Kinder Morgan (KMI) 10-K risk factor changes: FY2015 vs FY2014

Risks Related to [removed: Our] [added: Operating our] Business

Our [removed: pipelines business is] [added: businesses are] dependent on the supply of and demand for the commodities [removed: transported by our pipelines.][added: that we handle.]

Our [removed: pipelines] [added: pipelines, terminals and other assets and facilities] depend [added: in part] on [added: continued] production of natural gas, oil and other products in the [added: geographic] areas [removed: served by our pipelines.][added: that they serve.]

Without [removed: reserve additions,] [added: additions to oil and gas reserves,] production will decline over time as reserves are [removed: depleted] [added: depleted,] and production costs may rise.

Producers in areas served by us may not be successful in exploring for and developing additional reserves, and our [removed: gas plants and] pipelines [added: and related facilities] may not be able to maintain existing volumes of throughput.

Changes in the business environment, such as the [removed: recent] sharp decline in crude oil [removed: prices,] [added: prices that began in 2014,] an increase in production costs from higher feedstock prices, supply disruptions, or higher development costs, could result in a slowing of supply [removed: from oil] [added: to our pipelines, terminals] and [removed: natural gas producing areas.][added: other assets.]

In addition, changes in the regulatory environment or governmental policies may have an impact on the supply of crude [removed: oil and] [added: oil,] natural [removed: gas.][added: gas, coal and other products.]

Each of these factors impacts our customers shipping through our [removed: pipelines,] [added: pipelines or using our terminals,] which in turn could impact the prospects of new [removed: transportation] contracts [added: for transportation, terminaling] or [added: other midstream services, or] renewals of existing contracts.

[removed: The implementation] [added: Implementation] of new regulations or [removed: the modification of] [added: changes to] existing regulations affecting the [removed: oil and gas] [added: energy] industry could reduce [added: production of and/or] demand for natural gas, crude [removed: oil and] [added: oil,] refined petroleum products, [added: coal and other hydrocarbons,] 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 [added: production of and/or] demand for natural gas, crude oil [removed: and] refined petroleum [removed: products.][added: products and other hydrocarbons.]

We [removed: 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.

To the extent that an excess of supply into these areas is created and persists, our ability to [removed: recontract] [added: re-contract] for expiring transportation capacity at favorable rates or otherwise to retain existing customers could be impaired.

Part of our business strategy includes acquiring additional [removed: businesses, expanding existing assets] [added: businesses] and [removed: constructing new facilities.][added: assets.]

If we do not successfully integrate acquisitions, [removed: expansions or newly constructed facilities,] we may not realize anticipated operating advantages and cost savings.

[removed: The integration] [added: Integration] of acquired companies or [removed: 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; [added: and] (iv) difficulties in the assimilation and retention of necessary [removed: employees; and (v) potential adverse effects on operating results.][added: employees.]

Successful integration of each [removed: acquisition, expansion or construction project] [added: acquisition] will depend upon our ability to manage those operations and to eliminate redundant and excess costs.

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 [removed: acquisitions and expansions,] [added: acquisitions,] which would harm our financial condition and results of operations.

As of December 31, [removed: 2014,] [added: 2015,] we had approximately $41 billion of consolidated debt (excluding debt fair value adjustments).

Additionally, [removed: in connection with the Merger Transactions,] we and substantially all of our wholly owned subsidiaries [removed: entered into] [added: are parties to] a cross guarantee agreement [removed: whereby] [added: under which] each party to the agreement unconditionally guarantees the indebtedness of each other [removed: party to the agreement, thereby causing us to become] [added: party, which means that we are] liable for the debt of each of such subsidiaries.

This level of [added: consolidated] debt and the cross guarantee agreement could have important consequences, such as (i) limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements or potential growth or for other purposes; (ii) increasing the cost of our future borrowings; (iii) limiting our ability to use operating cash flow in other areas of our business or to pay dividends because we must dedicate a substantial portion of these funds to make payments on our debt; (iv) placing us at a competitive disadvantage compared to competitors with less debt; and (v) increasing our vulnerability to adverse economic and industry conditions.

Our ability to service our [added: consolidated] 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 [removed: operating results are] [added: consolidated cash flow is] not sufficient to service our [removed: indebtedness, including the cross-guaranteed] [added: consolidated] debt, and any future indebtedness that we incur, we will be forced to take [removed: actions, which may include] [added: actions such as] reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital.

We may not be able to [removed: affect] [added: effect] any of these actions on satisfactory terms or at all.

New regulations, rulemaking and oversight, as well as changes in regulations, by regulatory agencies having jurisdiction over our operations could adversely impact our [removed: income] [added: earnings, cash flows] and operations.

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 [removed: fines.][added: fines and potential loss of government contracts.]

For more information, see Items 1 and 2 “Business and [removed: Properties—(c)] [added: Properties-(c)] Narrative Description of [removed: Business—Regulation.”][added: Business-Regulation.”]

Some shippers on our pipelines have filed complaints with the regulators that seek substantial refunds for alleged overcharges during the years in [removed: question and prospective reductions in the tariff rates.]

[removed: Energy commodity] [added: 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 [removed: natural gas transmission] [added: transportation] and storage [removed: activities and] [added: of crude oil, natural gas,] refined petroleum [removed: products] [added: products, CO2, coal, chemicals] and [removed: CO2 transportation activities-such] [added: other products -such] as leaks, [removed: explosions and] [added: releases, explosions,] mechanical [removed: problems-that could result in substantial financial losses.][added: problems and damage caused by third parties.]

[removed: In addition, these] [added: 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.

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 [removed: earnings] [added: cash flows] while the affected asset is temporarily out of service.

There are, for example, federal guidelines [removed: for] [added: issued by] the DOT [removed: and] [added: for] pipeline companies in the areas of testing, education, training and communication.

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 [added: significant impact on integrity testing and repair costs.]

[removed: 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.

For example, if an accidental leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our [removed: pipelines] [added: pipelines, shipping vessels] or [removed: 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 [removed: level of] earnings and cash flows.

While we [added: believe we] have utilized operating, handling, and disposal practices that were consistent with industry practices at the time, hydrocarbons or other hazardous substances may have been released at or from properties owned, operated or used by us or our predecessors, or at or from properties where our or our predecessors’ wastes have been taken for disposal.

For more information, see Items 1 and 2 “Business and [removed: Properties—(c)] [added: Properties-(c)] Narrative Description of [removed: Business—Environmental] [added: Business-Environmental] Matters.”

Climate change regulation at the federal, state, provincial or regional levels could result in significantly increased operating and capital costs for [removed: us.][added: us and could reduce demand for our products and services.]

[removed: The] [added: Existing] EPA [removed: regulates greenhouse gas emissions and requires the reporting of] [added: regulations require us to report] greenhouse gas emissions in the U.S. [removed: for emissions] from [removed: specified large greenhouse] [added: sources such as our larger natural] gas [removed: emission sources,] [added: compressor stations,] fractionated NGL, and [removed: the] production of naturally occurring [removed: CO2, like] [added: CO2 (for example, from] our McElmo Dome CO2 [removed: field,] [added: field),] even when such production is not emitted to the atmosphere.

Our business also depends in part on the levels of demand for oil, natural gas, coal, steel, chemicals and other products in the geographic areas to which our pipelines, terminals, shipping vessels and other facilities deliver or provide service, and the ability and willingness of our shippers and other customers to supply such demand.

We are exposed to the risk of loss in the event of nonperformance by our customers or other counterparties, such as hedging counterparties, joint venture partners and suppliers.

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

We cannot provide any assurance that other financially distressed counterparties will not also default on their obligations to us or file for bankruptcy protection.

If a counterparty files for bankruptcy protection, we likely would be unable to collect all, or even a significant portion, of amounts that they owe to us.

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

Furthermore, in the case of

See “-Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.” In addition, decreases in the prices of crude oil, NGL and natural gas will have a negative impact on our operating results and cash flow.

Our ability to begin and complete construction on expansion and new build projects may be inhibited by difficulties in obtaining permits and rights-of-way, public opposition, cost overruns, inclement weather and other delays.

A variety of factors outside of our control, such as difficulties in obtaining permits and rights-of-way or other regulatory approvals that can be exacerbated by public opposition to our projects, have caused, and may continue to cause, delays in our ability to begin construction projects.

The acquisition of additional businesses and assets is part of our growth strategy.

We may experience difficulties integrating new properties and businesses, and we may be unable to achieve the benefits we expect from any future acquisitions.

Additional risks to vessels include adverse sea conditions, capsizing, grounding and navigation errors.

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

Our CO2 business segment (and the carrying value of its oil, NGL and natural gas producing properties) and certain midstream businesses within our Natural Gas Pipelines segment depend to a large degree, and certain businesses within our Product Pipelines segment depend to a lesser degree, on prevailing oil, NGL and natural gas prices.

We use hedging arrangements to partially mitigate our exposure to commodity prices, but these arrangements also are subject to inherent risks.

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

If prices fall substantially or remain low for a sustained period and we are not sufficiently protected through hedging arrangements, we may be unable to realize a profit from these businesses and would operate at a loss.

short periods of seasonal market demand.

The markets for instruments we use to hedge our commodity price exposure generally reflect then-prevailing conditions in the underlying commodity markets.

As our existing hedges expire, we will seek to replace them with new hedging arrangements.

To the extent underlying market conditions are unfavorable, new hedging arrangements available to us will reflect such unfavorable conditions.

These potential targets might include our pipeline systems, terminals, processing plants or operating systems.

A cyber security event could affect our ability to operate or control our facilities or disrupt our operations; also, customer information could be stolen.

The occurrence of one of these events could

Risks Related to Financing Our Business

We have limited amounts of internally generated cash flows to fund acquisitions and growth capital expenditures.

See “Information Regarding Forward-Looking Statements.” If the payment of dividends at the anticipated levels would leave us with insufficient cash to take timely

Our certificate of incorporation restricts the ownership of our common stock by non-U.S. citizens within the meaning of the Jones Act.

These restrictions may affect the liquidity of our common stock and may result in non-U.S. citizens being required to sell their shares at a loss.

The Jones Act requires, among other things, that at least 75% of our common stock be owned at all times by U.S. citizens, as defined under the Jones Act, in order for us to own and operate vessels in the U.S. coastwise trade.

As a safeguard to help us maintain our status as a U.S. citizen, our certificate of incorporation provides that, if the number of shares of our common stock owned by non-U.S. citizens exceeds 22%, we have the ability to redeem shares owned by non-U.S. citizens to reduce the percentage of shares owned by non-U.S. citizens to 22%.

These redemption provisions may adversely impact the marketability of our common stock, particularly in markets outside of the United States.

Further, stockholders would not have control over the timing of such redemption, and may be subject to redemption at a time when the market price or timing of the redemption is disadvantageous.

In addition, the redemption provisions might have the effect of impeding or discouraging a merger, tender offer or proxy contest by a non-U.S. citizen, even if it were favorable to the interests of some or all of our stockholders.

Risks Related to Regulation

question and prospective reductions in the tariff rates.

The results of these tests could cause

Various laws and regulations exist or are under development that seek to regulate the emission of greenhouse gases such as methane and CO2, including the EPA programs to control greenhouse gas emissions and state actions to develop statewide or regional programs.

Proposed approaches to further regulate greenhouse gas emissions include establishing greenhouse gas “cap and trade” programs, increased efficiency standards, and incentives or mandates for pollution reduction, use of renewable energy sources, or use of alternative fuels with lower carbon content.

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.

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.

significant impact on integrity testing and repair costs.

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.

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.

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.

Cost overruns and delays on our expansion and new build projects could adversely affect our business.

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 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

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, decreases in the prices of crude oil and NGL will have a negative impact on the results of our CO2 business segment.

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.

In the event prices fall substantially, we may not be able to realize a profit from our production and would operate at a loss.

The Dodd-Frank Act also requires many counterparties to our derivatives instruments

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 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.

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 [removed: 2014,] [added: 2015,] 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.”

| • | Natural Gas [removed: Pipelines—(i) the] [added: Pipelines—the] ownership and operation of [added: (i)] major interstate and intrastate natural gas pipeline and storage systems; (ii) [removed: the ownership and/or operation of associated] natural gas and crude oil gathering systems and natural gas processing and treating facilities; [removed: and] (iii) [removed: the ownership and/or operation of] NGL fractionation facilities and transportation systems; [added: and (iv) LNG facilities;] |

| • | Terminals—(i) the ownership and/or operation of liquids and bulk terminal facilities [removed: 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; |

| • | Other—primarily [removed: includes] other miscellaneous assets and liabilities [removed: 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 [removed: EP’s] legacy trading activities; and (iii) other miscellaneous [removed: EP] assets and liabilities. |

With respect to our interstate natural gas [removed: pipelines and] [added: pipelines,] related storage [removed: facilities,] [added: facilities and LNG terminals,] the revenues from these assets are primarily received under contracts with terms that are fixed for various and extended periods of time.

Similarly, the Texas Intrastate Natural Gas [removed: Group,] [added: Pipeline operations,] currently derives approximately [removed: 75%] [added: 73%] of its sales and transport margins from long-term transport and sales [removed: contracts that include requirements with minimum volume payment obligations.][added: contracts.]

As of December 31, [removed: 2014,] [added: 2015,] the remaining average contract life of our natural gas transportation contracts (including intrastate pipelines’ purchase and sales contracts) was approximately six years.

[removed: The] [added: These assets are generally fee-based and the] revenues and earnings we realize from gathering natural gas, processing natural gas in order to remove NGL from the natural gas stream, and fractionating NGL into their base components, are [removed: also] affected by the volumes of natural gas made available to our [removed: systems, which are primarily driven by levels of natural gas drilling activity.][added: systems.]

[removed: Contracts] [added: Our service contracts] may rely solely on a single type of arrangement, but more often they combine elements of two or more of the above, which helps us and our counterparties manage the extent to which each shares in the potential risks and benefits of changing commodity prices.

The CO2 source and transportation business primarily has third-party contracts with minimum volume requirements, which as of December 31, [removed: 2014,] [added: 2015,] had a remaining average contract life of approximately [removed: ten] [added: nine] years.

On a volume-weighted basis, for third-party contracts making deliveries in [removed: 2015,] [added: 2016,] and utilizing the average oil price per barrel contained in our [removed: 2015] [added: 2016] budget, approximately [removed: 86%] [added: 99%] of our revenue is based on a fixed fee or floor price, and [removed: 14%] [added: 1%] fluctuates with the price of oil.

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 [added: 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 [removed: $88.41] [added: $73.11] per barrel in [removed: 2014, $92.70] [added: 2015, $88.41] per barrel in [removed: 2013] [added: 2014,] and [removed: $87.72] [added: $92.70] per barrel in [removed: 2012.][added: 2013.]

Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged [removed: $86.48] [added: $47.56] per barrel in [removed: 2014, $94.94] [added: 2015, $86.48] per barrel in [removed: 2013] [added: 2014,] and [removed: $89.91] [added: $94.94] per barrel in [removed: 2012.][added: 2013.]

For the most part, we have contracts for this business that [removed: have] [added: contain] minimum volume guarantees [removed: and] [added: and/or service exclusivity arrangements under which customers] are [removed: volume based above the minimums.][added: required to utilize our terminals for all or a specified percentage of their handling and storage needs.]

[removed: Therefore,] the [removed: 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.

Our [removed: seven] [added: eight] 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 [added: and storage] business is generally driven by the volume of refined petroleum products that we transport and the prices we receive for our services.

[removed: Transportation] [added: The transportation and storage] volume levels are primarily driven by the demand for the refined petroleum products being shipped or stored.

[removed: In addition, a] [added: 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) [added: transact in and/or] use the [removed: local] Canadian dollar as the functional [removed: currency for its Canadian operations and we enter into foreign currency-based transactions, both of] [added: currency,] which affect segment results due to the [removed: inherent] variability in U.S. - Canadian dollar exchange rates.

For more information on our environmental disclosures, see Note [removed: 16] [added: 17] “Litigation, Environmental and Other Contingencies” to our consolidated financial statements.

For more information on legal proceedings, see Note [removed: 16] [added: 17] “Litigation, Environmental and Other Contingencies” to our consolidated financial statements.

Identifiable intangible assets having indefinite useful economic lives, including goodwill, are not subject to regular periodic amortization, [removed: and such assets are not to be amortized until their lives are determined to be finite.]

We evaluate [removed: our] goodwill for impairment on May 31 of each year.

For more information on our [removed: goodwill, see Notes 2 “Summary of Significant Accounting Policies” and 7 “Goodwill] [added: December 31, 2015 goodwill impairment evaluation] and [removed: Other Intangibles”] [added: amortizable intangibles, see Note 8 “Goodwill”] to our consolidated financial statements.

For more information on our [removed: amortizable intangibles,] [added: hedging activities,] see Note [removed: 7 “Goodwill and Other Intangibles”] [added: 14, “Risk Management”] to our consolidated financial statements.

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 [added: activities.]

[removed: Sustained] [added: Continued] lower commodity prices [removed: may also negatively impact] [added: as indicated by] forward curve pricing that is used in testing for impairment, estimated total proved and risk-adjusted probable [removed: and possible] oil and gas reserves, and related expected future cash flows, [removed: which] may result in [removed: impairment] [added: additional impairments] of our oil producing [removed: interests.][added: interests and increased DD&A expense in 2016.]

For more information on our [removed: hedging activities,] [added: interest rate swaps,] see Note [removed: 13] [added: 14] “Risk [added: Management—Interest Rate Risk] Management” to our consolidated financial statements.

As of December 31, [removed: 2014,] [added: 2015,] our pension plans were underfunded by [removed: $427] [added: $604] million and our other postretirement benefits plans were underfunded by [removed: $235] [added: $184] million.

[removed: We select] [added: For 2015, we selected] our discount rates by matching the timing and amount of our expected future benefit payments for our pension and other postretirement benefit obligations to the average yields of various high-quality bonds with corresponding maturities.

The selection of these assumptions is further discussed in Note [removed: 9] [added: 10] “Share-based Compensation and Employee Benefits” to our consolidated financial statements.

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 [added: expected future service of active participants, or over the expected future lives of inactive plan participants.]

[removed: We record these deferred] [added: | (a) | Includes] amounts [added: deferred] as either accumulated other comprehensive income (loss) or as a regulatory asset or liability for certain of our regulated operations. [added: |]

As of December 31, [removed: 2014,] [added: 2015,] we had deferred net losses of approximately [removed: $323] [added: $535] 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, [removed: 2014:][added: 2015:]

| | | Net benefit cost (income) | | | | Change in funded [removed: status and pretax accumulated other comprehensive income (loss)] [added: status(a)] | | | | Net benefit cost (income) | | | | Change in funded [removed: status and pretax accumulated other comprehensive income (loss)] [added: status(a)] | | |

| Discount rates | | $ | 10 | | | $ | [removed: 260] [added: 219] | | | $ | 2 | | | $ | [removed: 55] [added: 44] | |

| Rate of compensation increase | | [removed: 2] [added: 3] | | | | [removed: (13] [added: (10] | | ) | | — | | | | — | | |

| Health care cost trends | | — | | | | — | | | | 4 | | | | [removed: (47] [added: (31] | | ) |

Our midstream assets provide gathering and processing services for natural gas and gathering services for crude oil.

Such volumes are impacted by producer rig count and drilling activity.

In addition to fee based arrangements, we also provide some services based on percent-of-proceeds, percent-of-index and keep-whole contracts some of which may include minimum volume requirements.

Therefore, the extent to which changes in these variables affect our terminals business in the near term is a function of

The profitability of our minimum volume contracts is generally unaffected by short-term variation in economic conditions; however, to the extent we expect volumes above the minimum and/or have contracts which are volume-based we can be sensitive to changing market conditions.

We also have approximately 55 liquids terminals in this business segment that store fuels and offer blending services for ethanol and biofuels.

Our crude and condensate transportation services are primarily provided either pursuant to (i) long-term contracts that normally contain minimum volume commitments or (ii) through terms prescribed by the toll settlements with shippers and approved by regulatory authorities.

As a result of these contracts, our settlement volumes are generally not sensitive to changing market conditions in the shorter term, however, in the longer term the revenues and earnings we realize from our crude and condensate pipelines in the U.S. and Canada are affected by the volumes of crude and condensate available to our pipeline systems, which are impacted by the level of oil and gas drilling activity in the respective producing regions that we serve.

Our petroleum condensate processing facility splits condensate into its various components, such as light and heavy naphtha, under a long-term fee-based agreement with a major integrated oil company.

and such assets are not to be amortized until their lives are determined to be finite.

At year end and during other interim periods we evaluate our reporting units for events and changes that could indicate that it is more likely than not that the fair value of a reporting unit could be less than its carrying amount.

DD&A expense on our proved oil and gas properties is calculated using the unit of production (UOP) method.

The reserves that are used to determine the UOP depletion rate for leasehold acquisition and the costs to acquire proved properties is the total of our developed and undeveloped proved reserves which are known as total proved reserves.

The UOP depreciation rate for our tangible lease and well equipment costs, including development costs and exploration costs associated with successful drilling projects, is calculated based upon total proved developed reserves.

Our estimated future well plugging and abandonment costs along with future expected salvage values are considered in the UOP DD&A expense calculation.

For our oil and gas producing properties that have no proved reserves, the UOP depreciation rate is based on each property’s risk-adjusted probable reserves and NYMEX forward curve prices.

The sustained deterioration in the long-term outlook for commodity prices was a triggering event that required us to perform impairment testing of our assets that are sensitive to such commodity prices.

During 2015, we performed a two-step impairment testing of certain long-lived assets within our CO2 segment, which resulted in the impairment of certain of our oil and gas producing properties in the amount of $399 million for the year ended December 31, 2015.

As of December 31, 2015, the net book value of productive properties, plant and equipment associated with our oil and gas proved reserves was approximately $932 million, which included 49.5 million barrels of oil equivalent of estimated proved developed reserves, and the DD&A expense recorded on these properties in 2015 was $376 million.

If the estimates of proved reserves used in the unit-of-production calculation had been lower by 5%, DD&A expense in 2015 would have increased by approximately $15 million.

See Note 4 “Impairments and Disposals” to our consolidated financial statements.

Effective January 1, 2016, we changed our estimate of the service and interest cost components of net periodic benefit cost (credit) for our pension and other postretirement benefit plans.

The new estimate utilizes a full yield curve approach in the estimation of these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to their underlying projected cash flows.

The new estimate provides a more precise measurement of service and interest costs by improving the correlation between projected benefit cash flows and their corresponding spot rates.

The change does not affect the measurement of our pension and postretirement benefit obligations and it is accounted for as a change in accounting estimate, which is applied prospectively.

The change in the service and interest costs going forward will not be significant.

| DD&A expense(e) | 2,683 | | | | 2,390 | | | | 2,142 | | |

| Preferred stock dividends | (26 | | ) | | — | | | | — | | |

| DCF before certain items available to common stockholders | $ | 4,699 | | | $ | 2,618 | | | $ | 1,713 | |

| (b) | 2015 amount includes a $175 million non-cash pre-tax impairment ($84 million net after-tax impact to common stockholders) of a terminal facility reflecting the impact of an agreement to adjust certain payment terms under a contract with a coal customer, which occurred after the issuance of our 2015 fourth quarter earnings release containing our preliminary financial results ($175 million in certain items before book tax and $(48) million in book tax certain items). |

| (c) | Represents income tax provision on certain items plus discrete income tax items. |

| (f) | Excludes book tax certain items and includes income tax allocated to the segments. 2015, 2014 and 2013 amounts also include $72 million, $75 million and $66 million, respectively, of our share of taxable equity investee’s book tax expense. |

| (g) | Includes our share of taxable equity investee’s cash taxes of $(19) million, $(27) million and $(30) million in 2015, 2014 and 2013, respectively. |

| (h) | For 2015, consists primarily of non-cash compensation associated with our restricted stock awards program and for 2014 and 2013 consists primarily of excess coverage from our former master limited partnerships. |

In the Results of Operations table below and in the business segment tables that follow, segment EBDA before certain items is calculated by adjusting the segment earnings before DD&A for the applicable certain item amounts in the footnotes to those tables.

| Segment earnings before DD&A(a) | | | | | | | | | | | |

| Preferred Stock Dividends | (26 | | ) | | — | | | | — | | |

| Net Income Available to Common Stockholders | $ | 227 | | | $ | 1,026 | | | $ | 1,193 | |

After giving effect to these certain items, the remaining decrease of $550 million (18%) from the prior year in income from continuing operations before unallocable income taxes is primarily attributable to increased DD&A expense, general and administrative expense and interest expense, net of unallocable interest income.

As explained further below, our total segment earnings before DD&A did not change significantly when compared to the prior year as unfavorable commodity prices affecting our CO2 business segment were offset by increased results from our Products Pipelines, Terminals and Natural Gas Pipelines business segments.

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.

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.

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.

quantities are fixed, capped or bracketed through the use of financial derivative contracts, particularly for crude oil.

Because these contracts are volume based above the minimums, our profitability from the bulk business can be sensitive to economic conditions.

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.

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.

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.

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.

activities.

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.

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.

expected future service of active participants, or over the expected future lives of inactive plan participants.

_______

isolation or as substitutes for an analysis of our results as reported under GAAP.

For a discussion of our anticipated dividends for 2015, see “—Financial Condition—Cash Flows—KMI Dividends.”

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

However, we [removed: take steps to hedge, or limit our exposure to,] [added: manage] these risks by executing a hedging strategy that seeks to protect us financially against adverse price movements and serves to minimize potential losses.

[removed: We] [added: In addition, we] have [added: power forward and swap contracts related to legacy operations of acquired businesses for which we] entered into [removed: offsetting] positions that [removed: eliminate] [added: offset] the price risks associated with [removed: our power] [added: these] contracts.

[removed: Fundamentally, our] [added: Our] hedging strategy involves [removed: taking] [added: entering into] a [removed: simultaneous] financial position [removed: in the futures market that is equal and opposite] [added: intended] to [added: offset] our physical position, or anticipated position, in [removed: the cash market (or physical product) in] order to minimize the risk of financial loss from an adverse price change.

| Bank of America / Merrill Lynch | [removed: A-] [added: BBB+] |

| [removed: J.] [added: J] Aron [removed: & Company] / Goldman Sachs | [removed: A-] [added: BBB+] |

| J.P. Morgan | [removed: A] [added: A-] |

As of December 31, [removed: 2014] [added: 2015] and [removed: 2013,] [added: 2014,] a hypothetical 10% movement in underlying commodity natural gas prices would affect the estimated fair value of natural gas derivatives by [removed: $9] [added: $13] million and [removed: $15] [added: $9] million, respectively.

[removed: 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 [removed: $146] [added: $97] million and [removed: $201] [added: $146] million, respectively.

As of December 31, [removed: 2014] [added: 2015] and [removed: 2013,] [added: 2014,] a hypothetical 10% movement in underlying commodity NGL prices would affect the estimated fair value of our NGL derivatives by [removed: $0.3] [added: $4] million and [removed: $5] [added: $0.3] million, respectively.

As of both December 31, [removed: 2014] [added: 2015] and [removed: 2013,] [added: 2014,] a hypothetical 10% movement in underlying commodity electricity prices would not affect the estimated fair value of our power derivatives.

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 [removed: (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.

As of December 31, [removed: 2014] [added: 2015] and [removed: 2013,] [added: 2014,] the carrying values of the fixed rate debt [removed: (including the debt fair value adjustments)] were [removed: $41,538] [added: $43,039] million and [removed: $33,129] [added: $41,390] million, respectively.

These amounts compare to, as of December 31, [removed: 2014] [added: 2015] and [removed: 2013,] [added: 2014,] fair values of [removed: $42,164] [added: $37,329] million and [removed: $33,185] [added: $42,343] million, respectively.

A hypothetical 10% change in the average interest rates applicable to such debt for [removed: 2014] [added: 2015] and [removed: 2013,] [added: 2014,] would result in changes of approximately [removed: $1,539] [added: $1,667] million and [removed: $1,185] [added: $1,539] million, respectively, in the fair values of these instruments.

As of December 31, [removed: 2014] [added: 2015] and [removed: 2013] [added: 2014] we were party to [added: fixed-to-variable] interest rate swap agreements with notional principal amounts of [removed: $9,200] [added: $11,000] million and [removed: $5,400] [added: $9,200] million, respectively.

A hypothetical 10% change in the weighted average interest rate on all of our borrowings (approximately [removed: 50] [added: 49] basis points in [removed: 2014] [added: 2015] and approximately [removed: 51] [added: 50] basis points in [removed: 2013)] [added: 2014)] when applied to our outstanding balance of variable rate debt as of December 31, [removed: 2014] [added: 2015] and [removed: 2013,] [added: 2014,] including adjustments for the notional swap amounts described above, would result in changes of approximately [removed: $53] [added: $55] million and [removed: $43] [added: $53] million, respectively, in our [removed: 2014] [added: 2015] and [removed: 2013] [added: 2014] annual pre-tax earnings.

[removed: Interest] [added: Fixed-to-variable interest] rate swap agreements are entered into for the purpose of [removed: transforming] [added: converting] 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.

For more information on our interest rate risk management and on our interest rate swap agreements, see Note [removed: 13] [added: 14] “Risk Management” to our consolidated financial statements.

| Societe Generale | A |

As of December 31, 2015 and 2014, a hypothetical 10% movement in

As of December 31, 2015 and 2014, the carrying values of our variable rate debt were $188 million and $1,424 million, respectively.

These amounts compare to, as of December 31, 2015 and 2014, fair values of $152 million and $1,418 million, respectively.

As of December 31, 2015, including debt converted to variable rates through the use of interest rate swaps but excluding our debt fair value adjustments, approximately 27% of our debt balances were subject to variable interest rates.

Foreign Currency Risk

In connection with the issuance of our Euro denominated senior notes in March 2015, we entered into $1,358 million of cross-currency swap agreements that effectively convert all of the fixed-rate Euro denominated debt, including annual interest payments and the payment of principal at maturity, to U.S. dollar denominated debt at fixed rates.

These swaps eliminate the foreign currency risk associated with our foreign currency denominated debt.

As part of the EP acquisition, we acquired power forward and swap contracts.

None of these derivatives are designated as accounting hedges.

A hedge is successful to the extent gains or losses in the cash market are neutralized by losses or gains in the futures transaction.

| Morgan Stanley | A- |

_______

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

should be reclassified into earnings when the asset or liability affects earnings through cost of sales, depreciation, interest expense, etc.

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.

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.

As of December 31, 2014, approximately 26% is variable rate debt.

See Note [removed: 16] [added: 17] “Litigation, Environmental and [removed: Other”] [added: Other Contingencies”] to our consolidated financial statements.

For the fiscal year ended December 31, [removed: 2014][added: 2015]

[removed: ][added: ]

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. [added: o]

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, [removed: 2014] [added: 2015] was approximately [removed: $24,279,037,627.][added: $69,734,282,635.]

As of February [removed: 2, 2015,] [added: 11, 2016,] the registrant had [removed: 2,130,052,022] [added: 2,231,555,976] Class P shares outstanding.

| | [Information Regarding Forward-Looking [removed: Statements](#sC7583D7969CAB31C3AB036A4EF0AD1F6)] [added: Statements](#sA8E0F525AB2256788EE13BD445629009)] | [removed: [5](#sC7583D7969CAB31C3AB036A4EF0AD1F6)] [added: [5](#sA8E0F525AB2256788EE13BD445629009)] |

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| [Item [removed: 3.](#sBA02E4785815D03A6E9B36A4F2F33FA9)] [added: 3.](#sD63A476D0A8E5F23AC4D7FC8D69EE534)] | [Legal [removed: Proceedings](#sBA02E4785815D03A6E9B36A4F2F33FA9)] [added: Proceedings](#sD63A476D0A8E5F23AC4D7FC8D69EE534)] | [removed: [36](#sBA02E4785815D03A6E9B36A4F2F33FA9)] [added: [36](#sD63A476D0A8E5F23AC4D7FC8D69EE534)] |

| [Item [removed: 4.](#sE0A481435D28E57540DC36A4F324CC16)] [added: 4.](#s09F51DD27B6156C1A6D8D06D37BA3762)] | [Mine Safety [removed: Disclosures](#sE0A481435D28E57540DC36A4F324CC16)] [added: Disclosures](#s09F51DD27B6156C1A6D8D06D37BA3762)] | [removed: [36](#sE0A481435D28E57540DC36A4F324CC16)] [added: [36](#s09F51DD27B6156C1A6D8D06D37BA3762)] |

| [Item [removed: 5.](#s17D4D6C57AA76D6B139636A4A187C7CB)] [added: 5.](#s2CA51937BD4B5D759CDBA783EB5F6DB3)] | [Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity [removed: Securities](#s17D4D6C57AA76D6B139636A4A187C7CB)] [added: Securities](#s2CA51937BD4B5D759CDBA783EB5F6DB3)] | [removed: [37](#s17D4D6C57AA76D6B139636A4A187C7CB)] [added: [37](#s2CA51937BD4B5D759CDBA783EB5F6DB3)] |

| [Item [removed: 6.](#s300655590A402F2A882036A49A406524)] [added: 6.](#s63C1DB35318054F9A51DDB9F6234938E)] | [Selected Financial [removed: Data](#s300655590A402F2A882036A49A406524)] [added: Data](#s63C1DB35318054F9A51DDB9F6234938E)] | [removed: [38](#s300655590A402F2A882036A49A406524)] [added: [38](#s63C1DB35318054F9A51DDB9F6234938E)] |

| [Item [removed: 7.](#sD7E9938A85DED8805AEF36A4F3CC62EE)] [added: 7.](#sCDC4EAD2B0BF563EB9317B88081DC5C4)] | [Management’s Discussion and Analysis of Financial Condition and Results of [removed: Operations](#sD7E9938A85DED8805AEF36A4F3CC62EE)] [added: Operations](#sCDC4EAD2B0BF563EB9317B88081DC5C4)] | [removed: [39](#sD7E9938A85DED8805AEF36A4F3CC62EE)] [added: [39](#sCDC4EAD2B0BF563EB9317B88081DC5C4)] |

| | [Critical Accounting Policies and [removed: Estimates](#sA421691FB1F99BA7D46E36A4F41FBA78)] [added: Estimates](#s3532F672B2ED5043BCC7F2D7D34C65CD)] | [removed: [42](#sA421691FB1F99BA7D46E36A4F41FBA78)] [added: [41](#s3532F672B2ED5043BCC7F2D7D34C65CD)] |

| | [Results of [removed: Operations](#s8D25054149E45C48B4BF36A49B62432D)] [added: Operations](#s607C16145E2156A099B9B66E90164CDF)] | [removed: [45](#s8D25054149E45C48B4BF36A49B62432D)] [added: [45](#s607C16145E2156A099B9B66E90164CDF)] |

| | [Income Taxes—Continuing [removed: Operations](#s4ADF80D26F75007FE49D36A465BB2454)] [added: Operations](#sCEA89D83CC03572195F190EF0CD3CF14)] | [removed: [61](#s4ADF80D26F75007FE49D36A465BB2454)] [added: [63](#sCEA89D83CC03572195F190EF0CD3CF14)] |

| | [Liquidity and Capital [removed: Resources](#s48587C31D85DD37ECA3436A49B8D644D)] [added: Resources](#s5FE9F978B6FA590295E980FC53EFEFF9)] | [removed: [61](#s48587C31D85DD37ECA3436A49B8D644D)] [added: [63](#s5FE9F978B6FA590295E980FC53EFEFF9)] |

| | [Recent Accounting [removed: Pronouncements](#sE53E2A1C2DE239DAEA7636A4F5385E2F)] [added: Pronouncements](#s768834E03AB05BD5816744F79341742B)] | [removed: [67](#sE53E2A1C2DE239DAEA7636A4F5385E2F)] [added: [68](#s768834E03AB05BD5816744F79341742B)] |

| [Item [removed: 7A.](#s428A670E4B7A09E5314636A4F540CDF4)] [added: 7A.](#s2A21AC6E99EC5C9EA5FBFE0E4BB7FFF1)] | [Quantitative and Qualitative Disclosures About Market [removed: Risk](#s428A670E4B7A09E5314636A4F540CDF4)] [added: Risk](#s2A21AC6E99EC5C9EA5FBFE0E4BB7FFF1)] | [removed: [67](#s428A670E4B7A09E5314636A4F540CDF4)] [added: [69](#s2A21AC6E99EC5C9EA5FBFE0E4BB7FFF1)] |

| | [Energy Commodity Market [removed: Risk](#sF9A92EE7724A04B6D14C36A49DAF8975)] [added: Risk](#s17EE175621595AFC9C28FB62F37D51BD)] | [removed: [67](#sF9A92EE7724A04B6D14C36A49DAF8975)] [added: [69](#s17EE175621595AFC9C28FB62F37D51BD)] |

| | [Interest Rate [removed: Risk](#sDC84B32C1443986839AF36A4A3E6B518)] [added: Risk](#sE7B19310C62B593BA6EBAAF37210B99A)] | [removed: [69](#sDC84B32C1443986839AF36A4A3E6B518)] [added: [70](#sE7B19310C62B593BA6EBAAF37210B99A)] |

| [Item [removed: 8.](#s478E94DDF5D6CA568BDA36A4F56B3F8F)] [added: 8.](#s7B633407169C500E823891EC81A0AEA9)] | [Financial Statements and Supplementary [removed: Data](#s478E94DDF5D6CA568BDA36A4F56B3F8F)] [added: Data](#s7B633407169C500E823891EC81A0AEA9)] | [removed: [70](#s478E94DDF5D6CA568BDA36A4F56B3F8F)] [added: [71](#s7B633407169C500E823891EC81A0AEA9)] |

| [Item [removed: 9.](#sA3653FB5103C6B569AA236A4F58FAF24)] [added: 9.](#sB1C20A053D3257B393CEF0CEBC2446ED)] | [Changes in and Disagreements with Accountants on Accounting and Financial [removed: Disclosure](#sA3653FB5103C6B569AA236A4F58FAF24)] [added: Disclosure](#sB1C20A053D3257B393CEF0CEBC2446ED)] | [removed: [70](#sA3653FB5103C6B569AA236A4F58FAF24)] [added: [71](#sB1C20A053D3257B393CEF0CEBC2446ED)] |

| [Item [removed: 9A.](#s699D4B2D5D7CF7E7CBE636A4F5C0BE0D)] [added: 9A.](#s94AE4693DF6A5A8B8C9C5D33F3A0E2A4)] | [Controls and [removed: Procedures](#s699D4B2D5D7CF7E7CBE636A4F5C0BE0D)] [added: Procedures](#s94AE4693DF6A5A8B8C9C5D33F3A0E2A4)] | [removed: [70](#s699D4B2D5D7CF7E7CBE636A4F5C0BE0D)] [added: [71](#s94AE4693DF6A5A8B8C9C5D33F3A0E2A4)] |

10-K 1 kmi-2015x10k.htm 10-K

| Depositary Shares, each representing a 1/20th interest in a share of 9.75% Series A Mandatory Convertible Preferred Stock | New York Stock Exchange |

| | [Glossary](#s3BED0DD2E8945A06BE83F9687D5ECA87) | [4](#s3BED0DD2E8945A06BE83F9687D5ECA87) |

| | [PART I](#s709CAB4908F85C3EADAE1A32A2FD51FF) | |

| | [C](#sE96EDA78C6FD5AAB954227016E7EAF1D)O2 | [14](#sE96EDA78C6FD5AAB954227016E7EAF1D) |

| | [Terminals](#s99B3D73EE9EA5ABAA651AC8B8AF0FAFD) | [17](#s99B3D73EE9EA5ABAA651AC8B8AF0FAFD) |

| | [Other](#s8FFB2B7F2CDE58719A12AA21385028E6) | [19](#sD162CA4E068951838FFCA178002EAA1A) |

| | [Regulation](#s7F40D066D159570D92E77A6154082264) | [19](#s7F40D066D159570D92E77A6154082264) |

| | [Other](#s8FFB2B7F2CDE58719A12AA21385028E6) | [26](#s8FFB2B7F2CDE58719A12AA21385028E6) |

| | [PART II](#s5E60C414209653609CBA7B1258F45768) | |

| | [General](#s0D2A9104D0825D88B8A836682C401B05) | [39](#s0D2A9104D0825D88B8A836682C401B05) |

| | [PART IV](#s82BD9DEB59A25ABABB4FE9056122B51F) | |

| [Signatures](#s79361AB1F201541DA169A5FC7B4362B9) | | [163](#s79361AB1F201541DA169A5FC7B4362B9) |

| Copano | \= | Copano Energy, L.L.C. | KMGP | \= | Kinder Morgan G.P., Inc. |

| EagleHawk | \= | EagleHawk Field Services LLC | | | controlled subsidiaries |

| Eagle Ford | \= | Eagle Ford Gathering LLC | KMLP | \= | Kinder Morgan Louisiana Pipeline LLC |

| | | controlled subsidiaries | MEP | \= | Midcontinent Express Pipeline LLC |

| | | owned and controlled subsidiaries | SFPP | \= | SFPP, L.P. |

| Hiland | \= | Hiland Partners, LP | WYCO | \= | WYCO Development L.L.C. |

| /d | \= | per day | LIBOR | \= | London Interbank Offered Rate |

| BBtu | \= | billion British Thermal Units | LNG | \= | liquefied natural gas |

| Bcf | \= | billion cubic feet | MBbl | \= | thousand barrels |

| CERCLA | \= | Comprehensive Environmental Response, | MDth | \= | thousand dekatherms |

| | | Compensation and Liability Act | MLP | \= | master limited partnership |

| CPUC | \= | California Public Utilities Commission | MMcf | \= | million cubic feet |

| DCF | \= | distributable cash flow | NEB | \= | National Energy Board |

| DD&A | \= | depreciation, depletion and amortization | NGL | \= | natural gas liquids |

| | | excess cost of equity investments | | | Pipeline and Hazardous Materials Safety |

| | | Principles | | | |

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

| • | the ability of our customers and other counterparties to perform under their contracts with us; |

We are the largest energy infrastructure company in North America.

Our pipelines transport natural gas, refined petroleum products, crude oil, condensate,

References to EPB refer to EPB for periods prior to its merger into KMP.

| Asset or project | | Description | | Activity | | Approx. Capital Scope |

| ELC Acquisition | | Acquired Shell’s 49 percent equity interest in the ELC joint venture to develop liquefaction facilities at Elba Island, Georgia. | | Acquired July 2015. | | $510 million |

| NGPL Acquisition | | Acquired equity interest from Myria Holdings, Inc. increasing ownership in NGPL from 20 percent to 50 percent. | | Acquired December 2015. | | $136 million |

| TGP Southwest Louisiana Supply (formerly Cameron LNG) | | Project provides 900,000 Dth/d of long-term capacity to the future Cameron LNG export complex at Hackberry, Louisiana. Subscribed under long-term firm transportation contracts. | | Expected in service February 2018. | | $178 million |

| Asset or project | | Description | | Activity | | Approx. Capital Scope |

| Texas Intrastate Crossover Expansion | | Expansion project creating capacity from the Katy Hub, the company’s Houston Central processing plant, and other third party receipt points to serve the Texas Intrastate’s transportation commitments of 250,000 Dth/day to the Cheniere Corpus Christi LNG export facility and 527,000 Dth/day to the CFE at delivery points in South Texas. | | Expected in-service September 2016 for the CFE commitment and January 2019 for the Cheniere commitment. | | $164 million |

10-K 1 kmi-2014x10k.htm 10-K

| | [Glossary](#sFF114E9CF05431A1B2B336A4EEEB4D4E) | [4](#sFF114E9CF05431A1B2B336A4EEEB4D4E) |

| | [PART I](#s67A23F0AF293BB3D75C436A4EF3C042D) | |

| | [C](#sDED5A5E140885FCAFBE336A4A5DBA044)O2 | [15](#sDED5A5E140885FCAFBE336A4A5DBA044) |

| | [Other](#sC1C20B0EDCAF43D7EA1736A4F22B87A0) | [20](#s93122EF75F34116D668436A4F1833FD7) |

| | [Regulation](#sD29272AE09AC7549D44D36A4F1D889F7) | [20](#sD29272AE09AC7549D44D36A4F1D889F7) |

| | [Other](#sC1C20B0EDCAF43D7EA1736A4F22B87A0) | [26](#sC1C20B0EDCAF43D7EA1736A4F22B87A0) |

| | [PART II](#s9BE396FD74810D367EE536A4F3477143) | |

| | [General](#s5F42350C223138F1DE7336A4F3EC334D) | [39](#s5F42350C223138F1DE7336A4F3EC334D) |

| | [PART IV](#s4ED3007E8D42EFFB333536A4F72F1393) | |

| [Signatures](#s64D6D8AE4105489554C636A4AD8BF89C) | | [169](#s64D6D8AE4105489554C636A4AD8BF89C) |

| | | | | | |

| Calnev | \= | Calnev Pipe Line LLC | KMEP | \= | Kinder Morgan Energy Partners, L.P. |

| CPG | \= | Cheyenne Plains Gas Pipeline Company, L.L.C. | | | controlled subsidiaries |

| ELC | \= | Elba Liquefaction Company, L.L.C. | KMR | \= | Kinder Morgan Management, LLC |

| EPB | \= | El Paso Pipeline Partners, L.P. and its majority- | SFPP | \= | SFPP, L.P. |

| | | owned and controlled subsidiaries | SLC | \= | Southern Liquefaction Company, L.L.C. |

| BBtu/d | \= | billion British Thermal Units per day | LLC | \= | limited liability company |

| Bcf/d | \= | billion cubic feet per day | LNG | \= | liquefied natural gas |

| CERCLA | \= | Comprehensive Environmental Response, | MBbl/d | \= | thousands of barrels per day |

| | | Compensation and Liability Act | MDth/d | \= | thousand of dekatherm per day |

| CPUC | \= | California Public Utilities Commission | MMBbl/d | \= | millions barrels per day |

| DCF | \= | distributable cash flow | MMcf/d | \= | million cubic feet per day |

| DD&A | \= | depreciation, depletion and amortization | NEB | \= | National Energy Board |

| | | amortization expenses, including amortization of | OTC | \= | over-the-counter |

| | | Principles | WTI | \= | West Texas Intermediate |

| • | the ability to complete expansion projects and construction of our vessels on time and on budget; |

We are the largest energy infrastructure and the third largest energy company in North America with an enterprise value of more than $125 billion.

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.

| 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. | | Plant placed in service third quarter 2014. Compression placed in service fourth quarter 2014. | | $236 million |

| TGP Utica Backhaul | | Expansion project that provides 500,000 Dth/d incremental natural gas transportation capacity, from Utica south to the Tennessee Zone 1 area. | | Placed in service April 2014. | | $175 million |

| KM Texas and Mier-Monterrey pipelines expansion | | 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. | | First portion placed in service September and December 2014, expected second phase in service 2016. | | $105 million |

| Keystone Storage | | 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. | | Acquired July 2014. | | $92 million |

| TGP Rose Lake | | 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. | | $74 million |

| Sierrita Gas Pipeline | | 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. | | $66 million |

| Natural Gas Pipelines - Other announcements continued | | | | | | |

| 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. | | Precedent agreements executed. Expected in service fourth quarter 2018. | | $138 million |

| 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. | | $82 million |

| 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. | | $77 million |

[added: Our Class P common stock is listed for trading on the NYSE under the symbol “KMI.”] The high and low sale prices per Class P share as reported on the NYSE and the dividends declared per share by period for [removed: 2014, 2013] [added: 2015, 2014] and [removed: 2012,] [added: 2013,] are provided below.

| (a) | Dividend information is for dividends declared with respect to that quarter. Generally, our declared dividends [added: for our Class P common stock] are paid on or about the 16th day of each February, May, August and November. |

As of February [removed: 2, 2015,] [added: 11, 2016,] we had [removed: 12,483] [added: 12,739] holders of our Class P common stock, which does not include beneficial owners whose shares are held by a [removed: clearing agency,] [added: nominee,] such as a broker or bank.

For information on our equity compensation plans, see Note [removed: 9] [added: 10] “Share-based Compensation and Employee Benefits—Share-based [removed: Compensation—Kinder Morgan, Inc.”] [added: Compensation”] to our consolidated financial statements.

| Our Purchases of Our [removed: Class P Shares and] Warrants | | | | | | | | | | | | | | |

| Period | | Total number of securities [removed: purchased] [added: purchased(a)] | | | Average price paid per security | | | | Total number of securities purchased as part of publicly announced [removed: plans] [added: plans(a)] | | | Maximum number (or approximate dollar value) of securities that may yet be purchased under the plans or [removed: programs(a)] [added: programs] | | |

| 2015 | | | | | | | | | | | |

| First Quarter | $ | 39.45 | | | $ | 42.93 | | | $ | 0.48 | |

| Second Quarter | 38.33 | | | | 44.71 | | | | 0.49 | | |

| Third Quarter | 25.81 | | | | 38.58 | | | | 0.51 | | |

| Fourth Quarter | 14.22 | | | | 32.89 | | | | 0.125 | | |

| October 1 to October 31, 2015 | | 212,345 | | | $ | 0.90 | | | 212,345 | | | $ | 90,428,906 | |

| November 1 to November 30, 2015 | | — | | | — | | | | — | | | 90,428,906 | | |

| December 1 to December 31, 2015 | | — | | | — | | | | — | | | 90,428,906 | | |

| Total Warrants | | | | | | | | | | | | $ | 90,428,906 | |

| (a) | On June 12, 2015, we announced that our board of directors had approved a warrant repurchase program authorizing us to repurchase up to $100 million of warrants. |

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.

| 2012 | | | | | | | | | | | |

| First Quarter | $ | 31.76 | | | $ | 39.25 | | | $ | 0.32 | |

| Second Quarter | 30.51 | | | | 40.25 | | | | 0.35 | | |

| Third Quarter | 32.03 | | | | 36.63 | | | | 0.36 | | |

| Fourth Quarter | 31.93 | | | | 36.50 | | | | 0.37 | | |

| October 1 to October 31, 2014 | | — | | | $ | — | | | — | | | $ | 2,452,606 | |

| November 1 to November 30, 2014 | | — | | | $ | — | | | — | | | $ | 2,452,606 | |

| December 1 to December 31, 2014 | | — | | | $ | — | | | — | | | $ | 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. |

| | [removed: 2014] [added: 2015] | | | | [removed: 2013] [added: 2014] | | | | [removed: 2012] [added: 2013] | | | | [removed: 2011] [added: 2012] | | | | [removed: 2010] [added: 2011] | | |

| Revenues | $ | [removed: 16,226] [added: 14,403] | | | $ | [removed: 14,070] [added: 16,226] | | | $ | [removed: 9,973] [added: 14,070] | | | $ | [removed: 7,943] [added: 9,973] | | | $ | [removed: 7,852] [added: 7,943] | |

| Operating income | [removed: 4,448] [added: 2,447] | | | | [removed: 3,990] [added: 4,448] | | | | [removed: 2,593] [added: 3,990] | | | | [removed: 1,423] [added: 2,593] | | | | [removed: 1,133] [added: 1,423] | | |

| Earnings [removed: (loss)] from equity investments | [removed: 406] [added: 384] | | | | [removed: 327] [added: 406] | | | | [removed: 153] [added: 327] | | | | [removed: 226] [added: 153] | | | | [removed: (274] [added: 226] | | [removed: )] |

| Income from continuing operations | [removed: 2,443] [added: 208] | | | | [removed: 2,696] [added: 2,443] | | | | [removed: 1,204] [added: 2,696] | | | | [removed: 449] [added: 1,204] | | | | [removed: 64] [added: 449] | | |

| (Loss) income from discontinued operations, net of tax | — | | | | [removed: (4] [added: —] | | [removed: )] | | [removed: (777] [added: (4] | | ) | | [removed: 211] [added: (777] | | [added: )] | | [removed: 236] [added: 211] | | |

| Net income | [removed: 2,443] [added: 208] | | | | [removed: 2,692] [added: 2,443] | | | | [removed: 427] [added: 2,692] | | | | [removed: 660] [added: 427] | | | | [removed: 300] [added: 660] | | |

| Net income [removed: (loss)] attributable to Kinder Morgan, Inc. | [removed: 1,026] [added: 253] | | | | [removed: 1,193] [added: 1,026] | | | | [removed: 315] [added: 1,193] | | | | [removed: 594] [added: 315] | | | | [removed: (41] [added: 594] | | [removed: )] |

| Basic and Diluted Earnings Per Common Share From Continuing Operations | $ | [removed: 0.89] [added: 0.10] | | | $ | [removed: 1.15] [added: 0.89] | | | $ | [removed: 0.56] [added: 1.15] | | | $ | [removed: 0.70] [added: 0.56] | | | [added: $] | [added: 0.70] | |

| Basic and Diluted (Loss) Earnings Per Common Share From Discontinued Operations | — | | | | — | | | | [removed: (0.21] [added: —] | | [removed: )] | | [removed: 0.04] [added: (0.21] | | [added: )] | | [added: 0.04] | | |

| Total Basic and Diluted Earnings Per Common Share | $ | [removed: 0.89] [added: 0.10] | | | $ | [removed: 1.15] [added: 0.89] | | | $ | [removed: 0.35] [added: 1.15] | | | $ | [removed: 0.74] [added: 0.35] | | | [added: $] | [added: 0.74] | |

| Basic and Diluted Earnings Per Common Share From Continuing Operations | | | | | | | | | [removed: $] | [removed: 0.47] | | | $ | [removed: 0.64] [added: 0.47] | | | [added: $] | [added: 0.64] | |

| Basic and Diluted (Loss) Earnings Per Common Share From Discontinued Operations | | | | | | | | | [removed: (0.21] | | [removed: )] | | [removed: 0.04] [added: (0.21] | | [added: )] | | [added: 0.04] | | |

| Total Basic and Diluted Earnings Per Common Share | | | | | | | | | [removed: $] | [removed: 0.26] | | | $ | [removed: 0.68] [added: 0.26] | | | [added: $] | [added: 0.68] | |

| Basic Weighted Average Number of [added: Common] Shares Outstanding: | | | | | | | | | | | | | | | | | | | |

| Class P shares | [removed: 1,137] [added: 2,187] | | | | [removed: 1,036] [added: 1,137] | | | | [removed: 461] [added: 1,036] | | | | [removed: 118] [added: 461] | | | | [added: 118] | | |

| Class A shares | | | | | | | | | [removed: 446] | | | | [removed: 589] [added: 446] | | | | [added: 589] | | |

| Diluted Weighted Average Number of [added: Common] Shares Outstanding: | | | | | | | | | | | | | | | | | | | |

| Class P shares | [removed: 1,137] [added: 2,193] | | | | [removed: 1,036] [added: 1,137] | | | | [removed: 908] [added: 1,036] | | | | [removed: 708] [added: 908] | | | | [added: 708] | | |

| Dividends per common share declared for the period(a)(b) | $ | [removed: 1.74] [added: 1.605] | | | $ | [removed: 1.60] [added: 1.740] | | | $ | [removed: 1.40] [added: 1.600] | | | $ | [removed: 1.05] [added: 1.400] | | | [added: $] | [added: 1.050] | |

| Dividends per common share paid in the period(a) | [removed: 1.70] [added: 1.93] | | | | [removed: 1.56] [added: 1.70] | | | | [removed: 1.34] [added: 1.56] | | | | [removed: 0.74] [added: 1.34] | | | | [added: 0.74] | | |

| Net property, plant and equipment | $ | [removed: 38,564] [added: 40,547] | | | $ | [removed: 35,847] [added: 38,564] | | | $ | [removed: 30,996] [added: 35,847] | | | $ | [removed: 17,926] [added: 30,996] | | | $ | [removed: 17,071] [added: 17,926] | |

| Long-term debt(c) | [removed: 38,312] [added: 40,732] | | | | [removed: 31,910] [added: 38,312] | | | | [removed: 29,409] [added: 31,910] | | | | [removed: 13,261] [added: 29,409] | | | | [removed: 13,219] [added: 13,261] | | |

| (c) | Excludes debt fair value adjustments. Increases to long-term debt for debt fair value adjustments totaled [removed: $1,934] [added: $1,674] million, [removed: $1,977] [added: $1,785] million, [removed: $2,591] [added: $1,863] million, [removed: $1,095] [added: $2,479] million and [removed: $594] [added: $1,036] million as of December 31, [added: 2015,] 2014, 2013, 2012, [removed: 2011,] and [removed: 2010,] [added: 2011,] respectively. |

| Net income available to common stockholders | 227 | | | | 1,026 | | | | 1,193 | | | | 315 | | | | 594 | | |

| Class A shares | | | | | | | | | | | | | 446 | | | | 589 | | |

| Total assets | 84,104 | | | | 83,049 | | | | 75,071 | | | | 68,133 | | | | 30,658 | | |

| Total assets | 83,198 | | | | 75,185 | | | | 68,245 | | | | 30,717 | | | | 28,908 | | |

As of December 31, [removed: 2014,] [added: 2015,] 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.

Based on this assessment, our management concluded that our internal control over financial reporting was effective as of December 31, [removed: 2014.][added: 2015.]

The effectiveness of our internal control over financial reporting as of December 31, [removed: 2014,] [added: 2015,] has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their audit report, which appears herein.

There has been no change in our internal control over financial reporting during the fourth quarter of [removed: 2014] [added: 2015] that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

We acquired Hiland in a purchase business acquisition on February 13, 2015.

Hiland is a wholly-owned subsidiary and we excluded this business from the scope of our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2015.

Hiland total assets and total revenues represent 4% and 3%, respectively, of our related consolidated financial statement amounts as of and for the year ended December 31, 2015.

The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the [removed: 2015] [added: 2016] Annual Meeting of Stockholders, which shall be filed no later than April 30, [removed: 2015.][added: 2016.]

The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the [removed: 2015] [added: 2016] Annual Meeting of Stockholders, which shall be filed no later than April 30, [removed: 2015.][added: 2016.]

The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the [removed: 2015] [added: 2016] Annual Meeting of Stockholders, which shall be filed no later than April 30, [removed: 2015.][added: 2016.]

The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the [removed: 2015] [added: 2016] Annual Meeting of Stockholders, which shall be filed no later than April 30, [removed: 2015.][added: 2016.]

The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the [removed: 2015] [added: 2016] Annual Meeting of Stockholders, which shall be filed no later than April 30, [removed: 2015.][added: 2016.]

| See “Index to Financial Statements” set forth on Page [removed: [77](#sF61A9DFEC8414AF682C036A4F78177EB).] [added: [77](#sC3481BA8BD1358D29D671CF59785A730).] | |

| Exhibit Number [added: Description] | | | [removed: 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, [removed: Inc.,] [added: Inc. (KMI)] and P Merger Sub LLC (schedules omitted pursuant to Item 601(b)(2) of Regulation S-K) (filed as Exhibit 2.1 to [removed: Kinder Morgan, Inc.’s] [added: KMI’s] Current Report on Form [removed: 8-K (File No. 1-35081),] [added: 8-K,] filed August 12, [removed: 2014)] [added: 2014 (File No. 001-35081))] |

| 2.2 | | * | Agreement and Plan of Merger, dated as of August 9, 2014, by and among Kinder Morgan Management, LLC, [removed: Kinder Morgan, Inc.,] [added: KMI,] and R Merger Sub LLC (schedules omitted pursuant to Item 601(b)(2) of Regulation S-K) (filed as Exhibit 2.2 to [removed: Kinder Morgan, Inc.’s] [added: KMI’s] Current Report on Form [removed: 8-K (File No. 1-35081),] [added: 8-K,] filed August 12, [removed: 2014)] [added: 2014 (File No. 001-35081))] |

| 2.3 | | * | Agreement and Plan of Merger, dated as of August 9, 2014, by and among El Paso Pipeline Partners, L.P., El Paso Pipeline GP Company, L.L.C., [removed: Kinder Morgan, Inc.,] [added: KMI,] and E Merger Sub LLC (schedules omitted pursuant to Item 601(b)(2) of Regulation S-K) (filed as Exhibit 2.3 to [removed: Kinder Morgan, Inc.’s] [added: KMI’s] Current Report on Form [removed: 8-K (File No. 1-35081),] [added: 8-K,] filed August 12, [removed: 2014)] [added: 2014 (File No. 001-35081))] |

[removed: | 3.2 | | | Amended and Restated Bylaws of] Kinder Morgan, Inc. [removed: as amended by the Amendment No. 1 to the] [added: 2015] Amended and Restated [removed: Bylaws |][added: Stock Incentive Plan]

| 4.1 | | * | Form of certificate representing Class P common shares of [removed: Kinder Morgan, Inc.] [added: KMI] (filed as Exhibit 4.1 to [removed: Kinder Morgan, Inc.’s] [added: KMI’s] Registration Statement on Form S-1 filed on January 18, 2011 (File No. 333-170773)) |

| 4.2 | | * | Shareholders Agreement among [removed: Kinder Morgan, Inc.] [added: KMI] and certain holders of common stock (filed as Exhibit 4.2 to [added: KMI’s Quarterly Report on Form 10-Q for] the [removed: KMI 10-Q)] [added: three Months ended March 31, 2011 (File No. 001-35081))] |

| 4.3 | | * | Amendment No. 1 to the Shareholders Agreement among [removed: Kinder Morgan, Inc.] [added: KMI] and certain holders of common stock (filed as Exhibit 4.3 [removed: Kinder Morgan, Inc.’s] [added: to KMI’s] Current Report on Form 8-K filed on May 30, 2012 (File No. [removed: 1-35081))] [added: 001-35081))] |

| 4.4 | | * | Amendment No. 2 to the Shareholders Agreement among [removed: Kinder Morgan, Inc.] [added: KMI] and certain holders of common stock (filed as Exhibit 4.1 to [removed: Kinder Morgan, Inc.’s] [added: KMI’s] Current Report on Form 8-K filed on December 3, 2014 (File No. [removed: 1-35081))] [added: 001-35081))] |

| 4.5 | | * | Warrant Agreement, dated as of May 25, 2012, among [removed: Kinder Morgan, Inc.,] [added: KMI,] Computershare Trust Company, N.A. and Computershare Inc., as Warrant Agent (filed as Exhibit 4.1 to [removed: Kinder Morgan Inc.’s] [added: KMI’s] Current Report on Form 8-K filed on May 30, 2012 (File No. [removed: 1-35081))] [added: 001-35081))] |

[removed: | 10.3 | | * |] Kinder Morgan, Inc. [added: Amended and Restated] Stock Compensation Plan for Non-Employee Directors [removed: (filed as Exhibit 10.4 to the KMI 10-Q) |]

| [removed: 10.4] [added: 10.6] | | * | [added: 2011] Form of Non-Employee Director Stock Compensation Agreement (filed as Exhibit 10.3 to [added: KMI’s Quarterly Report on Form 10-Q for] the [removed: KMI 10-Q)] [added: three months ended March 31, 2011 (File No. 001-35081))] |

| [removed: 10.9] [added: 10.13] | | * | [removed: Registration Rights Agreement among Kinder Morgan Management, LLC,] [added: Indenture dated January 2, 2001 between] Kinder Morgan Energy Partners, L.P. and [removed: Kinder Morgan Kansas, Inc. dated May 18, 2001] [added: First Union National Bank, as trustee, relating to Senior Debt Securities (including form of Senior Debt Securities)] (filed as Exhibit [removed: 4.7] [added: 4.11] to Kinder Morgan [removed: Kansas, Inc.’s] [added: Energy Partners, L.P.’s] Annual Report on Form 10-K for the year ended December 31, [removed: 2002] [added: 2000] (File No. [removed: 1-06446))] [added: 1-11234))] |

| [removed: 10.10] [added: 10.18] | | * | [removed: Form of] Indenture dated [removed: as of] August [removed: 27,] [added: 19,] 2002 between Kinder Morgan [removed: Kansas, Inc.] [added: Energy Partners, L.P.] and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan [removed: Kansas, Inc.’s] [added: Energy Partners, L.P.’s] Registration Statement on Form S-4 filed on October 4, 2002 (File No. [removed: 333-100338))] [added: 333-100346))] |

| [removed: 10.11] [added: 10.9] | | * | Form of [removed: First Supplemental] [added: Senior] Indenture [removed: 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 [removed: S-4] [added: S-3] filed on [removed: January 31,] [added: February 4,] 2003 (File No. [removed: 333-102873))] [added: 333-102963))] |

| [removed: 10.12] [added: 10.10] | | * | Form of [removed: 6.50%] [added: Senior] Note [removed: due 2012] [added: of Kinder Morgan Kansas, Inc.] (included in the [added: Form of Senior] Indenture filed as Exhibit [removed: 4.1] [added: 4.2] to Kinder Morgan Kansas, Inc.’s Registration Statement on Form [removed: S-4] [added: S-3] filed on [removed: October] [added: February] 4, [removed: 2002] [added: 2003] (File No. [removed: 333-100338))] [added: 333-102963))] |

| [removed: 10.13] [added: 10.21] | | * | [removed: Form of] Senior Indenture [added: dated January 31, 2003] between Kinder Morgan [removed: Kansas, Inc.] [added: Energy Partners, L.P.] and Wachovia Bank, National [removed: Association, as Trustee] [added: Association] (filed as Exhibit 4.2 to Kinder Morgan [removed: Kansas, Inc.’s] [added: Energy Partners, L.P.’s] Registration Statement on Form S-3 filed on February 4, 2003 (File No. [removed: 333-102963))] [added: 333-102961))] |

| [removed: 10.14] [added: 10.22] | | * | Form of Senior Note of Kinder Morgan [removed: Kansas, Inc.] [added: Energy Partners, L.P.] (included in the Form of Senior Indenture filed as Exhibit 4.2 to Kinder Morgan [removed: Kansas, Inc.’s] [added: Energy Partners, L.P.’s] Registration Statement on Form S-3 filed on February 4, 2003 (File No. [removed: 333-102963))] [added: 333-102961))] |

| [removed: 10.15] [added: 10.11] | | * | Indenture dated as of December 9, 2005, among Kinder Morgan Finance Company LLC (formerly Kinder Morgan Finance Company, ULC), Kinder Morgan Kansas, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 15, 2005 (File No. 1-06446)) |

| [removed: 10.16] [added: 10.12] | | * | Forms of Kinder Morgan Finance Company LLC Notes (included in the Indenture filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 15, 2005 (File No. 1-06446)) |

| [removed: 10.18] [added: 10.25] | | * | [removed: Delegation] [added: Certificate] of [removed: Control Agreement among] [added: the Vice President and Treasurer and the Vice President and Chief Financial Officer of] Kinder Morgan Management, [removed: LLC,] [added: LLC and] Kinder Morgan G.P., [removed: Inc. and] [added: Inc., on behalf of] Kinder Morgan Energy Partners, [removed: L.P. and its operating partnerships] [added: L.P., establishing the terms of the 6.95% Senior Notes due 2038] (filed as Exhibit [removed: 10.1] [added: 4.2] to [removed: the] Kinder Morgan Energy Partners, [removed: L.P.] [added: L.P.’s Quarterly Report on] Form 10-Q for the quarter ended June 30, [removed: 2001] [added: 2007] (File No. 1-11234)) |

| [removed: 10.19] [added: 10.40] | | * | [removed: Amendment No. 1 to Delegation of Control] [added: Support] Agreement, dated as of [removed: July 20, 2007,] [added: August 9, 2014, by and] among Kinder Morgan [added: Energy Partners, L.P., Kinder Morgan] G.P., Inc., Kinder Morgan Management, LLC, [removed: Kinder Morgan Energy] [added: El Paso Pipeline] Partners, [removed: L.P.] [added: L.P., El Paso Pipeline GP Company, L.L.C., Richard D. Kinder] and [removed: its operating partnerships] [added: RDK Investments, Ltd.] (filed as Exhibit 10.1 to [removed: Kinder Morgan Energy Partners, L.P.’s] [added: KMI’s] Current Report on Form 8-K [removed: on July 20, 2007] [added: filed August 12, 2014] (File No. [removed: 1-11234))] [added: 001-35081))] |

| [removed: 10.28] [added: 10.19] | | * | [added: First Supplemental] Indenture [added: to Indenture] dated [removed: November 8, 2000] [added: August 19, 2002, dated August 23, 2002] between Kinder Morgan Energy Partners, L.P. and [removed: First Union National] [added: Wachovia] Bank, [added: National Association,] as Trustee (filed as Exhibit [removed: 4.8] [added: 4.2] to Kinder Morgan Energy Partners, L.P.’s [removed: Annual Report] [added: Registration Statement] on Form [removed: 10-K for the year ended December 31, 2001] [added: S-4 filed on October 4, 2002] (File No. [removed: 1-11234))] [added: 333-100346))] |

| [removed: 10.30] [added: 10.14] | | * | 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, [removed: L.P.] [added: L.P.’s] Current Report on Form 8-K filed on March 14, 2001 (File No. 1-11234)) |

| [removed: 10.31] [added: 10.15] | | * | Specimen of 7.40% Notes due March 15, 2031 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners, [removed: L.P.] [added: L.P.’s] Current Report on Form 8-K filed on March 14, 2001(File No. 1-11234)) |

| [removed: 10.32] [added: 10.16] | | * | 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, [removed: L.P.] [added: L.P.’s] Quarterly Report on Form 10-Q for the quarter ended March 31, 2002 (File No. 1-11234)) |

| [removed: 10.33] [added: 10.17] | | * | Specimen of 7.750% Notes due March 15, 2032 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners, [removed: L.P.] [added: L.P.’s] Quarterly Report on Form 10-Q for the quarter ended March 31, 2002 (File No. 1-11234)) |

| [removed: 10.34] [added: 10.20] | | * | [added: Form of 7.30% Notes due 2033 (contained in the] Indenture [removed: dated August 19, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association, as Trustee (filed] [added: filed] as Exhibit 4.1 to [removed: the] Kinder Morgan Energy Partners, [removed: L.P.] [added: L.P.’s] Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346)) |

| [removed: 10.39] [added: 10.23] | | * | Certificate of Vice President, Treasurer and Chief Financial Officer and Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 5.80% Notes due March 15, 2035 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, [removed: L.P.] [added: L.P.’s] Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 (File No. 1-11234)) |

| [removed: 10.40] [added: 10.24] | | * | Certificate of Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 6.00% Senior Notes due 2017 and 6.50% Senior Notes due 2037 (filed as Exhibit 4.28 to Kinder Morgan Energy Partners, [removed: L.P.] [added: L.P.’s] Annual Report on Form 10-K for the year ended December 31, 2006 (File No. 1-11234)) |

| [removed: 10.41] [added: 10.28] | | * | Certificate of the Vice President and [removed: Treasurer] [added: Chief Financial Officer] and the Vice President and [removed: Chief Financial Officer] [added: 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 [removed: 6.95%] [added: 5.625%] Senior Notes due [removed: 2038] [added: 2015, and the 6.85% Senior Notes due 2020] (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, [removed: L.P.] [added: L.P.’s] Quarterly Report on Form 10-Q for the quarter ended June 30, [removed: 2007] [added: 2009] (File No. 1-11234)) |

| [removed: 10.42] [added: 10.26] | | * | Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.95% Senior Notes due 2018 (filed as Exhibit 4.28 to Kinder Morgan Energy Partners, [removed: L.P.] [added: L.P.’s] Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 1-11234)) |

| [removed: 10.43] [added: 10.27] | | * | Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 9.00% Senior Notes due 2019 (filed as Exhibit 4.29 to Kinder Morgan Energy Partners, [removed: L.P.] [added: L.P.’s] Annual Report on Form 10-K for the year ended December 31, 2008 (File No. 1-11234)) |

| [removed: 10.44] [added: 10.30] | | * | Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the [removed: 5.625%] [added: 5.30%] Senior Notes due [removed: 2015,] [added: 2020,] and the [removed: 6.85%] [added: 6.55%] Senior Notes due [removed: 2020] [added: 2040] (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, [removed: L.P.] [added: L.P.’s] Quarterly Report on Form 10-Q for the quarter ended June 30, [removed: 2009] [added: 2010] (File No. 1-11234)) |

| [removed: 10.45] [added: 10.29] | | * | Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.80% Senior Notes due 2021, and the 6.50% Senior Notes due 2039 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, [removed: L.P.] [added: L.P.’s] Quarterly Report on Form 10-Q for the quarter ended September 30, 2009 (File No. 1-11234)) |

| [removed: 10.46] [added: 10.33] | | * | Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the [removed: 5.30%] [added: 3.500%] Senior Notes due [removed: 2020,] [added: 2016,] and the [removed: 6.55%] [added: 6.375%] Senior Notes due [removed: 2040] [added: 2041] (filed as Exhibit [removed: 4.2] [added: 4.1] to Kinder Morgan Energy Partners, [removed: L.P.] [added: L.P.’s] Quarterly Report on Form 10-Q for the quarter ended [removed: June 30, 2010] [added: March 31, 2011] (File No. 1-11234)) |

| [removed: 10.47] [added: 10.31] | | * | Indenture, dated December 20, 2010, among Kinder Morgan Finance Company LLC, Kinder Morgan Kansas, Inc. and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 23, 2010 (File No. 1-06446)) |

| [removed: 10.48] [added: 10.32] | | * | Officers’ Certificate establishing the terms of the 6.000% Senior Notes due 2018 of Kinder Morgan Finance Company LLC (with the form of note attached thereto) (filed as Exhibit 4.2 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 23, 2010 (File No. 1-06446)) |

| [removed: 10.49] [added: 10.34] | | * | Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the [removed: 3.500%] [added: 4.150%] Senior Notes due [removed: 2016,] [added: 2022,] and the [removed: 6.375%] [added: 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 [removed: March 31,] [added: September 30,] 2011 (File No. 1-11234)) |

| 3.1 | | * | Amended and Restated Certificate of Incorporation of KMI (filed as Exhibit 3.1 to KMI’s Quarterly Report on Form 10-Q for the three months ended June 30, 2015 (File No. 001-35081)) |

| 3.2 | | * | Amended and Restated Bylaws of KMI as amended by Amendment No. 1 to the Amended and Restated Bylaws (filed as Exhibit 3.1 to KMI’s Current Report on Form 8-K, filed January 26, 2016 (File No. 001-35081)) |

| Exhibit Number Description | | | |

| 3.3 | | * | Certificate of Designations of KMI 9.75% Series A Mandatory Convertible Preferred Stock, par value $0.01 per share (KMI Preferred Stock) (filed as Exhibit 3.1 to KMI’s Current Report on Form 8-K filed October 30, 2015 (File No. 001-35081)) |

| 4.6 | | * | Form of certificate for KMI Preferred Stock (included as Exhibit A to Exhibit 3.1 to KMI’s Current Report on Form 8-K filed October 30, 2015 (File No. 001-35081)) |

| 4.7 | | * | Deposit Agreement, dated as of October 30, 2015, between KMI and Computershare Inc. and Computershare Trust Company, N.A., as joint depositary, on behalf of all holders from time to time of the depositary receipts issued thereunder (filed as Exhibit 4.2 to KMI’s Current Report on Form 8-K filed October 30, 2015 (File No. 001-35081)) |

| 4.8 | | * | Form of Depositary Receipt for depositary shares, each representing 1/20th of a share of KMI Preferred Stock (included as Exhibit A to Exhibit 4.2 to KMI’s Current Report on Form 8-K filed October 30, 2015 (File No. 001-35081)) |

| 10.1 | | * | KMI 2015 Amended and Restated Stock Incentive Plan (filed as Exhibit 4.5 to KMI’s Registration Statement on Form S-8, filed on July 1, 2015, and incorporated herein by reference (File No. 333-205430)) |

| 10.2 | | * | 2015 Form of Employee Restricted Stock Unit Agreement (filed as Exhibit 4.6 to KMI’s Registration Statement on Form S-8, filed on July 1, 2015, and incorporated herein by reference (File No. 333-205430)) |

| 10.3 | | * | 2011 Form of Employee Restricted Stock Agreement (filed as Exhibit 10.2 to KMI’s Quarterly Report on Form 10-Q for the three months ended March 31, 2011 (File No. 001-35081)) |

| 10.4 | | * | Amended and Restated Stock Compensation Plan for Non-Employee Directors (filed as Exhibit 10.5 to KMI’s Quarterly Report on Form 10-Q for the three months ended June 30, 2015 (File No. 001-35081)) |

| 10.5 | | * | 2015 Form of Non-Employee Director Stock Compensation Agreement (filed as Exhibit 10.6 to KMI’s Quarterly Report on Form 10-Q for the three months ended June 30, 2015 (File No. 001-35081)) |

| 10.7 | | * | KMI Employees Stock Purchase Plan (filed as Exhibit 10.5 to KMI’s Quarterly Report on Form 10-Q for the three months ended March 31, 2011 (File No. 001-35081)) |

| 10.8 | | * | Amended and Restated Annual Incentive Plan of KMI (filed as Exhibit 10.4 to KMI’s Quarterly Report on Form 10-Q for the three months ended June 30, 2015 (File No. 001-35081)) |

| Exhibit Number Description | | | |

| Exhibit Number Description | | | |

| 10.39 | | * | Certificate of Vice President and Treasurer and Vice President and Secretary of KMI establishing the terms of the 1.500% Senior Notes due 2022 and 2.250% Senior Notes due 2027 (filed as Exhibit 4.2 to KMI’s Form 8-A, filed March 16, 2015 and incorporated herein by reference (File No. 001-35081)) |

| Exhibit Number Description | | | |

As described in Management’s Report on Internal Control over Financial Reporting appearing in Item 9A of the Company’s 2015 Annual Report on Form 10- K, management has excluded Hiland Partners, LP from its assessment of internal control over financial reporting as of December 31, 2015 because it was acquired in a purchase business combination by Kinder Morgan, Inc. on February 13, 2015.

We have also excluded Hiland Partners, LP from our audit of internal control over financial reporting.

Hiland Partners, LP is a wholly-owned subsidiary whose total assets and total revenues represent 4% and 3%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2015.

| Loss on impairment of goodwill | 1,150 | | | | — | | | | — | | |

| Loss (gain) on impairments and disposals of long-lived assets, net | 919 | | | | 274 | | | | (98 | | ) |

| Loss on impairments of equity investments | (30 | | ) | | — | | | | (65 | | ) |

| Preferred Stock Dividends | (26 | | ) | | — | | | | — | | |

| Total Assets | $ | 84,104 | | | $ | 83,049 | |

| Total Liabilities | 48,701 | | | | 48,623 | | |

| Total Liabilities and Stockholders’ Equity | $ | 84,104 | | | $ | 83,049 | |

| Loss on impairment of goodwill (Note 4) | 1,150 | | | | — | | | | — | | |

| Loss (gain) on impairments and disposals of long-lived assets and equity investments, net | 949 | | | | 274 | | | | (33 | | ) |

| Issuances of common shares (Note 11) | 3,870 | | | | — | | | | — | | |

| Issuance of mandatory convertible preferred stock (Note 11) | 1,541 | | | | — | | | | — | | |

| Net assets contributed to equity investment | 46 | | | | — | | | | — | | |

| | Common stock | | | | | | | Preferred stock | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| Issuances of common shares | 103 | | | 1 | | | | | | | | | | | 3,869 | | | | | | | | | | | | 3,870 | | | | | | | | 3,870 | | |

| Repurchases of warrants | | | | | | | | | | | | | | | (12 | | ) | | | | | | | | | | (12 | | ) | | | | | | (12 | | ) |

| Warrants exercised | | | | | | | | | | | | | | | 2 | | | | | | | | | | | | 2 | | | | | | | | 2 | | |

| Net income | | | | | | | | | | | | | | | | | | | 253 | | | | | | | | 253 | | | | (45 | | ) | | 208 | | |

| Preferred stock dividends | | | | | | | | | | | | | | | | | | | (26 | | ) | | | | | | (26 | | ) | | | | | | (26 | | ) |

| Common stock dividends | | | | | | | | | | | | | | | | | | | (4,224 | | ) | | | | | | (4,224 | | ) | | | | | | (4,224 | | ) |

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| 3.1 | | | Certificate of Incorporation of Kinder Morgan, Inc. as amended by the Certificate of Amendment to the Certificate of Incorporation |

| 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) |

| 10.5 | | * | 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)) |

| 10.17 | | * | 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)) |

| 10.20 | | * | Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2001 (File No. 1-11234)) |

| 10.21 | | * | Amendment No. 1 dated November 19, 2004 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed November 22, 2004 (File No. 1-11234)) |

| 10.22 | | * | Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed May 5, 2005 (File No. 1-11234)) |

| 10.23 | | * | Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed April 21, 2008 (File No. 1-11234)) |

| 10.24 | | * | Amendment No. 4 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.5 to Kinder Morgan Energy Partners, L.P. Form 10-K 2012 (File No. 1-11234)) |

| 10.25 | | * | Credit Agreement dated as of June 23, 2010 among Kinder Morgan Energy Partners, L.P., Kinder Morgan Operating L.P. “B”, the lenders party thereto, Wells Fargo Bank, National Association as Administrative Agent, Bank of America, N.A., Citibank, N.A., JPMorgan Chase Bank, N.A., and DnB NOR Bank ASA (filed as exhibit 10.1 to Kinder Morgan Energy Partners, L.P. Current Report on Form 8-K filed June 24, 2010 (File No. 1-11234)) |

| 10.26 | | * | First Amendment to Credit Agreement, dated as of July 1, 2011, among Kinder Morgan Energy Partners, L.P., Kinder Morgan Operating L.P. “B”, the lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 1-11234)) |

| 10.27 | | * | Indenture dated as of January 29, 1999 among Kinder Morgan Energy Partners, L.P., the guarantors listed on the signature page thereto and U.S. Trust Company of Texas, N.A., as trustee, relating to Senior Debt Securities (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Current Report on Form 8-K filed February 16, 1999 (File No. 1-11234)) |

| 10.29 | | * | Indenture dated January 2, 2001 between Kinder Morgan Energy Partners, L.P. and First Union National Bank, as trustee, relating to Senior Debt Securities (including form of Senior Debt Securities) (filed as Exhibit 4.11 to Kinder Morgan Energy Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2000 (File No. 1-11234)) |

| 10.35 | | * | 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)) |

| 10.54 | | * | 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) |

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February 23, 2015

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| Loss on sale and the remeasurement of the FTC Natural Gas Pipelines disposal group to fair value, net of tax | — | | | | (4 | | ) | | (937 | | ) |

| Class A Shares | | | | | | | | | | | |

| Basic and Diluted Earnings Per Common Share From Continuing Operations | | | | | | | | | $ | 0.47 | |

| Basic and Diluted Loss Per Common Share From Discontinued Operations | | | | | | | | | (0.21 | | ) |

| Total Basic and Diluted Earnings Per Common Share | | | | | | | | | $ | 0.26 | |

| Class P Shares | 1,137 | | | | 1,036 | | | | 461 | | |

| Class A Shares | | | | | | | | | 446 | | |

| Class P Shares | 1,137 | | | | 1,036 | | | | 908 | | |

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

| Change in fair value of derivatives utilized for hedging purposes (net of tax (expense) benefit of $(13), $4 and $(7), respectively) | 155 | | | | (24 | | ) | | 50 | | |