XML 42 R28.htm IDEA: XBRL DOCUMENT

Significant Accounting Policies and Methods of Application (Policies)

12 Months Ended

Dec. 31, 2015

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

Energy Marketing Receivables And Payables

Energy Marketing Receivables and Payables

Wholesale services provides services to retail marketers, wholesale marketers, utility companies and industrial customers. These customers, also known as counterparties, utilize netting agreements that enable our wholesale services segment to net receivables and payables by counterparty upon settlement. Wholesale services also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, wholesale services’ counterparties are settled net, they are recorded on a gross basis in our Consolidated Balance Sheets as energy marketing receivables and energy marketing payables.

Our wholesale services segment has trade and credit contracts that contain 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. To date, our credit ratings have exceeded the minimum requirements. As of December 31, 2015 and 2014, 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. 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 its counterparties. This credit risk is generally concentrated in 20 of its counterparties and is measured by 30-day receivable exposure plus forward exposure. We evaluate the credit risk of our counterparties using an 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 to 1, with 9 being equivalent to AAA/Aaa by S&P and Moody’s and 1 being equivalent to D/Default by S&P and Moody’s. A counterparty that does not have an external rating is assigned an internal rating based on the strength of its financial ratios. As of December 31, 2015, our top 20 counterparties represented 53%, or $196 million, of our total counterparty exposure and had a weighted average S&P equivalent rating of A-.

We have established credit policies to determine and monitor the creditworthiness of counterparties, including requirements to post 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 U.S. 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 combined with a reasonable measure of our credit risk. Wholesale services also uses other netting agreements with certain counterparties with whom it conducts significant transactions.

Receivables and Allowance for Uncollectible Accounts

Our other trade receivables consist primarily 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 our remaining receivables, if we are aware of a specific customer’s inability to pay, we record an allowance for doubtful accounts against amounts due to reduce the receivable balance to the amount we reasonably expect to collect. 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, customer deposits and general economic conditions. Customers’ accounts are written off once we deem them to be uncollectible.

Nicor Gas Credit risk exposure at Nicor Gas is mitigated by a bad debt rider approved by the Illinois Commission. 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 used to establish its base rates for the respective year. See Note 4 for additional information on the bad debt rider.

Atlanta Gas Light Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 14 Marketers in Georgia. The credit risk exposure to Marketers varies seasonally, with the lowest exposure in the non-peak 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 the purchase and sale of natural gas, customer service, billings and collections. We obtain credit security support in an amount equal to no less than two times a Marketer’s highest month’s estimated bill from Atlanta Gas Light.

Inventories

For our regulated utilities, except Nicor Gas, natural gas inventories and the inventories we hold for Marketers in Georgia are carried at cost on a WACOG basis. In Georgia’s competitive environment, Marketers 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. On a monthly basis, Atlanta Gas Light assigns to Marketers the majority of the pipeline storage services that it has under contract, along with a corresponding amount of inventory. Atlanta Gas Light retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand.

Nicor Gas’ inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year-end are charged to cost of goods sold at the estimated annual replacement cost. Inventory decrements that are not restored prior to year-end are charged to cost of goods sold at the actual LIFO cost of the layers liquidated. Since the cost of gas, including inventory costs, is charged to customers without markup, subject to Illinois Commission review, LIFO liquidations have no impact on net income. At December 31, 2015, the Nicor Gas LIFO inventory balance was $145 million. Based on the average cost of gas purchased in December 2015, the estimated replacement cost of Nicor Gas’ inventory at December 31, 2015 was $201 million, which exceeded the LIFO cost by $56 million. During 2015, we did not liquidate any of our LIFO-based inventory.

Our retail operations, wholesale services and midstream operations segments carry inventory at LOCOM, where cost is determined on a WACOG basis. For these segments, we 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. As indicated in the following table, for any declines considered to be other than temporary, we recorded LOCOM adjustments to cost of goods sold to reduce the value of our natural gas inventories to market value.



In millions	2015		2014		2013
Retail operations	$	3	$	4	$	1
Wholesale services ⁽¹⁾	19		73		8
Other	1		—		—
Total	$	23	$	77	$	9


(1)	The increase in 2014 was due to a significant decline in natural gas prices in December 2014.

Operational issues at a third-party storage facility during 2015 caused 5 Bcf of our inventory at wholesale services to be inaccessible. These operational issues at this facility have been resolved, and we began withdrawing the inventory in the fourth quarter of 2015. Our capacity contract with the facility expires at the end of the first quarter of 2016.

At midstream operations, mechanical integrity tests and engineering studies are periodically performed on the storage facilities in accordance with certain state regulatory requirements. During 2014, an engineering study and mechanical integrity tests were performed at one of our storage facilities and identified a lower amount of working gas capacity due to naturally occurring shrinkage of the storage cavern. Further, based on the lower capacity and an analysis of the volume of natural gas stored in the facility, we recorded $10 million in additional natural gas costs for the year ended December 31, 2014 to true-up the amount of retained fuel at this facility. Other storage facilities at midstream operations were not impacted.

Regulated Operations

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 that would otherwise be charged to expense in the current period are capitalized as regulatory assets when it is probable that such costs 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 estimated expenditures that have not yet been incurred. Generally, regulatory assets and regulatory liabilities are amortized into our Consolidated Statements of Income over the period authorized by the regulatory agencies.

Fair Value Measurements

We have financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value include cash and cash equivalents and derivative instruments. The carrying values of receivables, short and long-term investments, accounts payable, short-term debt, other current assets and liabilities, and accrued interest approximate their respective fair value. Our nonfinancial assets and liabilities include pension and welfare benefits. See Note 5 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 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 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 certain retirement plan assets.

Level 2 Pricing 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 marketplace. Instruments in this category include shorter tenor exchange-traded and non-exchange-traded derivatives such as OTC forwards and options and certain retirement plan assets.

Level 3 Pricing inputs include significant unobservable inputs that may be used with internally developed methodologies to determine management’s best estimate of fair value from the perspective of market participants. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. Our Level 3 assets, liabilities and any applicable transfers are primarily related to our pension and welfare benefit plan assets as described in Note 5 and Note 7. 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 whether the market for a financial asset is inactive or a transaction is distressed. Currently, this authoritative guidance does not affect us, as our derivative instruments are traded in active markets.

Derivative Instruments

Our policy is to classify derivative cash flows and gains and losses within the same financial statement category as the hedged item, rather than by the nature of the instrument.

Fair Value Hierarchy Derivative assets and liabilities are classified in their entirety into the previously described fair value hierarchy levels 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 measurement of fair value incorporates various factors required under the guidance, which 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 own 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 backup in the form of cash or letters of credit and, in most instances, enter into netting arrangements. See Note 5 for additional fair value disclosures.

Netting of Cash Collateral and Derivative Assets and Liabilities under Master Netting Arrangements We 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.

We have elected to net derivative assets and liabilities under master netting arrangements on our Consolidated Balance Sheets. With that election, we are also required to offset cash collateral held in our broker accounts with the associated net fair value of the instruments in the accounts. See Note 5 for additional information about our cash collateral.

Natural Gas and Weather Derivative Instruments The fair value of the natural gas derivative instruments that we use to manage exposures arising from changing natural gas prices and warmer-than-normal weather risk 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 6 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 regulatory requirements, any realized gains or losses related to these derivatives are reflected in natural gas costs and ultimately included in billings to customers. As previously noted, such derivative instruments are reported at fair value each reporting period on our Consolidated Balance Sheets. 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 until the related revenue is recognized.

For our weather risk associated with Nicor Gas, we have a corporate weather hedging program that utilizes weather derivatives to reduce the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather in Illinois. These weather derivatives are carried at intrinsic value. We will continue to use available methods to mitigate our exposure to weather in Illinois.

Retail Operations We have designated a portion of our derivative instruments, consisting of financial swaps to manage the risk associated with forecasted natural gas purchases and sales, as cash flow hedges. We record derivative gains or losses arising from cash flow hedges in OCI and reclassify them into earnings in the same period that the underlying hedged item is recognized in earnings.

We currently have minimal hedge ineffectiveness, which occurs when the gains or losses on the hedging instrument more than offset the losses or gains on the hedged item. Any cash flow hedge ineffectiveness is recorded on our Consolidated Statements of Income in the period in which it occurs. We have not designated the remainder of our derivative instruments as hedges for accounting purposes and, accordingly, we record changes in the fair values of such instruments within cost of goods sold on our Consolidated Statements of Income in the period of change.

We also enter into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather in the Heating Season. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non exchange-traded contracts are also reflected in operating revenues in our Consolidated Statements of Income.

Wholesale Services We purchase natural gas for storage when the current market price we pay to buy and transport natural gas plus the cost to store and finance 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 and OTC contracts to sell natural gas at that future price to substantially protect the operating margin we will ultimately realize when the stored natural gas is sold. We also enter into transactions to secure transportation capacity between delivery points in order to serve our customers and various markets. We use NYMEX futures and OTC contracts to capture the price differential or spread between the locations served by the capacity in order to substantially protect the operating margin we will ultimately realize when we physically flow natural gas between delivery points. These contracts generally meet the definition of derivatives and are carried at fair value on our Consolidated Balance Sheets, with changes in fair value recorded in operating revenues on our Consolidated Statements of Income in the period of change. These contracts are not designated as hedges for accounting purposes.

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 and transportation portfolio. We incur monthly demand charges for the contracted storage and transportation capacity and payments associated with asset management agreements, and we recognize these demand charges and payments on our Consolidated Statements of Income in the period they are incurred. This difference in accounting methods can result in volatility in our reported earnings, even though the economic margin is substantially unchanged from the dates the transactions were consummated.

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. See Note 5 for fair value disclosure.

Property, Plant and Equipment

A summary of our PP&E by classification as of December 31, 2015 and 2014 is provided in the following table.



In millions	2015		2014
Transportation and distribution	$	9,912	$	9,105
Storage facilities	1,255		1,202
Other	985		919
Construction work in progress	414		326
PP&E, gross	12,566		11,552
Less accumulated depreciation	2,775		2,462
PP&E, net	$	9,791	$	9,090

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


•	material and labor;


•	contractor costs;


•	construction overhead costs;


•	AFUDC; and,


•	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 do not recognize any gains or losses on depreciable utility property that is retired or otherwise disposed, as required under the composite depreciation method. Such gains or losses are ultimately refunded to, or recovered from, customers through future rate adjustments. Our natural gas utilities also hold property, primarily land, that is not presently used and useful in utility operations and is not included in rate base. Upon sale, any gain or loss is recognized in other income.

Retail Operations, Wholesale Services, Midstream Operations 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 within operation and maintenance expense for retired or otherwise disposed-of property. Natural gas in salt-dome storage at Jefferson Island and Golden Triangle that is retained as pad gas is classified as non-depreciable PP&E and is carried at cost. Central Valley has two types of pad gas in its depleted reservoir storage facility: the first is non-depreciable PP&E, which is carried at cost, and the second is non-recoverable, which is depreciated over the life of the storage facility.

On April 11, 2014, we entered into two arrangements associated with the Dalton Pipeline. The first was a construction and ownership agreement through which we will have a 50% undivided ownership interest in the 106 mile Dalton Pipeline that will be constructed in Georgia and serve as an extension of the Transco natural gas pipeline system into northwest Georgia. We also entered into an agreement to lease our 50% undivided ownership in the Dalton Pipeline once it is placed in service. The lease payments to be received are $26 million annually for an initial term of 25 years. The lessee will be responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC-regulated tariff. Engineering design work has commenced and construction is expected to begin in the second quarter of 2016. At December 31, 2015, our 50% share of construction costs was $33 million and is reflected in construction work in process on our Consolidated Balance Sheets.

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.



	2015		2014		2013
Atlanta Gas Light ⁽¹⁾	2.4	%	2.3	%	2.6	%
Chattanooga Gas ⁽¹⁾	2.5		2.5		2.5
Elizabethtown Gas ⁽²⁾	2.4		2.5		2.4
Elkton Gas ⁽²⁾	2.7		2.8		2.4
Florida City Gas ⁽²⁾	3.9		3.9		3.8
Nicor Gas ^{(2) (3)}	3.1		3.1		3.1
Virginia Natural Gas ⁽¹⁾	2.5		2.5		2.5


(1)	Average composite straight-line depreciation rates for depreciable property, excluding transportation equipment, which may be depreciated in excess of useful life and recovered in rates.


(2)	Composite straight-line depreciation rates.


(3)	In October 2013, the Illinois Commission approved a composite depreciation rate of 3.07%. The depreciation rate was effective as of August 30, 2013, the date the depreciation study was filed, and had the effect of reducing our 2014 and 2013 depreciation expense by $51 million and $19 million, respectively.

For our non-regulated segments, 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		5 – 10
Storage caverns		40 – 60
Other		up to 40

AFUDC and Capitalized Interest

AFUDC 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. Atlanta Gas Light, Nicor Gas, Chattanooga Gas and Elizabethtown Gas are authorized by applicable state regulatory agencies or legislatures to capitalize the cost of debt and equity funds as part of the cost of PP&E construction projects on our Consolidated Balance Sheets. The capital expenditures of our other three utilities do not qualify for AFUDC treatment. More information on our authorized or actual AFUDC rates is provided in the following table.



	2015			2014			2013
Atlanta Gas Light	8.10		%	8.10		%	8.10		%
Nicor Gas ⁽¹⁾	0.82		%	0.24		%	0.31		%
Chattanooga Gas	7.41		%	7.41		%	7.41		%
Elizabethtown Gas ⁽¹⁾	1.69		%	0.44		%	0.41		%
AFUDC (in millions) ⁽²⁾	$	6		$	7		$	18


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


(2)	Amount recorded on the Consolidated Statements of Income.

Asset Retirement Obligations

We record a liability at fair value for an asset retirement obligation (ARO) when a legal obligation to retire the asset has been incurred, with an offsetting increase to the carrying value of the related asset. Accretion of the ARO due to the passage of time is recorded as an operating expense. We have recorded an ARO of $3 million at December 31, 2015 and 2014 principally for our storage facilities. For our distribution PP&E, we cannot reasonably estimate the fair value of this obligation because we have determined that we have insufficient internal or industry information to reasonably estimate the potential settlement dates or costs.

Impairment of Assets

Our goodwill is not amortized, but is subject to an annual impairment test. Our other long-lived assets, including our finite-lived intangible assets, require an impairment review when events or circumstances indicate that the carrying amount may not be recoverable. We base our evaluation of the recoverability of other long-lived assets on the presence of impairment indicators such as the future economic benefit of the assets, any historical or future profitability measurements and other external market conditions or factors.

Goodwill Our annual impairment test is performed at the reporting unit level during the fourth quarter of each year or more frequently if impairment indicators arise.

Our 2014 annual goodwill impairment test indicated that the estimated fair value of our storage and fuels reporting unit, that had $14 million of goodwill, within our midstream operations segment exceeded its carrying value by less than 5% and would be at risk of failing step 1 of the goodwill impairment test if a further decline in the estimated fair value were to occur. While preparing our third quarter 2015 financial statements, and in connection with our 2016 annual budget process, we assessed various market factors and projections prepared by both internal and external sources related to subscription rates for contracting capacity at our storage facilities as well as the profitability of our storage and fuels reporting unit. Based on this assessment, we concluded that a decline in projected storage subscription rates as well as a reduction in the near-term projection of the reporting unit's profitability required us to perform an interim goodwill impairment test as of September 30, 2015.

Step 1 of our interim goodwill impairment test compared the fair value of the reporting unit to its carrying value utilizing the income approach, under which the fair value was estimated based on the present value of estimated future cash flows discounted at an appropriate interest rate. The result of our step 1 test revealed that the estimated fair value of our storage and fuels reporting unit was below its carrying value.

Step 2 of this interim goodwill impairment test compared the implied fair value of goodwill in our storage and fuels reporting unit, which was calculated as the residual amount from the reporting unit's overall fair value after assigning fair values to its assets and liabilities under a hypothetical purchase price allocation as if the reporting unit had been acquired in a business combination, to its carrying value. Based on the result of our step 2 test, we recorded a non-cash impairment charge of the full $14 million ($9 million, net of tax) of goodwill.

For our 2015 annual goodwill impairment test of the remaining goodwill, we performed the qualitative step 0 assessment focusing on the following qualitative factors: macroeconomic conditions, industry and market conditions, cost factors, financial performance, entity specific events and events specific to each reporting unit. Our step 0 analysis concluded that it is more likely than not that the fair value of our reporting units that have goodwill exceeds their carrying amounts and a quantitative assessment was not required. The amounts of goodwill as of December 31, 2015 and 2014 are provided below.



In millions	Distribution operations		Retail operations		Midstream operations			Consolidated
Goodwill - December 31, 2014	$	1,640	$	173	$	14		$	1,827
Impairment	—		—		(14		)	(14		)
Goodwill - December 31, 2015	$	1,640	$	173	$	—		$	1,813

Long-Lived Assets We depreciate or amortize our long-lived assets and other intangible assets, which are all located in the U.S., over their useful lives. We have no significant indefinite-lived intangible assets. These long-lived assets and other intangible assets are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through expected future cash flows. Impairment is indicated if the carrying amount of the long-lived asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If impairment is indicated, we record an impairment loss equal to the difference between the carrying value and the fair value of the long-lived asset. We determined that there were no long-lived asset impairments in 2015 or 2014; however, in 2013, we recorded an $8 million loss related to Sawgrass Storage.

Intangible Assets Our intangible assets within our retail operations segment are presented in the following table and represent the estimated fair value at the date of acquisition of the acquired intangible assets in our businesses. As indicated previously, we perform an impairment review when impairment indicators are present. If present, we first determine whether the carrying amount of the asset is recoverable through the undiscounted future cash flows expected from the asset. If the carrying amount is not recoverable, we measure the impairment loss, if any, as the amount by which the carrying amount of the asset exceeds its fair value.



		December 31, 2015							December 31, 2014
In millions	Weighted average amortization period (in years)	Gross		Accumulated amortization			Net		Gross		Accumulated amortization			Net
Customer relationships	13	$	132	$	(57	)	$	75	$	130	$	(42	)	$	88
Trade names	13	45		(11		)	34		45		(8		)	37
Total		$	177	$	(68	)	$	109	$	175	$	(50	)	$	125

We amortize these intangible assets in a manner in which the economic benefits are consumed utilizing the undiscounted cash flows that were used in the determination of their fair values. Amortization expense was $18 million in 2015, $20 million in 2014 and $18 million in 2013. Amortization expense for the next five years is expected to be as follows:



In millions	Amortization Expense
2016	$	17
2017	15
2018	14
2019	12
2020	11

Accounting for Retirement Benefit Plans

We recognize the funded status of our plans as an asset or a liability on our Consolidated Balance Sheets, measuring the plans’ assets and obligations that determine our funded status as of the end of the fiscal year. We generally 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. Because substantially all of its retirement costs are recoverable through base rates, Nicor Gas defers the change in funded status that would normally be charged or credited to comprehensive income 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 are measured at fair value within the funded status 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.

In determining net periodic benefit cost, the expected return on plan assets component is determined by applying our expected return on assets to a calculated asset value, rather than to the fair value of the assets as of the end of the previous fiscal year. For more information, see Note 7. In addition, we have elected to amortize gains and losses caused by actual experience that differ from our assumptions into subsequent periods. The amount to be amortized is the amount of the cumulative gain or loss as of the beginning of the year, excluding those gains and losses not yet reflected in the calculated value, that exceeds 10 percent of the greater of the benefit obligation or the calculated asset value. The amortization period is the average remaining service period of active employees.

Taxes

Income Taxes The reporting of our assets and liabilities for financial accounting purposes differs from the reporting for income tax purposes. The principal difference between net income and taxable income relates 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 temporary differences as deferred income tax assets or liabilities on our Consolidated Balance Sheets.

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

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

With the sale of Tropical Shipping in the third quarter of 2014, we determined that the cumulative foreign earnings of that business would no longer be indefinitely reinvested offshore. Accordingly, we recognized income tax expense of $60 million in 2014 related to the cumulative foreign earnings for which no tax liabilities had been previously recorded, resulting in our repatriation of $86 million in cash. Refer to Note 15 for additional information.

Income Tax Benefits The 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 uncertainty in income taxes only if it is more likely than not that the tax position will be sustained upon 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 upon the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement.

Uncertainty in Income Taxes We recognize accrued interest related to uncertainty in income taxes in interest expense and penalties in operating expense on our Consolidated Statements of Income.

Tax Collections We do not collect income taxes from our customers on behalf of governmental authorities. However, we do collect and remit various other taxes on behalf of various governmental authorities. We record these amounts on our Consolidated Balance Sheets. In other instances, we are allowed to recover from customers other taxes that are imposed upon us. We record such taxes as operating expenses and record the corresponding customer charges as operating revenues on our Consolidated Statements of Income.

Revenues

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

As required by the Georgia Commission, Atlanta Gas Light bills Marketers in equal monthly installments for each residential, commercial and industrial end-use customer’s distribution costs. Additionally, as required by the Georgia Commission, Atlanta Gas Light bills Marketers for capacity costs utilizing a seasonal rate design for the calculation of each residential end-use customer’s annual straight-fixed-variable charge, which reflects the historic volumetric usage pattern for the entire residential class. Generally, this seasonal rate design results in billing the Marketers a higher capacity charge in the winter months and a lower charge in the summer months, which impacts our operating cash flows. However, this seasonal billing requirement does not impact our revenues, which are recognized on a straight-line basis, because the associated rate mechanism ensures that we ultimately collect the full annual amount of the straight-fixed-variable charges.

All of our utilities, with the exception of Atlanta Gas Light, have rate structures that include volumetric rate designs that allow the opportunity to recover certain costs based on 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, unbilled revenues are recognized for estimated deliveries of gas not yet billed to these customers, from the last bill date to the end of the accounting period. For other commercial and industrial customers and for 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 WNAs that partially mitigate the impact of unusually cold or warm weather on customer billings and operating margin. The WNAs have the effect of reducing customer bills when winter weather is colder-than-normal and increasing customer bills when weather is warmer-than-normal. In addition, the tariffs for Virginia Natural Gas, Chattanooga Gas and Elkton Gas contain revenue normalization mechanisms that mitigate the impact of conservation and declining customer usage.

Revenue Taxes We charge customers for gas revenue and gas use taxes imposed on us and remit amounts owed to various governmental authorities. Our policy for gas revenue taxes is to record the amounts charged by us to customers, which for some taxes includes a small administrative fee, as operating revenues, and to record the related taxes imposed on us as operating expenses on our Consolidated Statements of Income. Our policy for gas use taxes is to exclude these taxes from revenue and expense, aside from a small administrative fee that is included in operating revenues as the tax is imposed on the customer. As a result, the amount recorded in operating revenues will exceed the amount recorded in operating expenses by the amount of administrative fees that are retained by the company. Revenue taxes included in operating expenses were $101 million in 2015, $130 million in 2014 and $110 million in 2013.

Retail operations Revenues from natural gas 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, unbilled revenues are recognized 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. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries during the period.

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

Wholesale services Revenues from energy and risk management activities are required under authoritative guidance to be netted with the associated costs. Profits from sales between segments are eliminated 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 for storage and transportation services in the period in which 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.

Cost of Goods Sold

Distribution operations Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, 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. In accordance with the authoritative guidance for rate-regulated entities, we defer or accrue (that is, include as an asset or liability on the Consolidated Balance Sheets and exclude from, or include on, the Consolidated Statements of Income, respectively) the difference between the actual cost of goods sold 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 and accrued natural gas costs are reflected as regulatory liabilities. For more information, see Note 4.

Retail operations Our retail operations customers are charged for actual or estimated natural gas consumed. Within our cost of goods sold, we also include costs of fuel and lost and unaccounted for gas, adjustments to reduce the value of our inventories to market value and gains and losses associated with certain derivatives. Costs to service our warranty and repair contract claims are recorded to cost of goods sold.

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 Note 12.

Earnings Per Common Share

We compute basic earnings per common share attributable to AGL Resources by dividing our net income attributable to AGL Resources by the daily weighted average number of common shares outstanding. Diluted earnings per common share attributable to AGL Resources reflect the potential reduction in earnings per common share attributable to AGL Resources that occurs when potentially dilutive common shares are added to common shares outstanding.

We derive our potentially dilutive common shares by calculating the number of shares issuable under restricted stock, restricted stock units and stock options award programs. The vesting of certain shares of the restricted stock and restricted stock units depends on the satisfaction of defined performance criteria and/or time-based criteria. The future issuance of shares underlying the outstanding stock options depends on whether the market price of the common shares underlying the options exceeds the respective exercise prices of the stock options.

Sale of Compass Energy

On May 1, 2013, we sold Compass Energy, a non-regulated retail natural gas business supplying commercial and industrial customers, within our wholesale services segment. We received an initial cash payment of $12 million, which resulted in an $11 million pre-tax gain ($5 million, net of tax). Under the terms of the purchase and sale agreement, we were eligible to receive contingent cash consideration up to $8 million with a guaranteed minimum receipt of $3 million that was recognized during 2013. The remaining $5 million of contingent cash consideration was to be received from the buyer annually over a five-year earn-out period based upon the financial performance of Compass Energy. In the third quarter of 2014, we negotiated with the buyer to settle the future earn-out payments and we received $4 million, resulting in the recognition of a $3 million gain. We have a five-year agreement through April 2018 to supply natural gas to our former customers and as a result of our continued involvement, the sale of Compass Energy did not meet the criteria for treatment as a discontinued operation in 2014.

Non-Wholly Owned 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 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. We have concluded that the only venture that we are required to consolidate as a VIE, as we are the primary beneficiary, is SouthStar. On our Consolidated Balance Sheets, we recognize Piedmont’s share of SouthStar 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 consolidation of SouthStar 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.

For entities that are not determined to be VIEs, we evaluate whether we have control or significant influence over the investee 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. However, we also invest in partnerships and limited liability companies that maintain separate ownership accounts. All such investments are required to be accounted for under the equity method unless our interest is so minor that there is virtually no influence over operating and financial policies, as are all investments in joint ventures.

Investments accounted for under the equity method are included in long-term investments on our Consolidated Balance Sheets, and the equity income is recorded within other income on our Consolidated Statements of Income and was immaterial for all periods presented. For additional information, see Note 11.

Use of Accounting Estimates

The preparation of our financial statements in conformity with GAAP requires us to use judgment and make estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures. Our estimates are based on historical experience and various other assumptions that we believe to be reasonable under the circumstances. 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 the accounting for our rate-regulated subsidiaries, uncollectible accounts and other allowances for contingent losses, goodwill and other intangible assets, retirement plan benefit obligations, derivative and hedging activities and provisions for income taxes. We evaluate our estimates on an ongoing basis and our actual results could differ from our estimates.

Accounting Developments

Accounting standards adopted in 2015

In April 2015, the FASB issued updated authoritative guidance related to debt issuance costs. The amendment modifies the presentation of unamortized debt issuance costs on our Consolidated Balance Sheets. Under the new guidance, we present such amounts as a direct deduction from the face amount of the debt, similar to unamortized debt discounts and premiums, rather than as an asset. Amortization of the debt issuance costs continues to be reported as interest expense on the Consolidated Statements of Income. While the guidance would have been effective for us beginning January 1, 2016, we elected to adopt its provisions effective April 1, 2015, and have applied its provisions to each prior period presented for comparative purposes. This new guidance resulted in an adjustment to the presentation of debt issuance costs primarily from other long-term assets to offset the related debt balances in long-term debt totaling $20 million and $21 million as of December 31, 2015 and 2014, respectively. The April 2015 guidance did not address the classification of debt issuance costs related to line-of-credit arrangements and, consequently, we continued to report such costs as assets subject to amortization over the term of the arrangement. In August 2015, the FASB issued clarifying guidance supporting the deferral and presentation of line-of-credit related debt issuance costs as an asset and subsequently amortizing these costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the arrangement.

Other newly issued accounting standards and updated authoritative guidance

In May 2014, the FASB issued updated authoritative guidance related to revenue from contracts with customers. The update replaces most of the existing guidance with a single set of principles for recognizing revenue from contracts with customers. In July 2015, the FASB delayed the effective date by one year and the guidance will now be effective for us beginning January 1, 2018. Early adoption of the standard is permitted, but not before the original effective date of December 15, 2016. The new guidance must be applied retrospectively to each prior period presented or via a cumulative effect upon the date of initial application. We have not yet determined the impact of this new guidance, nor have we selected a transition method.

In June 2014, the FASB issued an update to authoritative guidance related to accounting for a stock-based compensation performance target that could be achieved after the requisite service period. The guidance was issued to resolve diversity in practice. The new guidance was applied prospectively and became effective for us beginning January 1, 2016. We have determined that this new guidance will not have a material impact on our consolidated financial statements.

In February 2015, the FASB issued updated authoritative guidance related to the consolidation of other legal entities into our financial statements. The amendments modify aspects of the consolidation determination that could potentially impact us, including the analysis of limited partnerships and similar legal entities, fee arrangements, and related party relationships. The guidance became effective for us on January 1, 2016. We have determined that this new guidance will not have a material impact on our consolidated financial statements.

In April 2015, the FASB issued authoritative guidance related to the accounting for fees paid in connection with arrangements with cloud-based software providers. Under the new guidance, unless a software arrangement includes specific elements enabling customers to possess and operate software on platforms other than that offered by the cloud-based provider, the cost of such arrangements is to be accounted for as an operating expense of the period incurred. The new guidance was applied prospectively and became effective for us on January 1, 2016. We have determined that this new guidance will not have a material impact on our consolidated financial statements.

In May 2015, the FASB issued updated authoritative guidance to reduce the diversity in fair value measurements hierarchy disclosures. This amendment removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share. This guidance became effective for us on January 1, 2016. We have determined that this new guidance will not have a material impact on our consolidated financial statements.

In July 2015, the FASB issued updated authoritative guidance to simplify the measurement of certain inventories. Under the new guidance, inventories are required to be measured at the lower of cost and net realizable value, the latter representing the estimated selling price in the ordinary course of business, reduced by costs of completion, disposal, and transportation. Under current guidance, inventories are required to be measured at the lower of cost or market, but depending upon specific circumstances, market could refer to replacement cost, net realizable value, or net realizable value reduced by a normal profit margin. The amendments do not apply to inventories carried on a LIFO basis, which for us applies only to our Nicor Gas inventories. The guidance is to be applied prospectively, is effective for us beginning January 1, 2017, and early adoption is permitted. We are currently evaluating the potential impact of this new guidance.

In November 2015, the FASB issued updated authoritative guidance to the Balance Sheet Classification of Deferred Taxes, which requires companies to present deferred income tax assets and deferred income tax liabilities as noncurrent in a classified balance sheet instead of the current requirement to separate deferred income tax liabilities and assets into current and noncurrent amounts. The guidance is effective for us beginning January 1, 2017. Early application is permitted either prospectively or retrospectively. We have determined that this new guidance will not have a material impact on our consolidated financial statements.

In January 2016, the FASB issued updated authoritative guidance related to classification and measurement of Financial Instruments. The amendments modify the accounting and presentation for certain financial liabilities and equity investments not consolidated or reported using the equity method. The guidance is effective for us beginning January 1, 2019; limited early adoption is permitted. We are currently evaluating the potential impact of this new guidance.