Related Series to exceed 200% of the Aggregate Base Amount for the Exhibit 3.1 Related Series, until the Second Catch-Up Threshold for the corresponding Class B Series has been satisfied. (e) Once the 200% Threshold has been satisfied for the Related Series, and the Second Catch-Up Threshold has been satisfied for the corresponding Class B Series (and unless and until the 400% Threshold has been satisfied for the Related Series), the holders of shares of such Class C Series shall be entitled to receive, as a series, the portion of such Distribution (to the extent, if any, not previously distributed) equal to the excess of (i) the product of the amount of such Distribution and the Series C Distribution Percentage for such Class C Series as of the record date for such Distribution over (ii) the amount of such Distribution to which the holders of shares of the corresponding Class B Series are entitled pursuant to Section C.3(e)(ii) of this Article Fourth. The amount of such Distribution to be received by the holders of shares of such Class C Series pursuant to this paragraph (e) shall be distributed ratably, among such holders as of the record date for such Distribution, on a per share basis. (f) Once the 400% Threshold has been satisfied for the Related Series, the holders of shares of such Class C Series shall be entitled to receive, as a series, the percentage of such Distribution (to the extent, if any, not previously distributed) equal to 80% of the Series C Distribution Percentage for such Class C Series as of the record date for such Distribution. The amount of such Distribution to be received by the holders of shares of such Class C Series pursuant to this paragraph (f) shall be distributed ratably, among such holders as of the record date for such Distribution, on a per share basis. 5. For clarity, a Distribution can cause an applicable threshold described above in Section C.2, Section C.3 or Section C.4 of this Article Fourth to be met and/or exceeded, and the use of the term “satisfied” in such Sections does not require a Distribution to cause an applicable threshold only to be exactly met (in contrast to possibly also being exceeded) in order for such threshold to have been satisfied. D. Conversion of Class A Common Stock, Class B Common Stock and Class C Common Stock 1. Mandatory Conversion of Class A Common Stock, Class B Common Stock and Class C Common Stock (a) Determinations of Mandatory Conversion Date Values. As soon as practicable following the close of business on a Mandatory Conversion Date (other than a Change of Control Mandatory Acceleration Date), the Company shall (i) determine the Mandatory Conversion Date Per Share Value and the Mandatory Conversion Date Value with respect to each applicable Series and (ii) provide written notice (the “Mandatory Conversion Date Notice”) to all holders of shares of each applicable Series of such determinations and such other determinations as required by Section D.1 of this Article Fourth (collectively the “Mandatory Conversion Date Exhibit 3.1 to relevant information together with such all Determinations”), determinations. The Mandatory Conversion Date Determinations as set forth in the Mandatory Conversion Date Notice shall be made by the Company and shall be final, binding and conclusive unless a notice of objection is delivered in accordance with the immediately following sentence. The holders of (A) a majority of the shares then issued and outstanding of one or more Class A Series and/or (B) Class B Shares representing a majority of the Class B Shares then issued and outstanding may deliver a notice of objection in writing to the Company (a “Mandatory Conversion Date Objection Notice”) to the Mandatory Conversion Date Determinations as set forth in the Mandatory Conversion Date Notice prior to the close of business on the first (1st) Business Day following receipt of the Mandatory Conversion Date Notice; provided, however, that if such Mandatory Conversion Date is only in respect of one or more, but not all, Series, the reference in (A) above shall only be to holders of a majority of the Class A Shares then issued and outstanding of such applicable Class A Series. If (x) the holders of a majority of the shares then issued and outstanding of each Class A Series (other than the Class A Series in respect of Series A-9 Stock), determined as if the shares of Series A-1 Stock and Series A-2 Stock constituted a single Class A Series, and (y) the Class B Shareholders representing a majority of the Class B Shares then issued and outstanding are unable to agree upon such Mandatory Conversion Date Determinations within two (2) calendar days after delivery of such Mandatory Conversion Date Objection Notice (or such longer period as may be agreed by such Class A Shareholders and such Class B Shareholders), then (1) the Investor Shareholders representing a majority of the Class A Shares then held by the Investor Shareholders and (2) the Class B Shareholders representing a majority of the Class B Shares then issued and outstanding, as the two designated parties with respect to the dispute, shall enter into the Appraisal Procedure; provided, however, that if such Mandatory Conversion Date is only in respect of one or more, but not all, Series, the reference in (x) above shall only be to holders of a majority of the Class A Shares then issued and outstanding of such applicable Class A Series, and the reference in (1) above shall be to holders of a majority of the Class A Shares then issued and outstanding of such applicable Class A Series. (b) Mandatory Conversion of Class A Shares. As of the close of business on the Final Conversion Date, the shares of each applicable Class A Series shall automatically convert, without further action on the part of the holders thereof, into a number of Class P Shares equal to the quotient obtained by dividing (i) the Class A Maximum Amount for such Class A Series by (ii) the Mandatory Conversion Date Per Share Value. For clarification, no Class A Shares of a particular Series will remain outstanding after the occurrence of the Final Conversion Date for the Related Series. The Class P Shares received by holders of Class A Shares in a Series pursuant to the conversion in this Section D.1(b) shall be issued ratably, among such Class A Shareholders on a per share basis. (c) Mandatory Conversion of Class B Shares. As of the close of business on the Final Conversion Date, the shares of each applicable Class B Series shall Exhibit 3.1 automatically convert, without further action on the part of the holders thereof, into a number of Class P Shares equal to the quotient obtained by dividing (i) the Class B Maximum Amount for such Class B Series by (ii) the Mandatory Conversion Date Per Share Value. For clarification, no Class B Shares of a particular Series will remain outstanding after the occurrence of the Final Conversion Date for the Related Series. The Class P Shares received by holders of Class B Shares in a Series pursuant to the conversion in this Section D.1(c) shall be issued ratably, among such Class B Shareholders on a per share basis. (d) Mandatory Conversion of Class C Shares. As of the close of business on the Final Conversion Date, the shares of each applicable Class C Series shall automatically convert, without further action on the part of the holders thereof, into a number of Class P Shares equal to the quotient obtained by dividing (i) the Class C Maximum Amount for such Class C Series by (ii) the Mandatory Conversion Date Per Share Value. For clarification, no Class C Shares of a particular Series will remain outstanding after the occurrence of the Final Conversion Date for the Related Series. The Class P Shares received by holders of Class C Shares in a Series pursuant to the conversion in this Section D.1(d) shall be issued ratably, among such Class C Shareholders on a per share basis. (e) Change of Control Mandatory Acceleration Date. (i) Except as provided in Section D.1(e)(iv) of this Article Fourth, the unanimous vote of all holders of Common Stock shall be required to approve a Change of Control unless the Company ensures that, as a condition precedent to the consummation of a Change of Control, (A) all holders of shares of each Series, subject to clause (C) below, receive in such Change of Control the same cash and/or non-cash consideration in respect of such holders’ Class P Shares to be received upon conversion of such holders’ Class A Shares, Class B Shares and Class C Shares pursuant to this Section D.1(e) as all other Class P Shareholders, (B) all holders of shares, as such, of each Series are otherwise treated in an identical manner, and participate on the same basis, in such Change of Control as Class P Shareholders on the basis of the Total Number of Conversion Shares for such Series and (C) in the event that the Class P Shareholders have the opportunity to elect the form of consideration to be received in such Change of Control, the Class A Shareholders of each Series have an equivalent opportunity to so elect and the election of the Class A Shareholders of an applicable Series that represent a majority of the issued and outstanding Class A Shares of the Related Series shall apply to all Class A Shares, Class B Shares and Class C Shares in the Related Series (and if the Company so ensures, then the unanimity requirement stated above shall no longer apply and in lieu thereof the regular approval requirement that would otherwise be applicable shall apply instead). Exhibit 3.1 (ii) Except as provided in Section D.1(e)(iv) of this Article Fourth, immediately prior to the consummation of such Change of Control (unless a Change of Control Objection Notice is delivered pursuant to Section D.1 (e)(iii) of this Article Fourth, in which case immediately following the final determination of the Change of Control Determinations in accordance with Section D.1(e)(iii) of this Article Fourth), (A) the shares of each applicable Class A Series shall automatically convert, without further action on the part of the holders thereof, into a number of Class P Shares equal to the quotient obtained by dividing (x) the Class A Maximum Amount for such Class A Series by (y) the Mandatory Conversion Date Per Share Value, (B) the shares of each applicable Class B Series shall automatically convert, without further action on the part of the holders thereof, into a number of Class P Shares equal to the quotient obtained by dividing (x) the Class B Maximum Amount for such Class B Series by (y) the Mandatory Conversion Date Per Share Value and (C) the shares of each applicable Class C Series shall automatically convert, without further action on the part of the holders thereof, into a number of Class P Shares equal to the quotient obtained by dividing (x) the Class C Maximum Amount for such Class C Series by (y) the Mandatory Conversion Date Per Share Value; provided, that the Company shall ensure that, as a condition precedent to such automatic conversions and the consummation of such Change of Control, such Change of Control is structured to enable the Company to provide advance written notice (the “Change of Control Notice”) in accordance with Section D.1(e)(iii) of this Article Fourth to all holders of shares of each applicable Series of the determinations required by this paragraph (e)(ii) (the “Change of Control Determinations”), to such determinations. The Class P Shares received by holders of Class A Shares in a Series pursuant to the conversion in this Section D.1(e)(ii) shall be issued ratably, among such Class A Shareholders on a per share basis. The Class P Shares received by holders of Class B Shares in a Series pursuant to the conversion in this Section D.1(e)(ii) shall be issued ratably, among such Class B Shareholders on a per share basis. The Class P Shares received by holders of Class C Shares in a Series pursuant to the conversion in this Section D.1 (e)(ii) shall be issued ratably, among such Class C Shareholders on a per share basis. information relevant together with all (iii) The Change of Control Notice shall be delivered by the Company no later than 9:00 p.m., New York City time, on the trading day immediately preceding the date of the consummation of such Change of Control (which consummation shall not take place prior to 9:00 a.m., New York City time, on such date of consummation), and the Change of Control Determinations set forth in the Change of Control Notice shall be final, binding and conclusive unless the holders of (A) a majority of the shares then issued and outstanding of one or more Class A Series (other than the Class A Series in respect of Series A-9 Stock), for which purposes the Class A Series in respect of Series Exhibit 3.1 A-1 Stock and the Class A Series in respect of Series A-2 Stock shall be considered as a single Class A Series, and/or (B) Class B Shares representing a majority of the Class B Shares then issued and outstanding deliver a notice of objection in writing to the Company (a “Change of Control Objection Notice”) to the Change of Control Determinations set forth in the Change of Control Notice prior to 8:00 a.m., New York City time, on the date of the consummation of the Change of Control. If a Change of Control Objection Notice is delivered in accordance with the preceding sentence and the holders described in clauses (A) and (B) of the preceding sentence are unable to agree upon such Change of Control Determinations within two (2) calendar days after delivery of such Change of Control Objection Notice (or such longer period as may be agreed by such Class A Shareholders and such Class B Shareholders), then (1) the Investor Shareholders representing a majority of the Class A Shares then held by the Investor Shareholders and (2) the Class B Shareholders representing a majority of the Class B Shares then issued and outstanding, as the two designated parties to the dispute, shall enter into the Appraisal Procedure. (iv) If, in addition to any other approvals required by this Certificate of Incorporation, the bylaws of the Company or applicable law, the requisite Class A Shareholders, Class B Shareholders and Class C Shareholders approve a Replicated Change of Control pursuant to Section 3.6(h)(i) of the Shareholders Agreement, the Class A Shares, Class B Shares and Class C Shares shall receive the consideration provided for such shares in such Replicated Change of Control and Sections D.1(e)(i), (e)(ii) and (e)(iii) of this Article Fourth shall not apply with respect to such Replicated Change of Control; provided, that if, pursuant to Section 3.6(h)(i)(A) of the Shareholders Agreement, the requisite Class A Shareholders and Class B Shareholders approve a Replicated Change of Control and the requisite Class C Shareholders do not approve such Replicated Change of Control, the Class A Shares and the Class B Shares shall receive the consideration provided for the Class A Shares and the Class B Shares, respectively, in such Replicated Change of Control and Sections D.1(e)(i), (e)(ii) and (e)(iii) of this Article Fourth shall not apply to the Class A Shares and Class B Shares with respect to such Replicated Change of Control, and Sections D.1(e)(i), (e)(ii) and (e) (iii) of this Article Fourth shall apply to the Class C Shares unless the requisite Class C Shareholders elect to receive the consideration proposed in such Non-Cash Change of Control pursuant to Section 3.6(h)(i)(B) of the Shareholders Agreement, in which case the Class C Shares shall receive the consideration provided for the Class C Shares in such Non-Cash Change of Control and Sections D.1(e)(i), (e)(ii) and (e)(iii) of this Article Fourth shall not apply to the Class C Shares with respect to such Non-Cash Change of Control; provided, further, that, regardless of whether or not the requisite Class B Shareholders and/or Class C Shareholders have approved a Exhibit 3.1 Replicated Change of Control pursuant to Section 3.6(h)(i) of the Shareholders Agreement, the requisite Class A Shareholders may elect to have Sections D.1(e)(i), (e)(ii) and (e)(iii) of this Article Fourth apply to all Class A Shares, Class B Shares and Class C Shares with respect to such Non Cash Change of Control pursuant to Section 3.6(h)(ii) of the Shareholders Agreement. (f) Maximum Number of Conversion Shares. For the avoidance of doubt, in no event shall the aggregate number of shares of a Series convert into a number of Class P Shares greater than the Total Number of Conversion Shares remaining for such Series as of (1) the Final Conversion Date, in the case of a Mandatory Conversion Date (other than a Change of Control Mandatory Acceleration Date) or (2) immediately prior to the consummation of the Change of Control, in the case of a Change of Control Mandatory Acceleration Date. (g) Pending Distributions. In the event that a Final Conversion Date or a Change of Control Mandatory Acceleration Date occurs after the record date of a Distribution but prior to the payment of such Distribution, the automatic conversions contemplated in Sections D.1(b), D.1(c) and D.1(d) of this Article Fourth, or D.1(e) (ii) of this Article Fourth, as applicable, and the calculations relating to such conversions, shall not occur until the Business Day immediately following the payment date of such Distribution. For clarification, (i) none of the Final Mandatory Conversion Date Calculation Period, the Mandatory Conversion Date Value or the Mandatory Conversion Date Per Share Value relating to such Final Conversion Date or Change of Control Mandatory Acceleration Date shall be adjusted and (ii) such Distribution shall be reflected in the calculations of the Class A Maximum Amount, the Class B Maximum Amount and the Class C Maximum Amount (through such Distribution being reflected in the calculations of Series A Total Value, Series B Total Value and Series C Total Value). 2. Voluntary Conversion of Class A Common Stock and Related Automatic Conversion of Class B Common Stock and Class C Common Stock Prior to Mandatory Conversion Date. (a) Voluntary Conversion of Class A Shares. Prior to the Mandatory Conversion Date, a holder of shares of a Class A Series (other than Series A-9 Stock) shall be entitled, at any time and from time to time, to voluntarily convert each such share into a number of Class P Shares as determined below, subject to the following requirements: (i) Such holder (the “Converting Holder”) shall have provided written notice (each, a “Conversion Notice”) to the Company and the Transfer Agent indicating that such Converting Holder is converting shares of such Class A Series into the number of Class P Shares specified in the Conversion Notice in order to, as specified in such Conversion Notice, (x) other than pursuant to a tender offer, effect the Transfer of all such Class P Shares to be received Exhibit 3.1 upon such conversion (1) solely for cash (an “All Cash Sale”), which All Cash Sale must be executed (though not closed), prior to or concurrently with the delivery of the Conversion Notice to the Company and the Transfer Agent or (2) other than solely for cash (a “Non-Cash Sale”), which Non-Cash Sale must be executed (though not closed), or be subject to a definitive agreement entered into, prior to or concurrently with the delivery of the Conversion Notice to the Company and the Transfer Agent, (y) tender all of such Class P Shares to be received upon such conversion into a tender offer that must be outstanding at the time of the delivery of the Conversion Notice to the Company and the Transfer Agent and (1) involves all cash consideration (an “All Cash Tender Offer”) or (2) does not involve all cash consideration (a “Non-Cash Tender Offer”), or (z) distribute or transfer all Class P Shares to be received upon such conversion pursuant to an Investor Distribution. Such Conversion Notice shall set forth (A) the number of Class P Shares being Transferred (or transferred pursuant to an Investor Distribution), (B) in the case of an All Cash Sale, a Non-Cash Sale, an All Cash Tender Offer or a Non-Cash Tender Offer, the aggregate Net Sale Proceeds, and the weighted average per share Net Sale Proceeds with respect to the applicable Transfer (together with such supporting documentation as is reasonable under the circumstances regarding the calculation of aggregate and weighted average per share Net Sale Proceeds, including to enable the Company to determine the Fair Market Value of any non-cash consideration other than publicly traded securities (“Illiquid Consideration”)) and (C) in the case of an Investor Distribution, the Investor Distribution Per Share Value with respect to such Investor Distribution. (ii) Subject to Section D.2(a)(ii)(A) of this Article Fourth, in the case of an All Cash Sale, All Cash Tender Offer, Investor Distribution, Non-Cash Sale or Non-Cash Tender Offer (in the case of a Non-Cash Sale or a Non- Cash Tender Offer, in each case not involving Illiquid Consideration), no later than one (1) Business Day following receipt of a Conversion Notice, the Company shall provide written instructions to the Transfer Agent and the Converting Holder confirming the number of Class P Shares to be issued upon such Voluntary Conversion and the number of shares of the applicable Class A Series to be converted (the “Conversion Instructions”), and in the event of any discrepancy between the Conversion Notice and the Conversion Instructions, the Conversion Instructions shall control. In the case of a Non- Cash Sale or a Non-Cash Tender Offer, in each case involving Illiquid Consideration, the Company shall provide, as promptly as practicable following the delivery of a Conversion Notice (and supporting documentation described in Section D.2(a)(i) of this Article Fourth) to the Company and the Transfer Agent (but in no event later than five (5) Business Days following such delivery), written notice to the Converting Holder and the Class B Shareholders setting forth the Company’s determination of Fair Market Value of such Illiquid Consideration. No later than one (1) Business Exhibit 3.1 Day after the Fair Market Value of such Illiquid Consideration (and the corresponding calculation of Net Sale Proceeds) is finally determined in accordance with the definition of “Fair Market Value”, the Company shall provide written instructions (the “Non-Cash Conversion Instructions”) to the Transfer Agent and the Converting Holder confirming the number of Class P Shares to be issued pursuant to the Conversion Notice and the number of shares of the applicable Class A Series to be converted. In the event of a discrepancy between the Conversion Notice and the Non-Cash Conversion Instructions, the Non-Cash Conversion Instructions shall control. (A) Notwithstanding anything to the contrary contained herein, the first sentence of Section D.2(a)(ii) shall not apply to any All Cash Sale, All Cash Tender Offer, Investor Distribution, Non- Cash Sale or Non-Cash Tender Offer (in the case of a Non-Cash Sale or a Non-Cash Tender Offer, in each case not involving Illiquid Consideration), and the conversions and issuances contemplated by clause (x) of Section D.2(a)(iii) of this Article Fourth shall occur immediately and automatically upon the delivery of the Conversion Notice (and supporting documentation described in Section D.2(a) (i) of this Article Fourth) by the Converting Holder to the Transfer Agent and the Company, so long as such Conversion Notice in respect of such All Cash Sale, All Cash Tender Offer, Investor Distribution, Non-Cash Sale or Non-Cash Tender Offer, as applicable, (1) was delivered by the Converting Holder pursuant to Section D.2(a)(i) of this Article Fourth during a Periodic Sales Pre-Clearance Period for the applicable Class A Series (as determined pursuant to Section D.2 (a)(ii)(C) of this Article Fourth), (2) sets forth the weighted average of the Investor Distribution Per Share Value and per share Net Sale Proceeds for all All Cash Sales, All Cash Tender Offers, Investor Distributions, Non-Cash Sales or Non-Cash Tender Offers, as applicable, by such Converting Holder and all other holders of shares of the same Class A Series pursuant to Section D.2(a) of this Article Fourth during such Periodic Sales Pre-Clearance Period, such that the weighted average of the Investor Distribution Per Share Value and per share Net Sale Proceeds for all Investor Distributions and Transfers (considered as a group) by such Converting Holder and all other holders of shares of the same Class A Series pursuant to Section D.2(a) of this Article Fourth during such Periodic Sales Pre-Clearance Period (taking into account such current All Cash Sales, All Cash Tender Offers, Investor Distributions, Non-Cash Sales or Non-Cash Tender Offers, as applicable) falls within a Pre-Cleared Price, (3) sets forth a number of Class P Shares being Transferred (or transferred pursuant to an Investor Distribution) in connection with all such All Cash Sales, All Cash Tender Offers, Investor Distributions, Non-Cash Sales or Non-Cash Tender Offers, as applicable, such that the Exhibit 3.1 aggregate number of Class P Shares Transferred (or transferred pursuant to an Investor Distribution) by such Converting Holder and all other holders of shares of the same Class A Series pursuant to Section D.2(a) of this Article Fourth during such Periodic Sales Pre- Clearance Period (taking into account such current All Cash Sales, All Cash Tender Offers, Investor Distributions, Non-Cash Sales or Non-Cash Tender Offers, as applicable) does not exceed the Pre- Cleared Number of Shares corresponding to such Pre-Cleared Price, (4) sets forth the weighted average of the Investor Distribution Per Share Value and per share Net Sale Proceeds for such All Cash Sale, All Cash Tender Offer, Investor Distribution, Non-Cash Sale or Non- Cash Tender Offer, as applicable, by such Converting Holder, (5) sets forth the number of Class P Shares being Transferred (or transferred pursuant to an Investor Distribution) by such Converting Holder in connection with such All Cash Sale, All Cash Tender Offer, Investor Distribution, Non-Cash Sale or Non-Cash Tender Offer, as applicable, and (6) contains a certification by the Converting Holder that the requirements of clauses (1), (2) and (3) above are satisfied. (B) With respect to any Conversion Notice delivered pursuant to Section D.2(a)(ii)(A), the Converting Holder shall be permitted, at any time prior to the closing or consummation of the related Transfer or Investor Distribution, to amend such Conversion Notice to update the aggregate, and/or the weighted average per share Net Sale Proceeds or the Investor Distribution Per Share Value, as applicable, set forth therein, and/or any instructions of a ministerial or de minimis nature (which, for the avoidance of doubt, shall not include updates to the number of Class P Shares to be Transferred (or transferred pursuant to an Investor Distribution) pursuant to such Conversion Notice, any reduction to the number of Class P Shares ultimately Transferred or transferred pursuant to an Investor Distribution, as applicable, being governed by Section D.2(a)(v) of this Article Fourth), and such Conversion Notice, as amended, shall be deemed to be such Converting Holder’s “Conversion Notice” for purposes of Sections D.2(a)(v)-(xi), D.2(b) and D.2(d) of this Article Fourth; provided, that such Converting Holder shall not be permitted to amend such Conversion Notice pursuant to the foregoing if such Conversion Notice, as amended, would not meet the requirements set forth in clauses (2) and (3) of Section D.2(a)(ii)(A) of this Article Fourth. (C) A holder of shares of a Class A Series may, at any time and from time to time, deliver to the Company and the Transfer Agent a Periodic Sales Pre-Clearance Request, which shall be effective from and after the deemed certification of such Periodic Sales Pre- Exhibit 3.1 Clearance Request until the earliest of (w) the deemed certification of a subsequent Periodic Sales Pre-Clearance Request of such holder (or any other holder within the same Class A Series), (x) the next payment date by the Company of a Distribution, (y) the subsequent delivery of a Conversion Notice pursuant to Section D.2(a)(ii)(A) of this Article Fourth that does not meet the requirements set forth in clauses (2) and (3) of such Section and (z) the delivery of an Excess Class P Share Notice pursuant to Section D.2(a)(viii) (a “Periodic Sales Pre-Clearance Period”). If the Company either (I) notifies the Transfer Agent and the Requesting Holders that it does not object to such Periodic Sales Pre-Clearance Request or (II) does not deliver a notice of objection in writing to the Transfer Agent and the Requesting Holder by the close of business on the second (2nd) Business Day following the Requesting Holder’s delivery of a Periodic Sales Pre- Clearance Request to the Company and the Transfer Agent, which written objection must set forth with reasonable specificity the Company’s objections to such Periodic Sales Pre-Clearance Request (a “Pre-Clearance Objection”), then such Periodic Sales Pre- Clearance Request shall be deemed to have been duly certified by the Company for all purposes under this Article Fourth for the applicable Class A Series. If the Company does deliver to the Transfer Agent and the Requesting Holder a Pre-Clearance Objection by the close of business on the second (2nd) Business Day following the Requesting Holder’s delivery of a Periodic Sales Pre-Clearance Request, each of the Company and the Requesting Holder shall use reasonable best efforts to reach an agreement on Pre-Cleared Prices (and a corresponding Pre-Cleared Number of Shares for each Pre- Cleared Price) by the close of business on the second (2nd) Business Day following the Company’s delivery of such Pre-Clearance Objection. If the Requesting Holder and the Company are able to reach an agreement on Pre-Cleared Prices (and a corresponding Pre- Cleared Number of Shares for each Pre-Cleared Price), the Company shall immediately notify the Transfer Agent of such agreement, and the Periodic Sales Pre-Clearance Request (as adjusted for such agreed Pre-Cleared Prices and corresponding Pre-Cleared Number of Shares for each Pre-Cleared Price) shall be deemed to have been duly certified by the Company for all purposes under this Article Fourth for the applicable Class A Series. If the Requesting Holder and the Company fail to reach an agreement on a Pre-Cleared Number of Shares and Pre-Cleared Price by the close of business on the second (2nd) Business Day following the Company’s delivery of such Pre- Clearance Objection (or such longer period as the Requesting Holder and the Company shall agree), then the Requesting Holder and the Company, as the two designated parties to the dispute, shall enter into the Appraisal Procedure, and the Periodic Sales Pre-Clearance Exhibit 3.1 finally determined pursuant Request (as adjusted for the final determinations pursuant to the Appraisal Procedure) shall be deemed to have been duly certified by the Company for all purposes under this Article Fourth for the applicable Class A Series when Pre-Cleared Prices (and a corresponding Pre-Cleared Number of Shares for each Pre-Cleared Price) are the Appraisal Procedure. Notwithstanding anything to the contrary contained herein, the Company shall only deliver a Pre-Clearance Objection to assert that the Pre-Clearance Request violates the proviso contained at the end of the definition of “Periodic Sales Pre-Clearance Request;” and such Pre-Clearance Objection shall be limited to correcting such corresponding Pre-Cleared Number of Shares so that such Transfer or Investor Distribution would not cause the Total Number of Conversion Shares for the applicable Series to fall below the Conversion Share Minimum Threshold for such Series. to (iii) (x) Immediately and automatically upon the delivery of the Conversion Notice (and supporting documentation described in Section D.2 (a)(i) of this Article Fourth) or Conversion Instructions, as applicable, to the Transfer Agent and the Company (other than in the case of a Non-Cash Sale or a Non-Cash Tender Offer, in each case involving Illiquid Consideration), the issuance of Class P Shares (subject to Section D.2(a)(ix) of this Article Fourth, free of any restrictive legends or stop orders) in conversion of shares of the applicable Class A Series shall occur as specified in such Conversion Notice or Conversion Instructions, as applicable and (y) in the case of a Non- Cash Sale or a Non-Cash Tender Offer, in each case involving Illiquid Consideration, immediately and automatically upon the delivery of the Non- Cash Conversion Instructions by the Company to the Transfer Agent, the issuance of Class P Shares (subject to Section D.2(a)(ix) of this Article Fourth, free of any restrictive legends or stop orders) in conversion of shares of the applicable Class A Series shall occur as specified in such Non-Cash Conversion Instructions. (iv) Subject to the provisions of Section D.2(a)(viii) of this Article Fourth, in no event shall any holder of any Class A Series engage in an All Cash Sale, Non-Cash Sale, All Cash Tender Offer, Non-Cash Tender Offer, or Investor Distribution pursuant to this Section D.2(a) to the extent that such All Cash Sale, Non-Cash Sale, All Cash Tender Offer, Non-Cash Tender Offer, or Investor Distribution would result in the number of Class P Shares issued upon the conversion of shares of such Class A Series pursuant to the applicable Conversion Notice (and after giving effect to the concurrent conversions by other holders of shares of the same Class A Series) exceeding the Total Number of Conversion Shares remaining for the Related Series after taking into account the number of Class P Shares into which the corresponding Class B Series is entitled to convert in accordance with Section D.2(b) of this Exhibit 3.1 Article Fourth (without taking into account the limitation set forth in the final sentence of such Section D.2(b)) and the number of Class P Shares into which the corresponding Class C Series is entitled to convert in accordance with Section D.2(d) of this Article Fourth (without taking into account the limitation set forth in the final sentence of such Section D.2(d)), in each case as a result of the conversion of such Class A Series in connection with such Transfer or Investor Distribution, as applicable. (v) If a Voluntary Conversion occurs in connection with an All Cash Sale, a Non-Cash Sale or Investor Distribution, but such All Cash Sale, Non- Cash Sale or Investor Distribution is not closed or consummated in full (and in accordance with the terms set forth in the applicable Conversion Notice) within five (5) Business Days (or such longer period as may be agreed by the applicable Converting Holder and the Company) following such Voluntary Conversion occurring pursuant to Section D.2(a)(iii) of this Article Fourth, then the applicable Converting Holder shall, within one (1) Business Day thereafter, so notify the Transfer Agent and the Company in writing, and any Class P Shares issued in such Voluntary Conversion and with respect to which such All Cash Sale, Non-Cash Sale or Investor Distribution is not closed or consummated shall immediately and automatically convert into a number of Class A Shares of the applicable Class A Series as is necessary to cause the number of Class A Shares outstanding in such Class A Series to be equal to the number that would have been outstanding if the applicable Conversion Notice had initially set forth only such number of Class P Shares with respect to which such All Cash Sale, Non-Cash Sale or Investor Distribution did close or consummate. If a Voluntary Conversion occurs in connection with an All Cash Tender Offer or a Non-Cash Tender Offer, but such All Cash Tender Offer or Non-Cash Tender Offer is terminated or expires without the acceptance of all of the applicable Class P Shares having been effected (taking into account shares tendered via notice of guaranteed delivery as of the time of acceptance (if any), subject to pro-ration), including as a result of pro-ration in the event of any offer for less than all shares (or if there occurs any withdrawal of tendered Class P Shares by the Converting Holder), then the applicable Converting Holder shall, within one (1) Business Day thereafter, so notify the Transfer Agent and the Company in writing and the Class P Shares issued in such Voluntary Conversion that were not so accepted or that were withdrawn shall immediately and automatically convert into a number of Class A Shares of the applicable Class A Series as is necessary to cause the number of Class A Shares outstanding in such Class A Series to be equal to the number that would have been outstanding if the applicable Conversion Notice had initially set forth only such number of Class P Shares with respect to which such All Cash Tender Offer or a Non-Cash Tender Offer did close or consummate. In the event of any modification of the consideration to be paid in an All Cash Tender Offer or a Non-Cash Tender Offer (each, a “Tender Offer Consideration Event”), the applicable Converting Holder shall, within Exhibit 3.1 one (1) Business Day thereafter, so notify the Transfer Agent and the Company in writing, which notification shall update the information set forth in such Converting Holder’s Conversion Notice, as applicable, and shall be deemed to be such Converting Holder’s “Conversion Notice” for purposes of Sections D.2(a)(vi)-(xi), Section D.2(b) and Section D.2(d) of this Article Fourth, and if the requirement set forth in Section D.2(a)(ii) of this Article Fourth relating to the delivery of Conversion Instructions applied to such All Cash Tender Offer or a Non-Cash Tender Offer, the Company shall deliver to the Transfer Agent and such Converting Holder updated Conversion Instructions (or, if applicable, Non-Cash Conversion Instructions), which shall be deemed to be the Company’s “Conversion Instructions” (or “Non-Cash Conversion Instructions”) for purposes of Sections D.2(a)(vi)-(xi), Section D.2(b) and Section D.2(d) of this Article Fourth; provided, that in the event that the closing or consummation of such All Cash Tender Offer or Non-Cash Tender Offer following such Tender Offer Consideration Event would result in the Total Number of Conversion Shares remaining for the applicable Series falling below the Conversion Share Minimum Threshold for the applicable Series (after taking into account the number of Class P Shares into which the corresponding Class B Series is entitled to convert in accordance with Section D.2(b) of this Article Fourth (without taking into account the limitation set forth in the final sentence of such Section D.2(b)) and the number of Class P Shares into which the corresponding Class C Series is entitled to convert in accordance with Section D.2(d) of this Article Fourth (without taking into account the limitation set forth in the final sentence of such Section D.2(d)), in each case as a result of such closing or consummation), such Tender Offer Consideration Event shall be deemed a termination of such All Cash Tender Offer or Non-Cash Tender Offer for purposes of this Section D.2(a)(v). (vi) Within one (1) Business Day following the closing or completion of any All Cash Sale, Non-Cash Sale, All Cash Tender Offer, Non-Cash Tender Offer or Investor Distribution to which any Voluntary Conversion relates, the applicable Converting Holder shall so notify the Company in writing, which notice shall certify that such closing or completion occurred in accordance with the terms of the applicable Conversion Notice. Within one (1) Business Day following the receipt of such notice, the Company shall provide written instructions to the Transfer Agent (with a copy to all holders of Class A Shares, Class B Shares and Class C Shares) confirming, as a result of such Voluntary Conversion, if applicable, (A) the number of shares of the corresponding Class A Series that are being converted into the number of Class P Shares set forth in such Conversion Notice pursuant to Section D.2(a) of this Article Fourth, Exhibit 3.1 (B) the number of Class P Shares being issued upon conversion of shares of the corresponding Class B Series pursuant to Section D.2(b) of this Article Fourth, (C) the number of shares of the corresponding Class B Series that are being converted into such number of Class P Shares pursuant to Section D.2(b) of this Article Fourth, (D) the number of Class P Shares being issued upon conversion of shares of the corresponding Class C Series pursuant to Section D.2(d) of this Article Fourth, (E) the number of shares of the corresponding Class C Series that are being converted into such number of Class P Shares pursuant to Section D.2(d) of this Article Fourth, (F) the number of Class P Shares being issued upon conversion of shares of the Series A-9 Stock pursuant to Section D.2 (c)(i) of this Article Fourth, (G) the number of shares of the Series A-9 Stock that are being converted into such number of Class P Shares pursuant to Section D.2(c)(i) of this Article Fourth, (H) the number of Class P Shares being issued upon conversion of the shares of the Series B-9 Stock pursuant to Section D.2(c)(ii) of this Article Fourth as a result of the conversion of shares of the Series A-9 Stock pursuant to Section D.2(c)(i) of this Article Fourth, (I) the number of shares of the Series B-9 Stock that are being converted into such number of Class P Shares pursuant to Section D.2(c)(ii) of this Article Fourth as a result of the conversion of shares of the Series A-9 Stock pursuant to Section D.2(c)(i) of this Article Fourth, (J) the number of shares of Class P Shares being issued upon conversion of the shares of the Series C-9 Stock pursuant to Section D.2(c)(iii) of this Article Fourth as a result of the conversion of shares of the Series A-9 Stock pursuant to Section D.2(c)(i) of this Article Fourth, and (K) the number of shares of the Series C-9 Stock that are being converted into such number of Class P Shares pursuant to Section D.2(c)(iii) of this Article Fourth as a result of the conversion of shares Exhibit 3.1 of the Series A-9 Stock pursuant to Section D.2(c)(i) of this Article Fourth. Such written instructions to the Transfer Agent shall also set forth (i) the total number of Class P Shares that were issued to the holders of shares of the applicable Class A Series (the “Referential Class A Series”) pursuant to the applicable Conversion Notice, (ii) the weighted average per share Net Sale Proceeds or the Investor Distribution Per Share Value, as applicable, for the Transfer or Investor Distribution to which such Voluntary Conversion relates, as set forth in the applicable Conversion Notice (the “Referential Per Share Value”), (iii) the quotient, expressed as a percentage (the “Referential Conversion Percentage”), obtained by dividing (x) the aggregate number of Class P Shares issued to holders of shares of the Referential Class A Series by reason of such Voluntary Conversion and any prior Voluntary Conversions by (y) the Total Number of Conversion Shares set forth opposite the Referential Class A Series in the second sentence of the definition of “Total Number of Conversion Shares,” (taking into account any adjustments to the Total Number of Conversion Shares in respect of such Referential Class A Series pursuant to Section F.1 of this Article Fourth) and (iv) the Series A-9 Stock Conversion Percentage. Immediately and automatically upon the close of business on the Business Day immediately following the date of delivery of such written instructions to the Transfer Agent and the holders of Class A Shares, Class B Shares and Class C Shares, the conversion of such shares of Series A-9 Stock, Class B Shares and/or Class C Shares, as applicable, into Class P Shares shall occur as specified in such instructions, unless a notice of objection is delivered in accordance with the immediately following sentence. The Converting Holder and/or the Class B Shareholders representing a majority of the Class B Shares then issued and outstanding may object in writing to the determinations set forth in such written instructions of the Company prior to the close of business on the first (1st) Business Day following receipt of such written instructions of the Company. In such case, if (x) the Converting Holder, (y) the Company and (z) the Class B Shareholders representing a majority of the Class B Shares then issued and outstanding are unable to agree upon such determinations within two (2) calendar days after delivery of such notice of objection (or such longer period as they shall mutually agree), then (1) the Converting Holder and (2) the Class B Shareholders representing a majority of the Class B Shares then issued and outstanding, as the two designated parties to the dispute, shall enter into the Appraisal Procedure. In the event that a notice of objection is so delivered, the conversion of such shares of Series A-9 Stock, Class B Shares and/or Class C Shares, as applicable, into Class P Shares shall occur upon the close of business on the Business Day immediately following the date on which the Exhibit 3.1 matters in dispute are finally determined in accordance with this Section D.2 (a)(vi). (vii) The number of shares of the applicable Class A Series of a particular holder that will be converted into the number of Class P Shares being Transferred or transferred pursuant to an Investor Distribution, by such holder in accordance with this Section D.2(a), will be the number equal to the Class A Conversion Amount applicable to such holder. (viii) If the Company determines in good faith that, notwithstanding the provisions of Section D.2(a)(iv) of this Article Fourth, a conversion by a Converting Holder pursuant to Section D.2(a)(ii)(A) of this Article Fourth results in the number of Class P Shares issued upon the conversion of shares of a Class A Series pursuant to a particular Conversion Notice (after giving effect to the concurrent conversions by other holders of shares of the same Class A Series) exceeding the Total Number of Conversion Shares remaining for such Class A Series after taking into account the number of Class P Shares into which the corresponding Class B Series is entitled to convert in accordance with Section D.2(b) of this Article Fourth (without taking into account the limitation set forth in the final sentence of such Section D.2(b)) and the number of Class P Shares into which the corresponding Class C Series is entitled to convert in accordance with Section D.2(d) of this Article Fourth (without taking into account the limitation set forth in the final sentence of such Section D.2(d)) (such excess number of Class P Shares being referred to herein as the “Excess Class P Shares”), then no later than one (1) Business Day following receipt of the Conversion Notice for the applicable conversion, the Company shall provide written notice of such determination to the Transfer Agent and the applicable Converting Holder, setting forth the Company’s calculation of the number of Excess Class P Shares (an “Excess Class P Share Notice”); provided, that delivery of such Excess Class P Share Notice shall not prohibit or delay the conversion of Class A Shares, or the issuance of the full number of Class P Shares, as set forth in the Conversion Notice that is the subject of such Excess Class P Share Notice. The determination by the Company of the number of Excess Class P Shares, as set forth in the Excess Class P Share Notice, shall be final, binding and conclusive unless a notice of objection is delivered in accordance with the immediately following sentence. The Converting Holder may object in writing to such determination prior to the close of business on the first (1st) Business Day following receipt of the Excess Class P Share Notice. If the Converting Holder and the Company are unable to agree upon such determination within two (2) calendar days after delivery of such notice of objection (or such longer period as they shall mutually agree), then (1) the Converting Holder and (2) the Company, as the two designated parties to the dispute, shall enter into the Appraisal Procedure. In the event that a notice of objection is so delivered, the number of Excess Class P Shares, if any, Exhibit 3.1 shall be as are finally determined in accordance with this Section D.2(a) (viii). Following any final determination as to the number of Excess Class P Shares, (A) the Converting Holder shall, as promptly as reasonably practicable and in no event later than the fifth (5th) Business Day following such final determination, Transfer to the Company the number of Class P Shares equal to such number of Excess Class P Shares, free and clear of any security interests, liens or similar encumbrances, (B) immediately upon receipt by the Company of such number of Class P Shares from the Converting Holder as replacement for the Excess Class P Shares in accordance with clause (A), the Total Number of Conversion Shares for the applicable Series shall be deemed to be increased by such number of Excess Class P Shares and (C) such number of Class P Shares shall be issued as additional shares pursuant to the conversion of the applicable shares of the Class B Series and/or Class C Series so that the Class P Shares issued upon such conversions pursuant to Section D.2(b) and Section D.2(d) of this Article Fourth shall not be reduced on account of the limitations set forth in the final sentence of such Section D.2(b) or the final sentence of such Section D.2(d), respectively. (ix) Each Conversion Notice shall be accompanied by a certification of the applicable Converting Holder, in a form reasonably satisfactory to the Company and the Transfer Agent, that the Transfer or Investor Distribution, as applicable, being effected in connection with such Conversion Notice is being effected pursuant to a registered offering or in accordance with an exemption from the registration requirements of the Securities Act. (x) Except as otherwise expressly provided in this Section D.2(a)(x), any Voluntary Conversion that occurs pursuant to this Section D.2(a) in connection with an All Cash Sale, Non-Cash Sale, Investor Distribution, All Cash Tender Offer or Non-Cash Tender Offer shall be deemed for all purposes under this Charter (including (A) the automatic conversion of any Class B Shares, Class C Shares or Series A-9 Stock resulting from such Voluntary Conversion, (B) determining the holders of record of Common Stock (including with respect to the class and number held), as of any applicable record date and (C) all other calculations under this Article Fourth (other than for purposes of measuring compliance with Section D.2(a)(iv) of this Article Fourth and the requirements set forth in clauses (2) and (3) of Section D.2(a)(ii)(A) of this Article Fourth)) to have been effected immediately prior to the closing or consummation of such All Cash Sale, Non-Cash Sale, Investor Distribution, All Cash Tender Offer or Non-Cash Tender Offer. For the avoidance of doubt, (1) if any Class P Shares are converted into shares of an applicable Class A Series pursuant to Section D.2(a)(v) of this Article Fourth, for all purposes under this Charter the applicable shares of such Class A Series shall be treated as if the initial conversion of the applicable Exhibit 3.1 shares of such Class A Series into the applicable Class P Shares had not occurred and (2) if any Class P Shares are issued in accordance with Section D.2(a)(iii) of this Article Fourth to a Converting Holder in conversion of Class A Shares on or prior to the record date of a Distribution, and the closing or consummation of the applicable All Cash Sale, Non-Cash Sale, Investor Distribution, All Cash Tender Offer or Non-Cash Tender Offer occurs subsequent to the record date of such Distribution (such Class P Shares, the “Subject Class P Shares,” such Class A Shares, the “Subject Class A Shares” and such Distribution, the “Subject Distribution”), then the following shall be deemed to have occurred by operation of this Section D.2(a)(x): (1) such Subject Class A Shares shall be outstanding as of the record date of such Subject Distribution and such Subject Class P Shares shall not be outstanding as of such record date, (2) such Converting Holder shall, for all purposes under this Article Fourth, be the record holder of such Subject Class A Shares as of the record date of such Subject Distribution and shall not be the record holder of any Subject Class P Shares as of such record date (as there will not be a record holder of such Subject Class P Shares because such Subject Class P Shares will not be outstanding as of such record date), and (3) the Company shall solely pay the Subject Distribution in respect of such Subject Class A Shares and shall not pay any portion of such Subject Distribution in respect of such Subject Class P Shares. The Transfer Agent shall at all times be instructed by the Company to act in a manner consistent with this Section D.2 (a) of Article Fourth, including Section D.2(a)(ii)(A), (B) and (C) and Section D.2(a)(iii) of this Article Fourth and this Section D.2(a)(x). (xi) Notwithstanding the foregoing requirements of this Section D.2 (a), Section D.1 and Section D.2(c) of this Article Fourth, as applicable, shall govern the conversion of any shares of Series A-9 Stock into Class P Shares and holders of shares of Series A-9 Stock shall not be permitted to exercise any voluntary conversions pursuant to this Section D.2(a). (b) Automatic Conversion of Class B Shares Resulting from Conversion of Class A Shares. If immediately following a Voluntary Conversion of shares of a Class A Series (other than Series A-9 Stock) and the closing or consummation of the related Transfer(s) or Investor Distribution(s) of Class P Shares pursuant to Section D.2(a) of this Article Fourth or an automatic conversion of shares of Series A-9 Stock pursuant to Section D.2(c) of this Article Fourth, the Series A Total Value for the Related Series exceeds 150% of the Aggregate Base Amount for the Related Series, then a number of shares of the corresponding Class B Series held by each holder that equals the Class B Conversion Amount shall automatically convert in accordance with Section D.2(a)(vi) of this Article Fourth into a number of Class P Shares determined as follows: Exhibit 3.1 (i) If the Series A Total Value for the Related Series exceeds 150% of the Aggregate Base Amount for the Related Series, but the 200% Threshold for the Related Series has not been exceeded, in each case after giving effect to such Voluntary Conversion and the closing or consummation of the related Transfer(s) or Investor Distribution(s) and the automatic conversion of shares of the corresponding Class C Series pursuant to Section D.2(d) of this Article Fourth (and determined, for this purpose, by taking into account the automatic conversion of shares of such Class B Series pursuant to this Section D.2(b) resulting from such Voluntary Conversion and the closing or consummation of the related Transfer(s) or Investor Distribution(s)), then each holder of shares of such Class B Series shall receive, upon conversion of such Class B Conversion Amount, a number of Class P Shares equal to the product of: (A) such holder’s Class B Fraction, and (B) the quotient obtained by dividing (I) the amount, if any, by which (1) ((x ÷ 0.95) – x) exceeds (2) the Series B Total Value for such Class B Series, where “x” equals the amount, if any, by which the Series A Total Value for the Related Series exceeds the Aggregate Base Amount for the Related Series, in each case determined after giving effect to such Voluntary Conversion and the closing or consummation of the related Transfer(s) or Investor Distribution(s) of Class P Shares and the automatic conversion of shares of such Class C Series pursuant to Section D.2(d), but before giving effect to the conversion of shares of such Class B Series pursuant to this Section D.2(b) resulting from such Voluntary Conversion and the closing or consummation of the related Transfer(s) or Investor Distribution(s), by (II) the weighted average per share Net Sale Proceeds or the Investor Distribution Per Share Value of Class P Shares Transferred or transferred pursuant to an Investor Distribution in connection with such Voluntary Conversion, as set forth in the applicable Conversion Notice; (ii) If Section D.2(b)(i) of this Article Fourth does not apply and the 200% Threshold for the Related Series has been exceeded but the 400% Threshold with respect to the Related Series has not been exceeded (and the Series A Total Value for the Related Series equals or exceeds 195% of the Aggregate Base Amount for the Related Series), in each case after giving effect to such Voluntary Conversion and the closing or consummation of the related Transfer(s) or Investor Distribution(s) of Class P Shares and the automatic conversion of shares of the corresponding Class C Series pursuant Exhibit 3.1 to Section D.2(d) (and determined, for this purpose, by taking into account the automatic conversion of shares of the corresponding Class B Series pursuant to this Section D.2(b) resulting from such Voluntary Conversion and the closing or consummation of the related Transfer(s) or Investor Distribution(s)), then such holder of such Class B Series shall receive, upon conversion of such Class B Conversion Amount, a number of Class P Shares equal to the product of: (A) such holder’s Class B Fraction, and (B) the quotient obtained by dividing: (I) an amount, if any, such that the Series B Total Value (determined, for this purpose, by taking into account the automatic conversion of shares of such Class B Series pursuant to this Section D.2(b) and the automatic conversion of shares of such Class C Series pursuant to Section D.2(d), in each case resulting from such Voluntary Conversion and the closing or consummation of the related Transfer(s) or Investor Distribution(s)) equals the product of (i) the excess, if any, of the Total Value for the Related Series (determined, for this purpose, by taking into account the automatic conversion of shares of such Class B Series pursuant to this Section D.2(b) and the automatic conversion of shares of such Class C Series pursuant to Section D.2(d), in each case resulting from such Voluntary Conversion and the closing or consummation of the related Transfer(s) or Investor Distribution(s)), over the Aggregate Base Amount for the Related Series and (ii) the 10%-20% Automatic Conversion Percentage, by (II) the weighted average per share Net Sale Proceeds or the Investor Distribution Per Share Value of Class P Shares Transferred or transferred pursuant to an Investor Distribution in connection with such Voluntary Conversion, as set forth in the applicable Conversion Notice; and (iii) If Section D.2(b)(i) and Section D.2(b)(ii) of this Article Fourth do not apply and the 400% Threshold for the Related Series has been exceeded, after giving effect to such Voluntary Conversion and related Transfer(s) or Investor Distribution(s) and the automatic conversion of shares of the corresponding Class C Series pursuant to Section D.2(d) (and determined, for this purpose, by taking into account the automatic conversion of shares of the corresponding Class B Series pursuant to this Section D.2 (b) resulting from such Voluntary Conversion and related Transfer(s) or Investor Distribution(s)), then such holder of shares of such Class B Series Exhibit 3.1 shall receive, upon conversion of such Class B Conversion Amount, a number of Class P Shares equal to the product of: (A) such holder’s Class B Fraction, and (B) the quotient obtained by dividing: (I) the amount, if any, by which (1) ((x ÷ 0.80) – x) exceeds (2) the Series B Total Value for the Related Series, where “x” equals the amount, if any, by which the Series A Total Value for the Related Series exceeds the Aggregate Base Amount for the Related Series, in each case determined after giving effect to such Voluntary Conversion and the closing or consummation of the related Transfer(s) or Investor Distribution(s) of Class P Shares and the automatic conversion of shares of such Class C Series pursuant to Section D.2(d), but before giving effect to the automatic conversion of shares of such Class B Series pursuant to this Section D.2(b) resulting from such Voluntary Conversion and the closing or consummation of the related Transfer(s) or Investor Distribution(s), by (II) the weighted average per share Net Sale Proceeds or the Investor Distribution Per Share Value of Class P Shares Transferred or transferred pursuant to an Investor Distribution in connection with such Voluntary Conversion, as set forth in the applicable Conversion Notice. Notwithstanding the other provisions of this Section D.2(b), in no event shall shares of such Class B Series convert into a greater number of Class P Shares than the Total Number of Conversion Shares remaining for the Related Series as of the relevant time, which relevant time, for the avoidance of doubt, shall in all cases be measured following (i) the Voluntary Conversion and the closing or consummation of the related Transfer(s) or Investor Distribution(s) and (ii) the automatic conversion of shares of corresponding Class C Series pursuant to Section D.2(d), in each case giving rise to the automatic conversion of shares of such Class B Series pursuant to this Section D.2(b). (c) Automatic Conversion of Series A-9 Stock, Series B-9 Stock and Series C-9 Stock. (i) If immediately following a Voluntary Conversion of shares of a Class A Series (other than Series A-9 Stock) and the closing or consummation of the related Transfer(s) or Investor Distribution(s) of Class P Shares pursuant to Section D.2(a) of this Article Fourth, the Referential Conversion Percentage exceeds the Series A-9 Stock Conversion Percentage, then a Exhibit 3.1 number of shares of Series A-9 Stock equal to the Class A Conversion Amount for the Series A-9 Stock shall automatically convert into Class P Shares in accordance with Section D.2(a)(vi) of this Article Fourth, without further action on the part of the holders thereof, (A) so that the Series A-9 Stock Conversion Percentage (determined for this purpose after giving effect to such automatic conversion of Series A-9 Stock) equals the Referential Conversion Percentage or (B) if the conversion of the Series A-9 Stock at such time in the entirety would nonetheless result in the Series A-9 Stock Conversion Percentage (determined for this purpose after giving effect to such conversion of Series A-9 Stock at such time in its entirety) being less than the Referential Conversion Percentage, until the Series A-9 Stock is converted in the entirety. (ii) If immediately following a Voluntary Conversion of shares of a Class A Series (other than Series A-9 Stock) and the closing or consummation of the related Transfer(s) or Investor Distribution(s) of Class P Shares pursuant to Section D.2(a) of this Article Fourth, shares of Series A-9 Stock automatically convert pursuant to Section D.2(c) of this Article Fourth, then a number of shares of Series B-9 Stock equal to the Class B Conversion Amount for the Series B-9 Stock shall automatically convert into Class P Shares in accordance with Section D.2(b) of this Article Fourth, without further action on the part of the holders thereof. (iii) If immediately following a Voluntary Conversion of shares of a Class A Series (other than Series A-9 Stock) and the closing or consummation of the related Transfer(s) or Investor Distribution(s) of Class P Shares pursuant to Section D.2(a) of this Article Fourth, shares of Series A-9 Stock automatically convert pursuant to Section D.2(c) of this Article Fourth, then a number of shares of Series C-9 Stock equal to the Class C Conversion Amount for the Series C-9 Stock shall automatically convert into Class P Shares in accordance with Section D.2(d) of this Article Fourth, without further action on the part of the holders thereof. (iv) Notwithstanding any other provision of this Section D.2(c) of this Article Fourth, in no event shall shares of Series A-9 Stock, in the aggregate, convert into a Total Number of Conversion Shares of the Related Series greater than the maximum number of Class P Shares that may be received upon such conversion after taking into account the amount of the Total Number of Conversion Shares of the Related Series to which the holders of shares of Series B-9 Stock are then entitled pursuant to Section D.2(c)(ii) of this Article Fourth as a result of the automatic conversion of Series A-9 Stock pursuant to this Section D.2(c)(i) and the amount of the Total Number of Conversion Shares of the Related Series to which the holders of shares of Series C-9 Stock are then entitled pursuant to Section D.2(c)(iii) of this Article Exhibit 3.1 Fourth as a result of the automatic conversion of Series A-9 Stock pursuant to this Section D.2(c)(i). (d) Automatic Conversion of Class C Shares. (i) If immediately following a Voluntary Conversion of shares of a Class A Series and the closing or consummation of the related Transfer(s) or Investor Distribution(s) of Class P Shares, the 100% Threshold for the Related Series has been exceeded, after giving effect to such Voluntary Conversion and the closing or consummation of the related Transfer(s) or Investor Distribution(s), then a number of shares of the corresponding Class C Series held by each holder that equals the Class C Conversion Amount shall convert in accordance with Section D.2(a)(vi) of this Article Fourth, without further action on the part of the holders thereof, into a number of Class P Shares equal to the product of: (A) such holder’s Class C Fraction; and (B) the amount equal to ((x ÷ y) – x), where (A) “x” equals the number of Class P Shares received by the holder of shares of such Class A Series in such Voluntary Conversion; provided, that if the 100% Threshold for the Related Series would not have been exceeded but for such Voluntary Conversion, “x” shall equal a number of Class P Shares equal to the quotient obtained by dividing (1) the amount by which Series A Total Value (excluding clause (e) of the definition of Series A Total Value) for the Related Series exceeds 100% of the Base Amount for the Related Series by (2) the weighted average per share Net Sale Proceeds or the Investor Distribution Per Share Value of Class P Shares Transferred or transferred pursuant to an Investor Distribution in connection with such Voluntary Conversion, as set forth in the applicable Conversion Notice, and (B) “y” equals the Class A Percentage for such Class A Series. (ii) Notwithstanding the other provisions of this Section D.2(d), in no event shall shares of such Class C Series convert into a greater number of Class P Shares than the Total Number of Conversion Shares remaining for the Related Series as of the relevant time, which relevant time, for the avoidance of doubt, shall in all cases be measured following the Voluntary Conversion and the closing or consummation of the related Transfer(s) or Investor Distribution(s) giving rise to the automatic conversion of shares of such Class C Series pursuant to this Section D.2(d). 3. Acceleration of Conversion of Class B Common Stock and Class C Common Stock Exhibit 3.1 (a) If a holder of Class B Shares or Class C Shares (in such holder’s capacity as such) has incurred a Related Tax Liability pursuant to a Tax Event (or will incur a Related Tax Liability pursuant to a Tax Event, which Related Tax Liability is expected to be payable in cash within seventy five (75) days after delivery of the Accelerated Conversion Notice) (such holder, the “Affected Class B/C Holder”), and the sum of the amount of such Related Tax Liability and the aggregate amount of all Related Tax Liabilities that have been previously incurred by such Affected Class B/C Holder exceeds the aggregate amount of all Series B Total Value and Series C Total Value received in respect of all of the Class B Shares and Class C Shares then or theretofore owned by such Affected Class B/C Holder (such excess amount, the “Excess Amount” and, together with the Aggregate Gross-Up Amount, the “Grossed-Up Excess Amount”), then, subject to Section 7.16(b) of the Shareholders Agreement, such Affected Class B/C Holder shall be entitled to deliver to the Company and the holders of Class A Shares, Class B Shares and Class C Shares a notice of acceleration of conversion of its Class B Shares and/or Class C Shares (an “Accelerated Conversion Notice”) that (i) certifies that such Tax Event has occurred within fifteen (15) Business Days prior to the delivery of such Accelerated Conversion Notice or is expected to occur within seventy five (75) days after delivery of such Accelerated Conversion Notice, (ii) sets forth the amount of such Related Tax Liability, such Excess Amount, the Aggregate Gross-Up Amount, the Grossed- Up Excess Amount and the calculation of such amounts in reasonable detail (which amounts and calculations, to the extent based on estimates of the tax or interest amounts comprising the Related Tax Liability, shall be updated for all purposes of this Section D.3 to reflect the actual amounts as such information becomes available), (iii) certifies that such Affected Class B/C Holder intends to convert its Class B Shares and/or Class C Shares (as determined by such Affected Class B/C Holder, subject to Section D.3(b)(iii) of this Article Fourth) in the manner and to the extent described in paragraph (b) of this Section D.3 and to sell a number of Class P Shares equal to the number of Class P Shares, if any, received pursuant to this Section D.3 of this Article Fourth, and (iv) sets forth such Affected Class B/C Holder’s irrevocable agreement to sell a number of Class P Shares equal to the number of Class P Shares, if any, received pursuant to this Section D.3 of this Article Fourth as described above. An Affected Class B/C Holder that delivers an Accelerated Conversion Notice shall deliver to the Company any information within its possession or reasonably available that is relevant to the determinations required to be made by the Company under Section D.3(b)(i)(B) of this Article Fourth. Solely for purposes of calculating the Excess Amount under this Section D.3(a) and the Series Applicable Amounts under Section D.3(b)(i)(B) in connection with a Tax Event, the aggregate amount of all Series B Total Value and Series C Total Value of a Series received by the applicable Affected Class B/C Holder shall be (1) increased by (i) the Remaining Amount, if any, in respect of such Series, relating to any prior Acceleration Conversion Notice delivered by such Affected Class B/C Holder and (ii) the Remaining Loan Amount, if any, in respect of such Series, relating to any Cash Loan previously made to such Affected Class B/C Holder pursuant to Section 7.16(h) of the Shareholders Agreement, and (2) decreased by an amount, if any, equal to the Exhibit 3.1 product of the Assumed Tax Rate and the aggregate amount of Distributions, to the extent taxable, received by such Affected Class B/C Holder in respect of such holder’s Class B Shares and/or Class C Shares of such Series. For purposes of determining the rights under this Section D.3 of an Affected Class B/C Holder that is a Permitted Transferee or that has transferred Class B Shares or Class C Shares to a Permitted Transferee, the rights of such Affected Class B/C Holder shall not exceed the rights that such holder would have, determined as if (i) such holder, any prior holders of the Class B Shares and/or Class C Shares held by such holder, and all Permitted Transferees of such holder and prior holders were treated as one holder of Class B Shares or Class C Shares, and (ii) such collective holder had incurred a Related Tax Liability with respect to all Class B Shares and/or Class C Shares then or theretofore deemed held by such collective holder, in the same manner as the Related Tax Liability actually was or is expected to be incurred by such Affected Class B/C Holder, as set forth in the Final Accelerated Conversion Calculation Notice. (b) If an Affected Class B/C Holder delivers an Accelerated Conversion Notice, then: (i) Within two (2) Business Days following the delivery of such Accelerated Conversion Notice, the Company shall deliver to the holders of shares of each Class A Series, Class B Series and Class C Series a notice (an “Accelerated Conversion Calculation Notice”) that: (A) confirms that the Series B Total Value and/or Series C Total Value set forth in such Affected Class B/C Holder’s Accelerated Conversion Notice is accurate or sets forth the amounts of Series B Total Value and/or Series C Total Value that the Company determines has been received by such Affected Class B/C Holder (for this purpose, taking into account the adjustments set forth in the penultimate sentence of Section D.3(a)), (B) sets forth, for each Series and to the best of the knowledge of the Company, based on the information concerning such Affected Class B/C Holder’s Related Tax Liability supplied by such Affected Class B/C Holder or otherwise reasonably available to the Company, (1) the sum of the amount of such Related Tax Liability and the aggregate amount of all Related Tax Liabilities that have been previously incurred by such Affected Class B/C Holder in respect of Class B Shares and/or Class C Shares of such Series (each, a “Series Related Amount”), (2) the aggregate amount of all Series B Total Value and Series C Total Value received in respect of all of the Class B Shares and Class C Shares of such Series then or theretofore owned by such Affected Class B/C Holder (for this purpose, taking into account the adjustments set forth in the penultimate sentence of Section D.3(a)) (each, a “Series Total Value Amount”)), (3) the Exhibit 3.1 amount, if any, by which the Series Related Amount exceeds the Series Total Value Amount (the “Series Applicable Amount”), and (4) the Series Gross-Up Amount, and (C) sets forth, with respect to each Series, the quotient obtained by dividing (1) the sum of (x) the Series Applicable Amount and (y) the Series Gross-Up Amount for such Series by (2) the Accelerated Conversion Date Per Share Value, which quotient shall, subject to Section D.3(b)(iii) of this Article Fourth, represent the maximum number of Class P Shares, if any, to be issued upon conversion of shares of the corresponding Class B Series and/or corresponding Class C Series to the Affected Class B/C Holder pursuant to such Accelerated Conversion Notice. (ii) Within three (3) Business Days following the delivery of such Accelerated Conversion Calculation Notice (the “Review Period”), the Class A Representative shall notify the Company and such Affected Class B/C Holder in writing if it disagrees with such Accelerated Conversion Calculation Notice or any calculation or component thereof (the “Notice of Disagreement”). The Notice of Disagreement shall set forth in reasonable detail the basis for such disagreement. If no Notice of Disagreement is so delivered prior to the expiration of the Review Period, then the Accelerated Conversion Calculation Notice shall be deemed to have been accepted by the holders of Class A Common Stock and shall be binding and conclusive. During the five (5) days immediately following the delivery of the Notice of Disagreement (the “Consultation Period”), the Affected Class B/C Holder and the Class A Representative shall seek in good faith to resolve any differences that they may have with respect to the matters specified in the Notice of Disagreement. If, at the end of the Consultation Period, the Affected Class B/C Holder and the Class A Representative have been unable to resolve any differences that they may have with respect to the matters specified in the Notice of Disagreement, the Affected Class B/C Holder and the Class A Representative shall submit all matters that remain in dispute with respect to the Notice of Disagreement (along with a copy of the Accelerated Conversion Calculation Notice marked to indicate those line items that are not in dispute) to the Independent Accountant. The Independent Accountant, acting as an expert and not as an arbitrator, shall be jointly instructed by the Company, the Affected Class B/C Holder and the Class A Representative to, within five (5) days after such Independent Accountant’s selection, make a final determination with respect to each matter that remains in dispute with respect to the Notice of Disagreement, which determination shall be binding and conclusive. The Accelerated Conversion Calculation Notice that is binding and conclusive, as determined either by the failure to deliver a Notice of Disagreement to the Company and the Affected Class B/C Holder prior to the expiration of the Review Period, Exhibit 3.1 through the agreement of the Affected Class B/C Holder and the Class A Representative or by the Independent Accountant pursuant to this Section D.3(b)(ii), is referred to as the “Final Accelerated Conversion Calculation Notice.” The costs of conducting the dispute resolution contemplated by this Section D.3(b)(ii), including the fees of the Independent Accountant, shall be borne by the Company. (iii) For each Series, solely in the event that the Class A Shareholders of such Series do not make a Cash Loan Election pursuant to Section 7.16 (h) of the Shareholders Agreement, subject to Section 7.16(b) of the Shareholders Agreement, within five (5) Business Days following the date on which the Final Accelerated Conversion Calculation Notice becomes binding and conclusive, a number of shares of the corresponding Class B Series held by such Affected Class B/C Holder that is equal to the Class B Conversion Amount for such Class B Series and/or a number of shares of the corresponding Class C Series held by such Affected Class B/C Holder that is equal to the Class C Conversion Amount for such Class C Series shall convert, without further action by such holder (the date of such conversion, the “Accelerated Conversion Date”), into the lesser of: (A) the number of Class P Shares determined for such Class B Series and/or Class C Series under Section D.3(b)(i)(C) of this Article Fourth as set forth in the Final Accelerated Conversion Calculation Notice, and (B) the number of Class P Shares that such Affected Class B/ C Holder would receive in conversion of its shares of such Class B Series and/or such Class C Series pursuant to Section D.1 of this Article Fourth (for the avoidance of doubt, taking into account Section D.3(d) of this Article Fourth with respect to any prior accelerated conversion under this Section D.3) were (x) the Final Mandatory Conversion Date deemed to occur on the date immediately preceding the Accelerated Conversion Date and (y) the Mandatory Conversion Date Per Share Value deemed to be equal to the VWAP of one share of Class P Common Stock during the ten (10) trading days ending on the close of business on the trading day immediately preceding the Accelerated Conversion Date. For purposes of this Section D.3(b)(iii), the Class B Conversion Amount for a Class B Series, and the Class C Conversion Amount for a Class C Series, as the case may be, shall be calculated as though (x) all holders of shares of such Class B Series or Class C Series were converting shares of such Class B Series or Class C Series and (y) the number of Class P Shares to be issued to such Affected Class B/C Holder pursuant to the conversion of his, her or its shares of such Class B Series or Class C Series represented such Affected Class B/C Holder’s pro rata portion of the Class Exhibit 3.1 P Shares to be issued to all such holders of shares of such Class B Series or Class C Series. In the event that such Affected Class B/C Holder holds both Class B Shares and Class C Shares of such Series, the portion of the Class P Shares issuable pursuant to this Section D.3(b)(iii) that are attributed to the conversion of such Class B Shares and the portion of Class P Shares issuable pursuant to this Section D.3(b)(iii) that are attributed to the conversion of such Class C Shares may be determined by such Affected Class B/C Holder as set forth in the applicable Accelerated Conversion Notice; provided, that in no event shall such determination result in the number of Class P Shares attributed to the conversion of such Class B Shares or Class C Shares, as applicable, being greater than the number of Class P Shares attributable to such Class B Shares or Class C Shares, respectively, in the calculation described in paragraph (B) immediately above. (c) For each Series, solely in the event that the Class A Shareholders of such Series do not make a Cash Loan Election pursuant to Section 7.16(h) of the Shareholders Agreement, subject to Section 7.16(b) of the Shareholders Agreement, within five (5) Business Days following the date on which the Final Accelerated Conversion Calculation Notice becomes binding and conclusive, the Company shall cause such Affected Class B/C Holder to receive the number of Class P Shares to which such holder is entitled in conversion of its shares of the corresponding Class B Series and/or corresponding Class C Series pursuant to Section D.3(b)(iii) of this Article Fourth. (d) For each Series, for purposes of determining the rights of the holders of Class A Shares, Class B Shares and Class C Shares of such Series under this Article Fourth in respect of any Distribution, Voluntary Conversion or Mandatory Conversion Date related to such Series occurring after the date an Affected Class B/ C Holder delivers such Accelerated Conversion Notice: (i) the accelerated conversion of such Affected Class B/C Holder’s Class B Shares and/or Class C Shares under this Section D.3 pursuant to such Accelerated Conversion Notice shall be treated as if it had not occurred in calculating Series B Total Value, Series C Total Value, Mandatory Conversion Date Value and the number of Class B Shares and/or Class C Shares of such Series held by each holder of Class B Shares and/or Class C Shares of such Series, but shall subsequently be treated as occurring (and, for the avoidance of doubt, shall be included in such calculations) to the extent that reductions are made pursuant to Section D.3(d)(ii) of this Article Fourth; (ii) the amount of any Distributions that otherwise subsequently would be made to such Affected Class B/C Holder (or his or her heirs, legatees or executors, beneficiaries, or Permitted Transferees (with respect to Class B Shares and/ or Class C Shares of such Series subsequently Transferred, directly or testamentary Transferees, administrators, Exhibit 3.1 indirectly, to such Permitted Transferees)) with respect to such holder’s shares of a Class B Series and/or Class C Series (as applicable), and the number of Class P Shares that otherwise subsequently would be issued to such Affected Class B/C Holder (or his or her heirs, executors, administrators, testamentary Transferees, legatees or beneficiaries, or Permitted Transferees (with respect to Class B Shares and/or Class C Shares of such Series subsequently Transferred, directly or indirectly, to such Permitted Transferees)) upon conversion of such holder’s shares of such Class B Series and/or Class C Series (as applicable) pursuant to Section D.1 or D.2 of this Article Fourth, shall be reduced (including, if applicable, to zero), without duplication, until the aggregate of the amount of such Distributions and the value of such Class P Shares (determined pursuant to, and as of the date otherwise issuable under, Section D.1, D.2(b), D.2(c) or D.2(d) of this Article Fourth, as applicable) that, but for this clause (ii), would have been paid or issued to such Affected Class B/C Holder (collectively, the “Credited Amount”) is equal to the product of (x) the aggregate number of Class P Shares received by such Affected Class B/C Holder upon conversion of shares of such Class B Series and/or Class C Series (as applicable) under this Section D.3 pursuant to any Accelerated Conversion Notice(s) delivered by such Affected Class B/C Holder and (y) the weighted average of the applicable Accelerated Conversion Date Per Share Value(s) associated with the issuance (s) of such Class P Shares (the “Acceleration Amount,” and the amount, if any, by which the Acceleration Amount exceeds the Credited Amount, as calculated from time to time, the “Remaining Amount”); and (iii) For each Series, the amount of any Distributions that otherwise would have been made to such Affected Class B/C Holder with respect to such holder’s shares of such Class B Series and/or Class C Series (as applicable) but for clause (ii) immediately above shall be made to the holders of Class A Shares of the corresponding Class A Series. Any such Distribution shall be distributed ratably among the holders of Class A Shares of such Class A Series as of the record date for such Distribution, on a per share basis. With respect to each Series for which there has been an accelerated conversion pursuant to this Section D.3, immediately following such time that there is no Remaining Amount that exceeds zero, the Class B Shares and/or Class C Shares of such Series (as applicable) shall automatically recapitalize in a manner that causes the relative percentage of Class B Shares and/or Class C Shares (as applicable) of such Series held by each holder of Class B Shares and/or Class C Shares (as applicable) of such Series to be as if such accelerated conversion had not occurred. (e) If the Excess Amount is a positive amount with respect to a Series, the “Series Gross-Up Amount” for such Series shall equal the quotient obtained by dividing (i) the product of (I) the sum of (x) the excess, if any, of (1) the Applicable Exhibit 3.1 Value, in the aggregate, of the Class P Shares received upon conversion of Class B Shares and Class C Shares of such Series and owned by such Affected Class B/C Holder as of the date such holder delivers an Accelerated Conversion Notice, over (2) such holder’s tax basis (as determined for U.S. federal income tax purposes) in such Class P Shares and (y) the excess, if any, of (1) the product of (A) the number of Class P Shares that such Affected Class B/C Holder would otherwise receive pursuant to Section D.3(c) of this Article Fourth in respect of Class B Shares and Class C Shares of such Series, determined without regard to the application of this Section D.3(e) and assuming for this purpose that the Class A Shareholders of such Series did not make a Cash Loan Election pursuant to Section 7.16(h) of the Shareholders Agreement, and (B) the Accelerated Conversion Date Per Share Value, over (2) the tax basis (as determined for U.S. federal income tax purposes) that such Affected Class B/C Holder would have in such Class P Shares and (II) the Assumed Tax Rate for such Affected Class B/C Holder by (ii) an amount, expressed as a percentage, equal to one hundred percent (100%) minus the Assumed Tax Rate for such Affected Class B/C Holder. The “Aggregate Gross-Up Amount” shall equal the aggregate amount of the Series Gross-Up Amount for all Series. (f) For purposes of this Section D.3: (i) “Accelerated Conversion Date Per Share Value” shall mean, with respect to an accelerated conversion pursuant to this Section D.3, the VWAP of one Class P Share during the ten (10) trading days ending on the close of business on the trading day immediately preceding the delivery of the applicable Accelerated Conversion Notice. (ii) “Applicable Value” shall mean, with respect to the Class P Shares, if any, received by the applicable Affected Class B/C Holder pursuant to Section D.2(b), D.2(c) or D.2(d) of this Article Fourth, the product of such number of shares and the applicable per share value described in Section D.2 (b) of this Article Fourth. (iii) “Assumed Tax Rate” shall mean, (x) if the Affected Class B/C Holder is an individual resident of Texas, an entity treated as a disregarded entity or a grantor trust for U.S. federal income tax purposes each of the owners of which is an individual resident of Texas, or any other entity that is a direct or indirect Permitted Transferee of an individual resident of Texas that is or was a holder of Class B Shares and/or Class C Shares (but solely with respect to Class B Shares and/or Class C Shares transferred, directly or indirectly, by such holder to such Permitted Transferee), the highest combined marginal effective U.S. federal, state and local Income Tax rate (exclusive of interest, penalties or additions to tax) prescribed for an individual resident of Houston, Texas applicable to the character of the income realized by such holder, and (y) if the Affected Class B/C Holder is an individual resident of a jurisdiction other than Texas, an entity treated as Exhibit 3.1 a disregarded entity or a grantor trust for U.S. federal income tax purposes each of the owners of which is an individual resident of a jurisdiction other than Texas, or any other entity that is a direct or indirect Permitted Transferee of an individual resident of a jurisdiction other than Texas that is or was a holder of Class B Shares and/or Class C Shares (but solely with respect to Class B Shares and/or Class C Shares transferred, directly or indirectly, by such holder to such Permitted Transferee), the highest combined marginal effective U.S. federal, state and local Income Tax rate (exclusive of interest, penalties or additions to tax) prescribed for an individual resident of New York, New York applicable to the character of the income realized by such holder, in each case taking into account the deductibility of state and local Income Taxes as applicable at the time for U.S. federal income tax purposes to the extent such state and local Income Taxes are actually deductible by such Affected Class B/C Holder. References in this definition to Class B Shares or Class C Shares shall include the limited liability company units in exchange for which such shares were issued. (iv) “Class A Representative” shall mean GS Capital Partners V Fund, L.P., or such other Person as is designated in writing from time to time by the holders of a majority of the voting power of the Class A Common Stock then held by the Investor Shareholders. (v) “Income Tax” shall mean any Tax imposed on or measuredby net income, which shall include, for the avoidance of doubt, any Tax imposed by Section 1411 of the Code (or any successor provision). (vi) “Incorporation” shall mean the conversion of Kinder Morgan Holdco LLC from a Delaware limited liability company to Kinder Morgan, Inc., a Delaware corporation, pursuant to Section 265 of the DGCL and Section 18-216 of the Delaware Limited Liability Company Act. (vii) “Independent Accountant” shall mean (x) Grant Thornton LLP or, if such firm is unable or unwilling to act, such other independent certified public accounting firm mutually acceptable to a majority of the voting power of all issued and outstanding Class B Shares, a majority of the voting power of all issued and outstanding Class C Shares and the Class A Representative or (y) if such Persons are unable to agree upon such firm within three (3) days after the end of the Consultation Period, then, within an additional three (3) days, a majority of the voting power of all issued and outstanding Class B Shares and a majority of the voting power of all issued and outstanding Class C Shares, on the one hand, and the Class A Representative, on the other, shall each select one such independent certified public accounting firm and those two independent certified public accounting firms shall, within three (3) days after such independent certified public accounting firms have been Exhibit 3.1 selected, select a third such independent certified public accounting firm, in which event “Independent Accountant” shall mean such third firm. (viii) “Related Tax Liability” shall mean any liability of a holder of Class B Shares or Class C Shares for Income Tax due in cash or paid in cash (or that reduces a refund of Income Taxes otherwise receivable in cash) with respect to such holder’s Class B Shares or Class C Shares by reason of the occurrence of one or more transactions or events that are deemed, for applicable Income Tax purposes, to have the result of the receipt of property by some shareholders and an increase in the proportionate interests of such holder of Class B Shares or Class C Shares, as applicable, in the assets or earnings and profits of the Company; provided that, for the avoidance of doubt, Related Tax Liability shall not include Income Tax, if any, incurred (I) by reason of the Incorporation, (II) in respect of the sale, transfer or other disposition of shares of Common Stock (other than a disposition by virtue of the conversion of Class B Shares or Class C Shares into Class P Shares where the provision immediately preceding this proviso is otherwise applicable), (III) in respect of the actual payment of Distributions in cash or property by the Company to such holders of Class B Shares or Class C Shares with respect to such holder’s Class B Shares or Class C Shares or (IV) by reason of any transactions pursuant to the last sentence of Section D.3(d), including any recapitalizations, contributions to capital or other actions for the purpose of implementing the last sentence of Section D.3(d); provided, further that such Income Tax shall be determined on a “with and without” basis, and taking into account (i) the deductibility of state and local Income Taxes as applicable at the time for U.S. federal income tax purposes to the extent such state and local Income Taxes are actually deductible by the taxpayer and (ii) the deductibility of U.S. federal Income Taxes as applicable at the time for state and local Income Tax purposes to the extent such U.S. federal Income Taxes are actually deductible by the taxpayer. (ix) “Tax” shall mean any federal, state, local or foreign tax, and any interest, penalty or addition to tax incurred thereon or in connection therewith. (x) “Tax Event” shall mean any of (w) a “determination” within the meaning of Section 1313(a) of the Internal Revenue Code of 1986, as amended, (x) a settlement with a taxing authority with respect to which the taxpayer has no right to appeal, (y) a payment of Tax where the taxpayer retains the right to sue for a refund of such Tax, and (z) a payment of Tax pursuant to an originally filed or amended Income Tax return; provided that, in the case of clause (x), (y) or (z), Section 7.16(a) of the Shareholders Agreement has not been breached by the taxpayer. Exhibit 3.1 (xi) All other capitalized terms that are used in this Section D.3 but not defined in this Article Fourth shall have the meaning assigned to such terms in the Shareholders Agreement. 4. No fractional Class P Shares will be issued as a result of any conversion of Class A Shares, Class B Shares or Class C Shares. In lieu of any fractional share otherwise issuable in respect of any conversion pursuant to this Article Fourth, the Company shall pay an amount in cash equal to the same fraction of the closing price of the Class P Shares determined as of the trading day immediately preceding the effective date of such conversion. 5. Any Class A Shares, Class B Shares or Class C Shares that are converted or otherwise acquired by the Company shall cease to be outstanding and shall not be reissued, and the board of directors shall take all necessary action such that all such shares shall be retired and eliminated from the shares which the Company shall be authorized to issue other than (i) Class B Shares acquired by the Company and transferred to the Class B Trust (as defined in the Shareholders Agreement) pursuant to Section 3.8(b)(iv) of the Shareholders Agreement and (ii) Class A Shares converted into Class P Shares that are automatically converted back into Class A Shares pursuant to Section D.2(a)(v) of this Article Fourth. E. Voting 1. Class P Common Stock Except as otherwise required by applicable law or as otherwise set forth herein, each Class P Shareholder shall be entitled to one (1) vote for each Class P Share standing in its name on the books of the Company and shall vote together (a) with the Class A Shareholders, Class B Shareholders and Class C Shareholders as a single class with respect to the election of directors and (b) with the Class A Shareholders as a single class on all other matters to be voted on by the Company’s stockholders. 2. Class A Common Stock Except as otherwise required by applicable law or as otherwise set forth herein, each Class A Shareholder shall be entitled to a number of votes per Class A Share standing in its name on the books of the Company equal to the quotient obtained by dividing (a) the Total Number of Conversion Shares with respect to the applicable Series (as of the time of determination) by (b) the total number of shares of such Class A Series issued and outstanding (as of the time of determination) and shall vote together (x) with the Class P Shareholders, Class B Shareholders and Class C Shareholders as a single class with respect to the election of directors and (y) with the Class P Shareholders as a single class on all other matters to be voted on by the Company’s stockholders. 3. Class B Common Stock Except as otherwise required by applicable law or as otherwise set forth herein, Class B Shareholders are not entitled to any voting rights and their approval shall not be required for the taking of any corporate action; provided that with respect to the election of directors only, each Exhibit 3.1 Class B Shareholder shall be entitled to one-tenth of one vote (1/10) for each Class B Share standing in its name on the books of the Company and shall vote together with the Class P Shareholders, Class A Shareholders and Class C Shareholders as a single class. 4. Class C Common Stock Except as otherwise required by applicable law or as otherwise set forth herein, Class C Shareholders are not entitled to any voting rights and their approval shall not be required for the taking of any corporate action; provided that with respect to the election of directors only, each Class C Shareholder shall be entitled to one-tenth of one vote (1/10) for each Class C Share standing in its name on the books of the Company and shall vote together with the Class P Shareholders, Class A Shareholders and Class B Shareholders as a single class. 5. Class Voting Rights as to Amendments In addition to any rights that the holders of Common Stock may have pursuant to applicable law, the bylaws of this Company or as otherwise set forth herein, (i) any amendment or change (including through the adoption of any inconsistent provision(s)) to Article Fourth or Article Eleventh of this Certificate of Incorporation shall require the affirmative vote of the following: (A) the holders of at least a majority of the voting power of all issued and outstanding shares, if any, of Series A-1 Stock and Series A-2 Stock, voting together as a class, (B) the holders of at least a majority of the voting power of all issued and outstanding shares, if any, of Series A-3 Stock, voting as a class, (C) the holders of at least a majority of the voting power of all issued and outstanding shares, if any, of Series A-4 Stock, voting as a class, (D) the holders of at least a majority of the voting power of all issued and outstanding shares, if any, of Series A-5 Stock, voting as a class, and (E) the holders of at least a majority of the voting power of all issued and outstanding shares, if any, of Series A-6 Stock, voting as a class; (ii) any amendment or change (including through the adoption of any inconsistent provision(s)) to any provisions of this Certificate of Incorporation other than Article Fourth or Article Eleventh shall require the affirmative vote of holders of at least seventy- five percent (75%) of the voting power of all issued and outstanding Class A Shares, if any; (iii) any amendment or change (including through the adoption of any inconsistent provision(s)) to any provision of this Certificate of Incorporation that amends, alters, repeals, impairs or modifies the rights of a particular class of Common Stock shall require the affirmative vote of holders of at least a majority of the voting power of all issued and outstanding shares of such class of Common Stock, if any; and (iv) any amendment or change (including through the adoption of any inconsistent provision(s)) to any provision of this Certificate of Incorporation that modifies the rights of a particular series of a class of Common Stock in a manner adversely and differently from other series of the same class of Common Stock shall require the affirmative vote of holders of at least a majority of the voting power of all issued and outstanding shares of such series of Common Stock, if any. 6. No Actions Without Meeting Any vote or similar action required or permitted to be taken by the holders of Class P Shares of the Company must be effected at a duly called annual or special meeting of holders of shares of Common Stock of the Company entitled to vote or take similar action with respect to a particular corporate action, including the election of directors, and may not be effected by any Exhibit 3.1 consent in writing by such holders of shares of Common Stock. The holders of Class A Shares, Class B Shares and Class C Shares may, in addition to taking action at a meeting, effect any action required or permitted to be taken by the holders of Class A Shares, Class B Shares or Class C Shares, or any one or more of such classes, as applicable, by consent in writing by the holders of such Class A Shares, Class B Shares or Class C Shares, as applicable. F. Anti-Dilution 1. Certain Adjustments With respect to each Series, for so long as any Class A Shares, Class B Shares or Class C Shares of such Series remain outstanding, the Total Number of Conversion Shares shall be subject to adjustment from time to time as follows: (a) Stock Splits, Subdivisions, Combinations or Share Dividends. If the Company shall (i) split or subdivide the outstanding Class P Shares into a greater number of Class P Shares, (ii) reverse-split or combine the outstanding Class P Shares into a smaller number of Class P Shares, or (iii) dividend or distribute additional Class P Shares to existing Class P Shareholders, the Total Number of Conversion Shares in respect of each Series in effect as of the effective date of such split, subdivision, reverse-split, combination or share dividend shall be adjusted to the number obtained by multiplying the Total Number of Conversion Shares in respect of such Series in effect immediately prior to such effective date of such split, subdivision, reverse-split, combination or share dividend giving rise to this adjustment by a fraction (x) the numerator of which shall be the number of Class P Shares outstanding immediately after, and solely as a result of, such split, subdivision, reverse-split, combination or share dividend and (y) the denominator of which shall be the number of Class P Shares outstanding at the time of the effective date of such split, subdivision, reverse-split, combination or share dividend, prior to giving effect to such event. No dividends or distributions on Class A Shares, Class B Shares or Class C Shares shall be payable in Class P Shares. (b) Reclassifications. In the event of any reclassification of Class P Shares (other than a Change of Control), the right of the holders of shares of any Series to receive (in the aggregate) Class P Shares equal to the Total Number of Conversion Shares in respect of such Series upon conversion of Class A Shares, Class B Shares and Class C Shares of such Series shall be appropriately adjusted to fully reflect the number of shares of stock or other securities or property (including cash) which the Total Number of Conversion Shares in respect of such Series (as of the time of such reclassification) would have been entitled to receive upon consummation of such reclassification had the Total Number of Conversion Shares been issued and outstanding as of the time thereof. (c) Other Events. If any event occurs as to which the provisions of Sections F.1(a) or F.1(b) of this Article Fourth are not strictly applicable or, if strictly applicable, would not, in the good faith judgment of the board of directors, fairly Exhibit 3.1 and adequately protect the conversion rights of the Class A Shares, Class B Shares and Class C Shares in accordance with the essential intent and principles of such provisions, then the board of directors shall make such adjustments in the Total Number of Conversion Shares for each Series, as applicable, in accordance with such essential intent and principles, as shall be reasonably necessary, in the good faith opinion of the board of directors, to protect such conversion rights as aforesaid. (d) Miscellaneous. Any adjustments pursuant to the provisions of this Section F.1 of this Article Fourth shall be made successively whenever an event referred to herein shall occur. In the event that the Company shall propose to take any action of the type described in the provisions of this Section F.1 of this Article Fourth, the Company shall give notice to all holders of shares of each applicable Series, which notice shall specify the approximate date on which such action is to take place. Such notice shall also set forth the facts with respect thereto as shall be reasonably necessary to indicate the effect on the Total Number of Conversion Shares in respect of each applicable Series. In the case of any action which would require the fixing of a record date, such notice shall be given at least ten (10) calendar days prior to the date so fixed, and in case of all other action, such notice shall be given at least fifteen (15) calendar days prior to the taking of such proposed action. In addition, promptly following the time as of which the Total Number of Conversion Shares is adjusted as provided in this Section F.1 of this Article Fourth, the Company shall provide written notice thereof to the Transfer Agent and all holders of shares of each applicable Series, which notice shall show in reasonable detail the facts requiring such adjustment and the Total Number of Conversion Shares in respect of each applicable Series after such adjustment. All calculations of numbers of shares under the provisions of this Section F.1 of this Article Fourth shall be made to the nearest one-hundredth (1/100th) of a share. (e) Proceedings Prior to Any Action Requiring Adjustment. As a condition precedent to the taking of any action which would require an adjustment pursuant to the foregoing provisions of this Section F.1 of this Article Fourth, the Company shall take any action which may be necessary, including obtaining regulatory, national securities exchange or stockholder approvals or exemptions, in order that the Company may thereafter validly and legally issue as fully paid and nonassessable all shares or other securities or property (including cash) that the Class A Shareholders, Class B Shareholders and Class C Shareholders are entitled to receive upon conversion of Class A Shares, Class B Shares and Class C Shares. 2. Certain Other Actions The Company shall not (except in accordance with, and to the extent permitted by, Section 3.8(g) of the Shareholders Agreement) without first obtaining the prior written approval of the following: (A) holders of at least a majority of the voting power of all issued and outstanding shares, if any, of Series A-1 Stock and Series A-2 Stock, voting together as a class, (B) holders of at least a majority of the voting power of all issued and outstanding shares, if any, of Series A-3 Exhibit 3.1 Stock, voting as a class, (C) holders of at least a majority of the voting power of all issued and outstanding shares, if any, of Series A-4 Stock, voting as a class, (D) holders of at least a majority of the voting power of all issued and outstanding shares, if any, of Series A-5 Stock, voting as a class, and (E) holders of at least a majority of the voting power of all issued and outstanding shares, if any, of Series A-6 Stock, voting as a class, to authorize, cause or effect (i) any increase in the authorized number of Class A Shares, Class B Shares or Class C Shares, (ii) any issuance, reissuance or reallocation, of any additional Class A Shares, Class B Shares or Class C Shares, including without limitation as dividends on existing Class A Shares, Class B Shares or Class C Shares, or of any warrants, options or other rights to acquire Class A Shares, Class B Shares or Class C Shares, (iii) any split, subdivision, reverse-split or combination of existing Class A Shares, Class B Shares or Class C Shares or (iv) any authorization, or issuance of any shares of any additional class or series of Common Stock; provided, that (except in accordance with, and to the extent permitted by, Section 3.8(g) of the Shareholders Agreement) (1) any authorization or issuance of any Class B Shares shall also require the prior written approval of holders of at least a majority of the voting power of all issued and outstanding Class B Shares and (2) any authorization or issuance of any Class C Shares shall also require the prior written approval of holders of at least a majority of the voting power of all issued and outstanding Class C Shares. G. Reservation The Company shall at all times reserve and keep available out of its authorized and unissued Class P Shares, solely for issuance upon the conversion of Class A Shares, Class B Shares and Class C Shares as herein provided, free from any preemptive or other similar rights, such number of Class P Shares as shall from time to time be issuable upon the conversion of all the Class A Shares, Class B Shares and Class C Shares then outstanding. All Class P Shares delivered upon conversion of Class A Shares, Class B Shares or Class C Shares in accordance with this Article Fourth shall be duly authorized, validly issued, fully paid and non-assessable, free and clear of all liens, claims, security interests and other encumbrances. H. Payment of Transfer Taxes The Company shall pay all stock transfer, documentary, and stamp taxes relating to the conversion of Class A Shares, Class B Shares or Class C Shares, including, for the avoidance of doubt, the issuance or delivery of Class P Shares to the Converting Holder upon the conversion of Class A Shares, Class B Shares or Class C Shares pursuant to Section D of this Article Fourth. I. Delivery of Notices to the Company or the Transfer Agent; Receipt of Notices Whenever this Article Fourth requires notice, written notice or instructions by Class A Shareholders, Class B Shareholders or Class C Shareholders to be given to the Company, such notice or instructions shall be given by email to an officer of the Company at each of the email addresses provided by the Company to the Class A Shareholders, Class B Shareholders and Class C Shareholders in connection therewith. Whenever this Article Fourth requires notice, written notice or instructions by Class A Shareholders, Class B Shareholders or Class C Shareholders, or by the Company, to be given to the Transfer Agent, such notice or instructions shall be given by email to the Transfer Agent at the email address provided by the Transfer Agent to the Class A Exhibit 3.1 Shareholders, Class B Shareholders and Class C Shareholders and the Company in connection therewith. Any other notices or written notices to be delivered to the Company under this Certificate of Incorporation shall be addressed to an officer of the Company at the Company’s principal place of business. Any notices or instructions given by email shall be considered received on the same day if sent to the email addresses provided by the Company or the Transfer Agent, as applicable, prior to 4:00 p.m. (Central Prevailing Time) on a Business Day, and if not, shall be considered received on the recipient’s next Business Day; provided, that Change of Control Notices and Change of Control Objection Notices shall be delivered in accordance with Section D.1(e)(iii) of this Article Fourth. J. Delivery of Notices to Stockholders; Receipt of Notices Whenever this Certificate of Incorporation requires notice, written notice or instructions to be given to any Class A Shareholders, Class B Shareholders or Class C Shareholders, such notice or instructions shall be given by email to the email address(es) provided by the applicable Class A Shareholder, Class B Shareholder or Class C Shareholder to the Company in connection therewith. Any notices or instructions given by email shall be considered received on the same day if sent to the email address(es) provided by the applicable Class A Shareholder, Class B Shareholder or Class C Shareholder prior to 4:00 p.m. (Central Prevailing Time) on a Business Day, and if not, shall be considered received on the recipient’s next Business Day; provided, that Change of Control Notices and Change of Control Objection Notices shall be delivered in accordance with Section D.1(e)(iii) of this Article Fourth. FIFTH: The name and mailing address of the incorporator of the Company is Brandy L. Treadway, c/o Weil, Gotshal & Manges LLP, 200 Crescent Court, Suite 300, Dallas, Texas 75201. SIXTH: The number of directors constituting the initial board of directors is thirteen (13) and may be adjusted as provided in the bylaws of the Company. The names and mailing addresses of the individuals who are to serve as directors until the first annual meeting of stockholders or until their successors are elected and qualified are Richard D. Kinder, C. Park Shaper, Steven J. Kean, Henry Cornell, Michael Miller, Michael C. Morgan, Kenneth A. Pontarelli, Fayez Sarofim, John Stokes, R. Baran Tekkora and Glenn A. Youngkin, 500 Dallas Street, Suite 1000, Houston, Texas 77002. SEVENTH: Directors of the Company need not be elected by written ballot unless the bylaws of the Company otherwise provide. EIGHTH: In furtherance of, and not in limitation of, the powers conferred by statute, the board of directors of the Company is expressly authorized to adopt, amend, and repeal the bylaws of the Company or adopt new bylaws without any action on the part of the stockholders, in each case subject to the requirements and procedures, if any, set forth in the bylaws of the Company; provided that any bylaw adopted or amended by the board of directors, and any powers thereby conferred, may be amended, altered or repealed by the stockholders. Any amendment or repeal of the bylaws of the Company (or adoption of new bylaws) by action of the stockholders Exhibit 3.1 must be approved by the vote of shares representing at least entitled to vote for the election of directors. of the voting power of all shares NINTH: Indemnification. A. The Company shall indemnify any individual who was, is, or is threatened to be made a party to a proceeding (as hereinafter defined) by reason of the fact that he or she (a) is or was a director or officer of the Company or (b) while a director or officer of the Company, is or was serving at the request of the Company as a director, officer, partner, manager, venturer, proprietor, trustee, employee, agent, or similar function of another foreign or domestic corporation, partnership, joint venture, limited liability company, sole proprietorship, trust, employee benefit plan, or other enterprise, at any time during which this Certificate of Incorporation is in effect (whether or not such individual continues to serve in such capacity at the time any indemnification or advancement of expenses pursuant hereto is sought or at the time any proceeding relating thereto exists or is brought), and whether the basis of such proceeding is alleged action in an official capacity as a director or officer, or in such other capacity while serving as an a director or officer, to the fullest extent permitted under the DGCL, as the same exists or may hereafter be amended or modified from time to time (but, in the case of any such amendment or modification, only to the extent that such amendment or modification permits the Company to provide greater indemnification rights than said law permitted the Company to provide prior to such amendment or modification) against all expense, liability and loss (including attorney’s fees, judgments, fines, ERISA excise taxes or penalties and amounts paid in settlement) incurred or suffered by such individual in connection therewith. Such indemnification shall continue as to an individual who has ceased to be a director or officer and shall inure to the benefit of his or her heirs, executors and administrators. B. The indemnification permitted by this Article Ninth shall be a contract right and as such shall run from the Company (and any successor of the Company by operation of law or otherwise) to the benefit of any director or officer who is elected and accepts the position of director or officer of the Company or elects to continue to serve as a director or officer of the Company while this Article Ninth is in effect. Any repeal or amendment of this Article Ninth shall be prospective only and shall not limit the rights of any such director or officer or the obligations of the Company with respect to any claim arising from or related to the services of such director or officer in any of the foregoing capacities prior to any such repeal or amendment to this Article Ninth. C. To obtain indemnification under this Certificate of Incorporation, a claimant shall submit to the Company a written request, including therein or therewith such documentation and information as is reasonably available to the claimant and is reasonably necessary to determine whether and to what extent the claimant is entitled to indemnification. Upon written request by a claimant for indemnification, a determination, if required by applicable law, with respect to the claimant’s entitlement thereto shall be made as follows: (1) if requested by the claimant, by Independent Counsel (as hereinafter defined), or (2) if no request is made by the claimant for a determination by Independent Counsel, (i) by the board of directors by a majority vote of a quorum of the board of directors consisting of Disinterested Directors (as hereinafter defined) or by a committee of Disinterested Directors appointed by a majority vote of the board of directors, or (ii) if a quorum of the board of directors consisting of Disinterested Directors or a committee of Exhibit 3.1 Disinterested Directors is not obtainable or, even if obtainable, such quorum or committee of Disinterested Directors so directs, by Independent Counsel in a written opinion to the board of directors, a copy of which shall be delivered to the claimant, or (iii) if a quorum of Disinterested Directors or a committee of Disinterested Directors so directs, by a majority vote of the stockholders of the Company. In the event the determination of entitlement to indemnification is to be made by Independent Counsel, the Independent Counsel shall be selected by the claimant (subject to the consent of the board of directors by a majority vote, not to be unreasonably withheld or delayed) unless the claimant shall request that such selection be made by the board of directors by a majority vote. If it is so determined that the claimant is entitled to indemnification, payment to the claimant shall be made within ten (10) calendar days after such determination. A “Disinterested Director” means a director of the Company who is not and was not a party to the matter in respect of which indemnification is sought by the claimant. An “Independent Counsel” means a law firm, a member of a law firm, or an independent practitioner, that is experienced in matters of corporation law and shall include any individual who, under the applicable standards of professional conduct then prevailing, would not have a conflict of interest in representing either the Company or the claimant in an action to determine the claimant’s rights under this Certificate of Incorporation. D. A claimant shall have the right to be paid by the Company expenses (including attorney’s fees) incurred in defending any such proceeding in advance of its final disposition to the maximum extent permitted under the DGCL, as the same exists or may hereafter be amended or modified, only to the extent that such amendment or modification permits the Company to provide greater rights to advancement of expenses than said law permitted the Company to provide prior to such amendment or modification, upon receipt of any undertaking by or on behalf of such director or officer to repay such amount if it shall ultimately be determined that such director or officer is not entitled to be indemnified by the Company against such expenses as authorized by this Article Ninth, if such undertaking is required by the DGCL. Such advances shall be paid by the Company within twenty (20) calendar days after the receipt by the Company of a statement or statements from the claimant requesting such advance or advances from time to time (including such undertaking if required by the DGCL), and shall not require any action by the board of directors. The board of directors, by majority vote, may authorize the Company's counsel to represent such director or officer in any such proceeding, whether or not the Company is a party to such proceeding. E. If a claim for indemnification is not paid in full by the Company within sixty (60) calendar days after a written claim has been received by the Company, or if a claim for advancement of expenses is not paid in full by the Company within twenty (20) calendar days after a written claim has been received by the Company, the claimant may at any time thereafter bring suit against the Company to recover the unpaid amount of the claim, and if successful in whole or in part, the claimant shall also be entitled to be paid the expenses of prosecuting such claim to the fullest extent permitted by law. In any such suit: (1) It shall be a defense to any such action that such indemnification or advancement of costs of defense are not permitted under the DGCL, but the burden of proving such defense shall be on the Company. Exhibit 3.1 (2) The termination of any action, suit or proceeding by judgment, order, settlement, conviction, or upon a plea of nolo contendere or its equivalent, shall not, of itself, create a presumption that the individual did not act in good faith and in a manner which he or she reasonably believed to be in or not opposed to the best interests of the Company, and, with respect to any criminal action or proceeding, had reasonable cause to believe that his or her conduct was unlawful. (3) Neither the failure of the Company (including its board of directors or any committee thereof, Independent Counsel, or stockholders) to have made its determination prior to the commencement of such action that indemnification of the claimant is permissible in the circumstances nor an actual determination by the Company (including its board of directors or any committee thereof, Independent Counsel, or stockholders) that such indemnification is not permissible shall be a defense to the action or create a presumption that such indemnification is not permissible. (4) If a determination shall have been made pursuant to Section C of this Article Ninth that the indemnitee is entitled to indemnification, the Company shall be bound by such determination in any judicial proceeding commenced pursuant to this Section E. To the fullest extent permitted by law, the Company shall be precluded from asserting in any judicial proceeding commenced pursuant to this Section E that the procedures and presumptions of this Certificate of Incorporation are not valid, binding and enforceable and shall stipulate in such proceeding that the Company is bound by all the provisions of this Certificate of Incorporation. F. Non-Exclusive Remedy. (1) The rights conferred under this Article Ninth shall not be exclusive of any other right that any individual may have or hereafter acquire under any statute, bylaw, resolution of stockholders or directors, agreement, or otherwise and shall continue as to an individual who has ceased to be a director, officer, employee or agent, as applicable, and shall inure to the benefit of his or her heirs, executors, administrators, and personal representatives. (2) With respect to any indemnification obligations of the Company conferred under this Article Ninth, the Company hereby acknowledges and agrees (i) that it is the indemnitor of first resort with respect to all indemnification obligations of the Company pursuant to Section A of this Article Ninth (i.e., its obligations to an applicable indemnitee are primary and any obligation of the Investor Shareholders and their Affiliates (collectively, the “Fund Indemnitors”) to advance expenses or to provide indemnification and/or insurance for the same expenses or liabilities incurred by such indemnitee are secondary) and (ii) that it irrevocably waives, relinquishes and releases the Fund Indemnitors from any and all claims against the Fund Indemnitors for contribution, subrogation or any other recovery of any kind in respect thereof to the fullest extent permitted by law. G. The Company may additionally indemnify or provide advancement of expenses to any employee or agent of the Company or any other person to the fullest extent permitted by law. H. As used in this Article Ninth, the term “proceeding” means any threatened, pending, or completed action, suit, or proceeding, whether civil, criminal, administrative, arbitrative, or Exhibit 3.1 investigative, any appeal in such an action, suit, or proceeding, and any inquiry or investigation that could lead to such an action, suit, or proceeding. I. The Company may adopt bylaws or enter into agreements with such individuals for the purpose of providing for indemnification and/or the advancement of expenses as provided in this Article Ninth. J. The Company shall have power to purchase and maintain insurance on behalf of any individual who is or was a director, officer, employee or agent of the Company, or is or was serving at the request of the Company as a director, officer, partner, manager, venturer, proprietor, trustee, employee, agent, or similar function of another foreign or domestic corporation, partnership, joint venture, limited liability company, sole proprietorship, trust, employee benefit plan, or other enterprise, against any liability asserted against such individual and incurred by such individual in any such capacity, or arising out of such individual’s status as such, whether or not the Company would have the power to indemnify such individual against such liability under the provisions of this Article Ninth or otherwise. To the extent that the Company maintains any policy or policies providing for such insurance, each indemnitee to which rights to indemnification have been granted in this Article Ninth in its capacity as a director or officer, shall be covered by such policy or policies in accordance with its or their terms to the maximum extent of the coverage thereunder for any such indemnitee. TENTH: A director of the Company shall not be personally liable to the Company or its stockholders for monetary damages for breach of fiduciary duty as a director, except for liability (a) for any breach of the director’s duty of loyalty to the Company or its stockholders, (b) for acts or omissions not in good faith or that involve intentional misconduct or knowing violation of law, (c) under Section 174 of the DGCL, or (d) for any transaction from which the director derived an improper personal benefit. Neither amendment nor repeal of this Article Tenth nor the adoption of any provision of this Certificate of Incorporation inconsistent with this Article Tenth shall eliminate or reduce the effect of this Article Tenth in respect of any matter occurring, or any cause of action, suit or claim that, but for this Article Tenth, would accrue or arise, prior to such amendment, repeal or adoption of any inconsistent provision. In addition to the circumstances in which a director of the Company is not personally liable as set forth in the foregoing provisions of this Article Tenth, a director shall not be liable to the Company or its stockholders to such further extent as permitted by any law hereafter enacted, including without limitation any subsequent amendment to the DGCL. ELEVENTH: To the fullest extent permitted by applicable law, the Company, on behalf of itself and its wholly-owned subsidiaries, renounces any interest or expectancy of the Company and its wholly-owned subsidiaries in, or in being offered an opportunity to participate in, business opportunities (including, without limitation, any business activities or lines of business that are the same as or similar to those pursued by, or competitive with, the Company or any of its subsidiaries or any dealings with customers or clients of the Company or any of its subsidiaries) that are from time to time presented to an Investor Shareholder (or any director nominated by such Investor Shareholder) while such Investor Shareholder is a holder of Class A Shares or Related Shares, or any of its managers, officers, directors, agents, stockholders, members, partners, Affiliates and subsidiaries (other than the Company and its wholly-owned subsidiaries) (each, an “Investor Exhibit 3.1 Party”), even if the opportunity is one that the Company or its wholly-owned subsidiaries might reasonably be deemed to have pursued or had the ability or desire to pursue if granted the opportunity to do so, and each such Investor Party (and any director nominated by such Investor Party) shall have no duty to communicate or offer such business opportunity to the Company or any of its wholly-owned subsidiaries and, to the fullest extent permitted by applicable law, shall not be liable to the Company or any of its wholly-owned subsidiaries for breach of any fiduciary or other duty, as a director or otherwise, by reason of the fact that such Investor Party pursues or acquires such business opportunity, directs such business opportunity to another Person or fails to present such business opportunity, or information regarding such business opportunity, to the Company or its wholly-owned subsidiaries. Notwithstanding the foregoing, an Investor Party who is a director of the Company or one of its wholly-owned subsidiaries and who is offered a business opportunity solely in such capacity (a “Directed Opportunity”) shall be obligated to communicate such Directed Opportunity to the Company, provided, however, that all of the protections of this Article Eleventh shall otherwise apply to the Investor Party with respect to such Directed Opportunity, including, without limitation, the ability of the Investor Party to pursue, or acquire such Directed Opportunity or direct such Directed Opportunity to another Person; provided, further, that the provisions of this Article Eleventh shall in no way limit any confidentiality obligations of a director existing under applicable law. For clarification, neither the Company nor any or its Subsidiaries renounces or waives its ability to pursue, compete for, acquire or otherwise undertake any opportunity, and the Company and its Subsidiaries may do so, whether or not such opportunity is presented or offered to them or to any other Person, including those mentioned above. Neither the alteration, amendment or repeal of this Article Eleventh, nor the adoption of any provision(s) of this Certificate of Incorporation inconsistent with this Article Eleventh shall eliminate or reduce the effect of this Article Eleventh in respect of any matter occurring, or any cause of action, suit or claim that, but for this Article Eleventh, would accrue or arise, prior to such alteration, amendment, repeal or adoption. The undersigned, for the purpose of forming the Company under the laws of the State of Delaware, does make, file, and record this Certificate of Incorporation and does certify that this is the act and deed of the undersigned and that the facts stated herein are true and, accordingly, hereunto sets its hand on this 10th day of February, 2011. By: Name: /s/ Brandy L. Treadway Brandy L. Treadway INCORPORATOR Exhibit 3.1 CERTIFICATE OF AMENDMENT OF CERTIFICATE OF INCORPORATION OF KINDER MORGAN, INC. November 21, 2014 Kinder Morgan, Inc., a corporation organized and existing under the laws of the State of Delaware (the “Company”), hereby certifies as follows: 1. The name of the Company is Kinder Morgan, Inc. 2. The Board of Directors of the Company, acting in accordance with the provisions of Sections 141 and 242 of the General Corporation Law of the State of Delaware, adopted resolutions to amend the Certificate of Incorporation of the Company filed with the Secretary of State of the State of Delaware on February 10, 2011 (the “Certificate of Incorporation”), by amending Section A of Article FOURTH as set forth in paragraph 3 below. 3. The first sentence of Section A of Article FOURTH of the Certificate of Incorporation from the beginning of the sentence through the end of clause (1) is hereby amended to read as follows: “A. Authorized Shares The total number of shares of capital stock which the Company shall have authority to issue is 4,819,462,927 shares, of which 10,000,000 shares shall be preferred stock, par value $0.01 per share (the “Preferred Stock”), and 4,809,462,927 shares shall be common stock, par value $0.01 per share (the “Common Stock”), consisting of: (1) 4,000,000,000 shares of Class P Common Stock (the “Class P Common Stock”);” 4. This Certificate of Amendment was submitted to the stockholders of the Company and was approved by the stockholders of the Company in accordance with Sections 222 and 242 of the General Corporation Law of the State of Delaware. 5. This Certificate of Amendment shall become effective immediately upon filing with the Secretary of State of the State of Delaware. IN WITNESS WHEREOF, the undersigned has duly executed this Certificate of Amendment of the Certificate of Incorporation as of the date first written above. KINDER MORGAN, INC. By: /s/ David R. DeVeau David R. DeVeau Vice President Exhibit 3.2 AMENDED AND RESTATED BYLAWS OF KINDER MORGAN, INC. (a Delaware Corporation) PREAMBLE These Amended and Restated Bylaws (“Bylaws”) are subject to, and governed by, the General Corporation Law of the State of Delaware (the “DGCL”) and the certificate of incorporation of Kinder Morgan, Inc., a Delaware corporation (the “Company”). In the event of a direct conflict between the provisions of these Bylaws and the mandatory provisions of the DGCL or the provisions of the certificate of incorporation of the Company (as amended from time to time, the “Charter”), such provisions of the DGCL or the Charter, as the case may be, shall control. ARTICLE I Offices 1.1 Registered Office and Agent. The registered office and registered agent of the Company shall be as designated from time to time by the appropriate filing by the Company in the office of the Secretary of State of the State of Delaware. 1.2 Other Offices. The Company may also have offices at such other places, both within and without the State of Delaware, as the board of directors, by a Majority Vote, may from time to time determine or as the business of the Company may require. ARTICLE II Meetings of Stockholders 2.1 Annual Meeting. An annual meeting of stockholders of the Company shall be held each calendar year on such date and at such time as shall be designated from time to time by a Majority Vote of the board of directors and stated in the notice of the meeting. At such meeting, the stockholders shall elect directors and transact such other business as may properly be brought before the meeting. 2.2 Special Meeting. A special meeting of the stockholders may be called at any time by the Chairman of the Board, the Chief Executive Officer, the President, or the board of directors by a Majority Vote, and shall be called by the Chairman of the Board, Chief Executive Officer or President at the request in writing of the stockholders of record of not less than ten percent (10%) Exhibit 3.2 of all voting power entitled to vote at such meeting. A special meeting shall be held on such date and at such time as shall be designated by the Person(s) calling the meeting and stated in the notice of the meeting. Only such business shall be transacted at a special meeting as may be stated or indicated in the notice of such meeting. 2.3 Place of Meetings. An annual meeting of stockholders may be held at any place within or without the State of Delaware designated by a Majority Vote of the board of directors. A special meeting of stockholders may be held at any place within or without the State of Delaware designated in the notice of the meeting by a Majority Vote of the board of directors. Meetings of stockholders shall be held at the principal office of the Company unless another place is designated for meetings in the notice of the meeting or in the manner provided herein. 2.4 Notice. Notice stating the place, day, and time of each meeting of the stockholders and, in case of a special meeting, the purpose or purposes for which the special meeting is called shall be given not less than ten (10) nor more than sixty (60) days before the date of the meeting, by or at the direction of the President, the Secretary, or the officer or Person(s) calling the meeting, to each stockholder of record entitled to vote at such meeting. If such notice is to be sent by mail, it shall be directed to such stockholder at his address as it appears on the records of the Company. Without limiting the manner by which notice otherwise may be given effectively to stockholders, notice of meetings may be given to stockholders by means of electronic transmission in accordance with applicable law. 2.5 Voting List. At least ten (10) days before each meeting of stockholders, the Secretary or other officer of the Company who has charge of the Company’s stock ledger, either directly or through another officer appointed by him or through a transfer agent appointed by a Majority Vote of the board of directors, shall prepare a complete list of stockholders entitled to vote thereat, arranged in alphabetical order and showing the address of each stockholder and number of shares registered in the name of each stockholder. For a period of ten days prior to such meeting, such list shall be kept on file at the principal place of business of the Company and shall be open to examination by any stockholder during ordinary business hours. Such list shall be produced at such meeting and kept at the meeting at all times during such meeting and may be inspected by any stockholder who is present. 2.6 Quorum. The holders of shares representing a majority of the voting power of the outstanding shares entitled to vote, present in person or by proxy, shall constitute a quorum at any meeting of stockholders, except as otherwise provided by law, the Charter, or these Bylaws. If a quorum shall not be present, in person or by proxy, at any meeting of stockholders, the stockholders entitled to vote thereat who are present, in person or by proxy, or, if no stockholder entitled to vote is present, any officer of the Company, may adjourn the meeting from time to time, without notice other than announcement at the meeting (unless the board of directors, by a Majority Vote, after such adjournment, fixes a new record date for the adjourned meeting), until a quorum shall be present, in person or by proxy. At any adjourned meeting at which a quorum shall be present, in person or by proxy, any business may be transacted that may have been transacted at the original meeting had a quorum been present; provided, however, that if the adjournment is for more than 30 days or if after the adjournment a new record date is fixed for the adjourned meeting, a notice Exhibit 3.2 of the adjourned meeting shall be given to each stockholder of record entitled to vote at the adjourned meeting. 2.7 Required Vote; Withdrawal of Quorum. After a quorum is present at any meeting, the affirmative vote of the holders of shares representing at least a majority of the voting power of the outstanding shares entitled to vote who are present, in person or by proxy, shall decide any question brought before such meeting, unless the question is one on which, by express provision of statute, the Charter, or these Bylaws, a different vote is required, in which case such express provision shall govern and control the decision of such question. The stockholders present at a duly constituted meeting may continue to transact business until adjournment, notwithstanding the withdrawal of enough stockholders to leave less than a quorum. 2.8 Method of Voting; Proxies. Each outstanding share having voting power shall be entitled to the number of votes specified in the Charter. Elections of directors need not be by written ballot. Stockholders shall have no right to cumulate votes in the elections of directors. At any meeting of stockholders, every stockholder having the right to vote may vote either in person or by a proxy executed in the manner provided by law by the stockholder or by his duly authorized attorney in fact. Each such proxy shall be filed with the Secretary of the Company before or at the time of the meeting. No proxy shall be valid after three (3) years from the date of its execution, unless otherwise provided in the proxy. If no date is stated in a proxy, such proxy shall be presumed, only for purposes of determining whether three (3) years have passed since its execution, to have been executed on the date it was delivered to or filed with the Secretary of the Company. Each proxy shall be revocable unless expressly provided therein to be irrevocable and coupled with an interest sufficient in law to support an irrevocable power or unless otherwise made irrevocable by law. 2.9 Record Date. For the purpose of determining stockholders entitled to notice of or to vote at any meeting of stockholders, or any adjournment thereof, or entitled to receive payment of any dividend or other distribution or allotment of any rights, or entitled to exercise any rights in respect of any change, conversion, or exchange of stock or for the purpose of any other lawful action, the board of directors may, by a Majority Vote, fix a record date, which record date shall not precede the date upon which the resolution fixing the record date is adopted by the board of directors for any such determination of stockholders, such date in any case to be not more than sixty (60) days and not less than ten (10) days prior to such meeting nor more than sixty (60) days prior to any other action. If no record date is fixed: (a) The record date for determining stockholders entitled to notice of or to vote at a meeting of stockholders shall be at the close of business on the day next preceding the day on which notice is given. (b) The record date for determining stockholders for any other purpose shall be at the close of business on the day on which the board of directors adopts the resolution relating thereto. A determination of stockholders of record entitled to notice of or to vote at a meeting of stockholders shall apply to any adjournment of the meeting; provided, however, that the board of directors may fix a new record date for the adjourned meeting. (c) Exhibit 3.2 2.10 Conduct of Meeting. The Chairman of the Board, if such office has been filled, and, if not or if the Chairman of the Board is absent or otherwise unable to act, the Chief Executive Officer, shall preside at all meetings of stockholders and may adopt rules and regulations for the conduct of the meeting. The Secretary shall keep the records of each meeting of stockholders. In the absence or inability to act of any such officer, such officer’s duties shall be performed by the officer given the authority to act for such absent or non-acting officer under these Bylaws or by some person appointed at the meeting by a majority of the directors present at such meeting. 2.11 Inspectors. To the fullest extent required by law, the corporation shall, in advance of any meeting of stockholders, by a Majority Vote, appoint one (1) or more inspectors to act at such meeting or any adjournment thereof. If any of the inspectors so appointed shall fail to appear or act or if inspectors shall not have been appointed, the chairman of the meeting shall appoint one or more inspectors. Each inspector, before entering upon the discharge of his duties, shall take and sign an oath faithfully to execute the duties of inspector at such meeting with strict impartiality and according to the best of his ability. The inspectors shall determine the number of shares of capital stock of the Company outstanding and the voting power of each, the number of shares represented at the meeting, the existence of a quorum, and the validity and effect of proxies and shall receive votes, ballots, or consents, hear and determine all challenges and questions arising in connection with the right to vote, count and tabulate all votes, ballots, or consents, determine the results, and do such acts as are proper to conduct the election or vote with fairness to all stockholders. The inspectors shall make a report in writing of any challenge, request, or matter determined by them and shall execute a certificate of any fact found by them. No director or candidate for the office of director shall act as an inspector of an election of directors. Inspectors need not be stockholders. 2.12 Advance Notice of Stockholder Nominations and Proposals. (a) Timely Notice. At a meeting of the stockholders, only such nominations of persons for the election of directors and such other business shall be conducted as shall have been properly brought before the meeting. To be properly brought before an annual meeting, nominations or such other business must be: (i) specified in the Company’s notice of meeting, (ii) otherwise properly brought before the meeting by or at the direction of the board of directors, by a Majority Vote, or any committee thereof, or (iii) otherwise properly brought before an annual meeting by a stockholder who is a stockholder of record of the Company at the time such notice of meeting is given, who is entitled to vote at the meeting and who complies with the procedures set forth in this Section 2.12. To be properly brought before a special meeting, nominations or such other business must be specified in the Company’s notice of meeting. In addition, any proposal of business (other than the nomination of persons for election to the board of directors) must be a proper matter for stockholder action. For business (including, but not limited to, director nominations) to be properly brought before an annual meeting by a stockholder, the stockholder or stockholders of record intending to propose the business (the “Proposing Stockholder”) must have given timely notice thereof pursuant to this Section 2.12(a), and either Section 2.12(b) or Section 2.12(c) below, as applicable, in writing to the Secretary of the Company even if such matter is already the subject of (1) any notice to the stockholders from the board of directors or (2) any press release of the Company reported by a national news service or filed by the Company with the Securities and Exchange Commission (a “Public Disclosure”). To be timely, a Proposing Stockholder’s notice must be addressed to the Exhibit 3.2 Secretary of the Company and delivered to or mailed and received at the principal place of business of the Company not later than the close of business on the 90th day, nor earlier than the close of business on the one hundred twentieth (120th) day in advance of the anniversary of the previous year’s annual meeting; provided, however, that with respect to the Company’s first annual meeting or in the event that the date of the annual meeting is advanced by more than thirty (30) days or delayed by more than seventy (70) days from such anniversary date, notice by the Proposing Stockholder to be timely must be so delivered not later than the close of business on the later of the ninetieth (90th) day prior to such annual meeting or the tenth (10th) day following the day on which public announcement of the date of such meeting is first made. In no event shall the Public Disclosure of an adjournment or postponement of an annual meeting commence a new notice time period (or extend any notice time period). (b) Stockholder Nominations. For the nomination of any person or persons for election to the board of directors, a Proposing Stockholder’s notice to the Secretary of the Company shall set forth (i) the name, age, business address and residence address of each nominee proposed in such notice, (ii) the principal occupation or employment of each such nominee, (iii) the number, class and series of shares of capital stock of the Company which are owned of record and beneficially by each such nominee (if any), (iv) such other information concerning each such nominee as would be required to be disclosed in a proxy statement soliciting proxies for the election of such nominee as a director in an election contest (even if an election contest is not involved), or that is otherwise required to be disclosed, under the rules of the Securities and Exchange Commission, (v) the consent of the nominee to being named in the proxy statement as a nominee and to serving as a director if elected, and (vi) as to the Proposing Stockholder: (A) the name and address of the Proposing Stockholder as they appear on the Company’s books and of the beneficial owner, if any, on whose behalf the nomination is being made, (B) the number, class and series of shares of the Company which are owned by the Proposing Stockholder (beneficially and of record) and owned by the beneficial owner, if any, on whose behalf the nomination is being made, as of the date of the Proposing Stockholder’s notice, and a representation that the Proposing Stockholder will notify the Company in writing of the number, class and series of such shares owned of record and beneficially as of the record date for the meeting promptly following the later of the record date or the date notice of the record date is first publicly disclosed, (C) a description of any agreement, arrangement or understanding with respect to such nomination between or among the Proposing Stockholder and any of its affiliates or associates, and any others (including their names) acting in concert with any of the foregoing, and a representation that the Proposing Stockholder will notify the Company in writing of any such agreement, arrangement or understanding in effect as of the record date for the meeting promptly following the later of the record date or the date notice of the record date is first publicly disclosed, (D) a description of any agreement, arrangement or understanding (including any derivative or short positions, profit interests, options, hedging transactions, and borrowed or loaned shares) that has been entered into as of the date of the Proposing Stockholder’s notice by, or on behalf of, the Proposing Stockholder or any of its affiliates or associates, the effect or intent of which is to mitigate loss to, manage risk or benefit of share price changes for, or increase or decrease the voting power of the Proposing Stockholder or any of its affiliates or associates with respect to shares of stock of the Company, and a representation that the Proposing Stockholder will notify the Company in writing of any such agreement, arrangement or understanding in effect as of the record date for the meeting promptly following the later of the record date or the date notice Exhibit 3.2 of the record date is first publicly disclosed, (E) a representation that the Proposing Stockholder is a holder of record of shares of the Company entitled to vote at the meeting and intends to appear in person or by proxy at the meeting to nominate the person or persons specified in the notice, and (F) a representation whether the Proposing Stockholder intends to deliver a proxy statement and/ or form of proxy to holders of a majority of the total voting power and/or otherwise to solicit proxies from stockholders in support of the nomination. The Company may require any proposed nominee to furnish such other information as it may reasonably require to determine the eligibility of such proposed nominee to serve as an independent director of the Company or that could be material to a reasonable stockholder’s understanding of the independence, or lack thereof, of such nominee. No nominee of a stockholder (or stockholders) who has (or have) failed to comply with the requirements of this Section 2.12(b) shall be eligible to serve as a director of the Company. (c) Other Stockholder Proposals. For all business other than director nominations, a Proposing Stockholder’s notice to the Secretary of the Company shall set forth as to each matter the Proposing Stockholder proposes to bring before the annual meeting: (i) a brief description of the business desired to be brought before the annual meeting and the reasons for conducting such business at the annual meeting, (ii) any other information relating to such stockholder and beneficial owner, if any, on whose behalf the proposal is being made, required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for the proposal and pursuant to and in accordance with Section 14(a) of the Exchange Act and (iii) the information required by Section 2.12(b)(vi) above. (d) Effect of Noncompliance. Notwithstanding anything in these Bylaws to the contrary: (i) no business shall be conducted at any annual meeting except in accordance with the procedures set forth in this Section 2.12, and (ii) unless otherwise required by law, if a Proposing Stockholder intending to propose business at an annual meeting pursuant to this Section 2.12 does not provide the additional information required under the representations in Sections 2.12(b)(vi)(B), (C) and (D) to the Company promptly following the later of the record date or the date notice of the record date is first publicly disclosed, or the Proposing Stockholder (or a qualified representative of the Proposing Stockholder) does not appear at the meeting to present the proposed business, such business shall not be transacted, notwithstanding that proxies in respect of such business may have been received by the Company. The requirements of this Section 2.12 are included to provide the Company notice of a stockholder’s intention to bring business before an annual meeting and shall in no event be construed as imposing upon any stockholder the requirement to seek approval from the Company as a condition precedent to bringing any such business before an annual meeting. 2.13 No Actions Without Meeting. Any vote or similar action required or permitted to be taken by the holders of Class P Shares of the Company must be effected at a duly called annual or special meeting of holders of shares of common stock of the Company entitled to vote or take similar action with respect to a particular corporate action, including the election of directors, and may not be effected by any consent in writing by such holders of shares of common stock. The holders of Class A Shares, Class B Shares and Class C Shares may, in addition to taking action at a meeting, effect any action required or permitted to be taken by the holders of Class A Shares, Class B Shares or Class C Shares, as applicable, by consent in writing by the holders of such Class A Shares, Class B Shares or Class C Shares, as applicable. Exhibit 3.2 ARTICLE III Directors 3.1 Management. The business and property of the Company shall be managed by the board of directors. Subject to the restrictions imposed by law, the Charter, or these Bylaws, the board of directors may exercise all the powers of the Company. 3.2 Number; Qualification; Election; Term. (a) The number of directors shall, as of the effective date of these Bylaws, be fifteen (15) and may be increased in accordance with Section 3.3 of the Shareholders Agreement or decreased in accordance with Section 3.1(a) of the Shareholders Agreement. After the termination of Section 3.1 of the Shareholders Agreement with respect to all Shareholders, the number of directors shall be determined by resolution of a majority of the board of directors. (b) Except as otherwise required by law, the Charter or these Bylaws, the directors shall be elected at an annual meeting of stockholders at which a quorum is present; provided, that a special meeting may be called for the purpose of electing directors in accordance with Section 3.1(d) of the Shareholders Agreement. Directors shall be elected by a plurality of the votes of the shares present in person or represented by proxy and entitled to vote on the election of directors. Each director so chosen shall hold office until the first annual meeting of stockholders held after his election and until his successor is elected and qualified or, if earlier, until his death, resignation, or removal from office. None of the directors need be a stockholder of the Company or a resident of the State of Delaware. Each director must have attained the age of majority. 3.3 Change in Number. No decrease in the number of directors constituting the entire board of directors shall have the effect of shortening the term of any incumbent director. 3.4 Removal. Except as otherwise provided in the Charter or these Bylaws, at any meeting of stockholders called expressly for that purpose, any director or the entire board of directors may be removed, with or without cause, by a vote of the holders of shares representing a majority of the Total Voting Power. 3.5 Vacancies. Vacancies on the board of directors, however resulting, may be filled by the affirmative vote of a majority of the directors then in office, even if less than a quorum, or by the sole remaining director, and each director so chosen shall hold office until the first annual meeting of stockholders held after his election and until his successor is elected and qualified or, if earlier, until his death, resignation, or removal from office. However, at any time prior to the termination of Section 3.1 of the Shareholders Agreement with respect to all Shareholders, such vacancies shall be filled only with nominees chosen to fill such vacancies in accordance with the provisions of the Shareholders Agreement. Exhibit 3.2 3.6 Meetings of Directors. The directors may hold their meetings and may have an office and keep the books of the Company, except as otherwise provided by law, in such place or places within or without the State of Delaware as the board of directors, by a Majority Vote, may from time to time determine or as shall be specified in the notice of such meeting or duly executed waiver of notice of such meeting. 3.7 First Meeting. Each newly-elected board of directors may hold its first meeting for the purpose of organization and the transaction of business, if a quorum is present, immediately after and at the same place as the annual meeting of stockholders, and no notice of such meeting shall be necessary. 3.8 Election of Officers. At the first meeting of the board of directors after each annual meeting of stockholders at which a quorum shall be present, the board of directors shall elect the officers (other than the Chief Executive Officer) of the Company. The Chief Executive Officer theretofore serving shall be automatically reelected at such meeting without any necessary vote, subject to the provisions of Section 3.12(B)(1). New officers also may be elected and any vacancies filled at any meeting of the board of directors. 3.9 Regular Meetings. Regular meetings of the board of directors shall be held at such times and places as shall be designated from time to time by resolution of the board of directors by a Majority Vote. Notice of such regular meetings shall not be required. 3.10 Special Meetings. Special meetings of the board of directors shall be held whenever called by the Chairman of the Board, the Chief Executive Officer, or the President, or by at least two (2) directors, acting jointly. 3.11 Notice. The Secretary shall give notice of each special meeting to each director at least 24 hours before the meeting. Notice of any such meeting need not be given to any director who shall, either before or after the meeting, submit a signed waiver of notice or who shall attend such meeting without protesting, prior to or at its commencement, the lack of notice to him. Neither the business to be transacted at, nor the purpose of, any regular or special meeting of the board of directors need be specified in the notice or waiver of notice of such meeting. 3.12 Quorum; Majority Vote. At all meetings of the board of directors, a majority of the directors fixed in the manner provided in these Bylaws shall constitute a quorum for the transaction of business. If at any meeting of the board of directors there be less than a quorum present, a majority of those present or any director solely present may adjourn the meeting from time to time without further notice to the fullest extent permitted by law. The affirmative vote of a majority of the directors present at a meeting at which a quorum is in attendance shall be the act of the board of directors subject to the following exceptions: (A) the number otherwise required if the act of a greater number is required by law, the Charter, or these Bylaws; (B) the following actions shall require approval of the number of directors constituting a majority of all directors plus one (1): (1) termination of the Chief Executive Officer other than for “cause” (or other than for “Cause,” if the Chief Executive Officer is Kinder) and any selection of a replacement for a terminated Chief Executive Officer and (2) any determination as to the value of non-cash dividends; (C) the determination of certain “black- Exhibit 3.2 out periods” shall be determined in accordance with the definition of “Blackout Period” in the Shareholders Agreement; (D) the decisions to seek injunctive relief pursuant to the last paragraph of Section 3.6(f) of the Shareholders Agreement shall be determined in accordance with the last paragraph of Section 3.6(f) of the Shareholders Agreement; (E) the decisions with respect to the distribution of property in the Class B Trust (as defined in the Shareholders Agreement) contemplated by Section 3.8(g) of the Shareholders Agreement shall be determined in accordance with Section 3.8(g) of the Shareholders Agreement; (F) the provision of a written notice by the board of directors pursuant to clause (c) or (f) of the definition of “Cause” in the Shareholders Agreement with respect to Kinder and clause (c), (d) , (g) or (h) of the definition of “Cause” in the Shareholders Agreement with respect to any person other than Kinder shall be determined in accordance with such definition in the Shareholders Agreement; (G) except as provided specifically otherwise in these Bylaws, including the final paragraph of this Section 3.12, any matter brought before the board of directors shall be decided by, and any determination, action or approval of the board of directors shall require, a Supermajority Board Vote so long as the Investor Shareholders have the right to choose at least five (5) nominees to the board of directors pursuant to Section 3.1 (b) of the Shareholders Agreement, it being understood that at all times from and after such time as Kinder ceases to be chief executive officer of any of the Company, KMGP or KMR, any action by the Company or any of its Subsidiaries in its capacity as a shareholder, member or partner of KMGP related to the determination of the identity of board members (or similar governing body) of KMGP (including removal and filling vacancies) shall constitute matters to be determined by the board of directors and require a Majority Vote; provided, that the immediately foregoing clause (beginning with “it being understood”) shall not be interpreted to prevent or prohibit such matters from being determined by the board of directors at any time by a Majority Vote; and (H) so long as the Investor Shareholders have the right to choose at least five (5) nominees to the board of directors pursuant to Section 3.1(b) of the Shareholders Agreement, any of the following with respect to the Company and each of its Subsidiaries (other than KMP, KMP’s operating partnerships, EPB, KMR or any of their respective Subsidiaries, or KMGP (solely to the extent that KMGP (x) is acting in its capacity as a holder of shares of KMR or in its capacity as General Partner pursuant to Section 1.4 of the Delegation of Control Agreement to approve any action taken by KMR, or (y) is acting in its capacity as the general partner of KMP or any of its operating partnerships to approve any matter on behalf of KMP or any of its operating partnerships (and not to the extent acting in another capacity, such as acting to amend or waive a right or obligation of KMGP (or of its direct or indirect parent entities) under any organizational document of KMP or its operating partnerships)), or KMGP Services, to the extent it is taking action related to carrying out the terms of the Employee Services Agreement, or EPGP (solely to the extent that EPGP is acting in its capacity as the general partner of EPB with respect to the business and affairs of EPB or to approve any matter on behalf of EPB (and not to the extent acting in another capacity, such as acting to amend or waive a right or obligation of EPGP (or of its direct or indirect parent entities) under any organizational document of EPB)), in each case unless specifically provided for herein) (it being understood that the dollar thresholds below shall apply to the Company and such Subsidiaries in the aggregate), in each case, shall constitute matters that are required to be brought before the board of directors and require a Supermajority Board Vote: (a) (i) Commencement of a voluntary case, proceeding or other action (x) under any existing or future law of any jurisdiction, domestic or foreign, relating to bankruptcy, insolvency, Exhibit 3.2 reorganization or relief of debtors, seeking to have an order for relief entered with respect to the Company or any such Subsidiary, or seeking to adjudicate the Company or any such Subsidiary as bankrupt or insolvent, or seeking reorganization, arrangement, adjustment, winding-up, liquidation, dissolution, composition or other relief with respect to the Company or any such Subsidiary or the Company’s or any such Subsidiary’s debts, or (y) seeking appointment of a receiver, trustee, custodian or other similar official for the Company or any such Subsidiary or for all or any substantial part of the Company’s or any such Subsidiary’s assets, or (ii) making a general assignment for the benefit of the Company’s or any such Subsidiary’s creditors; (b) Commencement of any termination, plan of liquidation or dissolution or winding- up of the business and affairs of the Company or any such Subsidiary or consent to or entry into an agreement or arrangement related to any of the foregoing; (c) Commencement, settlement or compromise of any litigation, proceeding or investigation with a cost or expected value (for any individual matter or group of related matters) of more than $50 million or payment, discharge, settlement or satisfaction of any claims, liabilities or obligations (other than obligations under contracts relating to the operation of the business of the Company and its Subsidiaries) in excess of $50 million (for any individual matter or group of related matters), other than the payment, discharge, settlement or satisfaction thereof in the ordinary course of business consistent with past practice; (d) (i) Any changes to the dividend policy of the Company adopted by the board of directors (the “Dividend Policy”) and (ii) except with respect to distributions pursuant to the Dividend Policy, declaration, setting aside for payment or payment of any dividend on, or any other distribution (including dividend or distributions of Securities or other non-cash distributions of property) in respect of, any of the Company’s shares of capital stock or otherwise making any payments to the Company’s stockholders in their capacity as such (including payments in non-cash property or Securities); (e) (i) Any amendment to or waiver or modification of any material terms of any charter, bylaws or other similar governance document of the Company or any of its Subsidiaries or controlled Affiliates (other than controlled Affiliates of KMR, KMP or EPB), including any committee charters and any corporate governance or other similar board or committee policies, or any material terms of any security issued by the Company or any of its Subsidiaries or controlled Affiliates (other than (x) changes relating to wholly-owned Subsidiaries that do not (A) reduce the Company’s ultimate control of over such Subsidiaries, (B) reduce the board of directors’ rights pursuant to this Section 3.12 and (C) have any negative effect on the Investor Shareholders, including their rights under these Bylaws, the Charter or the Shareholders Agreement or (y) any security issued by controlled Affiliates of KMR, KMP or EPB), or (ii) otherwise make any material change to the governance structure of the Company or any of its Subsidiaries or controlled Affiliates that are not required by law or rule of the national stock exchange on which the Class P Shares are then listed (other than (x) changes relating to wholly-owned Subsidiaries that do not (A) reduce the Company’s ultimate control of over such Subsidiaries, (B) reduce the board of directors’ rights pursuant to this Section 3.12, or (C) have any negative effect on the Investor Shareholders, including their rights under these Exhibit 3.2 Bylaws, the Charter or the Shareholders Agreement or (y) to the governance structure of controlled Affiliates of KMR, KMP or EPB); (f) (i) Adoption of the Company’s annual budget (the “Annual Budget”) and (ii) except as contemplated by the Annual Budget, entry into any new lines of business or engaging in transactions outside the normal lines of business of the Company or any such Subsidiary, in each case, that, in the aggregate, are expected to generate revenue in any year in excess of $50 million or to incur costs in any year in excess of $50 million; (g) Except as specifically contemplated as part of the Annual Budget: (i) Buy or sell, or commit to buy or sell, any properties or assets with values greater than $50 million in the aggregate during any Fiscal Year (as hereinafter defined), except pursuant to commodity or hedging instructions in the ordinary course of business; (ii) Approve, adopt, enter into or effect (and in the case of contracts, amend, alter or cancel), any projects, mergers, contracts (other than contracts entered into or cancelled in the ordinary course of business), consolidations, recapitalizations, reorganizations, acquisitions, divestitures, joint ventures or alliances, or any agreements or commitments relating thereto, involving a value in excess of $50 million in the aggregate in any Fiscal Year; (iii) In any Fiscal Year, make binding bids to effect acquisitions (x) with an aggregate purchase price (including the assumption of liabilities) in excess of $50 million or (y) to acquire entities reasonably expected to generate cash flow in excess of $50 million in the aggregate in any Fiscal Year; (iv) Make capital expenditures in excess of $50 million in the aggregate during any Fiscal Year; (v) Enter into leases with aggregate payment obligations in excess of $25 million annually or $50 million during the term of such leases; (vi) Incur or assume any Indebtedness or otherwise become obligated with respect to any such Indebtedness, other than amounts not in excess of $50 million in the aggregate outstanding at any given time; (vii) Mortgage or otherwise encumber or subject to any lien, any properties or assets in excess of $50 million in the aggregate at any given time; (viii) Make, sell or otherwise dispose of any investments in other companies in excess of $50 million in the aggregate in any Fiscal Year; (ix) Issue or sell any equity interest of the Company or any of its Subsidiaries or any other Securities of the Company or any of its Subsidiaries or rights convertible into, exchangeable or exercisable for, or evidencing the right to subscribe for, or any warrants or options Exhibit 3.2 to acquire, any such shares, interests, voting securities or convertible securities or split, combine, subdivide, reclassify or redeem, purchase or otherwise acquire, or propose to redeem or purchase or otherwise acquire, any shares of its stock or beneficial interests, or any other Securities of the Company or any of its Subsidiaries (except issuances or sales of the purchase obligation described in, and purchases pursuant to, the purchase provisions contained in Annex B to the limited liability company agreement of KMR and, with regard to the Company, (i) upon conversion as provided in Article Fourth of the Charter, (ii) the distribution of Class B Shares (or Class P Shares received in connection with the conversion of such Class B Shares) held by the Class B Trust (as defined in the Shareholders Agreement) in accordance with Section 3.8(g) of the Shareholders Agreement or (iii) pursuant to a benefit or compensation plan approved by a Supermajority Board Vote); (x) Make loans or advances of money or assets of the Company or any such Subsidiary if such loans and advances aggregate greater than $25 million in the aggregate at any given time, except for (i) loans between the Company and any of its wholly-owned Subsidiaries or between wholly-owned Subsidiaries of the Company and (ii) mandatory advancement of expenses required by indemnification obligations of the Company pursuant to the Charter, these Bylaws or the Shareholders Agreement; or (xi) Knowingly take any action that violates any instrument of Indebtedness or any other material agreement. (h) Enter into transactions with any Affiliates (other than the Company or entities which are Affiliates solely because the Company has a direct or indirect interest therein (it being understood that neither KMR, KMP, EPB, nor their respective Subsidiaries shall constitute such an entity)), executive officers or directors of the Company or any Subsidiary, or any Management Shareholder, or any of their respective Affiliates (other than the Company or entities which are Affiliates solely because the Company has a direct or indirect interest therein (it being understood that neither KMR, KMP, EPB, nor their respective Subsidiaries shall constitute such an entity)), or with entities in which any such Person has a financial stake other than through their ownership in the Company (and other than a stake representing less than 2% of any class of equity securities of any publicly traded company); provided, however, that this provision will not restrict transactions in the day-to- day ordinary course of business with KMGP, KMP, KMR, EPGP or EPB or their respective Subsidiaries or controlled Affiliates that are not the types of actions that otherwise require approval by a Supermajority Board Vote pursuant to any of the enumerated items in Section 3.12(H)(a)-(n); provided, further, that this provision will not apply to the selection of underwriters in accordance with Section 5.1(g) of the Shareholders Agreement; it being understood that this subsection (h) shall not be read to imply that an action otherwise subject to a Supermajority Board Vote pursuant to any of the enumerated items in Section 3.12(H)(a)-(n) is not so subject; (i) Increase the employee compensation of any Management Shareholder or provide additional equity or profits related benefits to a Management Shareholder, including pursuant to compensatory cash payments made pursuant to Section 3.6(j) of the Shareholders Agreement; provided, that decisions with respect to the distribution of property in the Class B Trust (as defined in the Shareholders Agreement) contemplated by Section 3.8(g) of the Shareholders Agreement shall be determined in accordance with Section 3.8(g) of the Shareholders Agreement and shall not Exhibit 3.2 require a Supermajority Board Vote; provided, further, that approval pursuant to this provision shall be in addition to, and not in lieu of, any other approvals for the compensation of the Chief Executive Officer required pursuant to applicable stock exchange requirements; (j) Make material changes to or waive the material terms of any agreement or transaction the entry into which required or would have required a Supermajority Board Vote pursuant to this Section 3.12; (k) Take, or permit any of its Subsidiaries (which, for clarification, does not include KMR when acting as a holder of KMP i-units or KMGP (solely to the extent that KMGP (x) is acting in its capacity as a holder of shares of KMR or in its capacity as General Partner pursuant to Section 1.4 of the Delegation of Control Agreement to approve any action taken by KMR, or (y) is acting in its capacity as the general partner of KMP to approve any matter on behalf of KMP (and not to the extent acting in another capacity, such as acting to amend or waive a right or obligation of KMGP (or of its direct or indirect parent entities) under any organizational document of KMP)) or EPGP (solely to the extent that EPGP is acting in its capacity as the general partner of EPB with respect to the business and affairs of EPB or to approve any matter on behalf or EPB (and not to the extent acting in another capacity, such as acting to amend or waive a right or obligation of EPGP (or of its direct or indirect parent entities) under any organizational document of EPB)) or KMGP Services, to the extent it is taking action related to carrying out the terms of the Employee Services Agreement) to take, any action in its capacity as shareholder, member or partner of any Subsidiary or Affiliate, in each case, that is publicly traded (including KMP, KMR and EPB); provided, that this Section 3.12 shall not impose any board of directors voting requirement with respect to (i) the determination of the identity of the board members (or similar governing body) of KMR or EPGP or, except as specifically set forth in Section 3.12(G), of KMGP or (ii) for the avoidance of doubt, any actions required by Section 3.6(g) of the Shareholders Agreement; (l) Enter into any agreement or the taking of any action (i) that would by its terms purport to restrict or could reasonably be expected to restrict the ability of the Company or any of its Subsidiaries or its controlled Affiliates (other than controlled Affiliates of KMR, KMP or EPB) to make distributions, (ii) with the intent of negatively affecting or impairing any right that the board of directors and/or the stockholders have pursuant to these Bylaws, the Charter or the Shareholders Agreement or (iii) that by its terms purports to prohibit or could reasonably be expected to prohibit, or that imposes or could reasonably be expected to impose material penalties in the event of, the exercise of a right that the board of directors and/or the stockholders have pursuant to these Bylaws, the Charter or the Shareholders Agreement, but excluding in the case of this clause (iii) customary change of control provisions or similar provisions that are typical in agreements of the relevant nature; (m) Adopt, or, if adopted, modify or waive a shareholder rights plan of the Company; or (n) Authorize any of, commit, agree or propose to take any of, consent to or vote in favor of any of, publicly announce an intention to, or otherwise effect, in each case directly or indirectly, any actions that would constitute any of the foregoing, including with respect to any of the Company’s Subsidiaries or its Affiliates (other than KMP, KMP’s operating partnerships, EPB, Exhibit 3.2 KMR or any of their respective Subsidiaries or controlled Affiliates, or KMGP (solely to the extent that KMGP (x) is acting in its capacity as a holder of shares of KMR or in its capacity as General Partner pursuant to Section 1.4 of the Delegation of Control Agreement to approve any action taken by KMR, or (y) is acting in its capacity as the general partner of KMP or any of its operating partnerships to approve any matter on behalf of KMP or any of its operating partnerships (and not to the extent acting in another capacity, such as acting to amend or waive a right or obligation of KMGP (or of its direct or indirect parent entities) under any organizational document of KMP or its operating partnerships)) or EPGP (solely to the extent that EPGP is acting in its capacity as the general partner of EPB with respect to the business and affairs of EPB or to approve any matter on behalf or EPB (and not to the extent acting in another capacity, such as acting to amend or waive a right or obligation of EPGP (or of its direct or indirect parent entities) under any organizational document of EPB)) or KMGP Services, to the extent it is taking action relating to carrying out the terms of the Employee Services Agreement), except as specifically provided for in this Section 3.12). Notwithstanding any other provision of this Section 3.12, no Majority Vote or Supermajority Board Vote shall be required for any matter approved by a committee of the board of directors if such committee’s charter provides such committee with exclusive authority with respect to such matter. Notwithstanding anything to the contrary contained herein, but in no way limiting the provisions of Section 3.12(H)(k), it is expressly agreed that nothing in these Bylaws shall require a Supermajority Board Vote (or any other board of director action) in order for any member of management or other representative of the Company who is serving as an executive officer or a director (or in any similar capacity) for an entity with publicly traded Securities (other than the Company) to make decisions as he or she sees fit in such capacity or, if serving as an executive officer or a director (or in any similar capacity) for an entity that is a general partner or the delegate of a general partner of any entity that has publicly traded Securities (other than the Company), to make decisions as such an officer or a director (or in such similar capacity), when acting in such capacity, as he or she believes is required on behalf of such publicly traded entity; provided, that nothing in this paragraph shall be construed to limit the fiduciary duties owed to the Company and its Subsidiaries by any such member of management or other representative of the Company when acting in any capacity on behalf of the Company or any of its Subsidiaries. For the avoidance of doubt, nothing in these Bylaws shall require a Supermajority Board Vote for the following actions: (i) the filing of any current or periodic reports or any reports related to the beneficial ownership of securities required under the Exchange Act to be filed by the Company or KMI, or (ii) any action expressly required to be approved solely by independent members of the board of directors, or a committee composed thereof, pursuant to the Exchange Act or applicable stock exchange requirements when the number of independent directors then serving on the board of directors or such committee is less than the number of directors required to effect a Supermajority Board Vote. 3.13 Procedure. At meetings of the board of directors, business shall be transacted in such order as from time to time the board of directors may determine by a Majority Vote. The Chairman Exhibit 3.2 of the Board, if such office has been filled, and, if not or if the Chairman of the Board is absent or otherwise unable to act, the President shall preside at all meetings of the board of directors. In the absence or inability to act of either such officer, a chairman shall be chosen by the board of directors by the affirmative vote of a majority of the directors present. The Secretary of the Company shall act as the secretary of each meeting of the board of directors unless the board of directors appoints another person to act as secretary of the meeting by a Majority Vote. The board of directors shall keep regular minutes of its proceedings which shall be placed in the minute books of the Company. 3.14 Presumption of Assent. A director of the Company who is present at the meeting of the board of directors at which action on any corporate matter is taken shall be presumed to have assented to the action unless his dissent shall be entered in the minutes of the meeting or unless he shall file his written dissent to such action with the person acting as secretary of the meeting before the adjournment thereof or shall forward any dissent by certified or registered mail to the Secretary of the Company immediately after the adjournment of the meeting. Such right to dissent shall not apply to a director who voted in favor of such action. 3.15 Compensation. The board of directors, by a Majority Vote, shall have the authority to fix the compensation, including fees and reimbursement of expenses, paid to directors for attendance at regular or special meetings of the board of directors or any committee thereof; provided, however, that nothing contained in these Bylaws shall be construed to preclude any director from serving the Company in any other capacity or receiving compensation therefor. 3.16 Action Without Meeting. Any action required or permitted to be taken at any meeting of the board of directors, or of any committee thereof, may be taken without a meeting, if prior to such action a written consent thereto is signed by all members of the board of directors, or of such committee as the case may be, and such written consent is filed with the minutes of proceedings of the board of directors or committee thereof. ARTICLE IV Committees 4.1 Designation. The board of directors may, by resolution, designate one (1) or more committees. The board of directors, by resolution, shall designate and appoint an audit committee, a compensation committee (the “Compensation Committee”) and a corporate governance and nominating committee (the “Governance/Nominating Committee”) and may designate and appoint one (1) or more other committees under such names and for such purpose or function as may be deemed appropriate. 4.2 Number; Qualification; Term. Each committee shall consist of one (1) or more directors appointed by resolution adopted by the board of directors in accordance with the Shareholders Agreement. The number of committee members may be increased or decreased from time to time by resolution adopted by the board of directors in accordance with the Shareholders Agreement. Exhibit 3.2 4.3 Authority. Each committee, to the extent expressly provided in the resolution establishing such committee, shall have and may exercise all of the authority of the board of directors in the management of the business and property of the Company, except to the extent expressly restricted by law, the Charter, or these Bylaws (including any provisions under Section 3.12 requiring matters to be brought before the board of directors, or requiring a Supermajority Board Vote or a Majority Vote). 4.4 Committee Changes. Subject to the terms of the Shareholders Agreement, the board of directors, by a Majority Vote, shall have the power at any time to fill vacancies in, to change the membership of, and to discharge any committee. 4.5 Alternate Members of Committees. Subject to the terms of the Shareholders Agreement and the charter of any committee, the board of directors, by a Majority Vote, may designate one (1) or more directors as alternate members of any committee. Any such alternate member may replace any absent or disqualified member at any meeting of the committee. If no alternate committee members have been so appointed to a committee or each such alternate committee member is absent or disqualified, the member or members of such committee present at any meeting and not disqualified from voting, whether or not he or they constitute a quorum, may unanimously appoint another member of the board of directors to act at the meeting in the place of any such absent or disqualified member. 4.6 Regular Meetings. Regular meetings of any committee may be held without notice at such time and place as may be designated from time to time by the committee and communicated to all members thereof. 4.7 Special Meetings. Special meetings of any committee may be held whenever called by any committee member. The committee member calling any special meeting shall cause notice of such special meeting, including therein the time and place of such special meeting, to be given to each committee member at least twenty-four (24) hours before such special meeting. Neither the business to be transacted at, nor the purpose of, any special meeting of any committee need be specified in the notice or waiver of notice of any special meeting. 4.8 Quorum; Majority Vote. At meetings of any committee, a majority of the number of members designated by the board of directors shall constitute a quorum for the transaction of business. To the fullest extent permitted by law, if a quorum is not present at a meeting of any committee, a majority of the members present may adjourn the meeting from time to time, without notice other than an announcement at the meeting, until a quorum is present. The affirmative vote of a majority of the members present at any meeting at which a quorum is in attendance shall be the act of a committee, unless the act of a greater number is required by law, the Charter, or these Bylaws; provided, that all determinations by the Governance/Nominating Committee with respect to nominations, designations and appointments to the board of directors and committees of the board of directors shall require unanimous approval until the Investor Shareholders are no longer entitled to nominate at least three (3) directors to the board of directors pursuant to Section 3.1(b) of the Shareholders Agreement. Exhibit 3.2 4.9 Minutes. Each committee shall cause minutes of its proceedings to be prepared and shall report the same to the board of directors upon the request of the board of directors. The minutes of the proceedings of each committee shall be delivered to the Secretary of the Company for placement in the minute books of the Company. 4.10 Compensation. Committee members may, by resolution adopted by a Majority Vote of the board of directors, be allowed a fixed sum and expenses of attendance, if any, for attending any committee meetings or a stated salary or other compensation. 4.11 Responsibility. The designation of any committee and the delegation of authority to it shall not operate to relieve the board of directors or any director of any responsibility imposed upon it or such director by law. ARTICLE V Notice 5.1 Method. Whenever by statute, the Charter, or these Bylaws, notice is required to be given to any committee member, director, or stockholder and no provision is made as to how such notice shall be given, personal notice shall not be required and any such notice may be given (a) in writing, by mail, postage prepaid, addressed to such committee member, director, or stockholder at his address as it appears on the books or (in the case of a stockholder) the stock transfer records of the Company, or (b) by any other method permitted by law (including, without limitation, by overnight courier service, telegram, telex, or facsimile or other form of electronic transmission, provided such other form of electronic transmission creates a record that may be retained, retrieved, and reviewed by the recipient thereof, may be directly reproduced in paper form by such recipient, and such recipient has consented to the delivery of notice by such method). Notices or instructions relating to conversion of Class A Shares, Class B Shares or Class C Shares into Class P Shares in accordance with the Charter shall be given by email to the email addresses provided by the notice recipient in connection therewith. Any notice required or permitted to be given by mail shall be deemed to be delivered and given at the time when the same is deposited in the United States mail as aforesaid. Any notice required or permitted to be given by overnight courier service shall be deemed to be delivered and given at the time delivered to such service with all charges prepaid and addressed as aforesaid. Any notice required or permitted to be given by telegram, telex, or facsimile shall be deemed to be delivered and given at the time transmitted with all charges prepaid and addressed as aforesaid. 5.2 Waiver. Whenever any notice is required to be given to any stockholder, director, or committee member of the Company by statute, the Charter, or these Bylaws, a waiver thereof in writing signed by the Person or Persons entitled to such notice, whether before or after the time stated therein, shall be equivalent to the giving of such notice. Attendance of a stockholder, director, or committee member at a meeting shall constitute a waiver of notice of such meeting, so long as such stockholder, director or committee member does not object to the transaction of any business on the ground that the meeting is not lawfully called or convened. Exhibit 3.2 ARTICLE VI Officers 6.1 Number; Titles; Term of Office. The officers of the Company shall be a Chief Executive Officer, a President, a Chief Financial Officer, a Chief Operating Officer, a Secretary, and, if elected by the board of directors, a Chairman of the Board, and such other officers as the board of directors may from time to time elect or appoint, including one or more Vice Presidents (with each Vice President to be elected or appointed and to have such descriptive title, if any, as the board of directors shall determine by a Majority Vote), and a Treasurer. Subject to Section 3.12(B)(1) in the case of the Chief Executive Officer and Section 3.8, each officer shall be appointed or elected by the board of directors and shall hold office until his successor shall have been duly elected and shall have qualified, until his death, or until he shall resign or shall have been removed in the manner hereinafter provided. Any two (2) or more offices may be held by the same person. None of the officers need be a stockholder or a resident of the State of Delaware or, except in the case of the Chairman of the Board, a director of the Company. 6.2 Removal. Subject to Section 3.12(B)(1), any officer or agent elected or appointed by the board of directors (other than the Chief Executive Officer), may be removed by the board of directors by a Majority Vote with or without cause at any time. The board of directors, by a Majority Vote, may remove the Chief Executive Officer for cause (or Cause, if the Chief Executive Officer is Kinder) at any time. The board of directors, by the approval of the number of directors constituting a majority of all directors plus one, may remove the Chief Executive Officer other than for cause (or other than for Cause if the Chief Executive Officer is Kinder) pursuant to Section 3.12(B)(1). This Section 6.2 shall be without prejudice to the contract rights, if any, of the person so removed. Election or appointment of an officer or agent shall not of itself create contract rights except pursuant to Article VIII. 6.3 Vacancies. Any vacancy occurring in any office of the Company (by death, resignation, removal, or otherwise) may be filled by the board of directors, subject to Section 3.12(B)(1) in the case of the Chief Executive Officer. 6.4 Authority. Officers shall have such authority and perform such duties in the management of the Company as are provided in these Bylaws or as may be determined by resolution (including by a Majority Vote where these Bylaws so provide) of the board of directors not inconsistent with these Bylaws. 6.5 Compensation. The compensation, if any, of officers and agents shall be fixed from time to time by the board of directors, by a Majority Vote (except to the extent a Supermajority Board Vote is required pursuant to Section 3.12(H)(i)), or by the Compensation Committee (except to the extent a Supermajority Board Vote is required pursuant to Section 3.12(H)(i) and, with respect to the compensation of the Chief Executive Officer, such other approvals are required pursuant to applicable stock exchange requirements). Exhibit 3.2 6.6 Chairman of the Board. The Chairman of the Board, if one is elected by the board of directors, shall have such powers and duties as may be prescribed by the board of directors. Such officer shall preside at all meetings of the stockholders and of the board of directors. Such officer may sign all certificates for shares of stock of the Company. 6.7 Chief Executive Officer. The Chief Executive Officer shall have general supervision, management, direction and control of the business and affairs of the Company and shall see that all orders and resolutions of the board of directors are carried into effect. The Chief Executive Officer shall be authorized to execute promissory notes, bonds, mortgages, leases and other contracts requiring a seal, under the seal of the Company, except where required or permitted by law to be otherwise executed and except where the execution thereof shall be expressly delegated by the board of directors by a Majority Vote to some other officer or agent of the Company. In the absence of the Chairman of the Board, the Chief Executive Officer shall preside at all meetings of the stockholders and of the board of directors. The Chief Executive Officer shall have the general powers and duties of management usually vested in the office of chief executive officer of a corporation and shall perform such other duties and possess such other authority and powers as the board of directors may from time to time prescribe. 6.8 Chief Financial Officer. The Chief Financial Officer shall have general financial supervision, management, direction and control of the business and affairs of the Company and shall see that all financial orders and resolutions of the board of directors are carried into effect. The Chief Financial Officer shall be authorized to execute promissory notes, bonds, mortgages, leases and other contracts requiring a seal, under the seal of the Company, except where required or permitted by law to be otherwise executed and except where the execution thereof shall be expressly delegated by the board of directors by a Majority Vote to some other officer or agent of the Company. The Chief Financial Officer shall have the general financial powers and duties of management usually vested in the office of chief financial officer of a corporation and shall perform such other duties and possess such other authority and powers as the board of directors, the Chief Executive Officer, or the Chairman of the Board may from time to time prescribe. 6.9 President. The President shall have the general powers and duties of management usually vested in the office of president of a corporation (in circumstances where such corporation also maintains the office of chief executive officer) and shall perform such other duties and possess such other authority and powers as the board of directors, the Chief Executive Officer, or the Chairman of the Board may from time to time prescribe. 6.10 Chief Operating Officer. The Chief Operating Officer shall have the general powers and duties of management usually vested in the office of chief operating officer of a corporation (including general supervision of the day-to-day operations of the Company) and shall perform such other duties and possess such other authority and powers as the board of directors, the Chief Executive Officer, or the Chairman of the Board may from time to time prescribe. 6.11 Vice Presidents. Each Vice President shall have such powers and duties as may be assigned to him by the board of directors (by a Majority Vote), the Chairman of the Board, the Chief Executive Officer, the Chief Financial Officer, the Chief Operating Officer, the President, and (in Exhibit 3.2 order of their seniority as determined by the board of directors (by a Majority Vote) or, in the absence of such determination, as determined by the length of time they have held the office of Vice President) shall exercise the powers of the Chief Executive Officer or the President during that officer’s absence or inability to act. As between the Company and third parties, any action taken by a Vice President in the performance of the duties of the Chief Executive Officer or the President shall be conclusive evidence of the absence or inability to act of the Chief Executive Officer or the President at the time such action was taken. 6.12 Treasurer. The Treasurer shall have custody of the Company’s funds and Securities, shall keep full and accurate account of receipts and disbursements, shall deposit all monies and valuable effects in the name and to the credit of the Company in such depository or depositories as may be designated by the board of directors by a Majority Vote, and shall perform such other duties as may be prescribed by the board of directors (by a Majority Vote), the Chairman of the Board, the Chief Executive Officer, the Chief Financial Officer, the Chief Operating Officer or the President. 6.13 Assistant Treasurers. Each Assistant Treasurer shall have such powers and duties as may be assigned to him by the board of directors (by a Majority Vote), the Chairman of the Board, the Chief Executive Officer, the Chief Financial Officer, the Chief Operating Officer or the President. The Assistant Treasurers (in the order of their seniority as determined by the board of directors by a Majority Vote or, in the absence of such a determination, as determined by the length of time they have held the office of Assistant Treasurer) shall exercise the powers of the Treasurer during such officer’s absence or inability to act. 6.14 Secretary. Except as otherwise provided in these Bylaws, the Secretary shall keep the minutes of all meetings of the board of directors and of the stockholders in books provided for that purpose, and he shall attend to the giving and service of all notices. He may sign with the Chairman of the Board, the Chief Executive Officer, the President, the Chief Operating Officer, the Chief Financial Officer or a Vice President, in the name of the Company, all contracts of the Company and affix the seal of the Company thereto. He may sign with the Chairman of the Board, the President or a Vice President all certificates for shares of stock of the Company, and he shall have charge of the certificate books, transfer books, and stock papers as the board of directors by a Majority Vote may direct, all of which shall at all reasonable times be open to inspection by any director upon application at the office of the Company during ordinary business hours. He shall in general perform all duties incident to the office of the Secretary, subject to the control of the board of directors, the Chairman of the Board, the Chief Executive Officer and the President. 6.15 Assistant Secretaries. Each Assistant Secretary shall have such powers and duties as may be assigned to him by the board of directors (by a Majority Vote), the Chairman of the Board, the Chief Executive Officer, the Chief Operating Officer or the President. The Assistant Secretaries (in the order of their seniority as determined by the board of directors by a Majority Vote or, in the absence of such a determination, as determined by the length of time they have held the office of Assistant Secretary) shall exercise the powers of the Secretary during that officer’s absence or inability to act. Exhibit 3.2 ARTICLE VII Certificates and Stockholders 7.1 Certificates for Shares. Shares of stock in the Company shall be uncertificated and shall not be represented by certificates, except to the extent as may be required by applicable law or as may otherwise be authorized by the board of directors. In the event shares of stock are represented by certificates, such certificates shall be registered upon the books of the Company and signed by the Chairman of the Board or the President or a Vice President and also by the Secretary or an Assistant Secretary or by the Treasurer or an Assistant Treasurer. Any and all signatures on the certificate may be a facsimile and may be sealed with the seal of the Company or a facsimile thereof; provided, however, that no such seal of the Company shall be required thereon. If any officer, transfer agent, or registrar who has signed, or whose facsimile signature has been placed upon, a certificate has ceased to be such officer, transfer agent, or registrar whether because of death, resignation or otherwise before such certificate is issued by the Company, such certificate may nevertheless be issued and delivered by the Company with the same effect as if the person who signed such certificate or whose facsimile signature has been placed upon such certificate had not ceased to be an officer, transfer agent, or registrar at the date of issue. All certificates for shares of stock shall be consecutively numbered and shall be entered in the books of the Company as they are issued and shall exhibit the holder’s name and the number of shares. 7.2 Replacement of Lost or Destroyed Certificates. The board of directors may, by a Majority Vote, direct a new certificate or certificates to be issued in place of a certificate or certificates theretofore issued by the Company and alleged to have been lost or destroyed, upon the making of an affidavit of that fact by the Person claiming the certificate or certificates representing shares to be lost or destroyed. When authorizing such issue of a new certificate or certificates, the board of directors may, by a Majority Vote, in its discretion and as a condition precedent to the issuance thereof, require the owner of such lost or destroyed certificate or certificates, or his legal representative, to advertise the same in such manner as it shall require and/or to give the Company a bond with a surety or sureties satisfactory to the Company in such sum as it may direct as indemnity against any claim, or expense resulting from a claim, that may be made against the Company in respect of the certificate or certificates alleged to have been lost or destroyed. 7.3 Transfer of Shares. Shares of stock of the Company shall be transferable only on the books of the Company by the holders thereof in person or by their duly authorized attorneys or legal representatives. If the shares of stock are represented by certificates, then upon surrender to the Company or the transfer agent of the Company of a certificate representing shares duly endorsed or accompanied by proper evidence of succession, assignment, or authority to transfer, the Company or its transfer agent shall issue a new certificate to the Person entitled thereto, cancel the old certificate, and record the transaction upon its books. 7.4 Registered Stockholders. The Company shall be entitled to treat the holder of record of any share or shares of stock as the holder in fact thereof and, accordingly, shall not be bound to recognize any equitable or other claim to or interest in such share or shares on the part of any other Exhibit 3.2 Person, whether or not it shall have express or other notice thereof, except as otherwise provided by law. 7.5 Regulations. The board of directors shall have the power and authority, by a Majority Vote, to make all such rules and regulations as it may deem expedient concerning the issue, transfer, and registration or the replacement of certificates for shares of stock of the Company. 7.6 Legends. The board of directors shall have the power and authority, by a Majority Vote, to provide that certificates representing shares of stock bear such legends as the board of directors deems necessary to assure that the Company does not become liable for violations of federal or state securities laws or other applicable law. ARTICLE VIII Indemnification 8.1 Indemnification of Directors and Officers. The Company shall indemnify any person who was, is, or is threatened to be made a party to a proceeding (as hereinafter defined) by reason of the fact that he or she (a) is or was a director or officer of the Company or (b) while a director or officer of the Company, is or was serving at the request of the Company as a director, officer, partner, manager, venturer, proprietor, trustee, employee, agent, or similar function of another foreign or domestic corporation, partnership, joint venture, limited liability company, sole proprietorship, trust, employee benefit plan, or other enterprise, at any time during which these Bylaws are in effect (whether or not such person continues to serve in such capacity at the time any indemnification or advancement of expenses pursuant hereto is sought or at the time any proceeding relating thereto exists or is brought), and whether the basis of such proceeding is alleged action in an official capacity as a director or officer, or in such other capacity while serving as an a director or officer, to the fullest extent permitted under the DGCL, as the same exists or may hereafter be amended or modified from time to time (but, in the case of any such amendment or modification, only to the extent that such amendment or modification permits the Company to provide greater indemnification rights than said law permitted the Company to provide prior to such amendment or modification) against all expense, liability and loss (including attorney’s fees, judgments, fines, ERISA excise taxes or penalties and amounts paid in settlement) incurred or suffered by such person in connection therewith. Such indemnification shall continue as to a person who has ceased to be a director or officer and shall inure to the benefit of his or her heirs, executors and administrators. 8.2 Contract Rights. The indemnification permitted by this Article VIII shall be a contract right and as such shall run from the Company (and any successor of the Company by operation of law or otherwise) to the benefit of any director or officer who is elected and accepts the position of director or officer of the Company or elects to continue to serve as a director or officer of the Company while this Article VIII is in effect. Any repeal or amendment of this Article VIII shall be prospective only and shall not limit the rights of any such director or officer or the obligations of the Company with respect to any claim arising from or related to the services of such director or officer in any of the foregoing capacities prior to any such repeal or amendment to this Article VIII. Exhibit 3.2 8.3 Request for Indemnification. To obtain indemnification under these Bylaws, a claimant shall submit to the Company a written request, including therein or therewith such documentation and information as is reasonably available to the claimant and is reasonably necessary to determine whether and to what extent the claimant is entitled to indemnification. Upon written request by a claimant for indemnification, a determination, if required by applicable law, with respect to the claimant’s entitlement thereto shall be made as follows: (a) if requested by the claimant, by Independent Counsel (as hereinafter defined), or (b) if no request is made by the claimant for a determination by Independent Counsel, (i) by the board of directors by a majority vote of a quorum of the board of directors consisting of Disinterested Directors (as hereinafter defined) or by a committee of Disinterested Directors appointed by a Majority Vote of the board of directors, or (ii) if a quorum of the board of directors consisting of Disinterested Directors or a committee of Disinterested Directors is not obtainable or, even if obtainable, such quorum or committee of Disinterested Directors so directs, by Independent Counsel in a written opinion to the board of directors, a copy of which shall be delivered to the claimant, or (iii) if a quorum of Disinterested Directors or a committee of Disinterested Directors so directs, by a majority vote of the stockholders of the Company. In the event the determination of entitlement to indemnification is to be made by Independent Counsel, the Independent Counsel shall be selected by the claimant (subject to the consent of the board of directors by a Majority Vote, not to be unreasonably withheld or delayed) unless the claimant shall request that such selection be made by the board of directors by a Majority Vote. If it is so determined that the claimant is entitled to indemnification, payment to the claimant shall be made within ten (10) days after such determination. A “Disinterested Director” means a director of the Company who is not and was not a party to the matter in respect of which indemnification is sought by the claimant. An “Independent Counsel” means a law firm, a member of a law firm, or an independent practitioner, that is experienced in matters of corporation law and shall be a person who, under the applicable standards of professional conduct then prevailing, would not have a conflict of interest in representing either the Company or the claimant in an action to determine the claimant’s rights under these Bylaws. 8.4 Advancement of Expenses. A claimant shall have the right to be paid by the Company expenses (including attorney’s fees) incurred in defending any such proceeding in advance of its final disposition to the maximum extent permitted under the DGCL, as the same exists or may hereafter be amended or modified, only to the extent that such amendment or modification permits the Company to provide greater rights to advancement of expenses than said law permitted the Company to provide prior to such amendment or modification, upon receipt of any undertaking by or on behalf of such director or officer to repay such amount if it shall ultimately be determined that such director or officer is not entitled to be indemnified by the Company against such expenses as authorized by this Article VIII, if such undertaking is required by the DGCL. Such advances shall be paid by the Company within twenty (20) calendar days after the receipt by the Company of a statement or statements from the claimant requesting such advance or advances from time to time (including such undertaking if required by the DGCL), and shall not require any action by the board of directors. The board of directors, by Majority Vote, may authorize the Company’s counsel to represent such director or officer in any such proceeding, whether or not the Company is a party to such proceeding. Exhibit 3.2 8.5 Judicial Proceedings. If a claim for indemnification is not paid in full by the Company within sixty (60) days after a written claim has been received by the Company, or if a claim for advancement of expenses is not paid in full by the Company within twenty (20) days after a written claim has been received by the Company, the claimant may at any time thereafter bring suit against the Company to recover the unpaid amount of the claim, and if successful in whole or in part, the claimant shall also be entitled to be paid the expenses of prosecuting such claim to the fullest extent permitted by law. In any such suit: (a) It shall be a defense to any such action that such indemnification or advancement of costs of defense are not permitted under the DGCL, but the burden of proving such defense shall be on the Company. (b) The termination of any action, suit or proceeding by judgment, order, settlement, conviction, or upon a plea of nolo contendere or its equivalent, shall not, of itself, create a presumption that the person did not act in good faith and in a manner which he or she reasonably believed to be in or not opposed to the best interests of the Company, and, with respect to any criminal action or proceeding, had reasonable cause to believe that his or her conduct was unlawful. (c) Neither the failure of the Company (including its board of directors or any committee thereof, Independent Counsel, or stockholders) to have made its determination prior to the commencement of such action that indemnification of the claimant is permissible in the circumstances nor an actual determination by the Company (including its board of directors or any committee thereof, Independent Counsel, or stockholders) that such indemnification is not permissible shall be a defense to the action or create a presumption that such indemnification is not permissible. (d) If a determination shall have been made pursuant to Section 8.3 that the indemnitee is entitled to indemnification, the Company shall be bound by such determination in any judicial proceeding commenced pursuant to this Section 8.5. To the fullest extent permitted by law, the Company shall be precluded from asserting in any judicial proceeding commenced pursuant to this Section 8.5 that the procedures and presumptions of these Bylaws are not valid, binding and enforceable and shall stipulate in such proceeding that the Company is bound by all the provisions of these Bylaws. 8.6 Non-Exclusive Right. (a) The rights conferred under this Article VIII shall not be exclusive of any other right that any person may have or hereafter acquire under any statute, bylaw, resolution of stockholders or directors, agreement, or otherwise and shall continue as to a person who has ceased to be a director, officer, employee or agent, as applicable, and shall inure to the benefit of his or her heirs, executors, administrators, and personal representatives. (b) With respect to any indemnification obligations of the Company conferred under this Article VIII, the Company hereby acknowledges and agrees (i) that it is the indemnitor of first resort with respect to all indemnification obligations of the Company pursuant to Section Exhibit 3.2 8.1 (i.e., its obligations to an applicable indemnitee are primary and any obligation of the Investor Shareholders and their Affiliates (collectively, the “Fund Indemnitors”) to advance expenses or to provide indemnification and/or insurance for the same expenses or liabilities incurred by such indemnitee are secondary) and (ii) that it irrevocably waives, relinquishes and releases the Fund Indemnitors from any and all claims against the Fund Indemnitors for contribution, subrogation or any other recovery of any kind in respect thereof to the fullest extent permitted by law. 8.7 Indemnification of Others. The Company may additionally indemnify and/or provide advancement of expenses to any employee or agent of the Company or any other person to the fullest extent permitted by law. 8.8 Proceedings. As used in this Article VIII, the term “proceeding” means any threatened, pending, or completed action, suit, or proceeding, whether civil, criminal, administrative, arbitrative, or investigative, any appeal in such an action, suit, or proceeding, and any inquiry or investigation that could lead to such an action, suit, or proceeding. 8.9 Other Agreements. The Company may adopt bylaws or enter into agreements with such persons for the purpose of providing for indemnification and/or the advancement of expenses as provided in this Article VIII. 8.10 Insurance. The Company shall have power to purchase and maintain insurance on behalf of any person who is or was a director, officer, employee or agent of the Company, or is or was serving at the request of the Company as a director, officer, partner, manager, venturer, proprietor, trustee, employee, agent, or similar function of another foreign or domestic corporation, partnership, joint venture, limited liability company, sole proprietorship, trust, employee benefit plan, or other enterprise, against any liability asserted against such person and incurred by such person in any such capacity, or arising out of such person’s status as such, whether or not the Company would have the power to indemnify such person against such liability under the provisions of this Article VIII or otherwise. To the extent that the Company maintains any policy or policies providing such insurance, each indemnitee to which rights to indemnification have been granted in this Article VIII in its capacity as a director or an officer, shall be covered by such policy or policies in accordance with its or their terms to the maximum extent of the coverage thereunder for any such indemnitee. Exhibit 3.2 ARTICLE IX Miscellaneous Provisions 9.1 Dividends. Subject to provisions of law and the Charter, dividends may be declared by the board of directors at any regular or special meeting and may be paid in cash, in property, or in shares of stock of the Company. Such declaration and payment shall be at the discretion of the board of directors; provided, that, if there shall be in effect at the time of such declaration a dividend policy duly adopted by the board of directors, such declaration and payment shall be in accordance with such dividend policy and shall only require a Majority Vote. Notwithstanding the foregoing, the declaration and distribution of any dividends may not be in contravention of the DGCL. 9.2 Reserves. There may be created by the board of directors, by a Majority Vote, out of funds of the Company legally available therefor such reserve or reserves as the board of directors, by a Majority Vote, from time to time, in its discretion, considers proper to provide for contingencies, to equalize dividends, or to repair or maintain any property of the Company, or for such other purpose as the board of directors shall consider beneficial to the Company, and may modify or abolish any such reserve in the manner in which it was created. 9.3 Books and Records. The Company shall keep correct and complete books and records of account, shall keep minutes of the proceedings of its stockholders and board of directors and shall keep at its registered office or principal place of business, or at the office of its transfer agent or registrar, a record of its stockholders, giving the names and addresses of all stockholders and the number and class (and series, if any) of the shares held by each. 9.4 Fiscal Year. The fiscal year of the Company (the “Fiscal Year”) shall be the calendar year unless changed by the board of directors by a Majority Vote. 9.5 Seal. The seal of the Company shall be such as from time to time may be approved by the board of directors by a Majority Vote. 9.6 Resignations. Any director, committee member, or officer may resign by so stating at any meeting of the board of directors or by giving written notice (or by electronic transmission) to the board of directors, the Chairman of the Board, the Chief Executive Officer, the President, or the Secretary. Such resignation shall take effect at the time specified therein or, if no time is specified therein, immediately upon its receipt. Unless otherwise specified therein, the acceptance of such resignation shall not be necessary to make it effective. 9.7 Securities of Other Corporations. Except to the extent inconsistent with, or requiring any approvals under, any provision of these Bylaws, including Section 3.12, the Chairman of the Board, the Chief Executive Officer, the President, or any Vice President of the Company shall have the power and authority to transfer, endorse for transfer, vote, consent, or take any other action in respect of any Securities of another issuer that may be held or owned by the Company and to make, execute, and deliver any waiver, proxy, or consent in respect of any such Securities, if and only to Exhibit 3.2 the extent that such actions are of a ministerial and customary nature taken in the ordinary course of business of the Company. 9.8 Telephone Meetings. Stockholders (acting for themselves or through a proxy), members of the board of directors, and members of a committee of the board of directors may participate in and hold a meeting of such stockholders, board of directors, or committee by means of a telephone or similar communications equipment by means of which all persons participating in the meeting can hear each other, and participation in a meeting pursuant to this Section 9.8 shall constitute presence in person at such meeting, except where a person participates in the meeting for the express purpose of objecting to the transaction of any business on the ground that the meeting is not lawfully called or convened. 9.9 Invalid Provisions. If any part of these Bylaws shall be held invalid or inoperative for any reason, the remaining parts, so far as it is possible and reasonable, shall remain valid and operative. 9.10 Mortgages, etc. In respect of any deed, deed of trust, mortgage, or other instrument executed by the Company through its duly authorized officer or officers, the attestation to such execution by the Secretary of the Company shall not be necessary to constitute such deed, deed of trust, mortgage, or other instrument a valid and binding obligation against the Company unless the resolutions, if any, of the board of directors authorizing such execution expressly state that such attestation is necessary. 9.11 Headings. The headings used in these Bylaws have been inserted for administrative convenience only and do not constitute matter to be construed in interpretation. 9.12 References. Whenever herein the singular number is used, the same shall include the plural where appropriate, and words of any gender should include each other gender where appropriate. Whenever the words “included,” “includes,” or “including” are used in these Bylaws, they shall be deemed to be followed by the words “without limitation.” 9.13 Amendments. Except as may be otherwise provided in the Charter and subject to Section 3.12 (with respect to any action by the board of directors), these Bylaws may be altered, amended, or repealed or new Bylaws may be adopted by the stockholders holding shares representing two-thirds of Total Voting Power or by the board of directors at any regular meeting of the stockholders or the board of directors or at any special meeting of the stockholders or the board of directors if notice of such alteration, amendment, repeal, or adoption of new Bylaws be contained in the notice of such special meeting. Notwithstanding the foregoing, any adoption, alteration, amendment or repeal of any Bylaw by the board of directors shall require the approval of (i) a majority of the directors chosen for nomination by Kinder pursuant to the Shareholders Agreement (if any), (ii) a majority of the directors chosen for nomination by the Investor Shareholders (if any), (iii) in the case of an alteration, amendment or repeal of Article III, Section 6.2, Section 9.7, or Section 9.13, two-thirds of the directors chosen for nomination by the Investor Shareholders (if any) and (iv) in the case of an alteration, amendment or repeal of any provision of these Bylaws that would treat any Investor Shareholder adversely, the director(s) chosen for nomination by such Exhibit 3.2 affected Investor Shareholder (if any); provided, that the approval requirements in clauses (i)-(iv) shall not apply to any action of the board of directors to amend the Bylaws to the extent necessary to comply with the adoption of Rule 14a-11 or other proxy access rules enacted by the Securities and Exchange Commission after the date hereof. ARTICLE X Definitions Capitalized terms used and not otherwise defined in these Bylaws shall have the meaning given or referenced below: “Affiliate” of any Person means any other Person that directly or indirectly, through one or more intermediaries, Controls, is Controlled by, or is under common Control with, such first Person. “Carlyle” means (i) Carlyle Partners IV Knight, L.P. and CP IV Coinvestment, L.P., (ii) any investment funds or other entities sponsored, managed or owned directly or indirectly by Carlyle Investment Management L.L.C. or its affiliates collectively d/b/a “The Carlyle Group” or “Carlyle”, or otherwise under common control with the entities listed in clause (i) or their successors (by merger, consolidation, acquisition of substantially all assets or similar transaction) or with any entity then included in clause (ii), to which any entity previously included in the definition of “Carlyle” transferred, directly or indirectly (including through a series of transfers), Class A Shares after the IPO or Related Shares after a Mandatory Conversion Date, and (iii) any successors (by merger, consolidation, acquisition of substantially all assets or similar transaction) of the foregoing. For the avoidance of doubt, “Carlyle” shall be deemed not to include (A) Riverstone or any portfolio companies of any of the entities contained in clauses (i), (ii) or (iii) or (B) any entity that is not a party to the Shareholders Agreement. “Cause” means any of the following: (a) (b) (c) Kinder’s conviction of, or plea of nolo contendere to, any crime or offense constituting a felony under applicable law, other than any motor vehicle violations for which no custodial penalty is imposed; Kinder’s commission of fraud or embezzlement against the Company or any of its Subsidiaries; Kinder’s willful and material breach of the Bylaws, the Charter or the Shareholders Agreement, including, without limitation, by willfully causing the Company or any of its Subsidiaries or Affiliates to take any material action prohibited under these Bylaws, the Charter or the Shareholders Agreement and failing to cure such breach, if curable, within thirty (30) calendar days following written notice thereof, specifically identifying such willful and material breach, having been delivered by a majority of the members of the board of directors to Kinder; (d) a judicial determination that Kinder has breached his fiduciary duties; Exhibit 3.2 (e) Kinder’s failure to perform the duties and responsibilities of his office as his primary business activity, provided, that, subject to Section 3.6(f) of the Shareholders Agreement, so long as it does not materially interfere with his duties, nothing herein shall preclude Kinder from accepting appointment to or continuing to serve on any board of directors or as trustee of any business corporation or any charitable organization, from engaging in charitable and community activities, from delivering lectures and fulfilling speaking engagements, or from directing and managing his personal investments and those of his family; or (f) Kinder’s material breach of the provisions of Section 3.6(f) of the Shareholders Agreement that, if curable, is not cured within thirty (30) calendar days after notice of such breach is delivered to Kinder by a majority of the members of the board of directors. Action or inaction by Kinder shall not be considered “willful” unless done or omitted by him in bad faith or with actual knowledge that his action or inaction was in breach of these Bylaws, the Charter or the Shareholders Agreement as applicable, and shall not include failure to act by reason of total or partial incapacity due to physical or mental illness. “Class A Shares” means the shares of Class A common stock of the Company. “Class B Shares” means the shares of Class B common stock of the Company. “Class C Shares” means the shares of Class C common stock of the Company. “Class P Shares” means the shares of Class P common stock of the Company. “Control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise. “Delegation of Control Agreement” means the Delegation of Control Agreement dated as of May 18, 2001, as amended, among KMGP, KMR, KMP and KMP’s five operating partnerships. “Employee Services Agreement” means the Employee Services Agreement dated as of January 1, 2001, among KMGP Services Company, Inc., KMGP and KMP, as in effect of the date hereof (and not including any amendments or waivers). “EPB” means El Paso Pipeline Partners, L.P., a Delaware limited partnership. “EPGP” menas El Paso Pipeline GP Company, L.L.C., a Delaware limited liability company. Exhibit 3.2 “Exchange Act” means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time and any successor to such statute, and the rules and regulations promulgated thereunder. “GAAP” means United States generally accepted accounting principles. “Governmental Entity” means any court, administrative agency, regulatory body, commission or other governmental authority, board, bureau or instrumentality, domestic or foreign and any subdivision thereof. “GS” means (i) GS Capital Partners V Fund, L.P., a Delaware limited partnership; GS Capital Partners V Institutional, L.P., a Delaware limited partnership; GS Capital Partners VI Fund, L.P., a Delaware limited partnership; GS Capital Partners VI Parallel, L.P., a Delaware limited partnership; Goldman Sachs KMI Investors, L.P., a Delaware limited partnership; GSCP KMI Investors, L.P., a Delaware limited partnership; GSCP KMI Investors Offshore, L.P., a Cayman Islands exempted limited partnership; GS Global Infrastructure Partners I, L.P., a Delaware limited partnership; GS Institutional Infrastructure Partners I, L.P., a Delaware limited partnership; GSCP V Offshore Knight Holdings, L.P., a Delaware limited partnership; GSCP V Germany Knight Holdings, L.P., a Delaware limited partnership; GSCP VI Offshore Knight Holdings, L.P., a Delaware limited partnership; GSCP VI Germany Knight Holdings, L.P., a Delaware limited partnership; and GS Infrastructure Knight Holdings, L.P., a Delaware limited partnership, (ii) any investment funds or other entities sponsored, managed or owned directly or indirectly by the Merchant Banking Division of Goldman, Sachs & Co., or otherwise under common control with the entities listed in clause (i) or their successors (by merger, consolidation, acquisition of substantially all assets or similar transaction) or with any entity then included in clause (ii), to which any of the entities previously included in the definition of “GS” transferred, directly or indirectly (including through a series of transfers), Class A Shares after the IPO or Related Shares after a Mandatory Conversion Date, and (iii) any successors (by merger, consolidation, acquisition of substantially all assets or similar transaction) of the foregoing; provided, that for purposes of calculating the Total Voting Power held or owned by GS, such calculation shall not include any Class P Shares (other than Related Shares) beneficially owned by any direct or indirect Subsidiary of Goldman, Sachs & Co. contained in clauses (ii) or (iii), if such direct or indirect Subsidiary of Goldman, Sachs & Co. is not sponsored, managed or owned directly or indirectly by the Merchant Banking Division of Goldman, Sachs & Co., by a successor to the operations of the Merchant Banking Division of Goldman, Sachs & Co., or by any other entity in the business of sponsoring, managing or owning directly or indirectly private equity investments vehicles or investments. For the avoidance of doubt, “GS” shall be deemed not to include (A) any portfolio companies of any of the entities contained in clauses (i), (ii) or (iii) or (B) any entity that is not a party to the Shareholders Agreement. “Highstar” means (i) Highstar II Knight Acquisition Sub, L.P., Highstar III Knight Acquisition Sub, L.P., Highstar Knight Partners, L.P. and Highstar KMI Blocker LLC, (ii) any investment funds or other entities sponsored, managed or owned directly or indirectly by Highstar Capital LP or one of its controlled Affiliates, or otherwise under common control with the entities listed in clause (i) or their successors (by merger, consolidation, acquisition of substantially all assets or similar transaction) or with any entity then included in clause (ii), to which any entity Exhibit 3.2 previously included in the definition of “Highstar” transferred, directly or indirectly (including through a series of transfers), Class A Shares after the IPO or Related Shares after a Mandatory Conversion Date, and (iii) any successors (by merger, consolidation, acquisition of substantially all assets or similar transaction) of the foregoing. For the avoidance of doubt, “Highstar” shall be deemed not to include (A) any portfolio companies of any of the entities contained in clauses (i), (ii) or (iii) or (B) any entity that is not a party to the Shareholders Agreement. “Indebtedness” means, with respect to any Person, (i) indebtedness of such Person for borrowed money, (ii) other indebtedness of such Person evidenced by notes, bonds or debentures, (iii) capitalized leases classified as indebtedness of such Person under GAAP, (iv) all indebtedness created or arising under any conditional sale or other title retention agreement with respect to property acquired by such Person (even though the rights and remedies of the seller or lender under such agreement in the event of default are limited to repossession or sale of such property), (v) any obligation of such Person for the deferred purchase price of property or services (other than trade payables and other current liabilities), (vi) any Indebtedness of another Person referred to in clauses (i) through (v) above guaranteed directly or indirectly, jointly or severally, in any manner by such Person, (vii) any Indebtedness referred to in clauses (i) through (v) above secured by (or for which the holder of such Indebtedness has an existing right, contingent or otherwise, to be secured by) any lien or encumbrance on property (including, without limitation, accounts and contract rights) owned by such Person, even though such Person has not assumed or become liable for the payment of such Indebtedness, and (viii) the maximum amount of all direct or contingent obligations of such Person with respect to letters of credit, bankers’ acceptances, bank guaranties, surety bonds or similar facilities or instruments. Notwithstanding anything to the contrary herein, the Indebtedness of the Company and its Subsidiaries shall not include (a) any indebtedness or obligation owed by the Company to any wholly-owned Subsidiary, by any other wholly-owned Subsidiary to the Company, or between any wholly-owned Subsidiaries, or (b) any guarantee by the Company or any wholly- owned Subsidiary of any indebtedness or obligation described in clause (a) of this sentence. “Investor Shareholder” means each of GS, Highstar, Carlyle and Riverstone. “IPO” means the initial offering of Class P Shares to the public. “Kinder” means Richard D. Kinder. “KMGP” means Kinder Morgan G.P., Inc., a Delaware corporation. “KMGP Services” means KMGP Services Company, Inc., a Delaware corporation. “KMI” means Kinder Morgan Kansas, Inc., a Kansas corporation, and if the name of Kinder Morgan Kansas, Inc. is changed, “KMI” shall mean such corporation. “KMP” means Kinder Morgan Energy Partners, L.P., a Delaware limited partnership. “KMR” means Kinder Morgan Management, LLC, a Delaware limited liability company. Exhibit 3.2 “Majority Vote” means (i) the affirmative vote of a majority of the directors present at a meeting at which a quorum is in attendance, or (ii) any action taken by all members of the board of directors pursuant to Section 3.16. “Management Shareholders” means (i) any Shareholder who has served, at any time on or following the closing date of the IPO, as a member of management of the Company or any of its Subsidiaries (excluding, for this purpose, any service as a member of the board of directors) (which shall include any employee who is a holder of Class B Shares), (ii) Nancy Kinder and (iii) any Permitted Transferees (as defined in the Shareholders Agreement) to whom any of such Shareholder’s shares of capital stock are transferred in accordance with the Shareholders Agreement; provided, however, that in no event will any Investor Shareholder or any of its Affiliates be deemed to be a Management Shareholder. “Mandatory Conversion Date” has the meaning set forth in the Charter. “Person” means any individual, corporation, company, firm, partnership, joint venture, limited liability company, estate, trust, business association, organization, Governmental Entity or other entity. “Related Shares” means Class P Shares received by a holder of Class A Shares upon conversion of such holder’s Class A Shares as the result of the occurrence of a Mandatory Conversion Date for the series corresponding to such holder’s Class A Shares. “Riverstone” means (i) Carlyle/Riverstone Knight Investment Partnership, L.P., C/R Knight Partners, L.P., C/R Energy III Knight Non-U.S. Partnership, L.P., Carlyle Energy Coinvestment III, L.P. and Riverstone Energy Coinvestment III, L.P., (ii) any investment funds or other entities sponsored, managed or owned directly or indirectly by Riverstone Holdings, LLC or one of its controlled Affiliates or otherwise under common control with the entities listed in clause (i) or their successors (by merger, consolidation, acquisition of substantially all assets or similar transaction) or with any entity then included in clause (ii), to which any entity previously included in the definition of “Riverstone” transferred, directly or indirectly (including through a series of transfers), Class A Shares after the IPO or Related Shares after a Mandatory Conversion Date, and (iii) any successors (by merger, consolidation, acquisition of substantially all assets or similar transaction) of the foregoing. For the avoidance of doubt, “Riverstone” shall be deemed not to include (A) Carlyle or any portfolio companies of any of the entities contained in clauses (i), (ii) or (iii) or (B) any entity that is not a party to the Shareholders Agreement. “Securities” means securities of every kind and nature, including stock, limited liability company interests, notes, bonds, evidences of indebtedness, options to acquire any of the foregoing, and other business interests of every type. “Shareholder” means a holder of Voting Securities. Exhibit 3.2 “Shareholders Agreement” means the Shareholders Agreement, dated as of February 10, 2011, among the Company and the holders of shares of capital stock of the Company specified therein, as amended from time to time in accordance therewith. “Subsidiary” or “Subsidiaries” means, with respect to any Person, as of any date of determination, any other Person as to which such Person owns, directly or indirectly, or otherwise controls, more than 50% of the voting shares or other similar interests or is general partner or managing member of, or serves in a similar capacity for, such Person (including, in the case of the Company, KMP, KMR and EPB and their respective Subsidiaries). “Supermajority Board Vote” means (i) the affirmative vote of at least ten (10) directors; provided, that if the size of the board of directors has been expanded in accordance with Section 3.3 of the Shareholders Agreement, the number of directors whose affirmative votes are required for a Supermajority Board Vote shall be increased by the number of director seats by which the size of the board of directors has been so expanded; provided, further, that if a number of directors abstain (in such directors’ sole discretion) or are absent from any applicable vote at a meeting at which a quorum is present such that the number of remaining directors is less than the number of directors whose affirmative votes are then required for Supermajority Board Vote, then such absent and/or abstaining directors shall be excluded from such applicable vote and a Supermajority Board Vote shall mean the unanimous vote of such non-excluded directors, in each case (and notwithstanding the final sentence of Section 3.11) so long as such applicable vote does not relate to any matter, purpose or business that was not specified in the Secretary’s notice of the applicable meeting of the board of directors (or an agenda delivered together with such notice) delivered pursuant to Section 3.11, or (ii) any action taken by all members of the board of directors pursuant to Section 3.16. “Total Voting Power” means, as of any date of determination, the total number of votes that may be cast in the election of directors of the Company if all Voting Securities then outstanding were present and voted at a meeting held for such purpose. The percentage of the Total Voting Power of the Company owned by any Person as of any date of determination is the percentage of the Total Voting Power of the Company that is represented by the total number of votes that may be cast in the election of directors of the Company by Voting Securities then owned of record by such Person; provided, that if a holder of Class A Shares or Related Shares owns other Class P Shares, Total Voting Power with respect to that holder shall also include any Class P Shares owned directly or indirectly by such Person with respect to which such Person has voting power. “Voting Securities” means Class A Shares, Class B Shares, Class C Shares, Class P Shares and any other securities of the Company entitled to vote generally in the election of directors of the Company. The undersigned, the Secretary of the Company, hereby certifies that the foregoing Bylaws were adopted by unanimous consent by the board of directors of the Company on May 25, 2012. Exhibit 3.2 /s/ Joseph Listengart Joseph Listengart, Secretary Exhibit 3.2 AMENDMENT NO. 1 TO AMENDED AND RESTATED BYLAWS OF KINDER MORGAN, INC. This Amendment No. 1 to the Amended and Restated Bylaws (the “Bylaws”) of Kinder Morgan, Inc., a Delaware corporation (the “Company”), was duly adopted by unanimous written consent of the Board of Directors of the Company to be effective as of November 26, 2014. Section 3.2(a) of the Bylaws is hereby deleted in its entirety and replaced with the following: “(a) The number of directors shall be no more than sixteen (16) and no less than ten (10), as fixed from time to time by resolution of a majority of the board of directors, and may also be increased in accordance with Section 3.3 of the Shareholders Agreement or reduced to no less than nine (9) in accordance with Section 3.1(a) of the Shareholders Agreement.” 1 Exhibit 3.2 The undersigned, the Secretary of the Company, hereby certifies that the foregoing Amendment No. 1 to the Bylaws was duly adopted by unanimous consent by the Board of Directors of the Company on November 19, 2014. /s/ Adam S. Forman Adam S. Forman Secretary [Signature Page to Bylaws Amendment] Exhibit 10.53 KINDER MORGAN, INC. OFFICERS’ CERTIFICATE PURSUANT TO SECTION 301 OF INDENTURE Each of the undersigned, Anthony Ashley and Adam Forman, the Vice President and Treasurer and the Vice President and Secretary, respectively, of Kinder Morgan, Inc. (the “Corporation”), a Delaware corporation, does hereby establish the terms of a series of senior debt Securities of the Corporation under the Indenture relating to senior debt Securities, dated as of March 1, 2012 (the “Indenture”), between the Corporation and U.S. Bank National Association, as trustee (the “Trustee”), pursuant to resolutions adopted by the Board of Directors of the Corporation, or a committee thereof, on October 15, 2014 and November 24, 2014 and in accordance with Section 301 of the Indenture, as follows: 1. The titles of the Securities shall be “2.000% Senior Notes due 2017” (the “2017 Notes”), “3.050% Senior Notes due 2019” (the “2019 Notes”), “4.300% Senior Notes due 2025” (the “2025 Notes”), “5.300% Senior Notes due 2034” (the “2034 Notes”) and “5.550% Senior Notes due 2045” (the “2045 Notes,” and together with the 2017 Notes, the 2019 Notes, the 2025 Notes and the 2034 Notes, the “Notes”); 2. The aggregate principal amounts of the 2017 Notes, the 2019 Notes, the 2025 Notes, the 2034 Notes and the 2045 Notes which initially may be authenticated and delivered under the Indenture shall be limited to a maximum of $500,000,000, $1,500,000,000, $1,500,000,000, $750,000,000 and $1,750,000,000, respectively, except for Notes authenticated and delivered upon registration of transfer of, or in exchange for, or in lieu of, other Notes pursuant to the terms of the Indenture, and except that any additional principal amount of the Notes may be issued in the future without the consent of Holders of the Notes so long as such additional principal amount of Notes are authenticated as required by the Indenture; 3. The Notes shall be issued on November 26, 2014; the principal of the 2017 Notes shall be payable on December 1, 2017, the principal of the 2019 Notes shall be payable on December 1, 2019, the principal of the 2025 Notes shall be payable on June 1, 2025, the principal of the 2034 Notes shall be payable on December 1, 2034 and the principal of the 2045 Notes shall be payable on June 1, 2045; the Notes will not be entitled to the benefit of a sinking fund; 4. The 2017 Notes shall bear interest at the rate of 2.000% per annum, the 2019 Notes shall bear interest at the rate of 3.050% per annum, the 2025 Notes shall bear interest at the rate of 4.300% per annum, the 2034 Notes shall bear interest at the rate of 5.300% per annum and the 2045 Notes shall bear interest at the rate of 5.550% per annum; in each case which interest shall accrue from November 26, 2014, or from the most recent Interest Payment Date to which interest has been paid or duly provided for, which dates shall be June 1 and December 1 of each year, and such interest shall be payable semi-annually in arrears on June 1 and December 1 of each year, commencing Exhibit 10.53 June 1, 2015, to holders of record at the close of business on the May 15 or November 15, respectively, next preceding each such Interest Payment Date; 5. The principal of, premium, if any, and interest on, the Notes shall be payable at the office or agency of the Corporation maintained for that purpose in the Borough of Manhattan, New York, New York; provided, however, that at the option of the Corporation, payment of interest may be made from such office in the Borough of Manhattan, New York, New York by check mailed to the address of the person entitled thereto as such address shall appear in the Security Register. If at any time there shall be no such office or agency in the Borough of Manhattan, New York, New York, where the Notes may be presented or surrendered for payment, the Corporation shall forthwith designate and maintain such an office or agency in the Borough of Manhattan, New York, New York, in order that the Notes shall at all times be payable in the Borough of Manhattan, New York, New York. The Corporation hereby initially designates the Corporate Trust Office of the Trustee in the Borough of Manhattan, New York, New York, as one such office or agency; 6. U.S. Bank National Association is appointed as the Trustee for the Notes, and U.S. Bank National Association, and any other banking institution hereafter selected by the officers of the Corporation, are appointed agents of the Corporation (a) where the Notes may be presented for registration of transfer or exchange, (b) where notices and demands to or upon the Corporation in respect of the Notes or the Indenture may be made or served and (c) where the Notes may be presented for payment of principal and interest; 7. At any time prior to December 1, 2017, in the case of the 2017 Notes, November 1, 2019, in the case of the 2019 Notes, March 1, 2025, in the case of the 2025 Notes, June 1, 2034, in the case of the 2034 Notes and December 1, 2044 in the case of the 2045 Notes, the notes of the applicable series will be redeemable, at the Corporation’s option, at any time in whole, or from time to time in part, upon not less than 30 and not more than 60 days notice mailed to each Holder of the Notes to be redeemed at the Holder’s address appearing in the Security Register, at a price equal to 100% of the principal amount of the Notes to be redeemed plus accrued and unpaid interest to, but excluding, the Redemption Date, subject to the right of Holders of record on the relevant Record Date to receive interest due on an Interest Payment Date that is on or prior to the Redemption Date, plus a make-whole premium, if any. At any time on or after the applicable date in the preceding sentence, the Notes will be redeemable in whole or in part, at the Corporation’s option, at a redemption price equal to 100% of the principal amount of the Notes to be redeemed plus unpaid interest accrued to, but excluding, the date of redemption. In no event will the Redemption Price ever be less than 100% of the principal amount of the Notes being redeemed plus accrued interest to, but excluding, the Redemption Date. The amount of the make-whole premium on any Note, or portion of a Note, to be redeemed will be equal to the excess, if any, of: (1) the sum of the present values, calculated as of the Redemption Date, of: • each interest payment that, but for the redemption, would have been payable on the Note, or portion of a Note, being redeemed on each interest payment date occurring after the Redemption Date, excluding any accrued interest for the period prior to the Redemption Date; and -2- Exhibit 10.53 • the principal amount that, but for the redemption, would have been payable at the stated maturity of the Note, or portion of a Note, being redeemed; over (2) the principal amount of the Note, or portion of a Note, being redeemed. The present value of interest and principal payments referred to in clause (1) above will be determined in accordance with generally accepted principles of financial analysis. The present values will be calculated by discounting the amount of each payment of interest or principal from the date that each such payment would have been payable, but for the redemption, to the Redemption Date at a discount rate equal to the Treasury Yield, as defined below, plus 0.20% in the case of the 2017 Notes, 0.25% in the case of the 2019 Notes, 0.35% in the case of the 2025 Notes, 0.35% in the case of the 2034 Notes and 0.40% in the case of the 2045 Notes. The make-whole premium will be calculated by an independent investment banking institution of national standing appointed by the Corporation. If the Corporation fails to make that appointment at least 30 business days prior to the redemption date, or if the institution so appointed is unwilling or unable to make the calculation, the financial institution named in the Notes will make the calculation. If the financial institution named in the Notes is unwilling or unable to make the calculation, an independent investment banking institution of national standing appointed by the Trustee will make the calculation. For purposes of determining the make-whole premium, Treasury Yield refers to an annual rate of interest equal to the weekly average yield to maturity of United States Treasury Notes that have a constant maturity that corresponds to the remaining term to maturity of the Notes to be redeemed, calculated to the nearer 1/12 of a year (the “Remaining Term”). The Treasury Yield will be determined as of the third business day immediately preceding the applicable redemption date. The weekly average yields of United States Treasury Notes will be determined by reference to the most recent statistical release published by the Federal Reserve Bank of New York and designated “H.15(519) Selected Interest Rates” or any successor release (the “H.15 Statistical Release”). If the H.15 Statistical Release sets forth a weekly average yield for United States Treasury Notes having a constant maturity that is the same as the Remaining Term of the Notes to be redeemed, then the Treasury Yield will be equal to that weekly average yield. In all other cases, the Treasury Yield will be calculated by interpolation, on a straight-line basis, between the weekly average yields on the United States Treasury Notes that have a constant maturity closest to and greater than the Remaining Term of the Notes to be redeemed and the United States Treasury Notes that have a constant maturity closest to and less than the Remaining Term, in each case as set forth in the H.15 Statistical Release. Any weekly average yields so calculated by interpolation will be rounded to the nearer 0.01%, with any figure of 0.0050% or more being rounded upward. If weekly average yields for United States Treasury Notes are not available in the H.15 Statistical Release or otherwise, then the Treasury Yield will be calculated by interpolation of comparable rates selected by the independent investment banking institution. If less than all of the Notes are to be redeemed, the Trustee will select the Notes to be redeemed by a method that the Trustee deems fair and appropriate. The Trustee may select for -3- Exhibit 10.53 redemption Notes and portions of Notes in amounts of $2,000 or integral multiples of $1,000 in excess thereof. 8. Payment of principal of, and interest on, the Notes shall be without deduction for taxes, assessments or governmental charges paid by Holders of the Notes; 9. The Notes are approved in the form attached hereto as Exhibit A and shall be issued upon original issuance in whole in the form of one or more book-entry Global Securities, and the Depositary shall be The Depository Trust Company; and 10. The Notes shall be entitled to the benefits of the Indenture, including the covenants and agreements of the Corporation set forth therein, except to the extent expressly otherwise provided herein or in the Notes. Any initially capitalized terms not otherwise defined herein shall have the meanings ascribed to such terms in the Indenture. -4- IN WITNESS WHEREOF, each of the undersigned has hereunto signed his or her name this 26th day of November, 2014. Exhibit 10.53 ___/s/ Anthony Ashley______________ Anthony Ashley Vice President and Treasurer ___/s/ Adam Forman________________ Adam Forman Vice President and Secretary Exhibit 10.53 EXHIBIT A [FORM OF GLOBAL NOTE] THIS SECURITY IS A GLOBAL SECURITY WITHIN THE MEANING OF THE INDENTURE HEREINAFTER REFERRED TO AND IS REGISTERED IN THE NAME OF A DEPOSITARY OR A NOMINEE THEREOF. THIS SECURITY MAY NOT BE TRANSFERRED TO, OR REGISTERED OR EXCHANGED FOR SECURITIES REGISTERED IN THE NAME OF, ANY PERSON OTHER THAN THE DEPOSITARY OR A NOMINEE THEREOF AND NO SUCH TRANSFER MAY BE REGISTERED, EXCEPT IN THE LIMITED CIRCUMSTANCES DESCRIBED IN THE INDENTURE. EVERY SECURITY AUTHENTICATED AND DELIVERED UPON REGISTRATION OF TRANSFER OF, OR IN EXCHANGE FOR OR IN LIEU OF, THIS SECURITY SHALL BE A GLOBAL SECURITY SUBJECT TO THE FOREGOING, EXCEPT IN SUCH LIMITED CIRCUMSTANCES. IS SECURITY UNLESS THIS PRESENTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY, A NEW YORK CORPORATION, TO THE CORPORATION OR ITS AGENT FOR REGISTRATION OF TRANSFER, EXCHANGE OR PAYMENT, AND ANY SECURITY ISSUED IS REGISTERED IN THE NAME OF CEDE & CO. OR SUCH OTHER NAME AS IS REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY (AND ANY PAYMENT IS MADE TO CEDE & CO. OR TO SUCH OTHER ENTITY AS IS REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY), ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON IS WRONGFUL IN AS MUCH AS THE REGISTERED OWNER HEREOF, CEDE & CO., HAS AN INTEREST HEREIN. KINDER MORGAN, INC. [__]% NOTE DUE [___] U.S.$[________] NO. [__] CUSIP No. [_________] KINDER MORGAN, INC., a Delaware corporation (herein called the “Corporation,” which term includes any successor Person under the Indenture hereinafter referred to), for value received, hereby promises to pay to CEDE & CO., or registered assigns, the principal sum of [_______________] United States Dollars (U.S.$[_________]) on [__________], 20[__], and to pay interest thereon from [_________], 20[__], or from the most recent Interest Payment Date to which interest has been paid, semi-annually in arrears on [_____] and [_____] in each year, commencing [____], 2015 at the rate of [____]% per annum, until the principal hereof is paid. The amount of interest payable for any period shall be computed on the basis of twelve 30-day months and a 360-day year. The amount of interest payable for any partial period shall be computed on the basis of a 360-day year of twelve 30-day months and the days elapsed in any partial month. In the event that any date on which interest is payable on this Security is not a Business Day, then a payment Exhibit 10.53 of the interest payable on such date will be made on the next succeeding day which is a Business Day (and without any interest or other payment in respect of any such delay) with the same force and effect as if made on the date the payment was originally payable. A “Business Day” shall mean, when used with respect to any Place of Payment, each Monday, Tuesday, Wednesday, Thursday and Friday which is not a day on which banking institutions in that Place of Payment are authorized or obligated by law, executive order or regulation to close. The interest so payable, and punctually paid, on any Interest Payment Date will, as provided in such Indenture, be paid to the Person in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on the Regular Record Date for such interest, which shall be the [______] or [______] (whether or not a Business Day), as the case may be, next preceding such Interest Payment Date. Any such interest not so punctually paid shall forthwith cease to be payable to the Holder on such Regular Record Date and may either be paid to the Person in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on a Special Record Date for the payment of such Defaulted Interest to be fixed by the Trustee, notice of which shall be given to Holders of Securities of this series not less than 10 days prior to such Special Record Date, or be paid at any time in any other lawful manner not inconsistent with the requirements of any securities exchange or automated quotation system on which the Securities of this series may be listed or traded, and upon such notice as may be required by such exchange or automated quotation system, all as more fully provided in such Indenture. The principal of, premium, if any, and interest on, this Security shall be payable at the office or agency of the Corporation maintained for that purpose in the Borough of Manhattan, New York, New York; provided, however, that at the option of the Corporation, payment of interest may be made from such office in the Borough of Manhattan, New York, New York by check mailed to the address of the person entitled thereto as such address shall appear in the Security Register. If at any time there shall be no such office or agency in the Borough of Manhattan, New York, New York where this Security may be presented or surrendered for payment, the Corporation shall forthwith designate and maintain such an office or agency in the Borough of Manhattan, New York, New York, in order that this Security shall at all times be payable in the Borough of Manhattan, New York, New York. The Corporation hereby initially designates the Corporate Trust Office of the Trustee in the Borough of Manhattan, New York, New York, as one such office or agency. Payment of the principal of (and premium, if any) and any such interest on this Security will be made by transfer of immediately available funds to a bank account designated by the Holder in such coin or currency of the United States of America as at the time of payment is legal tender for payment of public and private debts. Reference is hereby made to the further provisions of this Security set forth on the reverse hereof, which further provisions shall for all purposes have the same effect as if set forth at this place. Unless the certificate of authentication hereon has been executed by the Trustee referred to on the reverse hereof by manual signature, this Security shall not be entitled to any benefit under the Indenture or be valid or obligatory for any purpose. Exhibit 10.53 IN WITNESS WHEREOF, the Corporation has caused this instrument to be duly executed. Dated: November 26, 2014 KINDER MORGAN, INC., By: Anthony Ashley Vice President and Treasurer This is one of the Securities designated therein referred to in the within-mentioned Indenture. U.S. BANK NATIONAL ASSOCIATION, As Trustee By: Authorized Signatory Exhibit 10.53 This Security is one of a duly authorized issue of securities of the Corporation (the “Securities”), issued and to be issued in one or more series under an Indenture dated as of March 1, 2012 relating to senior debt Securities (the “Indenture”), between the Corporation and U.S. Bank National Association, as trustee (the “Trustee”, which term includes any successor trustee under the Indenture), to which Indenture and all indentures supplemental thereto reference is hereby made for a statement of the respective rights, limitations of rights, obligations, duties and immunities thereunder of the Corporation, the Trustee and the Holders of the Securities and of the terms upon which the Securities are, and are to be, authenticated and delivered. As provided in the Indenture, the Securities may be issued in one or more series, which different series may be issued in various aggregate principal amounts, may mature at different times, may bear interest, if any, at different rates, may be subject to different redemption provisions, if any, may be subject to different sinking, purchase or analogous funds, if any, may be subject to different covenants and Events of Default and may otherwise vary as in the Indenture provided or permitted. This Security is one of the series designated on the face hereof, originally issued in book-entry only form in the aggregate principal amount of $[________]. This series of Securities may be reopened for issuances of additional Securities without the consent of Holders. [Before [_____], 20[__], the][The] Securities of this series will be redeemable, at the option of the Corporation, at any time in whole, or from time to time in part, upon not less than 30 and not more than 60 days notice mailed to each Holder of these Securities to be redeemed at the Holder’s address appearing in the Security Register, at a price equal to 100% of the principal amount of the Securities of this series to be redeemed plus accrued and unpaid interest to, but excluding, the Redemption Date, subject to the right of Holders of record on the relevant Regular Record Date to receive interest due on an Interest Payment Date that is on or prior to the Redemption Date, plus a make-whole premium, if any. [At any time on or after [_____], 20[__], the Securities of this series will be redeemable in whole or in part, at the option of the Corporation, at a redemption price equal to 100% of the principal amount of the Securities of this series to be redeemed plus unpaid interest accrued to, but excluding, the date of redemption.] In no event will the Redemption Price ever be less than 100% of the principal amount of the Securities of this series being redeemed plus accrued interest to the Redemption Date. The amount of the make-whole premium on any of the Securities of this series, or portion of the Securities of this series, to be redeemed will be equal to the excess, if any, of: (1) the sum of the present values, calculated as of the Redemption Date, of: each interest payment that, but for the redemption, would have been payable on the Security, or portion of a Security, being redeemed on each Interest Payment Date occurring after the Redemption Date, excluding any accrued interest for the period prior to the Redemption Date; and the principal amount that, but for the redemption, would have been payable at the Stated Maturity of the Security, or portion of a Security, being redeemed; over Exhibit 10.53 (2) the principal amount of the Security, or portion of a Security, being redeemed. The present value of interest and principal payments referred to in clause (1) above will be determined in accordance with generally accepted principles of financial analysis. The present values will be calculated by discounting the amount of each payment of interest or principal from the date that each such payment would have been payable, but for the redemption, to the Redemption Date at a discount rate equal to the Treasury Yield, as defined below, plus [____]%. The make-whole premium will be calculated by an independent investment banking institution of national standing appointed by the Corporation. If the Corporation fails to make that appointment at least 30 business days prior to the Redemption Date, or if the institution so appointed is unwilling or unable to make the calculation, Barclays Capital Inc. will make the calculation. If Barclays Capital Inc. is unwilling or unable to make the calculation, an independent investment banking institution of national standing appointed by the Trustee will make the calculation. For purposes of determining the make-whole premium, Treasury Yield refers to an annual rate of interest equal to the weekly average yield to maturity of United States Treasury Notes that have a constant maturity that corresponds to the remaining term to maturity of the Securities of this series to be redeemed, calculated to the nearer 1/12 of a year (the “Remaining Term”). The Treasury Yield will be determined as of the third business day immediately preceding the applicable Redemption Date. The weekly average yields of United States Treasury Notes will be determined by reference to the most recent statistical release published by the Federal Reserve Bank of New York and designated “H.15(519) Selected interest Rates” or any successor release (the “H.15 Statistical Release”). If the H.15 Statistical Release sets forth a weekly average yield for United States Treasury Notes having a constant maturity that is the same as the Remaining Term of the Securities to be redeemed, then the Treasury Yield will be equal to that weekly average yield. In all other cases, the Treasury Yield will be calculated by interpolation, on a straight-line basis, between the weekly average yields on the United States Treasury Notes that have a constant maturity closest to and greater than the Remaining Term of the Securities of this series to be redeemed and the United States Treasury Notes that have a constant maturity closest to and less than the Remaining Term, in each case as set forth in the H.15 Statistical Release. Any weekly average yields so calculated by interpolation will be rounded to the nearer 0.01%, with any figure of 0.0050% or more being rounded upward. If weekly average yields for United States Treasury Notes are not available in the H.15 Statistical Release or otherwise, then the Treasury Yield will be calculated by interpolation of comparable rates selected by the independent investment banking institution. If less than all of the Securities of this series are to be redeemed, the Trustee will select the Securities to be redeemed by a method that the Trustee deems fair and appropriate. The Trustee may select for redemption the Securities of this series and portions of such Securities in amounts of U.S.$2,000 or integral multiples of U.S.$1,000 in excess thereof. In the event of redemption of this Security in part only, a new Security or Securities of this series and of like tenor for the unredeemed portion hereof will be issued in the name of the Holder hereof upon the cancellation hereof. Exhibit 10.53 If an Event of Default with respect to Securities of this series shall occur and be continuing, the principal of, and any premium and accrued but unpaid interest on, the Securities of this series may be declared due and payable in the manner and with the effect provided in the Indenture. The Indenture permits, with certain exceptions as therein provided, the amendment thereof and the modification of the rights and obligations of the Corporation and the rights of the Holders of the Securities of each series to be affected under the Indenture at any time by the Corporation and the Trustee with the consent of not less than the Holders of a majority in aggregate principal amount of the Outstanding Securities of all series to be affected (voting as one class). The Indenture also contains provisions permitting the Holders of a majority in aggregate principal amount of the Outstanding Securities of all affected series (voting as one class), on behalf of the Holders of all Securities of such series, to waive compliance by the Corporation with certain provisions of the Indenture. The Indenture permits, with certain exceptions as therein provided, the Holders of a majority in principal amount of Securities of any series then Outstanding to waive past defaults under the Indenture with respect to such series and their consequences. Any such consent or waiver by the Holder of this Security shall be conclusive and binding upon such Holder and upon all future Holders of this Security and of any Security issued upon the registration of transfer hereof or in exchange herefor or in lieu hereof, whether or not notation of such consent or waiver is made upon this Security. As provided in and subject to the provisions of the Indenture, the Holder of this Security shall not have the right to institute any proceeding with respect to the Indenture or for the appointment of a receiver or trustee or for any other remedy thereunder, unless such Holder shall have previously given the Trustee written notice of a continuing Event of Default with respect to the Securities of this series, the Holders of not less than 25% in principal amount of the Securities of this series at the time Outstanding shall have made written request to the Trustee to institute proceedings in respect of such Event of Default as Trustee and offered the Trustee reasonable indemnity and the Trustee shall not have received from the Holders of a majority in principal amount of Securities of this series at the time Outstanding a direction inconsistent with such request, and shall have failed to institute any such proceeding, for 90 days after receipt of such notice, request and offer of indemnity. The foregoing shall not apply to any suit instituted by the Holder of this Security for the enforcement of any payment of principal hereof or any premium or interest hereon on or after the respective due dates expressed herein. No reference herein to the Indenture and no provision of this Security or of the Indenture shall, without the consent of the Holder, alter or impair the obligation of the Corporation, which is absolute and unconditional, to pay the principal of and any premium and interest on this Security at the times, place(s) and rate, and in the coin or currency, herein prescribed. This Security shall be entitled to the benefits of the Indenture, including the covenants and agreements of the Corporation set forth therein, except to the extent expressly otherwise set forth herein. This Global Security or portion hereof may not be exchanged for Definitive Securities of this series except in the limited circumstances provided in the Indenture. Exhibit 10.53 The Holders of beneficial interests in this Global Security will not be entitled to receive physical delivery of Definitive Securities except as described in the Indenture and will not be considered the Holders thereof for any purpose under the Indenture. The Securities of this series are issuable only in registered form without coupons in denominations of U.S.$1,000 and any integral multiple thereof. As provided in the Indenture and subject to certain limitations therein set forth, Securities of this series are exchangeable for a like aggregate principal amount of Securities of this series and of like tenor of a different authorized denomination, as requested by the Holder surrendering the same. No service charge shall be made for any such registration of transfer or exchange, but the Corporation may require payment of a sum sufficient to cover any tax or other governmental charge payable in connection therewith. Prior to due presentment of this Security for registration of transfer, the Corporation, the Trustee and any agent of the Corporation or the Trustee may treat the Person in whose name this Security is registered as the owner hereof for all purposes, whether or not this Security is overdue, and neither the Corporation, the Trustee nor any such agent shall be affected by notice to the contrary. Obligations of the Corporation under the Indenture and the Securities thereunder, including this Security, are non-recourse to the Corporation's Affiliates, and payable only out of cash flow and assets of the Corporation. The Trustee, and each Holder of a Security by its acceptance hereof, will be deemed to have agreed in the Indenture that (1) none of the Corporation's Affiliates, nor their respective assets, shall be liable for any of the obligations of the Corporation under the Indenture or such Securities, including this Security, and (2) no director, officer, employee, agent or shareholder, as such, of the Corporation, the Trustee or any of their respective Affiliates shall have any personal liability in respect of the obligations of the Corporation under the Indenture or such Securities by reason of his, her or its status. The Indenture contains provisions that relieve the Corporation from the obligation to comply with certain restrictive covenants in the Indenture and for satisfaction and discharge at any time of the entire indebtedness upon compliance by the Corporation with certain conditions set forth in the Indenture. This Security shall be governed by and construed in accordance with the laws of the State of New York. All terms used in this Security which are defined in the Indenture shall have the meanings assigned to them in the Indenture. Exhibit 10.58 CROSS GUARANTEE AGREEMENT This CROSS GUARANTEE AGREEMENT is dated as of November 26, 2014 (as amended, restated, supplemented or otherwise modified from time to time, this “Agreement”), by each of the signatories listed on the signature pages hereto and each of the other entities that becomes a party hereto pursuant to Section 19 (the “Guarantors” and individually, a “Guarantor”), for the benefit of the Guaranteed Parties (as defined below). W I T N E S S E T H: WHEREAS, Kinder Morgan, Inc., a Delaware corporation (“KMI”), and certain of its direct and indirect Subsidiaries have outstanding senior, unsecured Indebtedness and may from time to time issue additional senior, unsecured Indebtedness; WHEREAS, each Guarantor, other than KMI, is a direct or indirect Subsidiary of KMI; WHEREAS, each Guarantor desires to provide the guarantee set forth herein with respect to the Indebtedness of such Guarantors that constitutes the Guaranteed Obligations; and WHEREAS, each Guarantor acknowledges that it will derive substantial direct and indirect benefit from the making of the guarantees hereby; NOW, THEREFORE, in consideration of the premises, the Guarantors hereby agree with each other for the benefit of the Guaranteed Parties as follows: 1. Defined Terms. (a) As used in this Agreement, the following terms have the meanings specified below: “Agreement” has the meaning provided in the preamble hereto. “Bankruptcy Code” means Title 11 of the United States Code, as now or hereafter in effect, or any successor thereto. “Capital Stock” means, with respect to any Person, any and all shares, interests, rights to purchase, warrants, options, participations or other equivalents (however designated) of such Person’s equity, including (i) all common stock and preferred stock, any limited or general partnership interest and any limited liability company member interest, (ii) beneficial interests in trusts, and (iii) any other interest or participation that confers upon a Person the right to receive a share of the profits and losses of, or distribution of assets of, the issuing Person. “CFC” means a Person that is a “controlled foreign corporation” within the meaning of Section 957 of the Internal Revenue Code of 1986, as amended. “Commodity Exchange Act” means the Commodity Exchange Act (7 U.S.C. § 1 et seq.), as amended from time to time, and any successor statute. “Consolidated Assets” means, at the date of any determination thereof, the total assets of KMI and its Subsidiaries as set forth on a consolidated balance sheet of KMI and its Subsidiaries for their most recently completed fiscal quarter, prepared in accordance with GAAP. Exhibit 10.58 “Consolidated Tangible Assets” means, at the date of any determination thereof, Consolidated Assets after deducting therefrom the value, net of any applicable reserves and accumulated amortization, of all goodwill, trade names, trademarks, patents and other like intangible assets, all as set forth, or on a pro forma basis would be set forth, on a consolidated balance sheet of KMI and its Subsidiaries for their most recently completed fiscal quarter, prepared in accordance with GAAP. “Domestic Subsidiary” means any Subsidiary of KMI organized under the laws of any jurisdiction within the United States. “Excluded Subsidiary” means (i) any Subsidiary that is not a Wholly-owned Domestic Operating Subsidiary, (ii) any Domestic Subsidiary that is a Subsidiary of a CFC or any Domestic Subsidiary (including a disregarded entity for U.S. federal income tax purposes) substantially all of whose assets (held directly or through Subsidiaries) consist of Capital Stock of one or more CFCs or Indebtedness of such CFCs, (iii) any Immaterial Subsidiary, (iv) any Subsidiary listed on Schedule III, (v) each of Calnev Pipe Line LLC, SFPP, L.P., Kinder Morgan G.P., Inc. and EPEC Realty, Inc. and each of its Subsidiaries, (vi) any other Subsidiary that is not a Guarantor under the Revolving Credit Agreement Guarantee, (vii) any not-for-profit Subsidiary, (viii) any Subsidiary that is prohibited by a Requirement of Law from guaranteeing the Guaranteed Obligations, and (ix) any Subsidiary acquired by KMI or its Subsidiaries after the date of this Agreement to the extent, and so long as, the financing documentation governing any existing Indebtedness of such Subsidiary that survives such acquisition prohibits such Subsidiary from guaranteeing the Guaranteed Obligations; provided, that notwithstanding the foregoing, any Subsidiary that is party to the Revolving Credit Agreement Guarantee or that Guarantees any senior notes or senior debt securities issued by KMI (other than pursuant to this Agreement) shall not constitute an Excluded Subsidiary for so long as such Guarantee is in effect. “Excluded Swap Obligation” means, with respect to any Guarantor, any Swap Obligation if, and to the extent that, all or a portion of the Guarantee of such Guarantor of such Swap Obligation (or any Guarantee thereof) is or becomes illegal under the Commodity Exchange Act or any rule, regulation or order of the Commodity Futures Trading Commission (or the application or official interpretation of any thereof) by virtue of such Guarantor’s failure for any reason to constitute an “eligible contract participant” as defined in the Commodity Exchange Act and the regulations thereunder at the time the Guarantee of such Guarantor becomes effective with respect to such Swap Obligation. If a Swap Obligation arises under a master agreement governing more than one swap, such exclusion shall apply only to the portion of such Swap Obligation that is attributable to swaps for which such Guarantee is or becomes illegal. “GAAP” means generally accepted accounting principles in the United States of America from time to time, including as set forth in the opinions, statements and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and the Financial Accounting Standards Board. “Governmental Authority” means the government of the United States of America or any other nation, or of any political subdivision thereof, whether state or local, and any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of or pertaining to government (including any supra national bodies such as the European Union or the European Central Bank). “Guarantee” of or by any Person (the “guarantor”) means any obligation, contingent or otherwise, of the guarantor guaranteeing or having the economic effect of guaranteeing any Indebtedness or other obligation of any other Person (the “primary obligor”) in any manner, whether directly or Exhibit 10.58 indirectly, and including any obligation of the guarantor, direct or indirect, (i) to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness or other obligation or to purchase (or to advance or supply funds for the purchase of) any security for the payment thereof, (ii) to purchase or lease property, securities or services for the purpose of assuring the owner of such Indebtedness or other obligation of the payment thereof, (iii) to maintain working capital, equity capital or any other financial statement condition or liquidity of the primary obligor so as to enable the primary obligor to pay such Indebtedness or other obligation or (iv) as an account party in respect of any letter of credit or letter of guaranty issued to support such Indebtedness or obligation; provided that the term Guarantee shall not include endorsements for collection or deposit in the ordinary course of business. “Guarantee Termination Date” has the meaning set forth in Section 2(d). “Guaranteed Obligations” means the Indebtedness set forth on Schedule I hereto, as such schedule may be amended from time to time in accordance with the terms of this Agreement; provided that the term “Guaranteed Obligations” shall exclude any Excluded Swap Obligations. “Guaranteed Parties” means, collectively, (i) in the case of Guaranteed Obligations that are governed by trust indentures, the holders (as that term is defined in the applicable trust indenture) of such Guaranteed Obligations, (ii) in the case of Guaranteed Obligations that are governed by loan agreements, credit agreements, or similar agreements, the lenders providing such loans or credit, and (iii) in the case of Guaranteed Obligations with respect to Hedging Agreements, the counterparties under such agreements. “Guarantor” has the meaning provided in the preamble hereto. Schedule II hereto, as such schedule may be amended from time to time in accordance with the terms of this Agreement, sets forth the name of each Guarantor. “Hedging Agreement” means a financial instrument, agreement or security which hedges or is used to hedge or manage the risk associated with a change in interest rates, foreign currency exchange rates or commodity prices (but excluding any purchase, swap, derivative contract or similar agreement relating to power, electricity or any related commodity product). “Immaterial Subsidiary” means any Subsidiary that is not a Material Subsidiary. “Indebtedness” means, collectively, (i) any senior, unsecured obligation created or assumed by any Person for borrowed money, including all obligations of such Person evidenced by bonds, debentures, notes or similar instruments (other than surety, performance and guaranty bonds), and (ii) all payment obligations of any Person with respect to obligations under Hedging Agreements. “Investment Grade Rating” means a rating equal to or higher than Baa3 by Moody’s and BBB- by S&P; provided, however, that if (i) either of Moody’s or S&P changes its rating system, such ratings shall be the equivalent ratings after such changes or (ii) Moody’s or S&P shall not make a rating of a Guaranteed Obligation publicly available, the references above to Moody’s or S&P or both of them, as the case may be, shall be to a nationally recognized U.S. rating agency or agencies, as the case may be, selected by KMI and the references to the ratings categories above shall be to the corresponding rating categories of such rating agency or rating agencies, as the case may be. “Issuer” means the issuer, borrower, or other applicable primary obligor of a Guaranteed Obligation. “KMI” has the meaning provided in the recitals hereto. Exhibit 10.58 “Lien” means, with respect to any asset (i) any mortgage, deed of trust, lien, pledge, hypothecation, encumbrance, charge or security interest in, on or of such asset, and (ii) the interest of a vendor or a lessor under any conditional sale agreement, capital lease or title retention agreement (or any financing lease having substantially the same economic effect as any of the foregoing) relating to such asset. “Material Subsidiary” means, as at any date of determination, any Subsidiary of KMI whose total tangible assets (for purposes of the below, when combined with the tangible assets of such Subsidiary’s Subsidiaries, after eliminating intercompany obligations) as at such date of determination are greater than or equal to 5% of Consolidated Tangible Assets as of the last day of the fiscal quarter most recently ended for which financial statements of KMI have been filed with the SEC. “Moody’s” means Moody’s Investors Service, Inc. and its successors. “Operating Subsidiary” means any operating company that is a Subsidiary of KMI. “Person” means any natural person, corporation, limited liability company, trust, joint venture, association, company, partnership, Governmental Authority or other entity. “Qualified ECP Guarantor” means, in respect of any Swap Obligation, each Guarantor that has total assets exceeding $10,000,000 at the time the relevant Guarantee becomes effective with respect to such Swap Obligation or such other person as constitutes an “eligible contract participant” under the Commodity Exchange Act or any regulations promulgated thereunder and can cause another person to qualify as an “eligible contract participant” at such time by entering into a keepwell under Section 1a (18)(A)(v)(II) of the Commodity Exchange Act. “Rating Agencies” means Moody’s and S&P; provided that, if at the relevant time neither Moody’s nor S&P shall be rating the relevant Guaranteed Obligation, then “Rating Agencies” shall mean another nationally recognized rating service that rates such Guaranteed Obligation. “Rating Date” means the date immediately prior to the earlier of (i) the occurrence of a Release Event and (ii) public notice of the intention to effect a Release Event. “Rating Decline” means, with respect to a Guaranteed Obligation, the occurrence of the following on, or within 90 days after, the date of the occurrence of a Release Event or of public notice of the intention to effect a Release Event (which period may be extended so long as the rating of such Guaranteed Obligation is under publicly announced consideration for possible downgrade by either of the Rating Agencies): (i) in the event such Guaranteed Obligation is assigned an Investment Grade Rating by both Rating Agencies on the Rating Date, the rating of such Guaranteed Obligation by one or both of the Rating Agencies shall be below an Investment Grade Rating; or (ii) in the event such Guaranteed Obligation is rated below an Investment Grade Rating by either of the Rating Agencies on the Rating Date, any such below-Investment Grade Rating of such Guaranteed Obligation shall be decreased by one or more gradations (including gradations within rating categories as well as between rating categories). “Release Event” has the meaning set forth in Section 6(b). “Requirement of Law” means any law, statute, code, ordinance, order, determination, rule, regulation, judgment, decree, injunction, franchise, permit, certificate, license, authorization or other directive or requirement (whether or not having the force of law), including environmental laws, energy regulations and occupational, safety and health standards or controls, of any Governmental Authority. Exhibit 10.58 “Revolving Credit Agreement” means the Revolving Credit Agreement, dated as of September 19, 2014, among KMI, the lenders party thereto and Barclays Bank PLC, as administrative agent, as such credit agreement may be amended, modified, supplemented or restated from time to time, or refunded, refinanced, restructured, replaced, renewed, repaid or extended from time to time (whether with the original agents and lenders or other agents or lenders or trustee or otherwise, and whether provided under the original credit agreement or other credit agreements or note indentures or otherwise), including, without limitation, increasing the amount of available borrowings or other Indebtedness thereunder. “Revolving Credit Agreement Guarantee” means the Guarantee Agreement, dated as of November 26, 2014, made by the Subsidiaries of KMI party thereto in favor of Barclays Bank PLC, as administrative agent, for the benefit of the lenders and the issuing banks under the Revolving Credit Agreement, as such guarantee agreement may be amended, modified, supplemented or restated from time to time, and as it may be replaced or renewed from time to time in connection with any amendment, modification, supplement, restatement, refunding, refinancing, restructuring, replacement, renewal, repayment, or extension of any Revolving Credit Agreement from time to time. “S&P” means Standard & Poor’s Rating Services, a division of The McGraw-Hill Companies, Inc., and its successors. “SEC” means the United States Securities and Exchange Commission. “Subsidiary” means, with respect to any Person (the “parent”) at any date, any corporation, limited liability company, partnership, association or other entity the accounts of which would be consolidated with those of the parent in the parent’s consolidated financial statements if such financial statements were prepared in accordance with GAAP as of such date, as well as any other corporation, limited liability company, partnership, association or other entity (a) of which securities or other ownership interests representing more than 50% of the equity or more than 50% of the ordinary voting power or, in the case of a partnership, more than 50% of the general partner interests are, as of such date, owned, controlled or held, or (b) that is, as of such date, otherwise controlled, by the parent or one or more Subsidiaries of the parent or by the parent and one or more Subsidiaries of the parent. Unless the context otherwise clearly requires, references in this Agreement to a “Subsidiary” or the “Subsidiaries” refer to a Subsidiary or the Subsidiaries of KMI. Notwithstanding the foregoing, Plantation Pipe Line Company, a Delaware and Virginia corporation, shall not be a Subsidiary of KMI until such time as its assets and liabilities, profit or loss and cash flow are required under GAAP to be consolidated with those of KMI. “Swap Obligation” means, with respect to any Guarantor, any obligation to pay or perform under any agreement, contract or transaction that constitutes a “swap” within the meaning of Section 1a (47) of the Commodity Exchange Act. “Wholly-owned Domestic Operating Subsidiary” means any Wholly-owned Subsidiary that constitutes (i) a Domestic Subsidiary and (ii) an Operating Subsidiary. “Wholly-owned Subsidiary” means a Subsidiary of which all issued and outstanding Capital Stock (excluding in the case of a corporation, directors’ qualifying shares) is directly or indirectly owned by KMI. The words “hereof”, “herein” and “hereunder” and words of similar import when used in this Agreement shall refer to this Agreement as a whole and not to any particular provision of this (b) Exhibit 10.58 Agreement, and Section references are to Sections of this Agreement unless otherwise specified. The words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”. (c) The meanings given to terms defined herein shall be equally applicable to both the singular and plural forms of such terms. 2. Guarantee. (a) Subject to the provisions of Section 2(b), each of the Guarantors hereby, jointly and severally, unconditionally and irrevocably, guarantees, as primary obligor and not merely as surety, for the benefit of the Guaranteed Parties, the prompt and complete payment when due (whether at the stated maturity, by acceleration or otherwise) of the Guaranteed Obligations; provided that each Guarantor shall be released from its respective guarantee obligations under this Agreement as provided in Section 6 (b). Upon the failure of an Issuer to punctually pay any Guaranteed Obligation, each Guarantor shall, upon written demand by the applicable Guaranteed Party to such Guarantor, pay or cause to be paid such amounts. (b) Anything herein to the contrary notwithstanding, the maximum liability of each Guarantor hereunder shall in no event exceed the amount that can be guaranteed by such Guarantor under the Bankruptcy Code or any applicable laws relating to fraudulent conveyances, fraudulent transfers or the insolvency of debtors after giving full effect to the liability under this Agreement and its related contribution rights set forth in this Section 2, but before taking into account any liabilities under any other Guarantees. (c) Each Guarantor agrees that the Guaranteed Obligations may at any time and from time to time exceed the amount of the liability of such Guarantor hereunder (as a result of the limitations set forth in Section 2(b) or elsewhere in this Agreement) without impairing this Agreement or affecting the rights and remedies of any Guaranteed Party hereunder. (d) No payment or payments made by any Issuer, any of the Guarantors, any other guarantor or any other Person or received or collected by any Guaranteed Party from any Issuer, any of the Guarantors, any other guarantor or any other Person by virtue of any action or proceeding or any set- off or appropriation or application at any time or from time to time in reduction of or in payment of any Guaranteed Obligation shall be deemed to modify, reduce, release or otherwise affect the liability of any Guarantor hereunder, which shall, notwithstanding any such payment or payments, other than payments made by such Guarantor in respect of such Guaranteed Obligation or payments received or collected from such Guarantor in respect of such Guaranteed Obligation, remain liable for the Guaranteed Obligations up to the maximum liability of such Guarantor hereunder until all Guaranteed Obligations (other than any contingent indemnity obligations not then due and any letters of credit that remain outstanding which have been fully cash collateralized or otherwise back-stopped to the reasonable satisfaction of the applicable issuing bank) shall have been discharged by payment in full or shall have been deemed paid and discharged by defeasance pursuant to the terms of the instruments governing such Guaranteed Obligations (the “Guarantee Termination Date”). (e) If and to the extent required in order for the obligations of any Guarantor hereunder to be enforceable under applicable federal, state and other laws relating to the insolvency of debtors, the maximum liability of such Guarantor hereunder shall be limited to the greatest amount which can lawfully be guaranteed by such Guarantor under such laws, after giving effect to any rights of contribution, reimbursement and subrogation arising hereunder. Each Guarantor acknowledges and agrees Exhibit 10.58 that, to the extent not prohibited by applicable law, (i) such Guarantor (as opposed to its creditors, representatives of creditors or bankruptcy trustee, including such Guarantor in its capacity as debtor in possession exercising any powers of a bankruptcy trustee) has no personal right under such laws to reduce, or request any judicial relief that has the effect of reducing, the amount of its liability under this Agreement, (ii) such Guarantor (as opposed to its creditors, representatives of creditors or bankruptcy trustee, including such Guarantor in its capacity as debtor in possession exercising any powers of a bankruptcy trustee) has no personal right to enforce the limitation set forth in this Section 2(e) or to reduce, or request judicial relief reducing, the amount of its liability under this Agreement, and (iii) the limitation set forth in this Section 2(e) may be enforced only to the extent required under such laws in order for the obligations of such Guarantor under this Agreement to be enforceable under such laws and only by or for the benefit of a creditor, representative of creditors or bankruptcy trustee of such Guarantor or other Person entitled, under such laws, to enforce the provisions hereof. 3. Right of Contribution. Each Guarantor hereby agrees that to the extent that a Guarantor shall have paid more than its proportionate share of any payment made hereunder (including by way of set-off rights being exercised against it), such Guarantor shall be entitled to seek and receive contribution from and against any other Guarantor hereunder who has not paid its proportionate share of such payment as set forth in this Section 3. To the extent that any Guarantor shall be required hereunder to pay any portion of any Guaranteed Obligation guaranteed hereunder exceeding the greater of (a) the amount of the value actually received by such Guarantor and its Subsidiaries from such Guaranteed Obligation and (b) the amount such Guarantor would otherwise have paid if such Guarantor had paid the aggregate amount of such Guaranteed Obligation guaranteed hereunder (excluding the amount thereof repaid by the Issuer of such Guaranteed Obligation) in the same proportion as such Guarantor’s net worth on the date enforcement is sought hereunder bears to the aggregate net worth of all the Guarantors on such date, then such Guarantor shall be reimbursed by such other Guarantors for the amount of such excess, pro rata, based on the respective net worth of such other Guarantors on such date; provided that any Guarantor’s right of reimbursement shall be subject to the terms and conditions of Section 5 hereof. For purposes of determining the net worth of any Guarantor in connection with the foregoing, all Guarantees of such Guarantor other than pursuant to this Agreement will be deemed to be enforceable and payable after its obligations pursuant to this Agreement. The provisions of this Section 3 shall in no respect limit the obligations and liabilities of any Guarantor to the Guaranteed Parties, and each Guarantor shall remain liable to the Guaranteed Parties for the full amount guaranteed by such Guarantor hereunder. 4. No Right of Set-off. No Guaranteed Party shall have, as a result of this Agreement, any right of set-off against any amount owing by such Guaranteed Party to or for the credit or the account of a Guarantor. 5. No Subrogation. Notwithstanding any payment or payments made by any of the Guarantors hereunder, no Guarantor shall be entitled to be subrogated to any of the rights (or if subrogated by operation of law, such Guarantor hereby waives such rights to the extent permitted by applicable law) of any Guaranteed Party against any Issuer or any other Guarantor or any collateral security or guarantee or right of offset held by any Guaranteed Party for the payment of any Guaranteed Obligation, nor shall any Guarantor seek or be entitled to seek any contribution or reimbursement from any Issuer or any other Guarantor in respect of payments made by such Guarantor hereunder, until the Guarantee Termination Date. If any amount shall be paid to any Guarantor on account of such subrogation, contribution or reimbursement rights at any time prior to the Guarantee Termination Date, such amount shall be held by such Guarantor in trust for the applicable Guaranteed Parties, segregated from other funds of such Guarantor, and shall, forthwith upon receipt by such Guarantor, be turned over to the applicable Guaranteed Parties in the exact form received by such Guarantor (duly indorsed by such Exhibit 10.58 Guarantor to the applicable Guaranteed Parties if required), to be applied against the applicable Guaranteed Obligation, whether due or to become due. 6. Amendments, etc. with Respect to the Guaranteed Obligations; Waiver of Rights; Release. (a) Each Guarantor shall remain obligated hereunder notwithstanding that, without any reservation of rights against any Guarantor and without notice to or further assent by any Guarantor, (i) any demand for payment of any Guaranteed Obligation made by any Guaranteed Party may be rescinded by such party and any Guaranteed Obligation continued, (ii) a Guaranteed Obligation, or the liability of any other party upon or for any part thereof, or any collateral security or guarantee therefor or right of offset with respect thereto, may, from time to time, in whole or in part, be renewed, extended, amended, modified, accelerated, compromised, waived, allowed to lapse, surrendered or released by any Guaranteed Party, (iii) the instruments governing any Guaranteed Obligation may be amended, modified, supplemented or terminated, in whole or in part, and (iv) any collateral security, guarantee or right of offset at any time held by any Guaranteed Party for the payment of any Guaranteed Obligation may be sold, exchanged, waived, allowed to lapse, surrendered or released. No Guaranteed Party shall have any obligation to protect, secure, perfect or insure any Lien at any time held by it as security for the Guaranteed Obligations or for this Agreement or any property subject thereto. When making any demand hereunder against any Guarantor, a Guaranteed Party may, but shall be under no obligation to, make a similar demand on the Issuer of the applicable Guaranteed Obligation or any other Guarantor or any other person, and any failure by a Guaranteed Party to make any such demand or to collect any payments from such Issuer or any other Guarantor or any other person or any release of such Issuer or any other Guarantor or any other person shall not relieve any Guarantor in respect of which a demand or collection is not made or any Guarantor not so released of its several obligations or liabilities hereunder, and shall not impair or affect the rights and remedies, express or implied, or as a matter of law, of any Guaranteed Party against any Guarantor. For the purposes hereof “demand” shall include the commencement and continuance of any legal proceedings. (b) A Guarantor shall be automatically released from its guarantee hereunder upon release of such Guarantor from the Revolving Credit Agreement Guarantee, including upon consummation of any transaction resulting in such Guarantor ceasing to constitute a Subsidiary or upon any Guarantor becoming an Excluded Subsidiary (such transaction or event, a “Release Event”). (c) Upon the occurrence of a Release Event, each Guaranteed Obligation for which such released Guarantor was the Issuer shall be automatically released from the provisions of this Agreement and shall cease to constitute a Guaranteed Obligation hereunder; provided that in the case of any Guaranteed Obligation that has been assigned an Investment Grade Rating by the Rating Agencies, such Guaranteed Obligation shall be so released, effective as of the 91st day after the occurrence of the Release Event, if and only if a Rating Decline with respect to such Guaranteed Obligation does not occur. 7. Guarantee Absolute and Unconditional. (a) Each Guarantor waives any and all notice of the creation, contraction, incurrence, renewal, extension, amendment, waiver or accrual of any of the Guaranteed Obligations, and notice of or proof of reliance by any Guaranteed Party upon this Agreement or acceptance of this Agreement. To the fullest extent permitted by applicable law, each Guarantor waives diligence, promptness, presentment, protest and notice of protest, demand for payment or performance, notice of default or nonpayment, notice of acceptance and any other notice in respect of the Guaranteed Obligations or any part of them, and any defense arising by reason of any disability or other defense of any Issuer or any of the Guarantors Exhibit 10.58 with respect to the Guaranteed Obligations. Each Guarantor understands and agrees that this Agreement shall be construed as a continuing, absolute and unconditional guarantee of payment without regard to (i) the validity, regularity or enforceability of any of the Guaranteed Obligations, the indenture, loan agreement, note or other instrument evidencing or governing any of the Guaranteed Obligations or any collateral security therefor or guarantee or right of offset with respect thereto at any time or from time to time held by any Guaranteed Party, (ii) any defense, set-off or counterclaim (other than a defense of payment or performance) that may at any time be available to or be asserted by any Issuer against any Guaranteed Party or (iii) any other circumstance whatsoever (with or without notice to or knowledge of any Issuer or such Guarantor) that constitutes, or might be construed to constitute, an equitable or legal discharge of any Issuer for any of the Guaranteed Obligations, or of such Guarantor under this Agreement, in bankruptcy or in any other instance. When pursuing its rights and remedies hereunder against any Guarantor, any Guaranteed Party may, but shall be under no obligation to, pursue such rights and remedies as it may have against the Issuer or any other Person or against any collateral security or guarantee for the Guaranteed Obligations or any right of offset with respect thereto, and any failure by any Guaranteed Party to pursue such other rights or remedies or to collect any payments from the Issuer or any such other Person or to realize upon any such collateral security or guarantee or to exercise any such right of offset, or any release of the Issuer or any such other Person or any such collateral security, guarantee or right of offset, shall not relieve such Guarantor of any liability hereunder, and shall not impair or affect the rights and remedies, whether express, implied or available as a matter of law, of the other Guaranteed Parties against such Guarantor. (b) This Agreement shall remain in full force and effect and be binding in accordance with and to the extent of its terms upon each Guarantor and the successors and assigns thereof and shall inure to the benefit of the Guaranteed Parties and their respective successors, indorsees, transferees and assigns until the Guarantee Termination Date. 8. Reinstatement. This Agreement shall continue to be effective, or be reinstated, as the case may be, if at any time payment, or any part thereof, of any of the Guaranteed Obligations is rescinded or must otherwise be restored or returned by any Guaranteed Party upon the insolvency, bankruptcy, dissolution, liquidation or reorganization of any Issuer or any Guarantor, or upon or as a result of the appointment of a receiver, intervenor or conservator of, or trustee or similar officer for, any Issuer or any Guarantor or any substantial part of its property, or otherwise, all as though such payments had not been made. 9. Payments. Each Guarantor hereby guarantees that payments hereunder will be paid to the applicable Guaranteed Parties without set-off or counterclaim in dollars. 10. Representations and Warranties. Each Guarantor hereby represents and warrants to each Guaranteed Party that the following representations and warranties are true and correct in all material respects as of the date of this Agreement or as of the date such Guarantor became a party to this Agreement, as applicable: (a) such Guarantor (i) is a corporation, partnership or limited liability company duly organized or formed, validly existing and in good standing under the laws of the state of its incorporation, organization or formation, (ii) has all requisite corporate, partnership, limited liability company or other power and all material governmental licenses, authorizations, consents and approvals required to carry on its business as now conducted and (iii) is duly qualified to do business and is in good standing in every jurisdiction in which the failure to be so qualified would have a material adverse effect on its ability to perform its obligations under this Agreement; Exhibit 10.58 (b) such Guarantor has all requisite corporate (or other organizational) power and authority to execute and deliver and to perform its obligations under this Agreement, and all such actions have been duly authorized by all necessary proceedings on its behalf; (c) this Agreement has been duly and validly executed and delivered by or on behalf of such Guarantor and constitutes the valid and legally binding agreement of such Guarantor, enforceable against such Guarantor in accordance with its terms, except (i) as may be limited by bankruptcy, insolvency, reorganization, moratorium, fraudulent transfer, fraudulent conveyance or other similar laws relating to or affecting the enforcement of creditors’ rights generally, and by general principles of equity (including principles of good faith, reasonableness, materiality and fair dealing) which may, among other things, limit the right to obtain equitable remedies (regardless of whether considered in a proceeding in equity or at law) and (ii) as to the enforceability of provisions for indemnification for violation of applicable securities laws, limitations thereon arising as a matter of law or public policy; (d) no authorization, consent, approval, license or exemption of or registration, declaration or filing with any Governmental Authority is necessary for the valid execution and delivery of, or the performance by such Guarantor of its obligations hereunder, except those that have been obtained and such matters relating to performance as would ordinarily be done in the ordinary course of business after the date of this Agreement or as of the date such Guarantor became a party to this Agreement, as applicable; and (e) neither the execution and delivery of, nor the performance by such Guarantor of its obligations under, this Agreement will (i) breach or violate any applicable Requirement of Law, (ii) result in any breach or violation of any of the terms, covenants, conditions or provisions of, or constitute a default under, or result in the creation or imposition of (or the obligation to create or impose) any Lien upon any of its property or assets (other than Liens created or contemplated by this Agreement) pursuant to the terms of, any indenture, mortgage, deed of trust, agreement or other instrument to which it or any of its Subsidiaries is party or by which any of its properties or assets, or those of any of its Subsidiaries is bound or to which it is subject, except for breaches, violations and defaults under clauses (i) and (ii) that neither individually nor in the aggregate could reasonably be expected to result in a material adverse effect on its ability to perform its obligations under this Agreement, or (iii) violate any provision of the organizational documents of such Guarantor. 11. Rights of Guaranteed Parties. Each Guarantor acknowledges and agrees that any changes in the identity of the Persons from time to time comprising the Guaranteed Parties gives rise to an equivalent change in the Guaranteed Parties, without any further act. Upon such an occurrence, the persons then comprising the Guaranteed Parties are vested with the rights, remedies and discretions of the Guaranteed Parties under this Agreement. 12. Notices. (a) All notices, requests, demands and other communications to any Guarantor pursuant hereto shall be in writing and mailed, telecopied or delivered to such Guarantor in care of KMI, 1001 Louisiana Street, Suite 1000, Houston, Texas 77002, Attention: Treasurer, Telecopy: (713) 445-8302. (b) KMI will provide a copy of this Agreement, including the most recently amended schedules and supplements hereto, to any Guaranteed Party upon written request to the address set forth in Section 12(a); provided, however, that KMI’s obligations under this Section 12(b) shall be deemed satisfied if KMI has filed a copy of this Agreement, including the most recently amended schedules and Exhibit 10.58 supplements hereto, with the SEC within three months preceding the date on which KMI receives such written request. 13. Counterparts. This Agreement may be executed by one or more of the parties to this Agreement on any number of separate counterparts (including by facsimile or other electronic transmission), and all of said counterparts taken together shall be deemed to constitute one and the same instrument. A set of the copies of this Agreement signed by all the parties shall be lodged with KMI. 14. Severability. Any provision of this Agreement that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction. The parties hereto shall endeavor in good-faith negotiations to replace the invalid, illegal or unenforceable provisions with valid provisions the economic effect of which comes as close as possible to that of the invalid, illegal or unenforceable provisions. 15. Integration. This Agreement represents the agreement of each Guarantor with respect to the subject matter hereof, and there are no promises, undertakings, representations or warranties by any Guaranteed Party relative to the subject matter hereof not expressly set forth or referred to herein. 16. Amendments; No Waiver; Cumulative Remedies. (a) None of the terms or provisions of this Agreement may be waived, amended, supplemented or otherwise modified except by a written instrument executed by the affected Guarantors and KMI. (b) The Guarantors may amend or supplement this Agreement by a written instrument executed by all Guarantors: (i) to cure any ambiguity, defect or inconsistency; (ii) to reflect a change in the Guarantors or the Guaranteed Obligations made in accordance with this Agreement; (iii) to make any change that would provide any additional rights or benefits to the Guaranteed Parties or that would not adversely affect the legal rights hereunder of any Guaranteed Party in any material respect; or (iv) to conform this Agreement to any change made to the Revolving Credit Agreement or to the Revolving Credit Agreement Guarantee. Except as set forth in this clause (b) or otherwise provided herein, the Guarantors may not amend, supplement or otherwise modify this Agreement prior to the Guarantee Termination Date without the prior written consent of the holders of the majority of the outstanding principal amount of the Guaranteed Obligations (excluding obligations with respect to Hedging Agreements). Notwithstanding the foregoing, in the case of an amendment that would reasonably be expected to adversely, materially and disproportionately affect Guaranteed Parties with Guaranteed Obligations existing under Hedging Agreements relative to the other Guaranteed Parties, the foregoing exclusion of obligations with respect to Hedging Agreements shall not apply, and the outstanding principal amount attributable to each such Guaranteed Party’s Guaranteed Obligations shall be deemed to be equal to the termination payment that Exhibit 10.58 would be due to such Guaranteed Party as if the valuation date were an “Early Termination Date” under and calculated in accordance with each applicable Hedging Agreement. (c) No Guaranteed Party shall by any act, delay, indulgence, omission or otherwise be deemed to have waived any right or remedy hereunder or to have acquiesced in any breach of any of the terms and conditions hereof. No failure to exercise, nor any delay in exercising, on the part of any Guaranteed Party, any right, power or privilege hereunder shall operate as a waiver thereof. No single or partial exercise of any right, power or privilege hereunder shall preclude any other or further exercise thereof or the exercise of any other right, power or privilege. A waiver by a Guaranteed Party of any right or remedy hereunder on any one occasion shall not be construed as a bar to any right or remedy that such Guaranteed Party would otherwise have on any future occasion. The rights, remedies, powers and privileges herein provided are cumulative, may be exercised singly or concurrently and are not exclusive of any other rights or remedies provided by law. (d) 17. Section Headings. The Section headings used in this Agreement are for convenience of reference only and are not to affect the construction hereof or be taken into consideration in the interpretation hereof. 18. Successors and Assigns. This Agreement shall be binding upon the successors and assigns of each Guarantor and shall inure to the benefit of the Guaranteed Parties and their respective successors and permitted assigns, except that no Guarantor may assign, transfer or delegate any of its rights or obligations under this Agreement except pursuant to a transaction permitted by the Revolving Credit Agreement and in connection with a corresponding assignment under the Revolving Credit Agreement Guarantee. 19. Additional Guarantors. (a) KMI shall cause each Subsidiary (other than any Excluded Subsidiary) formed or otherwise purchased or acquired after the date of this Agreement (including each Subsidiary that ceases to constitute an Excluded Subsidiary after the date of this Agreement) to execute a supplement to this Agreement and become a Guarantor within 45 days of the occurrence of the applicable event specified in this Section 19(a). (b) Each Subsidiary of KMI that becomes, at the request of KMI, or that is required pursuant to Section 19(a) to become, a party to this Agreement shall become a Guarantor, with the same force and effect as if originally named as a Guarantor herein, for all purposes of this Agreement upon execution and delivery by such Subsidiary of a written supplement substantially in the form of Annex A hereto. The execution and delivery of any instrument adding an additional Guarantor as a party to this Agreement shall not require the consent of any other Guarantor hereunder. The rights and obligations of each Guarantor hereunder shall remain in full force and effect notwithstanding the addition of any new Guarantor as a party to this Agreement. 20. Additional Guaranteed Obligations. Any Indebtedness issued by a Guarantor or for which a Guarantor otherwise becomes obligated after the date of this Agreement shall become a Guaranteed Obligation upon the execution by all Guarantors of a notation of guarantee substantially in the form of Annex B hereto, which shall be affixed to the instrument or instruments evidencing such Indebtedness. Each such notation of guarantee shall be signed on behalf of each Guarantor by a duly authorized officer prior to the authentication or issuance of such Indebtedness. Exhibit 10.58 21. GOVERNING LAW. THIS AGREEMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK. 22. Keepwell. Each Qualified ECP Guarantor hereby jointly and severally absolutely, unconditionally and irrevocably undertakes to provide such funds or other support as may be needed from time to time by each other Guarantor to honor all of its obligations under this Agreement in respect of Swap Obligations (provided, however, that each Qualified ECP Guarantor shall only be liable under this Section 22 for the maximum amount of such liability that can be hereby incurred without rendering its obligations under this Section 22, or otherwise under this Agreement, voidable under applicable law relating to fraudulent conveyance or fraudulent transfer, and not for any greater amount). The obligations of each Qualified ECP Guarantor under this Section shall remain in full force and effect until the Guarantee Termination Date. Each Qualified ECP Guarantor intends that this Section 22 constitute, and this Section 22 shall be deemed to constitute, a “keepwell, support, or other agreement” for the benefit of each other Guarantor for all purposes of Section 1a(18)(A)(v)(II) of the Commodity Exchange Act. [Signature pages follow] IN WITNESS WHEREOF, each of the undersigned has caused this Agreement to be duly executed and delivered by its duly authorized officer or other representative as of the day and year first above written. Exhibit 10.58 KINDER MORGAN, INC. By: /s/ Anthony B. Ashley Name: Anthony B. Ashley Title: Treasurer AGNES B CRANE, LLC AMERICAN PETROLEUM TANKERS II LLC AMERICAN PETROLEUM TANKERS III LLC AMERICAN PETROLEUM TANKERS IV LLC AMERICAN PETROLEUM TANKERS LLC AMERICAN PETROLEUM TANKERS PARENT LLC AMERICAN PETROLEUM TANKERS V LLC AMERICAN PETROLEUM TANKERS VI LLC AMERICAN PETROLEUM TANKERS VII LLC APT FLORIDA LLC APT INTERMEDIATE HOLDCO LLC APT NEW INTERMEDIATE HOLDCO LLC APT PENNSYLVANIA LLC APT SUNSHINE STATE LLC AUDREY TUG LLC BEAR CREEK STORAGE COMPANY, L.L.C. BETTY LOU LLC CAMINO REAL GATHERING COMPANY, L.L.C. CANTERA GAS COMPANY LLC CDE PIPELINE LLC CENTRAL FLORIDA PIPELINE LLC CHEYENNE PLAINS GAS PIPELINE COMPANY, L.L.C. CIG GAS STORAGE COMPANY LLC CIG PIPELINE SERVICES COMPANY, L.L.C. CIMMARRON GATHERING LLC COLORADO INTERSTATE GAS COMPANY, L.L.C. COLORADO INTERSTATE ISSUING CORPORATION COPANO DOUBLE EAGLE LLC COPANO ENERGY FINANCE CORPORATION COPANO ENERGY, L.L.C. COPANO ENERGY SERVICES/UPPER GULF COAST LLC COPANO FIELD SERVICES GP, L.L.C. COPANO FIELD SERVICES/NORTH TEXAS, L.L.C. COPANO FIELD SERVICES/SOUTH TEXAS LLC COPANO FIELD SERVICES/UPPER GULF COAST LLC COPANO LIBERTY, LLC COPANO NGL SERVICES (MARKHAM), L.L.C. Exhibit 10.58 COPANO NGL SERVICES LLC COPANO PIPELINES GROUP, L.L.C. COPANO PIPELINES/NORTH TEXAS, L.L.C. COPANO PIPELINES/ROCKY MOUNTAINS, LLC COPANO PIPELINES/SOUTH TEXAS LLC COPANO PIPELINES/UPPER GULF COAST LLC COPANO PROCESSING LLC COPANO RISK MANAGEMENT LLC COPANO/WEBB-DUVAL PIPELINE LLC CPNO SERVICES LLC DAKOTA BULK TERMINAL, INC. DELTA TERMINAL SERVICES LLC EAGLE FORD GATHERING LLC EL PASO CHEYENNE HOLDINGS, L.L.C. EL PASO CITRUS HOLDINGS, INC. EL PASO CNG COMPANY, L.L.C. EL PASO ENERGY SERVICE COMPANY, L.L.C. EL PASO LLC EL PASO MIDSTREAM GROUP LLC EL PASO NATURAL GAS COMPANY, L.L.C. EL PASO NORIC INVESTMENTS III, L.L.C. EL PASO PIPELINE CORPORATION EL PASO PIPELINE GP COMPANY, L.L.C. EL PASO PIPELINE HOLDING COMPANY, L.L.C. EL PASO PIPELINE LP HOLDINGS, L.L.C. EL PASO PIPELINE PARTNERS, L.P. By El Paso Pipeline GP Company, L.L.C., its general partner EL PASO PIPELINE PARTNERS OPERATING COMPANY, L.L.C. EL PASO RUBY HOLDING COMPANY, L.L.C. EL PASO TENNESSEE PIPELINE CO., L.L.C. ELBA EXPRESS COMPANY, L.L.C. ELIZABETH RIVER TERMINALS LLC EMORY B CRANE, LLC EPBGP CONTRACTING SERVICES LLC EP ENERGY HOLDING COMPANY EP RUBY LLC EPTP ISSUING CORPORATION FERNANDINA MARINE CONSTRUCTION MANAGEMENT LLC FRANK L. CRANE, LLC GENERAL STEVEDORES GP, LLC GENERAL STEVEDORES HOLDINGS LLC GLOBAL AMERICAN TERMINALS LLC HAMPSHIRE LLC HARRAH MIDSTREAM LLC HBM ENVIRONMENTAL, INC. ICPT, L.L.C J.R. NICHOLLS LLC JAVELINA TUG LLC Exhibit 10.58 JEANNIE BREWER LLC JV TANKER CHARTERER LLC KINDER MORGAN (DELAWARE), INC. KINDER MORGAN 2-MILE LLC KINDER MORGAN ADMINISTRATIVE SERVICES TAMPA LLC KINDER MORGAN ALTAMONT LLC KINDER MORGAN AMORY LLC KINDER MORGAN ARROW TERMINALS HOLDINGS, INC. KINDER MORGAN ARROW TERMINALS, L.P. By Kinder Morgan River Terminals, LLC, its general partner KINDER MORGAN BALTIMORE TRANSLOAD TERMINAL LLC KINDER MORGAN BATTLEGROUND OIL LLC KINDER MORGAN BORDER PIPELINE LLC KINDER MORGAN BULK TERMINALS, INC. KINDER MORGAN CARBON DIOXIDE TRANSPORTATION COMPANY KINDER MORGAN CO2 COMPANY, L.P. By Kinder Morgan G.P., Inc., its general partner KINDER MORGAN COCHIN LLC KINDER MORGAN COLUMBUS LLC KINDER MORGAN COMMERCIAL SERVICES LLC KINDER MORGAN CRUDE & CONDENSATE LLC KINDER MORGAN CRUDE OIL PIPELINES LLC KINDER MORGAN CRUDE TO RAIL LLC KINDER MORGAN CUSHING LLC KINDER MORGAN DALLAS FORT WORTH RAIL TERMINAL LLC KINDER MORGAN ENDEAVOR LLC KINDER MORGAN ENERGY PARTNERS, L.P. By Kinder Morgan G.P., Inc., its general partner KINDER MORGAN EP MIDSTREAM LLC KINDER MORGAN FINANCE COMPANY LLC KINDER MORGAN FLEETING LLC KINDER MORGAN FREEDOM PIPELINE LLC KINDER MORGAN KEYSTONE GAS STORAGE LLC KINDER MORGAN KMAP LLC KINDER MORGAN LAS VEGAS LLC KINDER MORGAN LINDEN TRANSLOAD TERMINAL LLC KINDER MORGAN LIQUIDS TERMINALS LLC KINDER MORGAN LIQUIDS TERMINALS ST. GABRIEL LLC KINDER MORGAN MARINE SERVICES LLC KINDER MORGAN MATERIALS SERVICES, LLC KINDER MORGAN MID ATLANTIC MARINE SERVICES LLC KINDER MORGAN NATGAS O&M LLC Exhibit 10.58 KINDER MORGAN NORTH TEXAS PIPELINE LLC KINDER MORGAN OPERATING L.P. “A” By Kinder Morgan G.P., Inc., its general partner KINDER MORGAN OPERATING L.P. “B” By Kinder Morgan G.P., Inc., its general partner KINDER MORGAN OPERATING L.P. “C” By Kinder Morgan G.P., Inc., its general partner KINDER MORGAN OPERATING L.P. “D” By Kinder Morgan G.P., Inc., its general partner KINDER MORGAN PECOS LLC KINDER MORGAN PECOS VALLEY LLC KINDER MORGAN PETCOKE GP LLC KINDER MORGAN PETCOKE, L.P. By Kinder Morgan Petcoke GP LLC, its general partner KINDER MORGAN PETCOKE LP LLC KINDER MORGAN PETROLEUM TANKERS LLC KINDER MORGAN PIPELINE LLC KINDER MORGAN PIPELINES (USA) INC. KINDER MORGAN PORT MANATEE TERMINAL LLC KINDER MORGAN PORT SUTTON TERMINAL LLC KINDER MORGAN PORT TERMINALS USA LLC KINDER MORGAN PRODUCTION COMPANY LLC KINDER MORGAN RAIL SERVICES LLC KINDER MORGAN RESOURCES II LLC KINDER MORGAN RESOURCES III LLC KINDER MORGAN RESOURCES LLC KINDER MORGAN RIVER TERMINALS LLC KINDER MORGAN SERVICES LLC KINDER MORGAN SEVEN OAKS LLC KINDER MORGAN SOUTHEAST TERMINALS LLC KINDER MORGAN TANK STORAGE TERMINALS LLC KINDER MORGAN TEJAS PIPELINE LLC KINDER MORGAN TERMINALS, INC. KINDER MORGAN TEXAS PIPELINE LLC KINDER MORGAN TEXAS TERMINALS, L.P. By General Stevedores GP, LLC, its general partner KINDER MORGAN TRANSMIX COMPANY, LLC KINDER MORGAN TREATING LP By KM Treating GP LLC, its general partner KINDER MORGAN URBAN RENEWAL, L.L.C. KINDER MORGAN UTICA LLC KINDER MORGAN VIRGINIA LIQUIDS TERMINALS LLC KINDER MORGAN WINK PIPELINE LLC KINDERHAWK FIELD SERVICES LLC KM CRANE LLC KM DECATUR, INC. KM EAGLE GATHERING LLC KM GATHERING LLC KM KASKASKIA DOCK LLC KM LIQUIDS TERMINALS LLC Exhibit 10.58 KM NORTH CAHOKIA LAND LLC KM NORTH CAHOKIA SPECIAL PROJECT LLC KM NORTH CAHOKIA TERMINAL PROJECT LLC KM SHIP CHANNEL SERVICES LLC KM TREATING GP LLC KM TREATING PRODUCTION LLC KMBT LLC KMGP CONTRACTING SERVICES LLC KMGP SERVICES COMPANY, INC. KN TELECOMMUNICATIONS, INC. KNIGHT POWER COMPANY LLC LOMITA RAIL TERMINAL LLC MILWAUKEE BULK TERMINALS LLC MJR OPERATING LLC MOJAVE PIPELINE COMPANY, L.L.C. MOJAVE PIPELINE OPERATING COMPANY, L.L.C. MR. BENNETT LLC MR. VANCE LLC NASSAU TERMINALS LLC NGPL HOLDCO INC. NS 307 HOLDINGS INC. PADDY RYAN CRANE, LLC PALMETTO PRODUCTS PIPE LINE LLC PI 2 PELICAN STATE LLC PINNEY DOCK & TRANSPORT LLC QUEEN CITY TERMINALS LLC RAHWAY RIVER LAND LLC RAZORBACK TUG LLC RCI HOLDINGS, INC. RIVER TERMINALS PROPERTIES GP LLC RIVER TERMINAL PROPERTIES, L.P. By River Terminals Properties GP LLC, its general partner SCISSORTAIL ENERGY, LLC SNG PIPELINE SERVICES COMPANY, L.L.C. SOUTHERN GULF LNG COMPANY, L.L.C. SOUTHERN LIQUEFACTION COMPANY LLC SOUTHERN LNG COMPANY, L.L.C. SOUTHERN NATURAL GAS COMPANY, L.L.C. SOUTHERN NATURAL ISSUING CORPORATION SOUTHTEX TREATERS LLC SOUTHWEST FLORIDA PIPELINE LLC SRT VESSELS LLC STEVEDORE HOLDINGS, L.P. By Kinder Morgan Petcoke GP LLC, its general partner TAJON HOLDINGS, INC. TEJAS GAS, LLC TEJAS NATURAL GAS, LLC TENNESSEE GAS PIPELINE COMPANY, L.L.C. TENNESSEE GAS PIPELINE ISSUING CORPORATION TEXAN TUG LLC Exhibit 10.58 TGP PIPELINE SERVICES COMPANY, L.L.C. TRANS MOUNTAIN PIPELINE (PUGET SOUND) LLC TRANSCOLORADO GAS TRANSMISSION COMPANY LLC TRANSLOAD SERVICES, LLC UTICA MARCELLUS TEXAS PIPELINE LLC WESTERN PLANT SERVICES, INC. WYOMING INTERSTATE COMPANY, L.L.C. By: /s/ Anthony B. Ashley Anthony Ashley Vice President Exhibit 10.58 ANNEX A TO THE CROSS GUARANTEE AGREEMENT SUPPLEMENT NO. [ ] dated as of [ ] to the CROSS GUARANTEE AGREEMENT dated as of [ ] (the “Agreement”), among each of the Guarantors listed on the signature pages thereto and each of the other entities that becomes a party thereto pursuant to Section 19 of the Agreement (each such entity individually, a “Guarantor” and, collectively, the “Guarantors”). Unless otherwise defined herein, terms defined in the Agreement and used herein shall have the meanings given to them in the Agreement. A. The Guarantors consist of Kinder Morgan, Inc., a Delaware corporation (“KMI”), and certain of its direct and indirect Subsidiaries, and the Guarantors have entered into the Agreement in order to provide guarantees of certain of the Guarantors’ senior, unsecured Indebtedness outstanding from time to time. B. Section 19 of the Agreement provides that additional Subsidiaries may become Guarantors under the Agreement by execution and delivery of an instrument in the form of this Supplement. Each undersigned Subsidiary (each a “New Guarantor”) is executing this Supplement at the request of KMI or in accordance with the requirements of the Agreement to become a Guarantor under the Agreement. Accordingly, each New Guarantor agrees as follows: SECTION 1. In accordance with Section 19 of the Agreement, each New Guarantor by its signature below becomes a Guarantor under the Agreement with the same force and effect as if originally named therein as a Guarantor and each New Guarantor hereby (a) agrees to all the terms and provisions of the Agreement applicable to it as a Guarantor thereunder and (b) represents and warrants that the representations and warranties made by it as a Guarantor thereunder are true and correct on and as of the date hereof. Each reference to a Guarantor in the Agreement shall be deemed to include each New Guarantor. The Agreement is hereby incorporated herein by reference. SECTION 2. Each New Guarantor represents and warrants to the Guaranteed Parties that this Supplement has been duly authorized, executed and delivered by it and constitutes its legal, valid and binding obligation, enforceable against it in accordance with its terms. SECTION 3. This Supplement may be executed by one or more of the parties to this Supplement on any number of separate counterparts (including by facsimile or other electronic transmission), and all of said counterparts taken together shall be deemed to constitute one and the same instrument. A set of the copies of this Supplement signed by all the parties shall be lodged with KMI. This Supplement shall become effective as to each New Guarantor when KMI shall have received a counterpart of this Supplement that bears the signature of such New Guarantor. SECTION 4. Except as expressly supplemented hereby, the Agreement shall remain in full force and effect. SECTION 5. THIS SUPPLEMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK. Exhibit 10.58 SECTION 6. Any provision of this Supplement that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof and in the Agreement, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction. The parties hereto shall endeavor in good-faith negotiations to replace the invalid, illegal or unenforceable provisions with valid provisions the economic effect of which comes as close as possible to that of the invalid, illegal or unenforceable provisions. SECTION 7. All notices, requests and demands pursuant hereto shall be made in accordance with Section 12 of the Agreement. All communications and notices hereunder to each New Guarantor shall be given to it in care of KMI at the address set forth in Section 12 of the Agreement. [Signature Pages Follow] IN WITNESS WHEREOF, each New Guarantor has duly executed this Supplement to the Agreement as of the day and year first above written. Exhibit 10.58 _________________________________ as Guarantor By: Name: Title: Exhibit 10.58 ANNEX B TO THE CROSS GUARANTEE AGREEMENT FORM OF NOTATION OF GUARANTEE Subject to the limitations set forth in the Cross Guarantee Agreement, dated as of [•] (the “Guarantee Agreement”), the undersigned Guarantors hereby certify that this [Indebtedness] constitutes a Guaranteed Obligation, entitled to all the rights as such set forth in the Guarantee Agreement. The Guarantors may be released from their guarantees upon the terms and subject to the conditions provided in the Guarantee Agreement. Capitalized terms used but not defined in this notation of guarantee have the meanings assigned such terms in the Guarantee Agreement, a copy of which will be provided to [a holder of this instrument] upon request to [Issuer]. Schedule I of the Guarantee Agreement is hereby deemed to be automatically updated to include this [Indebtedness] thereon as a Guaranteed Obligation. [GUARANTORS], as Guarantor By: Name: Title: SCHEDULE I Guaranteed Obligations February 13, 2015 Indebtedness 5.15% notes 5.70% notes 8.25% bonds $100 million Letter of Credit Facility 7.00% bonds 2.00% notes 6.00% notes 7.00% bonds (Sonat) 7.25% bonds 3.05% notes 6.50% bonds 5.00% notes 5.625% notes 4.30% notes 6.70% bonds (Coastal) 6.67% debentures 7.25% debentures 6.95% bonds (Coastal) 8.05% bonds 7.80% bonds 7.75% bonds 5.30% notes 7.75% bonds (Coastal) 6.40% notes 7.42% bonds (Coastal) 5.55% notes 7.45% debentures Issuer Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan Energy Partners, L.P. 5.625% bonds Kinder Morgan Energy Partners, L.P. 3.50% bonds Kinder Morgan Energy Partners, L.P. 6.00% bonds Kinder Morgan Energy Partners, L.P. 5.95% bonds Kinder Morgan Energy Partners, L.P. 9.00% bonds Kinder Morgan Energy Partners, L.P. 2.65% bonds Kinder Morgan Energy Partners, L.P. 6.85% bonds Kinder Morgan Energy Partners, L.P. 5.30% bonds Kinder Morgan Energy Partners, L.P. 5.80% bonds Kinder Morgan Energy Partners, L.P. 3.50% bonds Kinder Morgan Energy Partners, L.P. 4.15% bonds Kinder Morgan Energy Partners, L.P. 3.95% bonds Kinder Morgan Energy Partners, L.P. 3.45% bonds Kinder Morgan Energy Partners, L.P. 3.50% bonds Kinder Morgan Energy Partners, L.P. 4.15% bonds Exhibit 10.58 Maturity March 1, 2015 January 5, 2016 February 15, 2016 June 20, 2016 June 15, 2017 December 1, 2017 January 15, 2018 February 1, 2018 June 1, 2018 December 1, 2019 September 15, 2020 February 15, 2021 November 15, 2023 June 1, 2025 February 15, 2027 November 1, 2027 March 1, 2028 June 1, 2028 October 15, 2030 August 1, 2031 January 15, 2032 December 1, 2034 October 15, 2035 January 5, 2036 February 15, 2037 June 1, 2045 March 1, 2098 February 15, 2015 March 1, 2016 February 1, 2017 February 15, 2018 February 1, 2019 February 1, 2019 February 15, 2020 September 15, 2020 March 1, 2021 March 1, 2021 March 1, 2022 September 1, 2022 February 15, 2023 September 1, 2023 February 1, 2024 Issuer Indebtedness Kinder Morgan Energy Partners, L.P. 4.25% bonds Kinder Morgan Energy Partners, L.P. 7.40% bonds Kinder Morgan Energy Partners, L.P. 7.75% bonds Kinder Morgan Energy Partners, L.P. 7.30% bonds Kinder Morgan Energy Partners, L.P. 5.80% bonds Kinder Morgan Energy Partners, L.P. 6.50% bonds Kinder Morgan Energy Partners, L.P. 6.95% bonds Kinder Morgan Energy Partners, L.P. 6.50% bonds Kinder Morgan Energy Partners, L.P. 6.55% bonds Kinder Morgan Energy Partners, L.P. 6.375% bonds Kinder Morgan Energy Partners, L.P. 5.625% bonds Kinder Morgan Energy Partners, L.P. 5.00% bonds Kinder Morgan Energy Partners, L.P. 5.00% bonds Kinder Morgan Energy Partners, L.P. 5.50% bonds Kinder Morgan Energy Partners, L.P. 5.40% bonds 4.10% bonds El Paso Pipeline Partners, L.P. 6.50% bonds El Paso Pipeline Partners, L.P. 5.00% bonds El Paso Pipeline Partners, L.P. 4.30% bonds El Paso Pipeline Partners, L.P. 7.50% bonds El Paso Pipeline Partners, L.P. 4.70% bonds El Paso Pipeline Partners, L.P. 8.00% bonds Tennessee Gas Pipeline Co. 7.50% bonds Tennessee Gas Pipeline Co. 7.00% bonds Tennessee Gas Pipeline Co. 7.00% bonds Tennessee Gas Pipeline Co. 8.375% bonds Tennessee Gas Pipeline Co. 7.625% bonds Tennessee Gas Pipeline Co. 5.95% bonds El Paso Natural Gas Co. 8.625% bonds El Paso Natural Gas Co. 7.50% bonds El Paso Natural Gas Co. 8.375% bonds El Paso Natural Gas Co. 5.95% bonds Colorado Interstate Gas Co. 6.8% bonds Colorado Interstate Gas Co. 6.85% bonds Colorado Interstate Gas Co. 5.90% bonds Southern Natural Gas Co. 4.40% bonds Southern Natural Gas Co. 7.35% bonds Southern Natural Gas Co. 8.00% bonds Southern Natural Gas Co. 7.125% bonds Copano Energy LLC 7.25% bonds El Paso Tennessee Pipeline Co. 6.00% Hamilton notes Other Exhibit 10.58 Schedule I (Guaranteed Obligations) February 13, 2015 Maturity September 1, 2024 March 15, 2031 March 15, 2032 August 15, 2033 March 15, 2035 February 1, 2037 January 15, 2038 September 1, 2039 September 15, 2040 March 1, 2041 September 1, 2041 August 15, 2042 March 1, 2043 March 1, 2044 September 1, 2044 November 15, 2015 April 1, 2020 October 1, 2021 May 1, 2024 November 15, 2040 November 1, 2042 February 1, 2016 April 1, 2017 March 15, 2027 October 15, 2028 June 15, 2032 April 1, 2037 April 15, 2017 January 15, 2022 November 15, 2026 June 15, 2032 March 15, 2015 November 15, 2015 June 15, 2037 April 1, 2017 June 15, 2021 February 15, 2031 March 1, 2032 April 1, 2021 December 15, 2025 April 21, 2015 Other Other Other Other Hiland Partners Holdings LLC and KM LQT IRBs-Stolt floating rate bonds January 15, 2018 KM LQT IRBs-Stolt floating rate bonds $25,000,000 (plus accrued and unpaid interest) letter of credit 5.50% KM Columbus MBFC notes Cora industrial revenue bonds 7.25% notes March 11, 2015 September 1, 2022 April 1, 2024 October 1, 2020 Exhibit 10.58 Schedule I (Guaranteed Obligations) February 13, 2015 Issuer Hiland Partners Finance Corp. Indebtedness Maturity Hiland Partners Holdings LLC and Hiland Partners Finance Corp. 5.50% notes May 15, 2022 Hedging Agreements1 Issuer Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan, Inc. Kinder Morgan Energy Partners, L.P. Kinder Morgan Energy Partners, L.P. Kinder Morgan Energy Partners, L.P. Kinder Morgan Energy Partners, L.P. Kinder Morgan Energy Partners, L.P. Kinder Morgan Energy Partners, L.P. November 26, 2014 November 26, 2014 Date August 29, 2001 March 14, 2002 December 23, 2011 August 29, 2001 November 26, 2014 November 26, 2014 Guaranteed Party Bank of America, N.A. Citibank, N.A. J. Aron & Company SunTrust Bank Barclays Bank PLC Bank of Tokyo-Mitsubishi, Ltd., New York Branch Canadian Imperial Bank of Commerce Credit Agricole Corporate and Investment Bank Credit Suisse International Deutsche Bank AG ING Capital Markets LLC Mizuho Capital Markets Corporation Royal Bank of Canada The Bank of Nova Scotia The Royal Bank of Scotland PLC Societe Generale UBS AG Wells Fargo Bank, N.A. Bank of America, N.A. Bank of Tokyo-Mitsubishi, Ltd., New York Branch Barclays Bank PLC Canadian Imperial Bank of Commerce Citibank, N.A. Credit Agricole Corporate and Investment Bank June 20, 2014 November 26, 2014 November 26, 2014 November 26, 2014 November 26, 2014 November 26, 2014 November 26, 2014 November 26, 2014 November 26, 2014 November 26, 2014 November 26, 2014 April 14, 1999 November 23, 2004 November 18, 2003 August 4, 2011 March 14, 2002 Kinder Morgan Energy Partners, L.P. Kinder Morgan Energy Partners, L.P. Kinder Morgan Energy Partners, L.P. Kinder Morgan Energy Partners, L.P. Kinder Morgan Energy Partners, L.P. Credit Suisse International Deutsche Bank AG ING Capital Markets LLC J. Aron & Company JPMorgan Chase Bank _________________________________________________ May 14, 2010 April 2, 2009 September 21, 2011 November 11, 2004 August 29, 2001 1 Guaranteed Obligations with respect to Hedging Agreements include International Swaps and Derivatives Association Master Agreements (“ISDAs”) and all transactions entered into pursuant to any ISDA listed on this Schedule I. Exhibit 10.58 Schedule I (Guaranteed Obligations) February 13, 2015 Hedging Agreements1 Issuer Kinder Morgan Energy Partners, L.P. Mizuho Capital Markets Corporation Guaranteed Party Kinder Morgan Energy Partners, L.P. Morgan Stanley Capital Services Inc. Kinder Morgan Energy Partners, L.P. Royal Bank of Canada Kinder Morgan Energy Partners, L.P. The Royal Bank of Scotland PLC Kinder Morgan Energy Partners, L.P. The Bank of Nova Scotia Kinder Morgan Energy Partners, L.P. Societe Generale Kinder Morgan Energy Partners, L.P. SunTrust Bank Kinder Morgan Energy Partners, L.P. UBS AG Kinder Morgan Energy Partners, L.P. Wells Fargo Bank, N.A. Kinder Morgan Texas Pipeline LLC Kinder Morgan Texas Pipeline LLC Barclays Bank PLC Canadian Imperial Bank of Commerce Kinder Morgan Texas Pipeline LLC Citibank, N.A. Kinder Morgan Texas Pipeline LLC Credit Suisse International Kinder Morgan Texas Pipeline LLC Deutsche Bank AG Kinder Morgan Texas Pipeline LLC Kinder Morgan Production Company LP ING Capital Markets LLC J. Aron & Company Kinder Morgan Texas Pipeline LLC J. Aron & Company Kinder Morgan Texas Pipeline LLC JPMorgan Chase Bank, N.A. Kinder Morgan Texas Pipeline LLC Macquarie Bank Limited Kinder Morgan Texas Pipeline LLC Merrill Lynch Commodities, Inc. Kinder Morgan Texas Pipeline LLC Morgan Stanley Capital Group Inc. Kinder Morgan Texas Pipeline LLC Natixis Kinder Morgan Texas Pipeline LLC Royal Bank of Canada Kinder Morgan Texas Pipeline LLC The Bank of Nova Scotia Kinder Morgan Texas Pipeline LLC Shell Trading (US) Company Kinder Morgan Texas Pipeline LLC Societe Generale Kinder Morgan Texas Pipeline LLC Wells Fargo Bank, N.A. Copano Risk Management, L.P. Citibank, N.A. Copano Risk Management, L.P. J. Aron & Company Copano Risk Management, L.P. Morgan Stanley Capital Group Inc. Copano Risk Management, L.P. Wells Fargo Bank, N.A. Date July 11, 2014 March 10, 2010 March 12, 2009 March 20, 2009 August 14, 2003 July 18, 2014 March 14, 2002 February 23, 2011 July 31, 2007 January 10, 2003 December 18, 2006 February 22, 2005 August 31, 2012 June 13, 2007 April 17, 2014 June 12, 2006 June 8, 2000 September 7, 2006 September 20, 2010 October 24, 2001 January 15, 2004 June 13, 2011 May 6, 2009 May 8, 2014 November 14, 2011 January 14, 2003 June 1, 2013 July 21, 2008 December 12, 2005 May 4, 2007 October 19, 2007 Exhibit 10.58 SCHEDULE II Guarantors February 13, 2015 Agnes B Crane, LLC American Petroleum Tankers II LLC American Petroleum Tankers III LLC American Petroleum Tankers IV LLC American Petroleum Tankers LLC American Petroleum Tankers Parent LLC American Petroleum Tankers V LLC American Petroleum Tankers VI LLC American Petroleum Tankers VII LLC APT Florida LLC APT Intermediate Holdco LLC APT New Intermediate Holdco LLC APT Pennsylvania LLC APT Sunshine State LLC Audrey Tug LLC Bear Creek Storage Company, L.L.C. Betty Lou LLC Camino Real Gathering Company, L.L.C. Cantera Gas Company LLC CDE Pipeline LLC Central Florida Pipeline LLC Cheyenne Plains Gas Pipeline Company, L.L.C. CIG Gas Storage Company LLC CIG Pipeline Services Company, L.L.C. Cimmarron Gathering LLC Colorado Interstate Gas Company, L.L.C. Colorado Interstate Issuing Corporation Copano Double Eagle LLC Copano Energy Finance Corporation Copano Energy Services/Upper Gulf Coast LLC Copano Energy, L.L.C. Copano Field Services GP, L.L.C. Copano Field Services/North Texas, L.L.C. Copano Field Services/South Texas LLC Copano Field Services/Upper Gulf Coast LLC Copano Liberty, LLC Copano NGL Services (Markham), L.L.C. Copano NGL Services LLC Copano Pipelines Group, L.L.C. Copano Pipelines/North Texas, L.L.C. Copano Pipelines/Rocky Mountains, LLC Copano Pipelines/South Texas LLC Copano Pipelines/Upper Gulf Coast LLC Copano Processing LLC Copano Risk Management LLC Copano/Webb-Duval Pipeline LLC CPNO Services LLC Dakota Bulk Terminal, Inc. Delta Terminal Services LLC Eagle Ford Gathering LLC El Paso Cheyenne Holdings, L.L.C. El Paso Citrus Holdings, Inc. El Paso CNG Company, L.L.C. El Paso Energy Service Company, L.L.C. El Paso LLC El Paso Midstream Group LLC El Paso Natural Gas Company, L.L.C. El Paso Noric Investments III, L.L.C. El Paso Ruby Holding Company, L.L.C. El Paso Tennessee Pipeline Co., L.L.C. Elba Express Company, L.L.C. Elizabeth River Terminals LLC Emory B Crane, LLC EP Energy Holding Company EP Ruby LLC EPBGP Contracting Services LLC EPTP Issuing Corporation Fernandina Marine Construction Management LLC Frank L. Crane, LLC General Stevedores GP, LLC General Stevedores Holdings LLC Global American Terminals LLC Hampshire LLC Harrah Midstream LLC HBM Environmental, Inc. Hiland Crude, LLC Hiland Operating, LLC Hiland Partners, LLC Hiland Partners Finance Corp. Hiland Partners Holdings LLC ICPT, L.L.C Independent Trading & Transportation Company I, L.L.C. J.R. Nicholls LLC Javelina Tug LLC Jeannie Brewer LLC JV Tanker Charterer LLC Kinder Morgan (Delaware), Inc. Kinder Morgan 2-Mile LLC Exhibit 10.58 Kinder Morgan Administrative Services Tampa LLC Kinder Morgan Altamont LLC Kinder Morgan Amory LLC Kinder Morgan Arrow Terminals Holdings, Inc. Kinder Morgan Arrow Terminals, L.P. Kinder Morgan Baltimore Transload Terminal LLC Kinder Morgan Battleground Oil LLC Kinder Morgan Border Pipeline LLC Kinder Morgan Bulk Terminals, Inc. Kinder Morgan Carbon Dioxide Transportation Company Kinder Morgan CO2 Company, L.P. Kinder Morgan Cochin LLC Kinder Morgan Columbus LLC Kinder Morgan Commercial Services LLC Kinder Morgan Crude & Condensate LLC Kinder Morgan Crude Oil Pipelines LLC Kinder Morgan Crude to Rail LLC Kinder Morgan Cushing LLC Kinder Morgan Dallas Fort Worth Rail Terminal LLC Kinder Morgan Endeavor LLC Kinder Morgan Energy Partners, L.P. Kinder Morgan EP Midstream LLC Kinder Morgan Finance Company LLC Kinder Morgan Fleeting LLC Kinder Morgan Freedom Pipeline LLC Kinder Morgan, Inc. Kinder Morgan Keystone Gas Storage LLC Kinder Morgan KMAP LLC Kinder Morgan Las Vegas LLC Kinder Morgan Linden Transload Terminal LLC Kinder Morgan Liquids Terminals LLC Kinder Morgan Liquids Terminals St. Gabriel LLC Kinder Morgan Marine Services LLC Kinder Morgan Materials Services, LLC Kinder Morgan Mid Atlantic Marine Services LLC Kinder Morgan NatGas O&M LLC Kinder Morgan North Texas Pipeline LLC Kinder Morgan Operating L.P. “ A” Kinder Morgan Operating L.P. “ B” Kinder Morgan Operating L.P. “ C” Kinder Morgan Operating L.P. “ D” Kinder Morgan Pecos LLC Kinder Morgan Pecos Valley LLC Kinder Morgan Petcoke GP LLC Kinder Morgan Petcoke LP LLC Kinder Morgan Petcoke, L.P. Kinder Morgan Petroleum Tankers LLC Kinder Morgan Pipeline LLC Kinder Morgan Port Manatee Terminal LLC Kinder Morgan Port Sutton Terminal LLC Kinder Morgan Port Terminals USA LLC Kinder Morgan Production Company LLC Kinder Morgan Rail Services LLC Kinder Morgan Resources II LLC Kinder Morgan Resources III LLC Kinder Morgan Resources LLC Kinder Morgan River Terminals LLC Kinder Morgan Services LLC Kinder Morgan Seven Oaks LLC Kinder Morgan Southeast Terminals LLC Kinder Morgan Scurry Connector LLC Kinder Morgan Tank Storage Terminals LLC Kinder Morgan Tejas Pipeline LLC Kinder Morgan Terminals, Inc. Kinder Morgan Texas Pipeline LLC Kinder Morgan Texas Terminals, L.P. Kinder Morgan Transmix Company, LLC Kinder Morgan Treating LP Kinder Morgan Urban Renewal, L.L.C. Kinder Morgan Utica LLC Kinder Morgan Virginia Liquids Terminals LLC Kinder Morgan Wink Pipeline LLC KinderHawk Field Services LLC KM Crane LLC KM Decatur, Inc. KM Eagle Gathering LLC KM Gathering LLC KM Kaskaskia Dock LLC KM Liquids Terminals LLC KM North Cahokia Land LLC KM North Cahokia Special Project LLC KM North Cahokia Terminal Project LLC KM Ship Channel Services LLC KM Treating GP LLC KM Treating Production LLC KMBT LLC KMGP Contracting Services LLC KMGP Services Company, Inc. KN Telecommunications, Inc. Knight Power Company LLC Lomita Rail Terminal LLC Milwaukee Bulk Terminals LLC MJR Operating LLC Mojave Pipeline Company, L.L.C. Exhibit 10.58 Mojave Pipeline Operating Company, L.L.C. Mr. Bennett LLC Mr. Vance LLC Nassau Terminals LLC NGPL Holdco Inc. Paddy Ryan Crane, LLC Palmetto Products Pipe Line LLC PI 2 Pelican State LLC Pinney Dock & Transport LLC Queen City Terminals LLC Rahway River Land LLC Razorback Tug LLC RCI Holdings, Inc. River Terminals Properties GP LLC River Terminal Properties, L.P. ScissorTail Energy, LLC SNG Pipeline Services Company, L.L.C. Southern Gulf LNG Company, L.L.C. Southern Liquefaction Company LLC Southern LNG Company, L.L.C. Southern Natural Gas Company, L.L.C. Southern Natural Issuing Corporation SouthTex Treaters LLC Southwest Florida Pipeline LLC SRT Vessels LLC Stevedore Holdings, L.P. Tajon Holdings, Inc. Tejas Gas, LLC Tejas Natural Gas, LLC Tennessee Gas Pipeline Company, L.L.C. Tennessee Gas Pipeline Issuing Corporation Texan Tug LLC TGP Pipeline Services Company, L.L.C. Trans Mountain Pipeline (Puget Sound) LLC TransColorado Gas Transmission Company LLC Transload Services, LLC Utica Marcellus Texas Pipeline LLC Western Plant Services, Inc. Wyoming Interstate Company, L.L.C. Exhibit 10.58 SCHEDULE III Excluded Subsidiaries ANR Real Estate Corporation Coastal Eagle Point Oil Company Coastal Oil New England, Inc. Colton Processing Facility Coscol Petroleum Corporation El Paso CGP Company, L.L.C. El Paso Energy Capital Trust I El Paso Energy E.S.T. Company El Paso Energy International Company El Paso Marketing Company, L.L.C. El Paso Merchant Energy North America Company, L.L.C. El Paso Merchant Energy-Petroleum Company El Paso Reata Energy Company, L.L.C. El Paso Remediation Company El Paso Services Holding Company EPEC Corporation EPEC Oil Company Liquidating Trust EPEC Polymers, Inc. EPED Holding Company Kinder Morgan Louisiana Pipeline Holding LLC Kinder Morgan Louisiana Pipeline LLC KN Capital Trust I KN Capital Trust III Mesquite Investors, L.L.C. Note: The Excluded Subsidiaries listed on this Schedule III may also be Excluded Subsidiaries pursuant to other exceptions set forth in the definition of “Excluded Subsidiary”. EXHIBIT 12.1 - STATEMENT RE: COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES KINDER MORGAN, INC. AND SUBSIDIARIES (Dollars in millions except ratio amounts) Exhibit 12.1 Earnings: Pre-tax income from continuing operations before cumulative effect of a change in accounting principle and before adjustment for noncontrolling interests and equity earnings (including amortization of excess cost of equity investments) per statements of income Add: Fixed charges Amortization of capitalized interest Distributed income of equity investees Less: Interest capitalized from continuing operations Noncontrolling interest in pre-tax income of subsidiaries with no fixed charges Income as adjusted Fixed charges: Interest and debt expense, net per statements of income (includes amortization of debt discount, premium, and debt issuance costs; excludes capitalized interest) Add: Portion of rents representative of the interest factor Fixed charges 2014 Year Ended December 31, 2011 2012 2013 2010 $ 2,730 $ 3,150 $ 1,213 $ 591 $ 510 1,921 5 381 1,785 6 398 1,486 5 311 766 5 200 704 4 132 (75) (52) (27) (15) (13) (377) $ 4,585 (390) $ 4,897 17 $ 3,005 (22) $ 1,525 (107) $ 1,230 $ 1,882 $ 1,742 $ 1,454 $ 718 $ 681 39 $ 1,921 43 $ 1,785 32 $ 1,486 $ 48 766 $ 23 704 Ratio of earnings to fixed charges 2.39 2.74 2.02 1.99 1.75 Kinder Morgan, Inc. Subsidiaries of the Registrant as of December 31, 2014 Exhibit 21.1 Agnes B Crane, LLC Agua del Cajon (Cayman) Company American Petroleum Tankers II LLC American Petroleum Tankers III LLC American Petroleum Tankers IV LLC American Petroleum Tankers LLC American Petroleum Tankers Parent LLC American Petroleum Tankers V LLC American Petroleum Tankers VI LLC American Petroleum Tankers VII LLC ANR Advance Holdings, Inc. ANR Real Estate Corporation APT Florida LLC APT Intermediate Holdco LLC APT New Intermediate Holdco LLC APT Pennsylvania LLC APT Sunshine State LLC Aquamarine Power Holdings, L.L.C. Audrey Tug LLC Battleground Oil Specialty Terminal Company LLC Bear Creek Storage Company, L.L.C. Berkshire Feedline Acquisition Limited Partnership BetaGen Power LLC Betty Lou LLC BHP Billiton Petroleum (Eagle Ford Gathering) LLC Bighorn Gas Gathering, L.L.C. Calnev Pipe Line LLC Camino Real Gathering Company, L.L.C. Coyote Gas Treating Limited Liability Company CDE Pipeline LLC Central Florida Pipeline LLC Cheyenne Plains Gas Pipeline Company, L.L.C. CIG Gas Storage Company LLC CIG Pipeline Services Company, L.L.C. Cimmarron Gathering LLC Citrus Energy Services, Inc. Citrus LLC Cliffside Helium, LLC Cliffside Refiners, L.P. Coastal Eagle Point Oil Company Coastal Energy Resources Ltd. Kinder Morgan, Inc. Subsidiaries of the Registrant as of December 31, 2014 Exhibit 21.1 Coastal Oil New England, Inc. Coastal Wartsila Petroleum Private Limited Colbourne Insurance Company Limited Colorado Interstate Gas Company, L.L.C. Colorado Interstate Issuing Corporation Colton Processing Facility Copano Double Eagle LLC Copano Energy Finance Corporation Copano Energy L.L.C. Copano Energy Services/Upper Gulf Coast LLC Copano Field Services GP, L.L.C. Copano Field Services/North Texas, L.L.C. Copano Field Services/South Texas LLC Copano Field Services/Upper Gulf Coast LLC Copano Liberty, LLC Copano NGL Services (Markham), L.L.C. Copano NGL Services LLC Copano Pipelines Group, L.L.C. Copano Pipelines/North Texas, L.L.C. Copano Pipelines/Rocky Mountains, LLC Copano Pipelines/SouthTexas LLC Copano Pipelines/Upper Gulf Coast LLC Copano Processing LLC Copano Risk Management LLC Copano/Webb-Duval Pipeline LLC Cortez Capital Corporation Cortez Expansion Capital Corporation Cortez Pipeline Company Coscol Petroleum Corporation CPNO Services LLC Cross Country Development L.L.C. Cypress Interstate Pipeline LLC Dakota Bulk Terminal, Inc. Deeprock Development, LLC Deeprock North, LLC Delta Terminal Services LLC Devco USA, L.L.C. Dietze Products LLC Double Eagle Pipeline LLC Eagle Ford Gathering LLC Eastern Insurance Company Limited Kinder Morgan, Inc. Subsidiaries of the Registrant as of December 31, 2014 Exhibit 21.1 El Paso Amazonas Energia Ltda. El Paso Cayger III Company El Paso Cayger IV Company El Paso CGP Company, L.L.C. El Paso Cheyenne Holdings, L.L.C. El Paso Citrus Holdings, Inc. El Paso CNG Company, L.L.C. El Paso Corporate Foundation El Paso Energia do Brasil Ltda. El Paso Energy Argentina Services Company El Paso Energy Capital Trust I El Paso Energy Cayger II Company El Paso Energy E.S.T. Company El Paso Energy International Company El Paso Energy Marketing de Mexico, S de RL de CV El Paso Energy Service Company, L.L.C. El Paso Fife I Company El Paso LLC El Paso Marketing Company, L.L.C. El Paso Merchant Energy North America Company, L.L.C. El Paso Merchant Energy-Petroleum Company El Paso Mexico Holding B.V. El Paso Midstream Group, Inc. El Paso Natural Gas Company, L.L.C. El Paso Neuquen Holding Company El Paso Noric Investments III, L.L.C. El Paso Pipeline Corporation El Paso Pipeline GP Company, L.L.C. El Paso Pipeline Holding Company, L.L.C. El Paso Pipeline LP Holdings, L.L.C. El Paso Pipeline Partners Operating Company, L.L.C. El Paso Pipeline Partners, L.P. El Paso Reata Energy Company, L.L.C. El Paso Remediation Company El Paso Rio Negro Energia Ltda. El Paso Ruby Holding Company, L.L.C. El Paso Services Holding Company El Paso Tennessee Pipeline Co. Elba Express Company, L.L.C. Elba Liquefaction Company, L.L.C. Elizabeth River Terminals LLC Kinder Morgan, Inc. Subsidiaries of the Registrant as of December 31, 2014 Exhibit 21.1 Emory B Crane, LLC Endeavor Gathering LLC EP Production International Cayman Company EP Ruby LLC EPBGP Contracting Services LLC EPC Building LLC EPC Property Holdings, Inc. EPEC Corporation EPEC Oil Company Liquidating Trust EPEC Polymers, Inc. EPEC Realty, Inc. EPED B Company EPED Holding Company EPIC Gas International Servicos do Brasil Ltda. EPTP Issuing Corporation Fayetteville Express Pipeline LLC Fernandina Marine Construction Management LLC Fife Power Florida Gas Transmission Company, LLC Fort Union Gas Gathering, L.L.C. Frank L Crane, LLC GEBF, L.L.C. General Stevedores GP, LLC General Stevedores Holdings LLC GLE Channel Improvement, LLC Global American Terminals LLC Greens Bayou Fleeting, LLC Greens Port CBR, LLC Guilford County Terminal Company, LLC Gulf LNG Energy (Port), LLC Gulf LNG Energy, LLC Gulf LNG Holdings Group, LLC Gulf LNG Liquefaction Company, LLC Gulf LNG Pipeline, LLC Hampshire LLC Harrah Midstream LLC HBM Environmental, Inc. Horizon Pipeline Company, L.L.C. I.M.T. Land Corp. ICPT, L.L.C. Interenergy Company Kinder Morgan, Inc. Subsidiaries of the Registrant as of December 31, 2014 Exhibit 21.1 International Marine Terminals Partnership J.R. Nicholls LLC Javelina Tug LLC Jeannie Brewer LLC Johnston County Terminal, LLC JV Tanker Charterer LLC Kellogg Terminal, LLC Kinder Morgan (Delaware), LLC Kinder Morgan 2-Mile LLC Kinder Morgan Administrative Services Tampa LLC Kinder Morgan Altamont LLC Kinder Morgan Amory LLC Kinder Morgan Arrow Terminals Holdings, Inc. Kinder Morgan Arrow Terminals, L.P. Kinder Morgan Arrow Terminals, L.P. Kinder Morgan Baltimore Transload Terminal LLC Kinder Morgan Battleground Oil LLC Kinder Morgan Border Pipeline LLC Kinder Morgan Bulk Terminals, Inc. Kinder Morgan Canada Company Kinder Morgan Carbon Dioxide Transportation Company Kinder Morgan CO2 Company, L.P. Kinder Morgan Cochin LLC Kinder Morgan Columbus LLC Kinder Morgan Commercial Services LLC Kinder Morgan Crude & Condensate LLC Kinder Morgan Crude Oil Pipelines LLC Kinder Morgan Crude to Rail LLC Kinder Morgan Cushing LLC Kinder Morgan Dallas Fort Worth Rail Terminal LLC Kinder Morgan Endeavor LLC Kinder Morgan Energy Partners, L.P. Kinder Morgan EP Midstream LLC Kinder Morgan Finance Company LLC Kinder Morgan Fleeting LLC Kinder Morgan Foundation Kinder Morgan Freedom Pipeline LLC Kinder Morgan G.P., Inc. Kinder Morgan Gas Natural de Mexico, S. de R.L. de C.V. Kinder Morgan Illinois Pipeline LLC Kinder Morgan, Inc. Kinder Morgan, Inc. Subsidiaries of the Registrant as of December 31, 2014 Exhibit 21.1 Kinder Morgan Insurance Ltd. Kinder Morgan Keystone Gas Storage LLC Kinder Morgan KMAP LLC Kinder Morgan Las Vegas LLC Kinder Morgan Linden Transload Terminal LLC Kinder Morgan Liquids Terminals LLC Kinder Morgan Liquids Terminals St. Gabriel LLC Kinder Morgan Louisiana Pipeline Holding LLC Kinder Morgan Louisiana Pipeline LLC Kinder Morgan Marine Services LLC Kinder Morgan Materials Services, LLC Kinder Morgan Mid Atlantic Marine Services LLC Kinder Morgan NatGas O & M LLC Kinder Morgan Operating L.P. "A" Kinder Morgan Operating L.P. "B" Kinder Morgan Operating L.P. "C" Kinder Morgan Operating L.P. "D" Kinder Morgan Pecos LLC Kinder Morgan Pecos Valley LLC Kinder Morgan Petcoke GP LLC Kinder Morgan Petcoke LP LLC Kinder Morgan Petcoke, L.P. Kinder Morgan Petroleum Tankers LLC Kinder Morgan Pipeline LLC Kinder Morgan Pipeline Servicios de Mexico S. de R.L. de C.V. Kinder Morgan Port Sutton Terminal LLC Kinder Morgan Port Terminals USA LLC Kinder Morgan Production Company LLC Kinder Morgan Rail Services LLC Kinder Morgan Resources II LLC Kinder Morgan Resources III LLC Kinder Morgan Resources LLC Kinder Morgan River Terminals LLC Kinder Morgan Scurry Connector LLC Kinder Morgan Services LLC Kinder Morgan Seven Oaks LLC Kinder Morgan Southeast Terminals LLC Kinder Morgan Tank Storage Terminals LLC Kinder Morgan Tejas Pipeline GP LLC Kinder Morgan Tejas Pipeline LLC Kinder Morgan Terminals, Inc. Kinder Morgan, Inc. Subsidiaries of the Registrant as of December 31, 2014 Exhibit 21.1 Kinder Morgan Texas Pipeline LLC Kinder Morgan Texas Terminals, L.P. Kinder Morgan Transmix Company, LLC Kinder Morgan Treating LP Kinder Morgan Urban Renewal, L.L.C. Kinder Morgan Utica LLC Kinder Morgan Virginia Liquids Terminals LLC Kinder Morgan Wink Pipeline LLC Kinder Morgan, Inc. KinderHawk Field Services LLC KM Canada Terminals ULC KM Crane LLC KM Decatur, Inc. KM Eagle Gathering LLC KM Gathering LLC KM Kaskaskia Dock LLC KM Liquids Terminals LLC KM North Cahokia Land LLC KM North Cahokia Special Project LLC KM North Cahokia Terminal Project LLC KM Ship Channel Services LLC KM Treating GP LLC KM Treating Production LLC KMBT LLC KMGP Contracting Services LLC KMGP Services Company, Inc. KN Telecommunications, Inc. Knight Power Company LLC KW Express, LLC Liberty Pipeline Group, LLC Lomita Rail Terminal LLC Mesquite Investors, L.L.C. Midco LLC Mid-Ship Group LLC Milwaukee Bulk Terminals LLC MJR Operating LLC Mojave Pipeline Company, L.L.C. Mojave Pipeline Operating Company, L.L.C. Mr. Bennett LLC Mr. Vance LLC Mt. Franklin Insurance Ltd. Kinder Morgan, Inc. Subsidiaries of the Registrant as of December 31, 2014 Exhibit 21.1 Nassau Terminals LLC Natural Gas Pipeline Company of America LLC NGPL HoldCo Inc. NGPL Holdco LLC NGPL PipeCo LLC North Cahokia Industrial, LLC North Cahokia Real Estate, LLC North Cahokia Terminal, LLC North Denton Pipeline, L.L.C. Northeast Expansion LLC Paddy Ryan Crane, LLC Palmetto Products Pipe Line LLC Parkway Pipeline LLC Pecos Carbon Dioxide Transportation Company PI 2 Pelican State LLC Pinney Dock & Transport LLC Plantation Pipe Line Company Plantation Services LLC Queen City Terminals LLC Rahway River Land LLC Razorback Tug LLC RCI Holdings, Inc. Red Cedar Gathering Company Reno Pipeline, L.L.C. River Consulting, LLC River Terminals Properties GP LLC River Terminals Properties L.P. Ruby Investment Company, L.L.C. Ruby Pipeline Holding Company, L.L.C. Ruby Pipeline, L.L.C. ScissorTail Energy, LLC SFPP, L.P. Sierrita Gas Pipeline LLC SNG Pipeline Services Company, L.L.C. Sonoran Pipeline LLC Southern Dome, LLC Southern Gulf LNG Company, L.L.C. Southern Liquefaction Company LLC Southern LNG Company, L.L.C. Southern Natural Gas Company, L.L.C. Southern Natural Issuing Corporation Kinder Morgan, Inc. Subsidiaries of the Registrant as of December 31, 2014 Exhibit 21.1 SouthTex Treaters LLC Southwest Florida Pipeline LLC SRT Vessels LLC Stevedore Holdings, L.P. Tajon Holdings, Inc. Tejas Gas, LLC Tejas Natural Gas, LLC Tennessee Gas Pipeline Company, L.L.C. Texan Tug LLC TGP Pipeline Services Company, L.L.C. Trans Mountain Pipeline (Puget Sound) LLC TransColorado Gas Transmission Company LLC Transload Services, LLC Transport USA, Inc. Utica Marcellus Texas Pipeline LLC Webb/Duval Gatherers Western Plant Services, Inc. WYCO Development LLC Wyoming Interstate Company, L.L.C. Young Gas Storage Company, Ltd. Entities part of the Canadian Structure as of December 31, 2014 Trans Mountain Pipeline (Puget Sound) LLC Kinder Morgan Canada Company KM Express Limited Express GP Holdings Ltd. 6048935 Canada Inc. Kinder Morgan Bison ULC Kinder Morgan Heartland ULC Kinder Morgan CO2 ULC Trans Mountain (Jet Fuel) Inc. Kinder Morgan Canada Inc. Trans Mountain Pipeline ULC Kinder Morgan Cochin ULC KM Canada Terminals ULC KM Crude by Rail Canada Corp KW Express Canada GP Limited KM Canada Rail Holdings GP Limited * Canadian structure does not include the partnerships and their subsidiaries: Trans Mountain Pipeline LP.; Kinder Morgan Canada Terminals Limited Partnership and its subsidiary, KM Canada Edmonton South Rail Terminal Corp; KM Canada Edmonton South Rail Terminals LP; KM Canada Edmonton North Rail Terminal LP; KW Express Canada LP CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We hereby consent to the incorporation by reference in the Registration Statements on (i) Form S-3 (Nos. 333-200421 and 333-179812); (ii) Form S-3, converted from Form S-4, (No. 333-177895) and (iii) Form S-8 (Nos. 333-172170, 333-172582, 333-172584, 333-172606, 333-172808 and 333-181782) of Kinder Morgan, Inc. of our report dated February 23, 2015 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K. Exhibit 23.1 /s/ PricewaterhouseCoopers LLP Houston, Texas February 23, 2015 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS As oil and gas consultants, we hereby consent to the use of our name and our report dated January 8, 2015, in this Form 10-K, incorporated by reference into Kinder Morgan, Inc.'s previously filed Registration Statements on (i) Form S-3 (Nos. 333-200421 and 333-179812); (ii) Form S-3, converted from Form S-4, (No. 333-177895) and (iii) Form S-8 (Nos. 333-181782, 333-172808, 333-172606, 333-172584, 333-172582 and 333-172170). Exhibit 23.2 NETHERLAND, SEWELL & ASSOCIATES, INC. /s/ Danny D. Simmons By: Danny D. Simmons, P.E. President and Chief Operating Officer Houston, Texas February 18, 2015 KINDER MORGAN, INC. AND SUBSIDIARIES CERTIFICATION 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 Exhibit 31.1 I, Richard D. Kinder, certify that: 1. I have reviewed this annual report on Form 10-K of Kinder Morgan, Inc.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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 in the United States; c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: February 23, 2015 /s/ RICHARD D. KINDER _______________________________________________ Richard D. Kinder Chairman and Chief Executive Officer Exhibit 31.2 KINDER MORGAN, INC. AND SUBSIDIARIES CERTIFICATION 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 I, Kimberly A. Dang, certify that: 1. 2. 3. 4. I have reviewed this annual report on Form 10-K of Kinder Morgan, Inc.; Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a. b. c. d. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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 in the United States; evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a. b. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: February 23, 2015 /s/ KIMBERLY A. DANG Kimberly A. Dang Vice President and Chief Financial Officer Exhibit 32.1 KINDER MORGAN, INC. AND SUBSIDIARIES CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report on Form 10-K of Kinder Morgan, Inc. (the "Company") for the yearly period ended December 31, 2014, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned, in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: February 23, 2015 /s/ RICHARD D. KINDER Richard D. Kinder Chairman and Chief Executive Officer Exhibit 32.2 KINDER MORGAN, INC. CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report on Form 10-K of Kinder Morgan, Inc. (the "Company") for the yearly period ended December 31, 2014, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned, in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: February 23, 2015 /s/ KIMBERLY A. DANG Kimberly A. Dang Vice President and Chief Financial Officer KINDER MORGAN, INC. AND SUBSIDIARIES EXHIBIT 95.1 – MINE SAFETY DISCLOSURES Exhibit 95.1 This exhibit contains the information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act. The following table provides information about citations, orders and notices issued under the Federal Mine Safety and Health Act of 1977 (the "Mine Act") by the federal Mine Safety and Health Administration ("MSHA") for our mines during the year ended December 31, 2014. Mine or Operating Name/ MSHA Identification Number Section 104 S&S Citations (#) Section 104(b) Orders (#) Section 104 (d) Citations and Orders (#) Section 110(b) (2) Violations (#) Section 107(a) Orders (#) Total Dollar Value of MSHA Assessments Proposed ($) Total Number of Mining Related Fatalities (#) Received Notice of Pattern of Violations Under Section 104 (e) (yes/no) Received Notice of Potential to Have Pattern under Section 104(e) (yes/no) Legal Actions Pending as of Last Day of Period (#) Legal Actions Initiated During Period (#) Legal Actions Resolved During Period (#) 1103225 Cahokia 1518234 Grand Rivers ____________ — — — — — — — — — — $ $ — — — — No No No No — — — — — — The dollar value represents the total dollar value of all MSHA citations issued and assessed for the two terminals noted above. The value includes S&S and non-S&S citations issued during calendar year 2014. The dollar value represents citations paid, pending payment, and citations in contest as of December 31, 2014. The MSHA citations, orders and assessments reflected above are those initially issued or proposed by MSHA. They do not reflect subsequent changes in the level of severity of a citation or order or the value of an assessment that may occur as a result of proceedings conducted in accordance with MSHA rules. As of December 31, 2014, there were no pending legal actions before the Federal Mine Safety and Health Review Commission involving any of our mines other than actions filed under the following docket numbers (all of which are contests of citations or orders under Section 104 of the Mine Act): N/A During the year ended December 31, 2014, the following legal actions before the Federal Mine Safety and Health Review Commission involving our mines were resolved: N/A  KINDER MORGAN, INC. AND SUBSIDIARIES Exhibit 99.1 - Netherland, Swell & Associates, Inc's Report January 8, 2015 Dr. Lanny G. Schoeling Kinder Morgan CO2 Company, L.P. 1001 Louisiana Street, Suite 1000 Houston, Texas 77002 Dear Dr. Schoeling: In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2014, to the Kinder Morgan CO2 Company, L.P. (Kinder Morgan) interest in certain oil and gas properties located in Texas. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Kinder Morgan. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Kinder Morgan, Inc.'s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose. We estimate the net reserves and future net revenue to the Kinder Morgan interest in these properties, as of December 31, 2014, to be: Net Reserves Category Oil (MBBL) NGL (MBBL) Gas (MMCF) Future Net Revenue (M$) Present Worth at 10% Total Proved Developed Producing Proved Developed Non-Producing Proved Undeveloped 57,034.8 3,217.7 37,304.7 4,583.6 0.0 6,235.9 2,069.3 0.0 0.0 2,191,510.9 50,679.7 756,555.7 1,677,258.9 29,635.1 203,205.7 Total Proved 97,557.2 10,819.5 2,069.3 2,998,746.3 1,910,099.7 The oil volumes shown include crude oil only. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases. The estimates shown in this report are for proved reserves. No study was made to determine whether probable or possible reserves might be established for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk. Gross revenue is Kinder Morgan's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Kinder Morgan's share of production taxes, ad valorem taxes, capital costs, abandonment costs, operating expenses, and payments to net profits interests but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties. Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2014. For oil and NGL volumes, the average West Texas Intermediate posted price of $91.48 per barrel is adjusted by field for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $4.350 per MMBTU is adjusted by field for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $88.74 per barrel of oil, $68.32 per barrel of NGL, and $4.691 per MCF of gas. Operating costs used in this report are based on operating expense records of Kinder Morgan. For the nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. As requested, operating costs for the operated properties are limited to direct lease- and field-level costs and Kinder Morgan's estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Operating costs have been divided into field-level costs, per-well costs, per-unit-of-production costs, and per-unit-of-injection costs and are not escalated for inflation. Capital costs used in this report were provided by Kinder Morgan and are based on its internal planning budgets and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are Kinder Morgan's estimates of the costs to abandon the wells and production facilities, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation. For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability. We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Kinder Morgan interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Kinder Morgan receiving its net revenue interest share of estimated future gross production. The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Kinder Morgan, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report. For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for undeveloped locations and for properties that rely on continued CO2 injection; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment. The data used in our estimates were obtained from Kinder Morgan, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Derek F. Newton, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 1997 and has over 14 years of prior industry experience. Mike K. 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. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis. Sincerely, NETHERLAND, SEWELL & ASSOCIATES, INC. Texas Registered Engineering Firm F-2699 By: By: /s/ C.H. (Scott) Rees III C.H. (Scott) Rees III, P.E. Chairman and Chief Executive Officer /s/ Mike K. Norton Mike K. Norton, P.G. 441 Senior Vice President /s/ Derek F. Newton By: Derek F. Newton, P.E. 97689 Vice President Date Signed: January 8, 2015 Date Signed: January 8, 2015 DFN:JLM DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations. (1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties. (2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest: (i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) Same environment of deposition; (iii) Similar geological structure; and (iv) Same drive mechanism. Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest. (3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non- hydrocarbons. (4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature. (5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure. (6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Supplemental definitions from the 2007 Petroleum Resources Management System: Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation. Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. (7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to: (i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves. (ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly. (iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems. (iv) Provide improved recovery systems. (8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project. (9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. (10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section. (11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date. (12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are: (i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs. (ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records. (iii) Dry hole contributions and bottom hole contributions. (iv) Costs of drilling and equipping exploratory wells. (v) Costs of drilling exploratory-type stratigraphic test wells. (13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section. (14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir. (15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. (16) Oil and gas producing activities. (i) Oil and gas producing activities include: (A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations; (B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties; (C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as: (1) Lifting the oil and gas to the surface; and (2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and (D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as: a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a b. common carrier, a refinery, or a marine terminal; and In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas. Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered. (ii) Oil and gas producing activities do not include: (A) Transporting, refining, or marketing oil and gas; (B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production; (C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or (D) Production of geothermal steam. (17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. (i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. (ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. (iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. (iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. (v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. (vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. (18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. (iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. (19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence. (20) Production costs. (i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are: (A) Costs of labor to operate the wells and related equipment and facilities. (B) Repairs and maintenance. (C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities. (D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. (E) Severance taxes. (ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above. (21) Proved area. The part of a property to which proved reserves have been specifically attributed. (22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible— from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first- day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. (23) Proved properties. Properties with proved reserves. (24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease. (25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. (26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project. Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations). Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas: 932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year: a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B) b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7). The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes. 932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B: a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end. b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs. c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves. d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows. e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves. f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount. (27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. (28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations. (29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion. (30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area. (31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. From the SEC's Compliance and Disclosure Interpretations (October 26, 2009): Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule. Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following: The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities); The company's historical record at completing development of comparable long-term projects; The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities; The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority). (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. (32) Unproved properties. Properties with no proved reserves. 

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