Significant Accounting Policies and Methods of Application

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Significant Accounting Policies [Text Block]

Note 2 – Significant Accounting Policies and Methods of Application

Cash and Cash Equivalents

Our cash and cash equivalents consist primarily of cash on deposit, money market accounts and certificates of deposit of domestic subsidiaries with original maturities of three months or less.

Receivables and Allowance for Uncollectible Accounts

Our receivables primarily consist of natural gas sales and transportation services billed to residential, commercial, industrial and other customers. We bill customers monthly, and our accounts receivable are due within 30 days. For the majority of our receivables, we establish an allowance for doubtful accounts based on our collection experience and other factors. For receivables where we are aware of a specific customer’s inability or reluctance to pay, we record an allowance for doubtful accounts against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could change as well. Circumstances that could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Customers’ accounts are written off once we deem them to be uncollectible.

Nicor GasCredit risk exposure at Nicor Gas is mitigated by the bad debt rider approved by the Illinois Commission on February 2, 2010. The bad debt rider provides for the recovery from (or refund to) customers of the difference between Nicor Gas’ actual bad debt experience on an annual basis and the benchmark bad debt expense included in its rates for the respective year. For more information on the bad debt rider, see discussion in Regulatory Assets and Liabilities.

Atlanta Gas LightConcentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of eleven Marketers in Georgia. The credit risk exposure to Marketers varies seasonally, with the lowest exposure in the nonpeak summer months and the highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. The functions of the retail sale of gas include customer service, billings, collections, and the purchase and sale of natural gas. Atlanta Gas Light’s tariff allows it to obtain security support in an amount equal to no less than two times a Marketer’s highest month’s estimated bill from Atlanta Gas Light.

Investments

Our investments in marketable securities are categorized at the date of acquisition as trading, held-to-maturity, or available-for-sale. Trading securities, which include money market funds, are carried at fair value and are classified as current assets unless held to satisfy a long-term obligation. We classify money market funds held by our non-United States subsidiaries as short-term investments and all others are classified as cash equivalents. Debt securities are categorized as held-to-maturity when our intent and ability is to hold the securities to maturity. Held-to-maturity securities are included in either short-term or long-term investments based upon their contractual maturity date. We carry held-to-maturity securities at amortized cost, which approximates fair value. Available-for-sale securities are carried at fair value, with unrealized gains and losses, net of tax, reported in common equity as a component of accumulated OCI. Available-for-sale securities are classified as noncurrent assets unless the intent is to sell the security within 12 months. The specific identification method is used to determine realized gains or losses on the sale of marketable securities. Investments in equity securities that do not have a readily determinable fair value and do not qualify for the equity method are carried at cost.

Our investments in debt and equity securities at December 31 are as follows:

In millions		2011
	Money market funds	$59
	Corporate bonds	6
	Other investments	7
	Total	$72

Investments in debt and equity securities are classified on the Consolidated Statements of Financial Position at December 31 as follows:

In millions	2011
Cash equivalents	$9
Short-term investments	53
Long-term investments	10
Total	$72

Investments categorized as trading (including money market funds) totaled $59 million at December 31, 2011. 

Corporate bonds and certain other investments are categorized as held-to-maturity. The contractual maturities of the held-to-maturity investments at December 31, 2011 are as follows:

	Years to maturity
In millions	Less than 1 year	1-5 years	5-10 years	Total
Held-to-maturity investments	$2	$5	$1	$8

Our investments also include certain investments, including certificates of deposit and bank accounts, maintained to fulfill statutory or contractual requirements. These investments totaled $3 million at December 31, 2011. In addition, we hold a $2 million investment in a port facility development venture carried at cost. Gains or losses included in earnings resulting from the sale of investments were not significant.

Inventories

Except for Nicor Gas, distribution operations records natural gas stored underground at WACOG. Nicor Gas’ inventory is carried at cost on a last-in-first-out (LIFO) basis. For our wholesale services and retail operations businesses, we account for natural gas inventory at the lower of WACOG or market price.

Based on the average cost of gas purchased in December 2011, the estimated replacement cost of Nicor Gas’ inventory at December 31, 2011 exceeded the LIFO cost by $189 million. During the 22 days of December 2011, Nicor Gas had an immaterial LIFO liquidation.

Our retail operations and wholesale services segments evaluate the weighted-average cost of their natural gas inventories against market prices to determine whether any declines in market prices below the WACOG are other-than-temporary. For any declines considered to be other-than-temporary, we record adjustments to reduce the weighted-average cost of the natural gas inventory to market price. Consequently, as a result of declining natural gas prices, Retail operations and wholesale services charged LOCOM adjustments to cost of goods sold, to reduce the value of their inventories to market value in the following amounts.

In millions	2011	2010	2009
Retail operations	$5	$0	$6
Wholesale services	31	8	8

In Georgia’s competitive environment, Marketers including SouthStar, sell natural gas to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation and provides this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. Atlanta Gas Light assigns, on a monthly basis, the majority of the pipeline storage services that it has under contract to Marketers, along with a corresponding amount of inventory.

Energy Marketing Receivables and Payables

Our wholesale services segment provides services to retail and wholesale marketers and utility and industrial customers. These customers, also known as counterparties, utilize netting agreements, which enable wholesale services to net receivables and payables by counterparty. Wholesale services also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. The amounts due from or owed to wholesale services’ counterparties are settled net, but are recorded on a gross basis in our Consolidated Statements of Financial Position as energy marketing receivables and energy marketing payables.

Our wholesale services segment has some trade and credit contracts that have explicit minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale services would need to post collateral to continue transacting business with some of its counterparties. No collateral has been posted under such provisions since our credit ratings have always exceeded the minimum requirements. As of December 31, 2011 and December 31, 2010, the collateral that wholesale services would have been required to post if our credit ratings had been downgraded to non-investment grade status would not have had a material impact to our consolidated results of operations, cash flows or financial condition. However, if such collateral were not posted, wholesale services’ ability to continue transacting business with these counterparties would be negatively impacted.

Wholesale services has a concentration of credit risk for services it provides to marketers and to utility and industrial counterparties. This credit risk is measured by 30-day receivable exposure plus forward exposure, which is generally concentrated in 20 of its counterparties. We evaluate the credit risk of our counterparties using a S&P equivalent credit rating, which is determined by a process of converting the lower of the S&P or Moody’s rating to an internal rating ranging from 9.00 to 1.00, with 9.00 being equivalent to AAA/Aaa by S&P and Moody’s and 1.00 being equivalent to D or Default by S&P and Moody’s. For a customer without an external rating, we assign an internal rating based on our analysis of the strength of its financial ratios. The following table provides additional information about wholesale services’ credit exposure at December 31, 2011, excluding $11 million of customer deposits.

	Credit exposure
Dollars in millions		Total (1)	# of top counterparties	Concentration risk %
Credit exposure		$304	20	60%

(1)Our counterparties or the counterparties’ guarantors had a weighted average S&P equivalent rating of BBB+ at December 31, 2011.

The weighted average credit rating is obtained by multiplying each customer’s assigned internal rating by its credit exposure and then adding the individual results for all counterparties. That total is divided by the aggregate total exposure. This numeric value is converted to an S&P equivalent.

We have established credit policies to determine and monitor the creditworthiness of counterparties, including requirements for posting of collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include cash or United States government securities held by a trustee. When wholesale services is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the “net” mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of our credit risk. Wholesale services also uses other netting agreements with certain counterparties with whom it conducts significant transactions.

Fair Value Measurements

The carrying values of cash and cash equivalents, receivables, short and long-term investments, derivative assets and liabilities, accounts payable, short-term debt, retirement plan assets, other current assets and liabilities and accrued interest approximate fair value. See Note 4 for additional fair value disclosures.

As defined in the authoritative guidance related to fair value measurements and disclosures, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observance of those inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by the guidance are as follows:

Level 1 Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 items consist of exchange-traded derivatives, money market funds and retirement plan assets.

Level 2Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial and commodity instruments that are valued using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. We obtain market price data from multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the market place. As we aggregate our disclosures by counterparty, the underlying transactions for a given counterparty may be a combination of exchange-traded derivatives and values based on other sources. Instruments in this category include shorter tenor exchange-traded and non-exchange-traded derivatives such as OTC forwards and options and retirement plan assets.

Level 3Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. Our Level 3 assets and liabilities are primarily related to our retirement plan assets as described in Note 4 and Note 6. However, we have nonretirement plan Level 3 assets and liabilities that are described further in Note 3, Note 4 and Note 5. Transfers into and out of Level 3 reflect the liquidity at the relevant natural gas trading locations and dates which affects the significance of unobservable inputs used in the valuation applied to natural gas derivatives. Transfers for retirement plan assets are described further in Note 4. We determine both transfers into and out of Level 3 using values at the end of the interim period in which the transfer occurred.

The authoritative guidance related to fair value measurements and disclosures also includes a two-step process to determine if the market for a financial asset is inactive and a transaction is not distressed. Currently, this authoritative guidance does not affect us, as our derivative instruments are traded in active markets.

Derivative Instruments

Fair Value Hierarchy As required by the authoritative guidance, derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values incorporates various factors required under the guidance. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our nonperformance risk on our liabilities. To mitigate the risk that a counterparty to a derivative instrument defaults on settlement or otherwise fails to perform under contractual terms, we have established procedures to monitor the creditworthiness of counterparties, seek guarantees or collateral back-up in the form of cash or letters of credit and, in most instances, enter into netting arrangements. See Note 4 for additional fair value disclosures. 

Netting of Cash Collateral and Derivative Assets and Liabilities under Master Netting ArrangementsWe maintain accounts with brokers to facilitate financial derivative transactions in support of our energy marketing and risk management activities. Based on the value of our positions in these accounts and the associated margin requirements, we may be required to deposit cash into these broker accounts.

Under authoritative guidance related to derivatives and hedging we have elected to net derivative assets and liabilities under master netting arrangements. With that election, we are also required to offset, on our Consolidated Statements of Financial Position cash collateral held in our broker accounts with the associated fair value of the instruments in the accounts. See Note 5 for additional information about our cash collateral.

Natural Gas Derivative Instruments

The fair value of natural gas derivative instruments we use to manage exposures arising from changing natural gas prices reflects the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. We use external market quotes and indices to value substantially all of our derivative instruments. See Note 5 for additional derivative disclosures.

Distribution Operations Nicor Gas, subject to review by the Illinois Commission, and Elizabethtown Gas, in accordance with a directive from the New Jersey BPU, enter into derivative instruments to hedge the impact of market fluctuations in natural gas prices. In accordance with the authoritative guidance related to derivatives and hedging, such derivative transactions are accounted for at fair value each reporting period in our Consolidated Statements of Financial Position. In accordance with regulatory requirements realized gains and losses related to these derivatives are reflected in natural gas costs and ultimately included in billings to customers. Thus, hedge accounting is not elected and, in accordance with accounting guidance pertaining to rate-regulated entities, unrealized changes in the fair value of these derivative instruments are deferred or accrued as regulatory assets or liabilities.

Nicor Gas also enters into swap agreements to reduce the earnings volatility of certain forecasted operating costs arising from fluctuations in natural gas prices, such as the purchase of natural gas for use in its operations. These derivative instruments are carried at fair value. To the extent hedge accounting is not elected, changes in such fair values are immediately recorded in the current period as operation and maintenance expense.

Retail OperationsWe have designated a portion of these derivative instruments, consisting of financial swaps to manage the risk associated with forecasted natural gas purchases and sales, as cash flow hedges under the authoritative guidance related to derivatives and hedging. We record derivative gains or losses arising from cash flow hedges in OCI and reclassify them into earnings in the same period as the settlement of the underlying hedged item.

We currently have minimal hedge ineffectiveness defined as when the gains or losses on the hedging instrument do not offset the losses or gains on the hedged item. This cash flow hedge ineffectiveness is recorded in cost of goods sold in our Consolidated Statements of Income in the period in which it occurs. We have not designated the remainder of our derivative instruments as hedges under the authoritative guidance related to derivatives and hedging and, accordingly, we record changes in the fair value of such instruments within cost of goods sold in our Consolidated Statements of Income in the period of change.

We enter into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather in the Heating Season. We account for these contracts using the intrinsic value method under the authoritative guidance related to financial instruments. These weather derivative instruments do not qualify for accounting hedge designation and changes in value are reflected in cost of goods sold on our Consolidated Statements of Income.

Wholesale ServicesWe purchase natural gas for storage when the difference in the current market price we pay to buy and transport natural gas plus the cost to store the natural gas is less than the market price we can receive in the future, resulting in a positive net operating margin. We use NYMEX futures contracts and other OTC derivatives to sell natural gas at that future price to substantially lock in the operating margin we will ultimately realize when the stored natural gas is sold. These futures contracts meet the definition of derivatives under the authoritative guidance related to derivatives and hedging and are accounted for at fair value in our Consolidated Statements of Financial Position, with changes in fair value recorded in our Consolidated Statements of Income in the period of change. These futures contracts are not designated as hedges as may be permitted under the guidance.

The purchase, transportation, storage and sale of natural gas are accounted for on a weighted average cost or accrual basis, as appropriate, rather than on the fair value basis we utilize for the derivatives used to mitigate the natural gas price risk associated with our storage portfolio. This difference in accounting can result in volatility in our reported earnings, even though the economic margin is essentially unchanged from the date the transactions were consummated.

Midstream Operations During the construction of the storage caverns, Golden Triangle Storage uses derivative instruments to reduce its exposure to the risk of changes in the price of natural gas that will be purchased in future periods for pad gas.

Golden Triangle Storage’s derivative instruments have been used to economically hedge operational purchases and sales and do not qualify as cash flow hedges. The pad gas is considered to be a component of the storage cavern’s construction costs; as a result, any derivative gains or losses arising from the cash flow hedges will remain in accumulated OCI until the pad gas is sold, which will not occur until the storage caverns are decommissioned. The fair value of these derivative instruments currently have minimal hedge ineffectiveness which is recorded in cost of goods sold in our Consolidated Statements of Income in the period in which it occurs. Golden Triangle Storage began entering into these derivative transactions during 2009.

Debt

We estimate the fair value of debt using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality and risk profile. In determining the market interest yield curve, we consider our currently assigned ratings for unsecured debt and the secured rating for the Nicor Gas first mortgage bonds. 

Property, Plant and Equipment

A summary of our PP&E by classification as of December 31, 2011 and 2010 is provided in the following table.

In millions	2011	2010
Transmission and distribution	$7,579		$4,955
Shipping vessels and containers	146		n/a
Storage	931		580
Other	747		484
Construction work in progress	376		247
Total gross PP&E	9,779		6,266
Less accumulated depreciation	1,879		1,861
Total net PP&E	$7,900		$4,405

Distribution Operations PP&E consists of property and equipment that is in use, being held for future use and under construction. We report PP&E at its original cost, which includes:

·material and labor

·contractor costs

·construction overhead costs

·an allowance for funds used during construction (AFUDC) which represents the estimated cost of funds, from both debt and equity sources, used to finance the construction of major projects and is capitalized in rate base for ratemaking purposes when the completed projects are placed in service

·Nicor Gas’ pad gas – the portion considered to be non-recoverable is recorded as depreciable PP&E while the portion considered to be recoverable is recorded as non-depreciable PP&E

We recognize no gains or losses on depreciable utility property that is retired or otherwise disposed, as required under the composite depreciation method. Such gains and losses are ultimately refunded to or recovered from customers through future rate adjustments.

Retail Operations, Wholesale Services, Midstream Operations, Cargo Shipping and Other PP&E includes property that is in use and under construction, and we report it at cost. We record a gain or loss for retired or otherwise disposed-of property. Natural gas in salt-dome storage at Jefferson Island and Golden Triangle Storage that is retained as pad gas is classified as non-depreciable PP&E and is valued at cost. Central Valley has two types of pad gas in its reservoir storage facility. The first is non-depreciable PP&E, which is valued at cost, and the second is non-recoverable to which we have no contractual ownership.

Depreciation Expense

We compute depreciation expense for distribution operations by applying composite, straight-line rates (approved by the state regulatory agencies) to the investment in depreciable property. More information on our rates used and the rate method is provided in the following table.

	2011		2010	2009
Atlanta Gas Light (1)		2.6%	2.5%	2.5%
Chattanooga Gas (1)		2.5%	2.8%	3.4%
Elizabethtown Gas (2)		2.5%	2.4%	3.1%
Elkton Gas (2)		2.4%	2.3%	2.1%
Florida City Gas (2)		3.9%	3.7%	3.9%
Nicor Gas (2)		4.1%	n/a	n/a
Virginia Natural Gas (1)		2.5%	3.0%	2.6%

(1)Average composite straight-line depreciation rates for depreciable property, excluding transportation equipment

(2)Composite straight-line depreciation rates

We compute depreciation expense on a straight-line basis over the following estimated useful lives of the assets.

In years	Estimated useful life
Transportation equipment (1)	5 - 10
Cargo shipping- vessels	20 - 25
Cargo shipping- freight equipment and freight handling equipment	8 - 18
Storage caverns	40
Other	up to 40

(1) May be depreciated in excess of useful life and recovered in rates.

AFUDC and Capitalized Interest

Four of our utilities are authorized by applicable state regulatory agencies or legislatures to capitalize the cost of debt and equity funds as part of the cost of construction projects in our Consolidated Statements of Financial Position. Nicor Gas does not have authorized AFUDC rates, but rather capitalizes AFUDC at the current actual cost of debt. The capital expenditures of our two other utilities do not qualify for AFUDC treatment. More information on our authorized AFUDC rates is provided in the following table.

	2011	2010	2009
Atlanta Gas Light (1)	8.10%	8.10%	8.53%
Chattanooga Gas (2)	7.41%	7.41%	7.89%
Elizabethtown Gas (3)	0.53%	0.40%	0.41%
Virginia Natural Gas (4)	7.38%	0%	9.24%
AFUDC (in millions) (5)	$6	$3	$13

(1)New rate as of November 1, 2010.

(2)New rate as of June 1, 2010.

(3)Variable rate is determined by FERC method of AFUDC accounting.

(4)Approved only for Hampton Roads construction project which ended in 2009. VNG received no AFUDC interest for 2010 or 2011.

(5)Expense recorded in the Consolidated Statements of Income.

Within our midstream operations segment, we have recorded capitalized interest as part of the cost of the Golden Triangle Storage and Central Valley construction projects in our Consolidated Statements of Financial Position, and within interest expense in our Consolidated Statements of Income, in the amounts of $1 million in 2011, $5 million in 2010 and $3 million in 2009.

Goodwill and Intangible Assets

Goodwill is the excess of the purchase price over the fair value of identifiable net assets acquired in business combinations. The fair values assigned to the trade name and customer relationship intangible assets at Nicor’s unregulated operations were determined using a combination of the cost savings, the multi-period excess earnings and the relief-from-royalty approaches.

In accordance with the authoritative guidance, we evaluate our goodwill balances for impairment on an annual basis or more frequently if impairment indicators arise. These indicators include, but are not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. We test goodwill impairment utilizing a fair value approach at a reporting-unit level which generally equates to our operating segments as discussed in Note 13. An impairment charge is recognized if the carrying value of a reporting unit’s goodwill exceeds its implied fair value. See Note 3 for a rollforward of total goodwill by operating segment.

Our goodwill impairment analysis for the years ended December 31, 2011 and 2010 was performed during the fourth quarter of each year and indicated that the fair value of each reporting unit is substantially in excess of carrying value, and the reporting units are not at risk of failing Step 1 of the impairment evaluation. As a result, we did not recognize any goodwill impairment charges.

In accordance with the authoritative guidance, we amortize intangible assets over their useful lives. These assets are reviewed for impairment when indicators arise, at which time we assess the recoverability of such assets by determining whether the carrying value will be recovered through expected future cash flows. In the event the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset’s carrying value over its fair value is recorded. No impairment has been recognized. We currently have no material indefinite lived intangible assets.

Taxes

The reporting of our assets and liabilities for financial accounting purposes differs from the reporting for income tax purposes. The principal differences between net income and taxable income relate to the timing of deductions, primarily due to the benefits of tax depreciation since we generally depreciate assets for tax purposes over a shorter period of time than for book purposes. The determination of our provision for income taxes requires significant judgment, the use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items. We report the tax effects of depreciation and other differences in those items as deferred income tax assets or liabilities in our Consolidated Statements of Financial Position in accordance with authoritative guidance related to income taxes.

Income TaxesWe have two categories of income taxes in our Consolidated Statements of Income: current and deferred. Current income tax expense consists of federal and state income tax less applicable tax credits related to the current year. Deferred income tax expense generally is equal to the changes in the deferred income tax liability and regulatory tax liability during the year.

Investment and Other Tax CreditsDeferred investment tax credits associated with distribution operations are included as a regulatory liability in our Consolidated Statements of Financial Position. These investment tax credits are being amortized over the estimated life of the related properties as credits to income in accordance with regulatory requirements.

Accumulated Deferred Income Tax Assets and LiabilitiesAs noted above, we report some of our assets and liabilities differently for financial accounting purposes than we do for income tax purposes. We report the tax effects of the differences in those items as deferred income tax assets or liabilities in our Consolidated Statements of Financial Position. We measure these deferred income tax assets and liabilities using enacted income tax rates.

Regulatory Income Tax Liability For our regulated utilities we also measure deferred income tax assets and liabilities using enacted income tax rates. Thus, when the statutory income tax rate declines before a temporary difference has fully reversed, the deferred income tax liability must be reduced to reflect the newly enacted income tax rates. In accordance with authoritative guidance related to rate-regulated entities, the amount of such a reduction is transferred to our regulatory income tax liability, which we are amortizing over the lives of the related properties as the temporary difference reverses or approximately 30 years.

A deferred income tax liability is not recorded on undistributed foreign earnings that are expected to be indefinitely reinvested offshore. We consider, among other factors, actual cash investments offshore as well as projected cash requirements in making this determination. Changes in our investment or repatriation plans or circumstances could result in a different deferred income tax liability.

Tax BenefitsThe authoritative guidance related to income taxes requires us to determine whether tax benefits claimed or expected to be claimed on our tax return should be recorded in our consolidated financial statements. Under this guidance, we may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. This guidance also addresses derecognition, classification, interest and penalties on income taxes, and accounting in interim periods.

Uncertain Tax Positions We recognize accrued interest related to uncertain tax positions in interest expense and penalties in operating expense in the Consolidated Statements of Income. As of December 31, 2011, we did not have a liability recorded for payment of interest and penalties associated with uncertain tax positions.

Tax Collections We do not collect income taxes from our customers on behalf of governmental authorities. We collect and remit various taxes on behalf of various governmental authorities. We record these amounts in our Consolidated Statements of Financial Position. In other instances, we are allowed to recover from customers other taxes that are imposed upon us. We record such taxes as operating expense and record the corresponding customer charges as revenue. These taxes were immaterial for all periods presented.

Revenues

Distribution operations We record revenues when services are provided to customers. Those revenues are based on rates approved by the state regulatory commissions of our utilities.

As required by the Georgia Commission, in July 1998, Atlanta Gas Light began billing Marketers in equal monthly installments for each residential, commercial and industrial customer’s distribution costs. As required by the Georgia Commission, effective February 1, 2001, Atlanta Gas Light implemented a seasonal rate design for the calculation of each residential customer’s annual straight-fixed-variable (SFV) capacity charge, which is billed to Marketers and reflects the historic volumetric usage pattern for the entire residential class. Generally, this change results in residential customers being billed by Marketers for a higher capacity charge in the winter months and a lower charge in the summer months. This requirement has an operating cash flow impact but does not change revenue recognition. As a result, Atlanta Gas Light continues to recognize its residential SFV capacity revenues for financial reporting purposes in equal monthly installments.

All of our utilities, with the exception of Atlanta Gas Light, have rate structures include volumetric rate designs that allow recovery of costs through gas usage. Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. Additionally, revenues are recorded for estimated deliveries of gas not yet billed to these customers, from the last bill date to the end of the accounting period. These are included in the Consolidated Statements of Financial Position as unbilled revenue. For other commercial and industrial customers and all wholesale customers, revenues are based on actual deliveries to the end of the period.

The tariffs for Virginia Natural Gas, Elizabethtown Gas and Chattanooga Gas contain WNA’s that partially mitigate the impact of unusually cold or warm weather on customer billings and operating margin. The WNA’s purpose is to reduce the effect of weather on customer bills by reducing bills when winter weather is colder than normal and increasing bills when weather is warmer than normal. In addition, the tariffs for Chattanooga Gas and Elkton Gas contain revenue normalization mechanisms that mitigate the impact of conservation and declining customer usage. 

Retail operations Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Sales revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. In addition, revenues are recorded for estimated deliveries of gas not yet billed to these customers, from the most recent meter reading date to the end of the accounting period. These are included in the Consolidated Statements of Financial Position as unbilled revenue. For other commercial and industrial customers and all wholesale customers, revenues are based on actual deliveries during the period.

We recognize revenue on 12-month utility-bill management contracts as the lesser of cumulative earned or cumulative billed amounts. We recognize revenue for warranty and repair contracts on a straight-line basis over the contract term. Revenue for maintenance services is recognized at the time such services are performed.

Wholesale services We record wholesale services’ revenues when services are provided to customers. Profits from sales between segments are eliminated in the other segment and are recognized as goods or services sold to end-use customers. Transactions that qualify as derivatives under authoritative guidance related to derivatives and hedging are recorded at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are required to be presented net in revenue. 

Midstream operations We record operating revenues at Jefferson Island and Golden Triangle Storage in the period in which actual volumes are transported and storage services are provided. The majority of our storage services are covered under medium to long-term contracts at fixed market-based rates. We recognize our park and loan revenues ratably over the life of the contract.

Cargo shipping Revenues and related delivery costs are recognized at the time vessels depart from port. Insurance premiums are recognized when the vessel carrying the insured cargo reaches its port of destination and the insured cargo is released to the consignee. The portion of premiums not earned at the end of the year is recorded as unearned premiums. 

Cost of goods sold

Excluding Atlanta Gas Light, we charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the state regulatory agencies. Under these mechanisms, all prudently incurred natural gas costs are passed through to customers without markup, subject to regulatory review. Therefore, in accordance with the authoritative guidance for rate-regulated entities, we defer or accrue (that is, include as an asset or liability in the Consolidated Statements of Financial Position and exclude from or include in the Statements of Consolidated Income, respectively) the difference between the actual cost of goods sold incurred and the amount of commodity revenue earned in a given period, such that no operating margin is recognized related to these costs. The deferred or accrued amount is either billed or refunded to our customers prospectively through adjustments to the commodity rate. Deferred natural gas costs are reflected as regulatory assets identified as recoverable natural gas costs, and accrued natural gas costs are reflected as regulatory liabilities which are identified as accrued natural gas costs within our Consolidated Statements of Financial Position. For more information, see “Regulatory Assets and Liabilities” in Note 2.

Our retail operations customers are charged for natural gas consumed. We also include within our cost of goods sold costs of fuel and lost and unaccounted for gas, adjustments to reduce the value of our inventories to market value and for gains and losses associated with certain derivatives.

Repair and maintenance expense

We record expense for repair and maintenance costs as incurred. This includes expenses for planned major maintenance, such as dry-docking the vessels owned by our cargo shipping business.

Operating leases

We have certain operating leases with provisions for step rent or escalation payments and certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms, in accordance with authoritative guidance related to leases. This accounting treatment does not affect the future annual operating lease cash obligations. For more information, see “Commitments, Guarantees and Contingencies” in Note 11.

Earnings Per Common Share

We compute basic earnings per common share attributable to AGL Resources Inc. common shareholders by dividing our income attributable to AGL Resources Inc. by the daily weighted average number of common shares outstanding. Diluted earnings per common share attributable to AGL Resources Inc. common shareholders reflect the potential reduction in earnings per common share attributable to AGL Resources Inc. common shareholders that could occur when potentially dilutive common shares are added to common shares outstanding. The increase in weighted average shares is due to the issuance of 38.2 million shares in connection with the Nicor merger on December 9, 2011. The effect of the additional shares was reduced as the shares were only outstanding for 22 days. We had 117.0 million shares outstanding as of December 31, 2011.

We derive our potentially dilutive common shares by calculating the number of shares issuable under restricted stock, restricted stock units and stock options. The vesting of shares of the restricted stock and restricted stock units depends on the satisfaction of certain performance criteria. The future issuance of shares underlying the outstanding stock options depends on whether the exercise prices of the stock options are less than the average market price of the common shares for the respective periods. The following table shows the calculation of our diluted shares attributable to AGL Resources Inc. common shareholders for the periods presented, ifperformance units currently earned under the plan ultimately vest and if stock options currently exercisable at prices below the average market prices are exercised:

In millions (except per share amounts)	2011	2010	2009
Net income attributable to AGL Resources Inc.	$172	$234	$222
Denominator:
Basic weighted-average number of shares outstanding (1)	80.4	77.4	76.8
Effect of dilutive securities	0.5	0.4	0.3
Diluted weighted-average number of shares outstanding	80.9	77.8	77.1
Basic and diluted earnings per share
Basic	$2.14	$3.02	$2.89
Diluted	$2.12	$3.00	$2.88
(1)Daily weighted average shares outstanding.

The following table contains the weighted average shares attributable to outstanding stock options that were excluded from the computation of diluted earnings per common share attributable to AGL Resources Inc. because their effect would have been anti-dilutive, as the exercise prices were greater than the average market price:

	December 31,
In millions	2011	2010			2009
Twelve months ended	0.0		0.8	2.0

The decrease in the number of shares that were excluded from the computation for the year ended December 31, 2011 and 2010 is the result of an increase in the average market value of our common shares for the years ended December 31, 2011 compared to 2010 and 2009.

Regulatory Assets and Liabilities 

We account for the financial effects of regulation in accordance with authoritative guidance related to regulated entities whose rates are designed to recover the costs of providing service. In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense in the current period are capitalized as regulatory assets when it is probable that such costs or expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Generally, regulatory assets are amortized into expense and regulatory liabilities are amortized into income over the period authorized by the regulatory commissions. Our regulatory assets and liabilities and associated assets and liabilities as of December 31, are summarized in the following table.

In millions	2011	2010
Regulatory assets - current
Recoverable regulatory infrastructure program costs	$48	$48
Recoverable ERC	7	7
Recoverable seasonal rates	10	11
Recoverable retirement benefit costs	29	0
Recoverable natural gas costs	0	0
Other	37	26
Total regulatory assets - current	131	92
Regulatory assets - long-term
Recoverable regulatory infrastructure program costs	305	244
Recoverable retirement benefit costs	262	0
Recoverable ERC	351	164
Unamortized losses on reacquired debt	21	11
Other	140	34
Total regulatory assets - long-term	1,079	453
Total regulatory assets	$1,210	$545
Regulatory liabilities - current
Accumulated removal costs	$14	$0
Derivative instruments	22	19
Accrued natural gas costs	53	23
Bad debt rider	30	0
Other	15	8
Total regulatory liabilities - current	112	31
Regulatory liabilities - long-term
Accumulated removal costs	1,321	182
Regulatory income tax liability	27	15
Bad debt rider	14	0
Unamortized investment tax credit	32	12
Other	11	16
Total regulatory liabilities - long-term	1,405	225
Total regulatory liabilities	$1,517	$256

The increase of $665 million in regulatory assets includes $545 million related to the addition of Nicor Gas’ regulatory assets and the increase of $1,261 million in regulatory liabilities includes $1,330 million related to the addition of Nicor Gas’ regulatory liabilities. The increase in ERC liabilities is discussed further in Note 11. The increase in regulatory infrastructure program costs primarily relates to updated engineering estimates based on actual path and rights of way for pipeline added to the program in 2010.

Our regulatory assets are probable or recovery specifically authorized by a state regulatory commission. Base rates are designed to provide both a recovery of cost and a return on investment during the period rates are in effect. As such, all of our regulatory assets recoverable through base rates are subject to review by the respective state regulatory commission during future rate proceedings. We are not aware of any evidence that these costs will not be recoverable through either rate riders or base rates, and we believe that we will be able to recover such costs, consistent with our historical recoveries. In the event that the provisions of authoritative guidance related to regulated operations were no longer applicable, we would recognize a write-off of regulatory assets that would result in a charge to net income, and be classified as an extraordinary item.

Additionally, while some regulatory liabilities would be written-off, others would continue to be recorded as liabilities but not as regulatory liabilities. Although the natural gas distribution industry is competing with alternative fuels, primarily electricity, our utility operations continue to recover their costs through cost-based rates established by the state regulatory commissions. As a result, we believe that the accounting prescribed under the guidance remains appropriate. It is also our opinion that all regulatory assets are recoverable in future rate proceedings, and therefore we have not recorded any regulatory assets that are recoverable but are not yet included in base rates or contemplated in a rate rider. The regulatory liabilities that do not represent revenue collected from customers for expenditures that have not yet been incurred are refunded to ratepayers through a rate rider or base rates. If the regulatory liability is included in base rates, the amount is reflected as a reduction to the rate base in setting rates.

The majority of our regulatory assets listed in the preceding table are included in base rates except for the recoverable regulatory infrastructure program costs, recoverable ERC, the bad debt rider and accrued natural gas costs, which are recovered through specific rate riders on a dollar-for-dollar basis. The rate riders that authorize the recovery of regulatory infrastructure program costs and natural gas costs include both a recovery of cost and a return on investment during the recovery period. Nicor Gas’ rate riders for environmental costs and energy efficiency costs also provide a return on investment during the period of recovery. However, there is no interest associated with the under or over collections of bad debt expense.

The Illinois Commission presently does not allow Nicor Gas the opportunity to earn a return on its recoverable retirement benefit costs. Such cost are expected to be recovered over a period of 9 to 11 years. The regulatory assets related to debt are also not included in rate base, but the costs are recovered over the term of the debt through the authorized rate of return component of base rates. 

Environmental Remediation Costs Our ERC liabilities are estimates of future remediation costs for investigation and clean up of our former operating sites that are contaminated. Our estimates are based on probabilistic models of potential costs, on an undiscounted basis. As cleanup options and plans mature and cleanup contracts are entered into, we are able to provide conventional engineering estimates of the likely costs of remediation at our former sites. These estimates contain various engineering uncertainties, but we continuously attempt to refine and update them. These liabilities do not include other potential expenses, such as unasserted property damage claims, personal injury or natural resource damage claims, unbudgeted legal expenses or other costs for which we may be held liable but for which we cannot reasonably estimate an amount. However, we have not yet performed these probabilistic models for all of our sites in Illinois, which will be completed in 2012.

Our paid and accrued ERCs are deferred in a corresponding regulatory asset until the costs are recovered from customers. We primarily recover these deferred costs through three rate riders that authorize dollar-for-dollar recovery. The ERC rate rider for Atlanta Gas Light only allows for recovery of the costs incurred over the subsequent five-year period. ERC associated with the investigation and remediation of Nicor Gas and Elizabethtown Gas remediation sites located in the states of Illinois and New Jersey are recovered under remediation adjustment clauses that include carrying cost on unrecovered expenditures. For more information on our ERC liabilities, see Note 11.

Bad Debt Rider Nicor Gas’ bad debt rider provides for the recovery from (or refund to) customers of the difference between Nicor Gas’ actual bad debt experience on an annual basis and the benchmark bad debt expense included in its rates for the respective year. The benchmark, against which 2011 actual bad debt experience is compared, is approximately $63 million. Nicor Gas’ actual 2011 bad debt expense was $31 million, resulting in a refund to customers of $32 million which will be refunded between June 2012 and May 2013. The prior year’s bad debt rider is recorded within operating expenses on our Consolidated Statements of Income and the over, or under, recovery is recorded as a regulatory asset or liability on our Consolidated Statements of Financial Position.

Other Regulatory Assets and Liabilities Our recoverable retirement benefit plan costs are recoverable through base rates over the next 2 to 21 years based on the remaining recovery period as designated by the applicable state regulatory commissions. Recoverable seasonal rates reflect the difference between the recognition of a portion of Atlanta Gas Light’s residential base rates revenues on a straight-line basis as compared to the collection of the revenues over a seasonal pattern. These amounts are fully recoverable through base rates within one year.

Accumulated Removal CostsIn accordance with regulatory treatment, our depreciation rates are comprised of two cost components – historical cost, net of estimated salvage, and the estimated cost of removal, or retirement, of certain regulated properties. We collect these costs in base rates through straight-line depreciation expense, with a corresponding credit to accumulated depreciation. Because the accumulated estimated removal costs meet the requirements of authoritative guidance related to regulated operations, we have accounted for them as a regulatory liability and have reclassified them from accumulated depreciation to accumulated removal costs in our Consolidated Statements of Financial Position. In the rate setting process, the liability for these accumulated removal costs are treated as a reduction to the net rate base upon which our regulated utilities have the opportunity to earn their allowed rate of return. Our accumulated removal costs increased $1.1 billion from December 31, 2010, principally related to Nicor Gas.

Regulatory Infrastructure Programs By order of the Georgia Commission (through a joint stipulation and a subsequent settlement agreement between Atlanta Gas Light and the Georgia Commission), Atlanta Gas Light began a pipeline replacement program to replace all bare steel and cast iron pipe in its system by December 2013. If Atlanta Gas Light does not perform in accordance with this order, it will be assessed certain nonperformance penalties. As of 2011, we have completed the replacement of all our cast iron pipes, and the remaining replacements are on schedule.

The order provides for recovery of all prudent costs incurred in the performance of the program, which Atlanta Gas Light has recorded as a regulatory asset. Atlanta Gas Light will recover from end-use customers, through billings to Marketers, the costs related to the program net of any cost savings from the program. All such amounts will be recovered through a combination of straight-fixed-variable rates and a pipeline replacement revenue rider. The regulatory asset has two components:

·the costs incurred to date that have not yet been recovered through the rate rider

·the future expected costs to be recovered through the rate rider

Atlanta Gas Light has recorded a current regulatory asset of $48 million, which represents the expected future collection of both expenditures already incurred and expected future capital expenditures to be incurred through the remainder of the program. Atlanta Gas Light has also recorded a noncurrent asset of $305 million, which represents the expected amount to be collected from customers over the next 12 months. The amounts recovered from the pipeline replacement revenue rider during the last three years were:

·$48 million in 2011

·$45 million in 2010

·$41 million in 2009

As of December 31, 2011, Atlanta Gas Light had recorded a current liability of $131 million representing expected program expenditures for the next 12 months and a noncurrent liability of $145 million, representing expected program expenditures through the end of the program in 2013.

Atlanta Gas Light capitalizes and depreciates the capital expenditure costs incurred from the pipeline replacement program over the life of the assets. Operation and maintenance costs are expensed as incurred. Recoveries, which are recorded as revenue, are based on a formula that allows Atlanta Gas Light to recover operation and maintenance costs in excess of those included in its current base rates, depreciation expense and an allowed rate of return on capital expenditures. In the near term, the primary financial impact to Atlanta Gas Light from the pipeline replacement program is reduced cash flow from operating and investing activities, as the timing related to cost recovery does not match the timing of when costs are incurred. However, Atlanta Gas Light is allowed the recovery of carrying costs on the under-recovered balance resulting from the timing difference.

The Georgia Commission has also approved Atlanta Gas Light’s STRIDE program, which is comprised of the ongoing pipeline replacement program, the new Integrated System Reinforcement Program (i-SRP) and the new Integrated Customer Growth Program (i-CGP). The purpose of the i-SRP is to upgrade Atlanta Gas Light’s distribution system and liquefied natural gas facilities in Georgia, improve its system reliability and operational flexibility, and create a platform to meet long-term forecasted growth. Atlanta Gas Light will be required to file an updated ten-year forecast of infrastructure requirements under the i-SRP along with a new three-year construction plan every three years for review and approval by the Georgia Commission.

Under i-CGP, the Georgia Commission authorized Atlanta Gas Light to extend its pipeline facilities to serve customers without pipeline access and create new economic development opportunities in Georgia. The i-CGP was approved as a three-year pilot program under STRIDE, and all related costs will be recovered through a surcharge.

In 2009, the New Jersey BPU approved an enhanced infrastructure program for Elizabethtown Gas, which was created in response to the New Jersey Governor’s request for utilities to assist in the economic recovery by increasing infrastructure investments. In May 2011, the New Jersey BPU approved Elizabethtown Gas’ request to spend an additional $40 million under this program before the end of 2012. Costs associated with the investment in this program are recovered through periodic adjustments to base rates. We expect to file for an extension of the program in 2012.

Accounting for Retirement Benefit Plans

The authoritative guidance related to retirement benefits requires that we recognize all obligations related to defined benefit retirement plans and quantify the plans’ funded status as an asset or a liability on our Consolidated Statements of Financial Position. The guidance further requires that we measure the plans’ assets and obligations that determine our funded status as of the end of the fiscal year. We are also required to recognize as a component of OCI the changes in funded status that occurred during the year that are not yet recognized as part of net periodic benefit cost as explained in authoritative guidance related to retirement benefits. Because substantially all of its retirement costs are recoverable through base rates, Nicor Gas generally defers any charge or credit to a regulatory asset or liability until the period in which the costs are included in base rates, in accordance with the authoritative guidance for rate-regulated entities. The assets of our retirement plans were accounted for at fair value and are classified in the fair value hierarchy in their entirety based on the lowest level of input that is significant to the fair value measurement.

Non-WhollyOwned Entities

We hold ownership interests in a number of business ventures with varying ownership structures. We evaluate all of our partnership interests and other variable interests to determine if each entity is a variable interest entity (VIE), as defined in the authoritative accounting guidance. If a venture is a VIE for which we are the primary beneficiary, we consolidate the assets, liabilities and results of operations of the entity. We reassess our conclusion as to whether an entity is a VIE upon certain occurrences which are deemed reconsideration events under the guidance. For entities that are not determined to be VIEs, we evaluate whether we have control or significant influence over the joint venture to determine the appropriate consolidation and presentation. Generally, entities under our control are consolidated, and entities over which we can exert significant influence, but do not control, are accounted for under the equity method of accounting.

We have concluded that the only venture that we are required to consolidate as a VIE, as we are the primary beneficiary, is SouthStar. We recognize on our Consolidated Statements of Financial Position, Piedmont’s share of the non-wholly owned entity as a separate component of equity entitled “noncontrolling interest.” Piedmont’s share of current operations is reflected in “net income attributable to the noncontrolling interest” on our Consolidated Statements of Income. The authoritative guidance has no effect on our calculation of basic or diluted earnings per common share amounts, which are based upon net income attributable to AGL Resources Inc. For additional information, see Note 10.

We also invest in partnerships and limited liability companies that are accounted for under the equity method, but are not joint ventures. In accordance with the authoritative guidance, all such investments are required to use the equity method unless our interest is so minor that there is virtually no influence over operating and financial policies.

Investments accounted for under the equity method are included in long-term investments on our Consolidated Statements of Financial Position, and the equity income is recorded in equity investment income on our Consolidated Statements of Income and was immaterial for all periods presented. For additional information, see Note 10.

Use of Accounting Estimates

The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures. We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, and we evaluate our estimates on an ongoing basis. Our estimates may involve complex situations requiring a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. The most significant estimates relate to our pipeline replacement program accruals, environmental liability accruals, uncollectible accounts and other allowance for contingent losses, goodwill and intangible assets, retirement plan obligations, derivative and hedging activities and provisions for income taxes. Our actual results could differ from our estimates.

Receivables Policy Text Block

Receivables and Allowance for Uncollectible Accounts

Our receivables primarily consist of natural gas sales and transportation services billed to residential, commercial, industrial and other customers. We bill customers monthly, and our accounts receivable are due within 30 days. For the majority of our receivables, we establish an allowance for doubtful accounts based on our collection experience and other factors. For receivables where we are aware of a specific customer’s inability or reluctance to pay, we record an allowance for doubtful accounts against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could change as well. Circumstances that could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Customers’ accounts are written off once we deem them to be uncollectible.

Nicor GasCredit risk exposure at Nicor Gas is mitigated by the bad debt rider approved by the Illinois Commission on February 2, 2010. The bad debt rider provides for the recovery from (or refund to) customers of the difference between Nicor Gas’ actual bad debt experience on an annual basis and the benchmark bad debt expense included in its rates for the respective year. For more information on the bad debt rider, see discussion in Regulatory Assets and Liabilities.

Atlanta Gas LightConcentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of eleven Marketers in Georgia. The credit risk exposure to Marketers varies seasonally, with the lowest exposure in the nonpeak summer months and the highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. The functions of the retail sale of gas include customer service, billings, collections, and the purchase and sale of natural gas. Atlanta Gas Light’s tariff allows it to obtain security support in an amount equal to no less than two times a Marketer’s highest month’s estimated bill from Atlanta Gas Light.

Marketable Securities Policy

Investments

Our investments in marketable securities are categorized at the date of acquisition as trading, held-to-maturity, or available-for-sale. Trading securities, which include money market funds, are carried at fair value and are classified as current assets unless held to satisfy a long-term obligation. We classify money market funds held by our non-United States subsidiaries as short-term investments and all others are classified as cash equivalents. Debt securities are categorized as held-to-maturity when our intent and ability is to hold the securities to maturity. Held-to-maturity securities are included in either short-term or long-term investments based upon their contractual maturity date. We carry held-to-maturity securities at amortized cost, which approximates fair value. Available-for-sale securities are carried at fair value, with unrealized gains and losses, net of tax, reported in common equity as a component of accumulated OCI. Available-for-sale securities are classified as noncurrent assets unless the intent is to sell the security within 12 months. The specific identification method is used to determine realized gains or losses on the sale of marketable securities. Investments in equity securities that do not have a readily determinable fair value and do not qualify for the equity method are carried at cost.

Our investments in debt and equity securities at December 31 are as follows:

In millions		2011
	Money market funds	$59
	Corporate bonds	6
	Other investments	7
	Total	$72

Investments in debt and equity securities are classified on the Consolidated Statements of Financial Position at December 31 as follows:

In millions	2011
Cash equivalents	$9
Short-term investments	53
Long-term investments	10
Total	$72

Investments categorized as trading (including money market funds) totaled $59 million at December 31, 2011. 

Corporate bonds and certain other investments are categorized as held-to-maturity. The contractual maturities of the held-to-maturity investments at December 31, 2011 are as follows:

	Years to maturity
In millions	Less than 1 year	1-5 years	5-10 years	Total
Held-to-maturity investments	$2	$5	$1	$8

Our investments also include certain investments, including certificates of deposit and bank accounts, maintained to fulfill statutory or contractual requirements. These investments totaled $3 million at December 31, 2011. In addition, we hold a $2 million investment in a port facility development venture carried at cost. Gains or losses included in earnings resulting from the sale of investments were not significant.

Inventory Policy Text Block

Inventories

Except for Nicor Gas, distribution operations records natural gas stored underground at WACOG. Nicor Gas’ inventory is carried at cost on a last-in-first-out (LIFO) basis. For our wholesale services and retail operations businesses, we account for natural gas inventory at the lower of WACOG or market price.

Based on the average cost of gas purchased in December 2011, the estimated replacement cost of Nicor Gas’ inventory at December 31, 2011 exceeded the LIFO cost by $189 million. During the 22 days of December 2011, Nicor Gas had an immaterial LIFO liquidation.

Our retail operations and wholesale services segments evaluate the weighted-average cost of their natural gas inventories against market prices to determine whether any declines in market prices below the WACOG are other-than-temporary. For any declines considered to be other-than-temporary, we record adjustments to reduce the weighted-average cost of the natural gas inventory to market price. Consequently, as a result of declining natural gas prices, Retail operations and wholesale services charged LOCOM adjustments to cost of goods sold, to reduce the value of their inventories to market value in the following amounts.

In millions	2011	2010	2009
Retail operations	$5	$0	$6
Wholesale services	31	8	8

In Georgia’s competitive environment, Marketers including SouthStar, sell natural gas to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation and provides this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. Atlanta Gas Light assigns, on a monthly basis, the majority of the pipeline storage services that it has under contract to Marketers, along with a corresponding amount of inventory.

Energy Marketing Accounts Receivables and Payables Text Block

Energy Marketing Receivables and Payables

Our wholesale services segment provides services to retail and wholesale marketers and utility and industrial customers. These customers, also known as counterparties, utilize netting agreements, which enable wholesale services to net receivables and payables by counterparty. Wholesale services also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. The amounts due from or owed to wholesale services’ counterparties are settled net, but are recorded on a gross basis in our Consolidated Statements of Financial Position as energy marketing receivables and energy marketing payables.

Our wholesale services segment has some trade and credit contracts that have explicit minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale services would need to post collateral to continue transacting business with some of its counterparties. No collateral has been posted under such provisions since our credit ratings have always exceeded the minimum requirements. As of December 31, 2011 and December 31, 2010, the collateral that wholesale services would have been required to post if our credit ratings had been downgraded to non-investment grade status would not have had a material impact to our consolidated results of operations, cash flows or financial condition. However, if such collateral were not posted, wholesale services’ ability to continue transacting business with these counterparties would be negatively impacted.

Wholesale services has a concentration of credit risk for services it provides to marketers and to utility and industrial counterparties. This credit risk is measured by 30-day receivable exposure plus forward exposure, which is generally concentrated in 20 of its counterparties. We evaluate the credit risk of our counterparties using a S&P equivalent credit rating, which is determined by a process of converting the lower of the S&P or Moody’s rating to an internal rating ranging from 9.00 to 1.00, with 9.00 being equivalent to AAA/Aaa by S&P and Moody’s and 1.00 being equivalent to D or Default by S&P and Moody’s. For a customer without an external rating, we assign an internal rating based on our analysis of the strength of its financial ratios. The following table provides additional information about wholesale services’ credit exposure at December 31, 2011, excluding $11 million of customer deposits.

	Credit exposure
Dollars in millions		Total (1)	# of top counterparties	Concentration risk %
Credit exposure		$304	20	60%

(1)Our counterparties or the counterparties’ guarantors had a weighted average S&P equivalent rating of BBB+ at December 31, 2011.

The weighted average credit rating is obtained by multiplying each customer’s assigned internal rating by its credit exposure and then adding the individual results for all counterparties. That total is divided by the aggregate total exposure. This numeric value is converted to an S&P equivalent.

We have established credit policies to determine and monitor the creditworthiness of counterparties, including requirements for posting of collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include cash or United States government securities held by a trustee. When wholesale services is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the “net” mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of our credit risk. Wholesale services also uses other netting agreements with certain counterparties with whom it conducts significant transactions.

Fair Value Of Financial Instruments Policy

Fair Value Measurements

The carrying values of cash and cash equivalents, receivables, short and long-term investments, derivative assets and liabilities, accounts payable, short-term debt, retirement plan assets, other current assets and liabilities and accrued interest approximate fair value. See Note 4 for additional fair value disclosures.

As defined in the authoritative guidance related to fair value measurements and disclosures, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observance of those inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by the guidance are as follows:

Level 1 Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 items consist of exchange-traded derivatives, money market funds and retirement plan assets.

Level 2Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial and commodity instruments that are valued using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. We obtain market price data from multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the market place. As we aggregate our disclosures by counterparty, the underlying transactions for a given counterparty may be a combination of exchange-traded derivatives and values based on other sources. Instruments in this category include shorter tenor exchange-traded and non-exchange-traded derivatives such as OTC forwards and options and retirement plan assets.

Level 3Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. Our Level 3 assets and liabilities are primarily related to our retirement plan assets as described in Note 4 and Note 6. However, we have nonretirement plan Level 3 assets and liabilities that are described further in Note 3, Note 4 and Note 5. Transfers into and out of Level 3 reflect the liquidity at the relevant natural gas trading locations and dates which affects the significance of unobservable inputs used in the valuation applied to natural gas derivatives. Transfers for retirement plan assets are described further in Note 4. We determine both transfers into and out of Level 3 using values at the end of the interim period in which the transfer occurred.

The authoritative guidance related to fair value measurements and disclosures also includes a two-step process to determine if the market for a financial asset is inactive and a transaction is not distressed. Currently, this authoritative guidance does not affect us, as our derivative instruments are traded in active markets.

Derivatives Policy Text Block

Derivative Instruments

Fair Value Hierarchy As required by the authoritative guidance, derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values incorporates various factors required under the guidance. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our nonperformance risk on our liabilities. To mitigate the risk that a counterparty to a derivative instrument defaults on settlement or otherwise fails to perform under contractual terms, we have established procedures to monitor the creditworthiness of counterparties, seek guarantees or collateral back-up in the form of cash or letters of credit and, in most instances, enter into netting arrangements. See Note 4 for additional fair value disclosures. 

Netting of Cash Collateral and Derivative Assets and Liabilities under Master Netting ArrangementsWe maintain accounts with brokers to facilitate financial derivative transactions in support of our energy marketing and risk management activities. Based on the value of our positions in these accounts and the associated margin requirements, we may be required to deposit cash into these broker accounts.

Under authoritative guidance related to derivatives and hedging we have elected to net derivative assets and liabilities under master netting arrangements. With that election, we are also required to offset, on our Consolidated Statements of Financial Position cash collateral held in our broker accounts with the associated fair value of the instruments in the accounts. See Note 5 for additional information about our cash collateral.

Natural Gas Derivative Instruments

The fair value of natural gas derivative instruments we use to manage exposures arising from changing natural gas prices reflects the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. We use external market quotes and indices to value substantially all of our derivative instruments. See Note 5 for additional derivative disclosures.

Distribution Operations Nicor Gas, subject to review by the Illinois Commission, and Elizabethtown Gas, in accordance with a directive from the New Jersey BPU, enter into derivative instruments to hedge the impact of market fluctuations in natural gas prices. In accordance with the authoritative guidance related to derivatives and hedging, such derivative transactions are accounted for at fair value each reporting period in our Consolidated Statements of Financial Position. In accordance with regulatory requirements realized gains and losses related to these derivatives are reflected in natural gas costs and ultimately included in billings to customers. Thus, hedge accounting is not elected and, in accordance with accounting guidance pertaining to rate-regulated entities, unrealized changes in the fair value of these derivative instruments are deferred or accrued as regulatory assets or liabilities.

Nicor Gas also enters into swap agreements to reduce the earnings volatility of certain forecasted operating costs arising from fluctuations in natural gas prices, such as the purchase of natural gas for use in its operations. These derivative instruments are carried at fair value. To the extent hedge accounting is not elected, changes in such fair values are immediately recorded in the current period as operation and maintenance expense.

Retail OperationsWe have designated a portion of these derivative instruments, consisting of financial swaps to manage the risk associated with forecasted natural gas purchases and sales, as cash flow hedges under the authoritative guidance related to derivatives and hedging. We record derivative gains or losses arising from cash flow hedges in OCI and reclassify them into earnings in the same period as the settlement of the underlying hedged item.

We currently have minimal hedge ineffectiveness defined as when the gains or losses on the hedging instrument do not offset the losses or gains on the hedged item. This cash flow hedge ineffectiveness is recorded in cost of goods sold in our Consolidated Statements of Income in the period in which it occurs. We have not designated the remainder of our derivative instruments as hedges under the authoritative guidance related to derivatives and hedging and, accordingly, we record changes in the fair value of such instruments within cost of goods sold in our Consolidated Statements of Income in the period of change.

We enter into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather in the Heating Season. We account for these contracts using the intrinsic value method under the authoritative guidance related to financial instruments. These weather derivative instruments do not qualify for accounting hedge designation and changes in value are reflected in cost of goods sold on our Consolidated Statements of Income.

Wholesale ServicesWe purchase natural gas for storage when the difference in the current market price we pay to buy and transport natural gas plus the cost to store the natural gas is less than the market price we can receive in the future, resulting in a positive net operating margin. We use NYMEX futures contracts and other OTC derivatives to sell natural gas at that future price to substantially lock in the operating margin we will ultimately realize when the stored natural gas is sold. These futures contracts meet the definition of derivatives under the authoritative guidance related to derivatives and hedging and are accounted for at fair value in our Consolidated Statements of Financial Position, with changes in fair value recorded in our Consolidated Statements of Income in the period of change. These futures contracts are not designated as hedges as may be permitted under the guidance.

The purchase, transportation, storage and sale of natural gas are accounted for on a weighted average cost or accrual basis, as appropriate, rather than on the fair value basis we utilize for the derivatives used to mitigate the natural gas price risk associated with our storage portfolio. This difference in accounting can result in volatility in our reported earnings, even though the economic margin is essentially unchanged from the date the transactions were consummated.

Midstream Operations During the construction of the storage caverns, Golden Triangle Storage uses derivative instruments to reduce its exposure to the risk of changes in the price of natural gas that will be purchased in future periods for pad gas.

Golden Triangle Storage’s derivative instruments have been used to economically hedge operational purchases and sales and do not qualify as cash flow hedges. The pad gas is considered to be a component of the storage cavern’s construction costs; as a result, any derivative gains or losses arising from the cash flow hedges will remain in accumulated OCI until the pad gas is sold, which will not occur until the storage caverns are decommissioned. The fair value of these derivative instruments currently have minimal hedge ineffectiveness which is recorded in cost of goods sold in our Consolidated Statements of Income in the period in which it occurs. Golden Triangle Storage began entering into these derivative transactions during 2009.

Goodwill And Intangible Assets PolicyText Block

Goodwill and Intangible Assets

Goodwill is the excess of the purchase price over the fair value of identifiable net assets acquired in business combinations. The fair values assigned to the trade name and customer relationship intangible assets at Nicor’s unregulated operations were determined using a combination of the cost savings, the multi-period excess earnings and the relief-from-royalty approaches.

In accordance with the authoritative guidance, we evaluate our goodwill balances for impairment on an annual basis or more frequently if impairment indicators arise. These indicators include, but are not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. We test goodwill impairment utilizing a fair value approach at a reporting-unit level which generally equates to our operating segments as discussed in Note 13. An impairment charge is recognized if the carrying value of a reporting unit’s goodwill exceeds its implied fair value. See Note 3 for a rollforward of total goodwill by operating segment.

Our goodwill impairment analysis for the years ended December 31, 2011 and 2010 was performed during the fourth quarter of each year and indicated that the fair value of each reporting unit is substantially in excess of carrying value, and the reporting units are not at risk of failing Step 1 of the impairment evaluation. As a result, we did not recognize any goodwill impairment charges.

In accordance with the authoritative guidance, we amortize intangible assets over their useful lives. These assets are reviewed for impairment when indicators arise, at which time we assess the recoverability of such assets by determining whether the carrying value will be recovered through expected future cash flows. In the event the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset’s carrying value over its fair value is recorded. No impairment has been recognized. We currently have no material indefinite lived intangible assets.

Income Tax Policy Text Block

Taxes

The reporting of our assets and liabilities for financial accounting purposes differs from the reporting for income tax purposes. The principal differences between net income and taxable income relate to the timing of deductions, primarily due to the benefits of tax depreciation since we generally depreciate assets for tax purposes over a shorter period of time than for book purposes. The determination of our provision for income taxes requires significant judgment, the use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items. We report the tax effects of depreciation and other differences in those items as deferred income tax assets or liabilities in our Consolidated Statements of Financial Position in accordance with authoritative guidance related to income taxes.

Income TaxesWe have two categories of income taxes in our Consolidated Statements of Income: current and deferred. Current income tax expense consists of federal and state income tax less applicable tax credits related to the current year. Deferred income tax expense generally is equal to the changes in the deferred income tax liability and regulatory tax liability during the year.

Investment and Other Tax CreditsDeferred investment tax credits associated with distribution operations are included as a regulatory liability in our Consolidated Statements of Financial Position. These investment tax credits are being amortized over the estimated life of the related properties as credits to income in accordance with regulatory requirements.

Accumulated Deferred Income Tax Assets and LiabilitiesAs noted above, we report some of our assets and liabilities differently for financial accounting purposes than we do for income tax purposes. We report the tax effects of the differences in those items as deferred income tax assets or liabilities in our Consolidated Statements of Financial Position. We measure these deferred income tax assets and liabilities using enacted income tax rates.

Regulatory Income Tax Liability For our regulated utilities we also measure deferred income tax assets and liabilities using enacted income tax rates. Thus, when the statutory income tax rate declines before a temporary difference has fully reversed, the deferred income tax liability must be reduced to reflect the newly enacted income tax rates. In accordance with authoritative guidance related to rate-regulated entities, the amount of such a reduction is transferred to our regulatory income tax liability, which we are amortizing over the lives of the related properties as the temporary difference reverses or approximately 30 years.

A deferred income tax liability is not recorded on undistributed foreign earnings that are expected to be indefinitely reinvested offshore. We consider, among other factors, actual cash investments offshore as well as projected cash requirements in making this determination. Changes in our investment or repatriation plans or circumstances could result in a different deferred income tax liability.

Tax BenefitsThe authoritative guidance related to income taxes requires us to determine whether tax benefits claimed or expected to be claimed on our tax return should be recorded in our consolidated financial statements. Under this guidance, we may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. This guidance also addresses derecognition, classification, interest and penalties on income taxes, and accounting in interim periods.

Uncertain Tax Positions We recognize accrued interest related to uncertain tax positions in interest expense and penalties in operating expense in the Consolidated Statements of Income. As of December 31, 2011, we did not have a liability recorded for payment of interest and penalties associated with uncertain tax positions.

Tax Collections We do not collect income taxes from our customers on behalf of governmental authorities. We collect and remit various taxes on behalf of various governmental authorities. We record these amounts in our Consolidated Statements of Financial Position. In other instances, we are allowed to recover from customers other taxes that are imposed upon us. We record such taxes as operating expense and record the corresponding customer charges as revenue. These taxes were immaterial for all periods presented.

Revenue Recognition Policy Text Block

Revenues

Distribution operations We record revenues when services are provided to customers. Those revenues are based on rates approved by the state regulatory commissions of our utilities.

As required by the Georgia Commission, in July 1998, Atlanta Gas Light began billing Marketers in equal monthly installments for each residential, commercial and industrial customer’s distribution costs. As required by the Georgia Commission, effective February 1, 2001, Atlanta Gas Light implemented a seasonal rate design for the calculation of each residential customer’s annual straight-fixed-variable (SFV) capacity charge, which is billed to Marketers and reflects the historic volumetric usage pattern for the entire residential class. Generally, this change results in residential customers being billed by Marketers for a higher capacity charge in the winter months and a lower charge in the summer months. This requirement has an operating cash flow impact but does not change revenue recognition. As a result, Atlanta Gas Light continues to recognize its residential SFV capacity revenues for financial reporting purposes in equal monthly installments.

All of our utilities, with the exception of Atlanta Gas Light, have rate structures include volumetric rate designs that allow recovery of costs through gas usage. Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. Additionally, revenues are recorded for estimated deliveries of gas not yet billed to these customers, from the last bill date to the end of the accounting period. These are included in the Consolidated Statements of Financial Position as unbilled revenue. For other commercial and industrial customers and all wholesale customers, revenues are based on actual deliveries to the end of the period.

The tariffs for Virginia Natural Gas, Elizabethtown Gas and Chattanooga Gas contain WNA’s that partially mitigate the impact of unusually cold or warm weather on customer billings and operating margin. The WNA’s purpose is to reduce the effect of weather on customer bills by reducing bills when winter weather is colder than normal and increasing bills when weather is warmer than normal. In addition, the tariffs for Chattanooga Gas and Elkton Gas contain revenue normalization mechanisms that mitigate the impact of conservation and declining customer usage. 

Retail operations Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Sales revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. In addition, revenues are recorded for estimated deliveries of gas not yet billed to these customers, from the most recent meter reading date to the end of the accounting period. These are included in the Consolidated Statements of Financial Position as unbilled revenue. For other commercial and industrial customers and all wholesale customers, revenues are based on actual deliveries during the period.

We recognize revenue on 12-month utility-bill management contracts as the lesser of cumulative earned or cumulative billed amounts. We recognize revenue for warranty and repair contracts on a straight-line basis over the contract term. Revenue for maintenance services is recognized at the time such services are performed.

Wholesale services We record wholesale services’ revenues when services are provided to customers. Profits from sales between segments are eliminated in the other segment and are recognized as goods or services sold to end-use customers. Transactions that qualify as derivatives under authoritative guidance related to derivatives and hedging are recorded at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are required to be presented net in revenue. 

Midstream operations We record operating revenues at Jefferson Island and Golden Triangle Storage in the period in which actual volumes are transported and storage services are provided. The majority of our storage services are covered under medium to long-term contracts at fixed market-based rates. We recognize our park and loan revenues ratably over the life of the contract.

Cargo shipping Revenues and related delivery costs are recognized at the time vessels depart from port. Insurance premiums are recognized when the vessel carrying the insured cargo reaches its port of destination and the insured cargo is released to the consignee. The portion of premiums not earned at the end of the year is recorded as unearned premiums. 

Cost Of Sales Policy Text Block

Cost of goods sold

Excluding Atlanta Gas Light, we charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the state regulatory agencies. Under these mechanisms, all prudently incurred natural gas costs are passed through to customers without markup, subject to regulatory review. Therefore, in accordance with the authoritative guidance for rate-regulated entities, we defer or accrue (that is, include as an asset or liability in the Consolidated Statements of Financial Position and exclude from or include in the Statements of Consolidated Income, respectively) the difference between the actual cost of goods sold incurred and the amount of commodity revenue earned in a given period, such that no operating margin is recognized related to these costs. The deferred or accrued amount is either billed or refunded to our customers prospectively through adjustments to the commodity rate. Deferred natural gas costs are reflected as regulatory assets identified as recoverable natural gas costs, and accrued natural gas costs are reflected as regulatory liabilities which are identified as accrued natural gas costs within our Consolidated Statements of Financial Position. For more information, see “Regulatory Assets and Liabilities” in Note 2.

Our retail operations customers are charged for natural gas consumed. We also include within our cost of goods sold costs of fuel and lost and unaccounted for gas, adjustments to reduce the value of our inventories to market value and for gains and losses associated with certain derivatives.

Maintenance Cost Policy Policy Text Block

Repair and maintenance expense

We record expense for repair and maintenance costs as incurred. This includes expenses for planned major maintenance, such as dry-docking the vessels owned by our cargo shipping business.

Lease Policy Text Block

Operating leases

We have certain operating leases with provisions for step rent or escalation payments and certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms, in accordance with authoritative guidance related to leases. This accounting treatment does not affect the future annual operating lease cash obligations. For more information, see “Commitments, Guarantees and Contingencies” in Note 11.

Earnings Per Share Policy Text Block

Earnings Per Common Share

We compute basic earnings per common share attributable to AGL Resources Inc. common shareholders by dividing our income attributable to AGL Resources Inc. by the daily weighted average number of common shares outstanding. Diluted earnings per common share attributable to AGL Resources Inc. common shareholders reflect the potential reduction in earnings per common share attributable to AGL Resources Inc. common shareholders that could occur when potentially dilutive common shares are added to common shares outstanding. The increase in weighted average shares is due to the issuance of 38.2 million shares in connection with the Nicor merger on December 9, 2011. The effect of the additional shares was reduced as the shares were only outstanding for 22 days. We had 117.0 million shares outstanding as of December 31, 2011.

We derive our potentially dilutive common shares by calculating the number of shares issuable under restricted stock, restricted stock units and stock options. The vesting of shares of the restricted stock and restricted stock units depends on the satisfaction of certain performance criteria. The future issuance of shares underlying the outstanding stock options depends on whether the exercise prices of the stock options are less than the average market price of the common shares for the respective periods. The following table shows the calculation of our diluted shares attributable to AGL Resources Inc. common shareholders for the periods presented, ifperformance units currently earned under the plan ultimately vest and if stock options currently exercisable at prices below the average market prices are exercised:

In millions (except per share amounts)	2011	2010	2009
Net income attributable to AGL Resources Inc.	$172	$234	$222
Denominator:
Basic weighted-average number of shares outstanding (1)	80.4	77.4	76.8
Effect of dilutive securities	0.5	0.4	0.3
Diluted weighted-average number of shares outstanding	80.9	77.8	77.1
Basic and diluted earnings per share
Basic	$2.14	$3.02	$2.89
Diluted	$2.12	$3.00	$2.88
(1)Daily weighted average shares outstanding.

The following table contains the weighted average shares attributable to outstanding stock options that were excluded from the computation of diluted earnings per common share attributable to AGL Resources Inc. because their effect would have been anti-dilutive, as the exercise prices were greater than the average market price:

	December 31,
In millions	2011	2010			2009
Twelve months ended	0.0		0.8	2.0

The decrease in the number of shares that were excluded from the computation for the year ended December 31, 2011 and 2010 is the result of an increase in the average market value of our common shares for the years ended December 31, 2011 compared to 2010 and 2009.

Regulatory Assets and Liabilities Policy

Regulatory Assets and Liabilities 

We account for the financial effects of regulation in accordance with authoritative guidance related to regulated entities whose rates are designed to recover the costs of providing service. In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense in the current period are capitalized as regulatory assets when it is probable that such costs or expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Generally, regulatory assets are amortized into expense and regulatory liabilities are amortized into income over the period authorized by the regulatory commissions. Our regulatory assets and liabilities and associated assets and liabilities as of December 31, are summarized in the following table.

In millions	2011	2010
Regulatory assets - current
Recoverable regulatory infrastructure program costs	$48	$48
Recoverable ERC	7	7
Recoverable seasonal rates	10	11
Recoverable retirement benefit costs	29	0
Recoverable natural gas costs	0	0
Other	37	26
Total regulatory assets - current	131	92
Regulatory assets - long-term
Recoverable regulatory infrastructure program costs	305	244
Recoverable retirement benefit costs	262	0
Recoverable ERC	351	164
Unamortized losses on reacquired debt	21	11
Other	140	34
Total regulatory assets - long-term	1,079	453
Total regulatory assets	$1,210	$545
Regulatory liabilities - current
Accumulated removal costs	$14	$0
Derivative instruments	22	19
Accrued natural gas costs	53	23
Bad debt rider	30	0
Other	15	8
Total regulatory liabilities - current	112	31
Regulatory liabilities - long-term
Accumulated removal costs	1,321	182
Regulatory income tax liability	27	15
Bad debt rider	14	0
Unamortized investment tax credit	32	12
Other	11	16
Total regulatory liabilities - long-term	1,405	225
Total regulatory liabilities	$1,517	$256

The increase of $665 million in regulatory assets includes $545 million related to the addition of Nicor Gas’ regulatory assets and the increase of $1,261 million in regulatory liabilities includes $1,330 million related to the addition of Nicor Gas’ regulatory liabilities. The increase in ERC liabilities is discussed further in Note 11. The increase in regulatory infrastructure program costs primarily relates to updated engineering estimates based on actual path and rights of way for pipeline added to the program in 2010.

Our regulatory assets are probable or recovery specifically authorized by a state regulatory commission. Base rates are designed to provide both a recovery of cost and a return on investment during the period rates are in effect. As such, all of our regulatory assets recoverable through base rates are subject to review by the respective state regulatory commission during future rate proceedings. We are not aware of any evidence that these costs will not be recoverable through either rate riders or base rates, and we believe that we will be able to recover such costs, consistent with our historical recoveries. In the event that the provisions of authoritative guidance related to regulated operations were no longer applicable, we would recognize a write-off of regulatory assets that would result in a charge to net income, and be classified as an extraordinary item.

Additionally, while some regulatory liabilities would be written-off, others would continue to be recorded as liabilities but not as regulatory liabilities. Although the natural gas distribution industry is competing with alternative fuels, primarily electricity, our utility operations continue to recover their costs through cost-based rates established by the state regulatory commissions. As a result, we believe that the accounting prescribed under the guidance remains appropriate. It is also our opinion that all regulatory assets are recoverable in future rate proceedings, and therefore we have not recorded any regulatory assets that are recoverable but are not yet included in base rates or contemplated in a rate rider. The regulatory liabilities that do not represent revenue collected from customers for expenditures that have not yet been incurred are refunded to ratepayers through a rate rider or base rates. If the regulatory liability is included in base rates, the amount is reflected as a reduction to the rate base in setting rates.

The majority of our regulatory assets listed in the preceding table are included in base rates except for the recoverable regulatory infrastructure program costs, recoverable ERC, the bad debt rider and accrued natural gas costs, which are recovered through specific rate riders on a dollar-for-dollar basis. The rate riders that authorize the recovery of regulatory infrastructure program costs and natural gas costs include both a recovery of cost and a return on investment during the recovery period. Nicor Gas’ rate riders for environmental costs and energy efficiency costs also provide a return on investment during the period of recovery. However, there is no interest associated with the under or over collections of bad debt expense.

The Illinois Commission presently does not allow Nicor Gas the opportunity to earn a return on its recoverable retirement benefit costs. Such cost are expected to be recovered over a period of 9 to 11 years. The regulatory assets related to debt are also not included in rate base, but the costs are recovered over the term of the debt through the authorized rate of return component of base rates. 

Environmental Remediation Costs Our ERC liabilities are estimates of future remediation costs for investigation and clean up of our former operating sites that are contaminated. Our estimates are based on probabilistic models of potential costs, on an undiscounted basis. As cleanup options and plans mature and cleanup contracts are entered into, we are able to provide conventional engineering estimates of the likely costs of remediation at our former sites. These estimates contain various engineering uncertainties, but we continuously attempt to refine and update them. These liabilities do not include other potential expenses, such as unasserted property damage claims, personal injury or natural resource damage claims, unbudgeted legal expenses or other costs for which we may be held liable but for which we cannot reasonably estimate an amount. However, we have not yet performed these probabilistic models for all of our sites in Illinois, which will be completed in 2012.

Our paid and accrued ERCs are deferred in a corresponding regulatory asset until the costs are recovered from customers. We primarily recover these deferred costs through three rate riders that authorize dollar-for-dollar recovery. The ERC rate rider for Atlanta Gas Light only allows for recovery of the costs incurred over the subsequent five-year period. ERC associated with the investigation and remediation of Nicor Gas and Elizabethtown Gas remediation sites located in the states of Illinois and New Jersey are recovered under remediation adjustment clauses that include carrying cost on unrecovered expenditures. For more information on our ERC liabilities, see Note 11.

Bad Debt Rider Nicor Gas’ bad debt rider provides for the recovery from (or refund to) customers of the difference between Nicor Gas’ actual bad debt experience on an annual basis and the benchmark bad debt expense included in its rates for the respective year. The benchmark, against which 2011 actual bad debt experience is compared, is approximately $63 million. Nicor Gas’ actual 2011 bad debt expense was $31 million, resulting in a refund to customers of $32 million which will be refunded between June 2012 and May 2013. The prior year’s bad debt rider is recorded within operating expenses on our Consolidated Statements of Income and the over, or under, recovery is recorded as a regulatory asset or liability on our Consolidated Statements of Financial Position.

Other Regulatory Assets and Liabilities Our recoverable retirement benefit plan costs are recoverable through base rates over the next 2 to 21 years based on the remaining recovery period as designated by the applicable state regulatory commissions. Recoverable seasonal rates reflect the difference between the recognition of a portion of Atlanta Gas Light’s residential base rates revenues on a straight-line basis as compared to the collection of the revenues over a seasonal pattern. These amounts are fully recoverable through base rates within one year.

Accumulated Removal CostsIn accordance with regulatory treatment, our depreciation rates are comprised of two cost components – historical cost, net of estimated salvage, and the estimated cost of removal, or retirement, of certain regulated properties. We collect these costs in base rates through straight-line depreciation expense, with a corresponding credit to accumulated depreciation. Because the accumulated estimated removal costs meet the requirements of authoritative guidance related to regulated operations, we have accounted for them as a regulatory liability and have reclassified them from accumulated depreciation to accumulated removal costs in our Consolidated Statements of Financial Position. In the rate setting process, the liability for these accumulated removal costs are treated as a reduction to the net rate base upon which our regulated utilities have the opportunity to earn their allowed rate of return. Our accumulated removal costs increased $1.1 billion from December 31, 2010, principally related to Nicor Gas.

Regulatory Infrastructure Programs By order of the Georgia Commission (through a joint stipulation and a subsequent settlement agreement between Atlanta Gas Light and the Georgia Commission), Atlanta Gas Light began a pipeline replacement program to replace all bare steel and cast iron pipe in its system by December 2013. If Atlanta Gas Light does not perform in accordance with this order, it will be assessed certain nonperformance penalties. As of 2011, we have completed the replacement of all our cast iron pipes, and the remaining replacements are on schedule.

The order provides for recovery of all prudent costs incurred in the performance of the program, which Atlanta Gas Light has recorded as a regulatory asset. Atlanta Gas Light will recover from end-use customers, through billings to Marketers, the costs related to the program net of any cost savings from the program. All such amounts will be recovered through a combination of straight-fixed-variable rates and a pipeline replacement revenue rider. The regulatory asset has two components:

·the costs incurred to date that have not yet been recovered through the rate rider

·the future expected costs to be recovered through the rate rider

Atlanta Gas Light has recorded a current regulatory asset of $48 million, which represents the expected future collection of both expenditures already incurred and expected future capital expenditures to be incurred through the remainder of the program. Atlanta Gas Light has also recorded a noncurrent asset of $305 million, which represents the expected amount to be collected from customers over the next 12 months. The amounts recovered from the pipeline replacement revenue rider during the last three years were:

·$48 million in 2011

·$45 million in 2010

·$41 million in 2009

As of December 31, 2011, Atlanta Gas Light had recorded a current liability of $131 million representing expected program expenditures for the next 12 months and a noncurrent liability of $145 million, representing expected program expenditures through the end of the program in 2013.

Atlanta Gas Light capitalizes and depreciates the capital expenditure costs incurred from the pipeline replacement program over the life of the assets. Operation and maintenance costs are expensed as incurred. Recoveries, which are recorded as revenue, are based on a formula that allows Atlanta Gas Light to recover operation and maintenance costs in excess of those included in its current base rates, depreciation expense and an allowed rate of return on capital expenditures. In the near term, the primary financial impact to Atlanta Gas Light from the pipeline replacement program is reduced cash flow from operating and investing activities, as the timing related to cost recovery does not match the timing of when costs are incurred. However, Atlanta Gas Light is allowed the recovery of carrying costs on the under-recovered balance resulting from the timing difference.

The Georgia Commission has also approved Atlanta Gas Light’s STRIDE program, which is comprised of the ongoing pipeline replacement program, the new Integrated System Reinforcement Program (i-SRP) and the new Integrated Customer Growth Program (i-CGP). The purpose of the i-SRP is to upgrade Atlanta Gas Light’s distribution system and liquefied natural gas facilities in Georgia, improve its system reliability and operational flexibility, and create a platform to meet long-term forecasted growth. Atlanta Gas Light will be required to file an updated ten-year forecast of infrastructure requirements under the i-SRP along with a new three-year construction plan every three years for review and approval by the Georgia Commission.

Under i-CGP, the Georgia Commission authorized Atlanta Gas Light to extend its pipeline facilities to serve customers without pipeline access and create new economic development opportunities in Georgia. The i-CGP was approved as a three-year pilot program under STRIDE, and all related costs will be recovered through a surcharge.

In 2009, the New Jersey BPU approved an enhanced infrastructure program for Elizabethtown Gas, which was created in response to the New Jersey Governor’s request for utilities to assist in the economic recovery by increasing infrastructure investments. In May 2011, the New Jersey BPU approved Elizabethtown Gas’ request to spend an additional $40 million under this program before the end of 2012. Costs associated with the investment in this program are recovered through periodic adjustments to base rates. We expect to file for an extension of the program in 2012.

Pension And Other Postretirement Plans Policy

Accounting for Retirement Benefit Plans

The authoritative guidance related to retirement benefits requires that we recognize all obligations related to defined benefit retirement plans and quantify the plans’ funded status as an asset or a liability on our Consolidated Statements of Financial Position. The guidance further requires that we measure the plans’ assets and obligations that determine our funded status as of the end of the fiscal year. We are also required to recognize as a component of OCI the changes in funded status that occurred during the year that are not yet recognized as part of net periodic benefit cost as explained in authoritative guidance related to retirement benefits. Because substantially all of its retirement costs are recoverable through base rates, Nicor Gas generally defers any charge or credit to a regulatory asset or liability until the period in which the costs are included in base rates, in accordance with the authoritative guidance for rate-regulated entities. The assets of our retirement plans were accounted for at fair value and are classified in the fair value hierarchy in their entirety based on the lowest level of input that is significant to the fair value measurement.

Use Of Estimates Policy

Use of Accounting Estimates

The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures. We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, and we evaluate our estimates on an ongoing basis. Our estimates may involve complex situations requiring a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. The most significant estimates relate to our pipeline replacement program accruals, environmental liability accruals, uncollectible accounts and other allowance for contingent losses, goodwill and intangible assets, retirement plan obligations, derivative and hedging activities and provisions for income taxes. Our actual results could differ from our estimates.