Our accompanying consolidated financial statements have been prepared under the rules and regulations of the United States Securities and Exchange Commission (SEC). These rules and regulations conform to the accounting principles contained in the Financial Accounting Standards Board’s Accounting Standards Codification, the single source of generally accepted accounting principles in the United States of America. 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. In this report, we refer to the Financial Accounting Standards Board as the FASB and the FASB Accounting Standards Codification as the Codification.

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

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

The Going Private Transaction was accounted for under the purchase method of accounting with the assets acquired and liabilities assumed recorded at their fair market values as of the acquisition date based on an allocation of the aggregate purchase price paid in the Going Private Transaction, resulting in a new basis of accounting effective with the closing of the Going Private Transaction. To the extent that we consolidated less than wholly owned subsidiaries (such as KMP and KMR), the reported assets and liabilities for these entities were given a new accounting basis only to the extent of our economic ownership interest in those entities. Therefore, the assets and liabilities of these entities are included in our financial statements, in part, at a new accounting basis reflecting our purchase of our economic interest in these entities (approximately 50% in the case of KMP and 14% in the case of KMR). The remaining percentage of these assets and liabilities, reflecting the continuing noncontrolling ownership interest, is included at its historical accounting basis.

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.

As of December 31, 2010, our restricted deposits totaled $90.5 million and consisted of restricted deposits associated with KM Insurance, Ltd., a Bermuda insurance company and wholly-owned subsidiary of KMI, and $50.0 million in a third-party escrow account at KMP to comply with contractual stipulations related to its equity investment in Watco Companies, LLC. In January 2011, the funds were released from escrow and KMP used the cash for its investment. For additional information on this investment, see Note 3 “Acquisitions and Divestitures—Acquisitions—(13) Watco Companies, LLC.”

Our policy for determining an appropriate allowance for doubtful accounts varies according to the type of business being conducted and the customers being served. Generally, we make periodic reviews and evaluations of the appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and we record adjustments as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. The following table shows the balance in the allowance for doubtful accounts and activity for the years ended December 31, 2011, 2010 and 2009 (in millions):

Allowance for doubtful accounts	Balance at beginning of period		Additions charged to costs and expenses		Additions charged to other accounts		Deductions(a)			Balance at end of period

Year ended December 31, 2011	$	6.8	$	0.2	$	-	$	(1.2	)	$	5.8

Year ended December 31, 2010	$	5.4	$	2.3	$	-	$	(0.9	)	$	6.8

Year ended December 31, 2009	$	6.2	$	0.5	$	-	$	(1.3	)	$	5.4

As of December 31, 2011 and 2010, the value of natural gas in our underground storage facilities under the weighted-average cost method was $61.8 million and $2.2 million, respectively, and we reported these amounts separately as “Gas in underground storage” in our accompanying consolidated balance sheets. We report materials and supplies inventories at cost, and periodically review for physical deterioration and obsolescence.

We value gas imbalances due to or due from interconnecting pipelines at the lower of cost or market, 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, 2011 and 2010, our gas imbalance receivables—including both trade and related party receivables—totaled $18.8 million, and we included these amounts within “Other current assets” on our accompanying consolidated balance sheets. As of December 31, 2011 and 2010, our gas imbalance payables—including both trade and related party payables— totaled $9.7 million and $7.7 million, respectively, and we included these amounts within “Accrued other current liabilities” on our accompanying consolidated balance sheets.

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 system sales, excluding land, are recorded to the appropriate accumulated depreciation reserve. Gains and losses for operating systems sales and land sales are booked to income or expense accounts in accordance with regulatory accounting guidelines.

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 1.6% to 12.5%, 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 maket 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.

In addition, we engage in enhanced recovery techniques in which carbon dioxide is injected into certain producing oil reservoirs. In some cases, the acquisition cost of the carbon dioxide 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 carbon dioxide 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.

We measure long-lived assets that are to be disposed of by sale at the lower of book value or fair value less the cost to sell, and we review for the impairment of long-lived assets whenever events or changes in circumstances indicate that our carrying amount of an asset may not be recoverable. We would recognize an impairment loss 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 Note 21.

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.

Included in the cost of our qualifying property, plant and equipment is (i) an allowance for funds used during construction (AFUDC) or upgrade for assets regulated by the Federal Energy Regulatory Commission or (ii) capitalized interest. The primary difference between AFUDC and capitalized interest is that AFUDC may include a component for equity funds, while capitalized interest does not. AFUDC on debt, as well as capitalized interest, represents the estimated cost of capital, from borrowed funds, during the construction period that is not immediately expensed, but instead is treated as an asset (capitalized) and amortized to expense over time in our income statements.

Total AFUDC on debt and capitalized interest in 2011, 2010 and 2009 was $14.5 million, $12.5 million and $32.9 million, respectively. Similarly, AFUDC on equity represents an estimate of the cost of capital funded by equity contributions, and in the years ended December 31, 2011, 2010 and 2009, we also capitalized $0.2 million, $0.7 million and $22.7 million, respectively, of equity AFUDC.

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. For more information on our asset retirement obligations, see Note 5 “Property, Plant and Equipment—Asset Retirement Obligations.”

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 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 as “Goodwill” on our accompanying consolidated balance sheets. Our total goodwill was $5,073.5 million and $4,830.9 million as of December 31, 2011 and 2010, respectively. Goodwill cannot be amortized, but instead must be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We perform our goodwill impairment test on May 31 of each year. 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. We would then perform an impairment test of the goodwill in the remaining portion of the segment after the goodwill allocation to ensure that the segment could support the remaining goodwill. See Note 7 for more information about goodwill and our annual impairment test.

We recognize revenues as services are rendered or goods are delivered and, if applicable, title has passed. We generally sell natural gas under long-term agreements, generally based on Houston Ship Channel index posted prices. In some cases, we sell natural gas under short-term agreements at prevailing market prices. In all cases, we recognize natural gas sales revenues when the natural gas 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. The natural gas we market is primarily purchased gas produced by third parties, and we market this gas to power generators, local distribution companies, industrial end-users and national marketing companies. We recognize gas gathering and marketing revenues in the month of delivery based on customer nominations and generally, our natural gas marketing revenues are recorded gross, not net of cost of gas sold.

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. 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. In addition to our firm and interruptible transportation services, we also provide natural gas balancing services to assist customers in managing short-term gas surpluses or deficits. Revenues are recognized based on the terms negotiated under these contracts.

We provide crude oil transportation services 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. Liquids terminal minimum take-or-pay revenue is recognized at the end of the contract year or contract term depending on the terms of the contract. 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, natural gas liquids, carbon dioxide and natural gas production 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. As a result, we maintain a minimum amount of product inventory in storage.

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 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. For more information on our environmental disclosures, see Note 16.

We are subject to litigation and regulatory proceedings as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. When we identify specific litigation that is expected to continue for a significant period of time is reasonably possible to occur and may require substantial expenditures, we identify a range of possible costs expected to be required to litigate the matter to a conclusion or reach an acceptable settlement, and we accrue for such amounts. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. In general, we expense legal costs as incurred and all recorded legal liabilities are revised as better information becomes available. For more information on our legal disclosures, see Note 16.

We fully recognize the overfunded or underfunded status of our consolidating subsidiaries’ pension and postretirement benefit plans as either assets or liabilities on our balance sheet. A plan’s funded status is the difference between the fair value of plan assets and the plan’s benefit obligation. 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, until they are amortized to expense. For more information on our pension and postretirement benefit disclosures; see Note 9.

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 “Shareholders’ Equity.”

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. Note 4 contains information about our income taxes, including the components of our income tax provision and the composition of our deferred income tax assets and liabilities.

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. 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.

Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which our reporting subsidiary operates, also referred to as its functional 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 income statements, gains and losses from our foreign currency transactions are included within “Other Income (Expense) – Other, net” in our accompanying consolidated statements of income.

Foreign currency translation is the process of expressing, in U.S. dollars, amounts denominated or measured in a different local functional currency, for example the Canadian dollar for a Canadian subsidiary. We translate the assets and liabilities of each of our consolidating 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. Translation adjustments result from translating all assets and liabilities at current year-end rates, while stockholders’ equity is translated by using historical and weighted-average rates. The cumulative translation adjustments balance is reported as a component of the “Accumulated other comprehensive loss” caption in our accompanying consolidated balance sheets.

Earnings per share is calculated using the two-class method. Earnings are allocated to each class of common stock based on the amount of dividends declared 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 shares in earnings or excess distributions over earnings. For the investor retained stock the allocation of undistributed earnings or excess distributions over earnings is in direct proportion to the maximum number of Class P shares into which it can convert.

For the Class P diluted per share computations, total net income attributable to Kinder Morgan, Inc. is divided by the adjusted weighted average shares outstanding during the period, including all dilutive potential shares. This includes the Class P shares into which the investor retained stock is convertible. Thus, the number of Class P shares on a fully-converted basis is the same before and after any conversion of our investor retained stock. Each time one Class P share is issued upon conversion of investor retained stock, the number of Class P shares goes up by one, and the number of Class P shares into which the investor retained stock is convertible goes down by one. Accordingly, there is 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 does not impact the number of Class P shares on a fully-converted basis. As no securities are convertible into Class A shares, the basic and diluted earnings per share computations for Class A shares are the same.

	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							$	594.4
Less: net income attributable to KMI members prior to incorporation								(70.6	)
Net income attributable to shareholders								523.8
Dividends declared during period	$	87.3	$	398.3	$	38.2		(523.8	)
Excess distributions over earnings		-		-		-	$	-

Total net income attributable to shareholders	$	87.3	$	398.3	$	38.2	$	523.8

Basic Earnings Per Share

Basic Weighted Average Number of Shares Outstanding(e)		118.0		589.0		N/A

Basic Earnings per Common Share(b)(c)	$	0.74	$	0.68		N/A

Diluted Earnings per Share

Total net income attributable to shareholders and assumed conversions(d)	$	523.8	$	398.3		N/A

Diluted Weighted Average Number of Shares(e)		707.6		589.0		N/A

Diluted Earnings per Common Share(b)(c)	$	0.74	$	0.68		N/A

(a)	Participating securities include Class B shares, Class C shares, and unvested restricted stock awards issued to non-senior management employees that contain rights to dividends. There were 1,163,090 restricted stock awards outstanding as of December 31, 2011.
(b)	The Class A shares earnings per share as compared to the Class P shares earnings per share has been 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 are referred to as “investor retained stock,” and are convertible into a fixed number of Class P shares. In the aggregate, our investor retained stock is 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 will not increase our total fully-converted shares outstanding, impact the aggregate dividends we pay or the dividends we pay per share on our Class P common stock.
(c)	Basic and diluted earnings per common share include earnings per share from discontinued operations of $0.01 for the period February 11, 2011 through December 31, 2011.
(d)	For the diluted earnings per share calculation, total net income attributable to each class of common stock is divided by the adjusted weighted average shares outstanding during the period, including all dilutive potential shares.
(e)	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.

We utilize energy commodity derivative contracts for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas, natural gas liquids 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 and cross-currency interest rate swap agreements to mitigate foreign currency risk from our investments in businesses owned and operated outside the United States. 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 specific hedge accounting criteria are met. If a derivative contract meets those criteria, the contract’s gains and losses are allowed to offset related results on the hedged item in our income statement, and we are required to both 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 sale of natural gas, natural gas liquids and crude oil, and we have designated 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 transaction affects earnings. The ineffective portion of the gain or loss is reported in earnings immediately. See Note 13 for more information on our risk management activities and disclosures.

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. The amount of regulatory assets and liabilities reflected within “Deferred charges and other assets” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance sheets as of December 31, 2011 and 2010 are not material to our consolidated balance sheets.

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