AGL RESOURCES INC Form 10-K Annual Report Filed 2014-02-06

We are required 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.

Additionally, 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, 2013, we did not have a liability recorded for payment of interest and penalties associated with uncertain tax positions.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to risks associated with natural gas prices, interest rates, credit and fuel prices. Natural gas price risk results from changes in the fair value of natural gas. Interest rate risk is caused by fluctuations in interest rates related to our portfolio of debt and equity instruments that we issue to provide financing and liquidity for our business. Credit risk results from the extension of credit throughout all aspects of our business but is particularly concentrated at Atlanta Gas Light in distribution operations and in wholesale services. Fuel price risk, primarily in our cargo shipping segment, is a product of the fluctuation in fuel prices; however, this risk is partially reduced through fuel surcharges. With the exception of fuel price risk in our cargo shipping segment, we use derivative instruments to manage these risks. Our use of derivative instruments is governed by a risk management policy, approved and monitored by our Risk Management Committee (RMC), which prohibits the use of derivatives for speculative purposes.

Our RMC is responsible for establishing the overall risk management policies and monitoring compliance with, and adherence to, the terms within these policies, including approval and authorization levels and delegation of these levels. Our RMC consists of members of senior management who monitor open natural gas price risk positions and other types of risk, corporate exposures, credit exposures and overall results of our risk management activities. It is chaired by our chief risk officer, who is responsible for ensuring that appropriate reporting mechanisms exist for the RMC to perform its monitoring functions.

Weather and Natural Gas Price Risks

Distribution Operations Our utilities, excluding Atlanta Gas Light, are authorized to use natural gas cost recovery mechanisms that allow them to adjust their rates to reflect changes in the wholesale cost of natural gas and to ensure they recover 100% of the costs incurred in purchasing gas for their customers. Since Atlanta Gas Light does not sell natural gas directly to its end-use customers, it has no natural gas price risk.

Nicor Gas and Elizabethtown Gas enter into derivative instruments to hedge the impact of market fluctuations in natural gas prices for customers. These derivatives are reflected at fair value and are not designated as hedges. Realized gains or losses on such instruments are included in the cost of gas delivered and are passed through directly to customers and therefore have no direct impact on earnings. Realized and unrealized changes in the fair value of these derivative instruments are deferred as regulatory assets or liabilities until recovered from or credited to our customers.

For our Illinois weather risk associated with Nicor Gas, we implemented a corporate weather hedging program in the second quarter of 2013 that utilizes OTC weather derivatives to reduce the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather. For more information, see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Natural gas price volatility” and the subheading “Hedges” and Note 2 to the consolidated financial statements under Item 8 herein.

Glossary

Table of Contents

Retail Operations and Wholesale Services We routinely utilize various types of derivative instruments to mitigate certain natural gas price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and OTC energy contracts, such as forward contracts, futures contracts, options contracts and swap agreements. Retail operations and wholesale services also actively manage storage positions through a variety of hedging transactions for the purpose of managing exposures arising from changing natural gas prices. These hedging instruments are used to substantially lock in economic margins (as spreads between wholesale and retail natural gas prices widen between periods) and thereby minimize our exposure to declining operating margins.

Midstream Operations We use derivative instruments to reduce our exposure to the risk of changes in the price of natural gas that will be purchased in future periods for pad gas, conditioning gas and additional volumes of gas used to de-water our caverns (de-water gas) during the construction of storage facilities. Pad gas includes volumes of non-working natural gas used to maintain the operational integrity of the caverns. Conditioning gas is used to ready a field for use and will be sold in connection with placing the storage facility into service. De-water gas is used to remove water from the cavern in anticipation of commercial service and will be sold after completion of de-watering. We also use derivative instruments for asset optimization purposes.

Consolidated The following tables include the fair values and average values of our consolidated derivative instruments as of the dates indicated. We base the average values on monthly averages for the 12 months ended December 31, 2013 and 2012.

	Derivative instruments average values (1) at December 31,
In millions	2013		2012
Asset	$	107	$	208
Liability		49		101

(1)	Excludes cash collateral amounts.

	Derivative instruments fair values netted with cash collateral at December 31,
In millions	2013		2012
Asset	$	119	$	144
Liability		80		39

The following table illustrates the change in the net fair value of our derivative instruments during the 12 months ended December 31, 2013, 2012 and 2011, and provides detail of the net fair value of contracts outstanding as of December 31, 2013, 2012 and 2011.

In millions	2013			2012			2011
Net fair value of derivative instruments outstanding at beginning of period	$	36		$	31		$	55
Derivative instruments realized or otherwise settled during period		(62	)		(61	)		(74	)
Net fair value of derivative instruments acquired during period		-			-			(5	)
Change in net fair value of derivative instruments		(56	)		66			55
Net fair value of derivative instruments outstanding at end of period		(82	)		36			31
Netting of cash collateral		121			69			147
Cash collateral and net fair value of derivative instruments outstanding at end of period (1)	$	39		$	105		$	178

(1)	Net fair value of derivative instruments outstanding includes $3 million premium and associated intrinsic value at December 31, 2013, $4 million at December 31, 2012 and $3 million at December 31, 2011 associated with weather derivatives.

The sources of our net fair value at December 31, 2013 are as follows.

In millions	Prices actively quoted (Level 1) (1)			Significant other observable inputs (Level 2) (2)
Mature through 2014	$	(43	)	$	(26	)
Mature 2015 - 2016		(26	)		15
Mature 2017 - 2018		(2	)		-
Total derivative instruments (3)	$	(71	)	$	(11	)

(1)	Valued using NYMEX futures prices.

(2)	Valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers.

(3)	Excludes cash collateral amounts.

VaR Our VaR may not be comparable to that of other entities due to differences in the factors used to calculate VaR. Our VaR is determined on a 95% confidence interval and a 1-day holding period, which means that 95% of the time, the risk of loss in a day from a portfolio of positions is expected to be less than or equal to the amount of VaR calculated. Our open exposure is managed in accordance with established policies that limit market risk and require daily reporting of potential financial exposure to senior management, including the chief risk officer. Because we generally manage physical gas assets and economically protect our positions by hedging in the futures markets, our open exposure is generally mitigated. We employ daily risk testing, using both VaR and stress testing, to evaluate the risks of our open positions.

Glossary

Table of Contents

We actively monitor open commodity positions and the resulting VaR. We also continue to maintain a relatively matched book, where our total buy volume is close to our sell volume, with minimal open natural gas price risk. Based on a 95% confidence interval and employing a 1-day holding period, SouthStar’s portfolio of positions for the 12 months ended December 31, 2013, 2012 and 2011 were less than $0.1 million and Sequent had the following VaRs.

In millions	2013		2012		2011
Period end	$	4.7	$	1.8	$	2.2
12-month average		2.3		2.0		1.6
High		4.9		4.8		3.1
Low		1.2		1.1		0.8

Fuel Price Risk

Cargo Shipping Tropical Shipping’s objective is to reduce its exposure to higher fuel costs through fuel surcharges. However, these fuel surcharges do not remove our entire risk in periods of increasing fuel prices and volatility, or increased competition, and any relief may not be realized in the same period as the cost incurred. An increase of 10% in Tropical Shipping’s average cost per gallon for vessel fuel results in approximately $6 million of additional annual fuel expense. Fuel surcharges would be implemented to reduce the impact of the increased fuel expense.

Interest Rate Risk

Interest rate fluctuations expose our variable-rate debt to changes in interest expense and cash flows. Our policy is to manage interest expense using a combination of fixed-rate and variable-rate debt. Based on $1.4 billion of variable-rate debt outstanding at December 31, 2013, a 100 basis point change in market interest rates would have resulted in an increase in pre-tax interest expense of $14 million on an annualized basis.

We utilize interest rate swaps to help us achieve our desired mix of variable to fixed-rate debt. Our variable rate debt target generally ranges from 20% to 45% of total debt. We also may use forward-starting interest rate swaps and interest rate lock agreements to lock in fixed interest rates on our forecasted issuances of debt. The objective of these hedges is to offset the variability of future payments associated with the interest rate on debt instruments we expect to issue. The gain or loss on the interest rate swaps designated as cash flow hedges is generally deferred in accumulated OCI until settlement, at which point it is amortized to interest expense over the life of the related debt. For additional information, see Note 5 to our consolidated financial statements under Item 8 herein.

In April 2013, we entered into two ten-year, $50 million fixed-rate forward-starting interest rate swaps to hedge any potential interest rate volatility prior to our issuance of senior notes in the second quarter 2013. The average interest rate on these swaps was 1.98%. Including $200 million of ten-year, 1.78% fixed-rate forward-starting interest rate swaps that were executed in December 2012, we had fixed-rate swaps totaling $300 million in notional value at an average interest rate of 1.85%. We designated the forward-starting interest rate swaps as cash flow hedges of our second quarter 2013 senior note issuance. The interest rate swaps were settled in May 2013, at which time we received $6 million in proceeds. The $6 million will be amortized to reduce interest expense over the first ten years of the 30-year senior notes.

Credit Risk

Distribution Operations Atlanta Gas Light has a concentration of credit risk, as it bills 12 certificated and active Marketers in Georgia for its services. The credit risk exposure to Marketers varies with the time of year, with exposure at its lowest in the nonpeak summer months and highest in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. These retail functions include customer service, billing, collections, and the purchase and sale of the natural gas commodity. The provisions of Atlanta Gas Light’s tariff allow Atlanta Gas Light to obtain security support in an amount equal to a minimum of two times a Marketer’s highest month’s estimated bill from Atlanta Gas Light. For 2013, the four largest Marketers based on customer count accounted for approximately 16% of our consolidated operating margin and 21% of distribution operations’ operating margin.

Several factors are designed to mitigate our risks from the increased concentration of credit that has resulted from deregulation. In addition to the security support described above, Atlanta Gas Light bills intrastate delivery service to Marketers in advance rather than in arrears. We accept credit support in the form of cash deposits, letters of credit/surety bonds from acceptable issuers and corporate guarantees from investment-grade entities. The RMC reviews on a monthly basis the adequacy of credit support coverage, credit rating profiles of credit support providers and payment status of each Marketer. We believe that adequate policies and procedures have been put in place to properly quantify, manage and report on Atlanta Gas Light’s credit risk exposure to Marketers.

Glossary

Table of Contents

Atlanta Gas Light also faces potential credit risk in connection with assignments of interstate pipeline transportation and storage capacity to Marketers. Although Atlanta Gas Light assigns this capacity to Marketers, in the event that a Marketer fails to pay the interstate pipelines for the capacity, the interstate pipelines would in all likelihood seek repayment from Atlanta Gas Light.

Our gas distribution businesses offer options to help customers manage their bills, such as energy assistance programs for low-income customers and a budget payment plan that spreads gas bills more evenly throughout the year. Customer credit risk has been substantially mitigated at Nicor Gas by the bad debt rider approved by the Illinois Commission on February 2, 2010, which 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 Virginia Natural Gas and Chattanooga Gas, we are allowed to recover the gas portion of bad debt write-offs through their gas recovery mechanisms.

Nicor Gas faces potential credit risk in connection with its natural gas sales and procurement activities to the extent a counterparty defaults on a contract to pay for or deliver at agreed-upon terms and conditions. To manage this risk, Nicor Gas maintains credit policies to determine and monitor the creditworthiness of its counterparties. In doing so, Nicor Gas seeks guarantees or collateral, in the form of cash or letters of credit, which limits its exposure to any individual counterparty and enters into netting arrangements to mitigate counterparty credit risk.

Certain of our derivative instruments contain credit-risk-related or other contingent features that could increase the payments for collateral we post in the normal course of business when our financial instruments are in net liability positions. As of December 31, 2013, for agreements with such features, our distribution operations derivative instruments with liability fair values totaled $2 million, for which we had posted no collateral to our counterparties.

Retail Operations We obtain credit scores for our firm residential and small commercial customers using a national credit reporting agency, enrolling only those customers that meet or exceed our credit threshold. We consider potential interruptible and large commercial customers based on reviews of publicly available financial statements and commercially available credit reports. Prior to entering into a physical transaction, we also assign physical wholesale counterparties an internal credit rating and credit limit based on the counterparties’ Moody’s, S&P and Fitch ratings, commercially available credit reports and audited financial statements.

Wholesale Services We have established credit policies to determine and monitor the creditworthiness of counterparties, as well as the quality of pledged collateral. We also utilize master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When we are engaged in more than one outstanding derivative transaction with the same counterparty and we also have 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. We also use other netting agreements with certain counterparties with whom we conduct significant transactions. Master netting agreements enable us to net certain assets and liabilities by counterparty. We also net across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions.

Additionally, we may require counterparties to pledge additional collateral when deemed necessary. We conduct credit evaluations and obtain appropriate internal approvals for a counterparty’s line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody’s and BBB- from S&P. Generally, we require credit enhancements by way of guaranty, cash deposit or letter of credit for transaction counterparties that do not have investment grade ratings.

We have a concentration of credit risk as measured by our 30-day receivable exposure plus forward exposure. As of December 31, 2013, excluding $8 million of customer deposits, our top 20 counterparties represented approximately 51% of the total counterparty exposure of $542 million.

As of December 31, 2013, our counterparties, or the counterparties’ guarantors, had a weighted average S&P equivalent credit rating of A-, which is consistent with the prior year. The S&P equivalent credit rating is determined by a process of converting the lower of the S&P or Moody’s ratings 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 D or 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 the financial ratios of that counterparty. To arrive at the weighted average credit rating, each counterparty is assigned an internal ratio, which is multiplied by their credit exposure and summed for all counterparties. The sum is divided by the aggregate total counterparties’ exposures, and this numeric value is then converted to an S&P equivalent. The following table shows our third-party natural gas contracts receivable and payable positions.

Glossary

Table of Contents

	As of December 31,
	Gross receivables				Gross payables
In millions	2013		2012		2013		2012
Netting agreements in place:
Counterparty is investment grade	$	496	$	485	$	265	$	282
Counterparty is non-investment grade		-		9		10		13
Counterparty has no external rating		260		175		393		315
No netting agreements in place:
Counterparty is investment grade		29		7		2		1
Counterparty has no external rating		1		1		1		-
Amount recorded on Consolidated Statements of Financial Position	$	786	$	677	$	671	$	611

We have certain 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, we would need to post collateral to continue transacting business with some of our counterparties. If such collateral were not posted, our ability to continue transacting business with these counterparties would be impaired. If our credit ratings had been downgraded to non-investment grade status, the required amounts to satisfy potential collateral demands under such agreements with our counterparties would have totaled $9 million at December 31, 2013, which would not have a material impact to our consolidated results of operations, cash flows or financial condition.

Glossary

Table of Contents

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of AGL Resources Inc.:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of AGL Resources Inc. and its subsidiaries at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in the Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO 1992). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Atlanta, GA

February 6, 2014

Glossary

Table of Contents

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Based on our evaluation under the framework in the Internal Control - Integrated Framework (1992) issued by COSO, our management concluded that our internal control over financial reporting was effective as of December 31, 2013, in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

The effectiveness of our internal control over financial reporting has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report appearing herein.

February 6, 2014

/s/ John W. Somerhalder II

John W. Somerhalder II

Chairman, President and Chief Executive Officer

/s/ Andrew W. Evans

Andrew W. Evans

Executive Vice President and Chief Financial Officer

Glossary

Table of Contents

AGL RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION - ASSETS

	As of December 31,
In millions	2013		2012
Current assets
Cash and cash equivalents	$	105	$	131
Short-term investments		50		58
Receivables
Energy marketing		786		677
Gas		385		362
Unbilled revenues		268		235
Other		119		89
Less allowance for uncollectible accounts		29		28
Total receivables, net		1,529		1,335
Inventories
Natural gas		637		679
Other		30		29
Total inventories		667		708
Regulatory assets		162		145
Derivative instruments		99		130
Prepaid expenses		65		141
Other		56		20
Total current assets		2,733		2,668
Long-term assets and other deferred debits
Property, plant and equipment		11,104		10,478
Less accumulated depreciation		2,323		2,131
Property, plant and equipment, net		8,781		8,347
Goodwill		1,888		1,837
Regulatory assets		737		944
Intangible assets		173		96
Long-term investments		119		136
Pension assets		117		33
Derivative instruments		20		14
Other		88		66
Total long-term assets and other deferred debits		11,923		11,473
Total assets	$	14,656	$	14,141

See Notes to Consolidated Financial Statements.

Glossary

Table of Contents

AGL RESOURCES INC. AND SUBISIDIARIES

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION - LIABILITIES AND EQUITY

	As of December 31,
In millions, except share amounts	2013			2012
Current liabilities
Short-term debt	$	1,171		$	1,377
Energy marketing trade payables		671			611
Other accounts payable - trade		432			334
Regulatory liabilities		183			161
Customer deposits and credit balances		136			143
Accrued taxes		85			53
Derivative instruments		75			33
Accrued wages and salaries		73			34
Accrued environmental remediation liabilities		70			57
Accrued interest		52			53
Accrued regulatory infrastructure program costs		5			121
Current portion of long-term debt and capital leases		-			226
Other		169			135
Total current liabilities		3,122			3,338
Long-term liabilities and other deferred credits
Long-term debt		3,813			3,327
Accumulated deferred income taxes		1,667			1,588
Regulatory liabilities		1,518			1,477
Accrued pension and retiree welfare benefits		404			508
Accrued environmental remediation liabilities		377			387
Derivative instruments		5			6
Other		74			75
Total long-term liabilities and other deferred credits		7,858			7,368
Total liabilities and other deferred credits		10,980			10,706
Commitments, guarantees and contingencies (see Note 11)
Equity
Common shareholders’ equity
Common stock, $5 par value; 750,000,000 shares authorized; outstanding: 118,888,876 shares at December 31, 2013 and 117,855,075 shares at December 31, 2012		595			590
Additional paid-in capital		2,054			2,014
Retained earnings		1,126			1,035
Accumulated other comprehensive loss		(136	)		(218	)
Treasury shares, at cost: 216,523 shares at December 31, 2013 and 2012		(8	)		(8	)
Total common shareholders’ equity		3,631			3,413
Noncontrolling interest		45			22
Total equity		3,676			3,435
Total liabilities and equity	$	14,656		$	14,141

See Notes to Consolidated Financial Statements.

Glossary

Table of Contents

AGL RESOURCES INC. AND SUBISIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

	Years ended December 31,
In millions, except per share amounts	2013			2012			2011
Operating revenues (includes revenue taxes of $112 for 2013, $86 for 2012 and $9 for 2011)	$	4,617		$	3,922		$	2,338
Operating expenses
Cost of goods sold		2,332			1,791			1,097
Operation and maintenance		999			921			501
Depreciation and amortization		418			415			186
Nicor merger expenses		-			20			57
Taxes other than income taxes		193			165			57
Total operating expenses		3,942			3,312			1,898
Gain on sale of Compass Energy		11			-			-
Operating income		686			610			440
Other income, net		17			24			7
Interest expenses, net		(181	)		(184	)		(136	)
Total other expense		(164	)		(160	)		(129	)
Earnings before income taxes		522			450			311
Income tax expenses		191			164			125
Net income		331			286			186
Less net income attributable to the noncontrolling interest		18			15			14
Net income attributable to AGL Resources Inc.	$	313		$	271		$	172
Per common share data
Basic earnings per common share attributable to AGL Resources Inc. common shareholders	$	2.65		$	2.32		$	2.14
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders	$	2.64		$	2.31		$	2.12
Cash dividends declared per common share	$	1.88		$	1.74		$	1.90
Weighted average number of common shares outstanding
Basic		117.9			117.0			80.4
Diluted		118.3			117.5			80.9

See Notes to Consolidated Financial Statements.

Glossary

Table of Contents

AGL RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Years Ended December 31,
In millions	2013			2012			2011
Net income	$	331		$	286		$	186
Other comprehensive income (loss), net of tax
Retirement benefit plans, net of tax
Actuarial gain (loss) arising during the period (net of income tax of $46, $16 and $47)		66			(17	)		(71	)
Prior service costs arising during the period (net of income tax of $1)		-			1			-
Reclassification of actuarial losses to net benefit cost (net of income tax of $10, $9 and $7)		15			13			9
Reclassification of prior service costs to net benefit cost (net of income tax of $2, $2 and $3)		(3	)		(2	)		(3	)
Retirement benefit plans, net		78			(5	)		(65	)
Cash flow hedges, net of tax
Net derivative instrument gains (losses) arising during the period (net of income tax of $1 and $2)		1			(2	)		(5	)
Reclassification of realized derivative losses to net income (net of income tax of $1, $3 and $1)		3			6			3
Cash flow hedges, net		4			4			(2	)
Other comprehensive income (loss), net of tax		82			(1	)		(67	)
Comprehensive income		413			285			119
Less comprehensive income attributable to noncontrolling interest		18			15			14
Comprehensive income attributable to AGL Resources Inc.	$	395		$	270		$	105

See Notes to Consolidated Financial Statements.

Glossary

Table of Contents

AGL RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

	AGL Resources Inc. Shareholders
	Common stock				Additional paid-in			Retained			Accumulated other comprehensive			Treasury			Noncontrolling
In millions, except per share amounts	Shares		Amount		capital			earnings			loss			shares			interest			Total
As of December 31, 2010		78.0	$	391	$	631		$	943		$	(150	)	$	(2	)	$	23		$	1,836
Net income		-		-		-			172			-			-			14			186
Other comprehensive loss		-		-		-			-			(67	)		-			-			(67	)
Dividends on common stock ($1.90 per share)		-		-		-			(148	)		-			-			-			(148	)
Distributions to noncontrolling interests		-		-		-			-			-			-			(16	)		(16	)
Stock granted, share-based compensation, net of forfeitures		-		-		(11	)		-			-			-			-			(11	)
Stock issued, dividend reinvestment plan		0.3		1		9			-			-			-			-			10
Stock issued, share-based compensation, net of forfeitures		0.5		3		20			-			-			(3	)		-			20
Purchase of treasury shares		-		-		-			-			-			(2	)		-			(2	)
Issuance of shares for Nicor merger		38.2		191		1,332			-			-			-			-			1,523
Stock-based compensation expense, net of tax		-		-		8			-			-			-			-			8
As of December 31, 2011		117.0	$	586	$	1,989		$	967		$	(217	)	$	(7	)	$	21		$	3,339
Net income		-		-		-			271			-			-			15			286
Other comprehensive loss		-		-		-			-			(1	)		-			-			(1	)
Dividends on common stock ($1.74 per share)		-		-		-			(203	)		-			-			-			(203	)
Distributions to noncontrolling interests		-		-		-			-			-			-			(14	)		(14	)
Stock granted, share-based compensation, net of forfeitures		-		-		(10	)		-			-			-			-			(10	)
Stock issued, dividend reinvestment plan		0.3		1		9			-			-			-			-			10
Stock issued, share-based compensation, net of forfeitures		0.6		3		19			-			-			(1	)		-			21
Stock-based compensation expense, net of tax		-		-		7			-			-			-			-			7
As of December 31, 2012		117.9	$	590	$	2,014		$	1,035		$	(218	)	$	(8	)	$	22		$	3,435
Net income		-		-		-			313			-			-			18			331
Other comprehensive income		-		-		-			-			82			-			-			82
Dividends on common stock ($1.88 per share)		-		-		-			(222	)		-			-			-			(222	)
Contribution from noncontrolling interest		-		-		-			-			-			-			22			22
Distributions to noncontrolling interests		-		-		-			-			-			-			(17	)		(17	)
Stock granted, share-based compensation, net of forfeitures		-		-		(6	)		-			-			-			-			(6	)
Stock issued, dividend reinvestment plan		0.3		1		10			-			-			-			-			11
Stock issued, share-based compensation, net of forfeitures		0.7		4		24			-			-			-			-			28
Stock-based compensation expense, net of tax		-		-		12			-			-			-			-			12
As of December 31, 2013		118.9	$	595	$	2,054		$	1,126		$	(136	)	$	(8	)	$	45		$	3,676

See Notes to Consolidated Financial Statements.

Glossary

Table of Contents

AGL RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years ended December 31,
In millions	2013			2012			2011
Cash flows from operating activities
Net income	$	331		$	286		$	186
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization		418			415			186
Change in derivative instrument assets and liabilities		66			72			(17	)
Deferred income taxes		(7	)		154			214
Gain on sale of Compass Energy		(11	)		-			-
Changes in certain assets and liabilities
Trade payables, other than energy marketing		92			51			(68	)
Prepaid taxes		70			37			(88	)
Accrued expenses		70			(22	)		(77	)
Inventories		41			42			158
Accrued natural gas costs		2			37			(3	)
Receivables, other than energy marketing		(80	)		19			45
Energy marketing receivables and trade payables, net		(49	)		(49	)		27
Other, net		28			(39	)		(112	)
Net cash flow provided by operating activities		971			1,003			451
Cash flows from investing activities
Acquisition of Nicor, net of cash acquired		-			-			(912	)
Expenditures for property, plant and equipment		(749	)		(782	)		(427	)
Acquisitions of assets		(154	)		-			-
Disposition of assets		19			-			-
Other, net		8			(4	)		-
Net cash flow used in investing activities		(876	)		(786	)		(1,339	)
Cash flows from financing activities
Issuances of senior notes		494			-			1,289
Benefit, dividend reinvestment and stock purchase plan		33			21			19
Contribution from noncontrolling interest		22			-			-
Payment of senior notes		(225	)		-			(300	)
Dividends paid on common shares		(222	)		(203	)		(148	)
Net (repayments) issuances of commercial paper		(206	)		56			91
Distribution to noncontrolling interest		(17	)		(14	)		(16	)
Payment of medium-term notes		-			(15	)		-
Proceeds from termination of interest rate swap		-			17			-
Proceeds from term loan facility		-			-			150
Payments of term loan facility		-			-			(150	)
Other, net		-			(17	)		(2	)
Net cash flow (used in) provided by financing activities		(121	)		(155	)		933
Net (decrease) increase in cash and cash equivalents		(26	)		62			45
Cash and cash equivalents at beginning of period		131			69			24
Cash and cash equivalents at end of period	$	105		$	131		$	69
Cash paid (received) during the period for
Interest	$	175		$	174		$	116
Income taxes		120			(37	)		12
Non cash transactions
Refinancing of gas facility revenue bonds	$	200		$	-		$	-
Merger with Nicor, common stock issued 38.2 million shares		-			-			1,523

See Notes to Consolidated Financial Statements.

Glossary

Table of Contents

Notes to Consolidated Financial Statements

Note 1 - Organization and Basis of Presentation

General

AGL Resources Inc. is an energy services holding company that conducts substantially all of its operations through its subsidiaries. Unless the context requires otherwise, references to “we,” “us,” “our,” the “company,” or “AGL Resources” mean consolidated AGL Resources Inc. and its subsidiaries.

Basis of Presentation

Our consolidated financial statements as of and for the period ended December 31, 2013 are prepared in accordance with GAAP and under the rules of the SEC. Our consolidated financial statements include our accounts, the accounts of our wholly owned subsidiaries, the accounts of our majority-owned and other controlled subsidiaries and the accounts of our variable interest entity for which we are the primary beneficiary. For unconsolidated entities that we do not control, but exercise significant influence over, we primarily use the equity method of accounting and our proportionate share of income or loss is recorded on the Consolidated Statements of Income. See Note 10 for additional information. We have eliminated intercompany profits and transactions in consolidation except for intercompany profits where recovery of such amounts are probable under the affiliates’ rate regulation process.

Certain amounts from prior periods have been reclassified and revised to conform to the current-period presentation. The reclassifications and revisions had no material impact on our prior-period balances.

During 2013, we recorded a $4 million ($2 million net of tax) reduction to our interest expense to correct the amortization period of credit fees related to the execution of the AGL Credit Facility in 2010 and its subsequent amendment in 2011.

On December 9, 2011 we closed our merger with Nicor and created a combined company with increased scale and scope in the distribution, storage and transportation of natural gas. The businesses acquired in the merger are included in our consolidated financial statements for all of 2013 and 2012, and for 22 days of 2011.

Note 2 - Significant Accounting Policies and Methods of Application

Cash and Cash Equivalents

Our cash and cash equivalents primarily consist of cash on deposit, money market accounts and certificates of deposit held by domestic subsidiaries with original maturities of three months or less. As of December 31, 2013 and 2012, we had $80 million of cash and short and long-term investments in our Consolidated Statements of Financial Position held by Tropical Shipping. These cash and investment amounts are available for use by us or our other operations only if we repatriate a portion of Tropical Shipping’s earnings in the form of a dividend, and pay a significant amount of U.S. income tax that has been previously deferred. See Note 12 for additional information on our income taxes.

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 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 Statements of Financial Position 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, 2013 and 2012, 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.

Glossary

Table of Contents

Wholesale services has a concentration of credit risk for services it provides to marketers and to utility and industrial 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. The following table provides additional information about wholesale services’ credit exposure at December 31, 2013, excluding $8 million of customer deposits.

Dollars in millions		Total (1)				# of top counterparties				Concentration risk %
Credit exposure		$	274				20				51	%

(1)	Our counterparties or the counterparties’ guarantors had a weighted average S&P equivalent rating of A- at December 31, 2013.

The weighted average credit rating is obtained by multiplying each counterparty’s assigned internal rating by its credit exposure and then summing the individual results for all counterparties. The sum is divided by the aggregate total exposure and this numeric value is then 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 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 or reluctance 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 3 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 12 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 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, our 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 the majority of the pipeline storage services that it has under contract to Marketers, along with a corresponding amount of inventory. Atlanta Gas Light also retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand. See Note 11 for information regarding a regulatory filing by Atlanta Gas Light related to gas inventory.

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, 2013, the Nicor Gas LIFO inventory balance was $168 million. Based on the average cost of gas purchased in December 2013, the estimated replacement cost of Nicor Gas’ inventory at December 31, 2013 was $402 million, which exceeded the LIFO cost by $234 million.

Glossary

Table of Contents

Our retail operations, wholesale services, and midstream operations segments carry inventory at the lower of cost or market value, 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. 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 value. For the periods presented, we recorded LOCOM adjustments to cost of goods sold in the following amounts to reduce the value of our inventories to market value.

In millions	2013		2012		2011
Retail operations	$	1	$	3	$	5
Wholesale services		8		19		31
Midstream operations		-		1		-

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 assets and liabilities. The carrying values of receivables, short and long-term investments, accounts payable, short-term debt, 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 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. 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. Our Level 3 assets, liabilities and any applicable transfers are primarily related to our pension and other retirement benefit plan assets as described in Note 3, Note 4 and Note 6. 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 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 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 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 4 for additional fair value disclosures.

Glossary

Table of Contents

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 Statements of Financial Position. 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 4 for additional information about our cash collateral.

Natural Gas and Weather Derivative Instruments The fair value of the natural gas and weather derivative instruments that we use to manage exposures arising from changing natural gas prices and 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 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 regulatory requirements, any realized gains and 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 in our Consolidated Statements of Financial Position. 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 Illinois weather risk associated with Nicor Gas, we implemented a corporate weather hedging program in the second quarter of 2013 that utilizes OTC weather derivatives to reduce the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather in Illinois. For January through April of 2014, we have purchased a put option that would partially offset lower operating margins resulting from lower customer usage in the event of warmer-than-normal weather, but would not be exercised in the event of colder-than-normal weather and, therefore, not offset higher margins if Heating Degree Days for the period are at normal or colder-than-normal levels. We will continue to use available methods to mitigate our exposure to weather in Illinois for future periods.

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 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 for accounting purposes and, accordingly, we record changes in the fair values of such instruments within cost of goods sold in 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 and do not qualify for hedge accounting designation. 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 lock in 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 lock in 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 in our Consolidated Statements of Financial Position, with changes in fair value recorded in operating revenues in our Consolidated Statements of Income in the period of change. These contracts are not designated as hedges for accounting purposes.

Glossary

Table of Contents

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 in 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 essentially 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.

Property, Plant and Equipment

A summary of our PP&E by classification as of December 31, 2013 and 2012 is provided in the following table.

In millions	2013		2012
Transportation and distribution	$	8,384	$	7,992
Storage facilities		1,170		1,149
Shipping vessels and containers		148		145
Other		854		820
Construction work in progress		548		372
Total PP&E, gross		11,104		10,478
Less accumulated depreciation		2,323		2,131
Total PP&E, net	$	8,781	$	8,347

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 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. Our natural gas utilities also hold property, primarily land; this 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, 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 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, over which we have no contractual ownership.

Glossary

Table of Contents

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.

	2013			2012			2011
Atlanta Gas Light (1)		2.6	%		2.6	%		2.6	%
Chattanooga Gas (1)		2.5	%		2.5	%		2.5	%
Elizabethtown Gas (2)		2.4	%		2.4	%		2.5	%
Elkton Gas (2)		2.4	%		2.4	%		2.4	%
Florida City Gas (2)		3.8	%		3.9	%		3.9	%
Nicor Gas (2) (3)		3.1	%		4.1	%		4.1	%
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)	On October 23, 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 2013 depreciation expense by $19 million.

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
Shipping vessels		20 - 25
Storage caverns		40 - 60
Other	up to 40

AFUDC and Capitalized Interest

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 in our Consolidated Statements of Financial Position. More information on our authorized or actual AFUDC rates is provided in the following table.

	2013			2012			2011
Atlanta Gas Light		8.10	%		8.10	%		8.10	%
Nicor Gas (1)		0.31	%		0.36	%		0.18	%
Chattanooga Gas		7.41	%		7.41	%		7.41	%
Elizabethtown Gas (1)		0.41	%		0.51	%		0.53	%
AFUDC (in millions) (2)	$	19		$	9		$	6

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

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

The capital expenditures of our other three utilities do not qualify for AFUDC treatment.

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, 2013 and 2012 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 We perform an annual goodwill impairment test on our reporting units that contain goodwill during the fourth quarter of each year, 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. To estimate the fair value of our reporting units, we use two generally accepted valuation approaches, the income approach and the market approach, using assumptions consistent with a market participant’s perspective.

Under the income approach, fair value is estimated based on the present value of estimated future cash flows discounted at an appropriate risk-free rate that takes into consideration the time value of money, inflation and the risks inherent in ownership of the business being valued. The cash flow estimates contain a degree of uncertainty, and changes in the projected cash flows could significantly increase or decrease the estimated fair value of a reporting unit. For the regulated reporting units, a fair recovery of, and return on, costs prudently incurred to serve customers is assumed. An unfavorable outcome in a rate case could cause the fair value of these reporting units to decrease. Key assumptions used in the income approach include the return on equity for the regulated reporting units, long-term growth rates used to determine terminal values at the end of the discrete forecast period, current and future rates charged for contracted capacity and a discount rate. The discount rate is applied to estimated future cash flows and is one of the most significant assumptions used to determine fair value under the income approach. As interest rates rise, the calculated fair values will decrease. The terminal growth rate is based on a combination of historical and forecasted statistics for real gross domestic product and personal income for each utility service area. The estimated rates we will charge to customers for capacity in the storage caverns were based on internal and external rate forecasts.

Glossary

Table of Contents

Under the market approach, fair value is estimated by applying multiples to forecasted cash flows. This method uses metrics from similar publicly-traded companies in the same industry, when available, to determine how much a knowledgeable investor in the marketplace would be willing to pay for an investment in a similar company.

We weight the results of the two valuation approaches to estimate the fair value of each reporting unit. Our goodwill impairment testing also develops a baseline test and performs a sensitivity analysis to calculate a reasonable valuation range. The sensitivities are derived by altering those assumptions that are subjective in nature and inherent to a discounted cash flows calculation.

The significant assumptions that drive the estimated values of our reporting units are projected cash flows, discount rates, growth rates, weighted average cost of capital (WACC) and market multiples. Due to the subjectivity of these assumptions, we cannot provide assurance that future analyses will not result in impairment, as a future impairment depends on market and economic factors affecting fair value. Our annual goodwill impairment analysis in the fourth quarter of 2013 indicated that the estimated fair values of all but one of our reporting units with goodwill were in excess of the carrying values by approximately 20% to almost 500%, and were not at risk of failing step one of the impairment test.

Within our midstream operations segment, the estimated fair value of our storage and fuels reporting unit with $14 million of goodwill, exceeded its carrying value by less than 5% and is at risk of failing the step one test. The discounted cash flow model used in the goodwill impairment test for this reporting unit assumed discrete period revenue growth through fiscal 2021 to reflect the recovery of subscription rates, stabilization of earnings and establishment of a reasonable base year off of which we estimated the terminal value. In the terminal year we assumed a long-term earnings growth rate of 2.5% that we believe is appropriate given the current economic and industry specific expectations. As of the valuation date, we utilized a WACC of 7.0%, which we believe is appropriate as it reflects the relative risk, the time value of money, and is consistent with the peer group of this reporting unit as well as the discount rate that was utilized in our 2012 annual goodwill impairment test.

The cash flow forecast for the storage and fuels reporting unit assumed earnings growth over the next eight years. Should this growth not occur, this reporting unit may fail step one of a goodwill impairment test in a future period. Along with any reductions to our cash flow forecast, changes in other key assumptions used in our 2013 annual impairment analysis may result in the requirement to proceed to step two of the goodwill impairment test in future periods.

We will continue to monitor this reporting unit for impairment and note that continued declines in capacity or subscription rates, declines for a sustained period at the current market rates or other changes to the key assumptions and factors used in this analysis may result in a future impairment of goodwill. The risk of impairment of the underlying long-lived assets is not estimated to be significant because the assets have long remaining useful lives and authoritative accounting guidance requires such assets to be tested for impairment on the basis of undiscounted cash flows over their remaining useful lives.

Changes in the amount of goodwill for the twelve months ended December 31, 2013 and 2012 are provided below.

In millions	Distribution Operations		Retail Operations			Wholesale Services			Midstream Operations			Cargo Shipping			Other			Consolidated
Goodwill - December 31, 2011	$	1,586	$	124		$	2		$	16		$	77		$	8		$	1,813
Adjustments to initial Nicor purchase price allocation and other		54		(2	)		(2	)		(2	)		(16	)		(8	)		24
Goodwill - December 31, 2012		1,640		122			-			14			61			-			1,837
2013 acquisitions		-		51			-			-			-			-			51
Goodwill - December 31, 2013	$	1,640	$	173		$	-		$	14		$	61		$	-		$	1,888

Long-Lived Assets We depreciate or amortize our long-lived assets and other intangible assets over their useful lives. Currently, 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. An 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 an 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 2013, with the exception of Sawgrass Storage, for which we recorded an $8 million loss.

Glossary

Table of Contents

Intangible Assets Our intangible assets 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. The increase in our intangible assets of $91 million as of December 31, 2013 compared to the prior year was the result of two acquisitions within the retail operations segment. For more information, see “Acquisitions” in Note 2.

	Weighted average		December 31, 2013							December 31, 2012
In millions	amortization period (in years)		Gross		Accumulated amortization			Net		Gross		Accumulated amortization			Net
Customer relationships
Retail operations		13	$	130	$	(15	)	$	115	$	53	$	(6	)	$	47
Cargo shipping		18		6		-			6		6		-			6
Trade names
Retail operations		13		45		(6	)		39		30		(2	)		28
Cargo shipping		15		15		(2	)		13		15		(1	)		14
Wholesale services		-		-		-			-		1		-			1
Total			$	196	$	(23	)	$	173	$	105	$	(9	)	$	96

Amortization expense was $14 million in 2013, $9 million in 2012 and $0 in 2011. Amortization expense for the next five years is estimated to be as follows:

In millions
2014	$	16
2015		16
2016		16
2017		15
2018		15

Accounting for Retirement Benefit Plans

We recognize the funded status of our plans as an asset or a liability on our Consolidated Statements of Financial Position, measuring the plans’ assets and obligations that determine our funded status as of the end of the fiscal year. We 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 generally defers any charge or credit 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 6. In addition, we have elected to amortize gains and losses caused by actual experience that differs 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; and 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 in our Consolidated Statements of Financial Position.

We have current and deferred income taxes in 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. We have recorded current deferred income taxes of $43 million (net of a valuation allowance of $8 million) as of December 31, 2013 and $4 million as of December 31, 2012 within other current assets in our Consolidated Statements of Financial Position.

Glossary

Table of Contents

Accumulated Deferred Income Tax Assets and Liabilities As 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.

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. We had $80 million of such cash and short-term investments on our Consolidated Statements of Financial Position as of December 31, 2013 and 2012. As of December 31, 2013, we would be required to record a deferred tax liability of $31 million if we no longer asserted indefinite reinvestment of undistributed foreign earnings.

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 uncertain tax position 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 on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement.

Uncertain Tax Positions We recognize accrued interest related to uncertain tax positions in interest expense and penalties in operating expense in 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 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 expenses and record the corresponding customer charges as operating revenues.

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 commissions 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 (SFV) 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 SFV charges.

All of our utilities, with the exception of Atlanta Gas Light, have rate structures that include volumetric rate designs which allow recovery of 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, 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. These are included in the Consolidated Statements of Financial Position as unbilled revenue. 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 purpose of a WNA is to mitigate 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 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 to customers, which for some taxes includes a small administrative fee, as operating revenues, and to record the related taxes incurred as operating expenses in 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 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 $110 million in 2013, $85 million in 2012 and $9 million in 2011.

Glossary

Table of Contents

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, 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. The related receivables are included in the Consolidated Statements of Financial Position as unbilled revenue. 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 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 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.

Cargo shipping Revenues 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

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 in the Consolidated Statements of Financial Position and exclude from, or include in, 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 3.

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 and costs associated with the installation of heating and cooling equipment are recorded to cost of goods sold.

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 Note 11.

Glossary

Table of Contents

Other income

Our other income is detailed in the following table. For more information on our equity investment income, see Note 10.

In millions	2013		2012		2011
AFUDC - equity	$	13	$	6	$	4
Equity investment income		3		13		1
Other, net		1		5		2
Total other income	$	17	$	24	$	7

Earnings Per Common Share

We compute basic earnings per common share attributable to AGL Resources Inc. common shareholders by dividing our net 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 occurs when potentially dilutive common shares are added to common shares outstanding. The increase in weighted average shares in 2012 compared to 2011 is primarily due to the issuance of 38.2 million shares in connection with the Nicor merger on December 9, 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 certain shares of the restricted stock and restricted stock units depends on the satisfaction of defined performance 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.

The following table shows the calculation of our diluted shares attributable to AGL Resources Inc. common shareholders for the periods presented, if performance 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)	2013		2012		2011
Net income attributable to AGL Resources Inc.	$	313	$	271	$	172
Denominator:
Basic weighted average number of shares outstanding (1)		117.9		117.0		80.4
Effect of dilutive securities		0.4		0.5		0.5
Diluted weighted average number of shares outstanding (2)		118.3		117.5		80.9

Earnings per share
Basic	$	2.65	$	2.32	$	2.14
Diluted (2)	$	2.64	$	2.31	$	2.12
(1) Daily weighted average shares outstanding.
(2) There were no outstanding stock options excluded from the computation of diluted earnings per common share attributable to AGL Resources Inc. for any of the periods presented because their effect would have been anti-dilutive, as the exercise prices were greater than the average market price.

Acquisitions

On January 31, 2013, our retail operations segment acquired approximately 500,000 service contracts and certain other assets from NiSource Inc. for $122 million. These service contracts provide home warranty protection solutions and energy efficiency leasing solutions to residential and small business utility customers and complement the retail business acquired in the Nicor merger. Intangible assets related to this acquisition are primarily customer relationships of $46 million and trade names of $16 million. The amortization periods are estimated to be 14 years for customer relationships and 10 years for trade names. The final allocation of the purchase price to the fair value of assets acquired and liabilities assumed is presented in the following table:

In millions
Current assets	$	3
PP&E		12
Goodwill		51
Intangible assets		62
Current liabilities		(6	)
Total purchase price	$	122

On June 30, 2013, our retail operations segment acquired approximately 33,000 residential and commercial energy customer relationships in Illinois for $32 million. These customer relationships have been recorded as an intangible asset and are expected to be amortized on a straight-line basis over an estimated period of 14 to 16 years.

On December 9, 2011, we completed our $2.5 billion merger with Nicor that created a combined company with increased scale and scope in the distribution, storage and transportation of natural gas. The effects of Nicor’s results of operations and financial condition are reflected for the twelve months ended December 31, 2013 and 2012, while our 2011 results include activity from December 10, 2011 through December 31, 2011. This merger resulted in:

·	The issuance of 38.2 million shares of AGL Resources common stock

·	Increased revenues in 2012 of $2,063 million

·	Increased net income in 2012 of $70 million

·	An increase to PP&E of $3,192 million

·	An increase to goodwill and other intangible assets of $1,423 million and $103 million, respectively

Glossary

Table of Contents

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 are 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 will be determined and would be received from the buyer annually over a five-year earn out period based upon the financial performance of Compass Energy.

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 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. 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 Statements of Financial Position, we recognize 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 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 Inc.

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 Statements of Financial Position, 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 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. 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 our rate-regulated subsidiaries, regulatory infrastructure program accruals, uncollectible accounts and other allowances for contingent losses, goodwill and 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

On January 1, 2013, we adopted ASU 2011-11, Disclosures about Offsetting Assets and Liabilities and ASU 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which require disclosures about offsetting and related arrangements in order to help financial statement users better understand the effect of those arrangements on our financial position. This guidance had no impact on our consolidated financial statements. See Note 4 for additional disclosures about our offsetting of derivative assets and liabilities.

On January 1, 2013, we adopted ASU 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, which requires enhanced disclosures of amounts reclassified out of accumulated other comprehensive income by component. This guidance had no impact on our consolidated financial statements. See Note 9 for additional disclosures relating to accumulated other comprehensive income.

Glossary

Table of Contents

Note 3 – 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 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 estimated 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 as of December 31, are summarized in the following table.

In millions	2013		2012
Regulatory assets
Recoverable regulatory infrastructure program costs	$	48	$	47
Recoverable ERC		45		38
Recoverable pension and retiree welfare benefit costs		9		19
Other		60		41
Total regulatory assets - current		162		145
Recoverable ERC		433		438
Recoverable pension and retiree welfare benefit costs		99		196
Recoverable regulatory infrastructure program costs		87		167
Long-term debt fair value adjustment		82		90
Other		36		53
Total regulatory assets - long-term		737		944
Total regulatory assets	$	899	$	1,089
Regulatory liabilities
Accrued natural gas costs	$	92	$	93
Bad debt over collection		41		37
Accumulated removal costs		27		16
Other		23		15
Total regulatory liabilities - current		183		161
Accumulated removal costs		1,445		1,393
Regulatory income tax liability		27		27
Unamortized investment tax credit		26		29
Bad debt over collection		17		17
Other		3		11
Total regulatory liabilities - long-term		1,518		1,477
Total regulatory liabilities	$	1,701	$	1,638

Our regulatory assets are probable of recovery. 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 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 or proceeding. 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 used to periodically set base rates.

Glossary

Table of Contents

The majority of our regulatory assets and liabilities listed in the preceding table are included in base rates except for the regulatory infrastructure program costs, ERC, bad debt, natural gas and energy efficiency 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 provide a return of investment and expense including short-term interest on reconciliation balances. However, there is no interest associated with the under or over collections of bad debt expense.

Nicor Gas’ pension and retiree welfare benefit costs have historically been considered in rate proceedings in the same period they are accrued under GAAP. As a regulated utility, Nicor Gas expects to continue rate recovery of the eligible costs of these defined benefit retirement plans and, accordingly, associated changes in the funded status of Nicor Gas’ plans have been deferred as a regulatory asset or liability until recognized in net income, instead of being recognized in OCI. The Illinois Commission presently does not allow Nicor Gas the opportunity to earn a return on its recoverable retirement benefit costs. Such costs are expected to be recovered over a period of 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 We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. Our ERC liabilities are estimates of future remediation costs for investigation and cleanup of our former operating sites that are contaminated. Our estimates are based on conventional engineering estimates and the use of probabilistic models of potential costs when such estimates cannot be made, on an undiscounted basis. As cleanup options and plans mature and cleanup contracts are entered into, we are increasingly able to provide conventional engineering estimates of the likely costs of many elements of the remediation program. These estimates contain various engineering assumptions, which we refine and update on an ongoing basis. These liabilities do not include other potential expenses, such as unasserted property damage claims, personal injury or natural resource damage claims, legal expenses or other costs for which we may be held liable but for which we cannot reasonably estimate an amount.

Our accrued ERC costs are not regulatory liabilities; however they are deferred as a corresponding regulatory asset until the costs are recovered from customers. These recoverable ERC assets are a combination of accrued ERC liabilities and recoverable cash expenditures for investigation and cleanup costs. We primarily recover these deferred costs through three rate riders that authorize dollar-for-dollar recovery. We expect to collect $45 million in revenues over the next 12 months, which is reflected as a current regulatory asset. We recovered $24 million in 2013, $13 million in 2012 and $5 million in 2011 from our ERC rate riders. The following table provides more information on the costs related to remediation of our former operating sites.

In millions	# of sites		Probabilistic model cost estimates (2)		Engineering estimates (2)		Amount recorded		Expected costs over next 12 months		Cost recovery period
Illinois (1)		24	$	209 - $458	$	42	$	251	$	38	As incurred (3)
New Jersey		6		139 - 233		6		145		18	7 years (3)
Georgia and Florida		13		28 - 112		8		40		7	5 years
North Carolina		1		n/a		11		11		7	No recovery
Total		44	$	376 - $803	$	67	$	447	$	70

(1)	Nicor Gas and Commonwealth Edison Company are parties to an agreement to cooperate equally in cleaning up residue at 23 sites.

(2)	Material cleanups have not been completed for 26 sites. Therefore precise estimates are not available for future cleanup costs and considerable variability remains in future cost estimates.

(3)	Includes recovery of carrying costs on unrecovered expenditures.

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 a benchmark bad debt expense of $63 million, as determined by the Illinois Commission in February 2010. The over recovery is recorded as an increase to operating expenses on our Consolidated Statements of Income and a regulatory liability on our Consolidated Statements of Financial Position until refunded to customers. In the period refunded, operating expenses are reduced and the regulatory liability is reversed. The actual bad debt experience and resulting refunds are shown in the following table.

	Bad debt		Total		Amount refunded in				Amount to be refunded in
In millions	experience		refund		2012		2013		2014		2015
2013	$	21	$	42	$	-	$	-	$	25	$	17
2012		23		40		-		24		16		-
2011		31		32		19		13		-		-

Accumulated Removal Costs In accordance with regulatory treatment, our depreciation rates are comprised of two cost components - historical cost and the estimated cost of removal, net of estimated salvage, 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 are not a generally accepted component of depreciation, but meet the requirements of authoritative guidance related to regulated operations, we have reclassified them from accumulated depreciation to the accumulated removal cost regulatory liability in our Consolidated Statements of Financial Position. In the rate setting process, the liability for these accumulated removal costs is treated as a reduction to the net rate base upon which our regulated utilities have the opportunity to earn their allowed rate of return.

Glossary

Table of Contents

Regulatory Infrastructure Programs We have infrastructure improvement programs at several of our utilities. Descriptions of these are as follows.

Atlanta Gas Light 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.

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: (i) the revenues recognized to date that have not yet been recovered from customers through the rate riders, and (ii) the future expected costs to be recovered through the base rates.

Atlanta Gas Light has recorded a current regulatory asset of $48 million, which represents the amount of recognized revenues expected to be collected from customers over the next 12 months. Atlanta Gas Light has also recorded a non-current asset of $87 million, which represents the expected future collection of revenues already recognized. The amounts recovered from the pipeline replacement revenue rider during the last three years were:

·	$49 million in 2013

·	$51 million in 2012

·	$48 million in 2011

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.

Our STRIDE program is comprised of the Integrated System Reinforcement Program (i-SRP), the Integrated Customer Growth Program (i-CGP), the pipeline replacement program that ended in 2013, and a new component, the Integrated Vintage Plastic Replacement Program (i-VPR). The purpose of the i-SRP is to upgrade our distribution system and liquefied natural gas facilities in Georgia, improve our peak-day system reliability and operational flexibility, and create a platform to meet long-term forecasted growth. Our i-CGP authorizes Atlanta Gas Light to extend its pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia. All related costs will be recovered through a surcharge. The STRIDE program requires us to file an updated ten-year forecast of infrastructure requirements under i-SRP along with a new construction plan every three years for review and approval by the Georgia Commission.

The purpose of the i-VPR program is to replace aging plastic pipe that was installed primarily in the mid-1960’s to the early 1980’s. We have identified approximately 3,300 miles of vintage plastic mains in our system that potentially should be considered for replacement over the next 15 - 20 years as it reaches the end of its useful life. On August 6, 2013, the Georgia Commission approved the replacement of 756 miles of vintage plastic pipe over four years at an estimated cost of $275 million. Additional reporting requirements and monitoring by the staff of the Georgia Commission were also included in the stipulation, which authorized a phased-in approach to funding the program through a monthly rider surcharge of $0.48 per customer through December 2014. This will be increased to $0.96 beginning in January 2015 and to $1.45 beginning in January 2016 and will continue through 2025.

Elizabethtown Gas In 2009, the New Jersey BPU approved the 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 that are approved by the New Jersey BPU. In August 2013, the New Jersey BPU approved the recovery of investments under this program through a permanent adjustment to base rates.

Glossary

Table of Contents

Additionally, in August 2013, we received approval from the New Jersey BPU for an extension of the accelerated infrastructure replacement program that we filed in July 2012. The approval allows for infrastructure investment of $115 million over four years, effective as of September 1, 2013. Carrying charges on the additional capital expenditures will be deferred at a weighted average cost for capital of 6.65%. Unlike the previous program, there will be no adjustment to base rates for the investments under the extended program until Elizabethtown Gas files its next rate case. We agreed to file a general rate case by September 2016.

On September 3, 2013, Elizabethtown Gas filed for a Natural Gas Distribution Utility Reinforcement Effort (ENDURE), a program that will improve our distribution system’s resiliency against coastal storms and floods. Under the proposed plan, Elizabethtown Gas will invest $15 million in infrastructure and related facilities and communication planning over a one year period beginning January 2014. Elizabethtown Gas is proposing to accrue and defer carrying charges on the investment until its next rate case proceeding.

Virginia Natural Gas On June 25, 2012, the Virginia Commission approved SAVE, an accelerated infrastructure replacement program, which is expected to be completed over a five-year period. The program permits a maximum capital expenditure of $25 million per year, not to exceed $105 million in total. SAVE is subject to annual review by the Virginia Commission. We began recovering program costs through a rate rider that was effective August 1, 2012. On May 1, 2013, we filed our annual SAVE rate update detailing the first-year performance and our expected future budget, which is subject to review and approval by the Virginia Commission. The rate update was approved with minor modifications by the Virginia Commission on July 23, 2013 and became effective as of August 1, 2013. On May 1, 2013, the Virginia Commission approved our CARE plan, which includes a limited set of conservation programs and measures at a cost of $2 million over a three-year period. The CARE plan became effective June 1, 2013.

Investment Tax Credits Deferred 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 lives of the related properties as credits to income tax expense.

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. However, the amount of the reduction is transferred to our regulatory income tax liability, which we are amortizing over the lives of the related properties as the temporary differences reverse over approximately 30 years.

Other Regulatory Assets and Liabilities Our recoverable pension and retiree welfare benefit plan costs for our utilities other than Nicor Gas are expected to be recovered through base rates over the next 2 to 21 years, based on the remaining recovery periods as designated by the applicable state regulatory commissions. This category also includes recoverable seasonal rates, which 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.

In September 2013, Nicor Gas filed its second Energy Efficiency Plan, which outlines program offerings and therm reduction goals with spending of $93 million over the three-year period June 2014 through May 2017. Nicor Gas’ first Energy Efficiency Program is currently in its third year and will end in May 2014. Although there is no statutory deadline for approval of gas utility plans, Nicor Gas requested approval in the same five-month timeframe, or by March 1, 2014, as established by statute for electric utilities. The new plan must be implemented by June 1, 2014.

Glossary

Table of Contents

Note 4 - Fair Value Measurements

Retirement benefit plans

The allocations of the AGL Resources Inc. Retirement Plan (AGL Plan), the Employees’ Retirement Plan of NUI Corporation (NUI Plan), and the Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. (AGL Welfare Plan) were approximately 74% equity and 26% fixed income at December 31, 2013. The plans’ investment policies provide for some variation in these targets. The actual asset allocations of our retirement plans are presented in the following table by Level within the fair value hierarchy.

	December 31, 2013
	Pension plans (1)															Welfare plans
In millions	Level 1			Level 2			Level 3			Total			% of total			Level 1			Level 2			Level 3			Total			% of total
Cash	$	3		$	1		$	-		$	4			-	%	$	1		$	-		$	-		$	1			1	%
Equity securities:
U.S. large cap (2)		93			205			-			298			33	%		-			52			-			52			62	%
U.S. small cap (2)		72			29			-			101			11	%		-			-			-			-			-	%
International companies (3)		-			139			-			139			15	%		-			14			-			14			17	%
Emerging markets (4)		-			34			-			34			4	%		-			-			-			-			-	%
Fixed income securities:
Corporate bonds (5)		-			207			-			207			23	%		-			17			-			17			20	%
Other (or gov’t/muni bonds)		-			29			-			29			3	%		-			-			-			-			-	%
Other types of investments:
Global hedged equity (6)		-			-			43			43			5	%		-			-			-			-			-	%
Absolute return (7)		-			-			39			39			4	%		-			-			-			-			-	%
Private capital (8)		-			-			22			22			2	%		-			-			-			-			-	%
Total assets at fair value	$	168		$	644		$	104		$	916			100	%	$	1		$	83		$	-		$	84			100	%
% of fair value hierarchy		19	%		70	%		11	%		100	%					1	%		99	%		-	%		100	%

	December 31, 2012
	Pension plans (1)															Welfare plans
In millions	Level 1			Level 2			Level 3			Total			% of total			Level 1			Level 2			Level 3			Total			% of total
Cash	$	14		$	2		$	-		$	16			2	%	$	1		$	-		$	-		$	1			1	%
Equity securities
U.S. large cap (2)		69			181			-			250			30	%		-			38			-			38			55	%
U.S. small cap (2)		60			22			-			82			10	%		-			-			-			-			-	%
International companies (3)		-			120			-			120			14	%		-			12			-			12			18	%
Emerging markets (4)		-			34			-			34			4	%		-			-			-			-			-	%
Fixed income securities:
Corporate bonds (5)		-			216			-			216			26	%		-			18			-			18			26	%
Other (or gov’t/muni bonds)		-			30			-			30			3	%		-			-			-			-			-	%
Other types of investments:
Global hedged equity (6)		-			-			38			38			4	%		-			-			-			-			-	%
Absolute return (7)		-			-			36			36			4	%		-			-			-			-			-	%
Private capital (8)		-			-			23			23			3	%		-			-			-			-			-	%
Total assets at fair value	$	143		$	605		$	97		$	845			100	%	$	1		$	68		$	-		$	69			100	%
% of fair value hierarchy		17	%		72	%		11	%		100	%					1	%		99	%		-	%		100	%

(1)	Includes $9 million at December 31, 2013 and $8 million at December 31, 2012 of medical benefit (health and welfare) component for 401h accounts to fund a portion of the other retirement benefits.

(2)	Includes funds that invest primarily in U.S. common stocks.

(3)	Includes funds that invest primarily in foreign equity and equity-related securities.

(4)	Includes funds that invest primarily in common stocks of emerging markets.

(5)	Includes funds that invest primarily in investment grade debt and fixed income securities.

(6)	Includes funds that invest in limited / general partnerships, managed accounts, and other investment entities issued by non-traditional firms or “hedge funds.”

(7)	Includes funds that invest primarily in investment vehicles and commodity pools as a “fund of funds.”

(8)

Includes funds that invest in private equity and small buyout funds, partnership investments, direct investments, secondary investments, directly / indirectly in real estate and may invest in equity securities of real estate related companies, real estate mortgage loans, and real-estate mezzanine loans.

Glossary

Table of Contents

The following is a reconciliation of our retirement plan assets in Level 3 of the fair value hierarchy.

	Fair value measurements using significant unobservable inputs - Level 3 (1)
In millions	Global hedged equity			Absolute return		Private capital			Total

Balance at December 31, 2011	$	30		$	34	$	25		$	89
Gains included in changes in net assets		3			2		3			8
Purchases		15			-		-			15
Sales		(10	)		-		(5	)		(15	)
Balance at December 31, 2012	$	38		$	36	$	23		$	97
Gains included in changes in net assets		5			3		4			12
Purchases		-			-		-			-
Sales		-			-		(5	)		(5	)
Balance at December 31, 2013	$	43		$	39	$	22		$	104

(1) There were no transfers out of Level 3, or between Level 1 and Level 2 for any of the periods presented.

Derivative Instruments

The following table summarizes, by level within the fair value hierarchy, our derivative assets and liabilities that were carried at fair value on a recurring basis in our Consolidated Statements of Financial Position as of the dates presented.

	December 31, 2013					December 31, 2012
In millions	Assets (1)		Liabilities			Assets (1)		Liabilities
Natural gas derivatives
Quoted prices in active markets (Level 1)	$	6	$	(79	)	$	8	$	(45	)
Significant other observable inputs (Level 2)		67		(79	)		96		(30	)
Netting of cash collateral		43		78			33		36
Total carrying value (2) (3)	$	116	$	(80	)	$	137	$	(39	)
Interest rate derivatives
Significant other observable inputs (Level 2)	$	-	$	-		$	3	$	-

(1)	$3 million of premium at December 31, 2013 and $4 million at December 31, 2012 associated with weather derivatives have been excluded as they are accounted for based on intrinsic value.

(2)	There were no significant unobservable inputs (Level 3) for any of the periods presented.

(3)	There were no significant transfers between Level 1, Level 2, or Level 3 for any of the periods presented.

Money Market Funds

At December 31, 2013 and 2012, the fair values of our money market funds, which were recorded within short-term investments, were as follows:

In millions		2013				2012
Money market funds (1)		$	48			$	66

(1)	Carried at fair value and classified as Level 1 within the fair value hierarchy.

Debt

Our long-term debt is recorded at amortized cost, with the exception of Nicor Gas’ first mortgage bonds, which were recorded at their acquisition-date fair value. The fair value adjustment of Nicor Gas’ first mortgage bonds is being amortized over the lives of the bonds. The following table presents the carrying amount and fair value of our long-term debt as of the following dates.

Note 5 - Derivative Instruments

Derivative Instruments

Our risk management activities are monitored by our Risk Management Committee, which consists of members of senior management and is charged with reviewing and enforcing our risk management activities and policies. Our use of derivative instruments, including physical transactions, is limited to predefined risk tolerances associated with pre-existing or anticipated physical natural gas sales and purchases and system use and storage. We use the following types of derivative instruments and energy-related contracts to manage natural gas price, interest rate, weather, automobile fuel price and foreign currency risks:

·	forward, futures and options contracts;

·	financial swaps;

·	treasury locks;

·	weather derivative contracts;

·	storage and transportation capacity contracts; and

·	foreign currency forward contracts

Certain of our derivative instruments contain credit-risk-related or other contingent features that could require us to post collateral in the normal course of business when our financial instruments are in net liability positions. As of December 31, 2013 and 2012 for agreements with such features, derivative instruments with liability fair values totaled $80 million and $39 million, respectively, for which we had posted no collateral to our counterparties. The maximum collateral that could be required with these features is $9 million. For more information, see “Energy Marketing Receivables and Payables” in Note 2. In addition, our energy marketing receivables and payables, which also have credit-risk-related or other contingent features, are discussed in Note 2. Our derivative instrument activities are included within operating cash flows as an adjustment to net income of $66 million, $72 million and $(17) million for the periods ended December 31, 2013, 2012 and 2011, respectively.

On April 4, 2013 we entered into two ten-year, $50 million fixed-rate forward-starting interest rate swaps to partially hedge any potential interest rate volatility prior to our issuance of the senior notes in the second quarter of 2013. The average interest rate on these swaps was 1.98%. Including existing $200 million of ten-year, 1.78% fixed-rate forward-starting interest rate swap hedges, which were executed on December 6, 2012, we had fixed-rate swaps totaling $300 million in notional value at an average interest rate of 1.85%. We designated the forward-starting interest rate swaps as cash flow hedges of our second quarter 2013 senior note issuance. The interest rate swaps were settled on May 16, 2013, the senior note issuance date, at which time we received $6 million in proceeds. The $6 million will be amortized to reduce interest expense over the first 10 years of the 30-year senior notes.

In May 2011, we entered into interest rate swaps related to the $300 million of outstanding 6.4% senior notes due in July 2016 that effectively converted $250 million from a fixed rate to a variable rate obligation. On September 6, 2012 we settled this $250 million fixed-rate to floating-rate interest rate swap.

The fair values of our interest rate swaps were reflected as a long-term derivative asset of $3 million at December 31, 2012. For more information on our debt, see Note 8.

The following table summarizes the various ways in which we account for our derivative instruments and the impact on our consolidated financial statements:

	Recognition and Measurement
Accounting Treatment	Statements of Financial Position	Income Statement
Cash flow hedge	Derivative carried at fair value	Ineffective portion of the gain or loss on the derivative instrument is recognized in earnings
	Effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated OCI (loss)	Effective portion of the gain or loss on the derivative instrument is reclassified out of accumulated OCI (loss) and into earnings when the hedged transaction affects earnings
Fair value hedge	Derivative carried at fair value Changes in fair value of the hedged item are recorded as adjustments to the carrying amount of the hedged item	Gains or losses on the derivative instrument and the hedged item are recognized in earnings. As a result, to the extent the hedge is effective, the gains or losses will offset and there is no impact on earnings. Any hedge ineffectiveness will impact earnings
Not designated as hedges	Derivative carried at fair value	Realized and unrealized gains or losses on the derivative instrument are recognized in earnings
	Distribution operations’ gains and losses on derivative instruments are deferred as regulatory assets or liabilities until included in cost of goods sold	Gains or losses on these derivative instruments are ultimately included in billings to customers and are recognized in cost of goods sold in the same period as the related revenues

Glossary

Table of Contents

Quantitative Disclosures Related to Derivative Instruments

As of the dates presented, our derivative instruments were comprised of both long and short natural gas positions. A long position is a contract to purchase natural gas, and a short position is a contract to sell natural gas. We had a net long natural gas contracts position outstanding in the following quantities:


	December 31,
In Bcf (1)	2013 (2)			2012
Hedge designation
Cash flow hedges		6			6
Not designated as hedges		183			96
Total hedges		189			102
Hedge position
Short position		(2,622	)		(1,955	)
Long position		2,811			2,057
Net long position		189			102

(1)	Volumes related to Nicor Gas exclude variable-priced contracts, which are accounted for as derivatives, but whose fair values are not directly impacted by changes in commodity prices.

(2)	Approximately 97% of these contracts have durations of two years or less and the remaining 3% expire between two and six years.

Derivative Instruments in our Consolidated Statements of Financial Position

In accordance with regulatory requirements, gains and losses on derivative instruments used at Nicor Gas and Elizabethtown Gas in our distribution operations segment to hedge natural gas purchases for customer use are reflected in accrued natural gas costs within our Consolidated Statements of Financial Position until billed to customers. The following amounts represent the net realized gains (losses) related to these natural gas cost hedges for the years ended December 31.

In millions	2013			2012
Nicor Gas	$	4		$	(35	)
Elizabethtown Gas	$	(6	)	$	(28	)

The following table presents the fair values and Consolidated Statements of Financial Position classifications of our derivative instruments:

		December 31, 2013						December 31, 2012
In millions	Classification	Assets			Liabilities			Assets			Liabilities
Designated as cash flow hedges and fair value hedges
Natural gas contracts	Current	$	3		$	(1	)	$	1		$	(2	)
Interest rate swap agreements	Current		-			-			3			-
Total			3			(1	)		4			(2	)

Not designated as cash flow hedges
Natural gas contracts	Current		691			(761	)		394			(355	)
Natural gas contracts	Long-term		206			(220	)		45			(50	)
Total			897			(981	)		439			(405	)
Gross amount of recognized assets and liabilities (1)			900			(982	)		443			(407	)
Gross amounts offset in our Consolidated Statements of Financial Position (2)			(781	)		902			(299	)		368
Net amounts of assets and liabilities presented in our Consolidated Statements of Financial Position (3)		$	119		$	(80	)	$	144		$	(39	)

(1)	The gross amounts of recognized assets and liabilities are netted within our Consolidated Statements of Financial Position to the extent that we have netting arrangements with the counterparties.

(2)

As required by the authoritative guidance related to derivatives and hedging, the gross amounts of recognized assets and liabilities above do not include cash collateral held on deposit in broker margin accounts of $121 million as of December 31, 2013 and $69 million as of December 31, 2012. Cash collateral is included in the “Gross amounts offset in our Consolidated Statements of Financial Position” line of this table.

(3)	At December 31, 2013 and 2012 we held letters of credit from counterparties that would offset, under master netting arrangements, an insignificant portion of these assets.

Glossary

Table of Contents

Derivative Instruments on the Consolidated Statements of Income

The following table presents the impacts of our derivative instruments in our Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011.

In millions	2013			2012			2011

Designated as cash flow hedges
Natural gas contracts - loss reclassified from OCI to cost of goods sold	$	(1	)	$	(5	)	$	(6	)
Interest rate swaps – gain (loss) reclassified from OCI to interest expense		(3	)		(4	)		2
Income tax benefit		1			3			1
Net of tax		(3	)		(6	)		(3	)

Not designated as hedges
Natural gas contracts - net fair value adjustments recorded in operating revenues (1)		(90	)		34			40
Natural gas contracts - net fair value adjustments recorded in cost of goods sold (2)		2			(4	)		(4	)
Income tax benefit (expense)		34			(11	)		(14	)
Net of tax		(54	)		19			22
Total (losses) gains on derivative instruments, net of tax	$	(57	)	$	13		$	19

(1)	Associated with the fair value of existing derivative instruments at December 31, 2013, 2012 and 2011.

(2)	Excludes losses recorded in cost of goods sold associated with weather derivatives of $5 million for the year ended December 31, 2013, $14 million for the year ended December 31, 2012 and $9 million for the year ended December 31, 2011.

Any amounts recognized in operating income, related to ineffectiveness or due to a forecasted transaction that is no longer expected to occur, were immaterial for the years ended December 31, 2013, 2012 and 2011.

Our expected gains to be reclassified from OCI into cost of goods sold, operation and maintenance expense, interest expense and operating revenues and recognized in our Consolidated Statements of Income over the next 12 months is $2 million. These deferred gains are related to natural gas derivative contracts associated with retail operations’ and with Nicor Gas’ system use. The expected gains are based upon the fair values of these financial instruments at December 31, 2013.

Note 6 - Employee Benefit Plans

Oversight of Plans

The Retirement Plan Investment Committee (the Committee) appointed by our Board of Directors is responsible for overseeing the investments of our defined benefit retirement plans. Further, we have an Investment Policy (the Policy) for our pension and other retirement benefit plans whose goal is to preserve these plans’ capital and maximize investment earnings in excess of inflation within acceptable levels of capital market volatility. To accomplish this goal, the plans’ assets are managed to optimize long-term return while maintaining a high standard of portfolio quality and diversification.

We will continue to diversify retirement plan investments to minimize the risk of large losses in a single asset class. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund. The Policy’s permissible investments include domestic and international equities (including convertible securities and mutual funds), domestic and international fixed income securities (corporate and government obligations), cash and cash equivalents and other suitable investments.

Equity market performance and corporate bond rates have a significant effect on our reported funded status. Changes in the projected benefit obligation (PBO) and accumulated postretirement benefit obligation (APBO) are mainly driven by the assumed discount rate. Additionally, equity market performance has a significant effect on our market-related value of plan assets (MRVPA), which is used by the AGL Plan, to determine the expected return on the plan assets component of net annual pension cost. The MRVPA is a calculated value. Gains and losses on plan assets are spread through the MRVPA based on the five-year smoothing weighted average methodology.

Pension Benefits

We sponsor the AGL Plan, which is a tax-qualified defined benefit retirement plan for our eligible employees. A defined benefit plan specifies the amount of benefits an eligible participant eventually will receive using information about the participant, including information related to the participant’s earnings history, years of service and age. In 2012, we also sponsored two other tax-qualified defined benefit retirement plans for our eligible employees, a Nicor plan and a NUI plan. Effective as of December 31, 2012, the NUI plan and the Nicor plan were merged into the AGL Plan. The participants of the former Nicor and NUI plans are now being offered their benefits, as described below, through the AGL Plan.

We generally calculate the benefits under the AGL Plan based on age, years of service and pay. The benefit formula for the AGL Plan is currently a career average earnings formula. Participants who were employees as of July 1, 2000 and who were at least 50 years of age as of that date earned benefits until December 31, 2010 under a final average pay formula. Participants who were employed as of July 1, 2000, but did not satisfy the age requirement to continue under the final average earnings formula, transitioned to the career average earnings formula on July 1, 2000.

Glossary

Table of Contents

Effective January 1, 2012, the AGL Plan was frozen with respect to participation for non-union employees hired on or after that date. Such employees are entitled to employer provided benefits under their defined contribution plan that exceed defined contribution benefits for employees who participate in the defined benefit plan.

Participants in the former Nicor plan receive noncontributory defined pension benefits. These benefits cover substantially all employees of Nicor Gas and its affiliates that adopted the Nicor plan, hired prior to 1998. Pension benefits are based on years of service and the highest average annual salary for management employees and job level for collectively bargained employees (referred to as pension bands). The benefit obligation related to collectively bargained benefits considers the past practice of regular benefit increases.

Participants in the former NUI plan included substantially all of NUI Corporation’s employees who were employed on or before December 31, 2005. Florida City Gas union employees, who until February 2008 participated in a union-sponsored multiemployer plan became eligible to participate in the AGL Plan in February 2008. The AGL Plan provides pension benefits to these participants based on years of credited service and final average compensation as of the plan freeze date. Effective December 31, 2005, participation and benefit accrual under the NUI Plan were frozen. As of January 1, 2006, former participants in that plan became eligible to participate in the AGL Plan.

Welfare Benefits

Until December 31, 2012, we sponsored two defined benefit retiree health care plans for our eligible employees, AGL Welfare Plan and the Nicor Welfare Benefit Plan (Nicor Welfare Plan). Eligibility for these benefits is based on age and years of service. Effective December 31, 2012, the Nicor Welfare Plan was terminated and as of January 1, 2013, all participants under that plan became eligible to participate in the AGL Welfare Plan. This change in plan participation eligibility did not affect the benefit terms. The Nicor Welfare Plan benefits described below are now being offered to such participants under the AGL Welfare Plan.

The AGL Welfare Plan includes medical coverage for all eligible AGL Resources employees who were employed as of June 30, 2002, if they reach the plan’s retirement age while working for us. In addition, the AGL Welfare Plan provides life insurance for all employees if they have ten years of service at retirement. The state regulatory commissions have approved phase-in plans that defer a portion of the related benefits expense for future recovery. The AGL Welfare Plan terms include a limit on the employer share of costs at limits based on the coverage tier, plan elected and salary level of the employee at retirement.

Medicare eligible retirees covered by the AGL Welfare Plan, including all of those at least age 65, receive benefits through our contribution to a retiree health reimbursement arrangement account. Additionally, on the pre-65 medical coverage of the AGL Welfare Plan our expected cost is determined by a retiree premium schedule based on salary level and years of service. Due to the cap, there is no impact on the periodic benefit cost or on our accumulated projected benefit obligation for a change in the assumed healthcare cost trend rate for this portion of the plan.

The plan provisions that are applicable to prior participants in the Nicor Welfare Plan include health care and life insurance benefits to eligible retired employees and include a limit on the employer share of cost for employees hired after 1982.

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 provides for a prescription drug benefit under Medicare Part D as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Prescription drug coverage for the Nicor Gas Medicare-eligible population changed, effective January 1, 2013, from an employer-sponsored prescription drug plan with the Retiree Drug Subsidy to an Employer Group Waiver Plan (EGWP). The EGWP replaces the employer sponsored prescription drug plan. The expected savings is estimated to be approximately 12% of total Medicare eligible liability.

We also have a separate unfunded supplemental retirement health care plan that provides health care and life insurance benefits to employees of discontinued businesses. This plan is noncontributory with defined benefits. Net plan expenses were immaterial in 2013 and 2012. The APBO associated with this plan was $2 million at December 31, 2013, and $3 million at December 31, 2012.

Assumptions

We considered a variety of factors in determining and selecting our assumptions for the discount rate at December 31. We based our discount rates separately for each plan on an above-mean yield curve provided by our actuaries that is derived from a portfolio of high quality (rated AA or better) corporate bonds with a yield higher than the regression mean curve and the equivalent annuity cash flows.

Glossary

Table of Contents

The components of our pension and welfare costs are set forth in the following table.

	Pension plans									Welfare plans
Dollars in millions	2013			2012			2011			2013			2012			2011
Service cost	$	29		$	28		$	14		$	3		$	4		$	1
Interest cost		43			44			29			14			16			6
Expected return on plan assets		(62	)		(64	)		(33	)		(6	)		(5	)		(5	)
Net amortization of prior service credit		(2	)		(2	)		(2	)		(5	)		(3	)		(4	)
Recognized actuarial loss		35			34			14			8			9			2
Net periodic benefit cost	$	43		$	40		$	22		$	14		$	21		$	-
Assumptions used to determine benefit costs
Discount rate (1)		4.2	%		4.6	%		5.4	%		4.0	%		4.5	%		5.2	%
Expected return on plan assets (1)		7.8	%		8.4	%		8.5	%		7.8	%		8.5	%		8.2	%
Rate of compensation increase (1)		3.7	%		3.7	%		3.7	%		3.8	%		3.8	%		3.7	%
Pension band increase (2)		2.0	%		2.0	%		2.0	%		n/a			n/a			n/a

(1)	Rates are presented on a weighted average basis.

(2)	Only applicable to the Nicor Gas union employees.

The following tables present details about our pension and welfare plans.

	Pension plans						Welfare plans
Dollars in millions	2013			2012			2013			2012
Change in plan assets
Fair value of plan assets, January 1,	$	837		$	754		$	77		$	67
Actual return on plan assets		134			101			16			10
Employee contributions		-			-			3			1
Employer contributions		1			42			19			17
Benefits paid		(65	)		(59	)		(23	)		(19	)
Medicare Part D reimbursements		-			-			1			1
Plan curtailment and settlements		-			(1	)		-			-
Fair value of plan assets, December 31,	$	907		$	837		$	93		$	77
Change in benefit obligation
Benefit obligation, January 1,	$	1,046		$	968		$	354		$	397
Service cost		29			28			3			4
Interest cost		43			44			14			17
Actuarial loss (gain)		(93	)		66			(26	)		(22	)
Plan amendments		-			-			-			(25	)
Medicare Part D reimbursements		-			-			1			1
Benefits paid		(65	)		(59	)		(23	)		(19	)
Employee contributions		-			-			3			1
Plan curtailment and settlements		-			(1	)		-			-
Benefit obligation, December 31,	$	960		$	1,046		$	326		$	354
Funded status at end of year	$	(53	)	$	(209	)	$	(233	)	$	(277	)
Amounts recognized in the Consolidated Statements of Financial Position consist of
Long-term asset	$	117		$	33		$	-		$	-
Current liability		(2	)		(2	)		-			(12	)
Long-term liability		(168	)		(240	)		(233	)		(265	)
Total liability at December 31,	$	(53	)	$	(209	)	$	(233	)	$	(277	)
Accumulated benefit obligation (1)	$	902		$	983			n/a			n/a
Assumptions used to determine benefit obligations
Discount rate		5.0	%		4.2	%		4.7	%		4.0	%
Rate of compensation increase		3.7	%		3.7	%		3.7	%		3.7	%
Pension band increase (2)		2.0	%		2.0	%		n/a			n/a

(1)	APBO differs from the projected benefit obligation in that the APBO excludes the effect of salary and wage increases.

(2)	Only applicable to the Nicor Gas union employees.

A portion of the net benefit cost or credit related to these plans has been capitalized as a cost of constructing gas distribution facilities and the remainder is included in operation and maintenance expense.

Assumptions used to determine the health care benefit cost for the AGL Welfare Plan were as follows:

	2013			2012
Health care cost trend rate assumed for next year		8.4	%		8.4	%
Ultimate rate to which the cost trend rate is assumed to decline		4.5	%		4.5	%
Year that reaches ultimate trend rate		2030			2030

Glossary

Table of Contents

Assumed health care cost trend rates can have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in the assumed health care cost trend rates for the AGL Welfare Plan would have the following effects:

In millions	Effect on service and interest cost		Effect on benefit obligation
1% Health care cost trend rate increase	$	-	$	15
1% Health care cost trend rate decrease		-		(13	)

As a result of a cap on expected cost for the AGL Welfare Plan, a one-percentage-point increase or decrease in the assumed health care trend does not materially affect periodic benefit cost or accumulated benefit obligation of the Plan.

The following table presents the amounts not yet reflected in net periodic benefit cost and included in net regulatory assets and accumulated OCI as of December 31, 2013 and 2012:

	Net regulatory assets					Accumulated OCI						Total
In millions	Pension plans		Welfare plans			Pension plans			Welfare plans			Pension plans			Welfare plans
December 31, 2013:
Prior service credit	$	-	$	(20	)	$	(9	)	$	-		$	(9	)	$	(20	)
Net loss		61		60			210			30			271			90
Total	$	61	$	40		$	201		$	30		$	262		$	70
December 31, 2012:
Prior service cost (credit)	$	-	$	(24	)	$	(11	)	$	(2	)	$	(11	)	$	(26	)
Net loss		146		83			324			52			470			135
Total	$	146	$	59		$	313		$	50		$	459		$	109

The 2014 estimated amortization out of regulatory assets or accumulated OCI for these plans are set forth in the following table.

	Net Regulatory Asset					Accumulated OCI					Total
In millions	Pension plans		Welfare plans			Pension plans			Welfare plans		Pension plans			Welfare plans
Amortization of prior service credit	$	-	$	(3	)	$	(2	)	$	-	$	(2	)	$	(3	)
Amortization of net loss		7		4			13			2		20			6

We recorded a regulatory asset for anticipated future cost recoveries of $108 million as of December 31, 2013 and $215 million as of December 31, 2012.

The following table presents the gross benefit payments expected for the years ended December 31, 2014 through 2023 for our pension and other retirement plans. There will be benefit payments under these plans beyond 2023.

In millions	Pension plans		Welfare plans
2014	$	56	$	20
2015		60		20
2016		63		21
2017		66		22
2018		68		23
2019-2023		366		123

Contributions

Our employees generally do not contribute to our pension and other retirement plans; however, Nicor Gas and pre-65 AGL retirees make nominal contributions to their health care plan. We fund the qualified pension plans by contributing at least the minimum amount required by applicable regulations and as recommended by our actuary. However, we may also contribute in excess of the minimum required amount. As required by The Pension Protection Act of 2006 (the Act), we calculate the minimum amount of funding using the traditional unit credit cost method.

The Act contained new funding requirements for single-employer defined benefit pension plans and established a 100% funding target (over a 7-year amortization period) for plan years beginning after December 31, 2007. In 2013 we had no required contributions to the merged AGL Plan. In 2012 we contributed a combined $40 million to the AGL Plan and the NUI Plan. No contributions were made to the Nicor Plan in 2012.

Employee Savings Plan Benefits

We sponsor defined contribution retirement benefit plans that allow eligible participants to make contributions to their accounts up to specified limits. Under these plans, our matching contributions to participant accounts were $16 million in 2013, $14 million in 2012 and $7 million in 2011.

Glossary

Table of Contents

Note 7 – Stock-Based Compensation

General

The AGL Resources Inc. Omnibus Performance Incentive Plan, as amended and restated, and the Long-Term Incentive Plan (1999) provide for the grant of incentive and nonqualified stock options, stock appreciation rights, shares of restricted stock, restricted stock units, performance cash awards and other stock-based awards to officers and key employees. Under the Omnibus Performance Incentive Plan, as of December 31, 2013, the number of shares issuable upon exercise of outstanding stock options, warrants and rights is 641,371 shares. Under the Long-Term Incentive Plan (1999) as of December 31, 2013, the number of shares issuable upon exercise of outstanding stock options, warrants and rights is 640,082 shares. The maximum number of shares available for future issuance under the Omnibus Performance Incentive Plan is 4,288,563 shares, which includes 1,697,363 shares previously available under the Nicor Inc. 2006 Long-Term Incentive Plan, as amended, pursuant to NYSE rules. No further grants will be made from the Long-Term Incentive Plan (1999) except for reload options that may be granted pursuant to the terms of certain outstanding options.

Accounting Treatment and Compensation Expense

We measure and recognize stock-based compensation expense for our stock-based awards over the requisite service period in our financial statements based on the estimated fair value at the date of grant for our stock-based awards using the modified prospective method. These stock awards include:

·	stock options;

·	stock and restricted stock awards; and

·	performance units (restricted stock units, performance share units and performance cash units).

Performance-based stock awards and performance units contain market conditions. Stock options, restricted stock awards and performance units also contain a service condition.

We estimate forfeitures over the requisite service period when recognizing compensation expense. These estimates are adjusted to the extent that actual forfeitures differ, or are expected to materially differ, from such estimates. The authoritative guidance requires excess tax benefits to be reported as a financing cash inflow. The difference between the proceeds from the exercise of our stock-based awards and the par value of the stock is recorded within additional paid-in capital.

We have granted incentive and nonqualified stock options with a strike price equal to the fair market value on the date of the grant. Fair market value is defined under the terms of the applicable plans as the closing price per share of AGL Resources common stock for the trading day immediately preceding the grant date, as reported in The Wall Street Journal. Stock options generally have a three-year vesting period.

The following table provides additional information related to our cash and stock-based compensation awards.

In millions	2013		2012		2011
Compensation costs (1)	$	22	$	9	$	14
Income tax benefits (1)		1		1		1
Excess tax benefits (2)		-		1		1

(1)	Recorded in our Consolidated Statements of Income.

(2)	Recorded in our Consolidated Statements of Financial Position.

Incentive and Nonqualified Stock Options

The stock options we granted generally expire 10 years after the date of grant. Participants realize value from option grants only to the extent that the fair market value of our common stock on the date of exercise of the option exceeds the fair market value of the common stock on the date of the grant.

As of December 31, 2013 and 2012, we had no unrecognized compensation costs related to stock options. Cash received from stock option exercises for 2013 was $21 million, and the income tax benefits from stock option exercises were immaterial. Cash received from stock option exercises for 2012 was $7 million, and the income tax benefit from stock option exercises was $1 million. The following tables summarize activity related to stock options for key employees and non-employee directors. As used in the table, intrinsic value for options means the difference between the current market value and the grant price.

Glossary

Table of Contents

Stock Options
	Number of options			Weighted average exercise price		Weighted average remaining life (in years)		Aggregate Intrinsic value (in millions)
Outstanding - December 31, 2010		2,229,112		$	34.85
Granted		1,685			42.19
Exercised		(383,646	)		31.11
Forfeited		(23,997	)		37.70
Outstanding - December 31, 2011		1,823,154		$	35.61
Granted		-			-
Exercised		(234,844	)		32.07
Forfeited		(59,720	)		37.34
Outstanding - December 31, 2012 (1)		1,528,590		$	36.09		3.7	$	6
Granted		-			-		-
Exercised		(617,358	)		35.37		2.3
Forfeited		(12,500	)		38.36		2.6
Outstanding - December 31, 2013 (1) (2)		898,732		$	36.55		3.0	$	10

(1)	All options outstanding at December 31, 2013 and 2012 were exercisable.

(2)	The range of exercise prices for the options outstanding at December 31, 2013 was $30.70 to $43.85.

We measure compensation cost related to stock options based on the fair value of these awards at their date of grant using the Black-Scholes option-pricing model. There were no options granted in 2013 and 2012, and the number of options granted in 2011 was immaterial. We use shares purchased under our 2006 share repurchase program to satisfy exercises to the extent that repurchased shares are available. Otherwise, we issue new shares from our authorized common stock.

Performance Units

In general, a performance unit is an award of the right to receive (i) an equal number of shares of our common stock, which we refer to as a restricted stock unit or (ii) cash, subject to the achievement of certain pre-established performance criteria, which we refer to as a performance cash unit. Performance units are subject to certain transfer restrictions and forfeiture upon termination of employment. The compensation cost of restricted stock unit awards is equal to the grant date fair value of the awards, recognized over the requisite service period, determined according to the authoritative guidance related to stock compensation. The compensation cost of performance cash unit awards is equal to the grant date fair value of the awards measured against progress towards the performance measure, recognized over the requisite service period. No other assumptions are used to value these awards.

Restricted Stock Units In general, a restricted stock unit is an award that represents the opportunity to receive a specified number of shares of our common stock, subject to the achievement of certain pre-established performance criteria. In 2013, we granted 43,830 restricted stock units to certain employees, all of which were outstanding as of December 31, 2013. These restricted stock units had a performance measurement period that ended December 31, 2013. The performance measure, which related to earnings before interest, income tax, depreciation and amortization, was met. As such, the related restricted stock awards will occur in 2014.

Performance Share Unit Awards A performance share unit award represents the opportunity to receive cash and shares subject to the achievement of certain pre-established performance criteria. We granted performance share unit awards to certain officers. These awards have a performance measure that relates to the Company’s relative total shareholder return relative to a group of peer companies. The recorded liability and maximum potential liability related to the 2013, 2012 and 2011 grants are as follows:

In millions	Measurement period end date	Fair value accrued at December 31, 2013		Maximum aggregate payout
Granted in 2011	December 31, 2013	$	7	$	12
Granted in 2012	December 31, 2014	$	6	$	18
Granted in 2013	December 31, 2015	$	3	$	18

Stock and Restricted Stock Awards

The compensation cost of both stock awards and restricted stock awards is equal to the grant date fair value of the awards, recognized over the requisite service period. No other assumptions are used to value the awards. We refer to restricted stock as an award of our common stock that is subject to time-based vesting or achievement of performance measures. Restricted stock awards are subject to certain transfer restrictions and forfeiture upon termination of employment.

Stock Awards - Non-Employee Directors Non-employee director compensation may be paid in shares of our common stock in connection with initial election, the annual retainer, and chair retainers, as applicable. Stock awards for non-employee directors are 100% vested and non-forfeitable as of the date of grant. During 2013 we issued 26,915 shares with a weighted average fair value of $44.04 to our non-employee directors.

Glossary

Table of Contents

Restricted Stock Awards - Employees The following table summarizes the restricted stock awards activity for our employees during the last two years.

	Shares of restricted stock			Weighted average remaining vesting period (in years)		Weighted average fair value
Outstanding - December 31, 2011 (1)		477,354				$	34.40
Issued		268,840					40.08
Forfeited		(28,829	)				39.07
Vested		(214,274	)				36.45
Outstanding - December 31, 2012 (1)		503,091			1.8	$	39.44
Issued		175,935			2.8		42.41
Forfeited		(33,352	)		2.0		40.64
Vested		(204,421	)		0.0		38.71
Outstanding - December 31, 2013 (1)		441,253			1.8	$	40.82

(1)	Subject to restriction.

Employee Stock Purchase Plan (ESPP)

We have a nonqualified, broad based ESPP for all eligible employees. As of December 31, 2013, there were 122,763 shares available for future issuance under this plan. Employees may purchase shares of our common stock in quarterly intervals at 85% of fair market value, and we record an expense for the 15% purchase price discount. Employee ESPP contributions may not exceed $25,000 per employee during any calendar year.

	2013		2012		2011
Shares purchased on the open market		103,343		108,132		65,843
Average per-share purchase price	$	42.96	$	38.96	$	40.55
Total purchase price discount	$	664,286	$	618,278	$	401,346

Glossary

Table of Contents

Note 8 - Debt and Credit Facilities

Our financing activities, including long-term and short-term debt, are subject to customary approval or review by state and federal regulatory bodies. Our wholly-owned subsidiary, AGL Capital, was established to provide for our ongoing financing needs through a commercial paper program, the issuance of various debt and hybrid securities and other financing arrangements. We fully and unconditionally guarantee all debt issued by AGL Capital. Nicor Gas is not permitted by regulation to make loans to affiliates or utilize AGL Capital for its financing needs. The following table provides maturity dates, year-to-date weighted average interest rates and amounts outstanding for our various debt securities and facilities that are included in our Consolidated Statements of Financial Position.

			December 31, 2013					December 31, 2012
Dollars in millions	Year(s) due		Weighted average interest rate (1)			Outstanding		Weighted average interest rate (1)			Outstanding
Short-term debt
Commercial paper - AGL Capital (2)	2014			0.4	%	$	857		0.5	%	$	1,063
Commercial paper- Nicor Gas (2)	2014			0.3			314		0.4			314
Total short-term debt				0.4	%	$	1,171		0.5	%	$	1,377
Current portion of long-term debt and capital leases
Current portion of long-term debt		n/a		-			-		4.6			225
Current portion of capital leases		n/a		-			-		4.9			1
Total current portion of long-term debt and capital leases				-		$	-		4.6	%	$	226
Long-term debt - excluding current portion
Senior notes		2015-2043		5.0	%	$	2,825		5.1	%	$	2,325
First mortgage bonds		2016-2038		5.6			500		5.6			500
Gas facility revenue bonds		2022-2033		1.0			200		1.2			200
Medium-term notes		2017-2027		7.8			181		7.8			181
Total principal long-term debt				4.9	%	$	3,706		5.0	%	$	3,206
Fair value adjustment of long-term debt (3)		2016-2038		n/a			91		n/a			103
Unamortized debt premium, net		n/a		n/a			16		n/a			18
Total non-principal long-term debt				n/a			107		n/a			121
Total long-term debt						$	3,813				$	3,327
Total debt						$	4,984				$	4,930

(1)	Interest rates are calculated based on the daily weighted average balance outstanding for the 12 months ended December 31, 2013 and 2012.

(2)	As of December 31, 2013, the effective interest rates on our commercial paper borrowings were 0.4% for AGL Capital and 0.3% for Nicor Gas.

(3)	See Note 4 for additional information on our fair value measurements.

Short-term Debt

Our short-term debt at December 31, 2013 and 2012 was composed of borrowings under our commercial paper programs.

Commercial Paper Programs We maintain commercial paper programs at AGL Capital and at Nicor Gas that consist of short-term, unsecured promissory notes that are used in conjunction with cash from operations to fund our seasonal working capital requirements. Working capital needs fluctuate during the year and are highest during the injection period in advance of the Heating Season. The Nicor Gas commercial paper program supports working capital needs at Nicor Gas, while all of our other subsidiaries and SouthStar participate in the AGL Capital commercial paper program. During 2013, our commercial paper maturities ranged from 1 to 123 days, and at December 31, 2013, remaining terms to maturity ranged from 2 to 99 days. During 2013, total borrowings and repayments netted to a payment of $206 million. For commercial paper issuances with original maturities over 3 months, borrowings and repayments were $374 million and $181 million, respectively.

Credit Facilities At December 31, 2013 and 2012, there were no outstanding borrowings under either the AGL Capital or Nicor Gas credit facilities. In November 2013, the lenders for our two credit facilities consented to our request to extend the maturity date of each facility by one year, in accordance with the terms of the respective credit agreements. The AGL Credit Facility and Nicor Gas Credit Facility maturity dates were extended to November 10, 2017 and December 15, 2017, respectively. The terms, conditions and pricing under the agreements remain unchanged.

Current Portion of Long-term Debt and Capital Leases The current portion of our long-term debt at December 31, 2012 was composed of the current portions of our long-term debt and capital lease obligations. Our capital leases consisted primarily of a sale/leaseback transaction of gas meters and other equipment that was completed in 2002 by Florida City Gas and expired in the second quarter 2013. In the second quarter 2012, Florida City Gas had the option to purchase the leased meters from the lessor at their fair market value, but it did not exercise this option.

Glossary

Table of Contents

Long-term Debt

Our long-term debt at December 31, 2013 and 2012 consisted of medium-term notes: Series A, Series B, and Series C, which we issued under an indenture dated December 1, 1989; senior notes; first mortgage bonds; and gas facility revenue bonds. Some of these issuances were completed in the private placement market. In determining that those specific bonds qualify for exemption from registration under Section 4(2) of the Securities Act of 1933, we relied on the facts that the bonds were offered only to a limited number of large institutional investors and each institutional investor that purchased the bonds represented that it was purchasing the bonds for its own account and not with a view to distribute them. We fully and unconditionally guarantee all of our senior notes. Additionally, substantially all of Nicor Gas’ properties are subject to the lien of the indenture securing its first mortgage bonds.

The majority of our long-term debt matures after fiscal year 2018. The annual maturities of our long-term debt for the next five years and thereafter are as follows:

Year	Amount (in millions)
2014	$	-
2015		200
2016		545
2017		22
2018		155
Thereafter		2,784
Total	$	3,706

Senior Notes On May 16, 2013 we issued $500 million in 30-year senior notes with a fixed interest rate of 4.4%. The net proceeds were used to repay a portion of AGL Capital’s commercial paper, including $225 million we borrowed to repay our senior notes that matured on April 15, 2013. There were no senior note issuances in 2012.

First Mortgage Bonds We acquired the first mortgage bonds of Nicor Gas, which were issued through the public and private placement markets, as a result of the 2011 merger.

Gas Facility Revenue Bonds We are party to a series of loan agreements with the New Jersey Economic Development Authority (NJEDA) under which the NJEDA has issued a series of gas facility revenue bonds. These gas revenue bonds are issued by state agencies or counties to investors, and proceeds from the issuance are then loaned to us.

During 2013 we refinanced $200 million of our outstanding tax-exempt gas facility revenue bonds, $180 million of which were previously issued by the New Jersey Economic Development Authority and $20 million of which were previously issued by Brevard County, Florida. The refinancing involved a combination of the issuance of $60 million of refunding bonds to, and the purchase of $140 million of existing bonds by, a syndicate of banks. Our relationship with the syndicate of banks regarding the bonds is governed by an agreement that contains representations, warranties, covenants and default provisions consistent with those contained in similar financing documents of ours. All of the bonds are floating-rate instruments. We had no cash receipts or payments in connection with the refinancing. The letters of credit providing credit support for the outstanding revenue bonds along with other related agreements were terminated as a result of the refinancing.

Financial and Non-Financial Covenants

The AGL Credit Facility and the Nicor Gas Credit Facility each include a financial covenant that requires us to maintain a ratio of total debt to total capitalization of no more than 70% at the end of any fiscal month; however, our goal is to maintain these ratios at levels between 50% and 60%. These ratios, as calculated in accordance with the debt covenants, include standby letters of credit and surety bonds and exclude accumulated OCI items related to non-cash pension adjustments, welfare benefits liability adjustments and accounting adjustments for cash flow hedges. Adjusting for these items, the following table contains our debt-to-capitalization ratios for the dates presented, which are below the maximum allowed.

	AGL Resources						Nicor Gas
	December 31,						December 31,
	2013			2012			2013			2012
Debt-to-capitalization ratio		57	%		58	%		55	%		55	%

The credit facilities contain certain non-financial covenants that, among other things, restrict liens and encumbrances, loans and investments, acquisitions, dividends and other restricted payments, asset dispositions, mergers and consolidations and other matters customarily restricted in such agreements.

Glossary

Table of Contents

Default Provisions

Our credit facilities and other financial obligations include provisions that, if not complied with, could require early payment or similar actions. The most important default events include:

·	a maximum leverage ratio

·	insolvency events and nonpayment of scheduled principal or interest payments

·	acceleration of other financial obligations

·	change of control provisions

We have no triggering events in our debt instruments that are tied to changes in our specified credit ratings or our stock price and have not entered into any transaction that requires us to issue equity based on credit ratings or other triggering events. We were in compliance with all existing debt provisions and covenants, both financial and non-financial, as of December 31, 2013 and 2012.

Preferred Securities

At December 31, 2013 and 2012, we had 10 million shares of authorized, unissued Class A junior participating preferred stock, no par value, and 10 million shares of authorized, unissued preferred stock, no par value.

Note 9 - Equity

Treasury Shares

Our Board of Directors authorized us to purchase up to 8 million treasury shares through our repurchase plan, which expired on January 31, 2011. This plan was used to offset shares issued under our employee and non-employee director incentive compensation plans and our dividend reinvestment and stock purchase plans. Stock purchases under this plan were made in the open market or in private transactions at times, and in amounts that we deemed appropriate. We held the purchased shares as treasury shares and accounted for them using the cost method. We purchased no treasury shares in 2013 or 2012.

Dividends

Our common shareholders may receive dividends when declared at the discretion of our Board of Directors. Dividends may be paid in cash, stock or other form of payment, and payment of future dividends will depend on our future earnings, cash flow, financial requirements and other factors.

Additionally, we derive a substantial portion of our consolidated assets, earnings and cash flow from the operation of regulated utility subsidiaries, whose legal authority to pay dividends or make other distributions to us is subject to regulation. As with most other companies, the payment of dividends is restricted by laws in the states where we conduct business. In certain cases, our ability to pay dividends to our common shareholders is limited by (i) our ability to pay our debts as they become due in the usual course of business and satisfy our obligations under certain financing agreements, including our debt-to-capitalization covenant, (ii) our ability to maintain total assets below total liabilities, and (iii) our ability to satisfy our obligations to any preferred shareholders.

Accumulated Other Comprehensive Loss

Our share of comprehensive income (loss) includes net income plus OCI, which includes changes in fair value of certain derivatives designated as cash flow hedges, certain changes in pension and other retirement benefit plans and reclassifications for amounts included in net income less net income and OCI attributable to the noncontrolling interest. For more information on our derivative instruments, see Note 5. For more information on our pensions and retirement benefit obligations, see Note 6. Our other comprehensive income (loss) amounts are aggregated within our accumulated other comprehensive loss. The following table provides changes in the components of our accumulated other comprehensive loss balances, net of the related tax effects allocated to each component of OCI.

In millions (1)	Cash flow hedges			Retirement benefit plans			Total
As of December 31, 2010	$	(5	)	$	(145	)	$	(150	)
Other comprehensive loss		(2	)		(65	)		(67	)
As of December 31, 2011		(7	)		(210	)		(217	)
Other comprehensive income (loss)		4			(5	)		(1	)
As of December 31, 2012		(3	)		(215	)		(218	)
Other comprehensive income, before reclassifications		1			66			67
Amounts reclassified from accumulated other comprehensive loss		3			12			15
As of December 31, 2013	$	1		$	(137	)	$	(136	)

(1)	All amounts are net of income taxes. Amounts in parentheses indicate debits to accumulated other comprehensive loss.

Glossary

Table of Contents

The following table provides details of the reclassifications out of accumulated other comprehensive loss for the year ended December 31, 2013 and the ultimate favorable (unfavorable) impact on net income.

In millions (1)
Cash flow hedges
Natural gas contracts	$	(1	)	Cost of goods sold
Interest rate contracts		(3	)	Interest expense, net
Total before income tax		(4	)
Income tax benefit		1
Total cash flow hedges		(3	)
Retirement benefit plan amortization of
Actuarial losses		(25	)	See (2), below
Prior service credits		5		See (2), below
Total before income tax		(20	)
Income tax benefit		8
Total retirement benefit plans		(12	)
Total reclassification for the period	$	(15	)

(1)	Amounts in parentheses indicate debits, or reductions, to profit/loss and credits to accumulated other comprehensive loss. Except for retirement benefit plan amounts, the profit/loss impacts are immediate.

(2)	Amortization of these accumulated other comprehensive loss components is included in the computation of net periodic benefit cost. See Note 5 for additional details about net periodic benefit cost.

Note 10 - Non-Wholly Owned Entities

Variable Interest Entities

On a quarterly basis we evaluate our variable interests in other entities, primarily ownership interests, to determine if they represent a variable interest entity (VIE) as defined by the authoritative accounting guidance on consolidation, and if so, which party is the primary beneficiary. We have determined that SouthStar, a joint venture owned by us and Piedmont, is the only VIE for which we are the primary beneficiary, which requires us to consolidate its assets, liabilities and Statements of Income. Our conclusion that SouthStar is a VIE resulted from our equal voting rights with Piedmont not being proportional to our economic obligation to absorb 85% of losses or residual returns from the joint venture. We account for our ownership of SouthStar in accordance with authoritative accounting guidance which is described within Note 2. The primary risks associated with SouthStar are discussed in our risk factors included in Item 1A.

SouthStar markets natural gas and related services under the trade name Georgia Natural Gas to customers in Georgia, and under various other trade names to customers in Illinois, Ohio, Florida, Maryland, Michigan and New York. Following are additional factors we considered in determining that we have the power to direct SouthStar’s activities that most significantly impact its performance.

Operations

Our wholly owned subsidiaries, Nicor Gas and Atlanta Gas Light, provide the following services, which affect SouthStar’s operations:

·	meter reading for SouthStar’s customers in Illinois and Georgia

·	maintenance and expansion of the natural gas infrastructure in Illinois and Georgia

·	assigning storage and transportation capacity used in delivering natural gas to SouthStar’s customers

Liquidity and capital resources

·	guarantees of SouthStar’s activities with, and its credit exposure to, its counterparties and to certain natural gas suppliers in support of SouthStar’s payment obligations

support of SouthStar’s daily cash management activities and assistance ensuring SouthStar has adequate liquidity and working capital resources by allowing SouthStar to utilize the AGL Capital commercial paper program for its liquidity and working capital requirements in accordance with our services agreement.

Back office functions

·	Accounting, information technology, credit and internal controls services in accordance with our services agreement

SouthStar’s earnings are allocated entirely in accordance with the ownership interests and are seasonal in nature, with the majority occurring during the first and fourth quarters of each year. SouthStar’s current assets consist primarily of natural gas inventory, derivative instruments and receivables from its customers. SouthStar also has receivables from us due to its participation in AGL Capital’s commercial paper program. SouthStar’s current liabilities consist primarily of accrued natural gas costs, other accrued expenses, customer deposits, derivative instruments and payables to us from its participation in AGL Capital’s commercial paper program.

SouthStar’s contractual commitments and obligations, including operating leases and agreements with third party providers, do not contain terms that would trigger material financial obligations in the event that such contracts were terminated. As a result, our maximum exposure to a loss at SouthStar is considered to be immaterial. SouthStar’s creditors have no recourse to our general credit beyond our corporate guarantees we have provided to SouthStar’s counterparties and natural gas suppliers. We have provided no financial or other support that was not previously contractually required. With the exception of our corporate guarantees and the aforementioned limited protections related to goodwill and intangible assets, we have not entered into any arrangements that could require us to provide financial support to SouthStar.

Glossary

Table of Contents

Price and volume fluctuations of SouthStar’s natural gas inventories can cause significant variations in our working capital and cash flow from operations. Changes in our operating cash flows are also attributable to SouthStar’s working capital changes resulting from the impact of weather, the timing of customer collections, payments for natural gas purchases and cash collateral amounts that SouthStar maintains to facilitate its derivative instruments.

Cash flows used in our investing activities include capital expenditures for SouthStar for the year ended December 31, of $3 million for 2013, $1 million for 2012 and $2 million for 2011. Cash flows used in our financing activities include SouthStar’s distribution to Piedmont for its portion of SouthStar’s annual earnings from the previous year. Generally, this distribution occurs in the first or second quarter of each fiscal year. For the years ended December 31, 2013, 2012 and 2011, SouthStar distributed $17 million, $14 million and $16 million to Piedmont, respectively.

On September 1, 2013 we contributed to SouthStar our Illinois retail energy businesses with approximately 108,000 customers. Additionally, Piedmont contributed to SouthStar $22.5 million in cash to maintain its 15% ownership in the joint venture. In connection with the contribution of our Illinois retail energy businesses, we provided certain limited protections to Piedmont regarding the value of the contributed businesses related to goodwill and other intangible assets. Piedmont’s contribution is reflected as an increase to the noncontrolling interest on our Consolidated Statements of Financial Position and a financing activity on our Consolidated Statements of Cash Flows. These funds were used to reduce our commercial paper borrowings.

The following table provides additional information on SouthStar’s assets and liabilities as of the dates presented, which are consolidated within our Consolidated Statements of Financial Position.

	December 31, 2013						December 31, 2012
In millions	Consolidated		SouthStar (1)		%(2)		Consolidated		SouthStar (1)		%(2)
Current assets	$	2,733	$	264	10	%	$	2,668	$	201	8	%
Goodwill and other intangible assets		2,061		139	7			1,933		-	-
Long-term assets and other deferred debit		9,862		12	-			9,540		10	-
Total assets	$	14,656	$	415	3	%	$	14,141	$	211	1	%
Current liabilities	$	3,122	$	95	3	%	$	3,338	$	62	2	%
Long-term liabilities and other deferred credits		7,858		-	-			7,368		-	-
Total liabilities		10,980		95	1			10,706		62	1
Equity		3,676		320	9			3,435		149	4
Total liabilities and equity	$	14,656	$	415	3	%	$	14,141	$	211	1	%

(1) These amounts reflect information for SouthStar and exclude intercompany eliminations and the balances of our wholly owned subsidiary with an 85% ownership interest in SouthStar.

(2) SouthStar’s percentage of the amount on our Consolidated Statements of Financial Position.

The following table provides additional information about SouthStar’s revenues and expenses for the periods presented, which are consolidated within our Consolidated Statements of Income.

	December 31,
In millions	2013		2012
Operating revenues	$	687	$	576
Operating expenses
Cost of goods sold		491		411
Operation and maintenance		72		63
Depreciation and amortization		5		2
Taxes other than income taxes		1		2
Total operating expenses		569		478
Operating income	$	118	$	98

Equity Method Investments

Triton We have an investment in Triton, a cargo container leasing company. Container equipment that is acquired by Triton is accounted for in tranches as defined in Triton’s operating agreement, and investors make capital contributions to Triton to invest in each of the tranches. As of December 31, 2013 we had invested in seven tranches established by Triton. For the years ended December 31, 2013 and 2012, income from our equity method investment in Triton of $9 million and $11 million, respectively, was classified as other income on our Consolidated Statements of Income.

Glossary

Table of Contents

Horizon Pipeline We have a 50% owned joint venture with Natural Gas Pipeline Company of America that is regulated by the FERC. Horizon Pipeline operates an approximate 70-mile natural gas pipeline from Joliet, Illinois to near the Wisconsin/Illinois border. Nicor Gas typically contracts for 70% to 80% of the total capacity.

Sawgrass Storage We own a 50% interest in Sawgrass Storage, a joint venture between us and a privately held energy exploration and production company. Sawgrass Storage was granted certification from the FERC in March 2012 for the development of an underground natural gas storage facility in Louisiana with 30 Bcf of working gas capacity. The FERC certificate is set to expire in March 2014.

In December 2013, the joint venture decided to terminate the development of this facility and recognized an impairment loss of $16 million, which reduced the carrying amount of the joint venture’s long-lived assets to fair value. Consequently, we recognized our 50% interest in the loss during the fourth quarter of 2013, resulting in an $8 million ($5 million net of tax) charge to operating income.

The carrying amounts of our investments that are accounted for under the equity method at December 31 were as follows:

In millions	2013		2012
Triton	$	70	$	73
Horizon Pipeline		15		17
Other (1)		1		9
Total	$	86	$	99

(1)	Includes our investment in Sawgrass Storage of $1 million at December 31, 2013 and $9 million at December 31, 2012.

Our net equity investment income for the years ended December 31, 2013, 2012 and 2011, was $3 million, $13 million and $1 million, respectively, which is reflected within other income on our Consolidated Statements of Income. The majority of our net equity investment income is attributable to our investment in Triton. For more information on our other income, see Note 2. During 2013 we received distributions of $17 million from our equity investees and $14 million in 2012.

Glossary

Table of Contents

Note 11 - Commitments, Guarantees and Contingencies

We have incurred various contractual obligations and financial commitments in the normal course of our operating and financing activities that are reasonably likely to have a material effect on liquidity or the availability of capital resources. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities. The following table illustrates our expected future contractual payments under our obligations and other commitments as of December 31, 2013.

													2019 &
In millions	Total		2014		2015		2016		2017		2018		thereafter
Recorded contractual obligations:
Long-term debt (1)	$	3,706	$	-	$	200	$	545	$	22	$	155	$	2,784
Short-term debt		1,171		1,171		-		-		-		-		-
Environmental remediation liabilities (2)		447		70		82		80		48		63		104
Pipeline replacement program costs (2)		5		5		-		-		-		-		-
Total	$	5,329	$	1,246	$	282	$	625	$	70	$	218	$	2,888

Unrecorded contractual obligations and commitments (3) (8):
Pipeline charges, storage capacity and gas supply (4)	$	2,298	$	733	$	507	$	299	$	138	$	102	$	519
Interest charges (5)		2,899		185		175		161		147		145		2,086
Operating leases (6)		233		39		34		28		25		18		89
Asset management agreements (7)		19		8		5		4		2		-		-
Standby letters of credit, performance/surety bonds (8)		29		29		-		-		-		-		-
Other		15		6		3		3		2		1		-
Total	$	5,493	$	1,000	$	724	$	495	$	314	$	266	$	2,694

(1)	Excludes the $82 million step up to fair value of first mortgage bonds, $16 million unamortized debt premium and $9 million interest rate swaps fair value adjustment.

(2)	Includes charges recoverable through base rates or rate rider mechanisms.

(3)	In accordance with GAAP, these items are not reflected in our Consolidated Statements of Financial Position.

(4)

Includes charges recoverable through a natural gas cost recovery mechanism or alternatively billed to Marketers and demand charges associated with Sequent. The gas supply balance includes amounts for Nicor Gas and SouthStar gas commodity purchase commitments of 31 Bcf at floating gas prices calculated using forward natural gas prices as of December 31, 2013, and is valued at $136 million. As we do for other subsidiaries, we provide guarantees to certain gas suppliers for SouthStar in support of payment obligations.

(5)	Floating rate interest charges are calculated based on the interest rate as of December 31, 2013 and the maturity date of the underlying debt instrument. As of December 31, 2013, we have $52 million of accrued interest on our Consolidated Statements of Financial Position that will be paid in 2014.

(6)

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 GAAP. However, this lease accounting treatment does not affect the future annual operating lease cash obligations as shown herein. Our operating leases are primarily for real estate.

(7)	Represent fixed-fee minimum payments for Sequent’s affiliated asset management agreements.

(8)	We provide guarantees to certain municipalities and other agencies and certain gas suppliers of SouthStar in support of payment obligations.

Substitute Natural Gas

In 2011, Illinois enacted laws that required Nicor Gas and other large utilities in Illinois to elect to either sign contracts to purchase SNG from coal gasification plants to be constructed in Illinois or file rate cases with the Illinois Commission in 2012, 2014 and 2016.

On October 11, 2011, the Illinois Power Agency (IPA) approved the form of a draft 30-year contract for the purchase by Nicor Gas of 20 Bcf per year of SNG from a proposed plant beginning as early as 2018. The purchase price of the SNG that may be produced from this proposed coal gasification plant may significantly exceed market prices for natural gas and is expected to be dependent upon a variety of factors, including the developer’s financing, plant construction costs and volumes sold, which are currently not determinable. The Illinois law pertaining to this plant provides that the price paid for SNG purchased from the plant is to be considered prudent and not subject to review or disallowance by the Illinois Commission.

In November 2011, we filed a lawsuit against the IPA and the developer of this proposed plant contending that the draft contract approved by the IPA does not conform to certain requirements of the enabling legislation. The lawsuit is pending in circuit court in DuPage County, Illinois. In accordance with the enabling legislation, the draft contract approved by the IPA was submitted to the Illinois Commission for further approvals by that regulatory body. The final form of contract approved by the Illinois Commission modified the draft contract submitted by the IPA in various respects. We have appealed the Illinois Commission’s decision to the circuit court in DuPage County, Illinois. As a result of pending litigation challenging aspects of the IPA and Illinois Commission decisions regarding the contract terms, we have not yet signed a contract with the developer to purchase SNG from the proposed plant.

Glossary

Table of Contents

Contingencies and Guarantees

Contingent financial commitments, such as financial guarantees, represent obligations that become payable only if certain predefined events occur. We have certain subsidiaries that enter into various financial and performance guarantees and indemnities providing assurance to third parties. We believe the likelihood of payment under our guarantees is remote. No liability has been recorded for such guarantees and indemnifications as the fair value is insignificant.

Financial guarantees Tropic Equipment Leasing Inc. (TEL), a wholly owned subsidiary, holds our interest in Triton and has an obligation to restore to zero any deficit in its equity account for income tax purposes in the unlikely event that Triton is liquidated and a deficit balance remains. This obligation continues for the life of the Triton partnerships and any payment is effectively limited to the net assets of TEL, which were $16 million at December 31, 2013. We believe the likelihood of any such payment by TEL is remote. No liability has been recorded for this obligation.

Indemnities In certain instances, we have undertaken to indemnify current property owners and others against costs associated with the effects and/or remediation of contaminated sites for which we may be responsible under applicable federal or state environmental laws, generally with no limitation as to the amount. These indemnifications relate primarily to ongoing coal tar cleanup, as discussed in Environmental Matters. We believe that the likelihood of payment under our other environmental indemnifications is remote. No liability has been recorded for such indemnifications.

Regulatory Matters

In December 2012, Atlanta Gas Light filed a petition with the Georgia Commission for approval to resolve an imbalance of approximately 4.8 Bcf of natural gas related to Atlanta Gas Light’s use of retained storage assets to operationally balance the system for the benefit of the natural gas market. We believe that any costs associated with resolving the imbalance should be recoverable from Marketers. The resolution of this imbalance will be decided by the Georgia Commission and we are unable to predict the ultimate outcome and recovery.

Environmental Matters

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. See Note 3 for additional information.

We are involved in an investigation by the EPA regarding the applicable regulatory requirements for polychlorinated biphenyl in the Nicor Gas distribution system. While we are unable to predict the outcome of this matter or to reasonably estimate our potential exposure related thereto, if any, and have not recorded a liability associated with this contingency, the final disposition of this matter is not expected to have a material adverse impact on our liquidity or financial condition.

Litigation

We are involved in litigation arising in the normal course of business. Although in some cases we are unable to estimate the amount of loss reasonably possible in addition to any amounts already recognized, it is possible that the resolution of these contingencies, either individually or in aggregate, will require us to take charges against, or will result in reductions in, future earnings. Management believes that while the resolution of these contingencies, whether individually or in aggregate, could be material to earnings in a particular period, they will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

PBR Proceeding Nicor Gas’ PBR plan for natural gas costs went into effect in 2000 and was terminated effective January 1, 2003, following allegations that Nicor Gas acted improperly in connection with the plan. Under this plan, Nicor Gas’ total gas supply costs were compared to a market-sensitive benchmark. Savings and losses relative to the benchmark were determined annually and shared equally with sales customers. Since 2002 the amount of the savings and losses required to be shared has been disputed by the Citizens Utility Board (CUB) and others, with the Illinois Attorney General (IAG) intervening, and subject to extensive contested discovery and other regulatory proceedings before administrative law judges and the Illinois Commission. In 2009, the staff of the Illinois Commission, the staff of the IAG and CUB requested refunds of $85 million, $255 million and $305 million, respectively.

In February 2012, we committed to a stipulation with the staff of the Illinois Commission for a resolution of the dispute through the crediting to Nicor Gas customers of $64 million. On November 5, 2012, the administrative law judges issued a proposed order for a refund of $72 million. In the fourth quarter of 2012, we increased our accrual for this dispute by $8 million for a total of $72 million as a result of these developments and its effect on the estimated liability.

On June 7, 2013 the Illinois Commission issued an order requiring us to refund $72 million to current Nicor Gas customers over a 12-month period. On July 1, 2013 we began refunding customers the full $72 million through our PGA mechanism. The amount refunded is based upon natural gas throughput and $29 million was refunded in 2013. The CUB is continuing to pursue its claim.

Glossary

Table of Contents

Other In addition to the matters set forth above, we are involved with legal or administrative proceedings before various courts and agencies with respect to general claims, taxes, environmental, gas cost prudence reviews and other matters. We are unable to determine the ultimate outcome of these other contingencies. We believe that these amounts are appropriately reflected in our financial statements, including the recording of appropriate liabilities when reasonably estimable.

Note 12 - Income Taxes

Income Tax Expense

The relative split between current and deferred taxes is due to a variety of factors including true ups of prior year tax returns, and most importantly, the timing of our property-related deductions. Components of income tax expense in the Consolidated Statements of Income are shown in the following table.

In millions	2013			2012			2011
Current income taxes
Federal	$	166		$	9		$	(89	)
State		35			4			1
Deferred income taxes
Federal		2			134			196
State		(9	)		20			18
Amortization of investment tax credits		(3	)		(3	)		(1	)
Total	$	191		$	164		$	125

The reconciliations between the statutory federal income tax rate of 35%, the effective rate and the related amount of income tax expense for the years ended December 31, in our Consolidated Statements of Income are presented in the following table.

In millions	2013			2012			2011
Computed tax expense at statutory rate	$	178		$	158		$	109
State income tax, net of federal income tax benefit		21			19			14
Sale of Compass Energy		6			-			-
Tax effect of net income attributable to the noncontrolling interest		(7	)		(6	)		(6	)
Amortization of investment tax credits		(3	)		(3	)		(1	)
Affordable housing credits		(2	)		(2	)		(1	)
Flexible dividend deduction		(2	)		(2	)		(2	)
Change in control payments		-			-			9
Merger transaction costs		-			-			3
Total income tax expense on Consolidated Statements of Income	$	191		$	164		$	125

Accumulated Deferred Income Tax Assets and Liabilities

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 the assets and liabilities using income tax rates that are currently in effect. We have provided a valuation allowance for some of these items that reduce our net deferred tax assets to amounts we believe are more likely than not to be realized in future periods. With respect to our continuing operations, we have net operating losses in various jurisdictions. Components that give rise to the net non-current accumulated deferred income tax liability are as follows.

Glossary

Table of Contents

	As of December 31,
In millions	2013			2012
Accumulated deferred income tax liabilities
Property - accelerated depreciation and other property-related items	$	1,613		$	1,533
Undistributed earnings of foreign subsidiaries		26			30
Investments in partnerships		18			26
Acquisition intangibles		15			26
Mark-to-market		-			22
Other		128			126
Total accumulated deferred income tax liabilities		1,800			1,763
Accumulated deferred income tax assets
Unfunded pension and retiree welfare benefit obligation		92			145
Deferred investment tax credits		7			9
Mark-to-market		4			-
Other		44			43
Total accumulated deferred income tax assets		147			197
Valuation allowances (1)		(14	)		(22	)
Total accumulated deferred income tax assets, net of valuation allowance		133			175
Net non-current accumulated deferred tax liability	$	1,667		$	1,588

(1)

The total valuation allowance is $22 million, which is comprised of $3 million valuation allowance is due to the net operating losses of a former non-operating subsidiary that are not allowed in New Jersey and $19 million valuation allowance is related to our investment in Triton. In addition, $8 million of the total is classified as a valuation allowance against current deferred income tax assets. See Note 2 for more information regarding current deferred income taxes.

To the extent foreign cargo shipping earnings are not repatriated to the U.S., such earnings are not currently subject to taxation. In addition, to the extent such earnings are indefinitely reinvested offshore, no deferred income tax expense is recorded by us. At December 31, 2013, we had $26 million of deferred income tax liabilities related to $75 million of cumulative undistributed earnings of our foreign subsidiaries. At December 31, 2012, we had $30 million of deferred income tax liabilities related to $87 million of cumulative undistributed earnings of our foreign subsidiaries. See Note 2 for more information about potential income taxes related to undistributed foreign earnings.

Tax Benefits

As of December 31, 2013 and December 31, 2012, we did not have a liability for unrecognized tax benefits. Based on current information, we do not anticipate that this will change materially in 2014. As of December 31, 2013, we did not have a liability recorded for payment of interest or penalties associated with uncertain tax positions nor did we have any such interest or penalties during 2013 or 2012.

We file a U.S. federal consolidated income tax return and various state income tax returns. We are no longer subject to income tax examinations by the Internal Revenue Service or in any state for years before 2008.

Note 13 - Segment Information

Our operating segments comprise revenue-generating components of our company for which we produce separate financial information internally that we regularly use to make operating decisions and assess performance. Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. We manage our businesses through five operating segments - distribution operations, retail operations, wholesale services, midstream operations, cargo shipping and one non-operating segment, other.

Our distribution operations segment is the largest component of our business and includes natural gas local distribution utilities in seven states. These utilities construct, manage, and maintain intrastate natural gas pipelines and distribution facilities. Although the operations of our distribution operations segment are geographically dispersed, the operating subsidiaries within the distribution operations segment are regulated utilities, with rates determined by individual state regulatory commissions. These natural gas distribution utilities have similar economic and risk characteristics.

We are also involved in several related and complementary businesses. Our retail operations segment includes retail natural gas marketing to end-use customers primarily in Georgia as well as various businesses that market retail energy-related products and services to residential and small business customers in Illinois. Additionally, our retail operations segment provides home protection products and services. Our wholesale services segment engages in natural gas storage and gas pipeline arbitrage and related activities. Additionally, they provide natural gas asset management and/or related logistics services for each of our utilities, as well as for non-affiliated companies, natural gas storage arbitrage and related activities. Our midstream operations segment includes our non-utility storage and pipeline operations, including the development and operation of high-deliverability natural gas storage assets.

Glossary

Table of Contents

Our cargo shipping segment transports containerized cargo between Florida, the eastern coast of Canada, the Bahamas and the Caribbean region. Our cargo shipping segment also includes amounts related to cargo insurance coverage sold to our customers and other third parties. Our cargo shipping segment’s vessels are under foreign registry, and its containers are considered instruments of international trade. Although the majority of its long-lived assets are foreign owned and its revenues are derived from foreign operations, the functional currency is generally the U.S. dollar. Our other segment includes intercompany eliminations and aggregated subsidiaries that are not significant on a stand-alone basis and that do not fit into one of our other five operating segments.

The chief operating decision maker of the company is the Chairman, President and Chief Executive Officer who utilizes EBIT as the primary measure of profit and loss in assessing the results of our segments and operations. EBIT includes operating income and other income and expenses. Items we do not include in EBIT are income taxes and financing costs, including interest and debt expense, each of which we evaluate on a consolidated basis.

Summarized Statements of Income, Statements of Financial Position and capital expenditure information by segment as of and for the years ended December 31, 2013, 2012 and 2011 are shown in the following tables.

2013
In millions	Distribution operations		Retail operations		Wholesale services			Midstream operations			Cargo shipping		Other and intercompany eliminations (4)			Consolidated
Operating revenues from external parties	$	3,275	$	858	$	45		$	74		$	365	$	-		$	4,617
Intercompany revenues (1)		182		-		13			-			-		(195	)		-
Total operating revenues		3,457		858		58			74			365		(195	)		4,617
Operating expenses
Cost of goods sold		1,687		564		21			33			222		(195	)		2,332
Operation and maintenance		690		132		48			24			115		(10	)		999
Depreciation and amortization		346		22		1			17			19		13			418
Taxes other than income taxes		167		3		3			5			6		9			193
Total operating expenses		2,890		721		73			79			362		(183	)		3,942
Gain on sale of Compass Energy		-		-		11			-			-		-			11
Operating income (loss)		567		137		(4	)		(5	)		3		(12	)		686
Other income (expense)		15		-		-			(5	)		9		(2	)		17
EBIT	$	582	$	137	$	(4	)	$	(10	)	$	12	$	(14	)	$	703
Identifiable and total assets (3)	$	11,727	$	694	$	1,166		$	713		$	445	$	(89	)	$	14,656
Capital expenditures	$	684	$	9	$	2		$	12		$	18	$	24		$	749

2012
In millions	Distribution operations		Retail operations		Wholesale services			Midstream operations		Cargo shipping			Other and intercompany eliminations (4)			Consolidated
Operating revenues from external parties	$	2,710	$	733	$	58		$	78	$	342		$	1		$	3,922
Intercompany revenues (1)		167		2		30			-		-			(199	)		-
Total operating revenues		2,877		735		88			78		342			(198	)		3,922
Operating expenses
Cost of goods sold		1,221		488		38			32		208			(196	)		1,791
Operation and maintenance		642		114		48			19		109			(11	)		921
Depreciation and amortization		351		13		2			14		22			13			415
Nicor merger expenses (2)		-		-		-			-		-			20			20
Taxes other than income taxes		140		4		4			5		6			6			165
Total operating expenses		2,354		619		92			70		345			(168	)		3,312
Operating income (loss)		523		116		(4	)		8		(3	)		(30	)		610
Other income		9		-		1			2		11			1			24
EBIT	$	532	$	116	$	(3	)	$	10	$	8		$	(29	)	$	634
Identifiable and total assets (3)	$	11,320	$	511	$	1,218		$	720	$	464		$	(92	)	$	14,141
Capital expenditures	$	649	$	8	$	3		$	62	$	7		$	53		$	782

Glossary

Table of Contents

2011

In millions	Distribution operations		Retail operations		Wholesale services		Midstream operations		Cargo shipping			Other and intercompany eliminations (4)			Consolidated
Operating revenues from external parties	$	1,451	$	702	$	95	$	70	$	19		$	1		$	2,338
Intercompany revenues (1)		146		-		3		-		-			(149	)		-
Total operating revenues		1,597		702		98		70		19			(148	)		2,338
Operating expenses
Cost of goods sold		625		534		41		33		12			(148	)		1,097
Operation and maintenance		362		71		48		15		7			(2	)		501
Depreciation and amortization		160		2		1		10		1			12			186
Nicor merger expenses (2)		-		-		-		-		-			57			57
Taxes other than income taxes		44		2		3		3		-			5			57
Total operating expenses		1,191		609		93		61		20			(76	)		1,898
Operating income (loss)		406		93		5		9		(1	)		(72	)		440
Other income		6		-		-		-		1			-			7
EBIT	$	412	$	93	$	5	$	9	$	-		$	(72	)	$	447
Capital expenditures	$	365	$	2	$	1	$	35	$	-		$	24		$	427

(1)	Wholesale services records its energy marketing and risk management revenues on a net basis and its total operating revenues include intercompany revenues of $417 million in 2013, $350 million in 2012 and $449 million in 2011.

(2)	Transaction expenses associated with the Nicor merger are shown separately to better compare year-over-year results.

(3)	Identifiable assets are those dedicated to each segment’s operations.

(4)	Our other segment’s assets consist primarily of cash and cash equivalents, PP&E and the effect of intercompany eliminations.

Glossary

Table of Contents

Note 14 - Selected Quarterly Financial Data (Unaudited)

The variance in our quarterly earnings is primarily the result of the seasonal nature of the distribution of natural gas to customers, the volatility within our wholesale services segment and the seasonality of our cargo shipping segment. During the Heating Season, natural gas usage and operating revenues are generally higher at our distribution operations and retail operations segments as more customers are connected to our distribution systems and natural gas usage is higher in periods of colder weather. However, our base operating expenses, excluding cost of goods sold, interest expense and certain incentive compensation costs, are incurred relatively uniformly over any given year. Thus, our operating results can vary significantly from quarter to quarter as a result of seasonality. The effects of seasonality on our quarterly earnings have been impacted by our Nicor merger as we have more customers within our distribution operations segment that are impacted by weather.

Our 2013 operating revenues and operating income were higher than 2012. This was primarily as a result of colder-than-normal weather in 2013 compared to significantly warmer-than-normal weather in 2012. The increases in our operating revenues and operating income in 2012 compared to 2011 are primarily the result of the Nicor merger, which closed on December 9, 2011. See Note 2 and Note 13 for the impact the Nicor merger had on our segments, financial position and results of operations. Our quarterly financial data for 2013, 2012 and 2011 are summarized below.

In millions, except per share amounts	March 31		June 30		September 30			December 31
2013
Operating revenues	$	1,709	$	904	$	675		$	1,329
Operating income		299		122		82			183
EBIT		304		129		89			181
Net income		164		50		28			89
Net income attributable to AGL Resources Inc.		154		49		28			82
Basic earnings per common share attributable to AGL Resources Inc. common shareholders		1.31		0.41		0.24			0.69
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders		1.31		0.41		0.24			0.68
2012
Operating revenues	$	1,404	$	686	$	614		$	1,218
Operating income		262		91		54			203
EBIT		266		100		60			208
Net income		139		35		9			103
Net income attributable to AGL Resources Inc.		130		34		9			98
Basic earnings per common share attributable to AGL Resources Inc. common shareholders		1.12		0.28		0.08			0.84
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders		1.11		0.28		0.08			0.84
2011
Operating revenues	$	878	$	375	$	295		$	790
Operating income		238		60		24			118
EBIT		239		62		25			121
Net income (loss)		134		19		(4	)		37
Net income (loss) attributable to AGL Resources Inc.		124		18		(3	)		33
Basic earnings (loss) per common share attributable to AGL Resources Inc. common shareholders		1.60		0.23		(0.04	)		0.37
Diluted earnings (loss) per common share attributable to AGL Resources Inc. common shareholders		1.59		0.23		(0.04	)		0.37

Our basic and diluted earnings per common share are calculated based on the weighted daily average number of common shares and common share equivalents outstanding during the quarter. Those totals differ from the basic and diluted earnings per common share attributable to AGL Resources Inc. common shareholders shown in the Consolidated Statements of Income, which are based on the weighted average number of common shares and common share equivalents outstanding during the entire year.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

ITEM 9A. CONTROLS AND PROCEDURES

Conclusions Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act). No system of controls, no matter how well-designed and operated, can provide absolute assurance that the objectives of the system of controls are met, and no evaluation of controls can provide assurance that the system of controls has operated effectively in all cases. Our disclosure controls and procedures however are designed to provide reasonable assurance that the objectives of disclosure controls and procedures are met.

Glossary

Table of Contents

Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2013, in providing a reasonable level of assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods in SEC rules and forms, including a reasonable level of assurance that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and our principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the fourth quarter ended December 31, 2013, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Reports of Management and Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting

Management has assessed, and our independent registered public accounting firm, PricewaterhouseCoopers LLP, has audited, our internal control over financial reporting as of December 31, 2013. The unqualified reports of management and PricewaterhouseCoopers LLP thereon are included in Item 8 of this Annual Report on Form 10-K and are incorporated by reference herein.

ITEM 9B. OTHER INFORMATION

None

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

EXECUTIVE OFFICERS OF THE REGISTRANT

Set forth below are the names, ages and positions of our executive officers along with their business experience during the past five years. All officers serve at the discretion of our Board of Directors. All information is as of the date of the filing of this report.

Name, age and position with the company	Periods served

John W. Somerhalder II, Age 58
Chairman, President and Chief Executive Officer	October 2007 - Present

Andrew W. Evans, Age 47
Executive Vice President and Chief Financial Officer	November 2010 - Present
Executive Vice President, Chief Financial Officer and Treasurer	June 2009 - November 2010
Executive Vice President and Chief Financial Officer	May 2006 - June 2009

Henry P. Linginfelter, Age 53
Executive Vice President, Distribution Operations	December 2011 - Present
Executive Vice President, Utility Operations	June 2007 - December 2011

Melanie M. Platt, Age 59
Executive Vice President, Chief People Officer	December 2011 - Present
Senior Vice President, Human Resources and Marketing Communications	November 2008 - December 2011

Paul R. Shlanta, Age 56
Executive Vice President, General Counsel and Chief Ethics and Compliance Officer	September 2005 - Present

Peter I. Tumminello, Age 51
Executive Vice President, Wholesale Services, and President Sequent	December 2011 - Present
President, Sequent	April 2010 - December 2011
Executive Vice President, Business Development and Support, Sequent	February 2007 - April 2010

The other information required by this item with respect to directors will be set forth under the captions “Proposal 1 -Election of Directors,” “Corporate Governance - Ethics and Compliance Program,” “Committees of the Board” and “Audit Committee” in the Proxy Statement for our 2014 Annual Meeting of Shareholders or in a subsequent amendment to this report. The information required by this item with respect to Section 16(a) beneficial ownership reporting compliance will be set forth under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” in the Proxy Statement or subsequent amendment referred to above. All such information that is provided in the Proxy Statement is incorporated herein by reference.

Glossary

100

Table of Contents

ITEM 11. EXECUTIVE COMPENSATION

The information required by this item will be set forth under the captions “Compensation and Management Development Committee Report,” “Compensation and Management Development Committee Interlocks and Insider Participation,” “Director Compensation,” “Compensation Discussion and Analysis” and “Executive Compensation” in the Proxy Statement or subsequent amendment referred to in Item 10 above. All such information that is provided in the Proxy Statement is incorporated herein by reference, except for the information under the caption “Compensation and Management Development Committee Report” which is specifically not so incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by this item will be set forth under the captions “Security Ownership of Certain Beneficial Owners and Management” and “Executive Compensation - Equity Compensation Plan Information” in the Proxy Statement or subsequent amendment referred to in Item 10 above. All such information that is provided in the Proxy Statement is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

The information required by this item will be set forth under the captions “Corporate Governance - Director Independence” and “- Policy on Related Person Transactions” and “Certain Relationships and Related Transactions” in the Proxy Statement or subsequent amendment referred to in Item 10 above. All such information that is provided in the Proxy Statement is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this item will be set forth under the caption “Proposal 2 - Ratification of the Appointment of PricewaterhouseCoopers LLP as Our Independent Registered Public Accounting Firm for 2014” in the Proxy Statement or subsequent amendment referred to in Item 10 above. All such information that is provided in the Proxy Statement is incorporated herein by reference.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) Documents Filed as Part of This Report.

(1)	Financial Statements Included in Item 8 are the following:

·	Report of Independent Registered Public Accounting Firm

·	Management’s Report on Internal Control Over Financial Reporting

·	Consolidated Statements of Financial Position as of December 31, 2013 and 2012

·	Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011

·	Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2013, 2012 and 2011

·	Consolidated Statements of Equity for the years ended December 31, 2013, 2012 and 2011

·	Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011

·	Notes to Consolidated Financial Statements

(2) Financial Statement Schedules

Financial Statement Schedule II. Valuation and Qualifying Accounts - Allowance for Uncollectible Accounts and Income Tax Valuations for Each of the Three Years in the Period Ended December 31, 2013. Schedules other than those referred to above are omitted and are not applicable or not required, or the required information is shown in the financial statements or notes thereto.

(3) Exhibits

Exhibit Number	Description of Exhibit	Filer	The Filings Referenced for Incorporation by Reference
2.1	Agreement and Plan of Merger, as amended, dated December 6, 2010	AGL Resources	December 7, 2010, Form 8-K, Exhibit 2.1
2.2	Waiver entered into as of February 4, 2011	AGL Resources	February 9, 2011, Form 8-K, Exhibit 2.1

Glossary

101

Table of Contents

3.1	Amended and Restated Articles of Incorporation filed December 9, 2011	AGL Resources	December 13, 2011, Form 8-K, Exhibit 3.1
3.2	Bylaws, as amended on July 31, 2012	AGL Resources	August 6, 2012, Form 8-K, Exhibit 3.1
4.1	Specimen form of Common Stock certificate	AGL Resources	September 30, 2007, Form 10-Q, Exhibit 4.1
4.2.a	Form of AGL Capital Corporation 6.00% Senior Notes due 2034	AGL Resources	September 27, 2004, Form 8-K, Exhibit 4.1
4.2.b	Form of Guarantee of AGL Resources Inc. dated September 27, 2004	AGL Resources	September 27, 2004, Form 8-K, Exhibit 4.3
4.3.a	AGL Capital Corporation 4.95% Senior Notes due 2015	AGL Resources	December 21, 2004, Form 8-K, Exhibit 4.1
4.3.b	Guarantee of AGL Resources Inc. dated December 20, 2004	AGL Resources	December 21, 2004, Form 8-K, Exhibit 4.3
4.4.a	AGL Capital Corporation 6.375% Senior Notes due 2016	AGL Resources	December 14, 2007, Form 8-K, Exhibit 4.1
4.4.b	Guarantee of AGL Resources Inc. dated December 14, 2007	AGL Resources	December 14, 2007, Form 8-K, Exhibit 4.2
4.5.a	AGL Capital Corporation 5.25% Senior Notes due 2019	AGL Resources	August 10, 2009, Form 8-K, Exhibit 4.1
4.5.b	Guarantee of AGL Resources Inc. dated August 10, 2009	AGL Resources	August 10, 2009, Form 8-K, Exhibit 4.2
4.6.a	AGL Capital Corporation 5.875% Senior Notes due 2041	AGL Resources	March 21, 2011, Form 8-K, Exhibit 4.1
4.6.b	Guarantee of AGL Resources Inc. dated March 21, 2011	AGL Resources	March 21, 2011, Form 8-K, Exhibit 4.2
4.7.a	Form of AGL Capital Corporation 3.50% Senior Notes due 2021	AGL Resources	September 20, 2011, Form 8-K, Exhibit 4.1
4.7.b	Form of Guarantee of AGL Resources Inc. dated September 2011	AGL Resources	September 20, 2011, Form 8-K, Exhibit 4.2
4.8.a	Form of AGL Capital Corporation Series A Senior Notes due 2016	AGL Resources	September 7, 2011, Form 8-K, Exhibit 4.1
4.8.b	Form of AGL Capital Corporation Series B Senior Notes due 2018	AGL Resources	September 7, 2011, Form 8-K, Exhibit 4.2
4.9.a	AGL Capital Corporation 4.40% Senior Notes due 2043	AGL Resources	May 16, 2013, Form 8-K, Exhibit 4.2
4.9.b	AGL Resources Inc. Guarantee related to the 4.40% Senior Notes due 2043	AGL Resources	May 16, 2013, Form 8-K, Exhibit 4.2
4.10.a	Indenture dated December 1, 1989	Atlanta Gas Light	File No. 33-32274, Form S-3, Exhibit 4(a)
4.10.b	First Supplemental Indenture dated March 16, 1992	Atlanta Gas Light	File No. 33-46419, Form S-3, Exhibit 4(a)
4.11	Indenture dated February 20, 2001	AGL Resources	September 17, 2001, File No. 333-69500, Form S-3, Exhibit 4.2
4.12.a	Indenture dated January 1, 1954	Nicor Gas	December 31, 1995, Form 10-K, Exhibit 4.01
4.12.b	Indenture dated February 9, 1954	Nicor Gas	December 31, 1995, Form 10-K, Exhibit 4.02
4.12.c	Supplemental Indenture dated February 15, 1998	Nicor Gas	December 31, 1997, Form 10-K, Exhibit 4.19
4.12.d	Supplemental Indenture dated May 15, 2001	Nicor Gas	July 20, 2001, File No. 333-65486, Form S-3, Exhibit 4.18
4.12.e	Supplemental Indenture dated December 1, 2003	Nicor Gas	December 31, 2003, Form 10-K, Exhibit 4.09
4.12.f	Supplemental Indenture dated December 1, 2003	Nicor Gas	December 31, 2003, Form 10-K, Exhibit 4.10
4.12.g	Supplemental Indenture dated December 1, 2003	Nicor Gas	December 31, 2003, Form 10-K, Exhibit 4.11
4.12.h	Supplemental Indenture dated December 1, 2006	Nicor Gas	December 31, 2006, Form 10-K, Exhibit 4.11
4.12.i	Supplemental Indenture dated August 1, 2008	Nicor Gas	September 30, 2008, Form 10-Q, Exhibit 4.01
4.12.j	Supplemental Indenture dated July 23, 2009	Nicor Gas	June 30, 2009, Form 10-Q, Exhibit 4.01
4.12.k	Supplemental Indenture dated February 1, 2011	Nicor Gas	December 31, 2010, Form 10-K, Exhibit 4.12
4.12.l	Supplemental Indenture dated October 26, 2012	Nicor Gas	September 30, 2012, Form 10-Q, Exhibit 4
10.1.a +	2006 Non-Employee Directors Equity Compensation Plan, amended and restated as of December 9, 2011	AGL Resources	December 15, 2011, Form 8-K, Exhibit 10.2
10.1.b +	1998 Common Stock Equivalent Plan for Non-Employee Directors	AGL Resources	December 31, 1997, Form 10-Q, Exhibit 10.1.b
10.1.c +	First Amendment to the 1998 Common Stock Equivalent Plan for Non-Employee Directors	AGL Resources	March 31, 2000, Form 10-Q, Exhibit 10.5
10.1.d +	Second Amendment to the 1998 Common Stock Equivalent Plan for Non-Employee Directors	AGL Resources	September 30, 2002, Form 10-Q, Exhibit 10.4

Glossary

102

Table of Contents

10.1.e +	Third Amendment to the 1998 Common Stock Equivalent Plan for Non-Employee Directors	AGL Resources	September 30, 2002, Form 10-Q, Exhibit 10.5
10.1.f +	Fourth Amendment to the 1998 Common Stock Equivalent Plan for Non-Employee Directors	AGL Resources	June 30, 2007, Form 10-Q, Exhibit 10.1.m
10.1.g +	Fifth Amendment to the 1998 Common Stock Equivalent Plan for Non-Employee Directors	AGL Resources	December 31, 2008, Form 10-K, Exhibit 10.1.l
10.1.h +	Form of Stock Award Agreement for Non-Employee Directors	AGL Resources	December 31, 2004, Form 10-K, Exhibit 10.1.aj
10.1.i +	Form of Nonqualified Stock Option Agreement for Non-Employee Directors	AGL Resources	December 31, 2004, Form 10-K, Exhibit 10.1.ak
10.1.j +	Form of Director Indemnification Agreement dated April 28, 2004	AGL Resources	June 30, 2004, Form 10-Q, Exhibit 10.3
10.1.k +	Long-Term Incentive Plan, as amended and restated as of January 1, 2002	AGL Resources	March 31, 2002, Form 10-Q, Exhibit 99.2
10.1.l +	First amendment to the Long-Term Incentive Plan, as amended and restated	AGL Resources	December 31, 2004, Form 10-K, Exhibit 10.1.b
10.1.m +	Second amendment to the Long-Term Incentive Plan, as amended and restated	AGL Resources	June 30, 2007, Form 10-Q, Exhibit 10.1.l
10.1.n +	Third amendment to the Long-Term Incentive Plan, as amended and restated	AGL Resources	December 31, 2008, Form 10-K, Exhibit 10.1.ad
10.1.o +	Omnibus Performance Incentive Plan, as amended and restated	AGL Resources	March 14, 2011, Schedule 14A, Annex A
10.1.p +	Form of Restricted Stock Unit Agreement under Omnibus Performance Incentive Plan, as amended and Restated	AGL Resources	December 31, 2011, Form 10-K, Exhibit 10.1.ae
10.1.q +	Form of Restricted Stock Agreement under Omnibus Performance Incentive Plan, as amended and restated	AGL Resources	December 31, 2011, Form 10-K, Exhibit 10.1.af
10.1.r +	Form of Performance Share Unit Award under Omnibus Performance Incentive Plan, as amended and restated	AGL Resources	Filed herewith
10.1.s +	2007 Omnibus Performance Incentive Plan	AGL Resources	March 19, 2007, Schedule 14A, Annex A
10.1.t +	First Amendment to the 2007 Omnibus Performance Incentive Plan, as amended and restated	AGL Resources	December 31, 2008, Form 10-K, Exhibit 10.1.ai
10.1.u +	Form of Incentive Stock Option Agreement – 2007 Omnibus Performance Incentive Plan	AGL Resources	June 30, 2007, Form 10-Q, Exhibit 10.1.b
10.1.v +	Form of Nonqualified Stock Option Agreement – 2007 Omnibus Performance Incentive Plan	AGL Resources	June 30, 2007, Form 10-Q, Exhibit 10.1.c
10.1.w +	Form of Incentive Stock Option Agreement and Nonqualified Stock Option Agreement for key employees (LTIP)	AGL Resources	September 30, 2004, Form 10-Q, Exhibit 10.1
10.1.x +	Forms of Nonqualified Stock Option Agreement without the reload provision (LTIP)	AGL Resources	March 18, 2005, Form 8-K, Exhibit 10.1
10.1.y +	Form of Nonqualified Stock Option Agreement with the reload provision (Officer Incentive Plan)	AGL Resources	March 18, 2005, Form 8-K, Exhibit 10.2
10.1.z +	Nonqualified Savings Plan as amended and restated as of January 1, 2009	AGL Resources	December 31, 2008, Form 10-K, Exhibit 10.1.av
10.1.aa +	First Amendment to the Nonqualified Savings Plan	AGL Resources	Filed herewith
10.1.ab +	Second Amendment to the Nonqualified Savings Plan	AGL Resources	Filed herewith
10.1.ac +	Third Amendment to the Nonqualified Savings Plan	AGL Resources	Filed herewith
10.1.ad +	Description of Supplemental Executive Retirement Plan for John W. Somerhalder II	AGL Resources	December 31, 2008, Form 10-K, Exhibit 10.1.ay
10.1.ae +	Excess Benefit Plan as amended and restated as of January 1, 2009	AGL Resources	December 31, 2008, Form 10-K, Exhibit 10.1.az
10.1.af +	Form of Continuity Agreement dated December 19, 2013	AGL Resources	December 19, 2013, Form 8-K, Exhibit 10.1
10.1.ag +	Description of compensation for each of John W. Somerhalder II, Andrew W. Evans, Henry P. Linginfelter, Paul R. Shlanta and Peter I. Tumminello (our Named Executive Officers for the year ended December 31, 2013)	AGL Resources	Compensation Discussion and Analysis section of the AGL Resources Inc. Proxy Statement for the Annual Meeting of Shareholders held April 30, 2013 filed March 15, 2013.
10.2.a	Form of Commercial Paper Dealer Agreement	AGL Resources	September 30, 2000, Form 10-K, Exhibit 10.79

Glossary

103

Table of Contents

10.2.b	Guarantee dated October 5, 2000 of payments on promissory notes	AGL Resources	September 30, 2000, Form 10-K, Exhibit 10.80
10.4	Note Purchase Agreement dated August 31, 2011	AGL Resources	September 7, 2011, Form 8-K, Exhibit 10.1
10.5	Final Allocation Agreement dated January 3, 2008	Nicor	December 31, 2007, Form 10-K, Exhibit 10.64
10.6	Second Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC dated September 6, 2013 by and between Georgia Natural Gas Company and Piedmont Energy Company	AGL Resources	September 30, 2013, Form 10-Q, Exhibit 10
10.7	Credit Agreement dated as of December 15, 2011(1)	AGL Resources	December 15, 2011, Form 8-K, Exhibit 10.1
10.8.a	Amended and Restated Credit Agreement dated as of November 10, 2011(2)	AGL Resources	November 17, 2011, Form 8-K, Exhibit 10.1
10.8.b	Guarantee Agreement dated as of November 10, 2011	AGL Resources	November 17, 2011, Form 8-K, Exhibit 10.2
10.9	Bank Rate Mode Covenants Agreement, dated as of February 26, 2013	AGL Resources	March 1, 2013, Form 8-K, Exhibit 10.1
10.10	Loan Agreement dated as of February 1, 2013	AGL Resources	March 1, 2013, Form 8-K, Exhibit 10.2
10.11	Loan Agreement dated as of March 1, 2013	AGL Resources	March 27, 2013, Form 8-K, Exhibit 10.1
10.12	Amended and Restated Loan Agreement dated as of March 1, 2013	AGL Resources	March 27, 2013, Form 8-K, Exhibit 10.2
10.13	Amended and Restated Loan Agreement dated as of March 1, 2013	AGL Resources	March 27, 2013, Form 8-K, Exhibit 10.3
10.14	Amended and Restated Loan Agreement dated as of March 1, 2013	AGL Resources	March 27, 2013, Form 8-K, Exhibit 10.4
12	Statement of Computation of Ratio of Earnings to Fixed Charges	AGL Resources	Filed herewith
14	Code of Ethics for the Chief Executive Officer and Senior Financial Officers	AGL Resources	December 31, 2004, Form 10-K, Exhibit 14
21	Subsidiaries of AGL Resources Inc.	AGL Resources	Filed herewith
23	Consent of PricewaterhouseCoopers LLP	AGL Resources	Filed herewith
24	Powers of Attorney	AGL Resources	Included on signature page hereto
31.1	Certification of John W. Somerhalder II	AGL Resources	Filed herewith
31.2	Certification of Andrew W. Evans	AGL Resources	Filed herewith
32.1	Certification of John W. Somerhalder II	AGL Resources	Filed herewith
32.2	Certification of Andrew W. Evans	AGL Resources	Filed herewith
101.INS	XBRL Instance Document	AGL Resources	Filed herewith
101.SCH	XBRL Taxonomy Extension Schema	AGL Resources	Filed herewith
101.CAL	XBRL Taxonomy Extension Calculation Linkbase	AGL Resources	Filed herewith
101.DEF	XBRL Taxonomy Definition Linkbase	AGL Resources	Filed herewith
101.LAB	XBRL Taxonomy Extension Labels Linkbase	AGL Resources	Filed herewith
101.PRE	XBRL Taxonomy Extension Presentation Linkbase	AGL Resources	Filed herewith

+ Management contract, compensatory plan or arrangement.

)

In November 2013, the Credit Agreement commitment terms were extended to a maturity date of December 15, 2017 via an approved extension request.

)

In November 2013, the Amended and Restated Credit Agreement commitment terms were extended to a maturity date of November 10, 2017 via an approved extension request.

(b)	Exhibits filed as part of this report.

	See Item 15(a)(3).
(c)	Financial statement schedules filed as part of this report. See Item 15(a)(2).

Glossary

104

Table of Contents

SIGNATURES

In accordance with Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on February 6, 2014.

AGL RESOURCES INC.

By: /s/ John W. Somerhalder II

John W. Somerhalder II

Chairman, President and Chief Executive Officer

Power of Attorney

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints John W. Somerhalder II, Andrew W. Evans, Paul R. Shlanta and Bryan E. Seas, and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K for the year ended December 31, 2013, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite or necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated as of February 6, 2014.

Signatures	Title

/s/ John W. Somerhalder II	Chairman, President and Chief Executive Officer (Principal Executive Officer)
John W. Somerhalder II

/s/ Andrew W. Evans	Executive Vice President and Chief Financial Officer (Principal Financial Officer)
Andrew W. Evans

/s/ Bryan E. Seas	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)
Bryan E. Seas

/s/ Sandra N. Bane	Director
Sandra N. Bane

/s/ Thomas D. Bell, Jr.	Director
Thomas D. Bell, Jr.	Director

/s/ Norman R. Bobins	Director
Norman R. Bobins

/s/ Charles R. Crisp	Director
Charles R. Crisp	Director


/s/ Brenda J. Gaines	Director
Brenda J. Gaines

/s/ Arthur E. Johnson	Director
Arthur E. Johnson	Director


/s/ Wyck A. Knox, Jr.	Director
Wyck A. Knox, Jr.
/s/ Dennis M. Love Dennis M. Love	Director

/s/ Charles H. McTier	Director
Charles H. McTier

/s/ Dean R. O’Hare	Director
Dean R. O’Hare

/s/ Armando J. Olivera	Director
Armando J. Olivera

/s/ John E. Rau	Director
John E. Rau

/s/ James A. Rubright	Director
James A. Rubright

/s/ Bettina M. Whyte	Director
Bettina M. Whyte

/s/ Henry C. Wolf	Director
Henry C. Wolf

Glossary

105

Table of Contents

Schedule II

AGL Resources Inc. and Subsidiaries

VALUATION AND QUALIFYING ACCOUNTS - FOR EACH OF THE THREE YEARS IN THE PERIOD ENDED DECEMBER 31, 2013.

			Additions
In millions	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts		Deductions			Balance at end of period
2011
Allowance for uncollectible accounts	$	16	$	20	$	-	$	(19	)	$	17
Income tax valuation		3		-		-		-			3

2012
Allowance for uncollectible accounts	$	17	$	25	$	3	$	(17	)	$	28
Income tax valuation		3		-		19		-			22

2013
Allowance for uncollectible accounts	$	28	$	37	$	-	$	(36	)	$	29
Income tax valuation		22		-		-		-			22

Note 14 - Selected Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information [Table Text Block]

In millions, except per share amounts	March 31		June 30		September 30		December 31
2013
Operating revenues	$	1,709	$	904	$	675	$	1,329
Operating income		299		122		82		183
EBIT		304		129		89		181
Net income		164		50		28		89
Net income attributable to AGL Resources Inc.		154		49		28		82
Basic earnings per common share attributable to AGL Resources Inc. common shareholders		1.31		0.41		0.24		0.69
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders		1.31		0.41		0.24		0.68

2012
Operating revenues	$	1,404	$	686	$	614	$	1,218
Operating income		262		91		54		203
EBIT		266		100		60		208
Net income		139		35		9		103
Net income attributable to AGL Resources Inc.		130		34		9		98
Basic earnings per common share attributable to AGL Resources Inc. common shareholders		1.12		0.28		0.08		0.84
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders		1.11		0.28		0.08		0.84

2011
Operating revenues	$	878	$	375	$	295		$	790
Operating income		238		60		24			118
EBIT		239		62		25			121
Net income (loss)		134		19		(4	)		37
Net income (loss) attributable to AGL Resources Inc.		124		18		(3	)		33
Basic earnings (loss) per common share attributable to AGL Resources Inc. common shareholders		1.60		0.23		(0.04	)		0.37
Diluted earnings (loss) per common share attributable to AGL Resources Inc. common shareholders		1.59		0.23		(0.04	)		0.37

Note 3 - Regulated Operations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended									12 Months Ended	4 Months Ended		12 Months Ended		12 Months Ended							6 Months Ended	8 Months Ended				12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 Regulatory Income Tax Liability [Member]	Dec. 31, 2013 Benchmark [Member] Nicor Gas [Member]	Dec. 31, 2013 Through December 2014 [Member] Atlanta Gas Light [Member] Integrated Vintage Plastic Replacement Program [Member]	Dec. 31, 2013 January 2015 [Member] Atlanta Gas Light [Member] Integrated Vintage Plastic Replacement Program [Member]	Dec. 31, 2013 January 2016 [Member] Atlanta Gas Light [Member] Integrated Vintage Plastic Replacement Program [Member]	Dec. 31, 2012 Maximum per Year [Member] Virginia Natural Gas [Member] SAVE Program[Member]	Dec. 31, 2013 Nicor Gas [Member] Recoverable Pension And Other Retirement Benefit Costs [Member]	Dec. 31, 2013 Nicor Gas [Member] Second Energy Efficiency Plan [Member]	Dec. 31, 2013 Nicor Gas [Member]	Dec. 31, 2013 Atlanta Gas Light [Member] Seasonal Rates [Member]	Dec. 31, 2013 Atlanta Gas Light [Member] Integrated Vintage Plastic Replacement Program [Member]	Dec. 31, 2013 Atlanta Gas Light [Member]	Dec. 31, 2012 Atlanta Gas Light [Member]	Dec. 31, 2011 Atlanta Gas Light [Member]	Dec. 31, 2013 Elizabethtown Gas [Member] Enhanced Infrastructure Program [Member]	Jul. 31, 2012 Elizabethtown Gas [Member] Enhanced Infrastructure Program [Member]	May 31, 2011 Elizabethtown Gas [Member] Enhanced Infrastructure Program [Member]	Dec. 31, 2013 Elizabethtown Gas [Member] Natural Gas Distribution Utility Reinforcement Effort [Member]	Dec. 31, 2012 Virginia Natural Gas [Member] SAVE Program[Member]	Dec. 31, 2013 Virginia Natural Gas [Member] CARE Plan [Member]	Dec. 31, 2012 Virginia Natural Gas [Member] Maximum [Member] SAVE Program[Member]	Dec. 31, 2013 Recoverable Pension And Other Retirement Benefit Costs [Member]	Dec. 31, 2012 Recoverable Pension And Other Retirement Benefit Costs [Member]	Dec. 31, 2013 Recoverable ERC Assets [Member]	Dec. 31, 2012 Recoverable ERC Assets [Member]	Dec. 31, 2011 Recoverable ERC Assets [Member]	Dec. 31, 2013 Maximum [Member] Recoverable Pension And Other Retirement Benefit Costs [Member]	Dec. 31, 2013 Minimum [Member] Recoverable Pension And Other Retirement Benefit Costs [Member]
Note 3 - Regulated Operations (Details) [Line Items]
Costs Recovery Period										11 years			1 year																	21 years	2 years
Regulatory Assets, Current	$ 162	$ 145													$ 48										$ 9	$ 19	$ 45
Increase (Decrease) in Other Regulatory Assets	(2)	(37)	3																								24	13	5
Number of Sites with Cleanup Responsibility	26											23
Provision for Doubtful Accounts	21	23	31		63
Regulatory Assets, Noncurrent	737	944													87										99	196
Recovered Pipeline Replacement Revenue															49	51	48
Approved Infrastructure Replacement Program									25					275					115	40			2	105
Infrastructure Replacement Program Rider (in Dollars per Item)						0.48	0.96	1.45
Fair Value Inputs, Discount Rate																		6.65%
Filed Infrastructure Replacement Program																					15
Program Duration Period											3 years											5 years	3 years
Regulatory Noncurrent Liability, Amortization Period				30
Filed Program											$ 93

Note 2 - Significant Accounting Policies and Methods of Application (Details) - Changes in Amount of Goodwill (USD $) In Millions, unless otherwise specified	12 Months Ended			12 Months Ended				12 Months Ended				12 Months Ended		12 Months Ended				12 Months Ended				12 Months Ended		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Distribution Operations [Member] Nicor Gas [Member]	Dec. 31, 2013 Distribution Operations [Member]	Dec. 31, 2012 Distribution Operations [Member]	Dec. 31, 2011 Distribution Operations [Member]	Dec. 31, 2012 Retail Operations [Member] Nicor Gas [Member]	Dec. 31, 2013 Retail Operations [Member]	Dec. 31, 2012 Retail Operations [Member]	Dec. 31, 2011 Retail Operations [Member]	Dec. 31, 2012 Wholesale Services [Member] Nicor Gas [Member]	Dec. 31, 2011 Wholesale Services [Member]	Dec. 31, 2012 Midstream Operations [Member] Nicor Gas [Member]	Dec. 31, 2013 Midstream Operations [Member]	Dec. 31, 2012 Midstream Operations [Member]	Dec. 31, 2011 Midstream Operations [Member]	Dec. 31, 2012 Cargo Shipping [Member] Nicor Gas [Member]	Dec. 31, 2013 Cargo Shipping [Member]	Dec. 31, 2012 Cargo Shipping [Member]	Dec. 31, 2011 Cargo Shipping [Member]	Dec. 31, 2012 Other Segments [Member] Nicor Gas [Member]	Dec. 31, 2011 Other Segments [Member]	Dec. 31, 2012 Nicor Gas [Member]
Goodwill [Line Items]
Goodwill	$ 1,888	$ 1,837	$ 1,813		$ 1,640	$ 1,640	$ 1,586		$ 173	$ 122	$ 124		$ 2		$ 14	$ 14	$ 16		$ 61	$ 61	$ 77		$ 8	$ 1,423
Adjustments to Goodwill	$ 51			$ 54				$ (2)	$ 51			$ (2)		$ (2)				$ (16)				$ (8)		$ 24

Note 7 - Stock-Based Compensation (Details) - Compensation Costs, Tax Benefits and Excess Tax Benefits (USD $)
In Millions, unless otherwise specified

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Compensation Costs, Tax Benefits and Excess Tax Benefits [Abstract]

Compensation costs (1)

$ 22

^[1]

$ 9

^[1]

$ 14

^[1]

Income tax benefits (1)

^[1]

Excess tax benefits (2)

^[2]

$ 1

^[2]

$ 1

^[2]

[1]	Recorded in our Consolidated Statements of Income.
[2]	Recorded in our Consolidated Statements of Financial Position.

Note 8 - Debt and Credit Facilities (Tables)

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Schedule of Debt [Table Text Block]

				December 31, 2013					December 31, 2012
Dollars in millions	Year(s) due			Weighted average interest rate (1)			Outstanding		Weighted average interest rate (1)			Outstanding
Short-term debt
Commercial paper - AGL Capital (2)		2014			0.4	%	$	857		0.5	%	$	1,063
Commercial paper- Nicor Gas (2)		2014			0.3	%		314		0.4			314
Total short-term debt					0.4	%	$	1,171		0.5	%	$	1,377
Current portion of long-term debt and capital leases
Current portion of long-term debt		n/a			-			-		4.6			225
Current portion of capital leases		n/a			-			-		4.9			1
Total current portion of long-term debt and capital leases					-		$	-		4.6	%	$	226
Long-term debt - excluding current portion

Senior notes	2015	-	2043		5.0	%	$	2,825		5.1	%	$	2,325
First mortgage bonds	2016	-	2038		5.6			500		5.6			500
Gas facility revenue bonds	2022	-	2033		1.0			200		1.2			200
Medium-term notes	2017	-	2027		7.8			181		7.8			181
Total principal long-term debt					4.9	%	$	3,706		5.0	%	$	3,206
Fair value adjustment of long-term debt (3)	2016	-	2038	n/a				91	n/a				103
Unamortized debt premium, net		n/a		n/a				16	n/a				18
Total non-principal long-term debt				n/a				107	n/a				121
Total long-term debt							$	3,813				$	3,327
Total debt							$	4,984				$	4,930

Schedule of Maturities of Long-term Debt [Table Text Block]

Year	Amount (in millions)
2014	$	-
2015		200
2016		545
2017		22
2018		155
Thereafter		2,784
Total	$	3,706

Schedule of Capitalization [Table Text Block]

	AGL Resources						Nicor Gas
	December 31,						December 31,
	2013			2012			2013			2012
Debt-to-capitalization ratio		57	%		58	%		55	%		55	%

Note 9 - Equity (Details) - Reclassifications Out of Accumulated Other Comprehensive Loss (USD $)
In Millions, unless otherwise specified

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Cash flow hedges

Interest rate contracts

$ (181)

$ (184)

$ (136)

Total before income tax

522

450

311

Income tax benefit

191

164

125

Net of tax

154

130

(3)

124

313

271

172

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Natural Gas Derivatives [Member]

Cash flow hedges

Natural gas contracts

(1)

^[1]

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate Contract [Member]

Cash flow hedges

Interest rate contracts

(3)

^[1]

Total before income tax

(4)

^[1]

Income tax benefit

^[1]

Net of tax

(3)

^[1]

Accumulated Defined Benefit Plans Adjustment [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

Cash flow hedges

Total before income tax

(20)

^[1]

Income tax benefit

^[1]

Net of tax

(12)

^[1]

Retirement benefit plan amortization of

Actuarial losses

(25)

^[1],[2]

Prior service credits

^[1],[2]

Reclassification out of Accumulated Other Comprehensive Income [Member]

Cash flow hedges

Net of tax

$ (15)

^[1]

[1]	Amounts in parentheses indicate debits, or reductions, to profit/loss and credits to accumulated other comprehensive loss. Except for retirement benefit plan amounts, the profit/loss impacts are immediate.
[2]	Amortization of these accumulated other comprehensive loss components is included in the computation of net periodic benefit cost. See Note 5 for additional details about net periodic benefit cost.

Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2013

Valuation and Qualifying Accounts [Abstract]

Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]


			Additions
In millions	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts		Deductions			Balance at end of period
2011
Allowance for uncollectible accounts	$	16	$	20	$	-	$	(19	)	$	17
Income tax valuation		3		-		-		-			3

2012
Allowance for uncollectible accounts	$	17	$	25	$	3	$	(17	)	$	28
Income tax valuation		3		-		19		-			22

2013
Allowance for uncollectible accounts	$	28	$	37	$	-	$	(36	)	$	29
Income tax valuation		22		-		-		-			22

Note 2 - Significant Accounting Policies and Methods of Application (Details) - Expected Amortization Expense (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Expected Amortization Expense [Abstract]
2014	$ 16
2015	16
2016	16
2017	15
2018	$ 15

Note 2 - Significant Accounting Policies and Methods of Application (Details) - Credit Exposure (USD $)
In Millions, unless otherwise specified

12 Months Ended

Dec. 31, 2013

Credit Exposure [Abstract]

Credit exposure (in Dollars)

$ 274

^[1]

Credit exposure

51.00%

[1]	Our counterparties or the counterparties' guarantors had a weighted average S&P equivalent rating of A- at December 31, 2013.

Note 12 - Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

In millions	2013			2012			2011
Current income taxes
Federal	$	166		$	9		$	(89	)
State		35			4			1
Deferred income taxes
Federal		2			134			196
State		(9	)		20			18
Amortization of investment tax credits		(3	)		(3	)		(1	)
Total	$	191		$	164		$	125

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

In millions	2013			2012			2011
Computed tax expense at statutory rate	$	178		$	158		$	109
State income tax, net of federal income tax benefit		21			19			14
Sale of Compass Energy		6			-			-
Tax effect of net income attributable to the noncontrolling interest		(7	)		(6	)		(6	)
Amortization of investment tax credits		(3	)		(3	)		(1	)
Affordable housing credits		(2	)		(2	)		(1	)
Flexible dividend deduction		(2	)		(2	)		(2	)
Change in control payments		-			-			9
Merger transaction costs		-			-			3
Total income tax expense on Consolidated Statements of Income	$	191		$	164		$	125

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

	As of December 31,
In millions	2013			2012
Accumulated deferred income tax liabilities
Property - accelerated depreciation and other property-related items	$	1,613		$	1,533
Undistributed earnings of foreign subsidiaries		26			30
Investments in partnerships		18			26
Acquisition intangibles		15			26
Mark-to-market		-			22
Other		128			126
Total accumulated deferred income tax liabilities		1,800			1,763
Accumulated deferred income tax assets
Unfunded pension and retiree welfare benefit obligation		92			145
Deferred investment tax credits		7			9
Mark-to-market		4			-
Other		44			43
Total accumulated deferred income tax assets		147			197
Valuation allowances (1)		(14	)		(22	)
Total accumulated deferred income tax assets, net of valuation allowance		133			175
Net non-current accumulated deferred tax liability	$	1,667		$	1,588

Note 2 - Significant Accounting Policies and Methods of Application (Details) - Potentially Dilutive Common Share Calculation (USD $)
In Millions, except Per Share data, unless otherwise specified

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Potentially Dilutive Common Share Calculation [Abstract]

Net income attributable to AGL Resources Inc. (in Dollars)

$ 82

$ 28

$ 49

$ 154

$ 98

$ 9

$ 34

$ 130

$ 33

$ (3)

$ 18

$ 124

$ 313

$ 271

$ 172

Basic weighted average number of shares outstanding (1)

117.9

^[1]

117.0

^[1]

80.4

^[1]

Effect of dilutive securities

0.4

0.5

Diluted weighted average number of shares outstanding (2)

118.3

^[2]

117.5

^[2]

80.9

^[2]

Earnings per share

Basic (in Dollars per share)

$ 0.69

$ 0.24

$ 0.41

$ 1.31

$ 0.84

$ 0.08

$ 0.28

$ 1.12

$ 0.37

$ (0.04)

$ 0.23

$ 1.60

$ 2.65

$ 2.32

$ 2.14

Diluted (2) (in Dollars per share)

$ 0.68

$ 0.24

$ 0.41

$ 1.31

$ 0.84

$ 0.08

$ 0.28

$ 1.11

$ 0.37

$ (0.04)

$ 0.23

$ 1.59

$ 2.64

^[2]

$ 2.31

^[2]

$ 2.12

^[2]

[1]	Daily weighted average shares outstanding.
[2]	There were no outstanding stock options excluded from the computation of diluted earnings per common share attributable to AGL Resources Inc. for any of the periods presented because their effect would have been anti-dilutive, as the exercise prices were greater than the average market price.

Note 4 - Fair Value Measurements (Details) - Derivative Assets and Liabilities (USD $)
In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Fair Value, Inputs, Level 1 [Member] | Natural Gas Derivatives [Member]

Natural gas derivatives

Derivative Assets

$ 6

^[1]

$ 8

^[1]

Derivative Liabilities

(79)

(45)

Fair Value, Inputs, Level 2 [Member] | Natural Gas Derivatives [Member]

Natural gas derivatives

Derivative Assets

^[1]

Derivative Liabilities

(79)

(30)

Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract [Member]

Natural gas derivatives

Derivative Assets

^[1]

Netting [Member] | Natural Gas Derivatives [Member]

Natural gas derivatives

Derivative Assets

^[1]

Derivative Liabilities

Natural Gas Derivatives [Member]

Natural gas derivatives

Derivative Assets

116

^[1],[2],[3]

137

^[1],[2],[3]

Derivative Liabilities

$ (80)

^[2],[3]

$ (39)

^[2],[3]

[1]	$3 million of premium at December 31, 2013 and $4 million at December 31, 2012 associated with weather derivatives have been excluded as they are accounted for based on intrinsic value.
[2]	There were no significant unobservable inputs (Level 3) for any of the periods presented.
[3]	There were no significant transfers between Level 1, Level 2, or Level 3 for any of the periods presented.

Consolidated Statements of Equity (Parentheticals) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Dividends on common stock, per share	$ 1.88	$ 1.74	$ 1.90

Note 4 - Fair Value Measurements (Details) - Money Market Funds (Fair Value, Inputs, Level 1 [Member], USD $)
In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Fair Value, Inputs, Level 1 [Member]

Note 4 - Fair Value Measurements (Details) - Money Market Funds [Line Items]

Money market funds (1)

$ 48

^[1]

$ 66

^[1]

[1]	Carried at fair value and classified as Level 1 within the fair value hierarchy.

Note 4 - Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2013

Note 4 - Fair Value Measurements (Tables) [Line Items]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

	As of December 31,
In millions	2013		2012
Long-term debt carrying amount	$	3,813	$	3,553
Long-term debt fair value (1)		3,956		4,057

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

	Fair value measurements using significant unobservable inputs - Level 3 (1)
In millions	Global hedged equity			Absolute return		Private capital			Total
Balance at December 31, 2011	$	30		$	34	$	25		$	89
Gains included in changes in net assets		3			2		3			8
Purchases		15			-		-			15
Sales		(10	)		-		(5	)		(15	)
Balance at December 31, 2012	$	38		$	36	$	23		$	97
Gains included in changes in net assets		5			3		4			12
Purchases		-			-		-			-
Sales		-			-		(5	)		(5	)
Balance at December 31, 2013	$	43		$	39	$	22		$	104
(1) There were no transfers out of Level 3, or between Level 1 and Level 2 for any of the periods presented.

Natural Gas and Interest Rate Derivatives [Member]

Note 4 - Fair Value Measurements (Tables) [Line Items]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

	December 31, 2013					December 31, 2012
In millions	Assets (1)		Liabilities			Assets (1)		Liabilities
Natural gas derivatives
Quoted prices in active markets (Level 1)	$	6	$	(79	)	$	8	$	(45	)
Significant other observable inputs (Level 2)		67		(79	)		96		(30	)
Netting of cash collateral		43		78			33		36
Total carrying value (2) (3)	$	116	$	(80	)	$	137	$	(39	)
Interest rate derivatives
Significant other observable inputs (Level 2)	$	-	$	-		$	3	$	-

Natural Gas Derivatives [Member]

Note 4 - Fair Value Measurements (Tables) [Line Items]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

	December 31, 2013
	Pension plans (1)															Welfare plans
In millions	Level 1			Level 2			Level 3			Total			% of total			Level 1			Level 2			Level 3			Total			% of total
Cash	$	3		$	1		$	-		$	4			-	%	$	1		$	-		$	-		$	1			1	%
Equity securities
U.S. large cap (2)		93			205			-			298			33	%		-			52			-			52			62	%
U.S. small cap (2)		72			29			-			101			11	%		-			-			-			-			-	%
International companies (3)		-			139			-			139			15	%		-			14			-			14			17	%
Emerging markets (4)		-			34			-			34			4	%		-			-			-			-			-	%
Fixed income securities
Corporate bonds (5)		-			207			-			207			23	%		-			17			-			17			20	%
Other (or gov’t/muni bonds)		-			29			-			29			3	%		-			-			-			-			-	%
Other types of investments
Global hedged equity (6)		-			-			43			43			5	%		-			-			-			-			-	%
Absolute return (7)		-			-			39			39			4	%		-			-			-			-			-	%
Private capital (8)		-			-			22			22			2	%		-			-			-			-			-	%
Total assets at fair value	$	168		$	644		$	104		$	916			100	%	$	1		$	83		$	-		$	84			100	%
% of fair value hierarchy		19	%		70	%		11	%		100	%					1	%		99	%		-	%		100	%

	December 31, 2012
	Pension plans (1)															Welfare plans
In millions	Level 1			Level 2			Level 3			Total			% of total			Level 1			Level 2			Level 3			Total			% of total
Cash	$	14		$	2		$	-		$	16			2	%	$	1		$	-		$	-		$	1			1	%
Equity securities
U.S. large cap (2)		69			181			-			250			30	%		-			38			-			38			55	%
U.S. small cap (2)		60			22			-			82			10	%		-			-			-			-			-	%
International companies (3)		-			120			-			120			14	%		-			12			-			12			18	%
Emerging markets (4)		-			34			-			34			4	%		-			-			-			-			-	%
Fixed income securities
Corporate bonds (5)		-			216			-			216			26	%		-			18			-			18			26	%
Other (or gov’t/muni bonds)		-			30			-			30			3	%		-			-			-			-			-	%
Other types of investments
Global hedged equity (6)		-			-			38			38			4	%		-			-			-			-			-	%
Absolute return (7)		-			-			36			36			4	%		-			-			-			-			-	%
Private capital (8)		-			-			23			23			3	%		-			-			-			-			-	%
Total assets at fair value	$	143		$	605		$	97		$	845			100	%	$	1		$	68		$	-		$	69			100	%
% of fair value hierarchy		17	%		72	%		11	%		100	%					1	%		99	%		-	%		100	%

Money Market Funds [Member]

Note 4 - Fair Value Measurements (Tables) [Line Items]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

In millions		2013				2012
Money market funds (1)		$	48			$	66

Note 3 - Regulated Operations (Tables)

12 Months Ended

Dec. 31, 2013

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets [Table Text Block]

In millions	2013		2012
Regulatory assets
Recoverable regulatory infrastructure program costs	$	48	$	47
Recoverable ERC		45		38
Recoverable pension and retiree welfare benefit costs		9		19
Other		60		41
Total regulatory assets - current		162		145
Recoverable ERC		433		438
Recoverable pension and retiree welfare benefit costs		99		196
Recoverable regulatory infrastructure program costs		87		167
Long-term debt fair value adjustment		82		90
Other		36		53
Total regulatory assets - long-term		737		944
Total regulatory assets	$	899	$	1,089
Regulatory liabilities
Accrued natural gas costs	$	92	$	93
Bad debt over collection		41		37
Accumulated removal costs		27		16
Other		23		15
Total regulatory liabilities - current		183		161
Accumulated removal costs		1,445		1,393
Regulatory income tax liability		27		27
Unamortized investment tax credit		26		29
Bad debt over collection		17		17
Other		3		11
Total regulatory liabilities - long-term		1,518		1,477
Total regulatory liabilities	$	1,701	$	1,638

Environmental Exit Costs by Cost [Table Text Block]

In millions	# of sites		Probabilistic model cost estimates (2)						Engineering estimates (2)		Amount recorded		Expected costs over next 12 months		Cost recovery period
Illinois (1)		24	$	209		-	$	458	$	42	$	251	$	38			As incurred (3)
New Jersey		6		139		-		233		6		145		18		7	years (3)
Georgia and Florida		13		28		-		112		8		40		7		5	years
North Carolina		1			n/a					11		11		7			No recovery
Total		44	$	376		-	$	803	$	67	$	447	$	70

Schedule of Valuation Allowance for Impairment of Recognized Servicing Assets [Table Text Block]

					Amount refunded in				Amount to be refunded in
In millions	Bad debt experience		Total refund		2012		2013		2014		2015
2013	$	21	$	42	$	-	$	-	$	25	$	17
2012		23		40		-		24		16		-
2011		31		32		19		13		-		-

Note 3 - Regulated Operations (Details) - Costs Related to Remediation of Former Operating Sites (USD $) In Millions, unless otherwise specified						12 Months Ended				12 Months Ended					12 Months Ended								12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Illinois Environmental [Member] Engineering Estimates [Member]	Dec. 31, 2013 Illinois Environmental [Member] Amount Recorded [Member]	Dec. 31, 2013 Illinois Environmental [Member]	Dec. 31, 2013 Illinois Environmental [Member] Minimum [Member]	Dec. 31, 2013 Illinois Environmental [Member] Maximum [Member]	Dec. 31, 2013 New Jersey Environmental [Member] Engineering Estimates [Member]	Dec. 31, 2013 New Jersey Environmental [Member] Amount Recorded [Member]	Dec. 31, 2013 New Jersey Environmental [Member]	Dec. 31, 2013 New Jersey Environmental [Member] Minimum [Member]	Dec. 31, 2013 New Jersey Environmental [Member] Maximum [Member]	Dec. 31, 2013 Georgia And Florida [Member] Engineering Estimates [Member]	Dec. 31, 2013 Georgia And Florida [Member] Amount Recorded [Member]	Dec. 31, 2013 Georgia And Florida [Member]	Dec. 31, 2013 Georgia And Florida [Member] Minimum [Member]	Dec. 31, 2013 Georgia And Florida [Member] Maximum [Member]	Dec. 31, 2013 North Carolina Environmental [Member] Engineering Estimates [Member]	Dec. 31, 2013 North Carolina Environmental [Member] Amount Recorded [Member]	Dec. 31, 2013 North Carolina Environmental [Member]	Dec. 31, 2013 Engineering Estimates [Member]	Dec. 31, 2013 Amount Recorded [Member]	Dec. 31, 2013 Minimum [Member]	Dec. 31, 2013 Maximum [Member]
Environmental Exit Cost [Line Items]
# of sites	44				24					6					13					1
Probabilistic model cost estimates, low estimate						$ 209					$ 139					$ 28							$ 376
Probabilistic model cost estimates, high estimate							458					233					112							803
Engineering estimates			42	251				6	145				8	40				11	11		67	447
Amount recorded			42	251				6	145				8	40				11	11		67	447
Expected costs over next 12 months	$ 70	$ 57			$ 38					$ 18					$ 7					$ 7
Cost recovery period										7 years					5 years

Note 5 - Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]

	December 31,
In Bcf (1)	2013 (2)			2012
Hedge designation
Cash flow hedges		6			6
Not designated as hedges		183			96
Total hedges		189			102
Hedge position
Short position		(2,622	)		(1,955	)
Long position		2,811			2,057
Net long position		189			102

In millions	2013			2012
Nicor Gas	$	4		$	(35	)
Elizabethtown Gas	$	(6	)	$	(28	)

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

		December 31, 2013						December 31, 2012
In millions	Classification	Assets			Liabilities			Assets			Liabilities
Designated as cash flow hedges and fair value hedges
Natural gas contracts	Current	$	3		$	(1	)	$	1		$	(2	)
Interest rate swap agreements	Current		-			-			3			-
Total			3			(1	)		4			(2	)

Not designated as cash flow hedges
Natural gas contracts	Current		691			(761	)		394			(355	)
Natural gas contracts	Long-term		206			(220	)		45			(50	)
Total			897			(981	)		439			(405	)
Gross amount of recognized assets and liabilities (1)			900			(982	)		443			(407	)
Gross amounts offset in our Consolidated Statements of Financial Position (2)			(781	)		902			(299	)		368
Net amounts of assets and liabilities presented in ourConsolidated Statements of Financial Position (3)		$	119		$	(80	)	$	144		$	(39	)

Schedule of Derivative Instruments [Table Text Block]

	December 31,
In millions	2013			2012			2011

Designated as cash flow hedges
Natural gas contracts - loss reclassified from OCI to cost of goods sold	$	(1	)	$	(5	)	$	(6	)
Interest rate swaps – gain (loss) reclassified from OCI to interest expense		(3	)		(4	)		2
Income tax benefit		1			3			1
Net of tax		(3	)		(6	)		(3	)

Not designated as hedges
Natural gas contracts - net fair value adjustments recorded in operating revenues (1)		(90	)		34			40
Natural gas contracts - net fair value adjustments recorded in cost of goods sold (2)		2			(4	)		(4	)
Income tax benefit (expense)		34			(11	)		(14	)
Net of tax		(54	)		19			22
Total (losses) gains on derivative instruments, net of tax	$	(57	)	$	13		$	19

Note 6 - Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2013

Compensation and Retirement Disclosure [Abstract]

Schedule of Net Benefit Costs [Table Text Block]

	Pension plans									Welfare plans
Dollars in millions	2013			2012			2011			2013			2012			2011
Service cost	$	29		$	28		$	14		$	3		$	4		$	1
Interest cost		43			44			29			14			16			6
Expected return on plan assets		(62	)		(64	)		(33	)		(6	)		(5	)		(5	)
Net amortization of prior service credit		(2	)		(2	)		(2	)		(5	)		(3	)		(4	)
Recognized actuarial loss		35			34			14			8			9			2
Net periodic benefit cost	$	43		$	40		$	22		$	14		$	21		$	-
Assumptions used to determine benefit costs
Discount rate (1)		4.2	%		4.6	%		5.4	%		4.0	%		4.5	%		5.2	%
Expected return on plan assets (1)		7.8	%		8.4	%		8.5	%		7.8	%		8.5	%		8.2	%
Rate of compensation increase (1)		3.7	%		3.7	%		3.7	%		3.8	%		3.8	%		3.7	%
Pension band increase (2)		2.0	%		2.0	%		2.0	%	n/a			n/a			n/a

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

	Pension plans						Welfare plans
Dollars in millions	2013			2012			2013			2012
Change in plan assets
Fair value of plan assets, January 1,	$	837		$	754		$	77		$	67
Actual return on plan assets		134			101			16			10
Employee contributions		-			-			3			1
Employer contributions		1			42			19			17
Benefits paid		(65	)		(59	)		(23	)		(19	)
Medicare Part D reimbursements		-			-			1			1
Plan curtailment and settlements		-			(1	)		-			-
Fair value of plan assets, December 31,	$	907		$	837		$	93		$	77
Change in benefit obligation
Benefit obligation, January 1,	$	1,046		$	968		$	354		$	397
Service cost		29			28			3			4
Interest cost		43			44			14			17
Actuarial loss (gain)		(93	)		66			(26	)		(22	)
Plan amendments		-			-			-			(25	)
Medicare Part D reimbursements		-			-			1			1
Benefits paid		(65	)		(59	)		(23	)		(19	)
Employee contributions		-			-			3			1
Plan curtailment and settlements		-			(1	)		-			-
Benefit obligation, December 31,	$	960		$	1,046		$	326		$	354
Funded status at end of year	$	(53	)	$	(209	)	$	(233	)	$	(277	)
Amounts recognized in the Consolidated Statements of Financial Position consist of
Long-term asset	$	117		$	33		$	-		$	-
Current liability		(2	)		(2	)		-			(12	)
Long-term liability		(168	)		(240	)		(233	)		(265	)
Total liability at December 31,	$	(53	)	$	(209	)	$	(233	)	$	(277	)
Accumulated benefit obligation (1)	$	902		$	983		n/a			n/a
Assumptions used to determine benefit obligations
Discount rate		5.0	%		4.2	%		4.7	%		4.0	%
Rate of compensation increase		3.7	%		3.7	%		3.7	%		3.7	%
Pension band increase (2)		2.0	%		2.0	%	n/a			n/a

Schedule of Health Care Cost Trend Rates [Table Text Block]

	2013			2012
Health care cost trend rate assumed for next year		8.4	%		8.4	%
Ultimate rate to which the cost trend rate is assumed to decline		4.5	%		4.5	%
Year that reaches ultimate trend rate	2030			2030

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]

In millions	Effect on service and interest cost		Effect on benefit obligation
1% Health care cost trend rate increase	$	-	$	15
1% Health care cost trend rate decrease		-		(13	)

Schedule of Net Periodic Benefit Cost Not yet Recognized [Table Text Block]

	Net regulatory assets					Accumulated OCI						Total
In millions	Pension plans		Welfare plans			Pension plans			Welfare plans			Pension plans			Welfare plans

December 31, 2013:
Prior service credit	$	-	$	(20	)	$	(9	)	$	-		$	(9	)	$	(20	)
Net loss		61		60			210			30			271			90
Total	$	61	$	40		$	201		$	30		$	262		$	70
December 31, 2012:
Prior service cost (credit)	$	-	$	(24	)	$	(11	)	$	(2	)	$	(11	)	$	(26	)
Net loss		146		83			324			52			470			135
Total	$	146	$	59		$	313		$	50		$	459		$	109

Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year [Table Text Block]

	Net Regulatory Asset					Accumulated OCI					Total
In millions	Pension plans		Welfare plans			Pension plans			Welfare plans		Pension plans			Welfare plans
Amortization of prior service credit	$	-	$	(3	)	$	(2	)	$	-	$	(2	)	$	(3	)
Amortization of net loss		7		4			13			2		20			6

Schedule of Expected Benefit Payments [Table Text Block]

In millions	Pension plans		Welfare plans
2014	$	56	$	20
2015		60		20
2016		63		21
2017		66		22
2018		68		23
2019 - 2023		366		123

Note 7 - Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan [Table Text Block]

In millions	2013		2012		2011
Compensation costs (1)	$	22	$	9	$	14
Income tax benefits (1)		1		1		1
Excess tax benefits (2)		-		1		1

Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]

	Number of options			Weighted average exercise price		Weighted average remaining life (in years)		Aggregate intrinsic value (in millions)
Outstanding - December 31, 2010		2,229,112		$	34.85
Granted		1,685			42.19
Exercised		(383,646	)		31.11
Forfeited		(23,997	)		37.70
Outstanding - December 31, 2011		1,823,154		$	35.61
Granted		-			-
Exercised		(234,844	)		32.07
Forfeited		(59,720	)		37.34
Outstanding - December 31, 2012 (1)		1,528,590		$	36.09		3.7	$	6
Granted		-			-		-
Exercised		(617,358	)		35.37		2.3
Forfeited		(12,500	)		38.36		2.6
Outstanding - December 31, 2013 (1) (2)		898,732		$	36.55		3.0	$	10

Schedule of Nonvested Performance-based Units Activity [Table Text Block]

In millions	Measurement period end date	Fair value accrued at December 31, 2013		Maximum aggregate payout
Granted in 2011	December 31, 2013	$	7	$	12
Granted in 2012	December 31, 2014	$	6	$	18
Granted in 2013	December 31, 2015	$	3	$	18

Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity [Table Text Block]

	Shares of restricted stock			Weighted average remaining vesting period (in years)		Weighted average fair value
Outstanding - December 31, 2011 (1)		477,354				$	34.40
Issued		268,840					40.08
Forfeited		(28,829	)				39.07
Vested		(214,274	)				36.45
Outstanding - December 31, 2012 (1)		503,091			1.8	$	39.44
Issued		175,935			2.8		42.41
Forfeited		(33,352	)		2.0		40.64
Vested		(204,421	)		0.0		38.71
Outstanding - December 31, 2013 (1)		441,253			1.8	$	40.82

Schedule of Share-based Compensation, Employee Stock Purchase Plan, Activity [Table Text Block]

	2013		2012		2011
Shares purchased on the open market		103,343		108,132		65,843
Average per-share purchase price	$	42.96	$	38.96	$	40.55
Total purchase price discount	$	664,286	$	618,278	$	401,346

Note 8 - Debt and Credit Facilities (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended	12 Months Ended							12 Months Ended										0 Months Ended
	May 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 Target ratio [Member] Minimum [Member]	Dec. 31, 2013 Target ratio [Member] Maximum [Member]	Dec. 31, 2013 Commercial Paper [Member] AGL Capital [Member]	Dec. 31, 2013 Commercial Paper [Member] Nicor Gas [Member]	Dec. 31, 2013 Commercial Paper [Member]	Dec. 31, 2013 Commercial Paper [Member] Minimum [Member]	Dec. 31, 2013 Commercial Paper [Member] Maximum [Member]	Mar. 31, 2013 Refinanced [Member] Debt Issued By New Jersey Economic Development Authority [Member] Gas Facility Revenue Bonds [Member]	Mar. 31, 2013 Refinanced [Member] Debt Issued by Brevard County Florida [Member] Gas Facility Revenue Bonds [Member]	Mar. 31, 2013 Refinanced [Member] Refunding Bonds [Member] Gas Facility Revenue Bonds [Member]	Mar. 31, 2013 Refinanced [Member] Purchase of Existing Bonds [Member] Gas Facility Revenue Bonds [Member]	Mar. 31, 2013 Refinanced [Member] Gas Facility Revenue Bonds [Member]	Dec. 31, 2013 Preferred Class A [Member]	Dec. 31, 2012 Preferred Class A [Member]	May 31, 2013 Senior Notes [Member]	Dec. 31, 2013 Senior Notes [Member]	Dec. 31, 2012 Senior Notes [Member]	May 31, 2011 Senior Notes [Member]	Dec. 31, 2013 Gas Facility Revenue Bonds [Member]	Dec. 31, 2012 Gas Facility Revenue Bonds [Member]	Nov. 30, 2013 AGL and Nicor Gas Credit Facilities [Member]	Dec. 31, 2013 Maximum [Member]
Note 8 - Debt and Credit Facilities (Details) [Line Items]
Debt Instrument, Interest Rate, Effective Percentage							0.40%	0.30%
Debt Instrument, Term										1 day	123 days								30 years
Debt Instrument, Remaining Maturity Term										2 days	99 days
Proceeds from (Repayments of) Commercial Paper		$ (206)	$ 56	$ 91
Proceeds from Short-term Debt, Maturing in More than Three Months									374
Repayments of Short-term Debt, Maturing in More than Three Months									181
Extension Term																									1 year
Proceeds from Issuance of Long-term Debt																			500
Debt Instrument, Interest Rate, Stated Percentage																			4.40%			6.40%
Repayments of Senior Debt	225	225		300
Long-term Debt		$ 3,813	$ 3,327									$ 180	$ 20	$ 60	$ 140	$ 200				$ 2,825	$ 2,325		$ 200	$ 200
Ratio of Indebtedness to Net Capital					0.50	0.60																				0.70
Preferred Stock, Shares Authorized (in Shares)		10	10														10	10

Note 10 - Non-Wholly Owned Entities (Tables)

12 Months Ended

Dec. 31, 2013

Noncontrolling Interest [Abstract]

Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Table Text Block]

	December 31, 2013							December 31, 2012
In millions	Consolidated		SouthStar (1)		% (2)			Consolidated		SouthStar (1)		% (2)
Current assets	$	2,733	$	264		10	%	$	2,668	$	201		8	%
Goodwill and other intangible assets		2,061		139		7			1,933		-		-
Long-term assets and other deferred debit		9,862		12		-			9,540		10		-
Total assets	$	14,656	$	415		3	%	$	14,141	$	211		1	%
Current liabilities	$	3,122	$	95		3	%	$	3,338	$	62		2	%
Long-term liabilities and other deferred credits		7,858		-		-			7,368		-		-
Total Liabilities		10,980		95		1			10,706		62		1
Equity		3,676		320		9			3,435		149		4
Total liabilities and equity	$	14,656	$	415		3	%	$	14,141	$	211		1	%

Schedule of Variable Interest Entities [Table Text Block]

	December 31,
In millions	2013		2012
Operating revenues	$	687	$	576
Operating expenses
Cost of goods sold		491		411
Operation and maintenance		72		63
Depreciation and amortization		5		2
Taxes other than income taxes		1		2
Total operating expenses		569		478
Operating income	$	118	$	98

Equity Method Investments [Table Text Block]

In millions	2013		2012
Triton	$	70	$	73
Horizon Pipeline		15		17
Other (1)		1		9
Total	$	86	$	99

Note 5 - Derivative Instruments (Details) - Net Long Natural Gas Contracts

Dec. 31, 2013

ft3

Dec. 31, 2012

ft3

Hedge designation

Cash flow hedges

6,000,000,000

^[1],[2]

6,000,000,000

^[1]

Not designated as hedges

183,000,000,000

^[1],[2]

96,000,000,000

^[1]

Total hedges

189,000,000,000

^[1],[2]

102,000,000,000

^[1]

Hedge position

Short position

(2,622,000,000,000)

^[1],[2]

(1,955,000,000,000)

^[1]

Long position

2,811,000,000,000

^[1],[2]

2,057,000,000,000

^[1]

Net long position

189,000,000,000

^[1],[2]

102,000,000,000

^[1]

[1]	Volumes related to Nicor Gas exclude variable-priced contracts, which are accounted for as derivatives, but whose fair values are not directly impacted by changes in commodity prices.
[2]	Approximately 97% of these contracts have durations of two years or less and the remaining 3% expire between two and six years.

Note 12 - Income Taxes

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

Note 12 - Income Taxes

Income Tax Expense

In millions	2013			2012			2011
Current income taxes
Federal	$	166		$	9		$	(89	)
State		35			4			1
Deferred income taxes
Federal		2			134			196
State		(9	)		20			18
Amortization of investment tax credits		(3	)		(3	)		(1	)
Total	$	191		$	164		$	125

In millions	2013			2012			2011
Computed tax expense at statutory rate	$	178		$	158		$	109
State income tax, net of federal income tax benefit		21			19			14
Sale of Compass Energy		6			-			-
Tax effect of net income attributable to the noncontrolling interest		(7	)		(6	)		(6	)
Amortization of investment tax credits		(3	)		(3	)		(1	)
Affordable housing credits		(2	)		(2	)		(1	)
Flexible dividend deduction		(2	)		(2	)		(2	)
Change in control payments		-			-			9
Merger transaction costs		-			-			3
Total income tax expense on Consolidated Statements of Income	$	191		$	164		$	125

Accumulated Deferred Income Tax Assets and Liabilities

We have provided a valuation allowance for some of these items that reduce our net deferred tax assets to amounts we believe are more likely than not to be realized in future periods. With respect to our continuing operations, we have net operating losses in various jurisdictions. Components that give rise to the net accumulated deferred income tax liability are as follows.

	As of December 31,
In millions	2013			2012
Accumulated deferred income tax liabilities
Property - accelerated depreciation and other property-related items	$	1,613		$	1,533
Undistributed earnings of foreign subsidiaries		26			30
Investments in partnerships		18			26
Acquisition intangibles		15			26
Mark-to-market		-			22
Other		128			126
Total accumulated deferred income tax liabilities		1,800			1,763
Accumulated deferred income tax assets
Unfunded pension and retiree welfare benefit obligation		92			145
Deferred investment tax credits		7			9
Mark-to-market		4			-
Other		44			43
Total accumulated deferred income tax assets		147			197
Valuation allowances (1)		(14	)		(22	)
Total accumulated deferred income tax assets, net of valuation allowance		133			175
Net non-current accumulated deferred tax liability	$	1,667		$	1,588

(1)

Tax Benefits

Note 11 - Commitments, Guarantees and Contingencies (Tables)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Contractual Obligation, Fiscal Year Maturity Schedule [Table Text Block]

													2019 &
In millions	Total		2014		2015		2016		2017		2018		thereafter
Recorded contractual obligations:

Long-term debt (1)	$	3,706	$	-	$	200	$	545	$	22	$	155	$	2,784
Short-term debt		1,171		1,171		-		-		-		-		-
Environmental remediation liabilities (2)		447		70		82		80		48		63		104
Pipeline replacement program costs (2)		5		5		-		-		-		-		-
Total	$	5,329	$	1,246	$	282	$	625	$	70	$	218	$	2,888

Unrecorded contractual obligations and commitments(3) (8):

Pipeline charges, storage capacity and gas supply (4)	$	2,298	$	733	$	507	$	299	$	138	$	102	$	519
Interest charges (5)		2,899		185		175		161		147		145		2,086
Operating leases (6)		233		39		34		28		25		18		89
Asset management agreements (7)		19		8		5		4		2		-		-
Standby letters of credit, performance/surety bonds (8)		29		29		-		-		-		-		-
Other		15		6		3		3		2		1		-
Total	$	5,493	$	1,000	$	724	$	495	$	314	$	266	$	2,694

Note 14 - Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information [Text Block]

Note 14 - Selected Quarterly Financial Data (Unaudited)

In millions, except per share amounts	March 31		June 30		September 30		December 31
2013
Operating revenues	$	1,709	$	904	$	675	$	1,329
Operating income		299		122		82		183
EBIT		304		129		89		181
Net income		164		50		28		89
Net income attributable to AGL Resources Inc.		154		49		28		82
Basic earnings per common share attributable to AGL Resources Inc. common shareholders		1.31		0.41		0.24		0.69
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders		1.31		0.41		0.24		0.68

2012
Operating revenues	$	1,404	$	686	$	614	$	1,218
Operating income		262		91		54		203
EBIT		266		100		60		208
Net income		139		35		9		103
Net income attributable to AGL Resources Inc.		130		34		9		98
Basic earnings per common share attributable to AGL Resources Inc. common shareholders		1.12		0.28		0.08		0.84
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders		1.11		0.28		0.08		0.84

2011
Operating revenues	$	878	$	375	$	295		$	790
Operating income		238		60		24			118
EBIT		239		62		25			121
Net income (loss)		134		19		(4	)		37
Net income (loss) attributable to AGL Resources Inc.		124		18		(3	)		33
Basic earnings (loss) per common share attributable to AGL Resources Inc. common shareholders		1.60		0.23		(0.04	)		0.37
Diluted earnings (loss) per common share attributable to AGL Resources Inc. common shareholders		1.59		0.23		(0.04	)		0.37

Note 7 - Stock-Based Compensation

12 Months Ended

Dec. 31, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

Note 7 – Stock-Based Compensation

General

Accounting Treatment and Compensation Expense

●

stock options;

●

stock and restricted stock awards; and

●

performance units (restricted stock units, performance share units and performance cash units).

Performance-based stock awards and performance units contain market conditions. Stock options, restricted stock awards and performance units also contain a service condition.

We have granted incentive and nonqualified stock options with a strike price equal to the fair market value on the date of the grant. Fair market value is defined under the terms of the applicable plans as the closing price per share of AGL Resources common stock for the trading day immediately preceding the grant date, as reported in The Wall Street Journal. Stock options generally have a three-year vesting period.

The following table provides additional information related to our cash and stock-based compensation awards.

In millions	2013		2012		2011
Compensation costs (1)	$	22	$	9	$	14
Income tax benefits (1)		1		1		1
Excess tax benefits (2)		-		1		1

(1)

Recorded in our Consolidated Statements of Income.

(2)

Recorded in our Consolidated Statements of Financial Position.

Incentive and Nonqualified Stock Options

Stock Options

	Number of options			Weighted average exercise price		Weighted average remaining life (in years)		Aggregate intrinsic value (in millions)
Outstanding - December 31, 2010		2,229,112		$	34.85
Granted		1,685			42.19
Exercised		(383,646	)		31.11
Forfeited		(23,997	)		37.70
Outstanding - December 31, 2011		1,823,154		$	35.61
Granted		-			-
Exercised		(234,844	)		32.07
Forfeited		(59,720	)		37.34
Outstanding - December 31, 2012 (1)		1,528,590		$	36.09		3.7	$	6
Granted		-			-		-
Exercised		(617,358	)		35.37		2.3
Forfeited		(12,500	)		38.36		2.6
Outstanding - December 31, 2013 (1) (2)		898,732		$	36.55		3.0	$	10

(1)

All options outstanding at December 31, 2013 and 2012 were exercisable.

(2)

The range of exercise prices for the options outstanding at December 31, 2013 was $30.70 to $43.85.

Performance Units

Restricted Stock Units In general, a restricted stock unit is an award that represents the opportunity to receive a specified number of shares of our common stock, subject to the achievement of certain pre-established performance criteria. In 2013, we granted 43,830 restricted stock units to certain employees, all of which were outstanding as of December 31, 2013. These restricted stock units had a performance measurement period that ended December 31, 2013. The performance measure, which related to earnings before interest, income tax, depreciation and amortization, was met. As such, the related restricted stock awards will occur in 2014.

Performance Share Unit Awards A performance share unit award represents the opportunity to receive cash and shares subject to the achievement of certain pre-established performance criteria. We granted performance share unit awards to certain officers. These awards have a performance measure that relates to the Company’s relative total shareholder return relative to a group of peer companies. The recorded liability and maximum potential liability related to the 2013, 2012 and 2011 grants are as follows:

In millions	Measurement period end date	Fair value accrued at December 31, 2013		Maximum aggregate payout
Granted in 2011	December 31, 2013	$	7	$	12
Granted in 2012	December 31, 2014	$	6	$	18
Granted in 2013	December 31, 2015	$	3	$	18

Stock and Restricted Stock Awards

Stock Awards -Non-Employee Directors Non-employee director compensation may be paid in shares of our common stock in connection with initial election, the annual retainer, and chair retainers, as applicable. Stock awards for non-employee directors are 100% vested and non-forfeitable as of the date of grant. During 2013 we issued 26,915 shares with a weighted average fair value of $44.04 to our non-employee directors.

Restricted Stock Awards -Employees The following table summarizes the restricted stock awards activity for our employees during the last two years.

	Shares of restricted stock			Weighted average remaining vesting period (in years)		Weighted average fair value
Outstanding - December 31, 2011 (1)		477,354				$	34.40
Issued		268,840					40.08
Forfeited		(28,829	)				39.07
Vested		(214,274	)				36.45
Outstanding - December 31, 2012 (1)		503,091			1.8	$	39.44
Issued		175,935			2.8		42.41
Forfeited		(33,352	)		2.0		40.64
Vested		(204,421	)		0.0		38.71
Outstanding - December 31, 2013 (1)		441,253			1.8	$	40.82

(1)

Subject to restriction.

Employee Stock Purchase Plan (ESPP)

	2013		2012		2011
Shares purchased on the open market		103,343		108,132		65,843
Average per-share purchase price	$	42.96	$	38.96	$	40.55
Total purchase price discount	$	664,286	$	618,278	$	401,346

Schedule II - Valuation and Qualifying Accounts (Details) - Valuation and Qualifying Accounts (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013 Allowance for Doubtful Accounts [Member]	Dec. 31, 2012 Allowance for Doubtful Accounts [Member]	Dec. 31, 2011 Allowance for Doubtful Accounts [Member]	Dec. 31, 2012 Valuation Allowance of Deferred Tax Assets [Member]	Dec. 31, 2013 Valuation Allowance of Deferred Tax Assets [Member]	Dec. 31, 2010 Valuation Allowance of Deferred Tax Assets [Member]
Valuation Allowance [Line Items]
Balance at beginning of period	$ 28	$ 17	$ 16	$ 3	$ 22	$ 3
Charged to costs and expenses	37	25	20
Charged to other accounts		3		19
Deductions	(36)	(17)	(19)
Balance at end of period	$ 29	$ 28	$ 17	$ 22	$ 22	$ 3

Note 8 - Debt and Credit Facilities

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Debt Disclosure [Text Block]

Note 8 - Debt and Credit Facilities

				December 31, 2013					December 31, 2012
Dollars in millions	Year(s) due			Weighted average interest rate (1)			Outstanding		Weighted average interest rate (1)			Outstanding
Short-term debt
Commercial paper - AGL Capital (2)		2014			0.4	%	$	857		0.5	%	$	1,063
Commercial paper- Nicor Gas (2)		2014			0.3	%		314		0.4			314
Total short-term debt					0.4	%	$	1,171		0.5	%	$	1,377
Current portion of long-term debt and capital leases
Current portion of long-term debt		n/a			-			-		4.6			225
Current portion of capital leases		n/a			-			-		4.9			1
Total current portion of long-term debt and capital leases					-		$	-		4.6	%	$	226
Long-term debt - excluding current portion

Senior notes	2015	-	2043		5.0	%	$	2,825		5.1	%	$	2,325
First mortgage bonds	2016	-	2038		5.6			500		5.6			500
Gas facility revenue bonds	2022	-	2033		1.0			200		1.2			200
Medium-term notes	2017	-	2027		7.8			181		7.8			181
Total principal long-term debt					4.9	%	$	3,706		5.0	%	$	3,206
Fair value adjustment of long-term debt (3)	2016	-	2038	n/a				91	n/a				103
Unamortized debt premium, net		n/a		n/a				16	n/a				18
Total non-principal long-term debt				n/a				107	n/a				121
Total long-term debt							$	3,813				$	3,327
Total debt							$	4,984				$	4,930

(1)	Interest rates are calculated based on the daily weighted average balance outstanding for the 12 months ended December 31, 2013 and 2012.

(2)	As of December 31, 2013, the effective interest rates on our commercial paper borrowings were 0.4% for AGL Capital and 0.3% for Nicor Gas.

(3)	See Note 4 for additional information on our fair value measurements.

Short-term Debt

Our short-term debt at December 31, 2013 and 2012 was composed of borrowings under our commercial paper programs.

Commercial Paper Programs We maintain commercial paper programs at AGL Capital and at Nicor Gas that consist of short-term, unsecured promissory notes that are used in conjunction with cash from operations to fund our seasonal working capital requirements. Working capital needs fluctuate during the year and are highest during the injection period in advance of the Heating Season. The Nicor Gas commercial paper program supports working capital needs at Nicor Gas, while all of our other subsidiaries and SouthStar participate in the AGL Capital commercial paper program. During 2013, our commercial paper maturities ranged from 1 to 123 days, and at December 31, 2013, remaining terms to maturity ranged from 2 to 99 days. During 2013, total borrowings and repayments netted to a payment of $206 million. For commercial paper issuances with original maturities over 3 months, borrowings and repayments were $374 million and $181 million, respectively.

Credit Facilities At December 31, 2013 and 2012, there were no outstanding borrowings under either the AGL Capital or Nicor Gas credit facilities. In November 2013, the lenders for our two credit facilities consented to our request to extend the maturity date of each facility by one year, in accordance with the terms of the respective credit agreements. The AGL Credit Facility and Nicor Gas Credit Facility maturity dates were extended to November 10, 2017 and December 15, 2017, respectively. The terms, conditions and pricing under the agreements remain unchanged.

Current Portion of Long-term Debt and Capital Leases The current portion of our long-term debt at December 31, 2012 was composed of the current portions of our long-term debt and capital lease obligations.Our capital leases consisted primarily of a sale/leaseback transaction of gas meters and other equipment that was completed in 2002 by Florida City Gas and expired in the second quarter 2013. In the second quarter 2012, Florida City Gas had the option to purchase the leased meters from the lessor at their fair market value, but it did not exercise this option.

Long-term Debt

The majority of our long-term debt matures after fiscal year 2018. The annual maturities of our long-term debt for the next five years and thereafter are as follows:

Year	Amount (in millions)
2014	$	-
2015		200
2016		545
2017		22
2018		155
Thereafter		2,784
Total	$	3,706

Senior Notes On May 16, 2013 we issued $500 million in 30-year senior notes with a fixed interest rate of 4.4%. The net proceeds were used to repay a portion of AGL Capital’s commercial paper, including $225 million we borrowed to repay our senior notes that matured on April 15, 2013. There were no senior note issuances in 2012.

First Mortgage Bonds We acquired the first mortgage bonds of Nicor Gas, which were issued through the public and private placement markets, as a result of the 2011 merger.

Gas Facility Revenue Bonds We are party to a series of loan agreements with the New Jersey Economic Development Authority (NJEDA) under which the NJEDA has issued a series of gas facility revenue bonds. These gas revenue bonds are issued by state agencies or counties to investors, and proceeds from the issuance are then loaned to us.

Financial and Non-Financial Covenants

	AGL Resources						Nicor Gas
	December 31,						December 31,
	2013			2012			2013			2012
Debt-to-capitalization ratio		57	%		58	%		55	%		55	%

Default Provisions

Our credit facilities and other financial obligations include provisions that, if not complied with, could require early payment or similar actions. The most important default events include:

●

a maximum leverage ratio

●

insolvency events and nonpayment of scheduled principal or interest payments

●

acceleration of other financial obligations

●

change of control provisions

Preferred Securities

Note 2 - Significant Accounting Policies and Methods of Application

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

Note 2 - Significant Accounting Policies and Methods of Application

Cash and Cash Equivalents

Energy Marketing Receivables and Payables

Dollars in millions		Total (1)				# of top counterparties				Concentration risk %
Credit exposure		$	274				20				51	%

(1)

Our counterparties or the counterparties’ guarantors had a weighted average S&P equivalent rating of A- at December 31, 2013.

Receivables and Allowance for Uncollectible Accounts

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 3 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 12 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 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

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, 2013, the Nicor Gas LIFO inventory balance was $168 million. Based on the average cost of gas purchased in December 31, 2013, the estimated replacement cost of Nicor Gas’ inventory at December 31, 2013 was $402 million, which exceeded the LIFO cost by $234 million.

In millions	2013		2012		2011
Retail operations	$	1	$	3	$	5
Wholesale services		8		19		31
Midstream operations		-		1		-

Fair Value Measurements

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. 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. Our Level 3 assets, liabilities and any applicable transfers are primarily related to our pension and other retirement benefit plan assets as described in Note 3, Note 4 and Note 6. 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.

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 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 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 4 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.

Natural Gas and Weather Derivative Instruments The fair value of the natural gas and weather derivative instruments that we use to manage exposures arising from changing natural gas prices and 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 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 regulatory requirements, any realized gains and 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 in our Consolidated Statements of Financial Position. 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 Illinois weather risk associated with Nicor Gas, we implemented a corporate weather hedging program in the second quarter of 2013 that utilizes OTC weather derivatives to reduce the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather in Illinois. For January through April of 2014, we have purchased a put option that would partially offset lower operating margins resulting from lower customer usage in the event of warmer-than-normal weather, but would not be exercised in the event of colder-than-normal weather and, therefore, not offset higher margins if Heating Degree Days for the period are at normal or colder-than-normal levels. We will continue to use available methods to mitigate our exposure to weather in Illinois for future periods.

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.

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 lock in 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 lock in 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 in our Consolidated Statements of Financial Position, with changes in fair value recorded in operating revenues in our Consolidated Statements of Income in the period of change. These contracts are not designated as hedges for accounting purposes.

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, 2013 and 2012 is provided in the following table.

In millions	2013		2012
Transportation and distribution	$	8,384	$	7,992
Storage facilities		1,170		1,149
Shipping vessels and containers		148		145
Other		854		820
Construction work in progress		548		372
Total PP&E, gross		11,104		10,478
Less accumulated depreciation		2,323		2,131
Total PP&E, net	$	8,781	$	8,347

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.

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 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, over which we have no contractual ownership.

Depreciation Expense

	2013			2012			2011
Atlanta Gas Light (1)		2.6	%		2.6	%		2.6	%
Chattanooga Gas (1)		2.5	%		2.5	%		2.5	%
Elizabethtown Gas (2)		2.4	%		2.4	%		2.5	%
Elkton Gas (2)		2.4	%		2.4	%		2.4	%
Florida City Gas (2)		3.8	%		3.9	%		3.9	%
Nicor Gas (2) (3)		3.1	%		4.1	%		4.1	%
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)

On October 23, 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 2013 depreciation expense by $19 million.

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
Shipping vessels		20	-	25
Storage caverns		40	-	60
Other			up to	40

AFUDC and Capitalized Interest

	2013			2012			2011
Atlanta Gas Light		8.10	%		8.10	%		8.10	%
Nicor Gas (1)		0.31	%		0.36	%		0.18	%
Chattanooga Gas		7.41	%		7.41	%		7.41	%
Elizabethtown Gas (1)		0.41	%		0.51	%		0.53	%
AFUDC (in millions) (2)	$	19		$	9		$	6

(1)

Variable rate is determined by FERC method of AFUDC accounting.

(2)

Amount recorded in the Consolidated Statements of Income.

The capital expenditures of our other three utilities do not qualify for AFUDC treatment.

Asset Retirement Obligations

Impairment of Assets

Goodwill We perform an annual goodwill impairment test on our reporting units that contain goodwill during the fourth quarter of each year, 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. To estimate the fair value of our reporting units, we use two generally accepted valuation approaches, the income approach and the market approach, using assumptions consistent with a market participant’s perspective.

Changes in the amount of goodwill for the twelve months ended December 31, 2013 and 2012 are provided below.

In millions	Distribution Operations		Retail Operations			Wholesale Services			Midstream Operations			Cargo Shipping			Other			Consolidated
Goodwill - December 31, 2011	$	1,586	$	124		$	2		$	16		$	77		$	8		$	1,813
Adjustments to initial Nicor purchase price allocation and other		54		(2	)		(2	)		(2	)		(16	)		(8	)		24
Goodwill - December 31, 2012		1,640		122			-			14			61			-			1,837
2013 acquisitions		-		51			-			-			-			-			51
Goodwill - December 31, 2013	$	1,640	$	173		$	-		$	14		$	61		$	-		$	1,888

Long-Lived Assets We depreciate or amortize our long-lived assets and other intangible assets over their useful lives. Currently, 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. An 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 an 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 2013, with the exception of Sawgrass Storage, for which we recorded an $8 million loss.

Intangible Assets Our intangible assets 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. The increase in our intangible assets of $91 million as of December 31, 2013 compared to the prior year was the result of two acquisitions within the retail operations segment. For more information, see “Acquisitions” in Note 2.

	Weighted average amortization period (in years)		December 31, 2013							December 31, 2012
In millions	Weighted average amortization period (in years)		Gross		Accumulated amortization			Net		Gross		Accumulated amortization			Net
Customer relationships
Retail operations		13	$	130	$	(15	)	$	115	$	53	$	(6	)	$	47
Cargo shipping		18		6		-			6		6		-			6
Trade names
Retail operations		13		45		(6	)		39		30		(2	)		28
Cargo shipping		15		15		(2	)		13		15		(1	)		14
Wholesale services		-		-		-			-		1		-			1
Total			$	196	$	(23	)	$	173	$	105	$	(9	)	$	96

Amortization expense was $14 million in 2013, $9 million in 2012 and $0 in 2011. Amortization expense for the next five years is estimated to be as follows:

In millions
2014	$	16
2015		16
2016		16
2017		15
2018		15

Accounting for Retirement Benefit Plans

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 in our Consolidated Statements of Financial Position.

Accumulated Deferred Income Tax Assets and Liabilities As 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.

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 uncertain tax position 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 on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement.

Uncertain Tax Positions We recognize accrued interest related to uncertain tax positions in interest expense and penalties in operating expense in 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 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 expenses and record the corresponding customer charges as operating revenues.

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 commissions of our utilities.

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 to customers, which for some taxes includes a small administrative fee, as operating revenues, and to record the related taxes incurred as operating expenses in 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 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 $110 million in 2013, $85 million in 2012 and $9 million in 2011.

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, 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. The related receivables are included in the Consolidated Statements of Financial Position as unbilled revenue. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries during the period.

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 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.

Cargo shipping Revenues 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

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 in the Consolidated Statements of Financial Position and exclude from, or include in, 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 3.

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 and costs associated with the installation of heating and cooling equipment are recorded to cost of goods sold.

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

Other income

Our other income is detailed in the following table. For more information on our equity investment income, see Note 10.

In millions	2013		2012		2011
AFUDC - equity	$	13	$	6	$	4
Equity investment income		3		13		1
Other, net		1		5		2
Total other income	$	17	$	24	$	7

Earnings Per Common Share

In millions (except per share amounts)	2013		2012		2011
Net income attributable to AGL Resources Inc.	$	313	$	271	$	172
Denominator:
Basic weighted average number of shares outstanding (1)		117.9		117.0		80.4
Effect of dilutive securities		0.4		0.5		0.5
Diluted weighted average number of shares outstanding (2)		118.3		117.5		80.9

Earnings per share
Basic	$	2.65	$	2.32	$	2.14
Diluted (2)	$	2.64	$	2.31	$	2.12

(1)Daily weighted average shares outstanding.
(2)There were no outstanding stock options excluded from the computation of diluted earnings per common share attributable to AGL Resources Inc. for any of the periods presented because their effect would have been anti-dilutive, as the exercise prices were greater than the average market price.

Acquisitions

In millions
Current assets	$	3
PP&E		12
Goodwill		51
Intangible assets		62
Current liabilities		(6	)
Total purchase price	$	122

●

The issuance of 38.2 million shares of AGL Resources common stock

●

Increased revenues in 2012 of $2,063 million

●

Increased net income in 2012 of $70 million

●

An increase to PP&E of $3,192 million

●

An increase to goodwill and other intangible assets of $1,423 million and $103 million, respectively

Sale of Compass Energy

Non-Wholly Owned Entities

Use of Accounting Estimates

Accounting Developments

On January 1, 2013, we adopted ASU 2011-11, Disclosures about Offsetting Assets and Liabilities and ASU 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which require disclosures about offsetting and related arrangements in order to help financial statement users better understand the effect of those arrangements on our financial position. This guidance had no impact on our consolidated financial statements. See Note 4 for additional disclosures about our offsetting of derivative assets and liabilities.

On January 1, 2013, we adopted ASU 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, which requires enhanced disclosures of amounts reclassified out of accumulated other comprehensive income by component. This guidance had no impact on our consolidated financial statements. See Note 9 for additional disclosures relating to accumulated other comprehensive income.

Note 1 - Organization and Basis of Presentation

12 Months Ended

Dec. 31, 2013

Disclosure Text Block [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]

Note 1 - Organization and Basis of Presentation

General

Basis of Presentation

Note 13 - Segment Information

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Segment Reporting Disclosure [Text Block]

Note 13 - Segment Information

2013

In millions	Distribution operations		Retail operations		Wholesale services			Midstream operations			Cargo shipping		Other and intercompany eliminations (4)			Consolidated
Operating revenues from external parties	$	3,275	$	858	$	45		$	74		$	365	$	-		$	4,617
Intercompany revenues (1)		182		-		13			-			-		(195	)		-
Total operating revenues		3,457		858		58			74			365		(195	)		4,617
Operating expenses
Cost of goods sold		1,687		564		21			33			222		(195	)		2,332
Operation and maintenance		690		132		48			24			115		(10	)		999
Depreciation and amortization		346		22		1			17			19		13			418
Nicor merger expenses (2)		-		-		-			-			-		-			-
Taxes other than income taxes		167		3		3			5			6		9			193
Total operating expenses		2,890		721		73			79			362		(183	)		3,942
Gain on sale of Compass Energy		-		-		11			-			-		-			11
Operating income (loss)		567		137		(4	)		(5	)		3		(12	)		686
Other income (expense)		15		-		-			(5	)		9		(2	)		17
EBIT	$	582	$	137	$	(4	)	$	(10	)	$	12	$	(14	)	$	703
Identifiable and total assets (3)	$	11,727	$	694	$	1,166		$	713		$	445	$	(89	)	$	14,656
Capital expenditures	$	684	$	9	$	2		$	12		$	18	$	24		$	749

2012

In millions	Distribution operations		Retail operations		Wholesale services			Midstream operations		Cargo shipping			Other and intercompany eliminations (4)			Consolidated
Operating revenues from external parties	$	2,710	$	733	$	58		$	78	$	342		$	1		$	3,922
Intercompany revenues (1)		167		2		30			-		-			(199	)		-
Total operating revenues		2,877		735		88			78		342			(198	)		3,922
Operating expenses
Cost of goods sold		1,221		488		38			32		208			(196	)		1,791
Operation and maintenance		642		114		48			19		109			(11	)		921
Depreciation and amortization		351		13		2			14		22			13			415
Nicor merger expenses (2)		-		-		-			-		-			20			20
Taxes other than income taxes		140		4		4			5		6			6			165
Total operating expenses		2,354		619		92			70		345			(168	)		3,312
Operating income (loss)		523		116		(4	)		8		(3	)		(30	)		610
Other income		9		-		1			2		11			1			24
EBIT	$	532	$	116	$	(3	)	$	10	$	8		$	(29	)	$	634
Identifiable and total assets (3)	$	11,320	$	511	$	1,218		$	720	$	464		$	(92	)	$	14,141
Capital expenditures	$	649	$	8	$	3		$	62	$	7		$	53		$	782

2011

In millions	Distribution operations		Retail operations		Wholesale services		Midstream operations		Cargo shipping			Other and intercompany eliminations (4)			Consolidated
Operating revenues from external parties	$	1,451	$	702	$	95	$	70	$	19		$	1		$	2,338
Intercompany revenues (1)		146		-		3		-		-			(149	)		-
Total operating revenues		1,597		702		98		70		19			(148	)		2,338
Operating expenses
Cost of goods sold		625		534		41		33		12			(148	)		1,097
Operation and maintenance		362		71		48		15		7			(2	)		501
Depreciation and amortization		160		2		1		10		1			12			186
Nicor merger expenses (2)		-		-		-		-		-			57			57
Taxes other than income taxes		44		2		3		3		-			5			57
Total operating expenses		1,191		609		93		61		20			(76	)		1,898
Operating income (loss)		406		93		5		9		(1	)		(72	)		440
Other income		6		-		-		-		1			-			7
EBIT	$	412	$	93	$	5	$	9	$	-		$	(72	)	$	447
Capital expenditures	$	365	$	2	$	1	$	35	$	-		$	24		$	427

(1)	Wholesale services records its energy marketing and risk management revenues on a net basis and its total operating revenues include intercompany revenues of $417 million in 2013, $350 million in 2012 and $449 million in 2011.

(2)	Transaction expenses associated with the Nicor merger are shown separately to better compare year-over-year results.

(3)	Identifiable assets are those dedicated to each segment’s operations.

(4)	Our other segment’s assets consist primarily of cash and cash equivalents, PP&E and the effect of intercompany eliminations.

Note 9 - Equity

12 Months Ended

Dec. 31, 2013

Stockholders' Equity Note [Abstract]

Stockholders' Equity Note Disclosure [Text Block]

Note 9 - Equity

Treasury Shares

Dividends

Accumulated Other Comprehensive Loss

In millions (1)	Cash flow hedges			Retirement benefit plans			Total
As of December 31, 2010	$	(5	)	$	(145	)	$	(150	)
Other comprehensive loss		(2	)		(65	)		(67	)
As of December 31, 2011		(7	)		(210	)		(217	)
Other comprehensive income (loss)		4			(5	)		(1	)
As of December 31, 2012		(3	)		(215	)		(218	)
Other comprehensive income, before reclassifications		1			66			67
Amounts reclassified from accumulated other comprehensive loss		3			12			15
As of December 31, 2013	$	1		$	(137	)	$	(136	)

(1)

All amounts are net of income taxes. Amounts in parentheses indicate debits to accumulated other comprehensive loss.

In millions (1)
Cash flow hedges
Natural gas contracts	$	(1	)	Cost of goods sold
Interest rate contracts		(3	)	Interest expense, net
Total before income tax		(4	)
Income tax benefit		1
Total cash flow hedges		(3	)
Retirement benefit plan amortization of
Actuarial losses		(25	)	See (2), below
Prior service credits		5		See (2), below
Total before income tax		(20	)
Income tax benefit		8
Total retirement benefit plans		(12	)
Total reclassification for the period	$	(15	)

(1)

Amounts in parentheses indicate debits, or reductions, to profit/loss and credits to accumulated other comprehensive loss. Except for retirement benefit plan amounts, the profit/loss impacts are immediate.

(2)

Amortization of these accumulated other comprehensive loss components is included in the computation of net periodic benefit cost. See Note 5 for additional details about net periodic benefit cost.

Note 5 - Derivative Instruments

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

Note 5 - Derivative Instruments

Derivative Instruments

●

forward, futures and options contracts;

●

financial swaps;

●

treasury locks;

●

weather derivative contracts;

●

storage and transportation capacity contracts; and

●

foreign currency forward contracts

The fair values of our interest rate swaps were reflected as a long-term derivative asset of $3 million at December 31, 2012. For more information on our debt, see Note 8.

The following table summarizes the various ways in which we account for our derivative instruments and the impact on our consolidated financial statements:

Accounting Treatment	Recognition and Measurement
	Statements of Financial Position	Income Statement
Cash flow hedge	Derivative carried at fair value	Ineffective portion of the gain or loss on the derivative instrument is recognized in earnings
	Effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated OCI (loss)	Effective portion of the gain or loss on the derivative instrument is reclassified out of accumulated OCI (loss) and into earnings when the hedged transaction affects earnings
Fair value hedge	Derivative carried at fair value Changes in fair value of the hedged item are recorded as adjustments to the carrying amount of the hedged item	Gains or losses on the derivative instrument and the hedged item are recognized in earnings. As a result, to the extent the hedge is effective, the gains or losses will offset and there is no impact on earnings. Any hedge ineffectiveness will impact earnings
Not designated as hedges	Derivative carried at fair value	Realized and unrealized gains or losses on the derivative instrument are recognized in earnings
	Distribution operations’ gains and losses on derivative instruments are deferred as regulatory assets or liabilities until included in cost of goods sold	Gains or losses on these derivative instruments are ultimately included in billings to customers and are recognized in cost of goods sold in the same period as the related revenues

Quantitative Disclosures Related to Derivative Instruments

	December 31,
In Bcf (1)	2013 (2)			2012
Hedge designation
Cash flow hedges		6			6
Not designated as hedges		183			96
Total hedges		189			102
Hedge position
Short position		(2,622	)		(1,955	)
Long position		2,811			2,057
Net long position		189			102

(1)

Volumes related to Nicor Gas exclude variable-priced contracts, which are accounted for as derivatives, but whose fair values are not directly impacted by changes in commodity prices.

(2)

Approximately 97% of these contracts have durations of two years or less and the remaining 3% expire between two and six years.

Derivative Instruments in our Consolidated Statements of Financial Position

In millions	2013			2012
Nicor Gas	$	4		$	(35	)
Elizabethtown Gas	$	(6	)	$	(28	)

The following table presents the fair values and Consolidated Statements of Financial Position classifications of our derivative instruments:

		December 31, 2013						December 31, 2012
In millions	Classification	Assets			Liabilities			Assets			Liabilities
Designated as cash flow hedges and fair value hedges
Natural gas contracts	Current	$	3		$	(1	)	$	1		$	(2	)
Interest rate swap agreements	Current		-			-			3			-
Total			3			(1	)		4			(2	)

Not designated as cash flow hedges
Natural gas contracts	Current		691			(761	)		394			(355	)
Natural gas contracts	Long-term		206			(220	)		45			(50	)
Total			897			(981	)		439			(405	)
Gross amount of recognized assets and liabilities (1)			900			(982	)		443			(407	)
Gross amounts offset in our Consolidated Statements of Financial Position (2)			(781	)		902			(299	)		368
Net amounts of assets and liabilities presented in ourConsolidated Statements of Financial Position (3)		$	119		$	(80	)	$	144		$	(39	)

(1)

The gross amounts of recognized assets and liabilities are netted within our Consolidated Statements of Financial Position to the extent that we have netting arrangements with the counterparties.

(2)

(3)

At December 31, 2013 and 2012 we held letters of credit from counterparties that would offset, under master netting arrangements, an insignificant portion of these assets.

Derivative Instruments on the Consolidated Statements of Income

The following table presents the impacts of our derivative instruments in our Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011.

	December 31,
In millions	2013			2012			2011

Designated as cash flow hedges
Natural gas contracts - loss reclassified from OCI to cost of goods sold	$	(1	)	$	(5	)	$	(6	)
Interest rate swaps – gain (loss) reclassified from OCI to interest expense		(3	)		(4	)		2
Income tax benefit		1			3			1
Net of tax		(3	)		(6	)		(3	)

Not designated as hedges
Natural gas contracts - net fair value adjustments recorded in operating revenues (1)		(90	)		34			40
Natural gas contracts - net fair value adjustments recorded in cost of goods sold (2)		2			(4	)		(4	)
Income tax benefit (expense)		34			(11	)		(14	)
Net of tax		(54	)		19			22
Total (losses) gains on derivative instruments, net of tax	$	(57	)	$	13		$	19

(1)

Associated with the fair value of existing derivative instruments at December 31, 2013, 2012 and 2011.

(2)

Excludes losses recorded in cost of goods sold associated with weather derivatives of $5 million for the year ended December 31, 2013, $14 million for the year ended December 31, 2012 and $9 million for the year ended December 31, 2011.

Note 3 - Regulated Operations

12 Months Ended

Dec. 31, 2013

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets and Liabilities [Text Block]

Note 3 – Regulated Operations

In millions	2013		2012
Regulatory assets
Recoverable regulatory infrastructure program costs	$	48	$	47
Recoverable ERC		45		38
Recoverable pension and retiree welfare benefit costs		9		19
Other		60		41
Total regulatory assets - current		162		145
Recoverable ERC		433		438
Recoverable pension and retiree welfare benefit costs		99		196
Recoverable regulatory infrastructure program costs		87		167
Long-term debt fair value adjustment		82		90
Other		36		53
Total regulatory assets - long-term		737		944
Total regulatory assets	$	899	$	1,089
Regulatory liabilities
Accrued natural gas costs	$	92	$	93
Bad debt over collection		41		37
Accumulated removal costs		27		16
Other		23		15
Total regulatory liabilities - current		183		161
Accumulated removal costs		1,445		1,393
Regulatory income tax liability		27		27
Unamortized investment tax credit		26		29
Bad debt over collection		17		17
Other		3		11
Total regulatory liabilities - long-term		1,518		1,477
Total regulatory liabilities	$	1,701	$	1,638

Environmental Remediation Costs We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. Our ERC liabilities are estimates of future remediation costs for investigation and cleanup of our former operating sites that are contaminated. Our estimates are based on conventional engineering estimates and the use of probabilistic models of potential costs when such estimates cannot be made, on an undiscounted basis. As cleanup options and plans mature and cleanup contracts are entered into, we are increasingly able to provide conventional engineering estimates of the likely costs of many elements of the remediation program. These estimates contain various engineering assumptions, which we refine and update on an ongoing basis. These liabilities do not include other potential expenses, such as unasserted property damage claims, personal injury or natural resource damage claims, legal expenses or other costs for which we may be held liable but for which we cannot reasonably estimate an amount.

In millions	# of sites		Probabilistic model cost estimates (2)						Engineering estimates (2)		Amount recorded		Expected costs over next 12 months		Cost recovery period
Illinois (1)		24	$	209		-	$	458	$	42	$	251	$	38			As incurred (3)
New Jersey		6		139		-		233		6		145		18		7	years (3)
Georgia and Florida		13		28		-		112		8		40		7		5	years
North Carolina		1			n/a					11		11		7			No recovery
Total		44	$	376		-	$	803	$	67	$	447	$	70

	(1)	Nicor Gas and Commonwealth Edison Company are parties to an agreement to cooperate equally in cleaning up residue at 23 sites.
	(2)	Material cleanups have not been completed for 26 sites. Therefore precise estimates are not available for future cleanup costs and considerable variability remains in future cost estimates.
	(3)	Includes recovery of carrying costs on unrecovered expenditures.

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 a benchmark bad debt expense of $63 million, as determined by the Illinois Commission in February 2010. The over recovery is recorded as an increase to operating expenses on our Consolidated Statements of Income and a regulatory liability on our Consolidated Statements of Financial Position until refunded to customers. In the period refunded, operating expenses are reduced and the regulatory liability is reversed. The actual bad debt experience and resulting refunds are shown in the following table.

					Amount refunded in				Amount to be refunded in
In millions	Bad debt experience		Total refund		2012		2013		2014		2015
2013	$	21	$	42	$	-	$	-	$	25	$	17
2012		23		40		-		24		16		-
2011		31		32		19		13		-		-

Accumulated Removal Costs In accordance with regulatory treatment, our depreciation rates are comprised of two cost components - historical cost and the estimated cost of removal, net of estimated salvage, 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 are not a generally accepted component of depreciation, but meet the requirements of authoritative guidance related to regulated operations, we have reclassified them from accumulated depreciation to the accumulated removal cost regulatory liability in our Consolidated Statements of Financial Position. In the rate setting process, the liability for these accumulated removal costs is treated as a reduction to the net rate base upon which our regulated utilities have the opportunity to earn their allowed rate of return.

Regulatory Infrastructure Programs We have infrastructure improvement programs at several of our utilities. Descriptions of these are as follows.

Atlanta Gas Light 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.

●

$49 million in 2013

●

$51 million in 2012

●

$48 million in 2011

Elizabethtown Gas In 2009, the New Jersey BPU approved the 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 that are approved by the New Jersey BPU. In August 2013, the New Jersey BPU approved the recovery of investments under this program through a permanent adjustment to base rates.

Virginia Natural Gas On June 25, 2012, the Virginia Commission approved SAVE, an accelerated infrastructure replacement program, which is expected to be completed over a five-year period. The program permits a maximum capital expenditure of $25 million per year, not to exceed $105 million in total. SAVE is subject to annual review by the Virginia Commission. We began recovering program costs through a rate rider that was effective August 1, 2012. On May 1, 2013, we filed our annual SAVE rate update detailing the first-year performance and our expected future budget, which is subject to review and approval by the Virginia Commission. The rate update was approved with minor modifications by the Virginia Commission on July 23, 2013 and became effective as of August 1, 2013. On May 1, 2013, the Virginia Commission approved our CARE plan, which includes a limited set of conservation programs and measures at a cost of $2 million over a three-year period. The CARE plan became effective June 1, 2013.

Investment Tax Credits Deferred 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 lives of the related properties as credits to income tax expense.

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. However, the amount of the reduction is transferred to our regulatory income tax liability, which we are amortizing over the lives of the related properties as the temporary differences reverse over approximately 30 years.

Other Regulatory Assets and Liabilities Our recoverable pension and retiree welfare benefit plan costs for our utilities other than Nicor Gas are expected to be recovered through base rates over the next 2 to 21 years, based on the remaining recovery periods as designated by the applicable state regulatory commissions. This category also includes recoverable seasonal rates, which 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.

Note 4 - Fair Value Measurements

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value Disclosures [Text Block]

Note 4 - Fair Value Measurements

Retirement benefit plans

	December 31, 2013
	Pension plans (1)															Welfare plans
In millions	Level 1			Level 2			Level 3			Total			% of total			Level 1			Level 2			Level 3			Total			% of total
Cash	$	3		$	1		$	-		$	4			-	%	$	1		$	-		$	-		$	1			1	%
Equity securities
U.S. large cap (2)		93			205			-			298			33	%		-			52			-			52			62	%
U.S. small cap (2)		72			29			-			101			11	%		-			-			-			-			-	%
International companies (3)		-			139			-			139			15	%		-			14			-			14			17	%
Emerging markets (4)		-			34			-			34			4	%		-			-			-			-			-	%
Fixed income securities
Corporate bonds (5)		-			207			-			207			23	%		-			17			-			17			20	%
Other (or gov’t/muni bonds)		-			29			-			29			3	%		-			-			-			-			-	%
Other types of investments
Global hedged equity (6)		-			-			43			43			5	%		-			-			-			-			-	%
Absolute return (7)		-			-			39			39			4	%		-			-			-			-			-	%
Private capital (8)		-			-			22			22			2	%		-			-			-			-			-	%
Total assets at fair value	$	168		$	644		$	104		$	916			100	%	$	1		$	83		$	-		$	84			100	%
% of fair value hierarchy		19	%		70	%		11	%		100	%					1	%		99	%		-	%		100	%

	December 31, 2012
	Pension plans (1)															Welfare plans
In millions	Level 1			Level 2			Level 3			Total			% of total			Level 1			Level 2			Level 3			Total			% of total
Cash	$	14		$	2		$	-		$	16			2	%	$	1		$	-		$	-		$	1			1	%
Equity securities
U.S. large cap (2)		69			181			-			250			30	%		-			38			-			38			55	%
U.S. small cap (2)		60			22			-			82			10	%		-			-			-			-			-	%
International companies (3)		-			120			-			120			14	%		-			12			-			12			18	%
Emerging markets (4)		-			34			-			34			4	%		-			-			-			-			-	%
Fixed income securities
Corporate bonds (5)		-			216			-			216			26	%		-			18			-			18			26	%
Other (or gov’t/muni bonds)		-			30			-			30			3	%		-			-			-			-			-	%
Other types of investments
Global hedged equity (6)		-			-			38			38			4	%		-			-			-			-			-	%
Absolute return (7)		-			-			36			36			4	%		-			-			-			-			-	%
Private capital (8)		-			-			23			23			3	%		-			-			-			-			-	%
Total assets at fair value	$	143		$	605		$	97		$	845			100	%	$	1		$	68		$	-		$	69			100	%
% of fair value hierarchy		17	%		72	%		11	%		100	%					1	%		99	%		-	%		100	%

(1)

Includes $9 million at December 31, 2013 and $8 million at December 31, 2012 of medical benefit (health and welfare) component for 401h accounts to fund a portion of the other retirement benefits.

(2)

Includes funds that invest primarily in U.S. common stocks.

(3)

Includes funds that invest primarily in foreign equity and equity-related securities.

(4)

Includes funds that invest primarily in common stocks of emerging markets.

(5)

Includes funds that invest primarily in investment grade debt and fixed income securities.

(6)

Includes funds that invest in limited / general partnerships, managed accounts, and other investment entities issued by non-traditional firms or “hedge funds.”

(7)

Includes funds that invest primarily in investment vehicles and commodity pools as a “fund of funds.”

(8)

The following is a reconciliation of our retirement plan assets in Level 3 of the fair value hierarchy.

	Fair value measurements using significant unobservable inputs - Level 3 (1)
In millions	Global hedged equity			Absolute return		Private capital			Total
Balance at December 31, 2011	$	30		$	34	$	25		$	89
Gains included in changes in net assets		3			2		3			8
Purchases		15			-		-			15
Sales		(10	)		-		(5	)		(15	)
Balance at December 31, 2012	$	38		$	36	$	23		$	97
Gains included in changes in net assets		5			3		4			12
Purchases		-			-		-			-
Sales		-			-		(5	)		(5	)
Balance at December 31, 2013	$	43		$	39	$	22		$	104
(1) There were no transfers out of Level 3, or between Level 1 and Level 2 for any of the periods presented.

Derivative Instruments

	December 31, 2013					December 31, 2012
In millions	Assets (1)		Liabilities			Assets (1)		Liabilities
Natural gas derivatives
Quoted prices in active markets (Level 1)	$	6	$	(79	)	$	8	$	(45	)
Significant other observable inputs (Level 2)		67		(79	)		96		(30	)
Netting of cash collateral		43		78			33		36
Total carrying value (2) (3)	$	116	$	(80	)	$	137	$	(39	)
Interest rate derivatives
Significant other observable inputs (Level 2)	$	-	$	-		$	3	$	-

(1)

$3 million of premium at December 31, 2013 and $4 million at December 31, 2012 associated with weather derivatives have been excluded as they are accounted for based on intrinsic value.

(2)

There were no significant unobservable inputs (Level 3) for any of the periods presented.

(3)

There were no significant transfers between Level 1, Level 2, or Level 3 for any of the periods presented.

Money Market Funds

At December 31, 2013 and 2012, the fair values of our money market funds, which were recorded within short-term investments, were as follows:

In millions		2013				2012
Money market funds (1)		$	48			$	66

(1)

Carried at fair value and classified as Level 1 within the fair value hierarchy.

Debt

	As of December 31,
In millions	2013		2012
Long-term debt carrying amount	$	3,813	$	3,553
Long-term debt fair value (1)		3,956		4,057

(1)

Fair value determined using Level 2 inputs.

Note 6 - Employee Benefit Plans

12 Months Ended

Dec. 31, 2013

Compensation and Retirement Disclosure [Abstract]

Pension and Other Postretirement Benefits Disclosure [Text Block]

Note 6 - Employee Benefit Plans

Oversight of Plans

Pension Benefits

Welfare Benefits

Assumptions

The components of our pension and welfare costs are set forth in the following table.

	Pension plans									Welfare plans
Dollars in millions	2013			2012			2011			2013			2012			2011
Service cost	$	29		$	28		$	14		$	3		$	4		$	1
Interest cost		43			44			29			14			16			6
Expected return on plan assets		(62	)		(64	)		(33	)		(6	)		(5	)		(5	)
Net amortization of prior service credit		(2	)		(2	)		(2	)		(5	)		(3	)		(4	)
Recognized actuarial loss		35			34			14			8			9			2
Net periodic benefit cost	$	43		$	40		$	22		$	14		$	21		$	-
Assumptions used to determine benefit costs
Discount rate (1)		4.2	%		4.6	%		5.4	%		4.0	%		4.5	%		5.2	%
Expected return on plan assets (1)		7.8	%		8.4	%		8.5	%		7.8	%		8.5	%		8.2	%
Rate of compensation increase (1)		3.7	%		3.7	%		3.7	%		3.8	%		3.8	%		3.7	%
Pension band increase (2)		2.0	%		2.0	%		2.0	%	n/a			n/a			n/a

(1)

Rates are presented on a weighted average basis.

(2)

Only applicable to the Nicor Gas union employees.

The following tables present details about our pension and other retirement plans.

	Pension plans						Welfare plans
Dollars in millions	2013			2012			2013			2012
Change in plan assets
Fair value of plan assets, January 1,	$	837		$	754		$	77		$	67
Actual return on plan assets		134			101			16			10
Employee contributions		-			-			3			1
Employer contributions		1			42			19			17
Benefits paid		(65	)		(59	)		(23	)		(19	)
Medicare Part D reimbursements		-			-			1			1
Plan curtailment and settlements		-			(1	)		-			-
Fair value of plan assets, December 31,	$	907		$	837		$	93		$	77
Change in benefit obligation
Benefit obligation, January 1,	$	1,046		$	968		$	354		$	397
Service cost		29			28			3			4
Interest cost		43			44			14			17
Actuarial loss (gain)		(93	)		66			(26	)		(22	)
Plan amendments		-			-			-			(25	)
Medicare Part D reimbursements		-			-			1			1
Benefits paid		(65	)		(59	)		(23	)		(19	)
Employee contributions		-			-			3			1
Plan curtailment and settlements		-			(1	)		-			-
Benefit obligation, December 31,	$	960		$	1,046		$	326		$	354
Funded status at end of year	$	(53	)	$	(209	)	$	(233	)	$	(277	)
Amounts recognized in the Consolidated Statements of Financial Position consist of
Long-term asset	$	117		$	33		$	-		$	-
Current liability		(2	)		(2	)		-			(12	)
Long-term liability		(168	)		(240	)		(233	)		(265	)
Total liability at December 31,	$	(53	)	$	(209	)	$	(233	)	$	(277	)
Accumulated benefit obligation (1)	$	902		$	983		n/a			n/a
Assumptions used to determine benefit obligations
Discount rate		5.0	%		4.2	%		4.7	%		4.0	%
Rate of compensation increase		3.7	%		3.7	%		3.7	%		3.7	%
Pension band increase (2)		2.0	%		2.0	%	n/a			n/a

(1)

APBO differs from the projected benefit obligation in that the APBO excludes the effect of salary and wage increases.

(2)

Only applicable to the Nicor Gas union employees.

Assumptions used to determine the health care benefit cost for the AGL Welfare Plan were as follows:

	2013			2012
Health care cost trend rate assumed for next year		8.4	%		8.4	%
Ultimate rate to which the cost trend rate is assumed to decline		4.5	%		4.5	%
Year that reaches ultimate trend rate	2030			2030

In millions	Effect on service and interest cost		Effect on benefit obligation
1% Health care cost trend rate increase	$	-	$	15
1% Health care cost trend rate decrease		-		(13	)

The following table presents the amounts not yet reflected in net periodic benefit cost and included in net regulatory assets and accumulated OCI as of December 31, 2013 and 2012:

	Net regulatory assets					Accumulated OCI						Total
In millions	Pension plans		Welfare plans			Pension plans			Welfare plans			Pension plans			Welfare plans

December 31, 2013:
Prior service credit	$	-	$	(20	)	$	(9	)	$	-		$	(9	)	$	(20	)
Net loss		61		60			210			30			271			90
Total	$	61	$	40		$	201		$	30		$	262		$	70
December 31, 2012:
Prior service cost (credit)	$	-	$	(24	)	$	(11	)	$	(2	)	$	(11	)	$	(26	)
Net loss		146		83			324			52			470			135
Total	$	146	$	59		$	313		$	50		$	459		$	109

The 2014 estimated amortization out of regulatory assets or accumulated OCI for these plans are set forth in the following table.

	Net Regulatory Asset					Accumulated OCI					Total
In millions	Pension plans		Welfare plans			Pension plans			Welfare plans		Pension plans			Welfare plans
Amortization of prior service credit	$	-	$	(3	)	$	(2	)	$	-	$	(2	)	$	(3	)
Amortization of net loss		7		4			13			2		20			6

We recorded a regulatory asset for anticipated future cost recoveries of $108 million as of December 31, 2013 and $215 million as of December 31, 2012.

In millions	Pension plans		Welfare plans
2014	$	56	$	20
2015		60		20
2016		63		21
2017		66		22
2018		68		23
2019 - 2023		366		123

Contributions

Employee Savings Plan Benefits

Note 14 - Selected Quarterly Financial Data (Unaudited) (Details) - Quarterly Financial Data (USD $)
In Millions, except Per Share data, unless otherwise specified

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

2013

Operating revenues

$ 1,329

$ 675

$ 904

$ 1,709

$ 1,218

$ 614

$ 686

$ 1,404

$ 790

$ 295

$ 375

$ 878

$ 4,617

$ 3,922

$ 2,338

Operating income

183

122

299

203

262

118

238

686

610

440

EBIT

181

129

304

208

100

266

121

239

703

634

447

Net income

164

103

139

(4)

134

331

286

186

Net income attributable to AGL Resources Inc.

$ 82

$ 28

$ 49

$ 154

$ 98

$ 9

$ 34

$ 130

$ 33

$ (3)

$ 18

$ 124

$ 313

$ 271

$ 172

Basic earnings per common share attributable to AGL Resources Inc. common shareholders (in Dollars per share)

$ 0.69

$ 0.24

$ 0.41

$ 1.31

$ 0.84

$ 0.08

$ 0.28

$ 1.12

$ 0.37

$ (0.04)

$ 0.23

$ 1.60

$ 2.65

$ 2.32

$ 2.14

Diluted earnings per common share attributable to AGL Resources Inc. common shareholders (in Dollars per share)

$ 0.68

$ 0.24

$ 0.41

$ 1.31

$ 0.84

$ 0.08

$ 0.28

$ 1.11

$ 0.37

$ (0.04)

$ 0.23

$ 1.59

$ 2.64

^[1]

$ 2.31

^[1]

$ 2.12

^[1]

[1]	There were no outstanding stock options excluded from the computation of diluted earnings per common share attributable to AGL Resources Inc. for any of the periods presented because their effect would have been anti-dilutive, as the exercise prices were greater than the average market price.

Note 9 - Equity (Tables)

12 Months Ended

Dec. 31, 2013

Stockholders' Equity Note [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

In millions (1)	Cash flow hedges			Retirement benefit plans			Total
As of December 31, 2010	$	(5	)	$	(145	)	$	(150	)
Other comprehensive loss		(2	)		(65	)		(67	)
As of December 31, 2011		(7	)		(210	)		(217	)
Other comprehensive income (loss)		4			(5	)		(1	)
As of December 31, 2012		(3	)		(215	)		(218	)
Other comprehensive income, before reclassifications		1			66			67
Amounts reclassified from accumulated other comprehensive loss		3			12			15
As of December 31, 2013	$	1		$	(137	)	$	(136	)

Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]

In millions (1)
Cash flow hedges
Natural gas contracts	$	(1	)	Cost of goods sold
Interest rate contracts		(3	)	Interest expense, net
Total before income tax		(4	)
Income tax benefit		1
Total cash flow hedges		(3	)
Retirement benefit plan amortization of
Actuarial losses		(25	)	See (2), below
Prior service credits		5		See (2), below
Total before income tax		(20	)
Income tax benefit		8
Total retirement benefit plans		(12	)
Total reclassification for the period	$	(15	)

Note 2 - Significant Accounting Policies and Methods of Application (Details) - Other Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2011
Other Income [Abstract]
AFUDC - equity	$ 13		$ 6		$ 4
Equity investment income	3		13		1
Other, net	1		5		2
Total other income	$ 17	$ 24	$ 24	$ 7	$ 7

Note 11 - Commitments, Guarantees and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies Disclosure [Text Block]

Note 11 - Commitments, Guarantees and Contingencies

													2019 &
In millions	Total		2014		2015		2016		2017		2018		thereafter
Recorded contractual obligations:

Long-term debt (1)	$	3,706	$	-	$	200	$	545	$	22	$	155	$	2,784
Short-term debt		1,171		1,171		-		-		-		-		-
Environmental remediation liabilities (2)		447		70		82		80		48		63		104
Pipeline replacement program costs (2)		5		5		-		-		-		-		-
Total	$	5,329	$	1,246	$	282	$	625	$	70	$	218	$	2,888

Unrecorded contractual obligations and commitments(3) (8):

Pipeline charges, storage capacity and gas supply (4)	$	2,298	$	733	$	507	$	299	$	138	$	102	$	519
Interest charges (5)		2,899		185		175		161		147		145		2,086
Operating leases (6)		233		39		34		28		25		18		89
Asset management agreements (7)		19		8		5		4		2		-		-
Standby letters of credit, performance/surety bonds (8)		29		29		-		-		-		-		-
Other		15		6		3		3		2		1		-
Total	$	5,493	$	1,000	$	724	$	495	$	314	$	266	$	2,694

(1)

Excludes the $82 million step up to fair value of first mortgage bonds, $16 million unamortized debt premium and $9 million interest rate swaps fair value adjustment.

(2)

Includes charges recoverable through base rates or rate rider mechanisms.

(3)

In accordance with GAAP, these items are not reflected in our Consolidated Statements of Financial Position.

(4)

(5)

Floating rate interest charges are calculated based on the interest rate as of December 31, 2013 and the maturity date of the underlying debt instrument. As of December 31, 2013, we have $52 million of accrued interest on our Consolidated Statements of Financial Position that will be paid in 2014.

(6)

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 GAAP. However, this lease accounting treatment does not affect the future annual operating lease cash obligations as shown herein. Our operating leases are primarily for real estate.

(7)

Represent fixed-fee minimum payments for Sequent’s affiliated asset management agreements.

(8)

We provide guarantees to certain municipalities and other agencies and certain gas suppliers of SouthStar in support of payment obligations.

Substitute Natural Gas

Contingencies and Guarantees

Financial guarantees Tropic Equipment Leasing Inc. (TEL), a wholly owned subsidiary, holds our interest in Triton and has an obligation to restore to zero any deficit in its equity account for income tax purposes in the unlikely event that Triton is liquidated and a deficit balance remains. This obligation continues for the life of the Triton partnerships and any payment is effectively limited to the net assets of TEL, which were $16 million at December 31, 2013. We believe the likelihood of any such payment by TEL is remote. No liability has been recorded for this obligation.

Indemnities In certain instances, we have undertaken to indemnify current property owners and others against costs associated with the effects and/or remediation of contaminated sites for which we may be responsible under applicable federal or state environmental laws, generally with no limitation as to the amount. These indemnifications relate primarily to ongoing coal tar cleanup, as discussed in Environmental Matters. We believe that the likelihood of payment under our other environmental indemnifications is remote. No liability has been recorded for such indemnifications.

Regulatory Matters

Environmental Matters

Litigation

PBR Proceeding Nicor Gas’ PBR plan for natural gas costs went into effect in 2000 and was terminated effective January 1, 2003, following allegations that Nicor Gas acted improperly in connection with the plan. Under this plan, Nicor Gas’ total gas supply costs were compared to a market-sensitive benchmark. Savings and losses relative to the benchmark were determined annually and shared equally with sales customers. Since 2002 the amount of the savings and losses required to be shared has been disputed by the Citizens Utility Board (CUB) and others, with the Illinois Attorney General (IAG) intervening, and subject to extensive contested discovery and other regulatory proceedings before administrative law judges and the Illinois Commission. In 2009, the staff of the Illinois Commission, the staff of the IAG and CUB requested refunds of $85 million, $255 million and $305 million, respectively.

Other In addition to the matters set forth above, we are involved with legal or administrative proceedings before various courts and agencies with respect to general claims, taxes, environmental, gas cost prudence reviews and other matters. We are unable to determine the ultimate outcome of these other contingencies. We believe that these amounts are appropriately reflected in our financial statements, including the recording of appropriate liabilities when reasonably estimable.

Accounting Policies, by Policy (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Cash and Cash Equivalents, Policy [Policy Text Block]

Cash and Cash Equivalents

Energy Marketing Receivables And Payables [Policy Text Block]

Energy Marketing Receivables and Payables

Dollars in millions		Total (1)				# of top counterparties				Concentration risk %
Credit exposure		$	274				20				51	%

(1)

Our counterparties or the counterparties’ guarantors had a weighted average S&P equivalent rating of A- at December 31, 2013.

Receivables, Policy [Policy Text Block]

Receivables and Allowance for Uncollectible Accounts

Inventory, Policy [Policy Text Block]

Inventories

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, 2013, the Nicor Gas LIFO inventory balance was $168 million. Based on the average cost of gas purchased in December 31, 2013, the estimated replacement cost of Nicor Gas’ inventory at December 31, 2013 was $402 million, which exceeded the LIFO cost by $234 million.

In millions	2013		2012		2011
Retail operations	$	1	$	3	$	5
Wholesale services		8		19		31
Midstream operations		-		1		-

Fair Value of Financial Instruments, Policy [Policy Text Block]

Fair Value Measurements

Derivatives, Policy [Policy Text Block]

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.

For our Illinois weather risk associated with Nicor Gas, we implemented a corporate weather hedging program in the second quarter of 2013 that utilizes OTC weather derivatives to reduce the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather in Illinois. For January through April of 2014, we have purchased a put option that would partially offset lower operating margins resulting from lower customer usage in the event of warmer-than-normal weather, but would not be exercised in the event of colder-than-normal weather and, therefore, not offset higher margins if Heating Degree Days for the period are at normal or colder-than-normal levels. We will continue to use available methods to mitigate our exposure to weather in Illinois for future periods.

Debt, Policy [Policy Text Block]

Property, Plant and Equipment, Policy [Policy Text Block]

Property, Plant and Equipment

A summary of our PP&E by classification as of December 31, 2013 and 2012 is provided in the following table.

In millions	2013		2012
Transportation and distribution	$	8,384	$	7,992
Storage facilities		1,170		1,149
Shipping vessels and containers		148		145
Other		854		820
Construction work in progress		548		372
Total PP&E, gross		11,104		10,478
Less accumulated depreciation		2,323		2,131
Total PP&E, net	$	8,781	$	8,347

●

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.

Depreciation Expense

	2013			2012			2011
Atlanta Gas Light (1)		2.6	%		2.6	%		2.6	%
Chattanooga Gas (1)		2.5	%		2.5	%		2.5	%
Elizabethtown Gas (2)		2.4	%		2.4	%		2.5	%
Elkton Gas (2)		2.4	%		2.4	%		2.4	%
Florida City Gas (2)		3.8	%		3.9	%		3.9	%
Nicor Gas (2) (3)		3.1	%		4.1	%		4.1	%
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)

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
Shipping vessels		20	-	25
Storage caverns		40	-	60
Other			up to	40

AFUDC and Capitalized Interest

	2013			2012			2011
Atlanta Gas Light		8.10	%		8.10	%		8.10	%
Nicor Gas (1)		0.31	%		0.36	%		0.18	%
Chattanooga Gas		7.41	%		7.41	%		7.41	%
Elizabethtown Gas (1)		0.41	%		0.51	%		0.53	%
AFUDC (in millions) (2)	$	19		$	9		$	6

(1)

Variable rate is determined by FERC method of AFUDC accounting.

(2)

Amount recorded in the Consolidated Statements of Income.

The capital expenditures of our other three utilities do not qualify for AFUDC treatment.

Asset Retirement Obligations

Goodwill and Intangible Assets, Goodwill, Policy [Policy Text Block]

Impairment of Assets

Changes in the amount of goodwill for the twelve months ended December 31, 2013 and 2012 are provided below.

In millions	Distribution Operations		Retail Operations			Wholesale Services			Midstream Operations			Cargo Shipping			Other			Consolidated
Goodwill - December 31, 2011	$	1,586	$	124		$	2		$	16		$	77		$	8		$	1,813
Adjustments to initial Nicor purchase price allocation and other		54		(2	)		(2	)		(2	)		(16	)		(8	)		24
Goodwill - December 31, 2012		1,640		122			-			14			61			-			1,837
2013 acquisitions		-		51			-			-			-			-			51
Goodwill - December 31, 2013	$	1,640	$	173		$	-		$	14		$	61		$	-		$	1,888

	Weighted average amortization period (in years)		December 31, 2013							December 31, 2012
In millions	Weighted average amortization period (in years)		Gross		Accumulated amortization			Net		Gross		Accumulated amortization			Net
Customer relationships
Retail operations		13	$	130	$	(15	)	$	115	$	53	$	(6	)	$	47
Cargo shipping		18		6		-			6		6		-			6
Trade names
Retail operations		13		45		(6	)		39		30		(2	)		28
Cargo shipping		15		15		(2	)		13		15		(1	)		14
Wholesale services		-		-		-			-		1		-			1
Total			$	196	$	(23	)	$	173	$	105	$	(9	)	$	96

Amortization expense was $14 million in 2013, $9 million in 2012 and $0 in 2011. Amortization expense for the next five years is estimated to be as follows:

In millions
2014	$	16
2015		16
2016		16
2017		15
2018		15

Pension and Other Postretirement Plans, Nonpension Benefits, Policy [Policy Text Block]

Accounting for Retirement Benefit Plans

Income Tax, Policy [Policy Text Block]

Taxes

Uncertain Tax Positions We recognize accrued interest related to uncertain tax positions in interest expense and penalties in operating expense in our Consolidated Statements of Income.

Revenue Recognition, Policy [Policy Text Block]

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 commissions of our utilities.

Cost of Sales, Policy [Policy Text Block]

Cost of goods sold

Repairs and Maintenance, 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 [Policy Text Block]

Operating leases

Other Income and Other Expense Disclosure [Text Block]

Other income

Our other income is detailed in the following table. For more information on our equity investment income, see Note 10.

In millions	2013		2012		2011
AFUDC - equity	$	13	$	6	$	4
Equity investment income		3		13		1
Other, net		1		5		2
Total other income	$	17	$	24	$	7

Earnings Per Share, Policy [Policy Text Block]

Earnings Per Common Share

In millions (except per share amounts)	2013		2012		2011
Net income attributable to AGL Resources Inc.	$	313	$	271	$	172
Denominator:
Basic weighted average number of shares outstanding (1)		117.9		117.0		80.4
Effect of dilutive securities		0.4		0.5		0.5
Diluted weighted average number of shares outstanding (2)		118.3		117.5		80.9

Earnings per share
Basic	$	2.65	$	2.32	$	2.14
Diluted (2)	$	2.64	$	2.31	$	2.12

(1)Daily weighted average shares outstanding.
(2)There were no outstanding stock options excluded from the computation of diluted earnings per common share attributable to AGL Resources Inc. for any of the periods presented because their effect would have been anti-dilutive, as the exercise prices were greater than the average market price.

Business Combinations Policy [Policy Text Block]

Acquisitions

In millions
Current assets	$	3
PP&E		12
Goodwill		51
Intangible assets		62
Current liabilities		(6	)
Total purchase price	$	122

●

The issuance of 38.2 million shares of AGL Resources common stock

●

Increased revenues in 2012 of $2,063 million

●

Increased net income in 2012 of $70 million

●

An increase to PP&E of $3,192 million

●

An increase to goodwill and other intangible assets of $1,423 million and $103 million, respectively

Sale of Business [Policy Text Block]

Sale of Compass Energy

Consolidation, Variable Interest Entity, Policy [Policy Text Block]

Non-Wholly Owned Entities

Use of Estimates, Policy [Policy Text Block]

Use of Accounting Estimates

New Accounting Pronouncements, Policy [Policy Text Block]

Accounting Developments

Condensed Consolidated Statements of Income (Parentheticals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating revenues, revenue taxes	$ 112	$ 86	$ 9

Note 13 - Segment Information (Tables)

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

In millions	Distribution operations		Retail operations		Wholesale services			Midstream operations			Cargo shipping		Other and intercompany eliminations (4)			Consolidated
Operating revenues from external parties	$	3,275	$	858	$	45		$	74		$	365	$	-		$	4,617
Intercompany revenues (1)		182		-		13			-			-		(195	)		-
Total operating revenues		3,457		858		58			74			365		(195	)		4,617
Operating expenses
Cost of goods sold		1,687		564		21			33			222		(195	)		2,332
Operation and maintenance		690		132		48			24			115		(10	)		999
Depreciation and amortization		346		22		1			17			19		13			418
Nicor merger expenses (2)		-		-		-			-			-		-			-
Taxes other than income taxes		167		3		3			5			6		9			193
Total operating expenses		2,890		721		73			79			362		(183	)		3,942
Gain on sale of Compass Energy		-		-		11			-			-		-			11
Operating income (loss)		567		137		(4	)		(5	)		3		(12	)		686
Other income (expense)		15		-		-			(5	)		9		(2	)		17
EBIT	$	582	$	137	$	(4	)	$	(10	)	$	12	$	(14	)	$	703
Identifiable and total assets (3)	$	11,727	$	694	$	1,166		$	713		$	445	$	(89	)	$	14,656
Capital expenditures	$	684	$	9	$	2		$	12		$	18	$	24		$	749

In millions	Distribution operations		Retail operations		Wholesale services			Midstream operations		Cargo shipping			Other and intercompany eliminations (4)			Consolidated
Operating revenues from external parties	$	2,710	$	733	$	58		$	78	$	342		$	1		$	3,922
Intercompany revenues (1)		167		2		30			-		-			(199	)		-
Total operating revenues		2,877		735		88			78		342			(198	)		3,922
Operating expenses
Cost of goods sold		1,221		488		38			32		208			(196	)		1,791
Operation and maintenance		642		114		48			19		109			(11	)		921
Depreciation and amortization		351		13		2			14		22			13			415
Nicor merger expenses (2)		-		-		-			-		-			20			20
Taxes other than income taxes		140		4		4			5		6			6			165
Total operating expenses		2,354		619		92			70		345			(168	)		3,312
Operating income (loss)		523		116		(4	)		8		(3	)		(30	)		610
Other income		9		-		1			2		11			1			24
EBIT	$	532	$	116	$	(3	)	$	10	$	8		$	(29	)	$	634
Identifiable and total assets (3)	$	11,320	$	511	$	1,218		$	720	$	464		$	(92	)	$	14,141
Capital expenditures	$	649	$	8	$	3		$	62	$	7		$	53		$	782

In millions	Distribution operations		Retail operations		Wholesale services		Midstream operations		Cargo shipping			Other and intercompany eliminations (4)			Consolidated
Operating revenues from external parties	$	1,451	$	702	$	95	$	70	$	19		$	1		$	2,338
Intercompany revenues (1)		146		-		3		-		-			(149	)		-
Total operating revenues		1,597		702		98		70		19			(148	)		2,338
Operating expenses
Cost of goods sold		625		534		41		33		12			(148	)		1,097
Operation and maintenance		362		71		48		15		7			(2	)		501
Depreciation and amortization		160		2		1		10		1			12			186
Nicor merger expenses (2)		-		-		-		-		-			57			57
Taxes other than income taxes		44		2		3		3		-			5			57
Total operating expenses		1,191		609		93		61		20			(76	)		1,898
Operating income (loss)		406		93		5		9		(1	)		(72	)		440
Other income		6		-		-		-		1			-			7
EBIT	$	412	$	93	$	5	$	9	$	-		$	(72	)	$	447
Capital expenditures	$	365	$	2	$	1	$	35	$	-		$	24		$	427

Note 10 - Non-Wholly Owned Entities

12 Months Ended

Dec. 31, 2013

Noncontrolling Interest [Abstract]

Noncontrolling Interest Disclosure [Text Block]

Note 10 - Non-Wholly Owned Entities

Variable Interest Entities

Operations

Our wholly owned subsidiaries, Nicor Gas and Atlanta Gas Light, provide the following services, which affect SouthStar’s operations:

●

meter reading for SouthStar’s customers in Illinois and Georgia

●

maintenance and expansion of the natural gas infrastructure in Illinois and Georgia

●

assigning storage and transportation capacity used in delivering natural gas to SouthStar’s customers

Liquidity and capital resources

●

guarantees of SouthStar’s activities with, and its credit exposure to, its counterparties and to certain natural gas suppliers in support of SouthStar’s payment obligations

●

Back office functions

●

Accounting, information technology, credit and internal controls services in accordance with our services agreement

The following table provides additional information on SouthStar’s assets and liabilities as of the dates presented, which are consolidated within our Consolidated Statements of Financial Position.

	December 31, 2013							December 31, 2012
In millions	Consolidated		SouthStar (1)		% (2)			Consolidated		SouthStar (1)		% (2)
Current assets	$	2,733	$	264		10	%	$	2,668	$	201		8	%
Goodwill and other intangible assets		2,061		139		7			1,933		-		-
Long-term assets and other deferred debit		9,862		12		-			9,540		10		-
Total assets	$	14,656	$	415		3	%	$	14,141	$	211		1	%
Current liabilities	$	3,122	$	95		3	%	$	3,338	$	62		2	%
Long-term liabilities and other deferred credits		7,858		-		-			7,368		-		-
Total Liabilities		10,980		95		1			10,706		62		1
Equity		3,676		320		9			3,435		149		4
Total liabilities and equity	$	14,656	$	415		3	%	$	14,141	$	211		1	%

(1) These amounts reflect information for SouthStar and exclude intercompany eliminations and the balances of our wholly owned subsidiary with an 85% ownership interest in SouthStar.

(2) SouthStar’s percentage of the amount on our Consolidated Statements of Financial Position.

The following table provides additional information about SouthStar’s revenues and expenses for the periods presented, which are consolidated within our Consolidated Statements of Income.

	December 31,
In millions	2013		2012
Operating revenues	$	687	$	576
Operating expenses
Cost of goods sold		491		411
Operation and maintenance		72		63
Depreciation and amortization		5		2
Taxes other than income taxes		1		2
Total operating expenses		569		478
Operating income	$	118	$	98

Equity Method Investments

Triton We have an investment in Triton, a cargo container leasing company. Container equipment that is acquired by Triton is accounted for in tranches as defined in Triton’s operating agreement, and investors make capital contributions to Triton to invest in each of the tranches. As of December 31, 2013 we had invested in seven tranches established by Triton. For the years ended December 31, 2013 and 2012, income from our equity method investment in Triton of $9 million and $11 million, respectively, was classified as other income on our Consolidated Statements of Income.

Horizon Pipeline We have a 50% owned joint venture with Natural Gas Pipeline Company of America that is regulated by the FERC. Horizon Pipeline operates an approximate 70-mile natural gas pipeline from Joliet, Illinois to near the Wisconsin/Illinois border. Nicor Gas typically contracts for 70% to 80% of the total capacity.

Sawgrass Storage We own a 50% interest in Sawgrass Storage, a joint venture between us and a privately held energy exploration and production company. Sawgrass Storage was granted certification from the FERC in March 2012 for the development of an underground natural gas storage facility in Louisiana with 30 Bcf of working gas capacity. The FERC certificate is set to expire in March 2014.

The carrying amounts of our investments that are accounted for under the equity method at December 31 were as follows:

In millions	2013		2012
Triton	$	70	$	73
Horizon Pipeline		15		17
Other (1)		1		9
Total	$	86	$	99

(1)

Includes our investment in Sawgrass Storage of $1 million at December 31, 2013 and $9 million at December 31, 2012.

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2013

Commission File Number 1-14174

AGL RESOURCES INC.
Ten Peachtree Place NE,
Atlanta, Georgia 30309
404-584-4000

Georgia	58-2210952
(State of incorporation)	(I.R.S. Employer Identification No.)


Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Stock, $5 Par Value	New York Stock Exchange



AGL Resources Inc. is a well-known seasoned issuer.

AGL Resources Inc. is required to file reports pursuant to Section 13 of the Securities Exchange Act.

AGL Resources Inc.: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days.

AGL Resources Inc. has submitted electronically and posted on its corporate website every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months.

AGL Resources Inc. believes that during the 2013 fiscal year, its executive officers, directors and 10% beneficial owners subject to Section 16(a) of the Securities Exchange Act complied with all applicable filing requirements, except as set forth under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” in AGL Resources Inc.’s Proxy Statement for the 2014 Annual Meeting of Shareholders.
AGL Resources Inc. is a large accelerated filer and is not a shell company.

The aggregate market value of AGL Resources Inc.’s common stock held by non-affiliates of the registrant (based on the closing sale price on June 29, 2013, as reported by the New York Stock Exchange), was $5,081,511,045.

The number of shares of AGL Resources Inc.’s common stock outstanding as of January 31, 2014 was 118,901,889.

DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Proxy Statement for the 2014 Annual Meeting of Shareholders (Proxy Statement) to be held on April 29, 2014, are incorporated by reference in Part III of this Form 10-K.

AFUDC	Allowance for funds used during construction, 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
AGL Capital	AGL Capital Corporation
AGL Credit Facility	$1.3 billion credit agreement entered into by AGL Capital to support the AGL Capital commercial paper program
AGL Resources	AGL Resources Inc., together with its consolidated subsidiaries
Atlanta Gas Light	Atlanta Gas Light Company
Bcf	Billion cubic feet
Central Valley	Central Valley Gas Storage, LLC
Chattanooga Gas	Chattanooga Gas Company
Chicago Hub	A venture of Nicor Gas, which provides natural gas storage and transmission-related services to marketers and gas distribution companies
California Commission	California Public Utilities Commission, the state regulatory agency for Central Valley
Compass Energy	Compass Energy Services, Inc., which was sold in 2013
EBIT	Earnings before interest and taxes, the primary measure of our operating segments’ profit or loss, which includes operating income and other income and excludes financing costs, including interest on debt and income tax expense
EPA	U.S. Environmental Protection Agency
ERC	Environmental remediation costs associated with our distribution operations segment that are generally recoverable through rate mechanisms
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Accounting principles generally accepted in the United States of America
Georgia Commission	Georgia Public Service Commission, the state regulatory agency for Atlanta Gas Light
Georgia Natural Gas	The trade name under which SouthStar does business in Georgia
Golden Triangle	Golden Triangle Storage, Inc.
Heating Degree Days	A measure of the effects of weather on our businesses, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
Heating Season	The period from November through March when natural gas usage and operating revenues are generally higher
Henry Hub	A major interconnection point of natural gas pipelines in Erath, Louisiana where NYMEX natural gas future contracts are priced
Illinois Commission	Illinois Commerce Commission, the state regulatory agency for Nicor Gas
Jefferson Island	Jefferson Island Storage & Hub, LLC
LIBOR	London Inter-Bank Offered Rate
LIFO	Last-in, first-out
LNG	Liquefied natural gas
LOCOM	Lower of weighted average cost or current market price
Marketers	Marketers selling retail natural gas in Georgia and certificated by the Georgia Commission
MGP	Manufactured gas plant
Moody’s	Moody’s Investors Service
New Jersey BPU	New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas
Nicor	Nicor Inc. - an acquisition completed in December 2011 and former holding company of Nicor Gas
Nicor Gas	Northern Illinois Gas Company, doing business as Nicor Gas Company
Nicor Gas Credit Facility	$700 million credit facility entered into by Nicor Gas to support its commercial paper program
NUI	NUI Corporation
NYMEX	New York Mercantile Exchange, Inc.
OCI	Other comprehensive income
Operating margin	A non-GAAP measure of income, calculated as operating revenues minus cost of goods sold and revenue tax expense
OTC	Over-the-counter
Pad gas	Volumes of non-working natural gas used to maintain the operational integrity of the natural gas storage facility, also known as base gas
PBR	Performance-based rate, a regulatory plan at Nicor Gas that provided economic incentives based on natural gas cost performance. The plan terminated in 2003
PGA	Purchased Gas Adjustment
Piedmont	Piedmont Natural Gas Company, Inc.
Pivotal Home Solutions	Nicor Energy Services Company, doing business as Pivotal Home Solutions
Pivotal Utility	Pivotal Utility Holdings, Inc., doing business as Elizabethtown Gas, Elkton Gas and Florida City Gas
PP&E	Property, plant and equipment
S&P	Standard & Poor’s Ratings Services
Sawgrass Storage	Sawgrass Storage, LLC
SEC	Securities and Exchange Commission
Sequent	Sequent Energy Management, L.P.
Seven Seas	Seven Seas Insurance Company, Inc.
SNG	Substitute natural gas, a synthetic form of gas manufactured from coal
SouthStar	SouthStar Energy Services LLC
STRIDE	Atlanta Gas Light’s Strategic Infrastructure Development and Enhancement program
Tennessee Authority	Tennessee Regulatory Authority, the state regulatory agency for Chattanooga Gas
Term Loan Facility	$300 million credit agreement entered into by AGL Capital to repay the $300 million senior notes that matured in 2011
TEU	Twenty-foot equivalent unit, a measure of volume in containerized shipping equal to one 20-foot-long container
Triton	Triton Container Investments LLC
Tropical Shipping	Tropical Shipping and Construction Company Limited
U.S.	United States
VaR	Value-at-risk is the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability.
Virginia Natural Gas	Virginia Natural Gas, Inc.
Virginia Commission	Virginia State Corporation Commission, the state regulatory agency for Virginia Natural Gas
WACOG	Weighted average cost of gas
WNA	Weather normalization adjustment

Distribution Operations	· ·	Serves 4.5 million customers across 7 states Performance driven by customer growth and/or usage, regulatory outcomes and infrastructure investment

Retail Operations	· ·	Serves 620,000 energy customers and 1.1 million service contracts across 17 states Performance driven by market leading position in Georgia as well as our June 2013 acquisition of approximately 33,000 residential and commercial relationships and our January 2013 acquisition of approximately 500,000 service contracts

Wholesale Services	· ·	Engages in natural gas storage, gas pipeline arbitrage and provides natural gas asset management and/or related logistics services for most of our utilities, as well as for non-affiliated companies Sequent’s portfolio of storage and transportation capacity is well positioned to serve customers and capture value under improving market conditions but remains subject to volatility in reported earnings due to changes in natural gas prices

Midstream Operations	· ·	Consists primarily of high deliverability natural gas storage facilities Business remains challenged due to weak seasonal spreads and continued oversupply of natural gas

Cargo Shipping	· · ·	Provides shipping services to, from and between the Bahamas and the Caribbean Includes Seven Seas and our investment in Triton Business improving due to higher volumes

($ in millions)	Nicor Gas (9)			Atlanta Gas Light			Virginia Natural Gas			Elizabethtown Gas			Florida City Gas			Chattanooga Gas
Authorized return on rate base (1)		8.09	%		8.10	%		7.38	%		7.64	%		7.36	%		7.41	%
Estimated 2013 return on rate base (2)		7.55	%		8.56	%		6.85	%		8.42	%		5.90	%		8.53	%
Authorized return on equity (1)		10.17	%		10.75	%		10.00	%		10.30	%		11.25	%		10.05	%
Estimated 2013 return on equity (2)		8.77	%		11.65	%		10.19	%		11.92	%		10.57	%		12.46	%
Authorized rate base % of equity (1)		51.07	%		51.00	%		45.36	%		47.89	%		36.77	%		46.06	%
Rate base included in 2013 return on equity (2)	$	1,486		$	2,226		$	596		$	496		$	166		$	89
Weather normalization (3)							ü			ü						ü
Decoupled or straight-fixed-variable rates (4)				ü			ü									ü
Regulatory infrastructure program rates (5)	ü			ü			ü			ü
Bad debt rider (6)	ü						ü									ü
Synergy sharing policy (7)				ü
Energy efficiency plan (8)	ü						ü			ü			ü			ü
Last decision on change in rates		2009			2010			2011			2009			N/A			2010

					Subscribed (1)
In Bcf	Location	Type	Working Gas Capacity		Amount		%
Jefferson Island (2) (3)	Louisiana	Salt-dome		7.3		5.6		77	%
Golden Triangle (3)	Texas	Salt-dome		13.5		2.0		15	%
Central Valley (4)	California	Depleted field		11.0		3.0		27	%
Total				31.8		10.6		33	%

		Page
Glossary of Key Terms			3
Part I
Item 1.	Business		4
	Distribution Operations		4
	Retail Operations		10
	Wholesale Services		10
	Midstream Operations		13
	Cargo Shipping		14
	Other		14
Item 1A.	Risk Factors		15
Item 1B.	Unresolved Staff Comments		25
Item 2.	Properties		25
Item 3.	Legal Proceedings		26
Item 4.	Mine Safety Disclosures		26
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		26
Item 6.	Selected Financial Data		27
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		28
	Executive Summary		28
	Results of Operations		28
	Operating Metrics		30
	Liquidity and Capital Resources		36
	Critical Accounting Policies and Estimates		42
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		47
Item 8.	Financial Statements and Supplementary Data		52
	Report of Independent Registered Public Accounting Firm		52
	Management’s Report on Internal Control Over Financial Reporting		53
	Consolidated Statements of Financial Position		54
	Consolidated Statements of Income		56
	Consolidated Statements of Comprehensive Income		57
	Consolidated Statements of Equity		58
	Consolidated Statements of Cash Flows		59
	Note 1 - Organization and Basis of Presentation		60
	Note 2 - Significant Accounting Policies and Methods of Application		60
	Note 3 - Regulated Operations		72
	Note 4 - Fair Value Measurements		76
	Note 5 - Derivative Instruments		78
	Note 6 - Employee Benefit Plans		80
	Note 7 - Stock-based and Other Incentive Compensation Plans and Agreements		84
	Note 8 - Debt and Credit Facilities		87
	Note 9 - Equity		89
	Note 10 - Non-Wholly Owned Entities		90
	Note 11 - Commitments, Guarantees and Contingencies		93
	Note 12 - Income Taxes		95
	Note 13 - Segment Information		96
	Note 14 - Selected Quarterly Financial Data (Unaudited)		99
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		99
Item 9A.	Controls and Procedures		99
Item 9B.	Other Information		100
Part III
Item 10.	Directors, Executive Officers and Corporate Governance		100
Item 11.	Executive Compensation		101
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		101
Item 13.	Certain Relationships and Related Transactions and Director Independence		101
Item 14.	Principal Accounting Fees and Services		101
Part IV
Item 15.	Exhibits, Financial Statement Schedules		101
Signatures			105
Schedule II			106

Utility	State	Number of customers (in thousands)		Approximate miles of pipe
Nicor Gas	Illinois		2,195		34,000
Atlanta Gas Light	Georgia		1,547		32,600
Virginia Natural Gas	Virginia		284		5,500
Elizabethtown Gas	New Jersey		279		3,200
Florida City Gas	Florida		105		3,500
Chattanooga Gas	Tennessee		63		1,600
Elkton Gas	Maryland		6		100
Total			4,479		80,500

	Total amount received
In millions	2013		2012		2011		Expiration Date
Atlanta Gas Light	$	6	$	5	$	9	March 2017
Virginia Natural Gas		4		3		9	March 2016
Florida City Gas		1		1		2	March 2015
Chattanooga Gas		1		1		3	March 2015
Elizabethtown Gas		6		5		9	March 2014 (1)
Total	$	18	$	15	$	32

Dollars in millions	Utility	Expenditures in 2013		Expenditures since project inception		Miles of pipe installed		Year project began		Scheduled year of completion
STRIDE program Pipeline replacement program (PRP) (1)	Atlanta Gas Light	$	151	$	833		2,708		1998		2013
Integrated System Reinforcement Program (i-SRP)	Atlanta Gas Light		27		251		n/a		2009		2017
Integrated Customer Growth Program (i-CGP)	Atlanta Gas Light		11		40		n/a		2010		2017
Integrated Vintage Plastic Replacement Program (i-VPR)	Atlanta Gas Light		5		5		29		2013		2017
Enhanced infrastructure program	Elizabethtown Gas		8		116		107		2009		2017
Accelerated infrastructure replacement program (SAVE)	Virginia Natural Gas		24		40		86		2012		2017
Total		$	226	$	1,285		2,930

In Bcf	Storage schedule (WACOG $3.42)		Expected net operating revenues (in millions)
First quarter - 2014		35	$	26
Second quarter - 2014		1		2
Total at December 31, 2013		36	$	28
Total at December 31, 2012		51	$	27

In millions	Expected net operating revenues
2014	$	63
2015		7
2016 and thereafter		3
Total at December 31, 2013	$	73
Total at December 31, 2012	$	3

	# of Employees		Contract Expiration Date
Nicor Gas International Brotherhood of Electrical Workers (Local No. 19) (1)		1,351	February 2014
Virginia Natural Gas International Brotherhood of Electrical Workers (Local No. 50)		132	May 2015
Elizabethtown Gas Utility Workers Union of America (Local No. 424)		172	November 2015
Total		1,655
(1) Contract negotiations are ongoing; however, we do not expect a new contract to be finalized prior to the expiration of the current contract. We have a continuation agreement in place and do not expect this to result in a work stoppage.

	Sales price of common stock				Cash dividend per common			Sales price of common stock				Cash dividend per common
Quarter ended:	High		Low		Share		Quarter ended:	High		Low		share
March 31, 2013	$	42.37	$	38.86	$	0.47	March 31, 2012 (1)	$	42.88	$	38.42	$	0.36
June 30, 2013		44.85		41.21		0.47	June 30, 2012		40.29		36.59		0.46
September 30, 2013		47.00		41.94		0.47	September 30, 2012		41.95		38.45		0.46
December 31, 2013		49.31		44.56		0.47	December 31, 2012		41.71		36.90		0.46
					$	1.88						$	1.74

Dollars and shares in millions, except per share amounts	2013			2012 (1)			2011 (1)			2010			2009
Income statement data
Operating revenues	$	4,617		$	3,922		$	2,338		$	2,373		$	2,317
Operating expenses
Cost of goods sold		2,332			1,791			1,097			1,164			1,142
Operation and maintenance (2)		999			921			501			497			497
Depreciation and amortization		418			415			186			160			158
Nicor merger expenses (2)		-			20			57			6			-
Taxes other than income taxes		193			165			57			46			44
Total operating expenses		3,942			3,312			1,898			1,873			1,841
Gain on sale of Compass Energy		11			-			-			-			-
Operating income		686			610			440			500			476
Other income (expense)		17			24			7			(1	)		9
EBIT		703			634			447			499			485
Interest expenses		181			184			136			109			101
Earnings before income taxes		522			450			311			390			384
Income taxes		191			164			125			140			135
Net income		331			286			186			250			249
Less net income attributable to the noncontrolling interest		18			15			14			16			27
Net income attributable to AGL Resources Inc.	$	313		$	271		$	172		$	234		$	222
Common stock data
Diluted weighted average common shares outstanding		118.3			117.5			80.9			77.8			77.1
Diluted earnings per common share - attributable to AGL Resources Inc. common shareholders	$	2.64		$	2.31		$	2.12		$	3.00		$	2.88
Dividends declared per common share (3)	$	1.88		$	1.74		$	1.90		$	1.76		$	1.72
Dividend payout ratio		71	%		75	%		89	%		58	%		60	%
Dividend yield (4)		4.0	%		4.4	%		4.5	%		4.9	%		4.7	%
Price range:
High	$	49.31		$	42.88		$	43.69		$	40.08		$	37.52
Low	$	38.86		$	36.59		$	34.08		$	34.21		$	24.02
Close (5)	$	47.23		$	39.97		$	42.26		$	35.85		$	36.47
Market value (5)	$	5,615		$	4,711		$	4,946		$	2,800		$	2,826
Statements of Financial Position data (5)
Total assets	$	14,656		$	14,141		$	13,913		$	7,520		$	7,079
Property, plant and equipment - net		8,781			8,347			7,900			4,405			4,146
Short-term debt		1,171			1,377			1,321			733			602
Long-term debt		3,813			3,553			3,578			1,971			1,974
Total debt		4,984			4,930			4,899			2,704			2,576
Total equity		3,676			3,435			3,339			1,836			1,819
Financial ratios (5)
Debt		58	%		59	%		59	%		60	%		59	%
Equity		42	%		41	%		41	%		40	%		41	%
Total		100	%		100	%		100	%		100	%		100	%
Return on average equity		8.8	%		8.0	%		6.6	%		12.8	%		12.7	%

									2013 vs.			2012 vs.			2013 vs.			2012 vs.			2011 vs.
Weather (Heating Degree Days)	Year ended December 31,								2012			2011			normal			normal			normal
	Normal (1)		2013		2012		2011		colder (warmer)			colder (warmer)			colder (warmer)			colder (warmer)			colder (warmer)
Year ended December 31,
Illinois (2)		5,729		6,305		4,863		5,892		30	%		(17	)%		10	%		(15	)%		3	%
Georgia		2,600		2,689		1,934		2,454		39	%		(21	)%		3	%		(26	)%		(6	)%

Quarter ended December 31,
Illinois (2)		2,039		2,383		1,890		1,810		26	%		4	%		17	%		(7	)%		(11	)%
Georgia		1,009		1,049		878		852		19	%		3	%		4	%		(13	)%		(16	)%

Customers and service contracts	Year ended December 31,									2013 vs. 2012 change						2012 vs. 2011 change
(average end-use, in thousands)	2013			2012			2011				#		%				#		%
Distribution operations customers		4,479			4,459			4,454			20			0.4	%		5			0.1	%
Retail operations
Energy customers (1)		619			623			578			(4	)		(1	)%		45			8	%
Service contracts (2)		1,127			684			710			443			65	%		(26	)		(4	)%
Market share in Georgia		31	%		32	%		33	%					(3	)%					(3	)%

Volumes
	Year ended December 31,									2013 vs. 2012			2012 vs. 2011
Distribution operations (In Bcf)	2013			2012			2011			% change			% change
Firm		720			606			247			19	%		145	%
Interruptible		111			107			105			4	%		2	%
Total		831			713			352			17	%		103	%
Retail operations (In Bcf)
Georgia firm		38			31			35			23	%		(11	)%
Illinois		9			8			-			13	%		-
Other (1)		8			8			10			-			(20	)%
Wholesale services
Daily physical sales (Bcf/day)		5.73			5.54			5.21			3	%		6	%
Cargo shipping (TEU’s - in thousands)
Shipments		187			170			n/a			10	%		n/a
	As of December 31,
		2013			2012			2011
Midstream operations
Working natural gas capacity (in Bcf)		31.8			31.8			13.5
% of firm capacity under subscription by third parties (2)		33	%		46	%		68	%

	Operating Margin (1) (2)							Operating Expenses (2) (3)						EBIT (1)
In millions	2013		2012			2011 (4)		2013		2012		2011 (4)		2013 (5)			2012			2011 (4)
Distribution operations	$	1,660	$	1,571		$	963	$	1,093	$	1,048	$	557	$	582		$	532		$	412
Retail operations		294		247			168		157		131		75		137			116			93
Wholesale services		37		50			57		52		54		52		(4	)		(3	)		5
Midstream operations		41		46			37		46		38		28		(10	)		10			9
Cargo shipping		143		134			7		140		137		8		12			8			-
Other		-		(2	)		-		12		28		72		(14	)		(29	)		(72	)
Consolidated	$	2,175	$	2,046		$	1,232	$	1,500	$	1,436	$	792	$	703		$	634		$	447

In millions	2013
EBIT - prior year	$	8

Operating margin
TEU volume increased due to market share expansion and modest improvement in economic conditions in our service regions; leverage effect of volume increases on fuel expense		21
Decreased average TEU rates due to changes in cargo mix and competitive pressures, partially offset by general ocean freight rate increases		(10	)
Other		(2	)
Increase in operating margin		9

Operating expenses
Increased operation and maintenance expenses		6
Decreased depreciation expense		(3	)
Increase in operating expenses		3
Decrease from equity investment income in Triton		(2	)
EBIT - current year	$	12

In millions	Year-end balance outstanding (1)		Daily average balance outstanding (2)		Minimum balance outstanding (2)		Largest balance outstanding (2)
Commercial paper - AGL Capital	$	857	$	777	$	380	$	1,064
Commercial paper - Nicor Gas		314		99		-		340
Senior Notes - Current Portion		-		64		-		225
Capital leases - Current Portion		-		-		-		1
Total short-term debt and current portions of long-term debt and capital leases	$	1,171	$	940	$	380	$	1,630

	Issuance Date	Amount (in millions)		Term (in years)		Interest rate
Gas facility revenue bonds	(1)	$	200		10-20	Floating rate
Senior notes (2)	May 2013	$	500		30		4.4	%
Senior notes - Series A (3) (4)	October 2011	$	120		5		1.9	%
Senior notes - Series B (3)	October 2011	$	155		7		3.5	%
Senior notes (3)	September 2011	$	200		30		5.9	%
Senior notes (3)	September 2011	$	300		10		3.5	%
Senior notes (5)	March 2011	$	500		30		5.9	%

In millions	2014 (1)		2013		2012		2011 (2)
Distribution business	$	503	$	421	$	371	$	159
Regulatory infrastructure programs		163		226		263		192
Natural gas storage		4		6		55		22
Other		120		96		93		54
Total	$	790	$	749	$	782	$	427

	Pension plans			Other retirement plans
Discount rate		5.00	%		4.70	%
Expected return on plan assets		7.75	%		7.75	%

Company RTSR Rank	Percentile Rank	Award Payment Level
1	100%	200%
2	92%	184%
3	83%	166%
4	75%	150%
5	67%	134%
6	58%	116%
7	50%	100%
8	42%	84%
9	33%	66%
10	25%	50%
>10	0%	0%

	Fiscal			Fiscal			Fiscal			Fiscal			Fiscal
Dollars in millions	2013			2012			2011			2010			2009
Earnings before income taxes	$	522		$	450		$	311		$	390		$	384
Add:
Fixed charges (see “B” below)		200			203			145			123			115
Amortization of capitalized interest (1)		-			-			1			-			-
Distributed income of equity investees		3			14			-			-			-
Less:
Interest capitalized (1)		-			(1	)		(1	)		(5	)		(3	)
Noncontrolling interest in pre-tax income of subsidiaries that have not incurred fixed charges		(18	)		(15	)		(14	)		(16	)		(27	)
Adjusted earnings (A)	$	707		$	651		$	442		$	492		$	469

Fixed charges
Interest on long-term debt	$	182		$	177		$	101		$	109		$	98
Other interest, including amortized premiums, discounts and capitalized expenses related to indebtedness liability		6			13			37			7			10
Estimated interest components of rentals		12			13			7			7			7
Total fixed charges (B)	$	200		$	203		$	145		$	123		$	115

Ratio of earnings to fixed charges (A)/(B)		3.54			3.21			3.05			4.00			4.08

Name of Subsidiary	State of Incorporation
AGL Capital Corporation	Nevada
Atlanta Gas Light Company	Georgia
Georgia Natural Gas Company	Georgia
SouthStar Energy Services LLC (2)	Delaware
Northern Illinois Gas Company (3)	Illinois
Pivotal Utility Holdings, Inc. (4)	New Jersey

1.	I have reviewed this annual report on Form 10-K of AGL Resources Inc.;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
	(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 6, 2014	/s/ John W. Somerhalder II
	Chairman, President and Chief Executive Officer

Note 3 - Regulated Operations (Details) - Summary of Regulatory Assets and Liabilities (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Regulatory assets
Regulatory assets - current	$ 162	$ 145
Regulatory assets - long-term	737	944
Total regulatory assets	899	1,089
Regulatory liabilities
Regulatory liabilities - current	183	161
Regulatory liabilities - long-term	1,518	1,477
Total regulatory liabilities	1,701	1,638
Accrued natural gas costs [Member]
Regulatory liabilities
Regulatory liabilities - current	92	93
Bad debt rider [Member]
Regulatory liabilities
Regulatory liabilities - current	41	37
Regulatory liabilities - long-term	17	17
Accumulated removal costs [Member]
Regulatory liabilities
Regulatory liabilities - current	27	16
Regulatory liabilities - long-term	1,445	1,393
Other Regulatory Liabilities [Member]
Regulatory liabilities
Regulatory liabilities - current	23	15
Regulatory liabilities - long-term	3	11
Regulatory Income Tax Liability [Member]
Regulatory liabilities
Regulatory liabilities - long-term	27	27
Unamortized investment tax credit [Member]
Regulatory liabilities
Regulatory liabilities - long-term	26	29
Recoverable regulatory infrastructure program costs [Member]
Regulatory assets
Regulatory assets - current	48	47
Regulatory assets - long-term	87	167
Recoverable Environmental Remediation Costs [Member]
Regulatory assets
Regulatory assets - current	45	38
Regulatory assets - long-term	433	438
Recoverable Pension And Other Retirement Benefit Costs [Member]
Regulatory assets
Regulatory assets - current	9	19
Regulatory assets - long-term	99	196
Other Regulatory Assets [Member]
Regulatory assets
Regulatory assets - current	60	41
Regulatory assets - long-term	36	53
Long-Term Debt Fair Value Adjustment [Member]
Regulatory assets
Regulatory assets - long-term	$ 82	$ 90

Note 2 - Significant Accounting Policies and Methods of Application (Details) - Estimated Useful Lives of Assets	12 Months Ended
	Dec. 31, 2013
Gas, Transmission and Distribution Equipment [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciable Property, Estimated Useful Life	5
Gas, Transmission and Distribution Equipment [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciable Property, Estimated Useful Life	10
Shipping Vessels and Containers [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciable Property, Estimated Useful Life	20
Shipping Vessels and Containers [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciable Property, Estimated Useful Life	25
Storage Facilities [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciable Property, Estimated Useful Life	40
Storage Facilities [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciable Property, Estimated Useful Life	60
Property, Plant and Equipment, Other Types [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciable Property, Estimated Useful Life	40

Note 6 - Employee Benefit Plans (Details) - One-Percentage-Point Change in Assumed Health Care Cost (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
One-Percentage-Point Change in Assumed Health Care Cost [Abstract]
1% Health care cost trend rate increase	$ 15
1% Health care cost trend rate decrease	$ (13)

Note 6 - Employee Benefit Plans (Details) - Expected Benefit Payments (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Pension Plan, Defined Benefit [Member]
Note 6 - Employee Benefit Plans (Details) - Expected Benefit Payments [Line Items]
2014	$ 56
2015	60
2016	63
2017	66
2018	68
2019 - 2023	366
Other Postretirement Benefit Plan, Defined Benefit [Member]
Note 6 - Employee Benefit Plans (Details) - Expected Benefit Payments [Line Items]
2014	20
2015	20
2016	21
2017	22
2018	23
2019 - 2023	$ 123

Note 8 - Debt and Credit Facilities (Details) - Debt-to-Capitalization Ratios	Dec. 31, 2013	Dec. 31, 2012
AGL Resources Inc [Member]
Schedule of Capitalization [Line Items]
Debt-to-capitalization ratio	0.57	0.58
Nicor Gas [Member]
Schedule of Capitalization [Line Items]
Debt-to-capitalization ratio	0.55	0.55

Note 9 - Equity (Details)	12 Months Ended
Note 9 - Equity (Details)	Dec. 31, 2013	Dec. 31, 2012	Jan. 31, 2011
Stockholders' Equity Note [Abstract]
Stock Repurchase Program, Number of Shares Authorized to be Repurchased			8,000,000
Treasury Stock, Shares, Acquired	0	0

Note 7 - Stock-Based Compensation (Details) (USD $)	12 Months Ended
Note 7 - Stock-Based Compensation (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Note 7 - Stock-Based Compensation (Details) [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Stock Options (in Dollars)	$ 0	$ 0
Proceeds from Stock Options Exercised (in Dollars)	21,000,000	7,000,000
Employee Service Share-based Compensation, Tax Benefit Realized from Exercise of Stock Options (in Dollars)		1,000,000
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Lower Range Limit (in Dollars per share)	$ 30.70
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Upper Range Limit (in Dollars per share)	$ 43.85
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross	0	0	1,685
Employee Stock Option [Member]
Note 7 - Stock-Based Compensation (Details) [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period	10 years
Restricted Stock Units (RSUs) [Member]
Note 7 - Stock-Based Compensation (Details) [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	43,830
Stock Awards [Member] \| Non-Employee Directors [Member]
Note 7 - Stock-Based Compensation (Details) [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	26,915
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage		100.00%
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value (in Dollars per share)	$ 44.04
Nicor Gas [Member] \| Long Term Incentive Plan [Member]
Note 7 - Stock-Based Compensation (Details) [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	1,697,363
Omnibus Performance Incentive Plan [Member]
Note 7 - Stock-Based Compensation (Details) [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	641,371
Share-based Compensation Arrangement by Share-based Payment Award, Number of Additional Shares Authorized	4,288,563
Long Term Incentive Plan [Member]
Note 7 - Stock-Based Compensation (Details) [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	640,082
Employee Stock Purchase Plan [Member]
Note 7 - Stock-Based Compensation (Details) [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	122,763
Share-based Compensation Arrangement by Share-based Payment Award, Purchase Price of Common Stock, Percent	85.00%
Share-based Compensation Arrangement by Share-based Payment Award, Discount from Market Price, Purchase Date	15.00%
Employee Stock Purchase Plan, Maximum Contributions Per Employee (in Dollars)	$ 25,000