Summary of Significant Accounting Policies

Basis of Presentation

Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars, except where stated otherwise. Canadian dollars are designated as C$.

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

Our consolidated financial statements include our accounts and the of our majority-owned and controlled subsidiaries as well as the accounts of KMP, EPB and KMR. Investments in jointly owned operations in which we hold a 50% or less interest (other than KMP, EPB and KMR, because we have the ability to exercise significant control over their operating and financial policies) are accounted for under the equity method.

Notwithstanding the consolidation of KMP and EPB and their respective subsidiaries into our financial statements, we are not liable for, and our assets are not available to satisfy, the obligations of KMP and EPB and/or their respective subsidiaries and vice versa, except as discussed in the following paragraph. Responsibility for payments of obligations reflected in our, KMP’s or EPB’s financial statements is a legal determination based on the entity that incurs the liability.

Effective November 1, 2012, we sold KMP’s FTC Natural Gas Pipelines disposal group to Tallgrass Energy Partners, L.P. for approximately $1.8 billion (before selling costs), or $3.3 billion including our share of joint venture debt, to satisfy terms of a March 15, 2012 agreement with the U.S. FTC to divest certain of our assets in order to receive regulatory approval for our EP acquisition. KMP’s FTC Natural Gas Pipelines disposal group’s assets included (i) Kinder Morgan Interstate Gas Transmission natural gas pipeline system; (ii) Trailblazer natural gas pipeline system; (iii) Casper and Douglas natural gas processing operations; and (iv) 50% equity investment in the Rockies Express natural gas pipeline system. Accordingly, we (i) reclassified and excluded KMP’s FTC Natural Gas Pipelines disposal group’s results of operations from our results of continuing operations and reported the disposal group’s results of operations separately as “Income from operations of KMP’s FTC Natural Gas Pipelines disposal group and other, net of tax” within the discontinued operations section of our accompanying consolidated statements of income for all periods presented and (ii) separately reported a “Loss on sale and the remeasurement of KMP’s FTC Natural Gas Pipelines disposal group to fair value, net of tax” within the discontinued operations section of our accompanying consolidated statements of income for the years ended December 31, 2013 and 2012. In addition, we did not elect to present separately the operating, investing and financing cash flows related to the disposal group in our accompanying consolidated statements of cash flows.

For more information about the divestiture of KMP’s FTC Natural Gas Pipelines disposal group, see Note 3.

Use of Estimates

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

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

Cash Equivalents and Restricted Deposits

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

Restricted cash of $75 million and $52 million as of December 31, 2013 and 2012, respectively is included in “Other current assets,” and restricted cash of $2 million as of December 31, 2013, is included in “Deferred charges and other assets.”

Accounts Receivable

The amounts reported as “Accounts receivable, net” on our accompanying consolidated balance sheets as of December 31, 2013 and 2012 primarily consist of amounts due from customers.

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

Inventories

Our inventories of products consist of materials and supplies, NGL, refined petroleum products and natural gas. We report these assets at the lower of weighted-average cost or market. We report materials and supplies inventories at cost, and periodically review for physical deterioration and obsolescence.

Gas Imbalances

We value gas imbalances due to or due from interconnecting pipelines at the lower of cost or market or index prices, per our quarterly imbalance valuation procedures. Gas imbalances represent the difference between customer nominations and actual gas receipts from, and gas deliveries to, our interconnecting pipelines and shippers under various operational balancing and shipper imbalance agreements. Natural gas imbalances are either settled in cash or made up in-kind subject to the pipelines’ various tariff provisions. As of both December 31, 2013 and 2012, our gas imbalance receivables—including both trade and related party receivables—totaled $83 million and $18 million, respectively, and we included these amounts within “Other current assets” on our accompanying consolidated balance sheets. As of December 31, 2013 and 2012, our gas imbalance payables—consisting of only trade payables—totaled $34 million and $150 million, respectively, and we included these amounts within “Other current liabilities” on our accompanying consolidated balance sheets.

Property, Plant and Equipment

Capitalization, Depreciation and Depletion and Disposals

We report property, plant and equipment at its acquisition cost. We expense costs for maintenance and repairs in the period incurred. As discussed below, for assets used in our oil and gas producing activities or in our unregulated bulk and liquids terminal activities, the cost of property, plant and equipment sold or retired and the related depreciation are removed from our balance sheet in the period of sale or disposition, and we record any related gains and losses from sales or retirements to income or expense accounts. For our pipeline system assets, we generally charge the original cost of property sold or retired to accumulated depreciation and amortization, net of salvage and cost of removal. We do not include retirement gain or loss in income except in the case of significant retirements or sales. Gains and losses on minor operating unit sales, excluding land, are recorded to the appropriate accumulated depreciation reserve. Generally, gains and losses for operating unit sales and land sales are booked to income or expense accounts in accordance with regulatory accounting guidelines. In those instances where we receive recovery in tariff rates related to losses on dispositions of operating units, we record a regulatory asset for the estimated recoverable amount.

We generally compute depreciation using the straight-line method based on estimated economic lives; however, for certain depreciable assets, we employ the composite depreciation method, applying a single depreciation rate for a group of assets. Generally, we apply composite depreciation rates to functional groups of property having similar economic characteristics. The rates range from 0.9% to 23.0% excluding certain short-lived assets such as vehicles. Depreciation estimates are based on various factors, including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates included changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives (and salvage values where appropriate) that we believe are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization expense. Historically, adjustments to useful lives have not had a material impact on our aggregate depreciation levels from year to year.

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

A gain on the sale of property, plant and equipment used in our oil and gas producing activities or in our bulk and liquids terminal activities is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received. A gain on an asset disposal is recognized in income in the period that the sale is closed. A loss on the sale of property, plant and equipment is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received or the market value if the asset is being held for sale. A loss is recognized when the asset is sold or when the net cost of an asset held for sale is greater than the market value of the asset.

We engage in enhanced recovery techniques in which CO₂ is injected into certain producing oil reservoirs. In some cases, the acquisition cost of the CO₂ associated with enhanced recovery is capitalized as part of our development costs when it is injected. The acquisition cost associated with pressure maintenance operations for reservoir management is expensed when it is injected. When CO₂ is recovered in conjunction with oil production, it is extracted and re-injected, and all of the associated costs are expensed as incurred. Proved developed reserves are used in computing units of production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs. The units-of-production rate is determined by field.

As discussed in “—Inventories” above, we own and maintain natural gas in underground storage as part of our inventory. This component of our inventory represents the portion of gas stored in an underground storage facility generally known as working gas, and represents an estimate of the portion of gas in these facilities available for routine injection and withdrawal. In addition to this working gas, underground gas storage reservoirs contain injected gas which is not routinely cycled but, instead, serves the function of maintaining the necessary pressure to allow efficient operation of the facility. This gas, generally known as cushion gas, is divided into the categories of recoverable cushion gas and unrecoverable cushion gas, based on an engineering analysis of whether the gas can be economically removed from the storage facility at any point during its life. The portion of the cushion gas that is determined to be unrecoverable is considered to be a permanent part of the facility itself (thus, part of our “Property, plant and equipment, net” balance in our accompanying consolidated balance sheets), and this unrecoverable portion is depreciated over the facility’s estimated useful life. The portion of the cushion gas that is determined to be recoverable is also considered a component of the facility but is not depreciated because it is expected to ultimately be recovered and sold.

Impairments

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

We evaluate our oil and gas producing properties for impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure, using undiscounted future cash flows based on total proved and risk-adjusted probable and possible reserves. For the purpose of impairment testing, adjustments for the inclusion of risk-adjusted probable and possible reserves, as well as forward curve pricing, will cause impairment calculation cash flows to differ from the amounts presented in our supplemental information on oil and gas producing activities disclosed in “Supplemental Information on Oil and Gas Producing Activities (Unaudited).”

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

Asset Retirement Obligations

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

Equity method of accounting

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

Goodwill

Goodwill represents the excess of the cost of an acquisition price over the fair value of the acquired net assets, and such amounts are reported separately on our consolidated balance sheets. As of December 31, 2013 and 2012 our total goodwill was $24,504 million and $23,632 million, respectively. Goodwill is not amortized, but instead is tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We perform our goodwill impairment test on May 31 of each year. There were no impairment charges resulting from our May 31, 2013, 2012 or 2011 impairment testing, and no event indicating an impairment has occurred subsequent to May 31, 2013.

If a significant portion of one of our business segments is disposed of (that also constitutes a business), we would allocate goodwill based on the relative fair values of the portion of the segment being disposed of and the portion of the segment remaining.

Revenue Recognition Policies

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

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

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

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

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

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

Environmental Matters

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

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

Pensions and Other Postretirement Benefits

We recognize the difference between the fair value of plan assets and the plan’s benefit obligation of our consolidated subsidiaries’ pension and other postretirement benefit plans as either assets or liabilities on our balance sheet. We record deferred plan costs and income—unrecognized losses and gains, unrecognized prior service costs and credits, and any remaining unamortized transition obligations—in accumulated other comprehensive income or as a regulatory asset or liability for certain of our regulated operations, until they are amortized to be recognized as a component of benefit expense.

Noncontrolling Interests

Noncontrolling interests represents the outstanding ownership interests in our consolidated subsidiaries that are not owned by us. In our accompanying consolidated income statements, the noncontrolling interest in the net income (or loss) of our consolidated subsidiaries is shown as an allocation of our consolidated net income and is presented separately as “Net income attributable to noncontrolling interests.” In our accompanying consolidated balance sheets, noncontrolling interests represents the ownership interests in our consolidated subsidiaries’ net assets held by parties other than us. It is presented separately as “Noncontrolling interests” within “Stockholders’ Equity.”

Income Taxes

Income tax expense is recorded based on an estimate of the effective tax rate in effect or to be in effect during the relevant periods. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit we do not expect to be realized.

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

Foreign Currency Transactions and Translation

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

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

Comprehensive Income

For each of the years ended December 31, 2013, 2012 and 2011, the difference between our net income and our comprehensive income resulted from (i) unrealized gains or losses on derivative contracts accounted for as cash flow hedges; (ii) foreign currency translation adjustments; and (iii) unrealized gains or losses related to changes in pension and other postretirement benefit plan liabilities. For more information on our risk management activities, see Note 13.

Risk Management Activities

We utilize energy commodity derivative contracts for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas, NGL and crude oil. In addition, we enter into interest rate swap agreements for the purpose of hedging the interest rate risk associated with our debt obligations. We measure our derivative contracts at fair value and we report them on our balance sheet as either an asset or liability. If the derivative transaction qualifies for and is designated as a normal purchase and sale, it is exempted from fair value accounting and is accounted for using traditional accrual accounting.

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

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

Regulatory Assets and Liabilities

Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. We included the amounts of our regulatory assets and liabilities within “Other current assets,” “Deferred charges and other assets,” “Other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance sheets. As of December 31, 2013, the recovery period for these regulatory assets was approximately one year to forty-two years.

The following table summarizes our regulatory asset and liability balances as of December 31, 2013 and 2012 (in millions):



	December 31,
	2013		2012
Current regulatory assets	$	91	$	62
Non-current regulatory assets	446		402
Total regulatory assets(a)	$	537	$	464

Current regulatory liabilities	$	135	$	7
Non-current regulatory liabilities	397		113
Total regulatory liabilities(b)	$	532	$	120

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(a)	Includes an $88 million increase since December 31, 2012 (net of related amortization of $5 million) associated with TGP’s sale of certain natural gas facilities located offshore in the Gulf of Mexico and onshore in the state of Louisiana.

(b)

During the second quarter of 2013, we began applying regulatory accounting to the Trans Mountain pipeline systems due to a newly negotiated long-term tolling agreement approved by the system’s regulator that went into effect in April 2013. The primary impact of applying regulatory accounting was the reclassification of approximately $362 million of current and long-term deferred credits to regulatory liabilities. KMP expects this regulatory liability to be refunded to rate-payers over approximately the next four years. As of December 31, 2013, $113 million remains classified as a current regulatory liability.

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

Transfer of Net Assets Between Entities Under Common Control

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

Earnings per Share

For the year ended December 31, 2013, earnings per share was calculated using the two-class method. Earnings were allocated to Class P shares of common stock and to participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards do not participate in excess distributions over earnings. For the year ended December 31, 2013, the following potential weighted-average Class P common shares are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share; (i) 4 million related to unvested restricted stock awards; (ii) 401 million related to outstanding warrants to purchase our Class P shares; and (iii) 10 million related to convertible trust preferred securities.

The following table sets forth the allocation of net income available to shareholders for Class P shares and for participating securities for the year ended December 31, 2013 (in millions):



	Year Ended December 31, 2013
Class P	$	1,187
Participating securities(a)	6
Net Income Attributable to Kinder Morgan, Inc.	$	1,193

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(a)	Participating securities are unvested restricted stock awards issued to management employees that contain non-forfeitable rights to dividend equivalent payments.

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

For the year ended December 31, 2012 and the period February 11, 2011 through December 31, 2011, earnings per share was calculated using the two-class method. Earnings were allocated to each class of common stock based on the amount of dividends paid in the current period for each class of stock plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. For the investor retained stock, the allocation of undistributed earnings or excess distributions over earnings was in direct proportion to the maximum number of Class P shares into which it could convert.

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

The following tables set forth the computation of basic and diluted earnings per share from continuing operations for the year ending December 31, 2012 and the period ending February 11, 2011 through December 31, 2011 (the date of our initial public offering) (in millions, except per share amounts):



	Year ended December 31, 2012
	Income from Continuing Operations Available to Shareholders
	Class P			Class A			Participating Securities(a)			Total
Income from continuing operations										$	1,204
Less: income from continuing operations attributable to noncontrolling interests										(696		)
Income from continuing operations attributable to KMI										508
Dividends paid in the period	$	601		$	542		$	41		(1,184		)
Excess distributions over earnings	(344		)	(331		)	(1		)	$	(676	)
Income from continuing operations attributable to shareholders	$	257		$	211		$	40		$	508
Basic earnings per share from continuing operations
Basic weighted-average number of shares outstanding	461			446			N/A
Basic earnings per common share from continuing operations(b)	$	0.56		$	0.47		N/A
Diluted earnings per share from continuing operations
Income from continuing operations attributable to shareholders and assumed conversions(c)	$	508		$	211		N/A
Diluted weighted-average number of shares	908			446			N/A
Diluted earnings per common share from continuing operations(b)	$	0.56		$	0.47		N/A



	February 11. 2011 through December 31, 2011
	Income from Continuing Operations Available to Shareholders
	Class P			Class A			Participating Securities(a)		Total
Income from continuing operations for the year ended December 31, 2011									$	449
Plus: loss from continuing operations attributable to noncontrolling interests for the year ended December 31, 2011									112
Income from continuing operations attributable to KMI for the year ended December 31, 2011									561
Less: income from continuing operations attributable to KMI members prior to incorporation									(67		)
Total net income from continuing operations attributable to shareholders									494
Dividends paid in the period	$	87		$	399		$	38	(524		)
Excess distributions over earnings	(5		)	(25		)	—		$	(30	)
Income from continuing operations attributable to shareholders	$	82		$	374		$	38	$	494
Basic earnings per share from continuing operations
Basic weighted-average number of shares outstanding(d)	118			589			N/A
Basic earnings per common share from continuing operations(b)	$	0.70		$	0.64		N/A
Diluted earnings per share from continuing operations
Income from continuing operations attributable to shareholders and assumed conversions(c)	$	494		$	374		N/A
Diluted weighted-average number of shares(d)	708			589			N/A
Diluted earnings per common share from continuing operations(b)	$	0.70		$	0.64		N/A

The following tables set forth the computation of basic and diluted earnings per share for the year ended December 31, 2012 and for the period February 11, 2011 through December 31, 2011 (in millions, except per share amounts):



	Year ended December 31, 2012
	Net Income Available to Shareholders
	Class P			Class A			Participating Securities(a)			Total
Net income attributable to KMI										$	315
Dividends paid in the period	$	601		$	542		$	41		(1,184		)
Excess distributions over earnings	(441		)	(426		)	(2		)	$	(869	)
Net income attributable to shareholders	$	160		$	116		$	39		$	315
Basic earnings per share
Basic weighted-average number of shares outstanding	461			446			N/A
Basic earnings per common share(b)	$	0.35		$	0.26		N/A
Diluted earnings per share
Net income attributable to shareholders and assumed conversions(c)	$	315		$	116		N/A
Diluted weighted-average number of shares	908			446			N/A
Diluted earnings per common share(b)	$	0.35		$	0.26		N/A



	February 11, 2011 through December 31, 2011
	Net Income Available to Shareholders
	Class P		Class A		Participating Securities(a)		Total
Net income attributable to KMI for the year ended December 31, 2011							$	594
Less: net income attributable to KMI members prior to incorporation							(70		)
Net income attributable to shareholders							524
Dividends paid in the period	$	87	$	399	$	38	(524		)
Excess distributions over earnings	—		—		—		$	—
Total net income attributable to shareholders	$	87	$	399	$	38	$	524
Basic earnings per share
Basic weighted-average number of shares outstanding(d)	118		589		N/A
Basic earnings per common share(b)	$	0.74	$	0.68	N/A
Diluted earnings per share
Net income attributable to shareholders and assumed conversions(c)	$	524	$	399	N/A
Diluted weighted-average number of shares(d)	708		589		N/A
Diluted earnings per common share(b)	$	0.74	$	0.68	N/A

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(a)

Participating securities included Class B shares, Class C shares, and unvested restricted stock awards issued to non-senior management employees that contained rights to dividend equivalents in the case of the restricted shares. Our Class B and Class C shares were entitled to participate in our earnings, only to the extent of cash distributions made to them. As a result, no earnings in excess of dividends received were allocated to the Class B and Class C shares in our determination of basic and diluted earnings per share.

(b)

The Class A shares earnings per share as compared to the Class P shares earnings per share were reduced due to the sharing of economic benefits (including dividends) amongst the Class A, B, and C shares. Class A, B and C shares owned by Richard Kinder, the sponsor investors, the original shareholders, and other management were referred to as “investor retained stock,” and were convertible into a fixed number of Class P shares. In the aggregate, our investor retained stock was entitled to receive a dividend per share on a fully-converted basis equal to the dividend per share on our common stock. The conversion of shares of investor retained stock into Class P shares did not increase our total fully-converted shares outstanding, impact the aggregate dividends we paid or the dividends we paid per share on our Class P common stock.


(c)	For the diluted earnings per share calculation, total net income attributable to each class of common stock was divided by the adjusted weighted-average shares outstanding during the period, including all dilutive potential shares.


(d)	The weighted-average shares outstanding calculation is based on the actual days in which the shares were outstanding for the period from February 11, 2011 to December 31, 2011.