UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
  
(Mark One)
þANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2010
OR
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from           to2013
 
Commission File Number 1-14174
 
AGL RESOURCES INC.
(Exact name of registrant as specified in its charter)Ten Peachtree Place NE,
Atlanta, Georgia 30309
404-584-4000
  
Georgia58-2210952
(State or other jurisdiction of incorporation or organization)incorporation)(I.R.S. Employer Identification No.)
  
Ten Peachtree Place NE,404-584-4000
Atlanta, Georgia 30309
(Address and zip code of principal executive offices)(Registrant’s telephone number, including area code)
  
Securities registered pursuant to Section 12(b) of the Act:
  
Title of each className of each exchange on which registered
Common Stock, $5 Par ValueNew York Stock Exchange
  
Securities registered pursuant to Section 12(g) of the Act: None
 
Indicate by check mark if the registrantAGL Resources Inc. is a well-known seasoned issuer, as defined in Rule 405 under the Securities Act.            Yes þ  No  ¨
issuer.
 
Indicate by check mark if the registrantAGL Resources Inc. is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act. Yes ¨  No  þ
 
Indicate by check mark whether the registrant:AGL Resources Inc.: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days. Yes þ  No  ¨
  
Indicate by check mark whether the registrantAGL Resources Inc. has submitted electronically and posted on its corporate Web site, if any,website every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨
months.
 
Indicate by check mark if disclosureAGL Resources Inc. believes that during the 2013 fiscal year, its executive officers, directors and 10% beneficial owners subject to Section 16(a) of delinquent filers pursuant to Item 405the 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 Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨Shareholders.
Indicate by check mark whether the registrantAGL Resources Inc. is a large accelerated filer an accelerated filer, a non-accelerated filer, or a smaller reporting company
Large accelerated filer  þ                 Accelerated filer  ¨                 Non-accelerated filer ¨                 Smaller reporting company ¨
                                                                                     (Doand is not check if smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes ¨  No þ
company.
 
The aggregate market value of the registrant’s voting and non-votingAGL Resources Inc.’s common equitystock held by non-affiliates of the registrant computed(based on the closing sale price on June 29, 2013, as reported by reference to the price at which the registrant’s common stockNew York Stock Exchange), was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter, was $2,792,228,461.$5,081,511,045.
  
The number of shares of the registrant’sAGL Resources Inc.’s common stock outstanding as of January 31, 20112014 was 77,999,557.118,901,889.
  
DOCUMENTS INCORPORATED BY REFERENCE:
 
Portions of the Proxy Statement for the 20112014 Annual Meeting of Shareholders (“Proxy Statement”)(Proxy Statement) to be held May 3, 2011,on April 29, 2014, are incorporated by reference in Part III.III of this Form 10-K.

 
 

 

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2



GLOSSARY OF KEY TERMS

AFUDCAllowance 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 CapitalAGL Capital Corporation
AGL NetworksCredit Facility$1.3 billion credit agreement entered into by AGL Capital to support the AGL Capital commercial paper program
AGL ResourcesAGL Networks, LLCResources Inc., together with its consolidated subsidiaries
Atlanta Gas LightAtlanta Gas Light Company
BcfBillion cubic feet
Bridge Facility
Central Valley
$1.05 billion credit agreement entered into by AGL Capital to help finance a portion of the proposed merger with Nicor.Central Valley Gas Storage, LLC
Chattanooga GasChattanooga Gas Company
Credit FacilityChicago Hub$1 billion credit agreement entered into by AGL CapitalA venture of Nicor Gas, which provides natural gas storage and transmission-related services to marketers and gas distribution companies
California CommissionCalifornia Public Utilities Commission, the state regulatory agency for Central Valley
Compass EnergyCompass Energy Services, Inc., which was sold in 2013
EBIT
Earnings before interest and taxes, a non-GAAPthe primary measure thatof our operating segments’ profit or loss, which includes operating income and other income and excludes financing costs, including interest andon debt and income tax expense each of which we evaluate on a consolidated level; as an indicator of our operating performance, EBIT should not be considered an alternative to, or more meaningful than, earnings before income taxes, or net income attributable to AGL Resources Inc. as determined in accordance with GAAP
EPAU.S. Environmental Protection Agency
ERCEnvironmental remediation costs associated with our distribution operations segment whichthat are generally recoverable through rate mechanisms
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
FitchFitch Ratings
Florida CommissionFlorida Public Service Commission, the state regulatory agency for Florida City Gas
GAAPAccounting principles generally accepted in the United States of America
Georgia CommissionGeorgia Public Service Commission, the state regulatory agency for Atlanta Gas Light
GNGGeorgia Natural Gas theThe trade name under which SouthStar does business in Georgia
Golden Triangle StorageGolden Triangle Storage, Inc.
Hampton RoadsVirginia Natural Gas’ pipeline project which connects its northern and southern pipelines
Heating Degree DaysA measure of the effects of weather on our businesses, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
Heating SeasonThe period from November tothrough March when natural gas usage and operating revenues are generally higher because more customers are connected to our distribution systems when weather is colder
Henry HubA major interconnection point of natural gas pipelines in Erath, Louisiana where NYMEX natural gas future contracts are priced
Illinois CommissionIllinois Commerce Commission, the state regulatory agency for Nicor Gas
Jefferson IslandJefferson Island Storage & Hub, LLC
LIBORLondon Inter-Bank Offered Rate
LIFOLast-in, first-out
LNGLiquefied natural gas
LOCOMLower of weighted average cost or current market price
MagnoliaMagnolia Enterprise Holdings, Inc.
MarketersMarketers selling retail natural gas in Georgia and certificated by the Georgia Commission
McfMillion cubic feet
MGPManufactured gas plant
Moody’sMoody’s Investors Service
New Jersey BPUNew Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas
NicorNicor Inc., - an acquisition completed in December 2011 and former holding company of Nicor Gas
Nicor GasNorthern Illinois corporationGas 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
NUINUI Corporation – an acquisition completed in November 2004
NYMEXNew York Mercantile Exchange, Inc.
OCIOther comprehensive income
Operating marginA non-GAAP measure of income, calculated as operating revenues minus cost of gas, that excludes operationgoods sold and maintenancerevenue tax expense depreciation and amortization, taxes other than income taxes, and the gain or loss on the sale of our assets; these items are included in our calculation of operating income as reflected in our Consolidated Statements of Income. Operating margin should not be considered an alternative to, or more meaningful than, operating income as determined in accordance with GAAP
OTCOver-the-counter
Pad gasVolumes of non-working natural gas used to maintain the operational integrity of the natural gas storage facility, also known as base gas
PBRPerformance-based rate, a regulatory plan at Nicor Gas that provided economic incentives based on natural gas cost performance. The plan terminated in 2003
PGAPurchased Gas Adjustment
PiedmontPiedmont Natural Gas Company, Inc.
Pivotal Home SolutionsNicor Energy Services Company, doing business as Pivotal Home Solutions
Pivotal UtilityPivotal Utility Holdings, Inc., doing business as Elizabethtown Gas, Elkton Gas and Florida City Gas
PP&EProperty, plant and equipment
S&PStandard & Poor’s Ratings Services
Sawgrass StorageSawgrass Storage, LLC
SECSecurities and Exchange Commission
SequentSequent Energy Management, L.P.
Seven SeasSeven Seas Insurance Company, Inc.
SNGSubstitute natural gas, a synthetic form of gas manufactured from coal
SouthStarSouthStar Energy Services LLC
STRIDEAtlanta Gas Light’s Strategic Infrastructure Development and Enhancement program
Tennessee AuthorityTennessee Regulatory Authority, the state regulatory agency for Chattanooga Gas.Gas
Term Loan Facility$300 million credit agreement entered into by AGL Capital to repay the $300 million senior notes duethat matured in 2011
TEUTwenty-foot equivalent unit, a measure of volume in containerized shipping equal to one 20-foot-long container
TritonTriton Container Investments LLC
Tropical ShippingTropical Shipping and Construction Company Limited
U.S.United States
VaRValue at riskValue-at-risk is defined as the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probabilityprobability.
Virginia Natural GasVirginia Natural Gas, Inc.
Virginia CommissionVirginia State Corporation Commission, the state regulatory agency for Virginia Natural Gas
WACOGWeighted average cost of gas
WNAWeather normalization adjustment

3

Forward-Looking Statements

Certain expectations and projections regarding our future performance referenced in this section and elsewhere in this report, as well as in other reports and proxy statements we file with the SEC or otherwise release to the public and on our website are forward-looking statements within the meaning of the U.S. federal securities laws and are subject to uncertainties and risks, as itemized in Item 1A “Risk Factors”, in this Form 10-K. Senior officers and other employees may also make verbal statements to analysts, investors, regulators, the media and others that are forward-looking.

Forward-looking statements involve matters that are not historical facts, and because these statements involve anticipated events or conditions, forward-looking statements often include words such as "anticipate," "assume," “believe,” "can," "could," "estimate," "expect," "forecast," "future," “goal,” "indicate," "intend," "may," “outlook,” "plan," “potential,” "predict," "project,” “proposed,” "seek," "should," "target," "would," or similar expressions. You are cautioned not to place undue reliance on our forward-looking statements. Our expectations are not guarantees and are based on currently available competitive, financial and economic data along with our operating plans. While we believe that our expectations ar e reasonable in view of currently available information, our expectations are subject to future events, risks and uncertainties, and there are numerous factors - many beyond our control - that could cause our actual results to vary significantly from our expectations.

Such events, risks and uncertainties include, but are not limited to, changes in price, supply and demand for natural gas and related products; the impact of changes in state and federal legislation and regulation including any changes related to climate change; actions taken by government agencies on rates and other matters; concentration of credit risk; utility and energy industry consolidation; the impact on cost and timeliness of construction projects by government and other approvals, development project delays, adequacy of supply of diversified vendors, unexpected change in project costs, including the cost of funds to finance these projects; the impact of acquisitions and divestitures; direct or indirect effects on our business, financial condition or liquidity resulting from a change in our credit ratings or the credit ratings of our counterparties or competitors; interest rate fluctuations; financial market conditions, including recent disruptions in the capital markets and lending environment and the current economic downturn; and general economic conditions; uncertainties about environmental issues and the related impact of such issues; the impact of changes in weather, including climate change, on the temperature-sensitive portions of our business; the impact of natural disasters such as hurricanes on the supply and price of natural gas; acts of war or terrorism; and other factors described in detail in our filings with the SEC.

In addition, actual results may differ materially due to the expected timing and likelihood of completion of the proposed merger with Nicor, including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the proposed merger that could reduce anticipated benefits or cause the parties to abandon the merger, the diversion of management's time and attention from our ongoing business during this time period, the ability to maintain relationships with customers, employees or suppliers as well as the ability to successfully integrate the businesses and realize cost savings and any other synergies and the risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect.

We caution readers that the important factors described elsewhere in this report, among others, could cause our business, results of operations or financial condition to differ significantly from those expressed in any forward-looking statements. There also may be other factors that we cannot anticipate or that are not described in this report that could cause results to differ significantly from our expectations.

Forward-looking statements are only as of the date they are made. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of future events, new information or otherwise, except as required under U.S. federal securities law.

PART I

ITEM 1.1. BUSINESS

Nature of Our Business

Unless the context requires otherwise, references to “we,” “us,” “our,”“our” and the “company” and “AGL Resources” are intended to mean consolidated AGL Resources Inc. The operations and its subsidiaries. Webusinesses described in this filing are owned and operated, and management services are provided, by distinct direct and indirect subsidiaries of AGL Resources. AGL Resources was organized and incorporated in 1995 under the laws of the State of Georgia.

Business Overview

AGL Resources, headquartered in Atlanta, Georgia, is an energy services holding company whose principalprimary business is the distribution of natural gas through our natural gas distribution utilities. We also are involved in six states - Florida, Georgia, Maryland, New Jersey, Tennesseeseveral other businesses that are mainly related and Virginia.complementary to our primary business. Our six utilities serve approximately 2.3 million end-use customers.operating segments consist of the following five operating and reporting segments which are consistent with how management views and manages our businesses.

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

We are also involved in several relatedFor more information on our segments, see Item 7, “Management’s Discussion and complementary businesses, including retail natural gas marketingAnalysis of Financial Condition and Results of Operations” under the caption “Results of Operations” and Note 13 to end-use customers in Georgia, Ohio and Florida; natural gas asset management and related logistics activities for each of our utilities as well as for non-affiliated companies; natural gas storage arbitrage and related activities; and the development and operation of high-deliverability natural gas storage assets. We manage these businesses through four operating segments — distribution operations, retail energy operations, wholesale services and energy investments — and a non-operating corporate segment.consolidated financial statements under Item 8 herein.


4

Proposed Merger with Nicor

InOn December 2010,9, 2011, we entered into an Agreementclosed our merger with Nicor and Plan of Merger (the Merger Agreement)created a combined company with Nicor. In accordance with the Merger Agreement, each share of Nicor common stock outstanding at the Effective Time (as definedincreased scale and scope in the Merger Agreement), other than shares to be cancelled,distribution, storage and Dissenting Shares (as defined in the Merger Agreement), will be converted into the right to receive consideration consistingtransportation of (i) $21.20 in cash and (ii) 0.8382 shares of our common stock, subject to adjustment in certain circumstances.

The completionnatural gas. As a result, we are currently one of the proposed merger is subject to various customary conditions, including, among others (i) shareholder approval by bothnation’s largest natural gas distribution companies (ii) expiration or terminationbased on customer count. The effects of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements ActNicor’s results of 1976, (iii) the SEC’s clearance of a registration statement registering our common stock to be issued in connection with the proposed mergeroperations and (iv) receipt of all required regulatory approvals from, among others, the Illinois Commerce Commission.

The Merger Agreement contains certain termination rights for both us and Nicor, and further providesfinancial condition are reflected for the payment of fees12 months ended December 31, 2013 and expenses upon termination under specified circumstances. The proposed merger is expected to be completed in the second half of 2011. Except for specific references to the proposed merger, the disclosures contained in this report on Form 10-K relate solely to AGL Resources.

In January2012, while our 2011 we filed a joint application with Nicor to the Illinois Commerce Commission for approval of the proposed merger. The application did not request a rate increase, but didresults include a commitment to maintain the number of full-time equivalent employees at Nicor’s natural gas utility for a period of three years following merger completion. The Illinois Commerce Commission has eleven months to act upon the application; however, we and Nicor have asked for approval of the merger by October 1, 2011.

For additional information relating to the proposed merger please see our Form 8-K filed onactivity from December 7, 2010 and the joint proxy statement / prospectus contained in the registration statement on Form S-4 filed on February 4,10, 2011 through December 31, 2011.

Distribution Operations

Our distribution operations segment is the largest component of our business and includes sixseven natural gas local distribution utilities.utilities with their primary focus being the safe and reliable delivery of natural gas. These utilities construct, manage and maintain intrastate natural gas pipelines and distribution facilities and include:

·  Atlanta Gas Light in Georgia
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 
·  Chattanooga Gas in Tennessee
·  Elizabethtown Gas in New Jersey
·  Elkton Gas in Maryland
·  Florida City Gas in Florida
·  Virginia Natural Gas in Virginia

Utility Regulation and Rate Design

Rate Structures Each utility operates subject to regulations and oversight of the state regulatory agencies in each of the six states that we serve with respect to rates charged to our customers, maintenance of accounting records and various service and safety matters. Rates charged to our customers vary according to customer class (residential, commercial or industrial) and rate jurisdiction. These agencies approve rates designed to provide us the opportunity to generate revenues to recover all prudently incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable return for our shareholders. Rate base generally consists of the original cost of utility plant in service, working capital and certain other assets; less accumulated depreciation on utility plant in service and net deferred income tax liabilities, and may include certain other additions or deductions.

For our largest utility, Atlanta Gas Light, the natural gas market was deregulated in 1997. Accordingly, Marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia and handle customer billing functions. The Marketers file their rates monthly with the Georgia Commission. As a result of operating in a deregulated environment, Atlanta Gas Light's role includes:

·  distributing natural gas for Marketers
·  constructing, operating and maintaining the gas system infrastructure, including responding to customer service calls and leaks
·  reading meters and maintaining underlying customer premise information for Marketers
·  planning and contracting for capacity on interstate transportation and storage systems

Atlanta Gas Light earns revenue by charging rates to its customers based primarily on monthly fixed charges that are periodically adjusted. The Marketers add these fixed charges to customer bills. This mechanism, called a straight-fixed-variable rate design minimizes the seasonality of Atlanta Gas Light’s revenues since the monthly fixed charge is not volumetric or directly weather dependent.

With the exception of Atlanta Gas Light, the earnings of our regulated utilities can be affected by customer consumption patterns that are a function of weather conditions and price levels for natural gas. Specifically, customer demand substantially increases during the Heating Season when natural gas is used for heating purposes. Various mechanisms such as weather normalization mechanisms exist at most of our utilities that limit our exposure to weather changes within typical ranges in all of our jurisdictions.
54

All of 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 does not need or utilize a natural gas cost recovery mechanism.

In traditional rate designs, utilities recover a significant portion of their fixed customer service and pipeline infrastructure costs based on assumed natural gas volumes used by our customers. Four of our utilities have “decoupled” regulatory mechanisms in place that encourage conservation. We believe that separating, or decoupling, the recoverable amount of these fixed costs from the customer throughput volumes, or amounts of natural gas used by our customers, allows us to encourage our customers’ energy conservation and ensures a more stable recovery of our fixed costs.

Recent Regulatory Actions In May 2010, the Tennessee Authority approved new base rates for Chattanooga Gas, which went into effect in June 2010. These new rates include energy-efficiency and conservation programs, as well as a mechanism to recover lost revenue resulting from these programs, updated depreciation rates that resulted in decreased depreciation expense of $2 million annually, and the recovery of approximately $1 million in prior legal expenses. The approved rate adjustment includes a reduction in the authorized return on equity from 10.3% to 10.05%. This decoupled rate design is the first such program for a utility in Tennessee.

In October 2010, the Georgia Commission voted and approved an annual increase of $27 million in base rate revenues for Atlanta Gas Light which became effective in November 2010. These new rates are reflected in Atlanta Gas Light’s base rate charges assessed to customers by their Marketer.

The Georgia Commission also adopted a new acquisition synergy sharing policy that allows Atlanta Gas Light to recover 50% of net synergy savings achieved on future acquisitions for a period of ten years. The policy also allows Atlanta Gas Light to recover, through December 2015, 25%, or $4 million annually, in acquisition synergy savings it continues to achieve from the 2004 NUI acquisition.

The annual rate increase also includes approximately $10 million in new customer service and safety oriented programs which Atlanta Gas Light will invest in technology and hire additional employees to support the programs. The decision also restores a standard depreciation methodology used to calculate net salvage value of utility assets, resulting in an increase in depreciation expenses of approximately $2 million.
In February 2011, Virginia Natural Gas filed a rate case with the Virginia Commission, seeking a net increase in revenues of $25 million. This requested rate increase is primarily the result of our infrastructure investments over the past ten years, including the Hampton Roads pipeline project and operational cost increases. The rate case requested a 10.95% return on equity and an authorized equity to total capitalization ratio of 51%. In order to mitigate the impact of the proposed rate increase on customer bills, we are proposing an alternative rate schedule that would phase in the Hampton Roads pipeline project capital recovery into base rates over a three year period. We expect the Virginia Commission to make a decision on this rate case within 12-18 months of our filing. New ra tes could go into effect, subject to refund, on August 1, 2011.
6

The following table provides regulatory information for our largest utilities.
  Atlanta Gas Light  Elizabethtown Gas  Virginia Natural Gas  Florida City Gas  Chattanooga Gas
Authorized return on rate base (1)
  8.10%  7.64%  9.24%  7.36%  7.41%
Estimated 2010 return on rate base (2)
  7.26%  7.87%  8.24%  5.04%  8.98%
Authorized return on equity (1)
  10.75%  10.30%  10.90%  11.25%  10.05%
Estimated 2010 return on equity (2)
  9.10%  10.76%  9.62%  6.22%  13.45% 
Authorized rate base % of equity (1)
  51.0%  47.9%  52.4%  36.8%  46.06% 
Rate base included in 2010 return on equity (in millions) (3)
 $1,312  $435  $502  $164  $91 
Performance based rates (4)
         ü          
Weather normalization (5)
     ü  ü      ü
Decoupled or straight-fixed-variable rates (6)
 ü      ü      ü
Regulatory infrastructure program rates (7)
 ü  ü              
Synergy sharing policy (8)
 ü                  
Last decision on change in rates Oct 2010  Dec 2009  July 2006   N/A  May 2010
(1)  The authorized return on rate base, return on equity, and percentage of equity were those authorized as of December 31, 2010.
(2)  Estimates based on principles consistent with utility ratemaking in each jurisdiction.
(3)  Estimated based on 13-month average.
(4)  Involves frozen rates.
(5)  Involves regulatory mechanisms that allow us to recover our costs in the event of unseasonal weather, but are not direct offsets to the potential impacts of weather and customer consumption on earnings. These mechanisms are designed to help stabilize operating results by increasing base rate amounts charged to customers when weather is warmer than normal and decreasing amounts charged when weather is colder than normal.
(6)  Decoupled and straight-fixed-variable rate designs allow for the recovery of fixed customer service costs separately from assumed natural gas volumes used by our customers.
(7)  Includes programs that update or expand our distribution systems and liquefied natural gas facilities. These programs include the program at Atlanta Gas Light and the utility infrastructure program at Elizabethtown Gas.
(8)  Involves the recovery of a portion of net synergy savings achieved on future acquisitions.
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. The following table provides more information on the costs related to remediation of our former operating sites.

In millions Cost estimate range  Amount recorded  Expected costs over next twelve months 
Georgia and Florida $57 - $105  $57  $3 
New Jersey  75 - 138   75   10 
North Carolina  11 - 16   11   1 
Total $143 - $259  $143  $14 

We report these estimates on an undiscounted basis. As we continue to conduct the actual remediation and enter into cleanup contracts, 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 uncertainties, and we regularly attempt to refine and update these engineering estimates. We primarily recover these costs through rate riders.

See item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Critical Accounting Estimates”, for additional information about our environmental remediation liabilities. Also see Item 8, “Financial Statements and Supplementary Data”, and Note 10, “Commitment and Contingencies”, for information on our environmental remediation efforts.

Competition and Customer Demand

All of our utilities face competition from other energy products. Our principal competition is fromcompetitors are electric utilities and oil and propane providers serving the residential, commercial and commercialindustrial markets throughout our service areas. Additionally, the potential displacement or replacement of natural gas appliances with electric appliances is a competitive factor.

Competition for space heating and general household and small commercial energy needs generally occurs at the initial installation phase when the customer or builder makes decisions as to which types of equipment to install. Customers generally continue to use the chosen energy source for the life of the equipment. Customer demand for natural gas could be affected by numerous factors, including:

·  changes in the availability or price of natural gas and other forms of energyenergy;
·  general economic conditionsconditions;
·  energy conservationconservation;
·  legislation and regulationsregulations;
·  the cost and capability to convert from natural gas to alternative fuelsfuels;
·  weatherweather;
·  new commercial constructionconstruction; and
·  new housing starts.

7

While there has been some improvement in the economic conditions within the areas we serve, there continue to be high rates of unemployment and depressed housing markets with high inventories, significantly reduced new home construction and a slow-down in new commercial development. As a result, we have experienced slight customer losses in our distribution operations segment.

Our year-over-year consolidated utility customer loss rate was (0.1)% in 2010, compared to (0.3)% for 2009. We anticipate overall competition and customer trends in 2011 to be similar to our 2010 results.

We continue to develop and growmitigate the effects of the current economic conditions on our business through ourthe use of a variety of targeted marketing programs designed to attract new customers and to retain existing customers. These efforts include working to add residential customers, multifamily complexes and commercial customers who use natural gas for purposes other than space heating, as well as evaluating and launching new natural gas related programs, products and services to enhance customer growth, mitigate customer attrition and increase operating revenues.

TheseThe natural gas related programs generally emphasize natural gas as the fuel of choice for customers and seek to expand the use of natural gas through a variety of promotional activities. In addition, we partner with numerous third-party entities such as builders, realtors, plumbers, mechanical contractors, architects and engineers to market the benefits of natural gas appliances and to identify potential retention options early in the process for those customers who might consider converting to alternative fuels.

Sources of Natural Gas Supply and Transportation Services

Procurement plans for natural gas supply and transportation to serve our regulated utility customers are reviewed and approved by our state utility commissions. We purchase natural gas supplies in the open market by contracting with producers, marketers and from our wholly owned subsidiary, Sequent, under asset management agreements. We also contract for transportation and storage services from interstate pipelines that are regulated by the FERC. On occasion, when firm pipeline services are temporarily not needed, we may release the services in the secondary market under FERC-approved capacity release provisions or utilize asset management arrangements, thereby reducing the net cost of natural gas charged to customers for most of our utilities. Peak-use requirements are met through utilization of company-owned storage facilities, pipeline transportation capacity, purchased storage services, peaking facilities and other supply sources, arranged by either our transportation customers or us. We have been able to obtain sufficient supplies of natural gas to meet customer requirements. We believe natural gas supply and pipeline capacity will be sufficiently available to meet market demands in the foreseeable future.

Transportation Our utilities use firm pipeline entitlements, storage services and/or peaking capacity contracted with interstate capacity providers to serve the firm natural gas supply needs of our customers. In addition, Nicor Gas, Atlanta Gas Light, Chattanooga Gas, Elizabethtown Gas and Virginia Natural Gas operate on-system LNG facilities, underground natural gas storage fields and/or propane/air plants to meet the gas supply and deliverability requirements of their customers in the winter period. Generally, we work to build a portfolio of year-round firm transportation, seasonal storage and short-duration peaking services that will meet the needs of our customers under severe weather conditions with adequate operational flexibility to reliably manage the variability inherent in servicing customers using natural gas for space heatingIncluding seasonal storage and peaking services in this portfolio is more efficient and cost effective than reserving firm pipeline capacity rights all year for a limited number of cold winter days.

Typically, our firm contracts range in duration from 3 to 10 years. We work to stagger terms to maintain our ability to adjust the overall portfolio to meet changing market conditions. Our utilities have contracted for capacity that is predominately sourced from producing areas in the midcontinent and gulf coast regions, and they continue to evaluate capacity options that will provide long-term access to reliable and affordable natural gas suppliesWe have and will continue to evaluate options to acquire capacity rights for shale gas being produced in close proximity to our service territories.

Given the number of agreements held by our utilities and the amount of capacity under contract, we make decisions as to the termination, extension or renegotiation of contracts every year. Slower demand and the growth in natural gas production from non-traditional supply basins have made the value assessment of capacity contracts more complex.

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Supply Six of our utilities use asset management agreements with regulatorsour wholly owned subsidiary, Sequent, for the primary purpose of reducing our utility customers’ gas cost recovery rates through payments to the utilities by Sequent (for Atlanta Gas Light these payments are controlled by the Georgia Commission and utilized for infrastructure improvements and to fund heating assistance programs, rather than for a reduction to gas cost recovery rates). Under these asset management agreements, Sequent supplies natural gas to the utility and markets excess capacity to improve the overall cost of supplying gas to the utility customers. At this time, the utilities primarily purchase their gas from Sequent. The purchase agreements require Sequent to provide firm gas to our utilities. However, these utilities maintain the right and ability to make their own gas supply purchases. This right allows our utilities to make long-term supply arrangements if they believe it is in the best interest of their customers. Nicor Gas has not entered into an asset management agreement with Sequent or any other parties.

Each agreement with Sequent has either an annual minimum guarantee within a profit sharing structure, a profit sharing structure without any annual minimum guarantee or a fixed fee. From the inception of these agreements in 2001 through 2013, Sequent has made sharing payments under these agreements totaling $225 million. The following table provides payments made by Sequent to our utilities under these agreements during the last three years.

  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  
(1)  Discussions are underway with the New Jersey BPU and we expect a new agreement to be in place prior to the March 2014 expiration date.

Utility Regulation and Rate Design

Rate Structures Our utilities operate subject to regulations and oversight of the state regulatory agencies in each of the states served by our jurisdictionsutilities with respect to educaterates charged to our customers, throughoutmaintenance of accounting records and various service and safety matters. Rates charged to our customers vary according to customer class (residential, commercial or industrial) and rate jurisdiction. These agencies approve rates designed to provide us the year about energyopportunity to generate revenues to recover all prudently incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable return for our shareholders. Rate base generally consists of the original cost of the utility plant in advanceservice, working capital and certain other assets, less accumulated depreciation on the utility plant in service and net deferred income tax liabilities, and may include certain other additions or deductions.

The natural gas market for Atlanta Gas Light was deregulated in 1997. Accordingly, Marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia and handle customer billing functions. The Marketers file their rates monthly with the Georgia Commission. As a result of operating in a deregulated environment, Atlanta Gas Light's role includes:

·  distributing natural gas for Marketers;
·  constructing, operating and maintaining the gas system infrastructure, including responding to customer service calls and leaks;
·  reading meters and maintaining underlying customer premise information for Marketers; and
·  
planning and contracting for capacity on interstate transportation and storage systems.

Atlanta Gas Light earns revenue by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia Commission and periodically adjusted. The Marketers add these fixed charges to customer bills. This mechanism, called a straight-fixed-variable rate design, minimizes the seasonality of Atlanta Gas Light’s revenues since the monthly fixed charge is not volumetric or directly weather dependent.

With the exception of Atlanta Gas Light, the earnings of our regulated utilities can be affected by customer consumption patterns that are largely a function of weather conditions and price levels for natural gas. Specifically, customer demand substantially increases during the Heating Season when natural gas is used for heating purposes. We have various mechanisms, such as weather normalization mechanisms and weather derivative instruments in place at most of our utilities, which limit our exposure to weather changes within typical ranges in these utilities’ respective service areas.

All of 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 that thosethey recover all of the costs prudently incurred in purchasing gas for their customers. Since Atlanta Gas Light does not sell natural gas directly to its end-use customers, qualifyingit does not need nor utilize a traditional natural gas cost recovery mechanism. However, Atlanta Gas Light does maintain inventory for the Low Income HomeMarketers in Georgia and recovers the cost of this gas through recovery mechanisms approved by the Georgia Commission specific to Georgia’s deregulated market. In addition to natural gas recovery mechanisms, we have other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow us to recover certain costs, such as those related to environmental remediation and energy efficiency plans.

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In traditional rate designs, utilities recover a significant portion of their fixed customer service and pipeline infrastructure costs based on assumed natural gas volumes used by our customers. Three of our utilities have decoupled regulatory mechanisms in place that encourage conservation. We believe that separating, or decoupling, the recoverable amount of these fixed costs from the customer throughput volumes, or amounts of natural gas used by our customers, allows us to encourage our customers’ energy conservation and ensures a more stable recovery of our fixed costs. The following table provides regulatory information for our six largest utilities.

($ 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 
(1)  The authorized return on rate base, return on equity and percentage of equity were those authorized as of December 31, 2013.
(2)  Estimates based on principles consistent with utility ratemaking in each jurisdiction. Rate base includes investments in regulatory infrastructure programs.
(3)  Involves regulatory mechanisms that allow us to recover our costs in the event of unseasonal weather, but are not direct offsets to the potential impacts of weather and customer consumption on earnings. These mechanisms are designed to help stabilize operating results by increasing base rate amounts charged to customers when weather is warmer-than-normal and decreasing amounts charged when weather is colder-than-normal.
(4)  Decoupled and straight-fixed-variable rate designs allow for the recovery of fixed customer service costs separately from assumed natural gas volumes used by our customers. Virginia Natural Gas’ request for approval of a decoupled rate design became effective June 1, 2013.
(5)  Includes programs that update or expand our distribution systems and liquefied natural gas facilities. Available in Illinois, but not yet effective.
(6)  Involves the recovery (refund) of the amount of bad debt expense over (under) an established benchmark expense. Virginia Natural Gas and Chattanooga Gas recover the gas portion of bad debt expense through PGA mechanisms.
(7)  Involves the recovery of 50% of net synergy savings achieved on mergers and acquisitions.
(8) Includes the recovery of costs associated with plans to achieve specified energy savings goals.
(9)  In connection with the December 2011 Nicor merger, we agreed to (i) not initiate a rate proceeding for Nicor Gas that would increase base rates prior to December 2014, (ii) maintain 2,070 full-time equivalent employees involved in the operation of Nicor Gas for a period of three years and (iii) maintain the personnel numbers in specific areas of safety oversight of the Nicor Gas system for a period of five years.

Current Regulatory Proceedings

Nicor Gas In June 2013, in connection with the PBR plan, the Illinois Commission issued an order requiring us to refund $72 million to Nicor Gas’ current customers over a 12-month period. In July 2013, Nicor Gas began refunding customers through our purchased gas adjustment mechanism, which is based on natural gas throughput. Through December 31, 2013, $29 million was refunded. For more information on the PBR plan, see Note 11 to our consolidated financial statements under Item 8 herein.

In July 2013, Illinois enacted legislation that will allow Nicor Gas to provide more widespread safety and reliability enhancements to its system. The legislation stipulates that rate increases to customer bills as a result of any infrastructure investments shall not exceed an annual average 4.0% of base rate revenues. We expect to submit a plan for approval by the Illinois Commission in mid-2014, to become effective in January 2015.

In July 2013, Illinois enacted legislation that provides a streamlined process to revise depreciation rates for natural gas utilities. On August 30, 2013, Nicor Gas filed a depreciation study with the Illinois Commission that proposed a composite depreciation rate of 3.07% compared to the prior composite rate of 4.10%. In October 2013, the Illinois Commission approved our proposed composite depreciation rate for Nicor Gas, which became effective as of the date the depreciation study was filed and had the effect of reducing our 2013 depreciation expense by $19 million. If applied to Nicor Gas’ PP&E throughout 2013, the new composite depreciation rate would have resulted in a $53 million decrease in annual depreciation expense. The lower composite depreciation rate did not impact customer rates.

In September 2013, Nicor Gas filed its second Energy AssistanceEfficiency 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 other similar programs receivewill 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.

Atlanta Gas Light 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 needed assistancecosts associated with resolving the imbalance are recoverable from Marketers. The resolution of this imbalance will be decided by the Georgia Commission and we are unable to predict the ultimate outcome.

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In accordance with an order issued by the Georgia Commission, where AGL Resources makes a business acquisition that reduces the costs allocated or charged to Atlanta Gas Light for shared services, the net savings to Atlanta Gas Light will be shared equally between the firm customers of Atlanta Gas Light and our shareholders for a ten-year period. In December 2013, we filed a Report of Synergy Savings with the Georgia Commission in connection with the Nicor acquisition. If and when approved, the net savings should result in annual rate reductions to the firm customers of Atlanta Gas Light of $5 million. We expect the Georgia Commission to continue this focusrule on the report in the second quarter of 2014.

Virginia Natural Gas In accordance with Virginia’s Natural Gas Conservation and Ratemaking Efficiency Act (CARE), Virginia Natural Gas filed for the foreseeable future. We have also workedapproval of its CARE plan with the Virginia Commission in December 2012. This plan includes a decoupling mechanism and the New Jersey BPUauthority to educate our customers aboutrecord accounting entries associated with such a mechanism. Our CARE plan has two principal components: (i) an Energy Conservation Plan component consisting of four cost-effective conservation and energy efficiency initiatives or programs plus a Community Outreach and Customer Education program; and (ii) a natural gas decoupling mechanism, Revenue Normalization Adjustment component and a rider which provides for a sales adjustment. In May 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.

Chattanooga Gas In April 2013, legislation was signed into law that gives the Tennessee Authority the ability to provide rebatesapprove alternative regulatory mechanisms. The law allows the Tennessee Authority to: (i) implement separate rate adjustment mechanisms that track specific costs, (ii) implement annual rate reviews in lieu of traditional rate cases and (iii) adopt other incentives forpolicies or procedures that permit a more timely review and revision of rates, streamline the purchaseregulatory process, and reduce the cost and time associated with the traditional ratemaking processes.

In April 2013, Chattanooga Gas filed a proposal with the Tennessee Authority to extend its energy conservation programs and associated rate adjustment mechanism that adjusts rates to recover reduced operating revenues as a result of high-efficiency natural gas-fueled equipment.reduced customer usage. In August 2013, a status conference was held by the Tennessee Authority and a procedural schedule was established whereby the Tennessee Authority’s Staff will issue a report on the evaluation of the conservation programs, which is expected in 2014. After the Tennessee Authority issues its report, Chattanooga Gas will be required to file a report on the impacts of the rate adjustment mechanism within 45 days. Interveners will then have 30 days to respond to Chattanooga Gas’s report and recommendations. The Tennessee Authority granted Chattanooga Gas an extension of its rate adjustment mechanism until the completion of the proceeding.

Capital Projects

We continue to focus on capital discipline and cost control while moving ahead with projects and initiatives that we expect will have current and future benefits to us and our customers, provide an appropriate return on invested capital and ensure the safety, reliability and integrity of our utility infrastructure.infrastructure. Total capital expenditures incurred during 2013 for our distribution operations segment were $684 million. The following table below and the following discussions provide updates on some of our larger capital projects under various programs at our distribution operations segment.segment. These programs update or expand our distribution systems to improve system reliability and meet operational flexibility and growth. Our anticipated expenditures for these programs in 20112014 are discussed in ‘Liquidity“Liquidity and Capital Resources’ under the caption ‘Cash Flows from Financing Activities’Resources”.
 
 
In millions
 
Expenditures
 in 2010
  Anticipated completion 
Pipeline replacement program $81   2013 
Integrated System Reinforcement Program  54   2012 
Integrated Customer Growth Program  5    2012 
Enhanced infrastructure program  46   2011 
Total $186     
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         
(1)  The mileage disclosed represents miles of pipe that have been retired. We closed the PRP on December 31, 2013.

Atlanta Gas Light In October 2009, the Georgia Commission approved Atlanta Gas Light’sOur STRIDE program. As approved, STRIDEprogram is comprised of the ongoing pipelinei-SRP, i-CGP, PRP (which ended in 2013), and a new component, i-VPR. These infrastructure and replacement program, which was started in 1998programs are used to update and the new Integrated System Reinforcement Program (i-SRP).expand distribution systems and liquefied natural gas facilities, improve system reliability and meet operations flexibility and growth.

The purpose of the i-SRP program under STRIDE is to upgrade Atlanta Gas Light’sour distribution system and liquefied natural gas facilities in Georgia, improve itsour peak-day system reliability and operational flexibility, and create a platform to meet long-term forecasted growth. Under STRIDE,Our i-CGP authorizes Atlanta Gas Light is requiredto extend its pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia. The STRIDE program requires us to file an updated ten-year forecast of infrastructure requirements under i-SRP along with a new three-year construction plan every three years for review and approval by the Georgia Commission.

In January 2010, the Georgia Commission also approved the Integrated Customer Growth Program (i-CGP) under STRIDE which authorized Atlanta Gas Light to extend Atlanta Gas Light’s pipeline facilities to serve customers without pipeline access and create new economic development opportunities in Georgia.

Elizabethtown Gas In 2009, the New Jersey BPU approved an accelerated enhanced infrastructure program, which was created in response to the New Jersey Governor’s request for utilities to assist in the economic recovery by increasing infrastructure investments. A regulatory cost recovery mechanism has been established whereby estimated rates go into effect at the beginning of each year. At the end of the program the regulatory cost recovery mechanism will be trued-up and any remaining costs not previously collected will be included in base rates. In December 2010, Elizabethtown Gas made a request to the New Jersey BPU to spend an additional $40 million under this program to be spent in 2011 and 2012. The outcome of this request is still pending.
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Collective Bargaining AgreementsIn December 2013, we received approval from the Georgia Commission for a new $260 million, four-year STRIDE program, $214 million of which will be for i-SRP related projects and $46 million of which will be for i-CGP related projects. The program will be funded through a monthly rider surcharge per customer of $0.48 beginning in January 2015, which will increase to $0.96 beginning in January 2016 and to $1.43 beginning in January 2017. This surcharge will continue through 2025.

The following table providespurpose 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. In August 2013, the Georgia Commission approved i-VPR which includes the replacement of the first 756 miles of vintage plastic pipe over four years for $275 million. The program will be funded through a monthly rider surcharge per customer of $0.48 through December 2014, which will be increased to $0.96 beginning in January 2015 and to $1.45 beginning in January 2016. This surcharge will continue through 2025. If the Commission elects to extend the i-VPR program beyond 2017, the remaining vintage plastic mains in our system potentially could be considered for replacement through the program over the next 15 - 20 years as it reaches the end of its useful life.

Elizabethtown Gas In August 2013, our request to extend the enhanced infrastructure program was approved by the New Jersey BPU. The approval allows for infrastructure investment of $115 million over four years, effective as of September 2013. Carrying charges on the additional capital spend will be accrued and 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. Also in August 2013, the New Jersey BPU approved the recovery of prior accelerated infrastructure investments under this program through a permanent adjustment to base rates.

In March 2013, the BPU issued an order inviting the submission of proposals from utilities in New Jersey for infrastructure upgrades designed to protect utility infrastructure from future major storm events. In September 2013, in response to this request, 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 In June 2012, the Virginia Commission approved Virginia Natural Gas’ SAVE program, which involves replacing aging infrastructure as prioritized through Virginia Natural Gas’ distribution integrity management program. SAVE was filed in accordance with a Virginia statute providing a regulatory cost recovery mechanism to recover the costs associated with certain infrastructure replacement programs. This is a five-year program that includes a maximum allowance for 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 costs based on this program through a rate rider that became effective in August 2012. In May 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 in July 2013 and became effective as of August 2013.
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 our current and former operating sites. As we continue to conduct the remediation and enter into cleanup contracts, 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 costs are primarily recovered through rate riders.

See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Critical Accounting Policies and Estimates” and Note 3 to our consolidated financial statements under Item 8 herein for additional information about our natural gas utilities’ collective bargaining agreements.environmental remediation liabilities and efforts.

# of EmployeesContract Expiration Date
Virginia Natural Gas
International Brotherhood of Electrical Workers (Local No. 50)
125May 2012
Elizabethtown Gas
Utility Workers Union of America (Local No. 424)
167Nov 2011
 Total292

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Our current collective bargaining agreements do not require our participation in multiemployer retirement plans and we have no obligation to contribute to any such plans. These agreements represent approximately 11%
Table of our total employees and we believe that our relations with them are good.Contents

Retail Energy Operations

Our retail energy operations segment consists ofserves approximately 620,000 natural gas commodity customers and 1.1 million service contracts. Companies within our retail operations segment include SouthStar a joint venture currently owned 85% by our subsidiary, Georgia Natural Gas Company, and 15% by Piedmont. Pivotal Home Solutions.

SouthStar markets natural gas and related services under the trade name Georgia Natural Gas to retail customers on an unregulated basis, primarily in Georgia. SouthStar also serves retail customers in Ohio and Florida and markets natural gas to largerresidential, commercial and industrial customers, primarily in Alabama, Tennessee, North Carolina, South Carolina, FloridaGeorgia and Georgia.Illinois, where we capture spreads between wholesale and retail natural gas prices. Additionally, we offer our customers energy-related products that provide for natural gas price stability and utility bill management. These products mitigate and/or eliminate the risks to customers of colder-than-normal weather and/or changes in natural gas prices. We charge a fee or premium for these services. Through our commercial operations, we optimize storage and transportation assets and effectively manage commodity risk, which enables us to maintain competitive retail prices and operating margin.

SouthStar expanded into the Ohio market in 2006, principally through being awarded supply agreements using retail choice programs. We continue to monitor and evaluate other states where natural gas choice programs may offer potential future markets and sources for growth.

Prior to January 1, 2010, we ownedis a 70% interest in SouthStar and Piedmont owned 30%. However, in July 2009, we entered into an amended joint venture agreement with Piedmont pursuant to which we purchased an additional 15% ownership interest for $58 million, effective January 1, 2010, thus increasing our interest toowned 85%. Prior to the effectiveness of our ownership increase, SouthStar’s earnings for customers in Georgia were allocated 75% to by us and 25% to15% by Piedmont while its earnings for customers in Ohio and Florida were allocated 70% to us and 30% to Piedmont. Earnings are now allocated entirely in accordance with the ownership interests. We have no contractual rights to acquire Piedmont’s remaining 15% ownership interests.

SouthStar is governed by an executive committee which is comprisedwith equal representation by both owners. After considering the relevant factors we consolidate SouthStar in our financial statements. In September 2013, we contributed our wholly owned Illinois retail energy subsidiaries to the SouthStar joint venture. Piedmont contributed $22.5 million in cash to SouthStar to maintain its 15% ownership interest. In connection with the contribution of six members, three representatives from AGL Resources and three from Piedmont. Underour Illinois retail energy businesses, we provided certain limited protections to Piedmont regarding the joint venture agreement, all significant management decisions require the unanimous approvalvalue of the contributed businesses related to goodwill and other intangible assets. See Note 10 to our consolidated financial statements under Item 8 herein for more information.

In June 2013, our retail operations segment acquired approximately 33,000 residential and commercial relationships in Illinois for $32 million. The transaction significantly increases the size of our retail energy customer portfolio in Illinois with minimal incremental operating expenses.

Pivotal Home Solutions provides a suite of home protection products and services that offer homeowners additional financial stability regarding their energy service delivery, systems and appliances. We offer a proprietary line of customizable home warranty and energy efficiency plans that can be co-branded with utility and energy companies. Currently, Pivotal Home Solutions serves customers in 17 states primarily in Illinois, Indiana and Ohio.

In January 2013, our retail operations segment acquired approximately 500,000 service contracts and certain other assets for $122 million. We believe this acquisition will provide an enhanced platform for growth and continued expansion of this business in a number of key markets.

Competition and Operations Our retail operations business competes with other energy marketers to provide natural gas and related services to customers in the areas that they operate. In the Georgia market, SouthStar executive committee; accordingly,operates as Georgia Natural Gas and is the largest of 12 Marketers, with average customers of nearly 500,000 over the last three years and market share of approximately 31%.

In recent years, increased competition and the heavy promotion of fixed-price plans by SouthStar’s competitors have resulted in increased pressure on retail natural gas margins. In response to these market conditions, SouthStar’s residential and commercial customers have been migrating to fixed-price plans, which, combined with increased competition from other Marketers, has impacted SouthStar’s customer growth as well as margins.

In addition, similar to our 85% financial interest is considerednatural gas utilities, our retail operations businesses face competition based on customer preferences for natural gas compared to be noncontrolling.other energy products, primarily electricity, and the comparative prices of those products. We record the earnings allocatedcontinue to Piedmont asuse a noncontrolling interest in our Consolidated Statementsvariety of Income,targeted marketing programs to attract new customers and we record Piedmont’s portion of SouthStar’s capital as a noncontrolling interest in our Consolidated Statements of Financial Position.to retain existing customers.

SouthStar’s operations are sensitive to seasonal weather, natural gas prices, customer growth and consumption patterns similar to those affecting our utility operations. SouthStar’s retail pricing strategies and the use of a variety of hedging strategies, such as the use of futures, options, swaps, weather derivative instruments and other risk management tools, help to ensure retail customer costs are covered to mitigate the potential effect of these issues and commodity price risk on its operations. For more information on SouthStar’s energy marketing and risk management activities, see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk - CommodityRisk” under the caption “Natural Gas Price Risk.”

Competition SouthStar competes with other energy Marketers to provide natural gasOur retail operations business also experiences price, convenience and related services to customers in Georgia and the Southeast. In the Georgia market, SouthStar is the largest of eleven Marketers, with average customers of approximately 500,000 over the last three years and market share of 33%.

In recent years, increased competition and the heavy promotion of fixed price plans by SouthStar’s competitors has resulted in increased pressure on retail natural gas margins. In response to these market conditions SouthStar’s residential and commercial customers have been migrating to fixed price plans, which, combined with increasedservice competition from other Marketers, has impacted SouthStar’s customer growth as well as margins.

In addition, similar to our natural gas utilities, SouthStar faces competition based on customer preferences for natural gas compared to other energy productswarranty and the comparative prices of those products. Natural gas price volatilityheating, ventilation, and air conditioning (HVAC) companies. These businesses also bear risk from potential changes in the wholesale natural gas commodity market has also contributed to an increase in competition for residential and commercial customers. SouthStar continues to use a variety of targeted marketing programs to attract new customers and to retain existing customers.regulatory environment.

Operations SouthStar generates revenues primarily in three ways. The first is through the sale of natural gas to residential, commercial and industrial customers, primarily in Georgia where SouthStar captures a spread between wholesale and retail natural gas prices.Wholesale Services

The second way SouthStar generates revenues is through the collection of monthly service fees and customer late payment fees. SouthStar evaluates the combination of these two retail price components to ensure such pricing is structured to cover related retail customer costs, such as bad debt expense, customer service and billing, and lost and unaccounted-for gas, and to provide a reasonable profit, as well as being competitive to attract new customers and maintain market share.
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The third way SouthStar generates revenues is through its commercial operations of optimizing storage and transportation assets and effectively managing commodity risk, which enables SouthStar to maintain competitive retail prices and operating margin. SouthStar is allocated storage and pipeline capacity from Atlanta Gas Light that is used to supply natural gas to its customers in Georgia. Through hedging transactions, SouthStar manages exposures arising from changing commodity prices by using natural gas storage transactions to capture operating margin from natural gas pricing differences that occur over time. SouthStar’s risk management policies allow the use of derivative instruments for hedging and risk management purposes but prohibit the use of derivative instruments for speculative purposes.
Wholesale Services

Our wholesale services segment consists primarily of our wholly owned subsidiary Sequent our wholly-owned subsidiary involvedthat engages in asset management and optimization, storage, transportation, producer and peaking services and wholesale marketing. The wholesale services segment also includes our wholly-owned subsidiary Compass Energy (Compass), which we acquired in 2007. Compass providesmarketing of natural gas supplyacross the U.S. and Canada. Wholesale services to commercial, industrial and governmental customers primarily in Kentucky, Ohio, Pennsylvania, Virginia and West Virginia. Compass contributed $2 million of EBIT in 2010 and zero in 2009.

Sequent utilizes a portfolio of natural gas storage assets, contracted supply from all of the major producing regions, as well as contracted storage and transportation capacity across the Gulf Coast, Eastern, Midwestern and Western sections of the United States and Canada to provide these services to its customers. Its customers consistingconsist primarily of electric and natural gas utilities, power generators and large industrial customers. Sequent’sOur logistical expertise enables itus to provide itsour customers with natural gas from the major producing regions and market hubs in the United States and Canada and meet its delivery requirements and customer obligations at competitive prices by leveraging its. We also leverage our portfolio of natural gas storage assets and contracted natural gas supply, transportation and storage capacity.capacity to meet our delivery requirements and customer obligations at competitive prices.
 
Sequent’s
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Wholesale services’ portfolio of storage and transportation capacity also enables itus to generate additional operating margin by optimizing the contracted assets through the application of itsour wholesale market knowledge and risk management skills as the opportunities arise in the Gulf Coast, Eastern, Midwestern and Western sections of the United States and Canada.. These asset optimization opportunities focus on capturing the value from idle or underutilized assets, typically by participating in transactions tothat take advantage of volatility in pricing differences between varying geographic locations and time horizons (location and seasonal spreads) within the natural gas supply, storage and transportation markets to generate earnings. Sequent seeksWe seek to mitigate the commodity price and volatility risks and protect itsour operating margin through a va rietyvariety of risk management and economic hedging activities.activities.

Sequent’s earningsIn May 2013, we sold Compass Energy, which served primarily commercial and industrial customers, for an initial cash payment of $12 million, which resulted in an $11 million pre-tax gain ($5 million net of tax). We are largely impacted by volatility ineligible 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 would be received from the natural gas marketplace. Volatility arises frombuyer over a numberfive-year earn out period based upon the financial performance of factors such as weather fluctuations or the change, supply, or demand for natural gas in different regions of the country. In December 2010, cold weather in the Northeast and Mid-Atlantic sections of the United States created not only customer demand for natural gas but also volatility, enabling Sequent to generate a large portion (approximately 25%) of its full year 2010 operating margin.
While this cold weather in December 2010 contributed to volatility in the marketplace, overall Sequent experienced reduced volatility in 2010 and continues to expect lower volatility brought on by a robust natural gas supply and ample storage in the market. This volatility is partially reflected in the year-over-year $14 million decline in economic value or operating revenues expected to be recorded in future periods associated with its existing natural gas storage inventory as discussed under energy marketing activities, as well as its transportation portfolio. Also contributing to the year-over-year decline is the impact of decreased gains on the derivative financial instruments used to hedge Sequent’s storage and transportation positions.Compass Energy.

Competition and operations SequentWholesale services competes for asset management, long-term supply and seasonal peaking service contracts with other energy wholesalers, often through a competitive bidding process. Sequent isWe are able to price competitively by utilizing itsour portfolio of contracted storage and transportation assets and by renewing and adding new contracts at prevailing lowermarket rates. SequentWe will further continue to broaden itsour market presence in the Pacific Northwest sectionwhere our portfolio of the United Statescontracted storage and Canada,transportation assets provides us a competitive advantage, as well as pursuecontinue our pursuit of additional opportunities with power generation companies located in the areas of the country it operates. Sequent isin which we operate. We are also focused on building its fee basedour fee-based services in part to have a source of operating margin that is less impacted by volatility in the marketplace.

Asset Management Transactions Sequent’s asset management customers include affiliated and nonaffiliated utilities, municipal utilities, power generators and large industrial customers. These customers, due to seasonal demand or levels of activity, may have contracts for transportation and storage capacity which exceed their actual requirements. Sequent enters into structured agreements with these customers, whereby Sequent, on behalf of the customers, optimizes the transportation and storage capacity during periods when customers do not use it for their own needs. Sequent may capture incremental operating margin through optimization, and either share margins with the customers or pay them a fixed a mount.

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Sequent has entered into asset management agreements with our affiliated utilities that include profit sharing mechanisms and fixed fee payments that require Sequent to make aggregate annual minimum payments of $10 million in 2011. These agreements are scheduled to expire over the next three years. The following table provides payments made under these agreements during the last three years.

  Profit sharing / fee payments 
In millions 2010  2009  2008 
Atlanta Gas Light $4  $16  $9 
Elizabethtown Gas  10   11   5 
Chattanooga Gas  4   4   4 
Virginia Natural Gas  5   7   2 
Florida City Gas  1   1   1 
Total $24  $39  $21 

Transportation Transactions Sequent contracts for natural gas transportation capacity and participates in transactions that manage the natural gas commodity and transportation costs in an attempt to achieve the lowest cost to serve its various markets. Sequent seeks to optimize this process on a daily basis as market conditions change by evaluating all the natural gas supplies, transportation alternatives and markets to which it has access and identifying the lowest-cost alternatives to serve the various markets. This enables Sequent to capture geographic pricing differences across these various markets as delivered natural gas prices change.

As Sequent executes transactions to secure transportation capacity, it often enters into forward financial contracts to hedge its positions and lock-in a margin on future transportation activities. The hedging instruments are derivatives, and Sequent reflects changes in the derivatives’ fair value in its reported operating results in the period of change, which can be in periods prior to actual utilization of the transportation capacity.

Producer Services Sequent’s producer services business primarily focuses on aggregating natural gas supply from various small and medium-sized producers located throughout the natural gas production areas of the United States. Sequent provides producers with certain logistical and risk management services that offer them attractive options to move their supply into the pipeline grid.

Natural Gas Storage Inventory and Transactions Sequent maintains natural gas storage balances for volumes associated with energy marketing activities and parked gas transactions and records these within natural gas stored underground inventory on our Consolidated Statement of Financial Position. Further and generally in connection with non-affiliated asset management transactions, Sequent’s recorded natural gas stored underground inventory includes volumes of natural gas it manages for its customers by purchasing the natural gas inventory from and physically delivering volumes of natural gas back to its customers based on specific delivery dates. The cost at which Sequent purchases the volumes of n atural gas from its customers or WACOG is also the same price at which Sequent sells the natural gas volumes to the customer. Consequently, Sequent makes no margin on the purchase and sale of the natural gas but makes operating margin through its natural gas storage optimization activities of these volumes under management. As of December 31, 2010, Sequent has recorded $283 million of natural gas stored underground inventory within our Consolidated Statement of Financial Position, representing 68 Bcf at an overall WACOG of $4.16.

Energy Marketing Activities Sequent purchases natural gas for storage when the current market price it pays plus the cost for transportation and storage is less than the market price it anticipates it could receive in the future. Sequent attempts to mitigate substantially all of the commodity price risk associated with its storage portfolio and uses derivative instruments to reduce the risk associated with future changes in the price of natural gas. Sequent sells NYMEX futures contracts or OTC derivatives in forward months to substantially lock in the operating revenue it will ultimately realize when the stored gas is actually sold.

We view Sequent’s tradingour wholesale margins from two perspectives. First, we base our commercial decisions on economic value whichfor both our natural gas storage and transportation transactions. For our natural gas storage transactions, economic value is defined asdetermined based on the locked-innet operating revenue to be realized at the time the physical gas is withdrawn from storage and sold and the derivative instrument used to economically hedge natural gas price risk on thatthe physical storage that is settled. SecondSimilarly, for our natural gas transportation transactions, economic value is determined based on the net operating revenue to be realized at the time physical gas is purchased, transported, and sold utilizing our transportation capacity along with the settlement value associated with any derivative instruments.

The second perspective is the values reported in accordance with GAAP reported value both inand encompassing periods prior to and in the period of physical withdrawal and sale of inventory.inventory or purchase, transportation and sale of natural gas. We enter into derivatives to hedge price risk prior to when the related physical storage withdrawal or transportation transactions occur based upon our commercial evaluation of future market prices. The reported GAAP amount is affected by the process of accounting for the financial hedging instruments in interim periods at fair value betweenand prior to the period whenof the natural gas is injected intorelated physical storage and when it is ultimately withdrawn and the derivative financial instruments are settled.transportation transactions. The change in the fair value of the hedging instruments is recognized in e arningsearnings in the period of change and is recorded as unrealized gains or losses. The actualThis results in reported earnings volatility during the interim periods, however, the expected margin based upon the hedged economic value less any interim recognition of gains or losses on hedges and adjustments for LOCOM, is ultimately realized whenin the period natural gas is delivered to its ultimate customer.physically withdrawn from storage or transported and sold at market prices and the related hedging instruments are settled.

Sequent accountsFor our natural gas storage portfolio, we purchase natural gas for storage when the current market price we pay plus the cost for transportation, storage and financing is less than the market price we anticipate we could receive in the future. We attempt to mitigate substantially all of the commodity price risk associated with our storage portfolio by using derivative instruments to reduce the risk associated with future changes in the price of natural gas. We sell NYMEX futures contracts or OTC derivatives in forward months to substantially lock in the operating revenue that we will ultimately realize when the stored gas is actually sold.

We account for natural gas stored in inventory differently than the derivatives Sequent useswe use to mitigate the commodity price risk associated with itsour storage portfolio. The natural gas that Sequent purchaseswe purchase and injectsinject into storage is accounted for at the lower of average cost or current marketLOCOM value. The derivatives that Sequent useswe use to mitigate commodity price risk are accounted for at fair value and marked to market each period. This difference in accounting treatment can result in volatility in Sequent’swholesale services reported results, even though the expected net operating revenue and locked-in economic value is essentially unchanged fromsince the date the transactions were initiated. These accounting timing differences also affect the comparability of Sequent’swholesale services period-over-period results, since changes in forward NYMEX prices do not increase and decrease on a consistent b asisbasis from year to year.

For our natural gas transportation portfolio, we enter into transportation capacity contracts with interstate and intrastate pipelines for the delivery of natural gas between receipt and delivery points in future periods. We purchase natural gas for transportation when the market price we pay for gas at a receipt point plus the cost of transportation capacity required to deliver the gas to the delivery point is less than the sales price at the delivery point. The difference between the price at the receipt point and the delivery point is the transportation basis or location spread. Similar to our storage transactions, we attempt to mitigate the commodity price risk associated with our transportation portfolio by using derivative instruments to reduce the risk associated with future changes in the price of natural gas at the receipt and delivery points. We utilize futures contracts or OTC derivatives to hedge both the commodity price risk relative to the market price at the receipt point and the market price at the delivery point to substantially lock in the operating revenue that we will ultimately realize once the natural gas is received, delivered and sold.

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Volatility in the natural gas market arises from a number of factors, such as weather fluctuations or changes in supply or demand for natural gas in different regions of the country. The volatility of natural gas commodity prices has a significant impact on our customer rates, our long-term competitive position against other energy sources and the ability of our wholesale services segment to capture value from location and seasonal spreads. During 2013, we experienced increased price volatility brought on by colder weather and supply constraints in the Northeast corridor, which enabled us to capture value under these market conditions. During 2012 and 2011, the volatility of daily Henry Hub spot market prices for natural gas in the U.S. was significantly lower than it had been for several prior years. This was the result of a robust natural gas supply, mild weather and ample storage.

It is possible the current market conditions may not continue and that natural gas prices will remain low for an extended period based on current levels of excess supply relative to market demand for natural gas, in part due to abundant sources of shale natural gas reserves, particularly in the Marcellus Shale producing region where Sequent has natural gas receipt requirements, and the lack of demand growth by commercial and industrial enterprises. However, as economic conditions improve, the demand for natural gas may increase, natural gas prices could rise and higher volatility could return to the natural gas markets. Consequently, we continue to reposition Sequent’s business model with respect to fixed costs and the types of contracts pursued and executed.

Our natural gas acquisition strategy is designed to secure sufficient supplies of natural gas to meet the needs of our utility customers and to hedge gas prices to effectively manage costs, reduce price volatility and maintain a competitive advantage. Additionally, our hedging strategies and physical natural gas supplies in storage enable us to reduce earnings risk exposure due to higher gas costs.

Sequent’s expected natural gas withdrawals from physical salt-domestorage and reservoir storageexpected recovery of hedge losses associated with Sequent’s transportation portfolio are presented in the following tabletables, along with the net operating revenues expected at the time of withdrawal.withdrawal from storage and the physical flow of natural gas between contracted transportation receipt and delivery points. Sequent’s expected net operating revenues exclude storage and transportation demand charges, as well as other variable fuel, withdrawal, receipt and delivery charges, but are net of the estimated impact of profit sharing under our asset management agreements and reflectagreements. Further, the amounts that are realizable in future periods are based on the inventory withdrawal schedule, planned physical flow of natural gas between the transportation receipt and delivery points and forward natural gas prices at December 31, 2010 and 2009.2013. A portion of Sequent’s storage inventory and transportation capacity is economically hedged with futures contracts, which results in realization of a substantially fixed margin,net operating revenues, timing notwithstanding.

  Withdrawal schedule    
  
(in Bcf)
  Expected 
  
Salt-dome (WACOG $3.70)
  
Reservoir (WACOG $3.74)
  
operating revenues
(in millions)
 
2011         
First quarter  2   22  $13 
Second quarter  1   1   1 
Third quarter  -   1   1 
Fourth quarter  1   -   1 
Total at Dec. 31, 2010  4   24  $16 
Total at Dec. 31, 2009  -   19  $30 
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 

For the year ended December 31, 2013, we have recorded $16 million in losses associated with the hedging of our storage position, compared to $14 million in storage hedge gains the same period last year. These hedge losses primarily relate to rising gas prices during the fourth quarter of 2013. If Sequent’s storage withdrawals associated with existing inventory positions are executed as planned, it expects net operating revenues from storage withdrawals of approximately $16$28 million during the next twelve months.in 2014. This willcould change as Sequent adjusts its daily injection and withdrawal plans in response to changes in market conditions in future months and as forward NYMEX prices fluctuate.

The net operating revenues expected to be generated from the physical withdrawal of natural gas from storage do not reflect the earnings impact related to the movement in our hedges to lock in the forward location spread for the delivery of natural gas between two transportation delivery points associated with our transportation capacity portfolio.

For the year ended December 31, 2013, we have recorded $73 million in losses associated with the hedging of our transportation portfolio, or $70 million higher hedge losses as compared to the same period last year. These hedge losses are the result of widening transportation basis spreads associated with colder-than-normal weather, higher demand during the second half of 2013 and supply constraints experienced at natural gas receipt and delivery points throughout the Northeast corridor. These losses primarily relate to forward transportation and commodity positions for 2014, during which we expect to physically flow natural gas between the hedged transportation receipt and delivery points and utilize the contracted transportation capacity. The following table shows the periods associated with the transportation hedge losses during which the derivatives will be settled and the physical transportation transactions will occur that offset the hedge losses recognized in 2013.
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 


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The unrealized storage and transportation hedge losses do not change the underlying economic value of our storage and transportation positions, and based on current expectations will largely be reversed in 2014 when the related transactions occur and are recognized. For more information on Sequent’s energy marketing and risk management activities, see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk - CommodityRisk” under the caption “Natural Gas Price Risk.”

Park and Loan Transactions Sequent routinely enters into park and loan transactions with various pipelines and storage facilities, which allow Sequent to park gas on, or borrow gas from, the pipeline in one period and reclaim gas from, or repay gas to, the pipeline in a subsequent period. For these services, Sequent charges rates which include the retention of natural gas lost and unaccounted for in-kind. The economics of these transactions are evaluated and price risks are managed in much the same way as traditional reservoir and salt-dome storage transactions are evaluated and managed.Midstream Operations

Sequent enters into forward NYMEX contracts to hedge the natural gas price risk associated with its park and loan transactions. While the hedging instruments mitigate the price risk associated with the delivery and receipt of natural gas, they can also result in volatility in Sequent’s reported results during the period before the initial delivery or receipt of natural gas. During this period, if the forward NYMEX prices in the months of delivery and receipt do not change in equal amounts, Sequent will report a net unrealized gain or loss on the hedges. Once gas is delivered under the park and loan transaction, earnings volatility is essentially eliminated since the park and loan transaction contains an embedded derivative, which is also marked to market and would substantially offset subsequent changes in value of the forward NYMEX contracts used to hedge the park and loan transaction.

Energy Investments

Our energy investmentsmidstream operations segment includes a number of businesses that are related and complementary to our primary business. The most significant of these businesses is our natural gas storage business, which develops, acquires and operates high-deliverability salt-dome caverns and otherunderground natural gas storage assets in the Gulf Coast region of the United States.U.S. and in northern California. While this business can also generate additional revenue during times of peak market demand for natural gas storage services, the majority of our natural gas storage facilities are covered underhave a portfolio of short, medium and long-term contracts at a fixed market rate. We generally have had approximately 90% to 95% of Jefferson Island’srates. The following table shows the working natural gas capacity underand firm subscription. As Golden Triangle Storage begins full commercial operations during the first quartersubscription amounts by storage facility as of 2011, it wi ll market its remaining available working natural gas capacity taking into consideration the prevailing market conditions in establishing rates and tenor of capacity contracts.December 31, 2013.

       
Subscribed (1)
 
In BcfLocationType Working Gas Capacity  Amount  % 
Jefferson Island (2) (3)
LouisianaSalt-dome  7.3   5.6   77%
Golden Triangle (3)
TexasSalt-dome  13.5   2.0   15%
Central Valley (4)
CaliforniaDepleted field  11.0   3.0   27%
Total    31.8   10.6   33%
(1)  The amount and percentage of firm capacity under subscription does not include 3.5 Bcf of capacity subscribed by Sequent at December 31, 2013.
(2)  Regulated by the Louisiana Department of Natural Resources.
(3)  Regulated by the FERC.
(4)  Regulated by the California Commission.

Jefferson IslandSawgrass Storage This wholly-owned subsidiary operates50% owned joint venture between us and a salt-domeprivately held energy exploration and production company was granted certification from FERC in March 2012 for the development of an underground natural gas storage and hub facility in Louisiana approximately eight miles from the Henry Hub. It currently consists of two salt-dome storage caverns with 7.530 Bcf of working gas capacity, 0.7 Bcf per day of withdrawal capacity and 0.4 Bcf per day of injection capacity. The FERC certificate is set to expire in March 2014. Given the current storage facility is regulated by the Louisiana Department of Natural Resources and by the FERC, which has regulatory authority over storage and transportation services. Jefferson Island provides storage and hub services through its direct connection to the Henry Hub and its interconnections with eight pipelines in the area. Jefferson Island currently has 6.9 Bcf under firm subscription, which represents approximately 92% of its working nat ural gas capacity. This level of firm subscription has remained consistent over the last three years.

In December 2009, the Louisiana Mineral and Energy Board approved an operating agreement between Jefferson Islandmarket conditions and the State of Louisiana. In June 2010, Jefferson Island filed a permit application with the Louisiana Department of Natural Resources to expand its natural gas storage facility through the addition of two caverns. Despite the opposition of a local group, we anticipate receiving approval during the second half of 2011. When completed theneed for additional two caverns would expand the total working gas capacity at Jefferson Island from 7.5 Bcf to approximately 19.5 Bcf of working gas capacity.
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Golden Triangle Storage Our wholly-owned subsidiary, Golden Triangle Storage, a new salt-dome storage facility in the Gulf Coast region of the United States, is designed for an initial 12 Bcf of working natural gas capacity and total cavern capacity of 18 Bcf. The facility potentially can be expanded to a total of five caverns with approximately 38 Bcf of working natural gas storage capacity in the future. The storagefuture, in December 2013 the joint venture decided to terminate development of this facility is regulated byand recognized an impairment loss of $16 million, which reduced the FERC. Golden Trianglecarrying 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. For more information about our investment in Sawgrass Storage, completed an approximately nine-mile dual 24” natural gas pipelinesee Note 10 to connect the storage facility with three interstate and three intrastate pipelines.consolidated financial statements under Item 8 herein.

Magnolia Enterprise Holdings, Inc. This wholly owned subsidiary operates a pipeline that provides our Georgia customers access to LNG from the Elba Island terminal near Savannah, Georgia. The first cavern with 6 Bcfpipeline was completed in November 2009 and provides diversification of working capacity began commercialnatural gas sources and increased reliability of service in September 2010. The second cavern, with an expected 6 Bcf of working capacity, is expected to be in service in mid-2012. Golden Triangle Storage currently has 2 Bcf under firm subscription, which represents approximately 33% of its current working natural gas capacity.

Our current estimate to complete both caverns, based on current prices for labor, materials and pad gas, is approximately $325 million. We have spent approximately $112 million in capital expenditures for this project in 2010. The actual project costs depend upon the facility’s configuration, materials, drilling costs, financing costs and the amount and cost of pad gas, which includes volumes of non-working natural gas used to maintain the operational integrity of the cavern facility. The costs for approximately 90% of these items have been fixed andevent that supplies coming from other supply sources are not subject to continued variability during construction. We are not able to predict whether these costs of construction will continue to increase, moderate or decrease from current levels, as there could be continued v olatility in the construction cost estimates.disrupted.

Competition and operations Our natural gas storage facilities primarily compete with natural gas facilities in the Gulf Coast region of the United StatesU.S. as the majority of the existing and proposed high deliverability salt-domesalt-dome natural gas storage facilities in North America are located in the Gulf Coast region. Salt caverns have also been leached from bedded salt formations in the Northeastern and Midwestern states. Storage valuesCompetition for our Central Valley storage facility primarily consists of storage facilities in northern California and western North America.

The market fundamentals of the natural gas storage business are cyclical. The abundant supply of natural gas in recent years and the resulting lack of market and price volatility have declined overnegatively impacted the past year due to low gasprofitability of our storage facilities. In 2013, expiring storage capacity contracts were re-subscribed at lower prices and low volatility and we expect thisanticipate these lower natural gas prices to continue in 2011.2014 as compared to historical averages. The prices for natural gas storage capacity are expected to increase as supply and demand quantities reach equilibrium as the economy improves, expected exports of LNG occur and/or natural gas demand increases in response to low prices and expanded uses for natural gas. We believe our storage assets are strategically located to benefit from these expected improvements in market fundamentals, including the overall growth in the natural gas market and there are significant barriers to develop new storage facilities, including time of construction and other costs, federal, state and local permitting and approvals and suitable and available sites, to capitalize on these expected improvements in market conditions.

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AGL Networks In July 2010, we sold AGL Networks, our telecommunication business that constructed and operated conduit fiber infrastructure within select metropolitan areas. This sale did not have a material effect on our consolidated resultsTable of operations, cash flows or financial condition.Contents

CorporateCargo Shipping

Our corporatecargo shipping segment consists of Tropical Shipping; multiple wholly owned foreign subsidiaries of Tropical Shipping that are treated as disregarded entities for U.S. income tax purposes; Seven Seas, a wholly owned domestic cargo insurance company; and an equity investment in Triton, a cargo container leasing business.

Tropical Shipping is a transporter of containerized cargo and provides southbound scheduled services from the U.S. and Canada to 25 ports in the Bahamas and the Caribbean, interisland service between several of the Caribbean ports and operates from St. Thomas and St. Croix as its hubs in the Caribbean. In addition, it provides northbound shipments from those islands to the U.S. and Canada. Other related services, such as inland transportation and cargo insurance, are also provided by Tropical Shipping or its other subsidiaries and affiliates.

Generally, approximately 70% - 75% of Tropical Shipping’s total volumes shipped are in the southbound market, 15% - 20% interisland and 5% - 10% northbound. Tropical Shipping measures volumes and capacity of vessels and containers in TEU’s. Details of Tropical Shipping’s properties are discussed in Item 2, “Properties” under the caption “Vessels and shipping containers.”

Seven Seas is a Florida domestic insurance corporation that provides cargo insurance policies mainly between Tropical Shipping and its customers. During 2013, 66% of Seven Seas’ revenues were generated from Tropical Shipping’s customers. Policy coverage is from the point when the cargo leaves the shipper’s possession to the point when the customer takes delivery.

Triton is a full-service global leasing company and an owner-lessor of marine intermodal cargo containers. Profits and losses are generally allocated to investors’ capital accounts in proportion to their capital contributions. Our investment in Triton is accounted for under the equity method, and our share of earnings is reported within “Other Income” on our Consolidated Statements of Income. For more information about our investment in Triton, see Note 10 to the consolidated financial statements under Item 8 herein.

Competition and Operations Cargo shipping has five main competitors that serve the same major transportation areas. Our volumes shipped increased during 2013, but our profitability on those volumes continued to be adversely affected by competitive shipping rates.

Tropical Shipping’s operating results are cyclical and very much aligned with the level of global gross domestic product, tourism and the cost of fuel. Overall, the economies of the Bahamas and the Virgin Islands are highly dependent on tourism from the U.S. and the Caribbean’s Windward and Leeward Island economies primarily depend on tourism from Europe. Fuel price volatility also impacts our earnings. Bunker surcharge rates are charged to customers and are used to mitigate the fluctuations in fuel transportation costs. In 2014, we expect similar general market challenges as those experienced in 2013 with respect to overall levels of competition and related impacts on shipping volumes and rate pressure.

Seven Seas generates revenues from premiums received on insurance policies subscribed to primarily by customers of Tropical Shipping. Seven Seas’ results depend on its ability to generate revenues from the premiums and to manage risk.

Other

Our other segment primarily includes our nonoperatingnon-operating business units. AGL Services Company is a service company we established to provide certain centralized shared services to our operating segments. We allocate substantially all of AGL Services Company’s operating expenses and interest costs to our operating segments in accordance with state regulations. Our EBIT results include the impact of these allocations to the various operating segments. However, merger-related costs were not allocated to our operating segments.

AGL Capital, our wholly-ownedwholly owned finance subsidiary, provides for our ongoing financing needs through a commercial paper program, the issuance of various debt and hybrid securities and other financing arrangements. Our corporateThis segment also includes intercompany eliminations for transactions between our operating business segments. Our EBIT results include the impact of these allocations to the various operating segments.

Employees

As of February 1, 2011,December 31, 2013, we had 2,621 employees.approximately 6,094 employees, 5,626 of whom were in the U.S.

Additional InformationThe following table provides information about our natural gas utilities’ collective bargaining agreements, which represent approximately 27% of our total employees.
# of EmployeesContract Expiration Date
Nicor Gas
International Brotherhood of Electrical Workers (Local No. 19) (1)
1,351February 2014
Virginia Natural Gas
International Brotherhood of Electrical Workers (Local No. 50)
132May 2015
Elizabethtown Gas
Utility Workers Union of America (Local No. 424)
172November 2015
 Total1,655
(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.

For additional information on
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We believe that we have a good working relationship with our segments, see Item 7, “Management’s Discussionunionized employees and Analysisthere have been no work stoppages at Virginia Natural Gas, Elizabethtown Gas, or Nicor Gas since we acquired those operations in 2000, 2004, and 2011, respectively. As we have historically done, we remain committed to work in good faith with the unions to renew or renegotiate collective bargaining agreements that balance the needs of Financial Conditionthe Company and Results of Operations” under the caption “Results of Operations”our employees. Our current collective bargaining agreements do not require our participation in multiemployer retirement plans and “Note 12, Segment Information,” set forth in Item 8, “Financial Statements and Supplementary Data.”we have no obligation to contribute to any such plans.

Available Information

Detailed information about us is contained in ourOur annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and proxy statements, and other reports, and amendments to those reports that we file with, or furnish to, the SEC. These reportsSEC are available free of charge at the SEC website http://www.sec.gov and at our website, www.aglresources.com, as soon as reasonably practicable after we electronically file such reports with, or furnish such reports to, the SEC. However, our website and any contents thereof should not be considered to be incorporated by reference into this document. We will furnish copies of such reports free of charge upon written request to our Investor Relations department. You can contact our Investor Relations department at:

AGL Resources Inc.
Investor Relations - Dept. 1071
P.O. Box 4569
Atlanta, GA 30302-4569
404-584-4000

In Part III of this Form 10-K, we incorporate certain information by reference from our Proxy Statement for our 20112014 annual meeting of shareholders. We expect to file that Proxy Statement with the SEC on or about March 14, 2011,2014, and we will make it available on our website as soon as reasonably practicable. Please refer to the Proxy Statement when it is available.

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Additionally, our corporate governance guidelines, code of ethics, code of business conduct and the charters of each committee of our Board of Directors are available on our website. We will furnish copies of such information free of charge upon written request to our Investor Relations department.

ITEM 1A.1A. RISK FACTORS

Forward-Looking Statements

This report and the documents incorporated by reference herein contain “forward-looking statements.” These statements, which may relate to such matters as future earnings, growth, liquidity, supply and demand, costs, subsidiary performance, credit ratings, dividend payments, new technologies and strategic initiatives, often include words such as “anticipate,” “assume,” “believe,” “can,” “could,” “estimate,” “expect,” “forecast,” “future,” “goal,” “indicate,” “intend,” “may,” “outlook,” “plan,” “potential,” “predict,” “project,” “proposed,” “seek,” “should,” “target,” “would” or similar expressions. You are cautioned not to place undue reliance on forward-looking statements. While we believe that our expectations are reasonable in view of the information that we currently have, these expectations are subject to future events, risks and uncertainties, and there are numerous factors—many beyond our control—that could cause actual results to vary materially from these expectations.

Such events, risks and uncertainties include, but are not limited to, changes in price, supply and demand for natural gas and related products; the impact of changes in state and federal legislation and regulation, including any changes related to climate matters; actions taken by government agencies on rates and other matters; concentration of credit risk; utility and energy industry consolidation; the impact on cost and timeliness of construction projects by government and other approvals, development project delays, adequacy of supply of diversified vendors, and unexpected change in project costs, including the cost of funds to finance these projects and our ability to recover our project costs from our customers; limits on pipeline capacity; the impact of acquisitions and divestitures, including recent acquisitions in our retail operations segment; our ability to successfully integrate operations that we have or may acquire or develop in the future; direct or indirect effects on our business, financial condition or liquidity resulting from a change in our credit ratings or the credit ratings of our counterparties or competitors; interest rate fluctuations; financial market conditions, including disruptions in the capital markets and lending environment; general economic conditions; uncertainties about environmental issues and the related impact of such issues, including our environmental remediation plans; the impact of the new depreciation rates for Nicor Gas; the impact of changes in weather, including climate change, on the temperature-sensitive portions of our business; the impact of natural disasters, such as hurricanes, on the supply and price of natural gas and on our cargo shipping business; acts of war or terrorism; the outcome of litigation; and the factors described in this Item 1A “Risk Factors” and the other factors discussed in our filings with the SEC.

There also may be other factors that we do not anticipate or that we do not recognize are material that could cause results to differ materially from expectations. Forward-looking statements speak only as of the date they are made. We expressly disclaim any obligation to update or revise any forward-looking statement, whether as a result of future events, new information or otherwise, except as required by law.

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Risks Related to Our Business

Risks related to the regulation of our businesses could affect the rates we are able to charge, our costs and our profitability.

Our businessesWe are subject to regulation by federal, state and local regulatory authorities. In particular, at the federal level our businesses are regulated by the FERC. At the state level, our businesses are regulated by theregulatory authorities in Illinois, Georgia, Tennessee,Virginia, New Jersey, Florida, VirginiaTennessee and Maryland regulatory authorities.Maryland.

These authorities regulate many aspects of our operations, including construction and maintenance of facilities, rights of way, operations, safety, rates that we charge customers, rates of return, the authorized cost of capital, recovery of costs associated with our regulatory infrastructure projects, including our pipeline replacement programs,program and environmental remediation activities, energy efficiency programs, relationships with our affiliates, franchise agreements and carrying costs we charge Marketers selling retail natural gas in Georgia for gas held in storage for their customer accounts. Our ability to obtain rate increases and rate supplements to maintain our current rates of return and recover regulatory assets and liabilities recorded in accordance with authoritative guidance related to regulated operations depends on regulatory discretion, and there can be no assurance that we will be abl eable to obtain rate increases or rate supplements or continue receiving our currently authorized rates of return including the recovery of our regulatory assets and liabilities.

The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 introduced a comprehensive new regulatory framework for swaps and security-based swaps. Althoughliabilities, or that the SEC and other regulators are still in the process of adopting rules to implement the new framework, it is possible that Sequent, or other aspects of AGL Resources’ operations, could be subject to the new regulations, depending on the ultimate definitions of key terms in the Dodd-Frank Act suchcommissions will deem all costs, including capital costs, as “swap,” “swap dealer” and “major swap participant.”prudently incurred.

We could incur significant compliance costs if we mustare required to adjust to new regulations. In addition, as the regulatory environment for our industry increases in complexity, the risk of inadvertent noncompliance could also increase. If we fail to comply with applicable regulations, whether existing or new, ones, we could be subject to fines, penalties or other enforcement action by the authorities that regulate our operations, or otherwise be subject to material costs and liabilities. This may require increased use of working capital for Sequent.  
In 1997, Georgia enacted legislation allowing deregulation of gas distribution operations. To date, Georgia is the only state in the nation that has fully deregulated gas distribution operations, which ultimately resulted in Atlanta Gas Light exiting the retail natural gas sales business while retaining its gas distribution operations. Marketers, including our majority-owned subsidiary, SouthStar, then assumed the retail gas sales responsibility at deregulated prices. The deregulation process required Atlanta Gas Light to completely reorganize its operations and personnel at significant expense. It is possible that the legislature could reverse or amend portions of the deregulation process.

Our business isWe are subject to environmental regulation in all jurisdictions in which we operate, and our costs to comply are significant. Any changes in existing environmental regulation could affect our results of operations and financial condition.

Our operations and propertiesWe are subject to extensive environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. Such environmental legislationregulation imposes, among other things, restrictions, liabilities and obligations in connectionassociated with storage, transportation, treatment and disposal of hazardous substancesMGP residuals and waste and in connection with spills, releases and emissions of various substances into the environment. Environmental legislation also requires that our facilities, sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Our current costs to comply with these laws and regulations are significant to our results of operations and financial condition. Failure to comply with these laws and regulations and failure to obtain any required permits and licenses may expose us to fines, penalties or interruptions in our operations that could be material to our results of operations.

We are generally responsible for liabilities associated with the environmental condition of the natural gas assets that we have operated, acquired or developed, regardless of when the liabilities arose and whether they are or were known or unknown. In addition, in connection with certain acquisitions and sales of assets, we may obtain, or be required to provide, indemnification against certain environmental liabilities. Before natural gas was widely available, we manufactured gas from coal and other fuels. Those manufacturing operations were known as MGPs, which we ceased operating in the 1950s. For more information regarding these obligations, see Note 11 to the consolidated financial statements under Item 8 herein.

In addition, claims against us under environmental laws and regulations could result in material costs and liabilities. Existing environmental laws and regulations also could also be revised or reinterpreted, and new laws and regulations could be adopted or become applicable to us or our facilities, and future changes in environmental laws and regulations could occur.facilities. With the trend toward stricter standards, greater regulation, more extensive permit requirements and an increase in the number and types of assets operated by us subject to environmental regulation, our environmental expenditures could increase in the future, particularly if those costs areand such expenditures may not be fully recoverable from our customers. Additionally, the discovery of presently unknown environmental conditions could give rise to expenditures and liabilities, including fines or penalties, which coul dcould have a material adverse effect on our business, results of operations or financial condition.

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Our infrastructure improvement and customer growth may be restricted by the capital-intensive nature of our business.

We must construct additions and replacements to our natural gas distribution systemsystems to continue the expansion of our customer base and improve system reliability, especially during peak usage. We also may also need to construct expansions of our existing natural gas storage facilities or develop and construct new natural gas storage facilities. The cost of thissuch construction may be affected by the cost of obtaining government and other approvals, development project delays, adequacy of supply of diversified vendors, vendor performance, or unexpected changes in project costs. Weather, general economic conditions and the cost of funds to finance our capital projects can materially alter the cost, andthe projected construction schedule and the completion timeline of a project. Our cash flows may not be fully adequate to finance the cost of thissuch construction. As a result, we may be required to fund a portion of our cash needs through borrowings or the issuance of common stock, or both. For our distribution operations segment, this may limit our ability to expand our infrastructure to connect new customers due to limits on the amount we can economically invest, which shifts costs to potential customers and may make it uneconomical for them to connect to our distribution systems. For our natural gas storage business, this may significantly reduce our earnings and return on investment from what would be expected for this business, or it may impair our ability to complete the expansions or development projects.

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We may be exposed to certain regulatory and financial risks related to climate change.change and associated legislation and regulation.

Climate change is receiving everexpected to receive increasing attention from scientiststhe current federal administration, non-governmental organizations and legislators alike. The debate is ongoinglegislators. Debate continues as to the extent to which our climate is changing, the potential causes of thisany change and its potential impacts. Some attribute global warming to increased levels of greenhouse gases, including carbon dioxide, which has led to significant legislative and regulatory efforts to limit greenhouse gas emissions.

Presently there are no federally mandated greenhouse gas reduction requirements inThe EPA has begun using provisions of the United States. However, there are a number of legislative and regulatory proposalsClean Air Act to addressregulate greenhouse gas emissions, which are in various phasesincluding carbon dioxide. Thus far, EPA has imposed greenhouse gas regulations on automobiles and implemented new permitting requirements for the construction or modification of discussion or implementation. major stationary sources of greenhouse gas emissions, including natural gas-fired power plants.

In addition, President Obama issued a Presidential Memorandum on June 25, 2013, directing EPA to adopt performance standards to regulate greenhouse gas emissions from power plants. Specifically, the Presidential Memorandum directs EPA to propose standards for future power plants by September 20, 2013 and propose regulations and emission guidelines for modified, reconstructed, and existing power plants by June 1, 2014. The Presidential Memorandum directs EPA to finalize those regulations by June 1, 2015. States would be required to develop regulations implementing the EPA’s guidelines by June 30, 2016. It also includes a wide variety of other initiatives designed to reduce greenhouse gas emissions, prepare for the impacts of climate change, and lead international efforts to address climate change.

The outcome of federal and state actions to address global climate change could potentially result in a variety of regulatory programs including potential new regulations, additional charges to fund energy efficiency activities or other regulatory actions. These actions, which in turn could:

·  
result in increased costs associated with our operations,
·  
increase other costs to our business,
·  affect the demand for natural gas (positively or negatively), and
·  impact the prices we charge our customers.customers and affect the competitive position of natural gas.

Because natural gas is a fossil fuel with low carbon content, it is possiblelikely that future carbon constraints couldwill create additional demand for natural gas, both for production of electricity and direct use in homes and businesses. The impact is already being seen in the power production sector due to both environmental regulations and low natural gas costs.

Any adoption by federal or state governments mandating a substantial reduction in greenhouse gas emissions could have far-reaching and significant impacts on the energy industry. We cannot predict the potential impact of such laws or regulations on our future consolidated financial condition, results of operations or cash flows.

Transporting and storing natural gas involves numerous risks that may result in accidents and other operating risks and costs.

Our gas distribution and storage activities involve a variety of inherent hazards and operating risks, such as leaks, accidents, including third party damages, and mechanical problems, which could cause substantial financial losses. In addition, theseThese risks could result in serious injury to employees and non-employees, loss of human life, significant damage to property, environmental pollution and impairment of our operations, which in turn could lead to substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The location of pipelines and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. The occurrence of any of th esethese events not fully covered by insurance could adversely affect our financial position and results of operations.

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We face increasing competition, and if we are unable to compete effectively, our revenues, operating results and financial condition will be adversely affected, which may limit our ability to grow our business.

The natural gas business is highly competitive, increasingly complex, and we are facing increasing competition from other companies that supply energy, including electric companies, oil and propane providers and, in some cases, energy marketing and trading companies. In particular, the success of our investment in SouthStarretail businesses is affected by the competition SouthStar faces from other energy marketers providing retail natural gas services in the Southeast.our service territories, most notably in Illinois and Georgia. Natural gas competes with other forms of energy. The primary competitive factor is price. Changes in the price or availability of natural gas relative to other forms of energy and the ability of end-users to convert to alternative fuels affect the demand for natural gas. In the case of commercial, industrial and agricultural customers, adverse economic conditions, including higher natural gas costs, , could also cause these customers to bypass or disconnect from our systems in favor of special competitive contracts with lower per-unit costs.

these fixed-price contracts may be adversely affected if natural gas prices are, or are perceived to be, low and stable. Our retail operations segment also faces risks in the form of price, convenience and service competition from other warranty and HVAC companies. Retail services also bears risk from potential changes in the regulatory environment.
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Our wholesale services segment competes with national and regional full-service energy providers, energy merchants and producers and pipelines for sales based on our ability to aggregate competitively priced commodities with transportation and storage capacity. Some of our competitors are larger and better capitalized than we are and have more national and global exposure than we do. The consolidation of this industry and the pricing to gain market share may affect our operating margin. We expect this trend to continue in the near term, and the increasing competition for asset management deals could result in downward pressure on the volume of transactions and the related operating margin available in this portion of Sequent’s business.

Our midstream operations segment competes with natural gas facilities in the Gulf Coast region of the U.S. as the majority of the existing and proposed high deliverability salt-dome natural gas storage facilities in North America are located in the Gulf Coast region. Competition for our Central Valley storage facility in northern California primarily consists of storage facilities in northern California and western North America. Storage values have declined over the past several years due to low gas prices and low volatility and we expect this to continue in 2014.

Our cargo shipping segment competes with international maritime companies. The continuationcurrent expansion of recent economic conditionsthe Panama Canal, which is expected to be completed and open for commercial ship transit in 2015, may lead to increased competition as larger vessels may gain access to the Caribbean. In addition, the growing development of the global logistic environment has moved away from port-to-port operations and towards the combined transport supply chain of various combinations of road, rail, sea and inland waterways. Globally, this has resulted in the need to improve ship productivity, sometimes via third party ship management, development of hub and spoke systems, larger ships, faster ship turnaround time and increased use of technology. Additionally, there are increased pricing pressures and decreased shipping volumes for the islands that Tropical Shipping currently serves. Increased competition may affect our volumes, market share, pricing structure and operating margin. Tropical Shipping does not have fuel contracts, but reduces its fuel price risk through fuel surcharges. Tropical Shipping has five primary competitors that serve the same major areas, some of which are larger and better capitalized than we are and have more global exposure than we do.

Changes or downturns in the economy could adversely affect our customers and negatively impact our financial results.

The slowdownoverall economy in the United States economy, along with increased mortgage defaults, andU.S. has a significant decreases in new home construction, home values and investment assets, has adversely impactedimpact on the financial well-being of many households in the United States. We cannot predict if the administrative and legislative actions to address this situation will be successful in reducing the severity or duration of this recession.U.S. As a result, changes or downturns in the U.S. economy could cause our customers mayto use less gas in future Heating Seasons and it may become more difficult for them to pay their natural gas bills. This may slow collections and lead to higher-than-normal levels of accounts receivables, bad debt and financing requirements. Sales to large industrial customers may be impacted by economic downturns. The manufacturing industry in the U.S. is subject to changing market conditions including international competition, fluctuating product demand and increased costs and regulation.

Tropical Shipping’s business consists primarily of the shipment of building materials, food and other necessities from the U.S. and Canada to developers, distributors and residents in the Bahamas and the Caribbean region, as well as tourist-related shipments intended for use in hotels, resorts and on cruise ships. As a result, Tropical Shipping’s results of operations, cash flows and financial condition can be significantly affected by adverse general economic conditions in the U.S., Bahamas, Caribbean region and Canada. Also, a shift in buying patterns that results in such goods being sourced directly from other parts of the world, including China and India, rather than the U.S. and Canada, could significantly affect Tropical Shipping’s results of operations, cash flows and financial condition.

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A significant portion of our accounts receivable is subject to collection risks, due in part to a concentration of credit risk in Georgiaat Nicor Gas, Atlanta Gas Light, SouthStar and at Sequent.

Nicor Gas and Sequent often extend credit to their counterparties. Despite performing credit analyses prior to extending credit and seeking to effectuate netting agreements, Nicor Gas and Sequent are exposed to the risk that they may not be able to collect amounts owed to them. If the counterparty to such a transaction fails to perform and any collateral Nicor Gas or Sequent has secured is inadequate, they could experience material financial losses.

Further, Sequent has a concentration of credit risk, which could subject a significant portion of its credit exposure to collection risks. Most of this concentration is with counterparties that are either load-serving utilities or end-use customers that have supplied some level of credit support. Default by any of these counterparties in their obligations to pay amounts due to Sequent could result in credit losses that would negatively impact our wholesale services segment.

We have accounts receivable collection riskrisks in Georgia due to a concentration of credit riskrisks related to the provision of natural gas services to Marketers. At December 31, 2010,2013, Atlanta Gas Light had elevenprovided services to 12 certificated and active Marketers in Georgia , four of which (based on customer count and including SouthStar) accounted for approximately 31% of our consolidated operating margin for 2010.Georgia. As a result, Atlanta Gas Light depends on a concentrated number of customers for revenues. The provisions of Atlanta Gas Light’s tariff allow it to obtain security support in an amount equal to no less than two times a Marketer’s highest month’s estimated bill in the form of cash deposits, letters of credit, surety bonds or guaranties. The failure of these Marketers to pa y Atlanta Gas Light could adversely affect Atlanta Gas Light’s business and results of operations and expose it to difficulties in collecting Atlanta Gas Light’s accounts receivable. AGL Resources provides a guarantee to Atlanta Gas Light as security support for SouthStar. Additionally, SouthStar markets directly to end-use customers and has periodically experienced credit losses as a result of severe cold weather or high prices for natural gas that increase customers’ bills and, consequently, impair customers’ ability to pay. For more information, see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” under the caption “Credit Risk” herein.

Sequent often extends credit to its counterparties. Despite performing credit analyses prior to extending credit and seeking to effectuate netting agreements, Sequent is exposed to the risk that it may not be able to collect amounts owed to it. If the counterparty to such a transaction fails to perform and any collateral Sequent has secured is inadequate, Sequent could experience material financial losses. Further, Sequent has a concentration of credit risk, which could subject a significant portion of its credit exposure to collection risks. Approximately 56% of Sequent’s credit exposure, excluding $61 million of customer deposits, is concentrated in its top 20 counterparties. Most of this concentration is with counterparties that are either load-serving utilities or end-use customers that have supplied some level of credit support . Default by any of these counterparties in their obligations to pay amounts due Sequent could result in credit losses that would negatively impact our wholesale services segment.

The asset management arrangements between Sequent and our local distribution companies, and between Sequent and its nonaffiliatednon-affiliated customers, may not be renewed or may be renewed at lower levels, which could have a significant impact on Sequent’s business.

Sequent currently manages the storage and transportation assets of our affiliates Atlanta Gas Light, ChattanoogaVirginia Natural Gas, Elizabethtown Gas, Elkton Gas, Florida City Gas, and Virginia NaturalChattanooga Gas and sharesElkton Gas. The profits it earns from the management of those assets with those customers andthese affiliates are shared with their respective customers except atand for Atlanta Gas Light with the Georgia Commission’s Universal Service Fund, with the exception of Chattanooga Gas and Elkton Gas where Sequent is assessed annual fixed-fees payable in monthly installments.fixed-fees. Entry into and renewal of these agreements are subject to regulatory approval. The asset management agreement foragreements with Elizabethtown Gas expiresand Elkton Gas expire in March 20112014 and we are currently working withcannot predict whether such agreements will be renewed or the New Jersey BPU to extend this agreement for an additional three years. The agreements for Atlanta Gas Light and Virginia Natural Gas are subject to renewal in March 2012. Additionally, the agreement with Florida City Gas expires in March 2013 and the agreement with Chattanooga Gas expires in March 2014.terms of such renewal.

Sequent also has asset management agreements with certain nonaffiliatednon-affiliated customers. Sequent’s results could be significantly impacted if these agreements are not renewed or are amended or renewed with less favorable terms. Sustained low natural gas prices could reduce the demand for these types of asset management arrangements.

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We are exposed to market risk and may incur losses in wholesale services, midstream operations and retail energy operations.

The commodity, storage and transportation portfolios at Sequent and the commodity and storage portfolios at midstream operations and SouthStar consist of contracts to buy and sell natural gas commodities, including contracts that are settled by the delivery of the commodity or cash. If the values of these contracts change in a direction or manner that we do not anticipate, we could experience financial losses from our trading activities. Based on a 95% confidence intervalFor more information, see Item 7A, “Quantitative and employing a 1-day holding period for all positions, Sequent’s and SouthStar’s portfolio of positions as of December 31, 2010 had a 1-day holding period VaR of $1.6 million and less than $0.1 million, respectively.Qualitative Disclosures About Market Risk” under the caption “Value-at-risk” herein.

Our accounting results may not be indicative of the risks we are taking or the economic results we expect for wholesale services.

Although Sequent enters into various contracts to hedge the value of our energy assets and operations, the timing of the recognition of profits or losses on the hedges does not always correspond to the profits or losses on the item being hedged. The difference in accounting can result in volatility in Sequent’s reported results, even though the expected operating margin is essentially unchanged from the date the transactions were initiated.

Changes in weather conditions may affect our earnings.

Weather conditions and other natural phenomena can have a large impact on our earnings. Severe weather conditions can impact our suppliers and the pipelines that deliver gas to our distribution system. Extended mild weather, during either the winter or summer period, can have a significant impact on demand for and cost of natural gas.

At Nicor Gas, approximately 50% of all usage is for space heating and approximately 75% of the usage and revenues occur from October through March. Weather fluctuations have the potential to significantly impact year-to-year comparisons of operating income and cash flow. We estimate that a 100 degree-day variation from normal weather of 5,729 Heating Degree Days impacts Nicor Gas’ margin, net of income taxes, by approximately $1 million under its current rate structure. 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 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.

We have a WNA mechanismmechanisms for Virginia Natural Gas, Elizabethtown Gas and Chattanooga Gas that partially offsetsoffset the impact of unusually cold or warm weather on residential and commercial customer billings and on our operating margin. At Elizabethtown Gas we could be required to return a portion of any WNA surcharge to its customers if Elizabethtown Gas’ return on equity exceeds its authorized return on equity of 10.3%.

Additionally, Virginia Natural Gas has a WNA mechanism for its residential customers that partially offsets the impacts
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These WNA regulatory mechanisms are most effective in a reasonable temperature range relative to normal weather using historical averages. The protection afforded by the WNA depends on continued regulatory approval. The loss of this continued regulatory approval could make us more susceptible to weather-related earnings fluctuations.

We also have decoupled, including straight-fixed-variable, rate designs at Atlanta Gas Light, Virginia Natural Gas and Chattanooga Gas, which allow for the recovery of fixed customer service costs separately from assumed natural gas volumes used by our customers. For more information, see Item 1, “Business” under the caption “Rate Structures” herein.

Changes in weather conditions also may also impact SouthStar’s earnings. As a result, SouthStar uses a variety of weather derivative instruments to stabilize the impact on its operating margin in the event of warmer or colder-than-normal weather in the winter months. However, these instruments do not fully protect SouthStar’s earnings from the effects of unusually warm or cold weather.

Wholesale services’ earnings are impacted by changes in weather conditions as weather impacts the demand for natural gas and volatility in the natural gas market. The volatility of natural gas commodity prices has a significant impact on our customer rates, our long-term competitive position against other energy sources and the ability of our wholesale services segment to capture value from location and seasonal spreads. The volatility of natural gas prices in 2013 was higher relative to 2011 and 2012 due to colder weather and supply constraints in the Northeast corridor but relative to periods prior to 2011, generally it was significantly lower in part due to mild hurricane seasons and mild summer and winter weather. Through the acquisition of natural gas and hedging of natural gas prices, wholesale services reduces the risk to its results of operations, cash flows and financial condition.

Tropical Shipping’s operations are affected by weather conditions in Florida, Canada, the Bahamas and Caribbean regions. During hurricane season in the summer and fall, Tropical Shipping may be subject to revenue loss, higher operating expenses, business interruptions, delays, and ship, equipment and facilities damage which could adversely affect Tropical Shipping’s results of operations, cash flows and financial condition. In addition, Seven Seas’ results of operations, cash flows and financial condition may be adversely affected due to increased insured losses relating to claims arising from hurricane-related events.

Our retail energy businesses in Illinois, Nicor Solutions and Nicor Advanced Energy, offer utility-bill management products that mitigate and/or eliminate the risks to customers of variations in weather and we hedge this risk to reduce any adverse effect to our results of operations, cash flows and financial condition.

A decrease in the availability of adequate pipeline transportation capacity due to weather conditions could reduce our revenues and profits.

Our gas supply for our distribution operations, retail operations, wholesale services and midstream operations segments depends on the availability of adequate pipeline transportation and storage capacity. We purchase a substantial portion of our gas supply from interstate sources. Interstate pipeline companies transport the gas to our system. A decrease in interstate pipeline capacity available to us or an increase in competition for interstate pipeline transportation and storage service could reduce our normal interstate supply of gas.gas or cause rates to fluctuate.

Our profitability may decline if the counterparties to Sequent’s asset management transactions fail to perform in accordance with Sequent’s agreements.

Sequent focuses on capturing the value from idle or underutilized energy assets, typically by executing transactions that balance the needs of various markets and time horizons. Sequent is exposed to the risk that counterparties to our transactions will not perform their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative hedging arrangements, honor the underlying commitment at then-current market prices or return a significant portion of the consideration received for gas. In such events, we may incur additional losses to the extent of amounts, if any, already paid to or received from counterparties.

We could incur additional material costs for the environmental condition of some of our assets, including former manufactured gas plants.

We are generally responsible for all on-site and certain off-site liabilities associated with the environmental condition of the natural gas assets that we have operated, acquired or developed, regardless of when the liabilities arose and whether they are or were known or unknown. In addition, in connection with certain acquisitions and sales of assets, we may obtain, or be required to provide, indemnification against certain environmental liabilities. Before natural gas was widely available, we manufactured gas from coal and other fuels. Those manufacturing operations were known as MGPs, which we ceased operating in the 1950s.

We have confirmed ten sites in Georgia and three in Florida where we own all or part of an MGP site. One additional former MGP site has been recently identified adjacent to an existing MGP remediation site. Precise engineering soil and groundwater clean up estimates are not available and considerable variability exists with this potential new site. We are required to investigate possible environmental contamination at those MGP sites and, if necessary, clean up any contamination. As of December 31, 2010, the soil and sediment remediation program was substantially complete for all Georgia sites, except for a few remaining areas of recently discovered impact, although groundwater cleanup continues. As of December 31, 2010, projected costs associated with the MGP sites associated with Atlanta Gas Light range from $57 million to $105 million. For elements of the MGP program where we still cannot provide engineering cost estimates, considerable variability remains in future cost estimates.

In addition, we are associated with former sites in New Jersey and North Carolina. Material cleanups of these sites have not been completed nor are precise estimates available for future cleanup costs and therefore considerable variability remains in future cost estimates. For the New Jersey sites, cleanup cost estimates range from $75 million to $138 million. Costs have been estimated for one site in North Carolina and range from $11 million to $16 million.

Inflation and increased gas costs could adversely impact our ability to control operating expenses and costs, increase our level of indebtedness and adversely impact our customer base.

Inflation has caused increases in certain operating expenses that have required us to replace assets at higher costs. We attempt to control costs in part through implementation of best practices and business process improvements, many of which are facilitated through investments in information systems and technology. We have a process in place to continually review the adequacy of our utility gas rates in relation to the increasing cost of providing service and the inherent regulatory lag in adjusting those gas rates. Historically, we have been able to control operating expenses and investments within the amounts authorized to be collected in rates, and we intend to continue to do so. However, any inability by us to control our expenses in a reasonable manner would adversely influence our future results.

Rapid increases in the price of purchased gas could cause us to experience a significant increase in short-term debt because we must pay suppliers for gas when it is purchased, which can be significantly in advance of when these costs may be recovered through the collection of monthly customer bills for gas delivered. Increases in purchased gas costs also slow our utility collection efforts as customers are more likely to delay the payment of their gas bills, leading to higher-than-normal accounts receivable. This situation results in higher short-term debt levels and increased bad debt expense. Should the price of purchased gas increase significantly, during the upcoming Heating Season, we would expect increases in our short-term debt, accounts receivable and bad debt expense during 2011.expense.

Finally, higher costs of natural gas in recent years have already caused many ofcan cause our utility customers to conserve in thetheir use of our gas services and could lead to even more customers utilizing such conservation methods or switchingswitch to other competing products. The higherHigher natural gas costs have also allowedmay increase competition from products utilizing alternative energy sources for applications that have traditionally used natural gas, encouraging some customers to move away from natural gas firedfueled equipment to equipment fueled by other energy sources. However,

natural gas prices are expected to remain lower than they have been for the last few years as a resultGlossary
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The cost of providing pension and postretirement health careretirement plan benefits to eligible employees and qualified retirees is subject to changes in pension fund values and changingchanges in liabilities as a result of updated demographics and assumptions. These changes may have a material adverse effect on our financial results.

We have defined benefit pension and postretirement health care plans for the benefit of substantially all full-time employees and qualified retirees.
The cost of providing theseretirement plan benefits to eligible current and former employees is subject to changes in the market value of our pension fund assets, changing demographics and assumptions, including longer life expectancy of beneficiaries and changes in health care cost trends.

Any sustained declines in equity markets and reductions in bond yields may have a material adverse effect on the value of our pension funds.plan assets. In these circumstances, we may be required to recognize an increased pension expense orand a charge to our other comprehensive income to the extent that the actual return on assets in the pension fund values areis less than the total anticipated liability under the plans. Market declines in the second half of 2008 resulted in significant losses in the value of our pension fund assets. Although the market made a recovery in 2009 and 2010 our pension fund assets are not at the levels they were prior to the market decline in 2008. As a result, based on the current funding status of the plans, we wouldexpected return. We may be required to make a minimum contribution to the plans of approximately $23 millionadditional contributions in 2011. We are planning to make additional contributi ons in 2011 up to $38 million, for a total of up to $61 million,future periods in order to preserve the current level of benefits under the plans and in accordance with the funding requirements of The Pension Protection Act of 2006 (Pension Protection Act). As of December 31, 2010 our pension plans assets represented 65% of our total pension plan obligations.

For more information, regarding some of these obligations, see Item 7, “Management's“Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Contractual Obligations and Commitments” and the subheading “Pension and Postretirement Obligations”Other Retirement Plans” and Note 5 “Employee Benefit Plans,” set forth in6 to the consolidated financial statements under Item 8 “Financial Statements and Supplementary Data.”herein.

Natural disasters, pandemic illness, material misconduct, terrorist activities and the potential for military and other actions could adversely affect our businesses.

Natural disasters may damage our assets.assets and interrupt our business operations. Pandemic illness could result in part of our workforce being unable to operate or maintain our infrastructure or perform other tasks necessary to conduct our business. An employee or third party may purposely, or inadvertently, fail to adhere to our policies and procedures or our policies and procedures may not be effective; this could result in the violation of a law or regulation, a material error or misstatement, damage to our reputation or the incurrence of substantial expense. The threat of terrorism and the impact of retaliatory military and other action by the United StatesU.S. and its allies may lead to increased political, economic and financial market instability and volatility in the price of natural gas that could affect our operations. In addition, future acts of terrorism could be directed against companies operating in the United States,U.S., and companies in the energy industry may face a heightened risk of exposure to acts of terrorism. These developments have subjected our operations to increased risks. The insurance industry has also been disrupted by these events. As a result, the availability of insurance covering risks against which we and our competitors typically insure may be limited.limited or may be insufficient. In addition, the insurance we are able to obtain may have higher deductibles, , higher premiums and more restrictive policy terms.

A work stoppage could adversely impact our results of operations, cash flows and financial condition.

Certain of our businesses are dependent upon employees who are represented by unions and are covered by collective bargaining agreements. These agreements may increase our costs, affect our ability to continue offering market-based salaries and benefits and limit our ability to implement efficiency-related improvements. Disputes with the unions could result in work stoppages that could impact the delivery of natural gas and other services, which could strain relationships with customers, vendors and regulators. We believe that we have a good working relationship with our unionized employees and we remain committed to work in good faith with the unions to renew or renegotiate collective bargaining agreements that balance the needs of the Company and our employees. For more information, see Item 1, “Business” under the caption “Employees” herein.

Changes in the laws and regulations regarding the sale and marketing of products and services offered by our retail operations segment could adversely affect our results of operations, cash flows and financial condition.

Our retail operations segment provides various energy-related products and services. These include sales of natural gas and utility-bill management services to residential and small commercial customers, and the sale, repair, maintenance and warranty of heating, air conditioning and indoor air quality equipment. The sale and marketing of these products and services are subject to various state and federal laws and regulations. Changes in these laws and regulations could impose additional costs on or restrict or prohibit certain activities, which could adversely affect our results of operations, cash flows and financial condition.

In 1997, Georgia enacted legislation allowing deregulation of gas distribution operations. To date, Georgia is the only state in the nation that has fully deregulated gas distribution operations, which ultimately resulted in Atlanta Gas Light exiting the retail natural gas sales business while retaining its gas distribution operations. Marketers, including our majority-owned subsidiary, SouthStar, then assumed the retail gas sales responsibility at deregulated prices. The deregulation process required Atlanta Gas Light to completely reorganize its operations and personnel at significant expense. We are not aware of any movement to do so, but it is possible that the legislature could reverse or amend portions of the deregulation process.

Changes in the laws and regulations regarding maritime activities offered by our cargo shipping segment could adversely affect our results of operations, cash flows and financial condition.

Tropical Shipping is subject to the International Ship and Port Facility Security Code and is also subject to the U.S. Maritime Transportation Security Act, both of which require extensive security assessments, plans and procedures. Tropical Shipping is also subject to the regulations of the Federal Maritime Commission, the Surface Transportation Board, as well as other federal agencies and local laws, where applicable. Additional costs that could result from changes in the rules and regulations of these regulatory agencies would adversely affect our results of operations, cash flows and financial condition.

Conservation could adversely affect our results of operations, cash flows and financial condition.

As a result of legislative and regulatory initiatives on energy conservation, we have put into place programs to promote additional energy efficiency by our customers. Funding for such programs is being recovered through cost recovery riders. However, the adverse impact of lower deliveries and resulting reduced margin could adversely affect our results of operations, cash flows and financial condition.

A security breach could disrupt our operating systems, shutdown our facilities or expose confidential personal information.

Security breaches of our information technology infrastructure, including cyber-attacks and cyber terrorism, could lead to system disruptions or generate facility shutdowns. If such an attack or security breach were to occur, our business, results of operations and financial condition could be materially adversely affected. In addition, such an attack could affect our ability to service our indebtedness, our ability to raise capital and our future growth opportunities.

Additionally, the protection of customer, employee and company data is critical to us. A breakdown or a breach in our systems that results in the unauthorized release of individually identifiable customer or other sensitive data could occur and have a material adverse effect on our reputation, operating results and financial condition. Such a breakdown or breach could also materially increase the costs we incur to protect against such risks. There is no guarantee that the procedures that we have implemented to protect against unauthorized access to secured data are adequate to safeguard against all data security breaches. We had no material security breaches in 2013.

We could be adversely affected by violations of the Foreign Corrupt Practices Act and similar worldwide anti-bribery laws.

Our international operations require us to comply with a number of U.S. and international laws and regulations, including those prohibiting certain payments to foreign officials. One of these laws, the Foreign Corrupt Practices Act (FCPA), generally prohibits U.S. companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or maintaining business. Although our policies require compliance with these laws and we maintain a compliance training program designed to avoid violations, controlling the actions of our employees and the representatives of our international operations is difficult and violations may occur. For a discussion of an investigation of a potential violation of such laws, see Item 3, “Legal Proceedings” herein. Violations of these laws, or allegations of such violations, could disrupt our business and result in a material adverse effect on our business and results of operations, cash flows and financial condition.

We may pursue acquisitions, divestitures and other strategic transactions, the success of which may impact our results of operations, cash flows and financial condition.

In the past, we have pursued acquisitions to complement or expand our business, divestures and other strategic transactions. Such future transactions are part of our general strategic objectives and may occur. If we identify an acquisition candidate, we may not be able to successfully negotiate or finance the acquisition or integrate the acquired businesses with our existing business and services. Acquisitions may result in potentially dilutive issuances of equity securities and the incurrence of debt and contingent liabilities, amortization expenses and substantial goodwill. Acquisitions may not be accretive to our earnings and may cause dilution to our earnings per share, which may negatively affect the market price of our common shares. We may be affected materially and adversely if we are unable to successfully integrate businesses that we acquire in an efficient and effective manner. Similarly, we may divest portions of our business, which may also have material and adverse effects.

We assess goodwill and indefinite-lived intangible assets for impairment at least annually and more frequently if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. We assess our long-lived assets, including finite-lived intangible assets, for impairment whenever events or circumstances indicate that an asset’s carrying amount may not be recoverable. To the extent the value of goodwill or long-lived assets become impaired, we may be required to incur impairment charges that could have a material impact on our results of operations. No impairment of goodwill was recorded as a result of our 2013 annual impairment testing as the fair value of each reporting unit was in excess of the carrying value. Additionally, no impairment of long-lived assets was recorded during 2013.

Since interest rates are a key component, among other assumptions, in the models used to estimate the fair values of our reporting units, as interest rates rise, the calculated fair values decrease and future impairments may occur. Further, the rates for contracting capacity at Jefferson Island, Golden Triangle and Central Valley are also key components in the models used to estimate their fair value. Consequently, a further decline in market fundamentals and the rates for contracting availability could result in future impairments. Our cargo shipping segment also has goodwill and assets subject to impairment testing and while conditions are improving in this segment it has been adversely impacted by the weak global economy. Due to the subjectivity of the assumptions and estimates underlying the impairment analysis, we cannot provide assurance that future analyses will not result in impairment. These assumptions and estimates include projected cash flows, current and future rates for contracted capacity, growth rates, weighted average cost of capital and market multiples. For additional information, see Item 7,”Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Critical Accounting Policies and Estimates” herein.

Failure to recruit, retain and train an appropriately qualified workforce could negatively impact our results of operations, cash flows and financial condition.

Our business is dependent on our ability to recruit, retain, and train employees. Certain circumstances, such as an aging workforce without appropriate replacements, a mismatch of existing skillsets to current and future needs, or the availability of outside resources may lead to operational challenges such as lack of resources, loss of knowledge, errors due to inexperience, or a lengthy training period. Our costs, including productivity and safety costs, costs to replace employees, and costs as a result of errors may increase. Failure to hire and adequately train employees, including the transfer of significant internal historical knowledge and expertise could adversely affect our ability to manage and operate our business.

Risks Related to Our Corporate and Financial Structure

We depend on our ability to successfully access the capital and financial markets. Any inability to access the capital or financial markets may limit our ability to execute our business plan or pursue improvements that we may rely on for future growth.

We rely on access to both short-term money markets (in the form of commercial paper and lines of credit) and long-term capital markets as a source of liquidity for capital and operating requirements not satisfied by the cash flow from our operations. If we are not able to access financial markets at competitive rates, our ability to implement our business plan and strategy will be negatively affected, and we may be forced to postpone, modify or cancel capital projects. Certain market disruptions may increase our cost of borrowing or affect our ability to access one or more financial markets. Such market disruptions could result from:

·  adverse economic conditionsconditions;
·  adverse general capital market conditionsconditions;
·  poor performance and health of the utility industry in generalgeneral;
·  bankruptcy or financial distress of unrelated energy companies or MarketersMarketers;
·  significant decrease in the demand for natural gasgas;
·  adverse regulatory actions that affect our local gas distribution companies and our natural gas storage businessbusiness;
·  terrorist attacks on our facilities or our suppliers,suppliers; or
·  extreme weather conditions.

The global credit markets have experienced significant disruption and volatility in recent years. While the commercial paper market has stabilized it has not returned to its pre-recession state. As of December 31, 2010, we had $732 million in commercial paper outstanding and no outstanding borrowings under our Credit Facility, Bridge Facility or Term Loan Facility. Subsequent to December 31, 2010, we drew a portion of the Term Loan Facility to help repay our senior notes that matured in January 2011.

During 2010, our borrowings under our Credit Facility along with our commercial paper were primarily used to purchase natural gas inventories for the current Heating Season. The amount of our working capital requirements in the near-term will primarily depend on the market price of natural gas and weather. Higher natural gas prices may adversely impact our accounts receivable collections and may require us to increase borrowings under our credit facilityfacilities to fund our operations.

While we believe we can meet our capital requirements from our operations and our available sources of financing, we can provide no assurance that we will continue to be able to do so in the future, especially if the market price of natural gas increases significantly in the near-term. The future effects on our business, liquidity and financial results due to market disruptions could be material and adverse to us, both in the ways described above, or in ways that we do not currently anticipate.

If we breach any of the financial covenants under our various credit facilities, our debt service obligations could be accelerated.

Our existingThe AGL Credit Facility, Bridge Facility, Term Loan Facility and the SouthStar line of creditNicor Gas Credit Facility contain financial covenants. If we breach any of the financial covenants under these agreements, our debt repayment obligations under them could be accelerated. In such event, we may not be able to refinance or repay all of our indebtedness, which would result in a material adverse effect on our business, results of operations and financial condition.

A downgrade in our credit rating could negatively affect our ability to access capital.capital, or may require us to provide additional collateral to certain counterparties.

Our senior unsecured debt is currently assigned investment grade credit ratings. If the rating agencies downgrade our ratings, particularly below investment grade, it may significantly limit our access to the commercial paper market and our borrowing costs would increase. In addition, we would likely be required to pay a higher interest rate in future financings and our potential pool of investors and funding sources would likely decrease.

Additionally, if our credit rating by either S&P or Moody’s falls to non-investment grade status, we willwould be required to provide additional support for certain customers of our wholesale business. In December 2010, after we announced the proposed merger with Nicor, S&P lowered our outlook from stable to negative watch, but S&P did not change our credit rating. As of December 31, 2010, if our credit rating had fallen below investment grade, we would have been required to provide collateral of approximately $39 million to continue conducting our wholesale services business with certain counterparties.customers. In December 2012, Fitch lowered the ratings of AGL Resources from A- to BBB+. There are no implications of this downgrade on our corporate funding ability or our ability to access the capital markets, nor does this downgrade trigger any collateralization requirements under our corporate guarantees. For additional credit rating and interest rate information, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Liquidity and Capital Resources” and Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” under the caption “Interest Rate Risk” herein.

We are vulnerable to interest rate risk with respect to our debt, which could lead to changes in interest expense and adversely affect our earnings.

We are subject to interest rate risk in connection with the issuance of fixed-rate and variable-rate debt. In order to maintain our desired mix of fixed-rate and variable-rate debt, we may use interest rate swap agreements and exchange fixed-rate and variable-rate interest payment obligations over the life of the arrangements, without exchange of the underlying principal amounts. For additional information, see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” under the caption “Interest Rate Risk.” We cannot ensure thatHowever, we will be successful in structuring suchmay not structure these swap agreements to managein a manner that manages our risks effectively. If we are unable to do so, our earnings may be reduced. In addition, higher interest rates, all other things equal, reduce the earnings that we derive from transactions where we capture the difference between authorized returns and short-t ermshort-term borrowings.

We are a holding company and are dependent on cash flow from our subsidiaries, which may not be available in the amounts and at the times we need.

A significant portion of our outstanding debt was issued by our wholly-ownedwholly owned subsidiary, AGL Capital, which we fully and unconditionally guarantee. Since we are a holding company and have no operations separate from our investment in our subsidiaries, we are dependent on the net income and cash in the formflows of our subsidiaries and their ability to pay upstream dividends or other distributions from our subsidiaries to meet our cash requirements.financial obligations and to pay dividends on our common stock. The ability of our subsidiaries to pay upstream dividends and make other distributions is subject to applicable state law.law and regulatory restrictions. In addition, Nicor Gas is not permitted to make money pool loans to affiliates. Refer to Item 5, “Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” for additional dividend restriction information. Our subsidiaries are separate legal entities and have no obligation to provide us with funds.

The use of derivative contracts in the normal course of our business could result in financial losses that negatively impact our results of operations.

We use derivatives,derivative instruments, including futures, options, forwards and swaps, to manage our commodity and financial market risks. We could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. In addition, derivative contracts entered for hedging purposes may not offset the underlying exposure being hedged as expected, resulting in financial losses. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these derivative financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could adversely affect the value of the reported fair value of these contracts.

The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 introduced a comprehensive new framework for the regulation of OTC derivatives, including the requirement that certain OTC derivatives, or swaps, to be centrally cleared and executed through an exchange or other approved trading platform. The Dodd-Frank Act required various regulatory agencies, including the Commodity Futures Trading Commission and the SEC, to establish regulations for implementation of this requirement and many other provisions of the Dodd-Frank Act. A number of those regulations have been adopted and we have enacted new procedures and modified existing business practices and contractual arrangements to comply with such regulations. In addition, based on current interpretation, we were not considered to be a “swap dealer” or “major swap participant” in 2013 so we are exempt from the clearing, exchange trading and certain other requirements under the Dodd-Frank Act. If these provisions were to apply to our derivative activities, we could be subject to higher costs for our derivative activities, including from higher margin requirements. In addition, implementation of, and compliance with, the OTC derivatives provisions of the Dodd-Frank Act by our swap counterparties could result in increased costs or additional collateral postings related to our derivative activities. We expect additional regulations to be issued, which should provide further clarity regarding the impact of this legislation on us, including any potential increased costs of our hedging activities.

As a result of cross-default provisions in our borrowing arrangements, we may be unable to satisfy all of our outstanding obligations in the event of a default on our part.

OurThe AGL Credit Facility Bridge Facility and Term Loanthe Nicor Gas Credit Facility contain cross-default provisions. Should an event of default occur under some of our debt agreements, we face the prospect of being in default under our other of our debt agreements, obligated in such instance to satisfy a large portion of our outstanding indebtedness and unable to satisfy all of our outstanding obligations simultaneously.

Risks Related to Our Proposed Merger with Nicor

The merger may not be completed, whichChanges in taxation could adversely affect our business operations and stock price.

To complete the merger, our shareholders must approve the issuance of shares of our common stock as contemplated by the Merger Agreement and the amendment to our Amended and Restated Articles of Incorporation to increase the number of directors that may serve on our Board of Directors, and Nicor shareholders must approve the Merger Agreement. In addition, we and Nicor must also make certain filings with, and obtain certain other approvals and consents from, various United States federal and state governmental and regulatory authorities.

We have not yet obtained all regulatory clearances, consents and approvals required to complete the merger. Governmental or regulatory agencies could still seek to block or challenge the merger or could impose restrictions they deem necessary or desirable in the public interest as a condition to approving the merger. If these approvals are not received, or they are not received on terms that satisfy the conditions set forth in the Merger Agreement, then we will not be obligated to complete the merger.

In addition, the Merger Agreement contains other customary closing conditions which may not be satisfied or waived. If we are unable to complete the merger, we would be subject to a number of risks, including the following:
·  we would not realize the anticipated benefits of the merger, including, among other things increased operating efficiencies
·  the attention of our management may have been diverted to the merger rather than to our operations and the pursuit of other opportunities that could have been beneficial to us
·  the potential loss of key personnel during the pendency of the merger as employees may experience uncertainty about their future roles with the combined company
·  we will have been subject to certain restrictions on the conduct of our business, which may prevent us from making certain acquisitions or dispositions or pursuing certain business opportunities while the merger is pending
·  the trading price of our common stock may decline to the extent that the current market price reflects a market assumption that the merger will be completed.

We are required to pay Nicor a termination fee and the reimbursement of merger-related out-of-pocket expenses if we terminate the merger under certain circumstances specified in the Merger Agreement.

The occurrence of any of these events individually or in combination could have a material adverse effect on our results of operations or the trading price of our common stock.

The market price of our common stock after the merger may be affected by factors different from those affecting the shares of AGL Resources or Nicor currently.

Our businesses differ from those of Nicor in important respects and, accordingly, the results of operations of the combined company and the market price of our shares of common stock following the merger may be affected by factors different from those currently affecting the results of our operations.

The merger is subject to receipt of consent or approval from governmental entities that could delay or prevent the completion of the merger or impose conditions that could have a material adverse effect on the combined company or that could cause abandonment of the merger.
To complete the merger, we and Nicor need to obtain approvals or consents from, or make filings with, a number of United States federal and state public utility, antitrust and other regulatory authorities.

While we believe that we will receive  the required statutory approvals and other clearances for the merger, there can be no assurance as to the receipt or timing of receipt of these approvals and clearances. If such approvals and clearances are received, they may impose terms (i) that do not satisfy the conditions set forth in the Merger Agreement, which could permit us or Nicor to terminate the Merger Agreement or (ii) that could reasonably be expected to have a detrimental impact on the combined company following completion of the merger. A substantial delay in obtaining the required authorizations, approvals or consents or the imposition of unfavorable terms, conditions or restrictions contained in such authorizations, approvals or consents could prevent the completion of the merger or have an adverse effect on the anticipat ed benefits of the merger, thereby impacting the business, financial condition or results of operations of the combined company.

Even after the statutory antitrust law waiting period has expired, governmental authorities could seek to block or challenge the merger as they deem necessary or desirable in the public interest.

We are subject to contractual restrictions in the Merger Agreement that may hinder operations pending the merger.

The Merger Agreement restricts each company, without the other’s consent, from making certain acquisitions and taking other specified actions until the merger occurs or the Merger Agreement terminates. These restrictions may prevent us from pursuing otherwise attractive business opportunities and making other changes to our business prior to completion of the merger or termination of the Merger Agreement.

We will be subject to various uncertainties while the merger is pending that may cause disruption and may make it more difficult to maintain relationships with employees, suppliers, or customers.

Uncertainty about the effect of the merger on employees, suppliers and customers may have an adverse effect on us. Although we intend to take steps designed to reduce any adverse effects, these uncertainties may impair our abilities to attract, retain and motivate key personnel until the merger is completed and for a period of time thereafter, and could cause customers, suppliers and others that deal with us to seek to change or terminate existing business relationships with us or not enter into new relationships or transactions.

Employee retention and recruitment may be particularly challenging prior to the completion of the merger, as employees and prospective employees may experience uncertainty about their future roles with the combined company. If, despite our retention and recruiting efforts, key employees depart or fail to continue employment with us because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, our financial results could be adversely affected. Furthermore, the combined company’s operational and financial performance following the merger could be adversely affected if it is unable to retain key employees and skilled workers. The loss of the services of key employees and skilled workers and their experience and knowledge regarding our business could adversely affect the combined company’s future operating results and the successful ongoing operation of its businesses.

Pending shareholder suits could delay or prevent the closing of the merger or otherwise adversely impact our business and operations.

Several class action lawsuits have been brought by purported Nicor shareholders challenging Nicor’s proposed merger with us. The complaints allege that we aided and abetted alleged breaches of fiduciary duty by Nicor’s Board of Directors. The shareholder actions seek, among other things, declaratory and injunctive relief, including orders enjoining the defendants from completing the proposed merger and, in certain circumstances, damages. No assurances can be given as to the outcome of these lawsuits, including the costs associated with defending these lawsuits or any other liabilities or costs the parties may incur in connection with the litigation or settlement of these lawsuits. Furthermore, one of the conditions to closing the merger is that there are no injunctions issued by any court preventing the completion of the trans actions. No assurance can be given that these lawsuits will not result in such an injunction being issued which could prevent or delay the closing of the Merger Agreement.

The merger may not be accretive to our earnings and may cause dilution to our earnings per share, which may negatively affect the market price of our common shares.

We currently anticipate that the merger will be neutral to our earnings per share in the first full year following the completion of the merger and accretive thereafter. This expectation is based on preliminary estimates which may materially change. We may encounter additional transaction and integration-related costs, may fail to realize all of the benefits anticipated in the merger or be subject to other factors that affect preliminary estimates. Any of these factors could cause a decrease in our earnings per share or decrease or delay the expected accretive effect of the merger and contribute to a decrease in the price of our common shares.

If the merger is completed, the anticipated benefits of combining Nicor with us may not be realized.

We entered into the Merger Agreement with the expectation that the merger would result in various benefits, including, among other things, increased operating efficiencies and reduced costs.

Although we expect to achieve the anticipated benefits of the merger, achieving them is subject to a number of uncertainties, including:

·  whether United States federal and state public utility, antitrust and other regulatory authorities whose approval is required to complete the merger impose conditions on the merger, which may have an adverse effect on the combined company, including its ability to achieve the anticipated benefits of the merger
·  the ability of the two companies to combine certain of their operations or take advantage of expected growth opportunities
·  general market and economic conditions
·  general competitive factors in the marketplace
·  higher than expected costs required to achieve the anticipated benefits of the merger.

No assurance can be given that these benefits will be achieved or, if achieved, the timing of their achievement. Failure to achieve these anticipated benefits could result in increased costs and decreases in the amount of expected revenues or net income of the combined company.

The integration of AGL Resources and Nicor following the merger will present significant challenges that may result in a decline in the anticipated potential benefits of the merger.

The merger involves the combination of two companies that previously operated independently. The difficulties of combining the companies’ operations include:

·  combining the best practices of two companies, including utility operations, non-regulated energy marketing operations and staff functions
·  coordinating geographically separated organizations, systems and facilities
·  integrating personnel with diverse business backgrounds and organizational cultures
·  moving our operating headquarters for our gas distribution business to Naperville, Illinois
·  reducing the costs associated with each company’s operations
·  preserving important relationships of both AGL Resources and Nicor and resolving potential conflicts that may arise.

The process of combining operations could cause an interruption of, or loss of momentum in, the activities of one or more of the combined company’s businesses and the possible loss of key personnel. The diversion of management’s attention and any delays or difficulties encountered in connection with the merger and the integration of the two companies’ operations could have an adverse effect on the business, results of operations, financial condition or prospects of the combined company after the merger.

We will incur significant transaction, merger-related and restructuring costs in connection with the merger.

We expect to incur costs associated with combining the operations of the two companies, as well as transaction fees and other costs related to the merger. The combined company also will incur restructuring and integration costs in connection with the merger. We are in the early stages of assessing the magnitude of these costs and additional unanticipated costs may be incurred in the integration of the businesses. The costs related to restructuring will be expensed as a cost of the ongoing results of operations of either AGL Resources or Nicor or the combined company. Although we expect that the elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, may offset incremental transaction, merger-related and restructuring costs over time, any net benefit may not be achiev ed in the near term, or at all.
Current shareholders will have a reduced ownership and voting interest after the merger and will exercise less influence over management of the combined company.

Upon completion of the merger we expect to issue up to approximately 38.6 million shares of common stock to Nicor shareholders in connection with the Merger Agreement. As a result, our current shareholders are expected to hold approximately 67% of the total shares of our common stock outstanding immediately following the completion of the proposed merger.

If the merger occurs, each of our shareholders will remain a shareholder of AGL Resources with a percentage ownership of the combined company that is significantly smaller than the shareholder’s percentage ownership of AGL Resources prior to the merger. As a result of these reduced ownership percentages, our shareholders will have less influence on the management and policies of the combined company than they now have with respect to us.

The combined company will record goodwill that could become impaired and adversely affect the combined company’s operating results.

We will account for the merger as a purchase in accordance with GAAP. Under the purchase method of accounting, the assets and liabilities of Nicor will be recorded, as of the date of completion of the merger, at their respective fair values and added to our assets and liabilities. Our reported financial condition and results of operations issued after completion of the merger will reflect Nicor balances and results after completion of the merger, but will not be restated retroactively to reflect the historical financial position or results of operations of Nicor for periods prior to the merger. Following completion of the merger, the earnings of the combined company will reflect purchase accounting adjustments.

Under the purchase method of accounting, the total purchase price will be allocated to Nicor’s tangible assets and liabilities and identifiable intangible assets based on their fair values as of the date of completion of the merger. The fair value of Nicor's tangible and intangible assets and liabilities subject to the rate setting practices of their regulators approximate their carrying value. The excess of the purchase price over those fair values will be recorded as goodwill. We expect that the merger will result in the creation of goodwill based upon the application of purchase accounting. To the extent the value of goodwill or intangibles becomes impaired, the combined company may be required to incur material charges relating to such impairment. Such a potential impairment charge could have a material impact on the combined co mpany’s operating results.

Our inability to obtain the financing necessary to complete the transaction could delay or prevent the completion of the merger.

We intend to finance the cash portion of the merger consideration with debt financing. AGL Capital (as borrower) and AGL Resources (as guarantor), entered into the Bridge Facility in December 2010, which may be used to partially finance the cash portion of the merger and pay related fees and expenses in the event that permanent financing is not available at the time of the closing of the merger. AGL Resources and/or AGL Capital may issue debt securities, preferred stock, common equity, or other securities, bank loans, or other debt financings in lieu of all or a portion of the drawing under the Bridge Facility.

Under the terms of the Merger Agreement, if all of the conditions to closing are satisfied and the proceeds of the financing or alternative financing necessary to complete the transaction are not available, the Merger Agreement may be terminated by either party. However, such party is not in material breach of its representations, warranties, or covenants in the Merger Agreement. In such event, we may be required to pay Nicor a financing failure fee of $115 million.

Although we have entered into the Bridge Facility, the availability of funds under the Bridge Facility is subject to certain conditions including, among others, the absence of a material adverse effect on AGL Resources or Nicor, pro forma compliance with a consolidated total debt to total capitalization ratio of 70%, the ability of the borrower to achieve certain minimum credit ratings and the ability of the borrower to achieve a certain liquidity level at closing. Although we expect to obtain in a timely manner the financing necessary to complete the pending merger, if we are unable to timely obtain the financing because one of the conditions to the financing fails to be satisfied, the closing of the merger could be significantly delayed or may not occur at all, and we could be obligated to pay Nicor the financial failure fee.

Our indebtedness following the merger will be higher than our existing indebtedness, which could limit our operations and opportunities, make it more difficult for us to pay or refinance our debts and may cause us to issue additional equity in the future, which would increase the dilution of our shareholders or reduce earnings.

In connection with the merger, we will assume Nicor’s outstanding debt and incur additional debt to pay the merger consideration and transactions expenses. Our total indebtedness as of September 30, 2010 was approximately $2.5 billion. Our pro forma total indebtedness as of September 30, 2010, after giving effect to the merger, would have been approximately $4.4 billion (including approximately $0.4 billion of currently payable long-term debt, approximately $1.0 billion of short-term borrowings and approximately $3.0 billion of long-term debt and other long-term obligations).

Our debt service obligations with respect to this increased indebtedness could have an adverse impact on our earnings and cash flows (which after the merger would include the earnings and cash flows of Nicor) for as long as the indebtedness is outstanding.

This increased indebtedness could also have important consequences to shareholders. For example, it could:

·  make it more difficult for us to pay or refinance our debts as they become due during adverse economic and industry conditions because any decrease in revenues could cause us to not have sufficient cash flows from operations to make our scheduled debt payments
·  limit our flexibility to pursue other strategic opportunities or react to changes in our business and the industry in which we operate and, consequently, place us at a competitive disadvantage to competitors with less debt
·  require a substantial portion of our cash flows from operations to be used for debt service payments, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, acquisitions, dividend payments and other general corporate purposes
·  result in a downgrade in the credit rating of our indebtedness, which could limit our ability to borrow additional funds or increase the interest rates applicable to our indebtedness (after the announcement of the merger, Standard & Poor's Ratings Services placed its long-term ratings on AGL Resources on negative watch)
·  reduce the amount of credit available to us to support hedging activities
·  result in higher interest expense in the event of increases in interest rates since some of our borrowings are, and will continue to be, at variable rates.

Based upon current levels of operations, we expect to be able to generate sufficient cash on a consolidated basis to make all of the principal and interest payments when such payments are due under our existing credit agreements, indentures and other instruments governing our outstanding indebtedness, and under the indebtedness of Nicor and its subsidiaries that may remain outstanding after the merger; but there can be no assurance that we will be able to repay or refinance such borrowings and obligations.

We are committed to maintaining and improving our credit ratings. In order to maintain and improve these credit ratings, we may consider it appropriate to reduce the amount of indebtedness outstanding following the merger. This may be accomplished in several ways, including issuing additional shares of common stock or securities convertible into shares of common stock, reducing discretionary uses of cash or a combination of these and other measures. Issuances of additional shares of common stock or securities convertible into shares of common stock would have the effect of diluting the ownership percentage that shareholders will hold in the combined company and might reduce the reported earnings per share. The specific measures that we may ultimately decide to use to maintain or improve our credit ratings and their timing, will depend upo n a number of factors, including market conditions and forecasts at the time those decisions are made.

Following the merger, shareholders will own equity interests in a company that owns and operates a carrier shipping business, which can present unique risks.

Nicor’s ownership and operation of Tropical Shipping, a carrier of containerized freight in the Bahamas and the Caribbean region, which we anticipate will make up approximately 4% of the combined company's earnings before interest and taxes, or EBIT, will subject the combined company to various risks to which we are not currently subject. These include the costs associated with compliance with the International Ship and Port-facility Security Code and the United States Maritime Transportation Security Act, both of which require extensive security assessments, plans and procedures, regulatory oversight by the Federal Maritime Commission and the Surface Transportation Board, the effect of general economic conditions in the United States, the Bahamas, the Caribbean region and Canada on the results of operations, cash flows and financia l conditions of Tropical Shipping, and the effect of weather conditions in Florida, Canada, the Bahamas and the Caribbean region on the results of operations, cash flows and financial conditions of Tropical Shipping. As shareholders of the combined company following the merger, our shareholders may be adversely affected by these risks.condition.

Various tax and fee increases may occur in locations in which we operate. We cannot predict whether other legislation or regulation will be introduced, the form of any legislation or regulation, or whether any such legislation or regulation will be passed by the legislatures or other governmental bodies. New taxes or an increase in tax rates would increase tax expense and could adversely affect our results of operations, cash flows and financial condition.

ITEM 1B.UNRESOLVED1B.UNRESOLVED STAFF COMMENTS

We do not have any unresolved comments from the SEC staff regarding our periodic or current reports under the Securities Exchange Act of 1934, as amended.

ITEM 2.2. PROPERTIES

We consider our properties to be well maintained, in good operating condition and suitable for their intended purpose. The following provides the location and general character of the materially important properties that are used by our segments. Substantially all of Nicor Gas’ properties are subject to the lien of the indenture securing its first mortgage bonds. See Note 8 to our consolidated financial statements under Item 8 herein.

Distribution and transmission assetsmains

At December 31, 2010, our distribution operations and energy investment segments owned approximately 46,000 miles of underground distribution and transmission mains. Our distribution networkssystems transport natural gas from our pipeline suppliers to our customers in our service areas. TheAt December 31, 2013, our distribution operations segment owned approximately 80,500 miles of underground distribution and transmission mains. These distribution and transmission mains are located on easements or rights-of-way which generally provide for perpetual use.

Storage assets

Distribution Operations We own and operate eight underground natural gas storage facilities in Illinois with a total inventory capacity of about 150 Bcf, approximately 135 Bcf of which can be cycled on an annual basis. The system is designed to meet about 50% of the estimated peak-day deliveries and approximately 40% of its normal winter deliveries in Illinois. This level of storage capability provides us with supply flexibility, improves the reliability of deliveries and can mitigate the risk associated with seasonal price movements.

We have approximately 7.57.6 Bcf of LNG storage capacity in five LNG plants located in Georgia, New Jersey and Tennessee. In addition, we own twoone propane storage facilitiesfacility in Virginia that havewith a combined storage capacity of approximately 0.50.3 Bcf. The LNG plants and propane storage facilitiesfacility are used by our distribution operations segment to supplement natural gas supply during peak usage periods.

Midstream Operations We currently own twothree high-deliverability natural gas storage and hub facilities which are operated by our energy investmentsmidstream operations segment. Our wholly-owned subsidiary, Jefferson Island is locatedoperates a salt-dome storage facility in Louisiana and containscurrently consisting of two salt dome gas storage caverns with approximately 10 Bcf of total capacity and about 87.3 Bcf of working gas capacity. Our wholly-owned subsidiary, Golden Triangle Storage, is locatedoperates a salt-dome storage facility in Texas and is designed for 1213.5 Bcf of working natural gas capacity and total cavern capacity of 18approximately 20 Bcf. The first cavernCavern 1, with 6 Bcf of working capacity, was completed and began commercial service in September 2010. The second cavernCavern 2, with an expected 67.5 Bcf of working capacity is expected to be, was completed and began commercial service in September 2012. Central Valley developed an underground natural gas storage facility in California with 11 Bcf of working natural gas capacity which was placed into commercial service in midJune 2012. Our energy investments segment also owns a pro pane storageIn addition to the LNG facilities that support utility operations, we have placed into commercial operations an LNG facility purchased from the Trussville Utilities District in Virginia with approximately 0.3 Bcf of storage capacity.Alabama. This facility supplements the natural gas supplyproduces LNG for Pivotal LNG, a wholly owned subsidiary, to our Virginia utility during peak usage periods.support its business of selling LNG as a substitute fuel in various market segments.

Vessels and shipping containers

Our cargo shipping segment regularly operates 11 owned vessels and 3 chartered vessels with a container capacity totaling approximately 6,750 TEUs. The owned vessels range in age from 3 - 37 years, and vary in length from 260 - 525 feet. In addition to the vessels, we own and/or lease containers, cargo-handling equipment, chassis and other equipment.

During the fourth quarter of 2013, we sold one of our vessels at approximately carrying value and replaced it with a chartered vessel that provides greater capacity and operational flexibility.

Offices

All of our segments own or lease office, warehouse and other facilities throughout our operating areas. We expect additional or substitute space to be available as needed to accommodate the expansion of our operations.operations.

ITEM 3.3. LEGAL PROCEEDINGS

The nature of our business ordinarily results in periodic regulatory proceedings before various state and federal authorities. In addition, we are party, as both plaintiff and defendant, to a number of lawsuits related to our business on an ongoing basis. Management believes that the outcome of all regulatory proceedings and litigation in which we are currently involved will not have a material adverse effect on our consolidated financial condition or results of operations.

In the third quarter of 2013, we commenced an investigation into payments to local officials and related persons at one of the foreign ports serviced by Tropical Shipping. While the investigation is ongoing, we believe that a number of payments were made over a series of years and the aggregate amount of these payments is less than $200,000 based upon information obtained to date. In October 2013, we voluntarily disclosed these matters to the U.S. Department of Justice (DOJ) and the SEC. We have been named as a defendant in several class action lawsuits broughtwill cooperate with any investigation by purported Nicor shareholders challenging Nicor’s proposed merger with us. The complaints allege that we aided and abetted alleged breachesthe DOJ or the SEC. We presently are unable to predict the duration, scope or result of fiduciary duty by Nicor’s Boardthis investigation or of Directors. The shareholder actions seek, among other things, declaratory and injunctive relief, including orders enjoining the defendants from completing the proposed merger and, in certain circumstances, damages. We believe the claims asserted in each lawsuit to be without merit and intend to vigorously defend against them.
any governmental investigation.

For more information regarding some of theseour regulatory proceedings and litigation, see Note 1011 to our consolidated financial statements under the caption “Litigation.”“Litigation” under Item 8 herein.

Glossary of Key TermsITEM 4. MINE SAFETY DISCLOSURES

25Not applicable.



MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Holders of Common Stock, Stock Price and Dividend Information

Our common stock is listed on the New York Stock Exchange under the ticker symbol AGL.GAS. At February 7, 2011,January 30, 2014, there were 9,27720,598 record holders of our common stock. Quarterly information concerning our high and low stock prices and cash dividends paid in 20102013 and 20092012 is as follows:

  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, 2010 $38.83  $34.26  $0.44 March 31, 2009 $34.93  $24.02  $0.43 
June 30, 2010  40.08   34.72   0.44 June 30, 2009  32.38   26.00   0.43 
September 30, 2010  40.00   35.29   0.44 September 30, 2009  35.79   30.05   0.43 
December 31, 2010  39.66   34.21   0.44 December 31, 2009  37.52   33.50   0.43 
          $1.76           $1.72 
  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 
(1)  As a result of the Nicor merger, our shareholders received a pro rata dividend of $0.0989 in the fourth quarter of 2011, which reduced the first quarter 2012 dividend by an equal amount. For presentation purposes the amount in the table was rounded to $0.10.

We have historically paid 264 consecutive quarterly dividends to our common shareholders beginning in 1948, historically four times aeach year: March 1, June 1, September 1 and December 1. We have paid 252 consecutive quarterly dividends beginning in 1948. Our common shareholders may receive dividends when declared at the discretion of our Board of Directors. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Cash Flow from Financing Activities - Dividends on Common Stock.” 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, some of which are noted below. In certain cases, our ability to pay dividends to our common shareholders is limited by the following:

·  our ability to satisfy our obligations under certain financing agreements, including debt-to-capitalization covenants, and
·  our ability to satisfy our obligations to any future preferred shareholdersshareholders.

Under Georgia law, the payment of cash dividends to the holders of our common stock is limited to our legally available assets and subject to the prior payment of dividends on any outstanding shares of preferred stock. Our assets are not legally available for paying cash dividends if, after payment of the dividend:

·  we could not pay our debts as they become due in the usual course of business, or
·  our total assets would be less than our total liabilities plus, subject to some exceptions, any amounts necessary to satisfy (upon dissolution) the preferential rights of shareholders whose preferential rights are superior to those of the shareholders receiving the dividendsdividends.
Securities Authorized for Issuance Under Equity Compensation Plans

See Part III, Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” under the heading “Executive Compensation - Equity Compensation Plan Information.”

Issuer Purchases of Equity Securities

The following table sets forth information regardingThere were no purchases of our common stock by us andor any affiliated purchasers during the three months ended December 31, 2010. Stock repurchases may be made in the open market or in private transactions at times and in amounts that we deem appropriate. However, there is no guarantee as to the exact number of additional shares that may be repurchased, and we may terminate or limit the stock repurchase program at any time. We currently anticipate holding the repurchased shares as treasury shares.2013.

Period 
Total number of shares purchased (1) (2)
  Average price paid per common share  
Total number of shares purchased as part of publicly announced plans or programs (2)
  
Maximum number of shares that may yet be purchased under the publicly announced plans or programs (2)
 
October 2010  -  $-   -   4,825,251 
November 2010  5,000   27.41   -   4,825,251 
December 2010  63,750   35.77   63,750   4,761,501 
Total fourth quarter  68,750  $35.16   63,750     
(1)  On March 20, 2001, our Board of Directors approved the purchase of up to 600,000 shares of our common stock in the open market to be used for issuances under the Officer Incentive Plan (Officer Plan). We purchased 5,000 shares for such purposes in the fourth quarter of 2010. As of December 31, 2010, we had purchased a total 347,153 of the 600,000 shares authorized for purchase, leaving 252,847 shares available for purchase under this program.
(2)  On February 3, 2006, we announced that our Board of Directors had authorized a plan to repurchase up to a total of 8 million shares of our common stock, excluding the shares remaining available for purchase in connection with the Officer Plan as described in note (1) above, over a five-year period. This repurchase plan expired January 31, 2011. However, we may request that our Board of Directors extend this plan.
ITEM 6.6. SELECTED FINANCIAL DATA

Selected financial data about AGL Resources for the last five years is set forth in the table below. You should read the data in the table in conjunction with the consolidated financial statements and related notes set forth in Item 8, “Financial Statements and Supplementary Data.” Material changes from 2011 to 2012 are primarily due to the Nicor merger which closed on December 9, 2011.

Dollars and shares in millions, except per share amounts 2010  2009  2008  2007  2006  2013  
2012 (1)
  
2011 (1)
  2010  2009 
Income statement data                              
Operating revenues $2,373  $2,317  $2,800  $2,494  $2,621  $4,617  $3,922  $2,338  $2,373  $2,317 
Cost of gas  1,164   1,142   1,654   1,369   1,482 
Operating margin (1)
  1,209   1,175   1,146   1,125   1,139 
Operating expenses                                        
Operation and maintenance  503   497   472   451   473 
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  160   158   152   144   138   418   415   186   160   158 
Nicor merger expenses (2)
  -   20   57   6   - 
Taxes other than income taxes  46   44   44   41   40   193   165   57   46   44 
Total operating expenses  709   699   668   636   651   3,942   3,312   1,898   1,873   1,841 
Gain on sale of Compass Energy  11   -   -   -   - 
Operating income  500   476   478   489   488   686   610   440   500   476 
Other (expense) income  (1)  9   6   4   (1)
Earnings before interest and taxes (EBIT) (1)
  499   485   484   493   487 
Other income (expense)  17   24   7   (1)  9 
EBIT  703   634   447   499   485 
Interest expenses  109   101   115   125   123   181   184   136   109   101 
Earnings before income taxes  390   384   369   368   364   522   450   311   390   384 
Income taxes  140   135   132   127   129   191   164   125   140   135 
Net income  250   249   237   241   235   331   286   186   250   249 
Less net income attributable to the noncontrolling interest  16   27   20   30   23   18   15   14   16   27 
Net income attributable to AGL Resources Inc. $234  $222  $217  $211  $212  $313  $271  $172  $234  $222 
Common stock data                                        
Weighted average common shares outstanding basic  77.4   76.8   76.3   77.1   77.6 
Weighted average common shares outstanding diluted  77.8   77.1   76.6   77.4   78.0 
Total shares outstanding (2)
  78.1   77.5   76.9   76.4   77.7 
Basic earnings per common share attributable to AGL Resources Inc. common shareholders $3.02  $2.89  $2.85  $2.74  $2.73 
Diluted earnings per common share – attributable to AGL Resources Inc. common shareholders $3.00  $2.88  $2.84  $2.72  $2.72 
Dividends declared per common share $1.76  $1.72  $1.68  $1.64  $1.48 
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  58%  60%  59%  60%  54%  71%  75%  89%  58%  60%
Dividend yield (3)
  4.9%  4.7%  5.4%  4.4%  3.8%
Dividend yield (4)
  4.0%  4.4%  4.5%  4.9%  4.7%
Price range:                                        
High $40.08  $37.52  $39.13  $44.67  $40.09  $49.31  $42.88  $43.69  $40.08  $37.52 
Low $34.21  $24.02  $24.02  $35.24  $34.40  $38.86  $36.59  $34.08  $34.21  $24.02 
Close (2)
 $35.85  $36.47  $31.35  $37.64  $38.91 
Market value (2)
 $2,800  $2,826  $2,411  $2,876  $3,023 
Statements of Financial Position data (2)
                    
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 $7,518  $7,074  $6,710  $6,258  $6,123  $14,656  $14,141  $13,913  $7,520  $7,079 
Property, plant and equipment – net  4,405   4,146   3,816   3,566   3,436 
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  2,706   2,576   2,541   2,255   2,161   4,984   4,930   4,899   2,704   2,576 
Total equity  1,836   1,819   1,684   1,708   1,651   3,676   3,435   3,339   1,836   1,819 
Cash flow data                    
Net cash flow provided by operating activities $526  $592  $227  $377  $351 
Net cash flow used in investing activities  (442)  (476)  (372)  (253)  (248)
Net cash flow (used in) provided by financing activities  (86)  (106)  142   (122)  (118)
Net borrowings and (payments) of short-term debt  131   (264)  286   52   6 
Financial ratios (2)
                    
Financial ratios (5)
                    
Debt  60%  59%  60%  57%  57%  58%  59%  59%  60%  59%
Equity  40%  41%  40%  43%  43%  42%  41%  41%  40%  41%
Total  100%  100%  100%  100%  100%  100%  100%  100%  100%  100%
Return on average equity  12.8%  12.7%  12.8%  12.6%  13.3%  8.8%  8.0%  6.6%  12.8%  12.7%
(1)  TheseMaterial changes from 2011 to 2012 are non-GAAP measurements. A reconciliation of operating marginprimarily due to operating income and EBIT to earnings before income taxes and net income is contained in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - AGL Resources-Results of Operations.”the Nicor merger on December 9, 2011.
(2)Transaction expenses associated with the Nicor merger were excluded from operation and maintenance expenses and presented separately.
(3)  As a result of the Nicor merger, AGL Resources shareholders of record as of the close of business on December 8, 2011 received a pro rata dividend of $0.0989 for the stub period, which accrued from November 19, 2011. This amount was rounded to $0.10 in the table.
(4)  
Dividends declared per common share during the fiscal period divided by market value per common share as of the last day of the fiscal period.
(5)  As of the last day of the fiscal period.
(3)  Dividends declared per common share divided by market value per common share.



ITEM 7.7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OverviewExecutive Summary

Our distribution operations segmentWe are an energy services holding company whose principal business is the largest component of our business and is subject to regulation and oversight by agencies in each of the six states we serve. These agencies approve natural gas rates designed to provide us the opportunity to generate revenues to recover the costdistribution of natural gas delivered toin seven states - Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee and Maryland - through our customers and our fixed and variable costs such as depreciation, interest, maintenance and overhead costs, and to earn a reasonable return for our shareholders. With the exception of Atlanta Gas Light, our largest utility, the earnings of our regulated utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels forseven natural gas distribution utilities. We are also involved in several other businesses, some of which are complementary to the distribution of natural gas along with other unregulated businesses. Our operating segments consist of the following five operating and general economic conditions that may impactreporting segments – distribution operations, retail operations, wholesale services, midstream operations and cargo shipping and one non-operating segment - other. These segments are consistent with how management views and operates our customers’ ability to pay for gas consumed. Various mechanisms exist that limitbusiness. The following table provides certain information on our exp osure to weather changes within specified ranges in all of our jurisdictions.segments.

Our retail energy operations segment, which consists
  EBIT  Assets  Capital Expenditures 
  2013  2012  2011  2013  2012  2011  2013  2012  2011 
Distribution operations  83%  84%  92%  80%  80%  79%  91%  83%  85%
Retail operations  19   18   21   5   4   4   1   1   1 
Wholesale services  (1)  -   1   8   9   9   -   -   - 
Midstream operations  (1)  2   2   5   5   5   2   8   8 
Cargo shipping  2   1   -   3   3   3   2   1   - 
Other  (2)  (5)  (16)  (1)  (1)  -   4   7   6 
Total  100%  100%  100%  100%  100%  100%  100%  100%  100%

In 2013, our net income attributable to AGL Resources Inc. was $313 million an increase of SouthStar, also is$42 million compared to 2012 as we benefited from colder-than-normal weather sensitive and uses a variety of hedging strategies, such as compared to the historically warm weather derivative instruments and other risk management tools, to mitigate potentialin 2012. Excluding weather, impacts.
Sequent,we achieved growth in our wholly-owned subsidiary within our wholesale services segment is temperature insensitive, but generally has greater opportunity to capture operating margin due to price volatilitymargins during 2013 primarily as a result of extreme weather. Our energy investments segment’s primarycontributions from our regulatory infrastructure programs in distribution operations, targeted acquisition growth in retail operations and significant improvement in commercial activity isin our natural gas storage business, which develops, acquireswholesale services, as well as the gain on the sale of Compass Energy, offset by mark-to-market accounting hedge losses recorded during the second half of 2013. These losses are temporary and operates high-deliverability salt-dome storage assetsexpected to be recovered primarily in 2014.

In 2014, our priorities are consistent with the Gulf Coast region ofdirection we have taken the United States. While this business also can generate additional revenue during times of peak market demand for natural gas storage services,Company over the majoritylast three years. We will remain focused on efficient operations across all of our storage servicesbusinesses, including offsetting inflationary pressures by aggressive cost controls, spreading costs across a broader customer base and sizing our operations to properly reflect market challenges. Several of our specific business objectives are covered under mediumdetailed as follows:

·  
Distribution Operations: Invest necessary capital to enhance and maintain safety and reliability; remain a low-cost leader within the industry; opportunistically expand the system and capitalize on potential customer conversions. We intend to continue investing in our regulatory infrastructure programs in Georgia, Virginia, New Jersey and Tennessee to minimize regulatory lag and the recovery cycle. During 2014 we intend to submit a regulatory infrastructure program in Illinois, to become effective in January 2015. We continue to effectively manage costs and leverage our shared services model across our businesses to largely overcome inflationary effects.
·  
Retail Operations: Maintain operating margins in Georgia and Illinois while continuing to expand into other profitable retail markets; integrate our warranty businesses and expand our overall market reach through partnership opportunities with our affiliates. We expect the Georgia retail market to remain highly competitive; however, our operating margins are forecasted to remain stable with modest growth from the acquisitions completed in 2013 and expansion into new markets.
·  
Wholesale Services: Maximize strong storage and transportation rollout value created in 2013; effectively perform on existing asset management agreements and expand customer base; and maintain cost structure in line with market fundamentals. We anticipate low volatility in certain areas of our portfolio; however, volatility is expected to increase in the supply-constrained Northeast corridor. We further anticipate narrow seasonal storage spreads will continue to be challenges in 2014.
·  
Midstream Operations: Optimize storage portfolio, including expiring contracts, pursue LNG transportation opportunities and lower development expenses.
·  
Cargo Shipping: Improve profitability, continue increasing vessel utilization, improve margin per TEU, prudently deploy capital investment and diligently manage operating costs.

Additionally, we will maintain our strong balance sheet and liquidity profile, solid investment grade ratings and our commitment to long-term contracts at a fixed market rate. sustainable annual dividend growth. For moreadditional information on our operating segments, see Note 13 to our consolidated financial statements under Item 8 herein and Item 1, “Business”.


We generate the majority of our operating revenues through the sale, distribution and storage of natural gas. We include in our consolidated revenues an estimate of revenues from natural gas distributed, but not yet billed, to residentialProposed merger with Nicor ,In December 2010, we entered into commercial and industrial customers from the date of the last bill to the end of the reporting period. No individual customer or industry accounts for a Merger Agreement with Nicor, which we expect to complete insignificant portion of our revenues. The following table provides more information regarding the second halfcomponents of 2011. The proposed merger will create a combined company with increased scale and scope in both regulated utility and non-regulated businesses as indicated below:our operating revenues.

·  Seven regulated natural gas distribution companies providing natural gas services to approximately 4.5 million customers in Illinois, Georgia, New Jersey, Virginia, Florida, Tennessee and Maryland
In millions 2013  2012  
2011 (1)
 
Residential $2,422  $2,011  $1,065 
Commercial  696   656   467 
Transportation  532   492   403 
Shipping  365   342   19 
Industrial  180   262   289 
Other  422   159   95 
Total operating revenues $4,617  $3,922  $2,338 
·(1)  Over 1 million retail customers inOur results of operations for the unregulated businessesyear ended December 31, 2011 includes 22 days of activity from the subsidiaries acquired from Nicor.
·  Physical wholesale gas business delivering approximately 4.7 Bcf of natural gas per day
·  Natural gas storage facilities that will provide approximately 31 Bcf of storage in 2012

Completion of the proposed merger is conditioned upon, among other things, shareholder approval by both companies, expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, and approval by, among others, the Illinois Commerce Commission. We anticipate that the necessary approvals will be obtained.

In January 2011, we filed a joint application with Nicor to the Illinois Commerce Commission for approval of the proposed merger. As stated above, approval by the Illinois Commerce Commission is a condition to completion of the merger. The application did not request a rate increase and included a commitment to maintain the number of full-time equivalent employees involved in the operation of Nicor’s gas distribution subsidiary at a level comparable to current staffing for a period of three years following merger completion. The Illinois Commerce Commission has eleven months to act upon the application; however, we and Nicor have asked for approval of the merger by October 1, 2011 .

The Merger Agreement contains certain termination rights for both us and Nicor, and further provides for the payment of fees and expenses upon termination under specified circumstances. For additional information relating to the proposed merger please see our Form 8-K filed on December 7, 2010. Further information concerning the proposed merger was included in a joint proxy statement/prospectus contained in the registration statement on Form S-4 that was filed with the SEC on February 4, 2011.

Legislative and regulatory update We continue to actively pursue a regulatory strategy that improves customer service and reduces the lag between our investments in infrastructure and the recovery of those investments through various rate mechanisms. If our rate design approvals are not approved, we will continue to work cooperatively with our regulators, legislators and others to create a framework that is conducive to our business goals and the interests of our customers and shareholders.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was enacted in July 2010, representing an overhaul of the framework for regulation of United States financial markets. We are currently evaluating the provisions of the Dodd-Frank Act and the potential impact that it may have on us.

However,We evaluate segment performance using the measures of EBIT and operating margin. EBIT includes operating income and other income and expenses. Items that we believedo not include in EBIT are financing costs, including interest expense and income taxes, each of which we evaluate on a consolidated basis. Operating margin is a non-GAAP measure that an aspectis calculated as operating revenues minus cost of the Dodd-Frank Act which requires that various regulatory agencies, including the SECgoods sold and revenue tax expense in distribution operations. Operating margin excludes operation and maintenance expense, depreciation and amortization, taxes other than income taxes, and the Commodities Futures Trading Commission, establish additional regulations for participating in financial markets for hedging certain risks inherentgain or loss on the sale of our assets. These items are included in our business, including commodity and interest rate risks, may be applicable to us. As a result, the costscalculation of participatingoperating income as reflected in financial markets for hedging certain risks may be increased as a resultour Consolidated Statements of the new legislation. We may also incur additional costs associated with our compliance with new regulations and anticipated additional reporting and disclosure obligations. For additional information on our regulatory strategy see Item 1, ̶ 0;Business” under the caption “Regulatory Planning”.Income.

CustomerWe believe operating margin is a better indicator than operating revenues for the contribution resulting from customer growth initiatives Relative to recent years, we continue to see higher than normal rates of unemployment, depressed housing markets with high inventories, significantly reduced new home construction and a slow-down in new commercial development. As a result, we experienced slight customer losses in our distribution operations segment since the cost of goods sold and revenue tax expenses can vary significantly and are generally billed directly to our customers. We also consider operating margin to be a better indicator in our retail energy operations, wholesale services, midstream operations and cargo shipping segments throughout 2010. We have largely offset this trend by implementing customer attrition mitigation strategiessince it is a direct measure of operating margin before overhead costs. You should not consider operating margin an alternative to, retain existing customers at allor a more meaningful indicator of, our utilities.operating performance than operating income, or net income attributable to AGL Resources Inc. as determined in accordance with GAAP. In addition, operating margin may not be comparable to similarly titled measures of other companies.

We expectalso believe presenting the non-GAAP measurements of basic and diluted earnings per share - as adjusted, which excludes Nicor merger-related expenses and the additional accrual for the Nicor Gas PBR issue, provides investors with an additional measure of our performance. Adjusted basic and diluted earnings per share should not be considered an alternative to, or a similar environmentmore meaningful indicator of our operating performance than our GAAP basic and diluted earnings per share. The following table reconciles operating revenue and operating margin to prevail throughoutoperating income and EBIT to earnings before income taxes and net income and our GAAP basic and diluted earnings per common share to our non-GAAP basic and diluted earnings per share – as adjusted, together with other consolidated financial information for the last three years.

In millions, except per share amounts    2013  2012  2011 
Operating revenues $4,617  $3,922  $2,338 
Cost of goods sold  (2,332)  (1,791)  (1,097)
Revenue tax expense (1)
  (110)  (85)  (9)
Operating margin  2,175   2,046   1,232 
Operating expenses (2) (3)
  (1,610)  (1,501)  (744)
Revenue tax expense (1)
  110   85   9 
Gain on sale of Compass Energy  11   -   - 
Nicor merger expenses (2)
  -   (20)  (57)
Operating income  686   610   440 
Other income  17   24   7 
EBIT  703   634   447 
Interest expenses  (181)  (184)  (136)
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            
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders (4)
 $2.64  $2.31  $2.12 
Additional accrual for Nicor Gas PBR issue  -   0.04   - 
Transaction costs of Nicor merger (2)
  -   0.11   0.80 
Diluted earnings per share - as adjusted $2.64  $2.46  $2.92 
(1)  Adjusted for Nicor Gas’ revenue tax expenses, which are passed directly through to customers.
(2)  Operating expenses associated with the merger with Nicor are shown separately to better compare year-over-year results and include $20 million ($13 million net of tax) in 2012 and $57 million ($48 million net of tax) in 2011. Additionally, in 2011, transaction costs of the Nicor merger include debt issuance costs and interest expense on pre-funding the cash portion of the purchase consideration of $25 million ($16 million net of taxes).
(3)  Total operating expenses in 2013 were unfavorably impacted by increased incentive compensation accruals of $37 million compared to the prior year. These amounts were above targeted levels in 2013.
(4)  Sale of Compass Energy increased basic and diluted EPS by $0.04 in 2013.

In 2013 our net income attributable to AGL Resources Inc. increased by $42 million or 15% compared to last year.

·  The overall increase was primarily the result of increased operating margin at distribution operations and retail operations due to weather that was both colder-than-normal and colder than the same period last year, increased regulatory infrastructure program revenues at Atlanta Gas Light, the acquisition of service contracts and residential and commercial energy customer relationships in our retail operations segment, as well as lower depreciation expense at Nicor Gas.
·  
The increase was unfavorably impacted by mark-to-market accounting hedge losses in our wholesale services segment during the second half of 2013, offset by higher commercial activity and the $11 million pre-tax gain on the sale of Compass Energy.
·  Our midstream operations segment was unfavorable compared to 2012 due to the $8 million loss associated with the termination of the Sawgrass Storage project, as well as lower contracted firm rates at Jefferson Island and higher operating expenses at Golden Triangle, Central Valley and Pivotal LNG resulting from full year operations in 2013 as compared to partial year operations in 2012.
·  Our cargo shipping segment added to the favorable variance due primarily to higher volumes, partially offset by decreased average TEU rates.
·  Favorability year-over-year also was partially offset by higher incentive compensation expenses in most of our businesses as our incentive compensation expense was above targeted levels in 2013 based on improved financial and operational performance compared to significantly below targeted annual levels in 2012 due to below target performance. In addition, our bad debt expense increased at distribution operations and retail operations primarily as a result of colder weather combined with natural gas prices that were higher than in the same period of the prior year.
·  In 2012 we recorded $20 million ($13 million net of tax) of Nicor merger related expenses.
·  In 2013 our interest expense decreased by $3 million compared to 2012. This decrease was the result of overall lower interest rates mostly offset by higher average debt outstanding primarily as a result of issuing $500 million of senior notes in place of variable-rate debt.
·  In 2013 our income tax expense increased by $27 million or 16% compared to 2012 primarily due to higher consolidated earnings, as previously discussed. Our effective tax rate was 38.0% in 2013 and 37.7% in 2012. Our estimated effective tax rate for 2014 is 37.9%.

In 2012 our net income attributable to AGL Resources Inc. increased by $99 million or 58% compared to 2011.
·  The increase was primarily the result of increased operating income at distribution operations, retail operations and cargo shipping as a result of the Nicor merger, and increased regulatory infrastructure program revenues at Atlanta Gas Light.
·  This increase was partially offset by the effect of warmer-than-normal weather in our distribution operations and retail operations segments, and significantly lower margins at wholesale services resulting from mark-to-market accounting hedge losses.
·  In 2011 we recorded $57 million ($48 million net of tax) of Nicor merger related expenses.
·  In 2012 our interest expense increased by $48 million or 35% compared to 2011. This increase was the result of higher average debt outstanding primarily as a result of the additional long-term debt issued to fund the Nicor merger and the long-term debt assumed in the transaction.
·  In 2012 our income tax expense increased by $39 million or 31% compared to the same period in 2011 primarily due to higher consolidated earnings. Our effective tax rate was 42.2% in 2011 primarily due to the non-deductible merger transaction expenses in 2011.

The variances for each operating segment are contained within the year-over-year discussion on the following pages.


Weather We measure the effects of weather on our business through Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for gas on our distribution systems. With the exception of Nicor Gas and Florida City Gas, we have various regulatory mechanisms, such as weather normalization mechanisms, which limit our exposure to weather changes within typical ranges in each of our utilities’ respective service areas. However, our utility customers in Illinois and retail operations’ customers in Georgia can be impacted by warmer or colder than normal weather. We have presented the Heating Degree Day information for those locations in the following table.

   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)%
(1)  Normal represents the ten-year average from January 1, 2003 through December 31, 2012, for Illinois at Chicago Midway International Airport, and for Georgia at Atlanta Hartsfield-Jackson International Airport as obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center.
(2)  
The 10-year average Heating Degree Days established by the Illinois Commission in our last rate case, is 2,020 for the fourth quarter and 5,600 for the 12 months from 1998 through 2007.

During 2013 we experienced weather in Illinois that was 10% colder-than-normal and 30% colder than the same period in the prior year. Georgia also experienced 3% colder-than-normal weather, and 39% colder than the same period last year. 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 January through April of 2014, we have purchased a put option that would partially offset lower operating margins resulting from reduced 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.

Customers Our customer metrics highlight the average number of customers for which we provide services and are provided in the table below. The number of customers at distribution operations and energy customers at retail operations can be impacted by natural gas prices, economic conditions and competition from alternative fuels. Our energy customers at retail operations are primarily located in Georgia and Illinois.

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)%
(1)  A portion of the energy customers represents customer equivalents in Ohio, which are computed by the actual delivered volumes divided by the expected average customer usage. The decrease for the year ended 2012 is primarily due to our contract to serve approximately 50,000 customer equivalents that ended on April 1, 2012, which was partially offset by the increase due to the addition of approximately 33,000 residential and commercial customer relationships acquired in Illinois in June 2013.
(2)  Increase primarily due to acquisition of approximately 500,000 service contracts on January 31, 2013.

We anticipate overall utility customer growth trends for 2013 to continue in 2014 based on an expectation of continuing improvement in the economy and the continuing low natural gas prices. We use a variety of targeted marketing programs to attract new customers and to retain existing customers. These efforts include working to addadding residential customers, multifamily complexes and commercial and industrial customers who use natural gas for purposes other than space heating, as well as evaluating and launching new natural gas related programs, products and services to enhance customer growth, mitigate customer attrition and increase operating revenues. These programs generally emphasize natural gas as the fuel of choice for customers and seek to expand the use of natural gas through a variety of promotional activities.

Natural gas price volatility The volatility of We also target customer conversions to natural gas commodity prices have a significant impact on our customer rates, our long-term competitive position againstfrom other energy sources andemphasizing the ability of our wholesale services segment to capture value from location and seasonal spreads. During 2008 and 2009, daily Henry Hub spot market prices for natural gas in the United States were extremely volatile. However, during 2010, the volatilitypricing advantage of natural gas prices was lower than itgas. These programs focus on premises that could be connected to our distribution system at little or no cost to the customer. In cases where conversion cost can be a disincentive, we may employ rebate programs and other assistance to address customer cost issues.

Retail operations’ market share in Georgia has been for the last few yearsdecreased slightly primarily as a result of a robust natural gas supply,highly competitive marketing environment, which we expect will continue for the weak economyforeseeable future. In 2013 our retail operations segment expanded its energy customers and ample storage.its service contracts through acquisitions and entering into new markets. We anticipate this expansion will provide growth opportunities in future years.

Volume Our natural gas acquisition strategy is designed to secure sufficient suppliesvolume metrics for distribution operations and retail operations, present the effects of weather and customers’ demand for natural gas compared to meetprior year. Wholesale services’ daily physical sales volumes represent the needs of our utility cus tomers and to hedge gas prices to effectively manage costs, reduce price volatility and maintain a competitive advantage. Additionally, our hedging strategies and physicaldaily average natural gas supplies in storage enable usvolumes sold to reduce earnings risk exposure due to higher gas costs.

It is possible thatits customers. Within our midstream operations segment, our natural gas prices will remain low for an extended period based onstorage businesses seek to have a significant percentage of their working natural gas capacity under firm subscription, but also take into account current levelsand expected market conditions. This allows our natural gas storage business to generate additional revenue during times of excess supply relative topeak market demand for natural gas storage services, but retain some consistency with their earnings and maximize the value of the investments. Additionally, our cargo shipping segment measures the volume of shipments during the period in part due to abundant sourcesTEUs. In 2013 we successfully increased our number of new shale natural gas reservesTEUs and therefore the lackutilization of demand by commercialour containers and industrial enterprises. However, as economic conditions improvevessels. Our volume metrics are presented in the demand for natural gas may increase, natural gas prices could rise and higher volatility could return to the natural gas markets.following table:

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%        
(1)  Includes Florida, Maryland, New York and Ohio.
(2)  The percentage of capacity under subscription does not include 3.5 Bcf of capacity under contract with Sequent at December 31, 2013, 3 Bcf of capacity under contract with Sequent at December 31, 2012 and 4 Bcf of capacity under contract with Sequent at December 31, 2011.

Capital market plan Segment informationOur capital market plan Operating margin, operating expenses and EBIT information for each of our segments are contained in the following tables for the remainder of 2011 includes successfully completing offerings of approximately $1 billion in long-term debt and $1.4 billion in common stock to finance the proposed Nicor merger and maintaining our solid investment-grade credit ratings.last three years.

For additional information on our Credit Facility and our capital market plan see “Liquidity and Capital Resources” under the caption “Cash Flow from Financing Activities” and “Short-term Debt”. See also Note 7 to our consolidated financial statements.
  
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 
(1)  
Operating margin is a non-GAAP measure. A reconciliation of operating revenue and operating margin to operating income and EBIT to earnings before income taxes and net income is contained in “Results of Operations.” See Note 13 to our consolidated financial statements under Item 8 herein for additional segment information.
(2)  Operating margin and expense are adjusted for revenue tax expense for Nicor Gas, which is passed directly through to customers.
(3)  Includes $20 million and $57 million in Nicor merger transaction expenses for 2012 and 2011, respectively, and an $8 million accrual in 2012 for the Nicor Gas PBR issue.
(4)  The 2011 amounts only include 22 days of Nicor activity from December 10, 2011 through December 31, 2011.
(5)  EBIT for 2013 includes $11 million pre-tax gain on sale of Compass Energy in our wholesale services segment and an $8 million pre-tax loss associated with the termination of the Sawgrass Storage project within our midstream operations segment.

Hedges Changes in commodity prices subject a significant portion of our operations to earnings variability. Our non-utility businesses principally use physical and financial arrangements to reduce the risks associated with both weather-related seasonal fluctuations in market conditions and changing commodity prices. These economic hedges may not qualify, or are not designated for, hedge accounting treatment. As a result, our reported earnings for the wholesale services and retail energy operations segments reflect changes in the fair values of certain derivatives. These values may change significantly from period to period and are reflected as gains or losses within our operating revenues or our OCI for those derivative instruments that qualify and are designated as accounting hedges .

Seasonality The operating revenues and EBIT of our distribution operations, retail energy operations, wholesale services and wholesale servicescargo shipping segments are seasonal. During the Heating Season, natural gas usage and operating revenues are generally higher because more customers are connected to our distribution systems and natural gas usage is higher in periods of colder weather.weather. Occasionally in the summer, Sequent’swholesale services operating revenues are impacted due to peak usage by power generators in response to summer energy demands. Seasonality also affects the comparison of certain statementsConsolidated Statements of financial positionFinancial Position items such asacross quarters, including receivables, unbilled revenue, inventories and short-term debt across quarters.debt. However, these items are comparable when reviewing our annual results.

our cargo shipping business are generally higher in the fourth quarter, as our customers require more tourist-related shipments as the hotels, resorts, and cruise ships typically have increased occupancy rates commencing in the fourth quarter and increasing further into the first quarter as consumer spending increases during traditional holiday periods. Revenues are impacted during the fourth quarter by peak season surcharges in effect from early October through December.
29


Approximately 70%66% of these segments’ operating revenues and 78%69% of these segments’ EBIT for the year ended December 31, 20102013 were generated during the first and fourth quarters of 2010,2013, and are reflected in our Consolidated Statements of Income for the quarters ended March 31, 20102013 and December 31, 2010.2013. Our base operating expenses, excluding cost of gas,goods sold, interest expense and certain incentive compensation costs, are incurred relatively equally over any given year. Thus, our operating results can vary significantly from quarter to quarter as a result of seasonality.


We generate nearly all our operating revenues through the sale, distribution and storage of natural gas. We include in our consolidated revenues an estimate of revenues from natural gas distributed, but not yet billed, to residential and commercial customers from the latest meter reading date to the end of the reporting period. No individual customer or industry accounts for a significant portion of our revenues. The following table provides more information regarding the components of our operating revenues.

In millions 2010  2009  2008 
Residential $1,083  $1,091  $1,194 
Commercial  521   467   598 
Transportation  404   378   459 
Industrial  205   185   322 
Other  160   196   227 
Total operating revenues $2,373  $2,317  $2,800 

We evaluate segment performance using the measures of operating margin and EBIT, which include the effects of corporate expense allocations. Operating margin is a non-GAAP measure that is calculated as operating revenues minus cost of gas, which excludes operation and maintenance expense, depreciation and amortization, taxes other than income taxes, and the gain or loss on the sale of our assets. These items are included in our calculation of operating income as reflected in our Consolidated Statements of Income. EBIT is also a non-GAAP measure that includes operating income, other income and expenses. Items that we do not include in EBIT are financing costs, including interest and debt expense and income taxes, each of which we evaluate on a consolidated basis.

We believe operating margin is a better indicator than operating revenues for the contribution resulting from customer growth in our distribution operations segment since the cost of gas can vary significantly and is generally billed directly to our customers. We also consider operating margin to be a better indicator in our retail energy operations, wholesale services and energy investments segments since it is a direct measure of operating margin before overhead costs.

We believe EBIT is a useful measurement of our operating segments’ performance because it provides information that can be used to evaluate the effectiveness of our businesses from an operational perspective, exclusive of the costs to finance those activities and exclusive of income taxes, neither of which is directly relevant to the efficiency of those operations. You should not consider operating margin or EBIT an alternative to, or a more meaningful indicator of, our operating performance than operating income, or net income attributable to AGL Resources Inc. as determined in accordance with GAAP. In addition, our operating margin and EBIT measures may not be comparable to similarly titled measures of other companies.

The following table reconciles operating margin to operating income and EBIT to earnings before income taxes and net income, together with other consolidated financial information for the last three years.

In millions 2010  2009  2008 
Operating revenues $2,373  $2,317  $2,800 
Cost of gas  1,164   1,142   1,654 
Operating margin  1,209   1,175   1,146 
Operating expenses  709   699   668 
Operating income  500   476   478 
Other (expense) income  (1)  9   6 
EBIT  499   485   484 
Interest expenses  109   101   115 
Earnings before income taxes  390   384   369 
Income tax expenses  140   135   132 
Net income  250   249   237 
Less net income attributable to the noncontrolling interest  16   27   20 
Net income attributable to AGL Resources Inc. $234  $222  $217 

In 2010, our net income attributable to AGL Resources Inc. increased by $12 million from the prior year primarily due to increased EBIT at distribution operations largely due to new rates at Atlanta Gas Light and Elizabethtown Gas as well as the completion of the Hampton Roads and Magnolia pipeline projects. The increase in our net income attributable to AGL Resources Inc. was also favorably impacted by increased EBIT at wholesale services and our additional 15% ownership interest in SouthStar, which was effective January 1, 2010. This was partly offset by increased interest expense and decreased EBIT at retail energy operations, energy investments and corporate. The decrease in EBIT at retail energy operations was mainly due to increased operating expenses. The decrease in EBIT at energy investments was the result of decreased operating margins mainly due to the sale of AGL Networks. The decrease in EBIT at corporate was mainly due to approximately $6 million of outside services expenses associated with non-recurring transaction costs associated with the proposed merger with Nicor.

In 2009, our net income attributable to AGL Resources Inc. increased by $5 million from the prior year primarily due to decreased interest expense and increased EBIT from retail energy operations largely due to higher operating margin. This was partly offset by decreased EBIT at distribution operations, wholesale services and energy investments. The decrease in EBIT at distribution operations was primarily due to increased operating expenses offset by increased operating margin. The decrease in EBIT at wholesale services and energy investments was the result of decreased operating margins and increased operating expenses.

The following table provides each operating segment’s percentage contribution to the total EBIT for our operating segments for the last three years.
  2010  2009  2008 
Distribution operations  69%  67% $68%
Retail energy operations  20   21   16 
Wholesale services  10   10    12 
Energy investments  1   2  $4 
Total EBIT  100%  100%  100%
Over the last three years, on average, we have derived 69% of our operating segments’ EBIT from our regulated natural gas distribution business whose rates are approved by state regulatory commissions. We derived our remaining operating segment’s EBIT for the last three years principally from businesses that are complementary to our natural gas distribution business. These businesses include the sale of natural gas to retail customers, natural gas asset management and the operation of high-deliverability natural gas underground storage as ancillary activities to our regulated utility franchises.

Interest expense Our interest expense over the last three years has fluctuated primarily due to short-term interest rate changes and higher average debt levels. The following table provides additional detail on interest expense for the last three years and the primary items that affect year-over-year change.

In millions 2010  2009  2008 
Interest expense $109  $101  $115 
Average debt outstanding (1)
 $2,393  $2,239  $2,156 
Average rate  4.6%  4.5%  5.3%
(1)  Daily average of all outstanding debt.

The difficult economic conditions of the past few years have resulted in low United States Treasury yields and corresponding indexes on short-term borrowings. These factors have favorably impacted our earnings in 2010, 2009 and 2008 through reduced short-term rates that we paid on our commercial paper borrowings. For more information on the impact that interest rate fluctuations have on our variable-rate debt, see “Interest Rate Risk” in Item 7A, “Quantitative and Qualitative Disclosures About Market Risk.”

Income tax expense Our income tax expense in 2010 increased by $5 million or 4% compared to 2009, and increased by $3 million or 2% in 2009 compared to 2008. These increases were primarily due to higher consolidated earnings. Our effective tax rate was 37.5% in 2010 and 37.8% in 2009 and 2008.

As a result of the authoritative guidance related to consolidations, income tax expense and our effective tax rate are determined from earnings before income taxes less net income attributable to the noncontrolling interest. For more information on our income taxes, including a reconciliation between the statutory federal income tax rate and the effective rate, see Note 11.

Operating metrics Selected weather, customer and volume metrics for 2010, 2009 and 2008, which we consider to be some of the key performance indicators for our operating segments, are presented in the following tables. We measure the effects of weather on our business through heating degree days. Generally, increased heating degree days result in greater demand for gas on our distribution systems. However, extended and unusually mild weather during the Heating Season can have a significant negative impact on demand for natural gas.

Our customer metrics highlight the average number of customers to which we provide services. This number of customers can be impacted by natural gas prices, economic conditions and competition from alternative fuels.

Volume metrics for distribution operations and retail energy operations present the effects of weather and our customers’ demand for natural gas. Wholesale services’ daily physical sales represent the daily average natural gas volumes sold to its customers. Within our energy investments segment, our natural gas storage businesses generally prefer to have approximately 95% of their working natural gas capacity under firm subscription. This allows our natural gas storage business to generate additional revenue during times of peak market demand for natural gas storage services, but retain consistency with their earnings.
Weather             2010 vs.  2009 vs.  2010 vs.    2009 vs.  2008 vs.  
Heating degree days (1)  Year ended December 31,  2009  2008  normal    normal  normal  
  Normal  2010  2009  2008  colder (warmer)  colder (warmer)  colder (warmer)    colder (warmer)  colder (warmer)  
Georgia  2,682   3,209   2,803   2,746   14%  2%  20%  5%  2% 
New Jersey  4,652   4,445   4,755   4,646   (7)%  2%  (4)%  2  -  
Virginia  3,203   3,601   3,312   3,031   9%  9%  12%  3%  (5)% 
Florida  573   1,108   548   416   102%  32%  93%  (4)%  (27)% 
Tennessee  3,085   3,594   3,154   3,179   14%  (1)%  16%  2%  3% 
Maryland  4,700   4,679   4,783   4,519   (2)%  6%  -   2  (4)% 
Ohio  4,899   5,181   4,919   5,155   5%  (5)%  6%  -   5% 
              2010 vs.  2009 vs.  2010 vs.    2009 vs.  2008 vs.  
   Quarter ended December 31,  2009  2008  normal    normal  normal  
  Normal  2010  2009  2008  colder (warmer)  colder (warmer)  colder (warmer)    colder (warmer)  colder (warmer)  
Georgia  1,030   1,187   1,182   1,092   -   8%  15%  15%  6% 
New Jersey  1,616   1,720   1,618   1,728   6%  (6)%  6%  -   7% 
Virginia  1,095   1,380   1,065   1,151   30%  (7)%  26%  (3)%  5% 
Florida  176   365   158   201   131%  (21)%  107%  (10)%  14% 
Tennessee  1,204   1,382   1,283   1,291   8%  (1)%  15%  7%  7% 
Maryland  1,665   1,822   1,665   1,691   9%  (2)%  9%  -   2% 
Ohio  1,826   2,028   1,893   1,914   7%  (1)%  11%  4%  5% 
          
Customers Year ended December 31,  2010 vs. 2009  2009 vs. 2008 
  2010  2009  2008  % change  % change 
Distribution Operations               
Average end-use customers (in thousands)
               
Atlanta Gas Light  1,544   1,549   1,557   (0.3)%  (0.5)%
Elizabethtown Gas  274   273   273   0.4   - 
Virginia Natural Gas  275   273   271   0.7   0.7 
Florida City Gas  103   103   104   -   (1.0)
Chattanooga Gas  62   62   62   -   - 
Elkton Gas  6   6   6   -   - 
Total  2,264   2,266   2,273   (0.1)%  (0.3)%
                     
Retail Energy Operations                    
Average customers (in thousands)
                    
Georgia  496   504   526   (2)%  (4)%
Ohio and Florida (2)
  77   103   122   (25)%  (16)%
Total  573   607   648   (6)%  (6)%
Market share in Georgia  33%  33%  34%  -   (3)%

Volumes
In billion cubic feet (Bcf)
 Year ended December 31,  2010 vs. 2009  2009 vs. 2008
  2010  2009  2008  % change  % change
Distribution Operations              
Firm  243   218   219   11%  - 
Interruptible  99   98   104   1%  (6)%
Total  342   316   323   8%  (2)%
                      
Retail Energy Operations                     
Georgia firm  46   40   41   15%  (2)%
Ohio and Florida  10   11   7   (9)%  57%
                      
Wholesale Services                     
Daily physical sales (Bcf / day)  4.57   2.96   2.60   54%  14%
                      
Energy Investments                     
Working natural gas capacity  13.5   7.5   7.5   80%  - 
% of capacity under subscription  66%  93%  93%  (29)%  - 
(1)  Obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center. Normal represents the ten-year averages from January 2000 to December 2010.
(2)  A portion of the Ohio customers represents customer equivalents, which are computed by the actual delivered volumes divided by the expected average customer usage.
Segment information Operating margin, operating expenses and EBIT information for each of our segments are contained in the following tables for the last three years.

In millions 
Operating margin (1)
  Operating expenses  
EBIT (1)
 
2010         
Distribution operations $882  $531  $355 
Retail energy operations  183   80   103 
Wholesale services  105   57   49 
Energy investments  39   32   4 
Corporate (2)  -   9   (12)
Consolidated $1,209  $709  $499 
 
2009
            
Distribution operations $836  $519  $326 
Retail energy operations  181   76   105 
Wholesale services  111   64   47 
Energy investments  46   33   12 
Corporate (2)  1   7   (5)
Consolidated $1,175  $699  $485 
2008            
Distribution operations $818  $493  $329 
Retail energy operations  149   73   77 
Wholesale services  122   62   60 
Energy investments  50   31   19 
Corporate (2)  7   9   (1)
Consolidated $1,146  $668  $484 
(1) These are non-GAAP measurements. A reconciliation of operating margin to operating income and EBIT to earnings before income taxes and net income is contained in “Results of Operations” herein.
(2) Includes intercompany eliminations.

Distribution Operations

In millions 2010  2009 
EBIT – prior year $326 ��$329 
         
Operating margin        
Increased revenues from the Hampton Roads and Magnolia pipeline projects  27   2 
Increased revenues from new rates and regulatory infrastructure program revenues at Atlanta Gas Light  9   6 
Increased revenues from new rates and enhanced infrastructure program revenues at Elizabethtown Gas  6   - 
Increased revenues from higher usage at Florida City Gas due to colder weather  3   - 
(Decreased) increased margins from gas storage carrying amounts at Atlanta Gas Light  (1)  8 
Other  2   2 
Increase in operating margin  46   18 
         
Operating expenses        
Increased pension expenses  4   12 
Increased payroll and incentive expenses  9   12 
Increased depreciation expenses  4   6 
Increased (decreased) marketing costs  1   (2)
Decreased bad debt expenses  (3)  (1)
Decreased outside services and other expenses  (3)  (1)
Increase in operating expenses  12   26 
(Decrease) increase in other income, primarily from regulatory allowance for funds used during construction of Hampton Roads pipeline project completed in 2009  (5)  5 
EBIT – current year $355  $326 
Our distribution operations segment is the largest component of our business and is subject to regulation and oversight by agencies in each of the seven states we serve. These agencies approve natural gas rates designed to provide us the opportunity to generate revenues to recover the cost of natural gas delivered to our customers and our fixed and variable costs such as depreciation, interest, maintenance and overhead costs, and to earn a reasonable return for our shareholders. With the exception of Atlanta Gas Light, our second largest utility, the earnings of our regulated utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas and general economic conditions that may impact our customers’ ability to pay for gas consumed. We have various mechanisms, such as weather normalization mechanisms at our utilities and weather derivative instruments that limit our exposure to weather changes within typical ranges in their respective service areas. During 2013, colder-than-normal weather increased our operating margin at our utilities, primarily at Nicor Gas by $12 million compared to expected levels based on 10-year normal weather. During 2012, warmer-than-normal weather decreased our operating margin by $24 million.

In millions 2013  2012 
EBIT - prior year $532  $412 
         
Operating margin        
Increased revenues from regulatory infrastructure programs, primarily at Atlanta Gas Light  31   15 
Increased operating margin from Nicor Gas as a result of the Nicor merger in December 2011  -   581 
Increased rider revenues primarily as a result of energy efficiency program recoveries at Nicor Gas  19   15 
Increased (decreased) operating margin mainly driven by weather, customer usage and customer growth  45   (6)
(Decreased) margin from gas storage carrying amounts at Atlanta Gas Light  (5)  2 
Other  (1)  1 
Increase in operating margin  89   608 
         
Operating expenses        
Increased (decreased) incentive compensation costs that reflect year over year performance  37   (7)
Increased rider expenses primarily as a result of energy efficiency programs at Nicor Gas  19   15 
Increased depreciation expense as a result of increased PP&E from infrastructure additions and improvements  15   8 
Increased (decreased) bad debt expenses as a result of change in natural gas prices and weather  4   (5)
Increased outside services and other expenses mainly as a result of maintenance programs  3   6 
Increased expenses for Nicor Gas as a result of the Nicor merger in December 2011  -   461 
Decreased depreciation expense at Nicor Gas due to deprecation study approval effective August 30, 2013  (19)  - 
Decreased operation and maintenance expense at Nicor Gas related to the 2012 PBR accrual  (8)  - 
(Decreased) increased pension and health benefits expenses primarily related to retiree health care costs and change in actuarial gains and losses  (6)  13 
Increase in operating expenses  45   491 
Increase in other income primarily from AFUDC equity from STRIDE Projects at Atlanta Gas Light  6   3 
EBIT - current year $582  $532 

In accordance with an order issued by the Georgia Commission, where AGL Resources makes a business acquisition that reduces the cost allocated or charged to Atlanta Gas Light for shared services, the net savings to Atlanta Gas Light will be shared equally between the firm customers of Atlanta Gas Light and our shareholders for a ten-year period. In December 2013 we filed a Report of Synergy Savings with the Georgia Commission in connection with the Nicor acquisition. If and when approved, the net savings should result in annual rate reductions to the firm customers of Atlanta Gas Light of $5 million. We expect the Georgia Commission to rule on the report in the second quarter of 2014.

Retail Operations

Our retail operations segment, which consists of several businesses that provide energy-related products and services to retail markets, also is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to partially mitigate potential weather impacts. During 2013, colder-than-normal weather increased operating margin by $9 million. During 2012, warmer-than-normal weather decreased operating margin by $9 million. Additionally, during 2013, our retail operations’ EBIT was favorably impacted by $12 million as a result of the acquisition of additional customer and service contracts.

Retail Energy Operations

In millions 2010  2009 
EBIT – prior year $105  $77 
         
Operating margin        
Increased average customer usage and colder weather  9   4 
Change in LOCOM adjustment  6   18 
Increased operating margins for Florida, Ohio and interruptible customers  1   5 
Change in retail pricing plan mix and decrease in average number of customers  (12)  (13)
(Decreased) increased contributions from the management and optimization of storage and transportation assets, and from retail price spreads  (1)  15 
Other  (1)  3 
Increase in operating margin  2   32 
         
Operating expenses        
Decreased bad debt expenses  -   (1)
Increased legal expense, offset by lower depreciation expenses  3   - 
Increased marketing and other expenses  1   4 
Increase in operating expenses  4   3 
Decreased other income  -   (1)
EBIT – current year $103  $105 


In millions 2013  2012 
EBIT - prior year $116  $93 
         
Operating margin        
Increased margin as a result of the Nicor merger in December 2011  -   76 
Increased (decreased) operating margin primarily related to average customer usage in Georgia due to demand and weather, net of weather hedges  17   (10)
Increased margin primarily due to acquisitions in January and June 2013 and expansions into additional retail energy markets  35   - 
(Decrease) increase related to change in gas costs and from retail price spreads, partially offset by changes to customer portfolio  (11)  10 
Storage inventory write-down (LOCOM) adjustment  3   1 
Other  3   2 
Increase in operating margin  47   79 
         
Operating expenses        
Increased expenses as a result of the Nicor merger in December 2011  -   59 
Increased expenses primarily due to acquisitions in January and June 2013  23   - 
Increased (decreased) bad debt expenses related to change in natural gas prices and weather  3   (5)
Other  -   2 
Increase in operating expenses  26   56 
EBIT - current year $137  $116 
Wholesale Services

In millions 2010  2009 
EBIT – prior year $47  $60 
         
Operating margin        
Change in storage hedge gains as a result of declining NYMEX natural gas prices  28   (35)
Change in commercial activity  10   (19)
(Decreased) increased gains on transportation hedges from the narrowing of transportation basis spreads and changes in park and loan hedges  (42)  27 
Change in LOCOM adjustment, net of hedging recoveries  (2)  16 
Decrease in operating margin  (6)  (11)
         
Operating expenses      
Increased payroll and other operating costs  2   - 
(Decreased) increased incentive compensation costs  (8)  4 
Decreased depreciation expenses  (1)  (2)
(Decrease) increase in operating expenses  (7)  2 
Increased other income  1   - 
EBIT – current year $49  $47 
Our wholesale services segment is involved in asset management and optimization, storage, transportation, producer and peaking services, natural gas supply, natural gas services and wholesale marketing. EBIT for our wholesale services segment is impacted by volatility in the natural gas market arising from a number of factors including weather fluctuations and changes in supply or demand for natural gas in different regions of the country. We principally use physical and financial arrangements to reduce the risks associated with fluctuations in market conditions and changing commodity prices. These economic hedges may not qualify, or are not designated for, hedge accounting treatment. As a result, our reported earnings for wholesale services reflect changes in the fair values of certain derivatives. These values may change significantly from period to period and are reflected as gains or losses within our operating revenues.

In millions 2013  2012 
EBIT - prior year $(3) $5 
         
Operating margin        
Change in commercial activity in 2013 largely driven by the withdrawal of a portion of the storage inventory economically hedged at the end of 2012, weather and increased cash optimization opportunities in the supply-constrained Northeast corridor  84   5 
Change in value of storage hedges as a result of changes in NYMEX natural gas prices  (30)  (23)
Change in value of transportation and forward commodity hedges from price movements related to natural gas transportation positions (1)
  (70)  (11)
Change in storage inventory LOCOM adjustment, net of estimated recoveries  3   22 
Decrease in operating margin  (13)  (7)
         
Operating expenses        
Decreased expenses due to sale of Compass Energy in May 2013  (4)  - 
Increased payroll, benefits and incentive compensation costs, offset by lower other costs  2   2 
(Decrease) increase in operating expenses  (2)  2 
Gain on sale of Compass Energy  11   - 
(Decrease) increase in other income  (1)  1 
EBIT - current year $(4) $(3)
(1)
2011 excluded forward commodity hedge losses associated with counterparty bankruptcy and Marcellus take-away constraint losses.

Change in commercial activity The commercial activity at wholesale services includes recognized storage and transportation values that were generated in prior periods, which reflect the impact of prior period hedge gains and losses as associated physical transactions occur in the period. Additionally, the commercial activity includes operating margin generated and recognized in the current period. For 2013, commercial activity increased significantly due to

·  increased cash optimization opportunities related to certain of our transportation portfolio positions, particularly in the Northeastern U.S.
·  the recognition of operating margin resulting from the withdrawal of storage inventory hedged at the end of 2012 that was included in the storage withdrawal schedule with a value of $27 million as of December 31, 2012
·  the effects of colder weather

The 2012 change in commercial activity was primarily due to losses in 2011 associated with constraints of natural gas purchased from producers in the Marcellus shale gas producing region and credit losses associated with a counterparty that filed for bankruptcy during 2011. Commercial activity in 2012 was also impacted by the abundance of natural gas supply due to shale production, which reduced price volatility and transportation spreads. Additionally, 2012 was one of the warmest years in recorded history causing a reduction in customer demand and transportation spreads.

Change in storage and transportation hedges Seasonal (storage) and geographical location (transportation) spreads and overall natural gas price volatility continued to remain low relative to historical periods. Storage hedge losses in 2013 are primarily due to the increase in natural gas prices during the fourth quarter of 2013 as compared to storage hedge gains last year resulting from a downward movement in the natural gas prices. Losses in our transportation hedge positions in 2013 are the result of widening transportation basis spreads, associated with colder-than-normal weather and higher demand during the second half of 2013 experienced at natural gas receipt and delivery points primarily in the Northeast corridor related to natural gas transportation constraints in the region. These losses are temporary and based on current expectations will be recovered in 2014 through 2016 (with the majority recognized in 2014) via the physical flow of natural gas and utilization of the contracted transportation capacity.

The following table indicates the components of wholesale services’ operating margin for 2010, 2009 and 2008.the periods presented.

In millions 2010  2009  2008 
Commercial activity $77  $67  $86 
Gain on transportation hedges  1   43   7 
Gain on storage hedges  29   1   36 
Gain on park and loan hedges  -   -   9 
Inventory LOCOM, net of hedging recoveries  (2)  -   (16)
Operating margin $105  $111  $122 
In millions 2013  2012  2011 
Commercial activity recognized $127  $43  $38 
(Loss) gain on transportation and forward commodity hedges  (73)  (3)  8 
(Loss) gain on storage hedges  (16)  14   37 
Inventory LOCOM adjustment, net of estimated current period recoveries  (1)  (4)  (26)
Operating margin $37  $50  $57 

For more information on Sequent’s expected operating revenues from its storage inventory and transportation and forward commodity hedges in 20112014 and discussion of commercial activity, see description of the inventory roll-out schedule in Item 1 “Business.” under the caption Wholesale Services.

Energy InvestmentsMidstream Operations

In millions 2010  2009 
EBIT – prior year $12  $19 
         
Operating margin        
Decreased operating revenues due to the sale of AGL Networks  (10)  - 
Increased revenues at Golden Triangle Storage  4   - 
Decreased revenues at Jefferson Island  -   (2)
Other  (1)  (2)
Decrease in operating margin  (7)  (4)
         
Operating expenses and other loss        
Decreased costs due to sale of AGL Networks  (5)  - 
Increased payroll, benefit costs, deprecation and outside services expenses at Golden Triangle Storage  4   - 
(Decreased) increased outside services and other expenses at Jefferson Island  (2)  1 
Other  2   1 
(Decrease) increase in operating expenses  (1)  2 
Increased other expenses  2   1 
EBIT – current year $4  $12 
Our midstream operations segment’s primary activity is operating non-utility storage and pipeline facilities including the development, acquisition and operation of high-deliverability underground natural gas storage assets. Our midstream operations segment also includes an equity investment in Sawgrass Storage, a joint venture between us and a privately held energy exploration and production company. The joint venture decided in December 2013 to terminate the development of the Sawgrass Storage facility. For more information, see Note 10 to our consolidated financial statements under Item 8 herein.

In millions 2013  2012 
EBIT - prior year $10  $9 
         
Operating margin        
Decreased margin from Central Valley Storage as a result of hedge gains in 2012 that did not occur in 2013; increased in 2012 due to the Nicor merger in December 2011  (2)  8 
Decreased revenues at Jefferson Island as a result of lower subscription rates  (3)  (4)
Increased revenues primarily at Golden Triangle as a result of Cavern 2 beginning commercial service in 2012 and Cavern 1 working gas capacity project in 2013, as well as revenue due to entry into LNG markets  -   5 
(Decrease) increase in operating margin  (5)  9 
         
Operating expenses        
Increased expense from Central Valley Storage as a result of the Nicor Merger in December 2011 and the facility beginning commercial service during the second quarter of 2012  4   7 
Increased operating and depreciation expenses primarily due to entry into the LNG markets and Cavern 2 at Golden Triangle beginning commercial service in 2012  4   3 
Increase in operating expenses  8   10 
         
Impairment loss at Sawgrass Storage  (8)  - 
Increase in other income from equity interest in Horizon Pipeline  1   2 
Other (expense) income  (7)  2 
EBIT - current year $(10) $10 

Cargo Shipping

Our cargo shipping segment’s primary activity is transporting containerized cargo in the Bahamas and the Caribbean. Our cargo shipping segment also includes an equity investment in Triton, a cargo container leasing business. The cargo shipping business reported EBIT of $8 million for the year ended December 31, 2012, including $11 million EBIT from our investment in Triton. This was compared to an immaterial EBIT for the year ended December 31, 2011, as it only reflected the 22 days following the close of our merger with Nicor. For more information on our investment in Triton, see Note 10 to our consolidated financial statements under Item 8 herein.





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 

Liquidity and Capital Resources

Overview The acquisition of natural gas and pipeline capacity, payment of dividends and funding of working capital requirementsneeds primarily related to our natural gas inventory are our most significant short-termshort-term financing requirements. The liquidity required to fund these short-term needs is primarily provided by our operating activities, and any needs not met, are primarily satisfied with short-term borrowings under our commercial paper programs, which are supported by the AGL Credit Facility and the Nicor Gas Credit Facility. For more information on the seasonality of our short-term borrowings, see “Short-term Debt” later in this section.

The need for long-term capital is driven primarily by capital expenditures and maturities and refinancing of long-term debt. In addition, we anticipate incurring indebtedness in connection with financing the consideration for the proposed Nicor merger.

The liquidity required to fund our working capital, capital expenditures and other cash needs is primarily provided by our operating activities. Our short-term cash requirements not met by cash from operations are primarily satisfied with short-term borrowings under our commercial paper program, which is supported by our Credit Facility. Periodically, we raise funds supporting our long-term cash needs from the issuance of long-term debt or equity securities. We regularly evaluate our funding strategy and profile to ensure that we have sufficient liquidity for our short-term and long-term needs in a cost-effective manner. Consistent with this strategy, in May 2013 we issued $500 million in 30-year senior notes with a 4.4% fixed interest rate.

Our capital market strategy has continued to focus on maintaining a strong Consolidated Statement of Financial Position, ensuring ample cash resources and daily liquidity, accessing capital markets at favorable times as needed, managing critical business risks and maintaining a balanced capital structure through the appropriate issuance of equity or long-term debt securities.

Our issuance of various securities,financing activities, including long-term and short-term debt and equity, isare subject to customary approval or review by state and federal regulatory bodies, including the various public service commissions of the states in which we conduct business the SEC and the FERC. Furthermore, a. Certain financing activities we undertake may also be subject to approval by state regulatory agencies. A substantial portion of our consolidated assets, earnings and cash flows areis derived from the operation of our regulated utility subsidiaries, whose legal authority to pay dividends or make other distributions to us is subject to regulation. Nicor Gas is restricted by regulation in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. Dividends are allowed only to the extent of Nicor Gas’ retained earnings balance, which was $499 million at December 31, 2013.

We believe the amounts available to us under our senior notes andlong-term debt, AGL Credit Facility Bridgeand Nicor Gas Credit Facility, Term Loan Facility and through the issuance of debt and equity securities, combined with cash provided by our operating activities, will continue to allow us to meet our needs for working capital, pension contributions, constructionand retiree welfare benefits, capital expenditures, anticipated debt redemptions, interest payments on debt obligations, dividend payments common share repurchases, financing requirements for the Nicor merger and other cash needs through the next several years. Nevertheless, ourOur ability to satisfy our working capital requirements and our debt service obligations, or fund planned capital expenditures, will substantially depend upon our future operating performance (which will be affected by prevailing economic conditions), and financial, business and ot herother factors, some of which we are unable to control. These factors include, among others, regulatory changes, the price of natural gas, theand demand for natural gas, and operational risks.

We will continue to evaluate our need to increase available liquidity basedAs of December 31, 2013 and 2012, we had $80 million of cash and short-term investments on our view of working capital requirements, including the impact of changes in natural gas prices, liquidity requirements established by rating agencies, the proposed merger with Nicor and other factors. See Item 1A, “Risk Factors,” for additional information on items that could impact our liquidity and capital resource requirements.

Cash Flows

The following table provides a summary of our cash flows provided by (used in) operating, investing and financing activities for the last three years.

In millions 2010  2009  2008 
Net cash provided by (used in):    
Operating activities $526  $592  $227 
Investing activities  (442)  (476)  (372)
Financing activities  (86)  (106)  142 
Net increase (decrease) in cash and cash equivalents  (2)  10   (3)
Cash and cash equivalent at beginning of period  26   16   19 
Cash and cash equivalent at end of period $24  $26  $16 

Cash Flow from Operating Activities We prepare our statement of cash flows using the indirect method. Under this method, we reconcile net income to cash flows from operating activities by adjusting net income for those items that impact net income but may not result in actual cash receipts or payments during the period. These reconciling items include depreciation and amortization, changes in derivative financial instrument assets and liabilities, deferred income taxes and changes in the Consolidated Statements of Financial Position held by Tropical Shipping. This cash and investments are indefinitely reinvested offshore and not available for working capital fromuse by the beginningCompany or our other operations unless we repatriate a portion of Tropical Shipping’s earnings in the form of a dividend, which would be subject to the end of the period.U.S. income tax. See Note 12 to our consolidated financial statements under Item 8 herein for additional information on our income taxes.

Year-over-year changes in our operating cash flows are primarily due to working capital changes within our distribution operations, retail energy operations and wholesale services segments resulting from the impact of weather, the price of natural gas, natural gas storage, the timing of customer collections, payments for natural gas purchases and deferred gas cost recoveries. The increase or decrease in the price of natural gas directly impacts the cost of gas stored in inventory.
2010 compared to 2009 In 2010, our net cash flow provided from operating activities was $526 million, a decrease of $66 million or 11% from 2009. This decrease was primarily a result of colder weather in the fourth quarter of 2010 as compared to 2009 within most of our service areas. As a result, the use of working capital for our gas receivables increased $134 million due to increased volumes sold to our customers.

We also refunded an additional $38 million to our utility customers for billed commodity costs compared to 2009 as natural gas commodity cost recovery rates charged to customers were reduced as under-recovered amounts were collected in part due to the decline in natural gas prices.

This increased use of operating cash flow was mostly offset by decreased working capital used by Sequent of $128 million for its energy marketing activities, resulting from the timing of payments for gas purchases relative to collections of accounts receivable and an increase in Sequent’s daily physical sales.

2009 compared to 2008 In 2009, our net cash flow provided from operating activities was $592 million, an increase of $365 million or 161% from 2008. The primary contributor to the recovery of working capital during 2009 was significantly lower natural gas commodity prices as compared to 2008. During 2008, the cost of natural gas increased significantly during the natural gas storage injection season. This resulted in a higher cost of inventories in 2008 as compared to 2009, and consequently higher customer bills and accounts receivable at the end of 2008. The higher receivable balances and inventory costs were billed to and /or collected from customers during 2009, which resulted in a $173 million increase in cash from the collection of our natural gas receivables and a $103 million increase in cash from our inventory withdrawals.

As a result of the lower natural gas prices during 2009, we used less cash while refilling our natural gas inventories. The lower natural gas prices and associated inventory costs reduced customer bills at the end of 2009, allowing us to reduce our working capital needs. Also contributing to the higher operating cash flows was the return of cash collateral requirements posted during 2008 due to unrealized hedge losses resulting from the dramatic decline in natural gas prices during the second half of 2008 and into 2009. Cash collateral requirements decreased $200 million for our derivative financial instrument activities at Sequent and SouthStar due to the change in hedge values as forward NYMEX curve prices shifted downward in 2009 and as positions settled.

Cash Flow from Investing Activities Our net cash used in investing activities consisted primarily of PP&E expenditures. The majority of our PP&E expenditures are within our distribution operations and energy investment segments.

Our estimated PP&E expenditures for 2011 and our actual PP&E expenditures incurred in 2010, 2009 and 2008 are shown within the following categories and are presented in the table below.
·  
Base business – new construction and infrastructure improvements at our distribution operations segment
·  
Regulatory infrastructure programs – Programs that update or expand our distribution systems and liquefied natural gas facilities to improve system reliability and meet operational flexibility and growth. These programs include the pipeline replacement program and STRIDE at Atlanta Gas Light and Elizabethtown Gas’ utility infrastructure enhancements program.
·  
Hampton Roads – Virginia Natural Gas’ pipeline project, which connects its northern and southern systems
·  
Magnolia project – pipelines which diversify our sources of natural gas by connecting our Georgia service territory to the Elba Island LNG terminal
·  
Natural gas storage – salt-dome cavern expansions at Golden Triangle Storage and Jefferson Island
·  
Other – primarily includes information technology and building and leasehold improvements
In millions 2008  2009  2010  
2011 (1)
 
Base business $131  $132  $159  $146 
Regulatory infrastructure programs  70   76   186   175 
Hampton Roads and Magnolia project  48   136   3   - 
Natural gas storage  64   95   114   37 
Other  59   37   48   81 
Total $372  $476  $510  $439 
(1)  Estimated PP&E expenditures

Our PP&E expenditures were $510 million for the year ended December 31, 2010, compared to $476 million for the same period in 2009. This increase of $34 million or 7% was primarily due to a $19 million increase in expenditures for the construction of the Golden Triangle Storage natural gas storage facility, $26 million in expenditures for Elizabethtown Gas’ utility infrastructure enhancements program and $84 million in expenditures for STRIDE and $38 million in other capital projects in distribution operations. This was offset by reduced expenditures of $133 million for the Hampton Roads and Magnolia projects, for which construction was substantially completed in 2009. The higher capital expenditures were further offset by $73 million in proceeds from the disposition of assets.
In 2009, our PP&E expenditures were $104 million or 28% higher than in 2008. This was primarily due to $43 million expended for the completed Magnolia project, $45 million in increased spending for the completed Hampton Roads pipeline project and an increase in our natural gas storage project expenditures of $31 million as we continued construction of our Golden Triangle Storage facility. This was largely offset by decreased expenditures of $22 million for the other category, primarily on information technology and building and leasehold improvements.

Our estimated expenditures for 2011 include discretionary spending for capital projects principally within the base business, regulatory infrastructure programs and other categories. We continually evaluate whether to proceed with these projects, reviewing them in relation to factors including our authorized returns on rate base, other returns on invested capital for projects of a similar nature, capital structure and credit ratings, among others. We will make adjustments to these discretionary expenditures as necessary based upon these factors.

Cash Flow from Financing Activities Our capitalization and financing strategy is intended to ensure that we are properly capitalized with the appropriate mix of equity and debt securities. This strategy includes active management of the percentage of total debt relative to total capitalization, appropriate mix of debt with fixed to floating interest rates (our variable debt target is 20% to 45% of total debt), as well as the term and interest rate profile of our debt securities.

As of December 31, 2010,2013, our variable-rate debt was $892 million$1.4 billion, or 33%28%, of our total debt, compared to $762 million$1.5 billion, or 30%32%, as of December 31, 2009. This increase2012. The decrease was principallyprimarily due to increaseddecreased commercial paper borrowings. As of December 31, 2010, our commercial paper borrowings were $131 million or 22% higher than the same time last year, primarily a result of higher working capital requirements and increased capital expenditures. For more information on our debt, see Note 7.8 to our consolidated financial statements under Item 8 herein.

We will continue to evaluate our need to increase available liquidity based on our view of working capital requirements, including the impact of changes in natural gas prices, liquidity requirements established by rating agencies and other factors. See Item 1A, “Risk Factors,” for additional information on items that could impact our liquidity and capital resource requirements.

Short-term Debt The following table provides additional information on our short-term debt throughout the year.

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 
(1)  
As of December 31, 2013.
(2)  
For the twelve months ended December 31, 2013. The minimum and largest balances outstanding for each debt instrument occurred at different times during the year. Consequently, the total balances are not indicative of actual borrowings on any one day during the year.

The largest, minimum and daily average balances borrowed under our commercial paper programs are important when assessing the intra-period fluctuations of our short-term borrowings and potential liquidity risk. The fluctuations are due to our seasonal cash requirements to fund working capital needs, in particular the purchase of natural gas inventory, margin calls and collateral.

Cash requirements generally increase between June and December as we purchase natural gas in advance of the Heating Season. The timing differences of when we pay our suppliers for natural gas purchases and when we recover our costs from our customers through their monthly bills can significantly affect our cash requirements. Our short-term debt balances are typically reduced during the Heating Season, as a significant portion of our current assets, primarily natural gas inventories, are converted into cash.

The AGL Credit Facility and the Nicor Gas Credit Facility can be drawn upon to meet working capital and other general corporate needs. The interest rates payable on borrowings under these facilities are calculated either at the alternative base rate, plus an applicable margin, or LIBOR, plus an applicable interest margin. The applicable interest margin used in both interest rate calculations will vary according to AGL Capital’s and Nicor Gas’ current credit ratings.

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 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. At December 31, 2013 and 2012, we had no outstanding borrowings under either credit facility.

The timing of natural gas withdrawals is dependent on the weather and natural gas market conditions, both of which impact the price of natural gas. Increasing natural gas commodity prices can have a significant impact on our commercial paper borrowings. Based on current natural gas prices and our expected purchases during the upcoming injection season, we believe that we have sufficient liquidity to cover our working capital needs.

The lenders under our credit facilities and lines of credit are major financial institutions with $2.2 billion of committed balances and all had investment grade credit ratings as of December 31, 2013. It is possible that one or more lending commitments could be unavailable to us if the lender defaulted due to lack of funds or insolvency. However, based on our current assessment of our lenders’ creditworthiness, we believe the risk of lender default is minimal. Commercial paper borrowings reduce availability of these credit facilities.

Long-term Debt Our long-term debt matures more than one year from December 31, 2013 and consists of medium-term notes: Series A, Series B, and Series C, which we issued under an indenture dated December 1989; senior notes; first mortgage bonds; and gas facility revenue bonds.

Our long-term cash used in financing activities was $86 million in 2010 comparedrequirements primarily depend upon the level of capital expenditures, long-term debt maturities and decisions to cash used of $106 million in 2009.refinance long-term debt. The decreased use of cash of $20 million was primarily due to increased commercial paper borrowings of $395 million in 2010 compared to 2009. This was partially offset byfollowing table summarizes our issuance of $300 million of senior notes in August 2009. Additional offsets in 2010 include our purchase of an additional 15% ownership interest in SouthStar for $58 million, an increase in dividends paid on common shares of $6 million, purchase of treasury shares of $7 million and an increased distribution tolong-term debt issuances over the noncontrolling interest of $7 million.last three years.

  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%
(1)  During the first quarter of 2013, we refinanced the gas facility revenue bonds. We had no cash receipts or payments in connection with the refinancing. See Note 8 to our consolidated financial statements under Item 8 herein for more information.
(2)  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.
(3)  The net proceeds were used to pay a portion of the cash consideration and expenses incurred in connection with the Nicor merger.
(4)  In October 2014 the interest rate for these senior notes will change to a floating rate.
(5)  The net proceeds were used to repay a portion of AGL Capital’s commercial paper, including $300 million we borrowed to repay our senior notes that matured on January 14, 2011. The remaining proceeds were used to pay a portion of the cash consideration and expenses incurred in connection with the Nicor merger.

Credit Ratings Our borrowing costs and our ability to obtain adequate and cost-effective financing are directly impacted by our credit ratings, as well as the availability of financial markets. In addition, creditCredit ratings are important to our counterparties when we engage in certain transactions, including OTC derivatives. It is our long-term objective to maintain or improve our credit ratings in order to manage our existing financing costcosts and enhance our ability to raise additional capital on favorable terms.

Credit ratings and outlooks are opinions subject to ongoing review by the rating agencies and may periodically change. Each rating should be evaluated independently of any other rating. The rating agencies regularly review our financial performance prospects and financial condition and reevaluate their ratings of our long-term debt and short-term borrowings, including our corporate ratings.

ratings and our ratings outlook. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. A credit rating is not a recommendation to buy, sell or hold securities.securities and each rating should be evaluated independently of other ratings.

Factors we consider important into assessing our credit ratings include our statementsConsolidated Statements of financial positionFinancial Position, leverage, capital spending, earnings, cash flow generation, available liquidity and overall business risks. We do not have any triggertriggering 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 agreements that would require us to issue equity based on credit ratings or other trigger events.

As of December 31, 2013, if our credit rating had fallen below investment grade, we would have been required to provide collateral of $11 million to continue conducting business with certain customers. The following table summarizes our credit ratings as of January 31, 2014 and reflects upgrades by Moody’s for certain of our ratings compared to December 31, 2010.2012.

AGL ResourcesNicor Gas
S&PMoody’sFitch  S&P  Moody’s  Fitch 
Corporate rating  A-BBB+   n/a  A-BBB+BBB+n/aA 
Commercial paper  A-2   P-2   F2A-2P-1F1 
Senior unsecured BBB+  Baa1A3BBB+BBB+   A-A2A+
Senior securedn/an/an/aA  Aa3  AA- 
Ratings outlook NegativeStable  Stable  Stable StableStable Stable

Subsequent to the announcement of our proposed merger with Nicor, S&P placed our long-term debt ratings and our A- corporate credit ratings on credit watch with negative implications. The primary reason for this change is the increased leverage we will assume to complete the proposed merger and the uncertainties that exist with the proposed merger. S&P’s rating for our commercial paper was affirmed A-2. Moody’s and Fitch each affirmed stable outlooks for their ratings of our debt obligations based on our sufficient equity as part of the financing for the proposed merger.
Our credit ratings depend largely on our financial performance, and aA downgrade in our current ratings, particularly below investment grade, could adversely affectwould increase our borrowing costs and significantlycould limit our access to the commercial paper market. In addition, we would likely be required to pay a higher interest rate in future financings, and our potential pool of investors and funding sources could decrease.
Merger Financing Agreements In December 2010, we amended our existing Credit Facility to allow for the closing of the proposed merger with Nicor. Additionally, in December 2010, we entered into a $1.05 billion Bridge Facility. The Bridge Facility may be used to partially finance the cash portion of our proposed merger with Nicor and pay related fees and expenses in the event that permanent financing is not available at the time of the closing of the proposed merger.
The Bridge Facility matures 364 days after funds are borrowed and any repaid amounts under the Bridge Facility may not be re-borrowed. The interest rate applicable to the Bridge Facility is the higher of (i) at our option, a floating base rate or a floating Eurodollar rate, in each case, plus an applicable margin ranging from 0.5% to 2.5% based on our credit rating, and the applicable interest rate option, and subject to a 0.25% increase for each 90 day period that elapses after the closing of the Bridge Facility or (ii) the highest interest rate we or any of our subsidiaries are paying on any similar facility. As of December 31, 2010, we had no outstanding borrowings under our Bridge Facility.
We do not currently plan to draw on our Bridge Facility to fund the proposed merger with Nicor, as we anticipate having more permanent financing in place subsequent to receipt of all regulatory approvals.

Default ProvisionsOur debt instruments and other financial obligations include provisions that, if not complied with, could require early payment additional collateral support or similar actions. Our Credit Facility containscredit facilities contain customary events of default, including, but not limited to, the failure to pay any interest or principal when due, the failure to furnish financial statements within the timeframe established by each debt facility, the failure to comply with certain affirmative and negative covenants, cross-defaults to certain other material indebtedness in excess of specified amounts, incorrect or misleading representations or warranties, insolvency or bankruptcy, fundamentaland a change of control, the occurrence of certain Employee Retirement Income Security Act events, judgment s in excess of specified amounts and certain impairments to the guarantee.control.

Our Credit Facility containscredit 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.

Our Credit Facility also includescredit facilities each include a financial covenant that does not permit ourrequires us to maintain a ratio on a consolidated basis, of total debt to total capitalization to exceedof no more than 70% (excluding for these purposes, debt incurred to partially refinance the Bridge Facility during the period prior to funding under the Bridge Facility) at the end of any fiscal month. This ratio, as defined within our debt agreements, includes standby lettersHowever, we typically seek to maintain these ratios at levels between 50% and 60%, except for temporary increases related to the timing of credit, performance/surety bondsacquisition and the exclusion of other comprehensive income pension adjustments.financing activities. Adjusting for these items, the following table contains our ratio, on a consolidated basis, of total debt to total capitalization was 58% at-to-capitalization ratios for December 31, 2010 and 57% at December 31, 2009.which are below the maximum allowed.

  AGL Resources  Nicor Gas 
  2013  2012  2013  2012 
Debt-to-capitalization ratio as calculated from our Consolidated Statement of Financial Position  58%  59%  54%  55%
Adjustments (1)
  (1)  (1)  1   - 
Debt-to-capitalization ratio as calculated from our credit facilities  57%  58%  55%  55%
(1)  As defined in credit facilities, includes standby letters of credit, performance/surety bonds and excludes accumulated OCI items related to non-cash pension adjustments, other post-retirement benefits liability adjustments and accounting adjustments for cash flow hedges.

As of December 31, 2010 and 2009, weWe were in compliance with all of our existing debt provisions and covenants, both financial and non-financial. Additionally,non-financial, as of December 31, 2013 and 2012. For more information on our Bridge Facility and Term Loan facility each contain the samedefault provisions, see Note 8 to our consolidated financial covenant and similar non-financial covenants and default provisions; however, these are not effective until we drawstatements under these facilities.Item 8 herein.
Our ratio, on a consolidated basis, of total debt to total capitalization is typically greater at the beginning of the Heating Season as we make additional short-term borrowings to fund our natural gas purchases and meet our working capital requirements. We intend to maintain our capitalization ratio in a target range of 50% to 60%. Accomplishing this capital structure objective and maintaining sufficient cash flow are necessary to maintain attractive credit ratings. The components of our capital structure, as calculated from our Consolidated Statements of Financial Position, as of the dates indicated, are provided in the following table.

In millions 
December 31, 2010
     December 31, 2009   
Short-term debt $1,033   23% $602   14% 
Long-term debt  1,673   37   1,974   45  
Total debt  2,706   60   2,576   59  
Equity  1,836   40   1,819   41  
  Total capitalization $4,542   100% $4,395   100% 

Short-term Debt Our short-term debt is composed of borrowings and payments under our Credit Facility and commercial paper program, lines of credit and payments of the current portion of our capital leases and our senior notes maturing in less than one year.
In millions 
 
Year-end balance outstanding (1)
  
Daily average balance outstanding (2)
  
Largest balance outstanding (2)
 
Commercial paper $732  $419  $760 
Senior notes  300   300   300 
Capital leases  1   1   1 
Total short-term debt $1,033  $720  $1,061 
Cash Flows

We prepare our Consolidated Statements of Cash Flows using the indirect method. Under this method, we reconcile net income to cash flows from operating activities by adjusting net income for those items that impact net income but may not result in actual cash receipts or payments during the period. These reconciling items include depreciation and amortization, changes in derivative instrument assets and liabilities, deferred income taxes, gains or losses on the sale of assets and changes in the Consolidated Statements of Financial Position for working capital from the beginning to the end of the period. The following table provides a summary of our operating, investing and financing cash flows for the last three years.

In millions 2013  2012  2011 
Net cash provided by (used in):    
Operating activities $971  $1,003  $451 
Investing activities  (876)  (786)  (1,339)
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 Flow from Operating Activities 2013 compared to 2012 Our net cash flow provided by operating activities in 2013 was $971 million, a decrease of $32 million or 3% from 2012. The decrease was primarily related to decreased cash provided by (i) receivables, other than energy marketing, due to colder weather in 2013, which resulted in higher volumes primarily at distribution operations and retail operations that will be collected in future periods and (ii) deferred income taxes, due to the net change in mark to market activity at wholesale services combined with less cash provided from accelerated tax depreciation in 2013 than in 2012. This decrease in cash provided by operating activities was partially offset by increased cash provided by (i) lower payments for incentive compensation in 2013 as a result of reduced earnings in 2012 as compared to 2011 and (ii) trade payables, other than energy marketing, due to higher gas purchase volumes primarily at distribution operations and retail operations resulting from colder weather in 2013.

2012 compared to 2011 Our net cash flow provided by operating activities in 2012 was $1,003 million, an increase of $552 million or 122% from 2011. The increase was primarily related to the recovery of working capital from the companies acquired in the December 2011 merger with Nicor. Cash provided by operations changed $89 million driven by derivative financial instrument assets and liabilities, primarily a result of the change in forward NYMEX prices at wholesale services year-over-year, and $70 million driven by a decrease in Sequent's park and loan gas transactions due to lower volumes and decreased prices. Additionally, we had a $26 million increase in operating cash flow from Elizabethtown Gas’ recoverable derivative position as a result of changes in forward NYMEX prices. These increases were partially offset by a decrease in recovery of working capital during 2012 as a result of warmer-than-normal weather. Our increased operating cash flow in 2012 was also impacted by a decrease in cash used for margin deposits of $94 million due to the change in cash collateral value on our hedged positions and a $121 million decrease in trade payables mainly due to lower natural gas prices and purchased volumes in 2012.

Cash Flow from Investing Activities The increase in net cash flow used in investing activities was primarily a result of our $122 million acquisition of customer service contracts during the first quarter of 2013 and our $32 million acquisition of residential and commercial energy customer relationships in Illinois during the second quarter of 2013, both in our retail operations segment. This increase was partially offset by decreased spending for PP&E expenditures of $33 million, a net decrease in short-term investments of $12 million and $12 million from the sale of Compass Energy.

Our estimated PP&E expenditures for 2014 and our actual PP&E expenditures incurred in 2013, 2012 and 2011 are within the following categories and are quantified in the following table.
·  
Distribution business- primarily includes new construction and infrastructure improvements
·  
Regulatory infrastructure programs- programs that update or expand our distribution systems and liquefied natural gas facilities to improve system reliability and meet operational flexibility and growth. These programs include STRIDE at Atlanta Gas Light, SAVE at Virginia Natural Gas, and an enhanced infrastructure program at Elizabethtown Gas
·  
Natural gas storage - underground natural gas storage facilities at Golden Triangle, Jefferson Island and Central Valley
·  
Other- primarily includes cargo shipping, information technology and building and leasehold improvements

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 
(1)  As of December 31, 2010.Estimated PP&E expenditures.
(2)  ForOnly includes Nicor expenditures subsequent to the year endedmerger date of December 31, 2010.9, 2011.
The largest amounts borrowed on our commercial paper borrowings are important when assessing the intra-period fluctuation of our short-term borrowings and any potential liquidity risk. Our year-end short-term debt outstanding and our largest short-term debt balance outstanding are significantly higher than our average short-term debt outstanding during 2010 due to our seasonal short-term cash requirements.

Such cash requirements generally increase between June and December as we purchase natural gas and pipeline capacity in advance of the Heating Season. The variation of when we pay our suppliers for natural gas purchases and pipeline capacity and when we recover our costs from our customers through their monthly bills can significantly affect our short-term cash requirements. Our short-term debt balances are typically reduced during the Heating Season because a significant portion of our current assets, primarily natural gas inventories, are converted into cash in the Heating Season.

Additionally, increasing natural gas commodity prices can have a significant impact on our commercial paper borrowings. Based on current natural gas prices and our expected purchases during the upcoming injection season, a $1 increase per Mcf in natural gas prices could result in an additional $60 to $70 million of working capital requirements during the peak of the Heating Season based upon our current injection plan. This range is sensitive to the timing of storage injections and withdrawals, collateral requirements and our portfolio position.

In September 2010, we entered into our new Credit Facility. The new Credit Facility matures in September 2013, and replaced our previous $1 billion facility that was due to expire during 2011. The new Credit Facility allows us to borrow up to $1 billion on a revolving basis, and includes an option to increase the Credit Facility to $1.25 billion, subject to the agreement by lenders who wish to participate in such an increase. The new Credit Facility may be used to provide for working capital, finance certain permitted acquisitions, issue up to $250 million in letters of credit and for general corporate purposes including to provide commercial paper backstop, fund capital expenditures, make repurchases of capital stock a nd repay existing indebtedness.

In December 2010, we amended our Credit Facility in connection with the Nicor merger to, among other things, increase the accordion feature from $250 million to $750 million. As of December 31, 2010 and 2009 we had no outstanding borrowings under our Credit Facility.
In December 2010, we entered into a $300 million Term Loan Facility to help repay the senior notes that matured in January 2011. The Term Loan Facility matures 180 days after the funds are borrowed. The interest rate applicable to the Term Loan Facility is, at our option, a floating base rate or a floating Eurodollar rate, in each case, plus an applicable margin ranging from 0.5% to 2.5% based on our credit rating and interest rate option. As of December 31, 2010, we had no outstanding borrowings under our Term Loan Facility. However, subsequent to year-end, along with $150 million of commercial paper borrowings we borrowed $150 million under the Term Loan Facility to repay the $300 million of senior notes that matured in January 2011. In February 2011, we intend to use commercial paper borrowings to repay the $150 million currently outstanding under the Ter m Loan Facility.
SouthStar has a $75 million line of credit which is used for its working capital and general corporate needs. Additionally, Sequent has a $5 million line of credit that bears interest at the London interbank offered rate (LIBOR) plus 3.0%. Sequent’s line of credit is used solely for the posting of margin deposits for NYMEX transactions and is unconditionally guaranteed by us. As of December 31, 2010 and 2009, we had no outstanding borrowings on either of these lines of credit.
The lenders under our Credit Facility, Bridge Facility, Term Loan Facility and lines of credit are major financial institutions with approximately $2.6 billion of committed balances and all have investment grade credit ratings as of December 31, 2010.Based on current credit market conditions, it is possible that one or more lending commitments could be unavailable to us if the lender defaulted due to lack of funds or insolvency. However, based on our current assessment of our lenders’ creditworthiness, we believe the risk of lender default is minimal.

Long-term Debt Our long-term debt matures more than one year from December 31, 2010 and consists of medium-term notes, senior notes, gas facility revenue bonds, and capital leases.

Our long-term cash requirements primarily depend upon the level of capital expenditures, long-term debt maturities and decisions to refinance long-term debt. The following represents our long-term debt activity over the last three years.
Our PP&E expenditures were $749 million for the year ended December 31, 2013, compared to $782 million for the same period in 2012.The decrease of $33 million, or 4%, was primarily due to decreased spending of $49 million on our natural gas storage projects consisting of $35 million at Central Valley and $14 million at Golden Triangle. Additionally, capital expenditures decreased $35 million for strategic projects and $16 million for utility infrastructure enhancement projects at Elizabethtown Gas. These decreases were partially offset by increased expenditures of $54 million for regulatory infrastructure programs at Atlanta Gas Facility Revenue BondsLight and $9 million for accelerated infrastructure replacement program projects at Virginia Natural Gas.

In JuneOur PP&E expenditures were $782 million for the year ended December 31, 2012, compared to $427 million for the same period in 2011.The increase of $355 million, or 83%, was primarily due to $188 million of PP&E expenditures at Nicor Gas and September 2008,$31 million of PP&E expenditures at Central Valley, both of which were acquired through our merger with Nicor in December 2011. Additionally, capital expenditures increased $63 million for pipeline replacement projects, $21 million for i-SRP projects and $10 million for i-CGP projects at Atlanta Gas Light, as well as $16 million for accelerated infrastructure replacement program projects at Virginia Natural Gas.

Our estimated expenditures for 2014 include discretionary spending for capital projects principally within the distribution business, regulatory infrastructure programs, natural gas storage and other categories. We continuously evaluate whether or not to proceed with these projects, reviewing them in relation to various factors, including our authorized returns on rate base, other returns on invested capital for projects of a similar nature, capital structure and credit ratings, among others. We will make adjustments to these discretionary expenditures as necessary based upon these factors.

Cash Flow from Financing Activities During 2013, we refinanced $160$200 million of our gas facility revenue bonds. There was no change to the maturity dates of these bonds. In October 2010, we completed the remarketing of $160 million ofoutstanding tax-exempt gas facility revenue bonds, with rates that reset daily. As part$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 remarketing, we entered into new agreementsissuance of $60 million of refunding bonds to and the purchase of $140 million of existing bonds by a syndicate of banks. Our relationship with remarketing agents to resellthe syndicate of banks regarding the bonds to investors. We established newis governed by an agreement that contains representations, warranties, covenants and default provisions consistent with our other financing arrangements. All of the bonds remain floating-rate instruments and we anticipate interest expense savings of approximately $2 million annually over the 5.5 year term of the agreement. AGL Resources had no cash receipts or payments in connection with the refinancing. The letters of credit to provideproviding credit enhancement tosupport for the bonds. The weighted average interest rates on our variable rateretired bonds, during 2010 ranged from 0.23% to 0.36%.along with other related agreements, were terminated as a result of the refinancing.
Senior notes

In August 2009,April 2013, our $225 million 4.45% senior notes matured. Repayment of these senior notes was funded through our commercial paper program. In May 2013, we issued $300$500 million of 10-yearin 30-year senior notes at an interest rate of 5.25%. Thewith net proceeds from the offering were approximately $297 million. Weof $494 million used the net proceeds from the sale of the senior notes to repay a portion of our short-term debt.

We had $300AGL Capital’s commercial paper, including $225 million ofwe borrowed to repay our senior notes that matured in January 2011,April 2013.

Nicor Merger Financing The total value of the consideration paid to Nicor common shareholders was $2.5 billion. Upon closing the merger, we assumed the first mortgage bonds of Nicor Gas, which as ofat December 31, 2010,2011 had principal balances totaling $500 million and maturity dates between 2016 and 2038. These bonds were reported asrecorded at their estimated fair value of $599 million on the currentdate the merger closed. Additionally, we assumed $424 million in short-term debt upon closing the merger.

During 2011, we secured the permanent debt financing we used to pay the cash portion of the purchase consideration. This included approximately $200 million from our $500 million in senior notes that were issued in March 2011, $500 million in senior notes that were issued in September 2011, and $275 million in senior unsecured notes that were issued in the private placement market in October 2011.

For more information on our financing activities, see short and long-term debt on our Consolidated Statements of Financial Position. These senior notes were repaid in January 2011 with $150 million of our commercial paperwithin “Liquidity and $150 million borrowed under our Term Loan Facility.Capital Resources.”

Noncontrolling Interest We recorded cash distributions for SouthStar’s dividend distributions to Piedmont of $27$17 million in 2010, $202013, $14 million in 20092012 and $30$16 million in 20082011 in our Consolidated StatementStatements of Cash Flows as financing activities.activities. The primary reason for the increase in the distribution to Piedmont during the current year was increased earnings for 2012 compared to 2011 and a distribution of excess working capital from the joint venture in 2013. Additionally, we received $22.5 million from Piedmont in 2013 to maintain their 15% ownership interest after we contributed our Illinois Energy business to the SouthStar joint venture.

Dividends on Common Stock Our common stock dividend payments were $133$222 million in 2010, $1272013, $203 million in 20092012 and $124$148 million in 2008.2011. The increases were generally the result of the annual dividend increasesincrease of $0.04 per share for each of the last three years. However, as a result of the Nicor merger, AGL Resources shareholders of record as of the close of business on December 8, 2011 received a pro rata dividend of $0.0989 per share for the stub period, which accrued from November 19, 2011 and totaled $7 million. The dividend payments made in February 2012 were reduced by this stub period dividend. For information about restrictions on our ability to pay dividends on our common stock, see Note 2 “Significant Accounting Policies and Methods of Application.”9 to our consolidated financial statements under Item 8 herein.

40


For the year ended December 31, 2010, we purchased approximately 0.2 million shares of our common stock at a weighted average cost of $36.01 per common share and an aggregate cost of $7 million. For the years ended December 31, 2009 and 2008, we did not purchase shares of our common stock. We currently anticipate holding the purchased shares as treasury shares. For more information on our common share repurchases see Item 5 “Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.”

Shelf Registration On August 17, 2010,In July 2013, we filed a shelf registration statement with the SEC, which expires in 2013. Debt2016. Under this shelf registration statement, debt securities will be issued by AGL Capital and related guarantees issued under the shelf registration will be issued by AGL CapitalResources under an indenture dated as of February 20, 2001, as supplemented and modified, as necessary, among AGL Capital, AGL Resources and The Bank of New York Mellon Trust Company, N.A., as trustee. The indenture provides for the issuance from time to time of debt securities in an unlimited dollar amount and an unlimited number of series, subject to our AGL Credit Facility and Term Loan Facility financial covenantscovenant related to total debt to total capitalization. The debt securities will be guaranteed by AGL Resources.

Off-balance sheet arrangements We have certain guarantees, as further described in Note 11 to our consolidated financial statements under Item 8 herein. We believe the likelihood of any such payment under these guarantees is remote. No liability has been recorded for these guarantees.

Contractual Obligations and Commitments We have incurred various contractual obligations and financial commitments in the normal course of our operating and financing activitiesbusiness that are reasonably likely to have a material effect on liquidity or the availability of requirements for 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. Contingent financial commitments represent obligations that become payable only if certain predefined events occur, such as financial guarantees, and include the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor.
The following table illustrates our expected future contractual obligation payments such as debt and lease agreements, and commitments and contingencies as of December 31, 2010.2013.

       2012 &  2014 &  2016 &                    2019 & 
In millions Total  2011  2013  2015  thereafter  Total  2014  2015  2016  2017  2018  thereafter 
Recorded contractual obligations:                                    
                                    
Long-term debt(1) $1,673  $-  $242  $200  $1,231  $3,706  $-  $200  $545  $22  $155  $2,784 
Short-term debt (1)
  1,033   1,033   -   -   -   1,171   1,171   -   -   -   -   - 
Environmental remediation liabilities (2)
  447   70   82   80   48   63   104 
Pipeline replacement program costs (2)
  228   62   166   -   -   5   5   -   -   -   -   - 
Environmental remediation liabilities (2)
  143   14   62   53   14 
Total $3,077  $1,109  $470  $253  $1,245  $5,329  $1,246  $282  $625  $70  $218  $2,888 

Unrecorded contractual obligations and commitments (3) (9):
               
Unrecorded contractual obligations and commitments (3) (8):
                     
                                    
Pipeline charges, storage capacity and gas supply (4)
 $1,899  $523  $663  $262  $451  $2,298  $733  $507  $299  $138  $102  $519 
Interest charges (5)
  897   89   166   144   498   2,899   185   175   161   147   145   2,086 
Operating leases (6)
  95   22   30   13   30   233   39   34   28   25   18   89 
Pension contributions (7)
  30   30   -   -   - 
Asset management agreements (8)  15   10   3   2   - 
Standby letters of credit, performance /
surety bonds (10)
  14   12   2   -   - 
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 $2,950  $686  $864  $421  $979  $5,493  $1,000  $724  $495  $314  $266  $2,694 
(1)  Includes current portionExcludes the $82 million step up to fair value of long-termfirst mortgage bonds, $16 million unamortized debt of $300premium and $9 million which matured and was repaid in January 2011.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 amountbalance includes amounts for Nicor Gas and SouthStar gas commodity purchase commitments of 1431 Bcf at floating gas prices calculated using forward natural gas prices as of December 31, 2010,2013, and is valued at $63$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 debt isinterest charges are calculated based on the interest rate as of December 31, 20102013 and the maturity date of the underlying debt instrument. As of December 31, 2010,2013, we have $40$52 million of accrued interest on our Consolidated Statements of Financial Position that will be paid in 2011.2014.
(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 authoritative guidance related to leases. However, this lease accounting treatment does not affect the future annualOur operating lease cash obligations as shown herein. We expect to fund these obligations with cash flow from operating and financing activities.leases are primarily for real estate.
(7)  Based on the current funding status of the plans, we would be required to make a minimum contribution to our pension plans of approximately $30 million in 2011. We may make additional contributions in 2011.
(8)  
Represent fixed-fee minimum payments for Sequent’s affiliated asset management agreements..
(9)(8)  The Merger Agreement with Nicor contains termination rights for both us and Nicor and provides that, if we terminate the agreement under specified circumstances, we may be required to pay a termination fee of $67 million. In addition, if we terminate the agreement due to a failure to obtain the necessary financing for the transaction, we may also be required to pay Nicor $115 million.
(10)  
We provide guarantees to certain municipalities and other agencies and certain gas suppliers of SouthStar in support of payment obligations.
obligations.

Standby letters of credit and performance / performance/surety bonds. We also have incurred various financial commitments in the normal course of business. Contingent financial commitments represent obligations that become payable only if certain predefined events occur, such as financial guarantees, and include the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor. We would expect to fund these contingent financial commitments with operating and financing cash flows.

Pension and postretirementother retirement obligations. Generally, our funding policy is to contribute annually an amount that will at least equal the minimum amount required to comply with the Pension Protection Act. Additionally, weWe calculate any required pension contributions using the traditional unit credit cost method. However,method; however, additional voluntary contributions are made from time to time as considered necessary.periodically made. Contributions are intended to provide not only for benefits attributed to service to date, but also for those expected to be earned in the future. The contributions represent the portion of the postretirementother retirement costs which we are responsible for under the terms of our plan and minimum funding required by state regulatory commissions.


The state regulatory commissions in all of our jurisdictions, except Illinois, have phase-ins that defer a portion of the postretirementretirement benefit expenseexpenses for retirement plans other than pensions for future recovery. We recorded a regulatory asset for these future recoveries of $9$108 million as of December 31, 20102013 and $10$215 million as of December 31, 2009.2012. In addition, we recorded a regulatory liability of $6 million as of December 31, 2010 and $5 million as of December 31, 2009 for our expectedIllinois, all accrued retirement plan expenses under the AGL Postretirement Plan.are recovered through base rates. See Note 5 “Employee Benefit Plans,”6 to our consolidated financial statements under Item 8 herein for additional information about our pension and postretirementother retirement plans.

In 2010, we contributed $31 million2013, no contributions were required to our qualified pension plans.plans. In 2009,2012, we contributed $24$40 million to ourthese qualified pension plans. Effective December 31, 2012, we merged the NUI Pension and Nicor Pension plans into the AGL Pension plan. Based on the current fundingestimated funded status of the plans,merged AGL Pension plan, we would bedo not expect any required to make a minimum contribution to the plans of approximately $30 millionplan in 2011.2014. We are planningmay, at times, elect to makecontribute additional contributions in 2011 upamounts to $31 million, for a total of up to $61 million, in order to preserve the current level of benefits under the plans andAGL Pension Plan in accordance with the funding requirements of the Pension Protection Act.Act.

Critical Accounting Policies and Estimates

The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts in our consolidated financial statements and accompanying notes. Those judgments and estimates have a significant effect on our financial statements, because they result primarily fromdue to the need to make estimates about the effects of matters that are inherently uncertain. Actual results could differ from those estimates. We frequently re-evaluatereevaluate our judgments and estimates that are based upon historical experience and various other assumptions that we believe to be reasonable under the circumstances.

We believe that The following is a summary of our significantmost critical accounting policies, described in Note 2 of the Notes to Consolidated Financial Statements, the following representswhich represent those that may involve a higher degree of uncertainty, judgment and complexity; these include Regulatory Infrastructure Program Liabilities, Environmental Remediation Liabilities, Derivatives and Hedging Activities, Contingencies, Pension and Other Postretirement Plans and Income Taxes.complexity. Our significant accounting policies are described in Note 2 to our consolidated financial statements under Item 8 herein.

Regulatory Infrastructure Program LiabilitiesAccounting for Rate-Regulated Subsidiaries

We record regulatory assets and liabilities in our Consolidated Statementsaccount for the financial effects of Financial Positionregulation in accordance with authoritative guidance related to regulated entities. We recordentities 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 costsestimated expenditures that have not yet been deferred for whichincurred. Generally, regulatory assets are amortized into expense and regulatory liabilities are amortized into income over the period authorized by the regulatory commissions. At December 31, 2013, our regulatory assets were $899 million and regulatory liabilities were $1.7 billion. At December 31, 2012, our regulatory assets were $1.1 billion and regulatory liabilities were $1.6 billion.

We believe 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 recovery is probablerate proceedings. We are not aware of any evidence that these costs will not be recoverable through either rate riders or base rates, specifically authorizedand 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 may 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 athe state regulatory commission. We recordcommissions. As a result, we believe that the accounting prescribed under the guidance remains appropriate. It is also our opinion that all regulatory liabilities when it isassets are probable of recovery in future rate proceedings, and therefore we have not recorded any regulatory assets that revenues will be reduced for amounts that will be credited to customers through theare recoverable but are not yet included in base rates or contemplated in a rate making process.

By order of the Georgia Commission, our wholly-owned subsidiary, 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 costs incurred to dateliabilities that do not represent revenue collected from customers for expenditures that have not yet been recoveredincurred are refunded to ratepayers through a rate riders, and (ii)rider or base rates. If the future expected costsregulatory liability is included in base rates, the amount is reflected as a reduction to be recovered throughthe rate riders.base in setting rates.

The determination of future expected costs associated with our pipeline replacement program liabilities involves judgment. Factors that must be considered in estimating the future expected costs are:

·  projected capital expenditure spending, including labor and material costs
·  the remaining pipeline footage to be replaced for remainder of the program
·  changes in the regulatory environment or our completive position
·  passage of new legislation
·  changes in accounting guidance

To the extent that circumstances associated with regulatory balances change, the regulatory balances are adjusted accordingly.

We recorded a long-term liability of $166 million as of December 31, 2010 and $155 million as of December 31, 2009, which represented engineering estimates for remaining capital expenditure costs in the pipeline replacement program. As of December 31, 2010, we had recorded a current liability of $62 million, representing expected pipeline replacement program expenditures for the next 12 months. We report these estimates on an undiscounted basis. If Atlanta Gas Light’s pipeline replacement program expenditures, subject to future recovery, were $10 million higher or lower its incremental expected annual revenues would have changed by approximately $1 million. Detailsmajority of our regulatory assets and liabilities are discussedincluded in Note 2.

Environmental Remediation Liabilities

Webase rates except for the recoverable regulatory infrastructure program costs, recoverable ERC, energy efficiency plans, the bad debt rider and accrued natural gas costs, which are subject to legislationrecovered through specific rate riders on a dollar-for-dollar basis. The rate riders that authorize the recovery of regulatory infrastructure program costs and regulation by federal, statenatural gas costs include both a recovery of cost and local authorities with respect to environmental matters. Additionally, we owned and operated a number of MGP sites at which hazardous substances may be present. In accordance with GAAP, we have established reservesreturn on investment during the recovery period. Nicor Gas’ rate riders for environmental remediation obligations when itcosts and energy efficiency costs provide a return of investment and expense including short-term interest on reconciliation balances. However, there is probable that a liability exists andno interest associated with the amountunder or rangeover collections of amounts can be reasonably estimated. We historically reported estimates of future environmental remediation costs based on probabilistic models of potential costs. We presently report estimates of future remediation costs on an undiscounted basis. These estimates contain various engineering uncertainties, and we continuously attempt to refine these estimates.bad debt expense.

In GeorgiaOur natural gas distribution operations and Florida, we have confirmed 14 former MGP sites where Atlanta Gas Light owned or operated all or partcertain regulated transmission and storage operations meet the criteria of a cost-based, rate-regulated entity under accounting principles generally accepted in the U.S. Accordingly, the financial results of these sites. Atlanta Gas Light’s environmental remediation liabilityoperations reflect the effects of the ratemaking and accounting practices and policies of the various regulatory commissions to which we are subject.

As a result, certain costs that would normally be expensed under accounting principles generally accepted in the U.S. are permitted to be capitalized or deferred on the balance sheet because it is includedprobable that they can be recovered through rates. Further, regulation may impact the period in its correspondingwhich revenues or expenses are recognized. The amounts to be recovered or recognized are based upon historical experience and our understanding of the regulations.

Discontinuing the application of this method of accounting for regulatory asset. Our recoveryassets and liabilities could significantly increase our operating expenses, as fewer costs would likely be capitalized or deferred on the balance sheet, which could reduce our net income. Assets and liabilities recognized as a result of these environmental remediation costs is subject to review by the Georgia Commission, which may seek to disallow the recovery of some expenses.
We have identified 6 former operating sitesrate regulation would be written off as extraordinary items in New Jersey, where Elizabethtown Gas is currently conducting remediation activities with oversight from the New Jersey Department of Environmental Protection. The New Jersey BPU has authorized Elizabethtown Gas to recover prudently incurred remediation costsincome for the New Jersey properties through its remediation adjustment clause.

We also own remediation sitesperiod in other states. One site,which the discontinuation occurred. A write-off of all our regulatory assets and regulatory liabilities at December 31, 2013, would result in Elizabeth City, North Carolina, is subject to an order by the North Carolina Department of Environment6% and Natural Resources. There is one other site15% decreases in North Carolina where investigationtotal assets and remediation is possible. We do not believe costs associated with this site can be reasonably estimated. There are no cost recovery mechanisms for the environmental remediation sites in North Carolina.

We cannot perform precise engineering soil and groundwater clean up estimates for certain of our former MGP sites. As we continue to conduct the actual remediation and enter into cleanup contracts, we are increasingly able to provide conventional engineering estimates of the likely costs of many elements of the remediation program. The following table providestotal liabilities, respectively. For more information on our former operating sites:regulated assets and liabilities, see Note 3 to our consolidated financial statements under Item 8 herein.

In millions Cost estimate range  Amount recorded  Expected costs over next twelve months 
Georgia and Florida $57 - $105  $57  $3 
New Jersey  75 - 138   75   10 
North Carolina  11 - 16   11   1 
Total $143 - $259  $143  $14 
Impairment of Goodwill and Long-Lived Assets, including Intangible Assets

Goodwill We do not amortize our goodwill, but test it for impairment at the reporting unit level during the fourth fiscal quarter 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. A reporting unit is the operating segment, or a business one level below the operating segment (a component), if discrete financial information is prepared and regularly reviewed by management. Components are aggregated if they have similar economic characteristics.

As part of our impairment test, an initial assessment is made by comparing the fair value of a reporting unit with its carrying value, including goodwill. If the fair value is less than the carrying value, an impairment is indicated, and we must perform a second test to quantify the amount of the impairment. In accordancethe second test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the reporting unit from the fair value of the entire reporting unit determined in step one of the assessment. If the carrying value of the goodwill exceeds the implied fair value of the goodwill, we record an impairment charge. To estimate the fair value of our reporting units, we use two generally accepted valuation approaches, an income approach and a market approach, using assumptions consistent with GAAP we have recordeda market participant’s perspective. 

Under the lowerincome approach, fair value is determined based upon 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. These forecasts contain a degree of uncertainty, and changes in these projected cash flows could significantly increase or decrease the estimated fair value of the 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 included 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, 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.

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

The goodwill impairment testing develops a baseline test and performs a sensitivity analysis to calculate a reasonable valuation range. Beyond 2012, these costs cannot beThe sensitivities are derived by altering those assumptions which are subjective in nature and inherent to a discounted cash flows calculation. We weight the results of the two valuation approaches to estimate the fair value of each reporting unit.

The significant assumptions that drive the estimated and considerable variability remains in available estimates. Detailsfair values of our environmental remediation costsreporting units are discussedprojected 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 value of all but one of our reporting units with goodwill was in excess of the carrying value by approximately 20% to almost 500%, and none of these reporting units were at risk of failing step one of the impairment test.

Within our midstream operations segment, the estimated fair value of the 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 will likely 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. For more information, see “Acquisitions” in Note 2 to our consolidated financial statements under Item 8 herein.

We will continue to monitor this reporting unit for impairment and Note 10.note that continued declines in contracted 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 future failure of the step 1 goodwill impairment test and may also result in a future impairment of goodwill. If subscription rates and subscribed volumes decline, the estimated future cash flows will decrease from our current estimates. As of December 31, 2013, we estimate that 15% of our future cash flows will be received over the next 10 years, an additional 20% over the following 10 years and 65% in periods thereafter over the remaining useful lives of our storage facilities. 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 based on the basis of undiscounted cash flows over their remaining useful lives.

Long-Lived Assets We depreciate or amortize our long-lived assets and other intangible assets, over their estimated useful lives. Currently, we have no indefinite-lived intangible assets. We assess our long-lived assets and other intangible assets for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount 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 the expected future cash flows. An impairment is indicated if the carrying amount of a 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; however, if our storage facilities within midstream operations experience further natural gas price declines or a prolonged slow recovery, future analyses may result in an impairment of long-lived assets.

Derivatives and Hedging Activities

The authoritative guidance to determine whether a contract meets the definition of a derivative instrument, contains an embedded derivative requiring bifurcation, or qualifies for hedge accounting treatment is voluminous and complex. The treatment of a single contract may vary from period to period depending upon accounting elections, changes in our assessment of the likelihood of future hedged transactions or new interpretations of accounting guidance. As a result, judgment is required in determining the appropriate accounting treatment. In addition, the estimated fair value of derivative instruments may change significantly from period to period depending upon market conditions, and changes in hedge effectiveness may impact the accounting treatment.

The authoritative guidance related to derivatives and hedging requires that every derivative financial instrument (including certain derivative instruments embedded in other contracts) be recorded inon the statementsConsolidated Statements of financial positionFinancial Position as either an asset or liability measured at its fair value. However, if the derivative transaction qualifies for and is designated as a normal purchase andor normal sale, it is exempted from the fair value accounting treatment and is, instead, subject to traditional accrual accounting. We utilize market data or assumptions that market participants would use in pricing the derivative asset or liability, including assumptions about risk and the risks inherent in the inputs of the valuation technique.

The authoritative accounting guidance requires that changes in the derivative’sderivatives’ fair value are recognized concurrently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, the guidance allows a derivative’sderivative gains and losses to offset related results onof the hedged item in the income statement in the case of a fair value hedge, or to record the gains and losses in OCI until the hedged transaction occurs in the case of a cash flow hedge. Additionally, the guidance requires that a company formally designate a derivative as a hedge as well as document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting treatment.
Nicor Gas and Elizabethtown Gas utilize derivative instruments to hedge the price risk for the purchase of natural gas for customers. These derivatives are reflected at fair value and are not designated as accounting hedges. Realized gains or losses on such instruments are included in the cost of gas delivered and are passed through directly to customers, subject to review by the applicable state regulatory commissions, and therefore have no direct impact on earnings. Unrealized changes in the fair value of these derivative instruments are deferred as regulatory assets or liabilities.

We use derivative financial instruments primarily to reduce the impact to our results of operations due to the risk of changes in the price of natural gas. The fair value of natural gas derivative financial instruments we useused to manage exposures arising fromour exposure to changing natural gas prices reflects the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. For the derivatives utilized in retail operations and wholesale services that are not designated as accounting hedges, changes in fair value are reported as gains or losses in our results of operations in the period of change. Retail operations records derivative gains or losses arising from cash flow hedges in OCI and reclassifies them into earnings in the same period that the underlying hedged item is recognized in earnings.

Additionally, as required by the authoritative guidance, we are required to classify our derivative financial assets and liabilities 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.hierarchy. The determination of the fair value of our derivative instruments incorporates various factors required under the guidance. These factors include:


·  the credit worthiness of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit);
·  events specific to a given counterpartycounterparty; and
·  
the impact of our nonperformance risk on our liabilities.liabilities.
 
We have recorded derivative financial instrument assets of $228$119 million at December 31, 20102013 and $238$144 million at December 31, 2009.2012. Additionally, we have recorded derivative financial liabilities of $48$80 million at December 31, 20102013 and $62$39 million at December 31, 2009. In 2010, we2012. We recorded $46 million of losses and in 2009 we recorded $15 million of losses on our Consolidated Statements of Income.Income of $97 million in 2013 and gains of $10 million in 2012 and $24 million in 2011.

If there is a significant change in the underlying market prices or pricing assumptions we use in pricing our derivative assets or liabilities, we may experience a significant impact on our financial position, resultresults of operations and cash flows. Our derivative and hedging activities are described in further detail in Note 2 and Note 5 to our consolidated financial statements under Item 8 herein and Item 1, “Business”.“Business.”

Contingencies

Our accounting policies for contingencies cover a variety of activities that are incurred in the normal course of business activities, includingand generally relate to contingencies for potentially uncollectible receivables, rate matters, and legal and environmental exposures. We accrue for these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered, and an amount can be reasonably estimated in accordance with authoritative guidance related to contingencies.estimated. We base our estimates for these liabilities on currently available facts and our estimates of the ultimate outcome or resolution of the liability in the future.

Actual results may differ from estimates, and estimates can be, and often are, revised either negatively or positively depending on actual outcomes or changes in the facts or expectations surrounding each potential exposure. Changes in the estimates related to contingencies could have a negative impact on our consolidated results of operations, cash flows or financial position. Our contingencies are further discussed in Note 10.11 to our consolidated financial statements under Item 8 herein.

Pension and Other PostretirementRetirement Plans

Our pension and other postretirementretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates. We annually review the estimates and assumptions underlying our pension and other postretirementretirement plan costs and liabilities and update them when appropriate.

appropriate.The critical actuarial assumptions used to develop the required estimates for our pension and postretirementother retirement plans include the following key factors:

·  assumed discount rates
·  expected return on plan assets
·  the market value of plan assets
·  assumed mortality table
·  assumed rates of retirement.
·assumed discount rates;
·expected return on plan assets;
·     the market value of plan assets;
·assumed mortality table;
·assumed health care costs;
·assumed compensation increases;
·assumed rates of retirement; and
·assumed rates of termination.

The discount rate is utilized in calculating the actuarial present value of our pension and postretirementother retirement obligations and our annual net pension and postretirementother retirement costs. When establishing our discount rate, with the assistance of our actuaries, we consider certain market indices, including Moody’s Corporate AA long-term bond rate, the Citigroup Pension Liability rate, other high-grade bond indices and aindices. The single equivalent discount rate is derived utilizing the forecasted future cash flows in each year toby applying the appropriate spot rates based on high quality (AA or better) corporate bonds.bonds that have a yield higher than the regression mean yield curve, to the forecasted future cash flows in each year for each plan.

The expected long-term rate of return on assets is used to calculate the expected return on plan assets component of our annual pension and postretirement plan cost.other retirement plans costs. We estimate the expected return on plan assets by evaluating expected bond returns, equity risk premiums, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider guidance from our investment advisors in making a final determination of our expected rate of return on assets. To the extent the actual rate of return on assets realized over the course of a year is greater than or less than the assumed rate, that year’s annual pension or postretirementother retirement plan cost is not affected. Rather,affected; rather, this gain or loss reduces or increases future pension or postretirementother retirement plan costs.

Equity market performance and corporate bond rates have a significant effect on our reported results. For our largestthe AGL pension plan, market performance also effectsaffects our market-related value of plan assets (MRVPA), which is a calculated value and differs from the actual market value of plan assets. The MRVPA recognizes differences between the actual market value and expected market value of our plan assets and is determined by our actuaries using a five-year movingsmoothing weighted average methodology. Gains and losses on plan assets are spread through the MRVPA based on the five-year movingsmoothing weighted average methodology, which affects the expected return on plan assets component of pension expense.
In addition, differences between actuarial assumptions and actual plan resultsexperience are deferred and amortized into cost when the accumulated differences exceed 10% of the greater of the projected benefit obligation (PBO) or the MRVPA for our largestthe AGL pension plan. If necessary, theThe excess, if any, is amortized over the average remaining service period of active employees.

During 2010,2013, we recorded net periodic benefit costs of $17$57 million (pre-capitalization) related to our defined pension and postretirementother retirement benefit costs.plans. We estimate that in 2011,2014, we will record net periodic pension and other postretirementretirement benefit costs in the range of $38 million to $42 million (pre-capitalization), a $15 million to $19 million to $21 million, a $2 million to $4 million increasedecrease compared to 2010.2013. In determining our estimated expenses for 2011,2014, our actuarial consultant assumed an 8.75%the following expected return on plan assets and a discount rate of 5.40% for the AGL Retirement Plan and 5.20% for the NUI Retirement Plan and for our postretirement plan.rates:

  Pension plans  Other retirement plans 
Discount rate  5.00%  4.70%
Expected return on plan assets  7.75%  7.75%

The actuarial assumptions we use may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal and retirement rates, and longer or shorter life spans of participants. The following table illustrates the effect of changing the critical actuarial assumptions for our pension and postretirementother retirement plans while holding all other assumptions constant.constant:

Dollars in millions
Percentage-point
change in assumption
  In millions
Actuarial assumptionsPercentage-point change
Increase (decrease)
 in assumptionPBO/ APBO
  
Increase (decrease)
 in APBO
Increase (decrease) in cost 
Expected long-term return on plan assets  +/- 1% $- / -  $(4)(9) / 49 
Discount rate  +/- 1% $(80)(154) / 90171  $(7)(13) / 713 

See Note 54 and Note 6 to our consolidated financial statements under Item 8 herein for additional information on our pension and postretirement plans.other retirement plans.

Income Taxes

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 account for income taxes in accordance with the authoritative guidance related to income taxes,, which requires that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax basis of recorded assets and liabilities. The guidance also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assetassets will not be realized.realized.

This liability isDeferred tax liabilities are estimated based on the expected future tax consequences of items recognized in the financial statements. Additionally, during the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. As a result, we recognize tax liabilities based on estimates of whether additional taxes and interest will be due. After application of the federal statutory tax rate to book income, judgment is required with respect to the timing and deductibility of expense in our income tax returns.

A deferred income tax liability is not recorded on undistributed foreign earnings that are expected, in our judgment, 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 and we would be required to record a deferred tax liability of $31 million if we no longer asserted indefinite reinvestment of undistributed foreign earnings.

For state income tax and other taxes, judgment is also required with respect to the apportionment among the various jurisdictions. A valuation allowance is recorded if we expect that it is more likely than not that our deferred tax assets will not be realized. In addition, we operate within multiple tax jurisdictions and we are subject to auditaudits in these jurisdictions. These audits can involve complex issues, which may require an extended period of time to resolve. We maintain a liability for the estimate of potential income tax exposure and, in our opinion, adequate provisions for income taxes have been made for all years.years reported.

We had a $3$22 million valuation allowance on $109$216 million of deferred tax assets ($147 million of long term and $69 million of current) as of December 31, 2010,2013, reflecting the expectation that most of these assets will be realized. Our netgross long-term deferred tax liability totaled $768$1,800 million at December 31, 2010.2013. See Note 1112 to our consolidated financial statements under Item 8 herein for additional information on our taxes.


In January 2010, the FASB issued authoritative guidance to improve fair value measurement disclosures. The guidance requires us to separately disclose significant transfers of amounts between Levels 1 and 2 and the reasons for the transfers. In addition, the reconciliation of fair value measurements using significant unobservable inputs (Level 3) should separately present transfers in/out of Level 3 as well as purchases, sales, issuances and settlements. We are required to present fair value measurements for each class of assets and liabilities anddetermine whether tax benefits claimed or expected to disclosebe claimed on our valuation techniques and inputs used to measure fair value. The amended guidance became effective for us on January 1, 2010, with the exception of the presentation of Level 3 fair value measurements, which willtax return should be effective for us on January 1, 2011. The adoption of this guidance did not have a material impact onrecorded in our consolidated financial statements. For more information on our fair value measurements, see Note 3.

In December 2010,Under this guidance, we may recognize the FASB provided additional guidance for performing Step 1 of the test for goodwill impairment whentax benefit from an entity has reporting units with zero or negative carrying values. Under the new guidance, Step 2 of the goodwill impairment test must be performed when adverse qualitative factors indicate that goodwilluncertain tax position only if it is more likely than not impaired. Althoughthat the guidancetax position will be effective for ussustained on January 1, 2011, our goodwill impairment analysis forexamination by the years endedtaxing 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, 2010 and 2009 indicates that the fair values of our reporting units substantially exceed their carrying values, and2013, we did not take a goodwill impairment charge in the current year nor do we expect to take a charge in future years. The amended guidance is not expected to have a material impact on our consolidated financial statements.
In December 2010, the FASB issued clarification of the accounting guidance around disclosure of pro forma information for business combinations that occur in the current reporting period. The guidance requires us to present pro forma information in our comparative financial statements as if the acquisition date for any business combinations taking place in the current reporting period had occurred at the beginning of the prior year reporting period. We will adopt this guidance effective January 1, 2011,interest and include any required pro forma information for our proposed mergerpenalties associated with Nicor, which is expected to be completed in the second half of 2011.uncertain tax positions.

ITEM 7A.7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to risks associated with natural gas prices, interest rates, credit and credit.fuel prices. Natural gas price risk is defined as the potential loss that we may incur as a result ofresults from changes in the fair value of natural gas. Interest rate risk results fromis 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 Risk Management Committee (RMC)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 RiskRisks

Retail EnergyDistribution Operations SouthStar’sOur 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 derivative instruments is governed by a risk management policy, approvednatural gas and monitored byto 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 Finance and Risk Management Committee, which prohibits the use of derivatives for speculative purposes.end-use customers, it has no natural gas price risk.

SouthStarNicor 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.

Retail Operationsand Wholesale Services We routinely utilizesutilize various types of derivative financial instruments to mitigate certain natural gas price and weather riskrisks 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. This includes the active management ofRetail 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. SouthStar uses theseThese 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 itsour exposure to declining operating margins.

Wholesale Services Sequent routinely uses various types of derivative financial instruments to mitigate certain natural gas price 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 financial swap agreements.

Energy InvestmentsMidstream Operations Golden Triangle Storage usesWe use derivative financial instruments to reduce itsour 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 the cavernour caverns (de-water gas) during the construction of storage caverns.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 financial instruments for asset optimization purposes.

Consolidated The following tables include the fair values and average values of our consolidated derivative financial instruments as of the dates indicated. We base the average values on monthly averages for the 12 months ended December 31, 20102013 and 2009.2012.
 
 Derivative financial instruments average fair values at December 31,  
Derivative instruments average values (1)
at December 31,
 
In millions 
2010 (1)
  
2009 (1)
  2013  2012 
Asset $226  $194  $107  $208 
Liability  70   97   49   101 
(1)  Excludes cash collateral amounts.

  Derivative financial instruments fair values netted with cash collateral at December 31, 
In millions 2010  2009 
Asset $228  $240 
Liability  48   62 
46
  
Derivative instruments fair values netted with cash collateral
at December 31,
 
In millions 2013  2012 
Asset $119  $144 
Liability  80   39 


The following tables illustratetable illustrates the change in the net fair value of our derivative financial instruments during the twelve12 months ended December 31, 2010, 20092013, 2012 and 2008,2011, and provide detailsprovides detail of the net fair value of contracts outstanding as of December 31, 2010, 20092013, 2012 and 2008.2011.

In millions 2010  2009  2008 
Net fair value of derivative financial instruments outstanding at beginning of period $121  $65  $68 
Derivative financial instruments realized or otherwise settled during period  (117)  (54)  (60)
Net fair value of derivative financial instruments acquired during period  -   50   - 
Change in net fair value of derivative financial instruments  71   60   57 
Net fair value of derivative financial instruments outstanding at end of period  75   121   65 
Netting of cash collateral  105   57   129 
Cash collateral and net fair value of derivative financial instruments outstanding at end of period (1)
 $180  $178  $194 
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 financial instruments outstanding includes less than $1$3 million premium and associated intrinsic value at December 31, 2010, $2 million at December 31, 2009 and2013, $4 million at December 31, 20082012 and $3 million at December 31, 2011 associated with weather derivatives.

The sources of our net fair value at December 31, 2010,2013 are as follows.

In millions 
Prices actively quoted
(Level 1) (1)
  
Significant other observable inputs
(Level 2) (2)
 
Mature through 2011 $(32) $82 
Mature 2012 - 2013  (17)  31 
Mature 2014 - 2016  -   11 
Total derivative financial instruments (3)
 $(49) $124 
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.

Value-at-risk 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 immaterial, permitting us to operate within relatively low VaR limits.mitigated. We employ daily risk testing, using both VaR and stress testing, to evaluate the risks of our open positions.

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, 2010, 20092013, 2012 and 20082011 were less than $0.1 million and Sequent had the following VaRs.VaRs.

In millions 2010  2009  2008  2013  2012  2011 
Period end $1.6  $2.4  $2.5  $4.7  $1.8  $2.2 
12-month average  1.3   1.8   1.8   2.3   2.0   1.6 
High  3.0   3.3   3.1   4.9   4.8   3.1 
Low  0.7   0.7   0.8   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 $892 million$1.4 billion of variable-rate debt which includes $732 million of our variable-rate short-term debt and $160 million of variable-rate gas facility revenue bonds outstanding at December 31, 2010,2013, a 100 basis point change in market interest rates from 0.4% to 1.4% would have resulted in an increase in pretaxpre-tax interest expense of $9$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 eleven12 certificated and active Marketers in Georgia for its services. The credit risk exposure to Marketers varies with the time of the 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 2010,2013, the four largest Marketers based on customer count which includes SouthStar, accounted for approximately 31%16% of our consolidated operating margin and 43%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.

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 Energy Operations SouthStar obtainsWe obtain credit scores for itsour firm residential and small commercial customers using a national credit reporting agency, enrolling only those customers that meet or exceed SouthStar’sour credit threshold.

SouthStar considers We consider potential interruptible and large commercial customers based on a reviewreviews of publicly available financial statements and review of commercially available credit reports. Prior to entering into a physical transaction, SouthStarwe also assignsassign 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 Sequent hasWe have established credit policies to determine and monitor the creditworthiness of counterparties, as well as the quality of pledged collateral. SequentWe also utilizesutilize master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Sequent iswe are engaged in more than one outstanding derivative transaction with the same counterparty and itwe also hashave 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 Sequent’sour credit risk. SequentWe also usesuse other netting agreements with certain counterparties with whom it conductswe conduct significant transactions .transactions. Master netting agreements enable Sequentus to net certain assets and liabilities by counterparty. SequentWe also netsnet across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions.

Additionally, Sequentwe may require counterparties to pledge additional collateral when deemed necessary. Sequent conductsWe conduct credit evaluations and obtainsobtain appropriate internal approvals for itsa 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, Sequent requireswe require credit enhancements by way of guaranty, cash deposit or letter of credit for transaction counterparties that do not have investment grade ratings.

Sequent, which provides services to retail marketers and utility and industrial customers, also hasWe have a concentration of credit risk as measured by itsour 30-day receivable exposure plus forward exposure. As of December 31, 2010,2013, excluding $61$8 million of customer deposits, Sequent’sour top 20 counterparties represented approximately 56%51% of the total counterparty exposure of $598$542 million derived by adding together the top 20 counterparties’ exposures, exclusive of customer deposits, and dividing by the total of Sequent’s counterparties’ exposures..

As of December 31, 2010, Sequent’s2013, our counterparties, or the counterparties’ guarantors, had a weighted average S&P equivalent credit rating of BBB+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. There were no credit defaults with Sequent’s counterparties. The following table shows Sequent’sour third-party natural gas contracts receivable and payable positions.positions.




 
  As of Dec. 31, 
  Gross receivables 
In millions 2010  2009 
Netting agreements in place and counterparty is:      
Investment grade $515  $483 
Non-investment grade  11   12 
No external rating  260   106 
No netting agreements in place and counterparty is:        
Investment grade  2   14 
Amount recorded on statements of financial position $788  $615 
  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 

  As of Dec. 31, 
  Gross payables 
In millions 2010   2009 
Netting agreements in place and counterparty is:     
Investment grade $341  $277 
Non-investment grade  40   34 
No external rating  363   207 
No netting agreements in place and counterparty is:        
Investment grade  -   6 
Amount recorded on statements of financial position $744  $524 

Sequent hasWe 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, Sequentwe would need to post collateral to continue transacting business with some of itsour counterparties. If such collateral were not posted, Sequent’sour 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 between Sequent and itswith our counterparties would have totaled $39$9 million at December 31, 2010,2013, which would not have a material impact to our consolidated results of operations, cash flows or financial condition.



ITEM 8.8.     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, 20102013 and 2009,2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 20102013 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 Com panyCompany maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010,2013, based on criteria established in the Internal Control - Integrated Framework(1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)(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 Overover 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 St ates)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;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 Companycompany are being made only in accordance with authoriz ationsauthorizations of management and directors of the Company;company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’scompany’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, GeorgiaGA
February 9, 20116, 2014



Management’sManagement’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).

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.

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, 2010,2013, 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 9, 20116, 2014


/s/ John W.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



AGL Resources Inc.
Consolidated Statements of Financial Position - Assets

  As of December 31, 
In millions 2010  2009 
Current assets      
Cash and cash equivalents (Note 2) $24  $26 
Receivables (Note 2)        
Energy marketing receivables  788   615 
Gas  204   178 
Unbilled revenues  173   155 
Other  13   29 
Less allowance for uncollectible accounts  16   14 
Total receivables  1,162   963 
Inventories        
Natural gas stored underground  615   649 
Other  24   23 
Total inventories (Note 2)  639   672 
Derivative financial instruments – current portion (Note 2, Note 3 and Note 4)  182   188 
Recoverable regulatory infrastructure program costs – current portion (Note 2)  48   43 
Recoverable environmental remediation costs – current portion (Note 2 and Note 10)  7   11 
Other current assets  100   97 
Total current assets  2,162   2,000 
Long-term assets and other deferred debits        
Property, plant and equipment  6,266   5,939 
Less accumulated depreciation  1,861   1,793 
Property, plant and equipment – net (Note 2)  4,405   4,146 
Goodwill (Note 2)  418   418 
Recoverable regulatory infrastructure program costs (Note 2)  244   223 
Recoverable environmental remediation costs (Note 2 and Note 10)  164   161 
Derivative financial instruments (Note 2, Note 3 and Note 4)  46   52 
Other  79   74 
Total long-term assets and other deferred debits  5,356   5,074 
Total assets $7,518  $7,074 

See Notes to Consolidated Financial Statements.


AGL Resources Inc.
Consolidated Statements of Financial Position - Liabilities and Equity

  As of December 31, 
In millions, except share amounts 2010  2009 
Current liabilities      
Energy marketing trade payable $744  $524 
Short-term debt (Note 3 and Note 7)  732   602 
Current portion of long-term debt (Note 7)  300   - 
Accounts payable – trade  184   196 
Accrued regulatory infrastructure program costs – current portion (Note 2)  62   55 
Customer deposits  52   41 
Accrued wages and salaries  51   56 
Accrued taxes  48   35 
Derivative financial instruments – current portion (Note 2, Note 3 and Note 4)  44   52 
Accrued interest (Note 10)  40   41 
Deferred natural gas costs (Note 2)  19   30 
Accrued environmental remediation liabilities – current portion (Note 2 and Note 10)  14   25 
Other current liabilities  138   115 
Total current liabilities  2,428   1,772 
Long-term liabilities and other deferred credits        
Long-term debt (Note 3 and Note 7)  1,673   1,974 
Accumulated deferred income taxes (Note 2 and Note 11)  768   695 
Accrued pension obligations (Note 3 and Note 5)  186   159 
Accumulated removal costs (Note 2)  182   183 
Accrued regulatory infrastructure program costs (Note 2)  166   155 
Accrued environmental remediation liabilities (Note 2 and Note 10)  129   119 
Accrued postretirement benefit costs (Note 3 and Note 5)  36   38 
Derivative financial instruments (Note 2, Note 3 and Note 4)  4   10 
Other long-term liabilities and other deferred credits  110   150 
Total long-term liabilities and other deferred credits  3,254   3,483 
Total liabilities and other deferred credits  5,682   5,255 
Commitments and contingencies (see Note 10)
        
Equity        
AGL Resources Inc. common shareholders’ equity, $5 par value; 750 million shares authorized  1,813   1,780 
Noncontrolling interest (Note 9)  23   39 
Total equity  1,836   1,819 
Total liabilities and equity $7,518  $7,074 

See Notes to Consolidated Financial Statements.



 
AGL Resources Inc.RESOURCES INC. AND SUBSIDIARIES

  Years ended December 31, 
In millions, except per share amounts 2010  2009  2008 
Operating revenues (Note 2) $2,373  $2,317  $2,800 
Operating expenses            
Cost of gas (Note 2)  1,164   1,142   1,654 
Operation and maintenance  503   497   472 
Depreciation and amortization (Note 2)  160   158   152 
Taxes other than income taxes  46   44   44 
Total operating expenses  1,873   1,841   2,322 
Operating income  500   476   478 
Other (expense) income  (1)  9   6 
Interest expenses, net  (109)  (101)  (115)
Earnings before income taxes  390   384   369 
Income tax expenses (Note 11)  140   135   132 
Net income  250   249   237 
Less net income attributable to the noncontrolling interest (Note 9)  16   27   20 
Net income attributable to AGL Resources Inc. $234  $222  $217 
Per common share data (Note 2)            
Basic earnings per common share attributable to AGL Resources Inc. common shareholders $3.02  $2.89  $2.85 
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders $3.00  $2.88  $2.84 
Cash dividends declared per common share $1.76  $1.72  $1.68 
Weighted average number of common shares outstanding (Note 2)            
Basic  77.4   76.8   76.3 
Diluted  77.8   77.1   76.6 
  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.



AGL Resources Inc.RESOURCES INC. AND SUBISIDIARIES
  AGL Resources Inc. Shareholders       
     Premium on     Accumulated other          
In millions,
except per share amounts
 Common stock  common  Earnings  comprehensive  Treasury  Noncontrolling    
 Shares  Amount  stock  reinvested  loss  shares  interest  Total 
As of December 31, 2007  76.4  $390  $667  $680  $(13) $(63) $47  $1,708 
Net income  -   -   -   217   -   -   20   237 
Other comprehensive loss (Note 8)  -   -   -   -   (121)  -   (5)  (126)
Dividends on common stock ($1.68 per share)  -   -   -   (128)  -   4   -   (124)
Distributions to noncontrolling interests (Note 9)  -   -   -   -   -   -   (30)  (30)
Issuance of treasury shares (Note 8)  0.5   -   (1)  (6)  -   16   -   9 
Stock-based compensation expense (net of tax) (Note 6)  -   -   10   -   -   -   -   10 
As of December 31, 2008  76.9   390   676   763   (134)  (43)  32   1,684 
Net income  -   -   -   222   -   -   27   249 
Other comprehensive income (Note 8)  -   -   -   -   18   -   -   18 
Dividends on common stock ($1.72 per share)  -   -   -   (132)  -   5   -   (127)
Distributions to noncontrolling interests (Note 9)  -   -   -   -   -   -   (20)  (20)
Issuance of treasury shares (Note 8)  0.6   -   (4)  (5)  -   17   -   8 
Stock-based compensation expense (net of tax) (Note 6)  -   -   7   -   -   -   -   7 
As of December 31, 2009  77.5   390   679   848   (116)  (21)  39   1,819 
Net income  -   -   -   234   -   -   16   250 
Other comprehensive (loss) income (Note 8)  -   -   -   -   (33)  -   1   (32)
Dividends on common stock ($1.76 per share)  -   -   -   (136)  -   3   -   (133)
Purchase of additional 15% ownership interest in SouthStar (Note 9)  -   -   (51)  -   (1)  -   (6)  (58)
Distributions to noncontrolling interests (Note 9)  -   -   - �� -   -   -   (27)  (27)
Purchase of treasury shares (Note 8)  (0.2)  -   -   -   -   (7)  -   (7)
Issuance of treasury shares (Note 8)  0.7   1   (5)  (3)  -   22   -   15 
Stock-based compensation expense (net of tax) (Note 6)  -   -   8   -   -   1   -   9 
As of December 31, 2010  78.0  $391  $631  $943  $(150) $(2) $23  $1,836 
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION - LIABILITIES AND EQUITY

See Notes to Consolidated Financial Statements.
  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.




AGL RESOURCES INC. AND SUBSIDIARIESSUBISIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

  Years ended December 31, 
In millions 2010  2009  2008
Comprehensive income attributable to AGL Resources Inc. (net of tax)        
Net income attributable to AGL Resources Inc. $234  $222  $217 
(Loss) gain resulting from unfunded pension and postretirement obligation during the period (Note 5)  (28)  17   (111)
Cash flow hedges (Note 4):             
Derivative financial instruments unrealized losses arising during the period  (14)  (12)  (4)
Reclassification of derivative financial instruments realized losses (gains) included in net income  9   13   (6)
Other comprehensive (loss) income  (33)  18   (121)
Comprehensive income (Note 8) $201  $240  $96 
              
Comprehensive income (loss) attributable to noncontrolling interest (net of tax)             
Net income attributable to noncontrolling interest (Note 9) $16  $27  $20 
Cash flow hedges (Note 4):             
Derivative financial instruments unrealized losses arising during the period  (1)  (7)  (1)
Reclassification of derivative financial instruments realized losses (gains) included in net income  2   7   (4)
Other comprehensive income (loss)  1   -   (5)
Comprehensive income (Note 8) $17  $27  $15 
              
Total comprehensive income (net of tax)             
Net income $250  $249  $237 
(Loss) gain resulting from unfunded pension and postretirement obligation during the period  (28)  17   (111)
Cash flow hedges (Note 4):             
Derivative financial instruments unrealized losses arising during the period  (15)  (19)  (5)
Reclassification of derivative financial instruments realized losses (gains) included in net income  11   20   (10)
Other comprehensive (loss) income  (32)  18   (126)
Comprehensive income (Note 8) $218  $267  $111 
  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.



AGL Resources Inc.RESOURCES INC. AND SUBSIDIARIES
Consolidated Statements of Cash FlowsCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

  Years ended December 31, 
In millions 2010  2009  2008 
Cash flows from operating activities         
Net income $250  $249  $237 
Adjustments to reconcile net income to net cash flow provided by operating activities            
Depreciation and amortization (Note 2)  160   158   152 
Deferred income taxes (Note 11)  92   105   89 
Change in derivative financial instrument assets and liabilities (Note 3 and Note 4)  (2)  11   (129)
Changes in certain assets and liabilities            
Energy marketing receivables and energy marketing trade payables, net (Note 2)  47   (81)  10 
Inventories (Note 2)  33   (9)  (112)
Accrued expenses  7   19   26 
Gas and trade payables  (12)  1   29 
Deferred natural gas costs (Note 2)  (14)  24   1 
Gas, unbilled and other receivables (Note 2)  (26)  108   (65)
Other – net  (9)  7   (11)
Net cash flow provided by operating activities  526   592   227 
Cash flows from investing activities            
Expenditures for property, plant and equipment (Note 2)  (510)  (476)  (372)
Proceeds from the disposition of assets  73   -   - 
Other  (5)  -   - 
Net cash flow used in investing activities  (442)  (476)  (372)
Cash flows from financing activities            
Net payments and borrowings of short-term debt  131   (264)  286 
Issuance of treasury shares (Note 8)  15   8   9 
Issuances of senior notes (Note 7)  -   297   - 
Issuances of variable rate gas facility revenue bonds (Note 7)  160   -   160 
Payments of gas facility revenue bonds (Note 7)  (160)  -   (160)
Purchase of treasury shares (Note 8)  (7)  -   - 
Distribution to noncontrolling interest (Note 9)  (27)  (20)  (30)
Purchase 15% ownership in SouthStar from Piedmont (Note 9)  (58)  -   - 
Dividends paid on common shares (Note 8)  (133)  (127)  (124)
Other  (7)  -   1 
Net cash flow (used in) provided by financing activities  (86)  (106)  142 
Net (decrease) increase in cash and cash equivalents  (2)  10   (3)
Cash and cash equivalents at beginning of period  26   16   19 
Cash and cash equivalents at end of period $24  $26  $16 
Cash paid during the period for            
Interest $107  $93  $115 
Income taxes  58   50   27 
  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.




 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.



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.


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”“company, or “AGL Resources” mean consolidated AGL Resources Inc. and its subsidiaries. We have prepared the accompanying consolidated financial statements under the rules of the SEC.

Basis of Presentation

Our consolidated financial statements as of and for the period ended December 31, 20102013 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. This meansFor unconsolidated entities that we do not control, but exercise significant influence over, we primarily use the equity method of accounting and our accounts are combined withproportionate share of income or loss is recorded on the subsidiaries’ accounts.Consolidated Statements of Income. See Note 10 for additional information. We have eliminated any intercompany profits and transactions in consolidation; however, we have not eliminatedconsolidation except for intercompany profits whenwhere recovery of such amounts are probable of recovery 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 primarily of cash on deposit, money market accounts and certificates of deposit held by domestic subsidiaries with original maturities of three months or less.

Receivables As of December 31, 2013 and Allowance2012, 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 Uncollectible Accounts 

Our receivables consistuse by us or our other operations only if we repatriate a portion of natural gas salesTropical Shipping’s earnings in the form of a dividend, and transportation services billed to residential, commercial, industrial and other customers. We bill customers monthly, and accounts receivable are due within 30 days. For the majoritypay a significant amount of our receivables, we establish an allowanceU.S. income tax that has been previously deferred. See Note 12 for doubtful accounts basedadditional information on our collection experience and other factors. On certain other receivables where we are aware of a specific customer’s inability or reluctance to pay, we record an allowance for doubtful accounts against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be different. Circums tances that could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. We write-off our customers’ accounts once we deem them to be uncollectible.income taxes.

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

Inventories

For our distribution operations subsidiaries, we record natural gas stored underground at WACOG. For Sequent and SouthStar, we account for natural gas inventory at the lower of WACOG or market price.

Sequent and SouthStar evaluate the 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, adjustments are recorded to reduce the weighted average cost of the natural gas inventory to market price. Consequently, as a result of declining natural gas prices, Sequent recorded LOCOM adjustments against cost of gas, to reduce the value of its inventories to market value, of $8 million in 2010, $8 million in 2009 and $40 million in 2008. SouthStar was not required to make LOCOM adjustments in 2010, but recorded LOCOM adjustments of $6 million in 2009 and $24 million in 2008.

In Georgia’s competitive environment, Marketers including SouthStar, our retail marketing subsidiary, began selling natural gas in 1998 to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation that provides for this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. Atlanta Gas Light assigns, on a monthly basis, the majority of the pipeline storage services that it has under contract to Marketers, along with a corresponding amount of inventory.
Energy Marketing Receivables and Payables

Our wholesale services segment provides services to retail and wholesale marketers and utility and industrial customers. These customers, also known as counterparties, utilize netting agreements, which enable our wholesale services segment to net receivables and payables by counterparty.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. TheWhile the amounts due from, or owed to, wholesale services’ counterparties are netted andsettled 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 some trade and credit contracts that have explicitcontain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale services would need to post collateral to continue transacting business with some of its counterparties. No collateral has been posted under such provisions sinceTo date, our credit ratings have always exceeded the minimum requirements. As of December 31, 20102013 and December 31, 2009,2012, 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 fina ncialfinancial condition. However, ifIf such collateral were not posted, wholesale services’ ability to continue transacting business with these counterparties would be negatively impacted.

Wholesale services has a concentration of credit risk for services it provides to marketers and to utility and industrial counterparties. This credit risk is generally concentrated in 20 of its counterparties and is measured by 30-day receivable exposure plus forward exposure, which is generally concentrated in 20 of its counterparties. Sequent evaluatesexposure. We evaluate the credit risk of itsour counterparties using aan 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 9.009 to 1.00,1, with 9.009 being equivalent to AAA/Aaa by S&P and Moody’s and 1.001 being equivalent to D or D/Default by S&P and Moody’s. For a customer withoutA counterparty that does not have an external rating Sequent assignsis assigned an internal rating based on Sequent’s analysis of the strength of its financial ratios. At December 31, 2010 and excluding $61 millio n of customer deposits, Sequent’s top 20 counterparties represented approximately 56% of the totalThe following table provides additional information about wholesale services’ credit exposure of $598 million, derived by adding together the top 20 counterparties’ exposures and dividing by the total of Sequent’s counterparties’ exposures. Sequent’s counterparties or the counterparties’ guarantors had a weighted average S&P equivalent rating of BBB+ at December 31, 2010.2013, 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 customer’scounterparty’s assigned internal rating by its credit exposure and then addingsumming the individual results for all counterparties. That totalThe sum is divided by the aggregate total exposure. Thisexposure and this numeric value is then converted to an S&P equivalent.

Sequent hasWe have established credit policies to determine and monitor the creditworthiness of counterparties, including requirements for posting of collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include cash or United StatesU.S. government securities held by a trustee. When Sequentwholesale 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 andcombined with a reasonable measure of Sequent’sour credit risk. SequentWholesale services also uses other netting agre ementsagreements with certain counterparties with whom it conducts significant transactions.

Fair value measurementsReceivables 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.

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 cashreceivables, short and cash equivalents, receivables, derivative financiallong-term investments, accounts payable, short-term debt, other current assets and liabilities accounts payable, pension and postretirement plan assets and liabilities, other current liabilities, and accrued interest approximate fair value. See Note 34 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 and endeavor to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to cl assifyclassify 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

Level 1Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 items consist of financial instruments with exchange-traded derivatives.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 mult iplemultiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the market place. As we aggregate our disclosures by counterparty, the underlying transactions for a given counterparty may be a combination of exchange-traded derivatives and values based on other sources.marketplace. Instruments in this category include shorter tenor exchange-traded and non-exchange-traded derivatives such as OTC forwards and options.options and certain retirement plan assets.

Level 3

Pricing inputs include significant unobservable inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result into determine management’s best estimate of fair value.value from the perspective of market participants. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. We have no assets or liabilities classified asTransfers into and out of Level 3 except forreflect 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 5.6. 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 establishedincludes a two-step process to determine ifwhether the market for a financial asset is inactive andor a transaction is not distressed. Currently, this authoritative guidance does not affect us, as our derivative financial instruments are traded in active markets.

Derivative Financial 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 HierarchyAs required by the authoritative guidance, derivative financial 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 nonper formanceown 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.

The authoritative guidance relatedWe have elected to derivativesnet derivative assets and hedging requiresliabilities 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 on our Consolidated Statements of Financial Position with the associated net fair value of the instruments in the accounts. OurSee Note 4 for additional information about our cash collateral amounts were $105 million as of December 31, 2010 and $57 million as of December 31, 2009.collateral.

Natural Gas and Weather Derivative Financial Instruments

The fair value of the natural gas and weather derivative financial 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 financial instruments. See Note 5 for additional derivative disclosures.

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

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.
60


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

SouthStarWe currently hashave minimal hedge ineffectiveness defined as, which occurs when the gains or losses on the hedging instrument do notmore than offset the losses or gains on the hedged item. ThisAny cash flow hedge ineffectiveness is recorded in cost of gas in our Consolidated Statements of Income in the period in which it occurs. We have not designated the remainder of SouthStar’sour derivative financial instruments as hedges under the authoritative guidance related to derivatives and hedgingfor accounting purposes and, accordingly, we record changes in theirthe fair valuevalues of such instruments within cost of gasgoods 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 difference in 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 contracts and other OTC derivativescontracts 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.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 futures contracts generally meet the definition of derivatives under the authoritative guidance related to derivatives and hedging and are accounted forcarried at fair value in our Consolidated Statements of Financial Posit ion,Position, with changes in fair value recorded in operating revenues in our Consolidated Statements of Income in the period of change. However, these futuresThese contracts are not designated as hedges in accordance with the guidance.for accounting purposes.

The purchase, transportation, storage and sale of natural gas are accounted for on a weighted average cost or accrual basis, as appropriate, rather than on the fair value basis we utilize for the derivatives used to mitigate the natural gas price risk associated with our storage and transportation portfolio. We incur monthly demand charges for the contracted storage and transportation capacity, and payments associated with asset management agreements, and we recognize these demand charges and payments 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 datedates the transactions were consummated.

Energy InvestmentsDebt During the construction of the storage caverns Golden Triangle Storage uses derivative financial instruments to reduce its exposure to the risk of changes in the price of natural gas that will be purchased in future periods for pad gas. Pad gas includes volumes of non-working natural gas used to maintain the operational integrity of the caverns.

We have designated all of Golden Triangle Storage’s derivative financial instruments, consisting of financial swaps, as cash flow hedges under the authoritative guidance related to derivatives and hedging. The pad gas is considered to be a component of the storage cavern’s construction costs; as a result, any derivative gains or losses arising from the cash flow hedges will remain in OCI until the pad gas is sold, which will not occur until the storage caverns are decommissioned. The fair value of these derivative financial instruments currently have minimal hedge ineffectiveness which is recorded in cost of gas in our Consolidated Statements of Income in the period in which it occurs. Golden Triangle Storage began entering into these derivative financial transactions during 2009.

Weather Derivative Financial Instruments

SouthStar entered into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal and colder-than-normal weather in the Heating Season. SouthStar accounts for these contracts using the intrinsic value method under the authoritative guidance related to financial instruments. These weather derivative financial instruments are not designated as derivatives or hedges and are reflected in cost of gas on our Consolidated Statements of Income.

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 consideredconsider our currently assigned ratings for unsecured debt.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, 20102013 and 20092012 is provided in the following table.

In millions 2010  2009 
Transmission and distribution $4,955  $4,579 
Storage  580   290 
Other  484   725 
Construction work in progress  247   345 
Total gross PP&E  6,266   5,939 
Accumulated depreciation  (1,861)  (1,793)
Total net PP&E $4,405  $4,146 
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 expenditures consistconsists 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 laborlabor;
·  contractor costscosts;
·  construction overhead costscosts;
·  an allowance for funds used during construction (AFUDC) which representsAFUDC; and,
·  
Nicor Gas’ pad gas - the estimated cost of funds, from both debt and equity sources, usedportion considered to financebe non-recoverable is recorded as depreciable PP&E, while the construction of major projects andportion considered to be recoverable is capitalized in rate base for ratemaking purposes when the completed projects are placed in servicerecorded as non-depreciable PP&E.

We chargerecognize no gains or losses on depreciable utility property that is retired or otherwise disposed, ofas required under the composite depreciation method. Such gains and losses are ultimately refunded to, accumulated depreciation since such costs areor recovered from, customers through future rate adjustments. Our natural gas utilities also hold property, primarily land; this is not presently used and useful in rates.utility operations and is not included in rate base. Upon sale, any gain or loss is recognized in other income.

Retail Energy Operations, Wholesale Services, Energy InvestmentsMidstream Operations, Cargo Shipping and CorporateOther PP&E expenditures includeincludes 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 Storage that is retained as pad gas (volumes of non-working natural gas used to maintain the operational integrity of the cavern facility) is classified as non-depreciable property, plant and equipmentPP&E and is valuedcarried 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

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. The average composite straight-line depreciationMore information on our rates for depreciable property -- excluding transportation equipment for Atlanta Gas Light, Virginia Natural Gas and Chattanooga Gasused and the composite, straight-line rates for Elizabethtown Gas, Florida City Gas and Elkton Gas are listedrate method is provided in the following table. We depreciate
  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 a period of 5 to 10 years. We compute depreciation expense for other segments on a straight-line basis up to 35 years based on the following estimated useful lifelives of the asset.assets.

  2010  2009  2008 
Atlanta Gas Light  2.5%  2.5%  2.5%
Chattanooga Gas  2.8%  3.4%  3.3%
Elizabethtown Gas  2.4%  3.1%  3.1%
Elkton Gas  2.3%  2.1%  2.9%
Florida City Gas  3.7%  3.9%  3.9%
Virginia Natural Gas  3.0%  2.6%  2.7%
In yearsEstimated useful life
Transportation equipment5 - 10
Shipping vessels20 - 25
Storage caverns40 - 60
Otherup to 40

AFUDC and Capitalized Interest

Four of our utilitiesAtlanta Gas Light, Nicor Gas, Chattanooga Gas and Elizabethtown Gas are authorized by applicable state regulatory agencies or legislatures to recordcapitalize the cost of debt and equity funds as part of the cost of PP&E construction projects in our Consolidated Statements of Financial Position. Additionally, we recorded AFUDC of $3 million in 2010, $13 million in 2009 and $8 million in 2008 within the Consolidated Statements of Income. The capital expenditures of our two other utilities do not qualify for AFUDC treatment. More information on our authorized or actual AFUDC rates is provided in the following table.

  2010  2009  2008 
Atlanta Gas Light(1)  8.10%  8.53%  8.53%
Chattanooga Gas (2)  7.41%  7.89%  7.89%
Elizabethtown Gas (3)
  0.40%  0.41%  2.84%
Virginia Natural Gas (4)  -   9.24%  8.91%
  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)New rate as of November 1, 2010.
(2)  New rate as of June 1, 2010.
(3)  Variable rate is determined by FERC method of AFUDC accounting.
(4)(2)  Approved only for Hampton Roads construction project which endedAmount recorded in 2009. VNG received no AFUDC interest for 2010.the Consolidated Statements of Income.

WithinThe capital expenditures of our energy investments segment, we have recorded capitalized interest as part of the cost of the Golden Triangle Storage construction project in our Consolidated Statements of Financial Position, and within interest expense in our Consolidated Statements of Income in the amount of $5 million in 2010, $3 million in 2009 and $2 million in 2008.other three utilities do not qualify for AFUDC treatment.

GoodwillAsset Retirement Obligations

Goodwill isWe record a liability at fair value for an asset retirement obligation (ARO) when a legal obligation to retire the excessasset has been incurred, with an offsetting increase to the carrying value of the purchase price overrelated 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 identifiable netthis 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, acquired in business combinations. In accordance withincluding our finite-lived intangible assets, require an impairment review when events or circumstances indicate that the authoritative guidance, we annually evaluatecarrying 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 balances for 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. We test goodwill impairment utilizing aTo 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 reporting unit level which generally equates to our operating segments, as discusseddegree of uncertainty, and changes in Note 12 “Segment Information,” and an impairment charge is recognized if the carryingprojected cash flows could significantly increase or decrease the estimated fair value of a reporting unit’s goodwill exceeds itsunit. For the regulated reporting units, a fair value.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.

Our goodwill impairment analysisUnder 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 years ended December 31, 2010 and 2009 indicated thatresults of the two valuation approaches to estimate the fair value of each reporting unit is substantiallyunit. 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 value,values by approximately 20% to almost 500%, and arewere not at risk of failing step one of the impairment evaluation. As a result, we did not recognize anytest.

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 chargestest for this reporting unit assumed discrete period revenue growth through fiscal 2021 to reflect the recovery of subscription rates, stabilization of earnings and do not anticipate takingestablishment 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 chargestest.

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 forseeable future. 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.

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 TaxesThe reporting of our assets and liabilities for financial accounting purposes differs from the reporting for income tax purposes. The principal differencesdifference between net income and taxable income relaterelates 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 in those items as deferred income tax assets or liabilities in our Consolidated Statements of Financial Position in accordance with authoritative guidance related to income taxes.Position.

Income TaxesWe have two categories ofcurrent and deferred income taxes in our Consolidated Statements of Income: current and deferred.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 is equal to the changes in the deferred income tax liability and regulatory tax liability during the year.

Investment We have recorded current deferred income taxes of $43 million (net of a valuation allowance of $8 million) as of December 31, 2013 and Other Tax Credits Deferred investment tax credits associated with distribution operations are included$4 million as a regulatory liabilityof December 31, 2012 within other current assets in our Consolidated Statements of Financial Position. These investment tax credits are being amortized over the estimated life of the related properties as credits to income in accordance with regulatory requirements. In 2007, we invested in a guaranteed affordable housing tax credit fund. We reduce income tax expense in our Consolidated Statements of Income for the investment tax credits and other tax credits associated with our non-regulated subsidiaries, including the affordable housing credits.Position.

Accumulated Deferred Income Tax Assets and Liabilities WeAs 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 thethese deferred income tax assets and liabilities using enacted income tax ratesrates.

A deferred income tax liability is not recorded on undistributed foreign earnings that are currentlyexpected to be indefinitely reinvested offshore. We consider, among other factors, actual cash investments offshore as well as projected cash requirements in effect. Becausemaking 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 the regulated naturesuch cash and short-term investments on our Consolidated Statements of the utilities’ business,Financial Position as of December 31, 2013 and 2012. As of December 31, 2013, we recordedwould be required to record a regulatorydeferred tax liability in accordance with authoritative guidance related to income taxes, whichof $31 million if we are amortizing over approximately 30 years.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 onupon examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. This guidance also provides guida nce on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures. As of December 31, 2010 and December 31, 2009, we did not have a liability for unrecognized tax benefits. Based on current information, we do not anticipate that this will change materially in 2011.

Uncertain Tax Positions We recognize accrued interest and penalties related to uncertain tax positions in interest expense and penalties in operating expensesexpense in theour Consolidated Statements of Income, which is consistent with the recognition of these items in prior reporting periods. As of December 31, 2010, we did not have a liability recorded for payment of interest and penalties associated with uncertain tax positions.Income.

Tax Collections We do not collect income taxes from our customers on behalf of governmental authorities. WeHowever, 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 except taxes in the state of Florida whichPosition. In other instances, we are requiredallowed to include in revenuesrecover from customers other taxes that are imposed upon us. We record such taxes as operating expenses and record the corresponding customer charges as operating expenses. These Florida related taxes are immaterial for all periods presented.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, in July 1998, Atlanta Gas Light began billingbills Marketers in equal monthly installments for each residential, commercial and industrial end-use customer’s distribution costs. AsAdditionally, as required by the Georgia Commission, effective February 1, 2001, Atlanta Gas Light implementedbills Marketers for capacity costs utilizing a seasonal rate design for the calculation of each residential end-use customer’s annual straight-fixed-variable (SFV) capacity charge, which is billed to Marketers and reflects the historic volumetric usage pattern for the entire residential class. Generally, this changeseasonal rate design results in residential customers being billed bybilling the Marketers for a higher capacity charge in the winter months and a lower charge in the summer months. This requirement has anmonths, which impacts our operating cash flow impact butflows. However, this seasonal billing requirement does not change revenue recognition. Asimpact our revenues, which are recognized on a result,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, continues to recognize its residential SFV capacity revenues for financial reporting purposes in equal monthly installments.
The Elizabethtown Gas, Virginia Natural Gas, Florida City Gas, Chattanooga Gas and Elkton Gashave rate structures that include volumetric rate designs thatwhich allow recovery of certain costs throughbased 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 recordedrecognized for estimated deliveries of gas not yet billed to these customers, from the last meter readingbill 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 en dend of the period.

The tariffs for ElizabethtownVirginia Natural Gas, Virginia NaturalElizabethtown Gas and Chattanooga Gas contain WNA’sWNAs that partially mitigate the impact of unusually cold or warm weather on customer billings and operating margin. The WNA’s purpose of a WNA is to reducemitigate 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 tarifftariffs for Virginia Natural Gas, contains aChattanooga Gas and Elkton Gas contain revenue normalization mechanismmechanisms that mitigatesmitigate 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.

Retail energy operations We record retail energy operations’ revenues when services are provided to customers. 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 recordedrecognized 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. TheseThe 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 deliv eriesdeliveries 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 corporateother 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.

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

Cargo shipping Revenues 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 gasgoods sold

Distribution operationsExcluding 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 a currentan asset or liability in the Consolidated Statements of Financial Position and exclude from, or include in, the Consolidated Statements of Consolidated Income)Income, respectively) the difference between the actual cost of gasgoods sold and what is collected from or billed to customersthe amount of commodity revenue earned in a given period.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. These amountsDeferred natural gas costs are reflected as regulatory assets identified as recoverableand accrued natural gas costs orare reflected as regulatory liabilities which are identified as deferred natural gas costs within our Consolidated Statements of Financial Position.liabilities. For more information, see “Regulatory Assets and Liabilities” in Note 2.3.

Retail operations Our retail energy operations customers are charged for actual or estimated natural gas consumed. We also include withinWithin our cost of gas amounts forgoods 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 for 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. However, thisThis accounting treatment does not affect the future annual operating lease cash obligations. For more information, see Note 11.




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 could occuroccurs 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 future issuancevesting of certain shares underlyingof the restricted stock and restricted sharestock units depends on the satisfaction of certaindefined performance criteria. The future issuance of shares underlying the outstanding stock options depends on whether the exercise prices of the stock options are less than the average market price of the common shares forunderlying the options exceeds the respective periods. 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 2010  2009  2008 
Denominator for basic earnings per common share attributable to AGL Resources Inc. common shareholders (1)
  77.4   76.8   76.3 
Assumed exercise of potential common shares  0.4   0.3   0.3 
Denominator for diluted earnings per common share attributable to AGL Resources Inc. common shareholders  77.8   77.1   76.6 
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:

(1)·  Daily weighted averageThe issuance of 38.2 million shares outstanding.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

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 following table containsremaining $5 million of contingent cash consideration will be determined and would be received from the weighted average sharesbuyer 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 outstanding stock options that were excluded from the computationnoncontrolling 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. because their effect wouldInc.

For entities that are not determined to be VIEs, we evaluate whether we have been anti-dilutive,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 accountsAll 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 the exercise prices were greater than the average market price:
   December 31,  
In millions 2010 2009 2008   
Twelve months ended  0.8   2.0   1.6 
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 decreasepreparation 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 numberapplication and interpretation of shares that were excluded from the computation for the year ended December 31, 2010 is the result of an increaseexisting literature or in the average market valuedevelopment of estimates that impact our common sharesfinancial statements. The most significant estimates relate to our rate-regulated subsidiaries, regulatory infrastructure program accruals, uncollectible accounts and other allowances for the years ended December 31, 2010 compared to 2009contingent losses, goodwill and 2008. While the market value ofintangible assets, retirement plan benefit obligations, derivative and hedging activities and provisions for income taxes. We evaluate our common shares rose during 2009, the average share price for 2009 was lower than 2008.
estimates on an ongoing basis and our actual results could differ from our estimates.

RegulatoryAccounting 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 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 and recorded as regulatory assets when it is probable that the incurredsuch costs or estimated future 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 and the associated assets and liabilitiesas of December 31, are summarized in the following table.

  December 31, 
In millions 2010  2009 
Regulatory assets      
Recoverable regulatory infrastructure program costs $292  $266 
Recoverable ERC  171   172 
Recoverable seasonal rates  11   11 
Recoverable postretirement benefit costs  9   10 
Recoverable natural gas costs  3   - 
Other  35   27 
Total regulatory assets  521   486 
Associated assets        
Derivative financial instruments  20   11 
Total regulatory and associated assets $541  $497 
Regulatory liabilities        
Accumulated removal costs $182  $183 
Derivative financial instruments  20   11 
Deferred natural gas costs  19   30 
Regulatory tax liability  15   17 
Unamortized investment tax credit  12   13 
Other  24   17 
Total regulatory liabilities  272   271 
Associated liabilities        
Regulatory infrastructure program costs  228   210 
ERC  132   133 
Total associated liabilities  360   343 
Total regulatory and associated liabilities $632  $614 
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 recoverable through either rate riders or base rates specifically authorized by a state regulatory commission.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 any future rate proceedings. We are not aware of any evidence that these costs will not be recoverable through either rate riders or base rates, and we believe that we will be able to recover thesesuch costs consistentlyconsistent 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, thewhile some regulatory liabilities would not be written-off butwritten off, others would continue to be recorded as liabilities, but not as regulatory liabilities.

Although the natural gas distribution industry is becoming increasingly competitive,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.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, th ethe amount is reflected as a reduction to the rate base in settingused to periodically set base rates.

The majority of our regulatory assets includedand liabilities listed in the preceding table are included in base rates except for the recoverable regulatory infrastructure program costs, recoverable ERC, and deferredbad debt, natural gas and energy efficiency costs, which are recovered through specific rate riders on a dollar for dollardollar-for-dollar basis. The rate riders that authorize the recovery of recoverable regulatory infrastructure program costs and the deferred natural gas costs include both a recovery of costscost 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 customarily reported estimates of future remediation costs for investigation and cleanup of our former operating sites that are contaminatedcontaminated. Our estimates are based on conventional engineering estimates and the use of probabilistic models of potential costs andwhen 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 at our former sites.program. These estimates contain various engineering uncertainties, butassumptions, which we continuously attempt to refine and update these engineering estimates.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, unbudgeted legal expenses or other costs f orfor which we may be held liable but for which we cannot reasonably estimate an amount.

Our accrued ERC liabilitiescosts are includednot regulatory liabilities; however they are deferred as a corresponding regulatory asset.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 rate riders. We have twothree rate riders that authorize dollar-for-dollar recovery. We expect to collect $45 million in revenues over the recovery of these costs. Thenext 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 rider for Atlanta Gas Light only allows for recovery of the costs incurred and the recovery period occurs over the five years after the expense is incurred. ERC associated with the investigation and remediation of Elizabethtown Gas remediation sites located in the state of New Jersey are recovered under a remediation adjustment clause and include the carrying cost on recoverable amounts not currently in rates. Forriders. The following table provides more information on the costs related to remediation of our ERC liabilities, see Note 10.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.

Derivative Financial InstrumentsBad Debt Rider ElizabethtownNicor Gas’ derivative financial instrument asset and liability reflect unrealized losses or gains that will be recoveredbad debt rider provides for the recovery from, or passedrefund to rate payers through, 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 its natural gas costsIncome and a regulatory liability on a dollar for dollar basis, onceour Consolidated Statements of Financial Position until refunded to customers. In the losses or gainsperiod refunded, operating expenses are realized. For more information on Elizabethtown Gas’ derivative financial instruments, see Note 4.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   -   - 

Other Regulatory AssetsAccumulated Removal Costs In accordance with regulatory treatment, our depreciation rates are comprised of two cost components - historical cost and Liabilities Our recoverable postretirement benefitthe 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 recoverable through base rates overnot a generally accepted component of depreciation, but meet the next 3requirements of authoritative guidance related to 22 years based on the remaining recovery period as designated by the applicable state regulatory commissions. Recoverable seasonal rates reflect the difference between the recognition of a portion of Atlanta Gas Light’s residential base rates revenues on a straight-line basis as comparedregulated operations, we have reclassified them from accumulated depreciation to the collectionaccumulated removal cost regulatory liability in our Consolidated Statements of Financial Position. In the revenues overrate setting process, the liability for these accumulated removal costs is treated as a seasonal pattern. These amounts are fully recoverable throughreduction to the net rate base rates within one year.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 LightBy order of the Georgia Commission (through a joint stipulation and a subsequent settlement agreement between Atlanta Gas Light and the Georgia Commission), Atlanta Gas Light began a pipeline replacement program to replace all bare steel and cast iron pipe in its system by December 2013. If Atlanta Gas Light does not perform in accordance with this order, it will be assessed certain nonperformance penalties. As of 2010, we have completed the replacement of all our cast iron pipes, and the remaining replacements are on schedule.
The order provides for recovery of all prudent costs incurred in the performance of the program, which Atlanta Gas Light has recorded as a regulatory asset. Atlanta Gas Light will recover from end-use customers, through billings to Marketers, the costs related to the program net of any cost savings from the program. All such amounts will be recovered through a combination of straight-fixed-variable rates and a pipeline replacement revenue rider. The regulatory asset has two components: (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.

·  the costs incurred to date that have not yet been recovered through the rate rider
·  the future expected costs to be recovered through the rate rider
Atlanta Gas Light has recorded a long-termcurrent regulatory asset of $244 million, which represents the expected future collection of both expenditures already incurred and expected future capital expenditures to be incurred through the remainder of the program. Atlanta Gas Light has also recorded a current asset of $48 million, which represents the amount of recognized revenues expected amount to be collected from customers over the next 12 months.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:

·  $4549 million in 20102013
·  $4151 million in 20092012
·  $3048 million in 20082011

As of December 31, 2010, Atlanta Gas Light had recorded a current liability of $62 million representing expected program expenditures for the next 12 months and a long-term liability of $166 million, representing expected program expenditures starting in 2011 through the end of the program in 2013.

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

The Georgia Commission has also approved Atlanta Gas Light’sOur STRIDE program which is comprised of the ongoing pipeline replacement program, the new Integrated System Reinforcement Program (i-SRP) and, the new Integrated Customer Growth Program (i-CGP), the pipeline replacement program that ended in 2013, and a new component, the Integrated Vintage Plastic Replacement Program (i-VPR). Under STRIDE theThe purpose of the i-SRP program is to upgrade Atlanta Gas Light’sour distribution system and liquefied natural gas facilities in Georgia, improve itsour peak-day system reliability and operational flexibility, and create a platform to meet long-term forecasted growth. Under STRIDE,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 requiredrecovered through a surcharge. The STRIDE program requires us to file an updated ten-year forecast of infrastructure requirements under the i-SRP along with a new three-year construction plan every three years for review and approval by the Georgia Commission.

UnderThe purpose of the i-CGPi-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 Atlanta Gas Lighta phased-in approach to extendfunding the company’s pipeline facilitiesprogram through a monthly rider surcharge of $0.48 per customer through December 2014. This will be increased to serve customers without pipeline access$0.96 beginning in January 2015 and create new economic development opportunitiesto $1.45 beginning in Georgia. The i-CGP was approved as a three-year pilot program under STRIDE,January 2016 and will be recoveredcontinue through a surcharge.2025.

Elizabethtown Gas In April 2009, the New Jersey BPU approved anthe enhanced infrastructure program for Elizabethtown Gas, which began in 2009 and is scheduled to be completed in 2011. This program was created in response to the New Jersey Governor’s request for utilities to assist in the economic recovery by increasing infrastructure investments. A regulatory cost recovery mechanism will be established with estimated rates put into effect atIn May 2011, the beginning of each year. AtNew 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 regulatory costNew Jersey BPU. In August 2013, the New Jersey BPU approved the recovery mechanism will be trued-up and any remaining costs not previously collected will be included inof investments under this program through a permanent adjustment to base rates.

The following table provides additional information on our expenditures under these programs during the year ended December 31, 2010.

In millions   
Georgia   
Pipeline replacement program $81 
Integrated System Reinforcement Program  54 
Integrated Customer Growth Program  6 
New Jersey    
Enhanced infrastructure program  46 
Total $187 

AccountingAdditionally, in August 2013, we received approval from the New Jersey BPU for employee benefit plansan 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 authoritative guidance relatedprogram permits a maximum capital expenditure of $25 million per year, not to retirement benefits requiresexceed $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 recognize all obligations relatedfiled our annual SAVE rate update detailing the first-year performance and our expected future budget, which is subject to defined benefit pensionsreview and other postretirement benefitsapproval by the Virginia Commission. The rate update was approved with minor modifications by the Virginia Commission on July 23, 2013 and quantifybecame effective as of August 1, 2013. On May 1, 2013, the plans’ funding statusVirginia 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 an asset or a regulatory liability onin our Consolidated Statements of Financial Position. The guidance further requires thatThese 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 the plans’deferred income tax assets and obligations that determine our funded status asliabilities 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 endreduction is transferred to our regulatory income tax liability, which we are amortizing over the lives of the fiscal year. We are also required to recognizerelated properties as a component of OCI the changes in funded status that occurred during the year that are not recognized as part of net periodic benefit cost as explained in authoritative guidance related totemporary differences reverse over approximately 30 years.

Other Regulatory Assets and Liabilities Our recoverable pension and postretirement benefits. Our retirement and postretirement plans’ assets were accountedretiree welfare benefit plan costs for at fair value andour utilities other than Nicor Gas are classified in their entiretyexpected to be recovered through base rates over the next 2 to 21 years, based on the lowest levelremaining 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 input that is significanta portion of Atlanta Gas Light’s residential base rates revenues on a straight-line basis as compared to the fair value measurement.
Non-Wholly-Owned Entitiescollection of the revenues over a seasonal pattern. These amounts are fully recoverable through base rates within one year.

We hold ownership interestsIn 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 a numberits third year and will end in May 2014. Although there is no statutory deadline for approval of joint 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 definedgas utility plans, Nicor Gas requested approval in the authoritative accounting guidance. If a venture is a VIEsame five-month timeframe, or by March 1, 2014, as established by statute 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.

On Januaryelectric utilities. The new plan must be implemented by June 1, 2010, we adopted authoritative accounting guidance that requires us to reassess our determination that we are the primary beneficiary of a VIE based on whether we have the power to direct matters that most significantly impact the activities of a VIE, and have the obligation to absorb losses or the right to receive benefits of a VIE. The adoption of this guidance had no effect on our Consolidated Statements of Income, Cash Flows or Financial Position because we concluded that SouthStar’s accounts should continue to be consolidated with the accounts of AGL Resources Inc. and its majority-owned and controlled subsidiaries.2014.

We have concluded that the only joint venture that we are required to consolidate as a VIE, for which we are the primary beneficiary, is SouthStar. We recognize on our Consolidated Statements of Financial Position, Piedmont’s share of the non-wholly owned entity as a separate component of equity entitled “noncontrolling interest.” Piedmont’s share of current operations is reflected in “net income attributable to the noncontrolling interest” on our Consolidated Statements of Income. The authoritative guidance has no effect on our calculation of basic or diluted earnings per common share amounts, which are based upon net income attributable to AGL Resources Inc. For additional information, see Note 9.

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 of contingent assets and liabilities. We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, and we evaluate our estimates on an ongoing basis. Our estimates may involve complex situations requiring a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. The most significant estimates include our pipeline replacement program accruals, environmental liability accruals, uncollectible accounts and other allowance for contingenci es, pension and postretirement obligations, derivative and hedging activities and provision for income taxes. Our actual results could differ from our estimates.


Note 3 –4 - Fair Value Measurements

Retirement benefit plans

The methods used to determine fair valueallocations 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 assets and liabilitiesretirement plans are fully described within Note 2.

Derivative Financial Instruments

Thepresented in the following table summarizes, by levelLevel within the fair value hierarchy, our derivative financial assets and liabilities that were accounted for at fair value on a recurring basis for the years ended December 31, 2010 and 2009.
  
Recurring fair values
Natural gas derivative financial instruments
 
  December 31, 2010  December 31, 2009 
In millions 
Assets (1)
  Liabilities  
Assets (1)
  Liabilities 
Quoted prices in active markets (Level 1) $22  $(71) $36  $(37)
Significant other observable inputs (Level 2)  153   (29)  172   (52)
Unobservable inputs (Level 3)  -   -   -   - 
Netting of cash collateral  53   52   30   27 
Total carrying value (2)
 $228  $(48) $238  $(62)
(1)  Less than $1 million of premium at December 31, 2010 and $2 million at December 31, 2009 associated with weather derivatives have been excluded as they are based on intrinsic value not fair value.
(2)  There were no transfers between Level 1, Level 2, or Level 3 for any periods presented.
hierarchy.

Other Fair Value Measures
  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%    

In addition to our derivative financial instruments above, we have several financial and nonfinancial assets and liabilities subject to fair value measures. These financial assets and liabilities include cash and cash equivalents, accounts receivable, accounts payable and debt. For cash and cash equivalents, accounts receivable and accounts payable, we consider carrying value to materially approximate fair value due to their short-term nature. The nonfinancial assets and liabilities include pension and post-retirement benefits.

Pension and post-retirement benefits Our pension and postretirement target asset allocations consist of approximately 30% - 95% equity, 10% - 40% fixed income, 10% - 35% real estate and other and the remaining 0% - 10% in cash. Our actual retirement and postretirement plans’ asset allocations by level within the fair value hierarchy for the year ended December 31, 2010, are presented in the table below.

 December 31, 2012 
 
Retirement plans (1)
  Postretirement plan  
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  Level 1  Level 2  Level 3  Total  % of total  Level 1  Level 2  Level 3  Total  % of total 
Cash $7  $-  $-  $7   2% $1  $-  $-  $1   1% $14  $2  $-  $16   2% $1  $-  $-  $1   1%
Equity Securities                                        
Equity securities                                        
U.S. large cap (2)
  91   -   -   91   26%  -   36   -   36   57%  69   181   -   250   30%  -   38   -   38   55%
U.S. small cap (2)
  51   -   -   51   15%  -   -   -   -   -   60   22   -   82   10%  -   -   -   -   -%
International companies (3)
  -   43       43   12%  -   12   -   12   19%  -   120   -   120   14%  -   12   -   12   18%
Emerging markets (4)
  -   16   -   16   4%  -   -   -   -   -   -   34   -   34   4%  -   -   -   -   -%
Fixed income securities                                        
Fixed income securities:                                        
Corporate bonds (5)
  -   56   -   56   16%  -   15   -   15   23%  -   216   -   216   26%  -   18   -   18   26%
Other types of investments                                        
Other (or gov’t/muni bonds)  -   30   -   30   3%  -   -   -   -   -%
Other types of investments:                                        
Global hedged equity (6)
  -   -   35   35   10%  -   -   -   -   -   -   -   38   38   4%  -   -   -   -   -%
Absolute return (7)
  -   -   30   30   9%  -   -   -   -   -   -   -   36   36   4%  -   -   -   -   -%
Private capital (8)
  -   -   22   22   6%  -   -   -   -   -   -   -   23   23   3%  -   -   -   -   -%
Total assets at fair value $149  $115  $87  $351   100% $1  $63  $-  $64   100% $143  $605  $97  $845   100% $1  $68  $-  $69   100%
% of fair value hierarchy  42%  33%  25%  100%      1%  99%  -   100%      17%  72%  11%  100%      1%  99%  -%  100%    
(1)  Includes $7$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 postretirement obligation.other retirement benefits.
(2)  Includes funds that invest primarily in United StatesU.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.

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

  Fair value measurements using significant unobservable inputs – Level 3
In millions Global hedged equity    
Absolute return
  Private capital  Equity Security - international companies  
Total
  
Assets:             
Beginning balance $33  $26  $13  $5  $77 
Transfers out of Level 3 (1)
  -   -   -   (4)  (4)
Gains included in changes in net assets  2   2   2   -   6 
Purchases and issuances  -   14   8   -   22 
Sales and settlements  -   (12)  (1)  (1)  (14)
Ending balance $35  $30  $22  $-  $87 
(1)  Transferred to Level 2 as a result of change in investment vehicle and pricing inputs becoming directly observable.

Debt Our debt is recorded at carrying value. We estimate the fair value of our 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 considered our currently assigned ratings for unsecured debt. The following table presents the carrying value and fair value of our debt for the years ended December 31, 2010 and 2009:

  
As of
December 31,
 
In millions 2010  2009 
Carrying amount $2,706  $2,576 
Fair value $2,122  $2,060 
7076

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.
  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.

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Note 4 –5 - Derivative Financial Instruments

Derivative Financial 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 financial instruments, andincluding 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 financial instruments and physical transactionsenergy-related contracts to manage natural gas price, interest rate, weather, automobile fuel price and foreign currency risks:

·  forward, contracts
·  futures contracts
·  and options contractscontracts;
·  financial swapsswaps;
·  treasury lockslocks;
·  weather derivative contractscontracts;
·  storage and transportation capacity transactionscontracts; and
·  foreign currency forward contracts

OurCertain of our derivative financial instruments do not contain any material credit-risk-related or other contingent features that could increase the payments forrequire us to post collateral we post in the normal course of business when our financial instruments are in net liability positions. OurAs 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 doalso have credit-risk-related or other contingent features, are discussed in Note 2. Our derivative financial instrument activities are included within operating cash flows as an adjustment to net income of $(2)$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 2010, $11notional 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 2009 and $(129)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 2008.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 below summarizes the various ways in which we account for our derivative instruments and the impact on our Consolidated Financial Statements:consolidated financial statements:

 
Recognition and Measurement
Accounting Treatment
StatementStatements of Financial PositionIncome Statement
Cash flow hedgeRecordedDerivative carried at fair valueIneffective 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 other comprehensive incomeOCI (loss)Effective portion of the gain or loss on the derivative instrument is reclassified out of accumulated other comprehensive incomeOCI (loss) and into earnings when the forecastedhedged 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 hedgesRecordedDerivative carried at fair valueThe gainRealized and unrealized gains or losslosses on the derivative instrument isare recognized in earnings
 Elizabethtown Gas’Distribution operations’ gains and losses on derivative financial instruments are recordeddeferred as a regulatory assetassets or liabilityliabilities until included in cost of gasgoods soldThe gainGains or losslosses on these derivative instruments is reflected in cost of gas and isare ultimately included in billings to customers
Change in fair value of the derivative instrument is recorded as an adjustment to book valueChange in fair value of the derivative instrument is and are recognized in earningscost of goods sold in the same period as the related revenues

Interest Rate Swaps

In May 2010, as a result of an anticipated refinancing of senior notes that matured in January 2011, we entered into $200 million of forward interest rate swaps, with a treasury rate of 3.94%. We designated the forward interest rate swap as a cash flow hedge against the first 20 future semi-annual interest payments of debt securities. In December 2010 we settled the interest rate swaps for a cost of $7 million, which is included within financing cash flows.
7178

Quantitative Disclosures Related to Derivative Financial Instruments

As of December 31, 2010 and 2009,the dates presented, our derivative financial 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. As of December 31, 2010 and 2009, weWe had a net long natural gas contracts position outstanding in the following quantities:
 
Natural gas contracts       
        
In Bcf 
December 31, 2010 (1)
    December 31, 2009 
Hedge designation:     
Cash flow  4   5 
Not designated  220   108 
Total  224   113 
Hedge position:         
Short  (1,605)  (1,518)
Long  1,829   1,631 
Net long position  224   113 
       
  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 96%97% of these contracts have durations of two years or less and the remaining 4%3% expire in 3 to 6between two and six years.

Derivative Financial Instruments on the Consolidated Statements of Income

The following table presents the gain or (loss) on derivative financial instruments in our Consolidated Statements of Income.Financial Position
  
For the twelve
months ended
December 31,
In millions 2010  2009
      
Designated as cash flow hedges     
Natural gas contracts – loss reclassified from OCI into cost of gas for settlement of hedged item $(16) $(31)
         
Not designated as hedges        
Natural gas contracts – fair value adjustments recorded in operating revenues (1)
  (1)  21 
Natural gas contracts – net gain fair value adjustments recorded in cost of gas (2)
  (2)  1 
Total losses on derivative instruments $(19) $(9)
(1)  Associated with the fair value of existing derivative instruments at December 31, 2010 and 2009.
(2)  Excludes losses recorded in cost of gas associated with weather derivatives of $27 million for the year ended December 31, 2010 and $6 million for the year ended December 31, 2009.

Our expected net loss to be reclassified from OCI into cost of gas and recognized in our Consolidated Statements of Income over the next twelve months is less than $1 million. These pre-tax deferred losses recorded in OCI are associated with retail energy operations’ derivative instruments and are based upon the fair values of these financial instruments.

72


Derivative Financial Instruments on the Consolidated Statements of Financial Position

In accordance with regulatory requirements, $35 million of realizedgains and losses on derivative financial instruments used at Nicor Gas and Elizabethtown Gas in our distribution operations segment wereto hedge natural gas purchases for customer use are reflected in deferredaccrued natural gas costs within our Consolidated Statements of Financial Position duringuntil billed to customers. The following amounts represent the yearnet realized gains (losses) related to these natural gas cost hedges for the years ended December 31, 2010 and $38 million during the year ended December 31, 2009. 31.

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

The following table presents the fair valuevalues and Consolidated Statements of Financial Position classificationclassifications of our derivative financial instruments:instruments:
   December 31,
In millions
Statement of financial position location (1) (2)
  
2010
   2009  
Designated as cash flow hedges    
      
Asset Financial Instruments    
Current natural gas contractsDerivative financial instruments assets and liabilities – current portion $3  $6 
Noncurrent natural gas contractsDerivative financial instruments assets and liabilities  -   - 
Liability Financial Instruments         
Current natural gas contractsDerivative financial instruments assets and liabilities – current portion  (5)  (5)
Total   (2)  1 
           
Not designated as cash flow hedges         
           
Asset Financial Instruments         
Current natural gas contractsDerivative financial instruments assets and liabilities – current portion  541   590 
Noncurrent natural gas contractsDerivative financial instruments assets and liabilities  105   118 
           
Liability Financial Instruments         
Current natural gas contractsDerivative financial instruments assets and liabilities – current portion  (489)  (510)
Noncurrent natural gas contractsDerivative financial instruments assets and liabilities  (80)  (78)
Total   77   120 
Total derivative financial instruments $75  $121 
   
December 31 2013
  December 31, 2012 
In millionsClassification Assets  Liabilities  Assets  Liabilities 
Designated as cash flow hedges and fair value hedges            
Natural gas contractsCurrent $3  $(1) $1  $(2)
Interest rate swap agreementsCurrent  -   -   3   - 
Total   3   (1)  4   (2)
                 
Not designated as cash flow hedges                
Natural gas contractsCurrent  691   (761)  394   (355)
Natural gas contractsLong-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)  These
The gross amounts of recognized assets and liabilities are netted within our Consolidated Statements of Financial Position. Some of our derivative financial instruments have asset positions which are presented as a liability in our Consolidated Statements of Financial Position andto the extent that we have derivative instruments that have liability positions which are presented as an asset in our Consolidated Statements of Financial Position.netting arrangements with the counterparties.
(2)  As required by the authoritative guidance related to derivatives and hedging, the fair valuegross amounts above are presented on a gross basis. As a result, the amountsof recognized assets and liabilities above do not include cash collateral held on deposit in broker margin accounts of $105$121 million as of December 31, 20102013 and $57$69 million as of December 31, 2009. Accordingly,2012. Cash collateral is included in the “Gross amounts above will differ from the amounts presented onoffset in our Consolidated Statements of Financial Position,Position” line of this table.
(3)  At December 31, 2013 and the fair value information presented for our derivative financial instruments in the recurring values table in Note 3.2012 we held letters of credit from counterparties that would offset, under master netting arrangements, an insignificant portion of these assets.


7379



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 56 - 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 retirementpension and postretirementother retirement benefit plans aimedwhose 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 retirement and postretirement benefit plans’ assets are actively 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 United States government obligations), cash and cash equivalents and other suitable investments.

Equity market performance and corporate bond rates have a significant effect on our reported unfundedfunded status. Changes in the projected benefit obligation (PBO) and accumulated postretirement benefit obligation (APBO), as the primary factors that drive the value of our unfunded PBO and APBO are mainly driven by the assumed discount rate and the actual return on plan assets.rate. Additionally, equity market performance has a significant effect on our market-related value of plan assets (MRVPA), which is used by our largestthe AGL Plan, to determine the expected return on the plan assets component of net annual pension plan.cost. The MRVPA is a calculated value and differs from the actual market value of plan assets. The MRVPA also recognizes the difference between the actual market value and expected market value of our plan assets and is determined by our actuaries using a five-year moving weighted average methodology.value. Gains and losses on plan assets are spread through the MR VPAMRVPA based on the five-year movingsmoothing weighted average methodology, which affects the expected return on plan assets component of pension expense.methodology.

Pension Benefits

We sponsor twothe AGL Plan, which is a tax-qualified defined benefit retirement plansplan for our eligible employees, the AGL Resources Inc. Retirement Plan (AGL Retirement Plan) and the Employees’ Retirement Plan of NUI Corporation (NUI Retirement Plan).employees. A defined benefit plan specifies the amount of benefits an eligible participant eventually will receive using information about the participant.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 Retirement Plan based on age, years of service and pay. The benefit formula for the AGL Retirement Plan is currently a career average earnings formula except for participants. Participants who were employees as of July 1, 2000 and who were at least 50 years of age as of that date. For those participants, we use a final average earnings benefit formula, and used this benefit formula for such participantsdate earned benefits until December 31, 2010 at which time any of those participantsunder a final average pay formula. Participants who were still actively employed accrued future benefitsas 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.formula on July 1, 2000.

80

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

PostretirementWelfare Benefits

We sponsor aUntil December 31, 2012, we sponsored two defined benefit postretirementretiree health care planplans for our eligible employees, the Health andAGL Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. (AGL Postretirementthe 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 PostretirementWelfare 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 PostretirementWelfare Plan provides life insurance for all employees if they have ten years of service at retirement. The state regulatory commissions have approved phase-insphase-in plans that defer a portion of other postretirementthe related benefits expense for future recovery. We recordedThe AGL Welfare Plan terms include a regulatory asset for these future recoverieslimit on the employer share of $9 million ascosts at limits based on the coverage tier, plan elected and salary level of December 31, 2010 and $10 million asthe employee at retirement.

Medicare eligible retirees covered by the AGL Welfare Plan, including all of December 31, 2009. In addition, we recordedthose at least age 65, receive benefits through our contribution to a regulatory liabilityretiree health reimbursement arrangement account. Additionally, on the pre-65 medical coverage of $6 million as of December 31, 2010 and $5 million as of December 31, 2009 forthe AGL Welfare Plan our expected expenses undercost is determined by a retiree premium schedule based on salary level and years of service. Due to the AGL Postretirement Plan. We expectcap, 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 pay $8 millionprior 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 insurance claimscost for the postretiremen t plan in 2011, but we do not anticipate making any additional contributions.employees hired after 1982.

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Effective December 8, 2003, theThe Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law. This act 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.

From January 1, through June 30, 2009, Medicare-eligible participants received prescription drugWe also have a separate unfunded supplemental retirement health care plan that provides health care and life insurance benefits throughto 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 Medicare Part Dvariety of factors in determining and selecting our assumptions for the discount rate at December 31. We based our discount rates separately for each plan offeredon an above-mean yield curve provided by our actuaries that is derived from a third partyportfolio of high quality (rated AA or better) corporate bonds with a yield higher than the regression mean curve and to which we subsidized participant premiums. Medicare-eligible retirees who opted outthe equivalent annuity cash flows.

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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 PostretirementWelfare Plan were eligible to receive a cash subsidy which could be used towards eligible prescription drug expenses. Effective July 1, 2009, Medicare eligible retirees, including all of those at least age 65, receive benefits through our contribution to a retiree health reimbursement arrangement account.as follows:

Effective January 1, 2010, enhancements were made to
  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 

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Assumed health care cost trend rates can have a significant effect on the pre-65 medical coverage by removingamounts reported for the currenthealth 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 our expected costs and implementingcost for the AGL Welfare Plan, a new cap determined byone-percentage-point increase or decrease in the new retiree premium schedule based on salary level and years of service. Consequently, there is no impact on theassumed health care trend does not materially affect periodic benefit cost or on our accumulated projected 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 AGL postretirement planyears ended December 31, 2014 through 2023 for a change in the assumed healthcare cost trend.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 theour pension and other retirement plans.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. The Actplans and established a 100% funding target (over a 7-year amortization period) for plan years beginning after December 31, 2007. If certain conditions are met, the Worker, Retiree and Employer Recovery Act of 2008 (passed December 2008) allowed us to measure our minimumIn 2013 we had no required contributions based on a funding target at 96% in 2009 and 100% in 2010.to the merged AGL Plan. In 20102012 we contributed $31a combined $40 million to our qualified pension plans. In 2009 we contributed $24 million to our qualified pension plans. For more information on our 2011 contributions to our pension plans, see Note 10.

Funded status

Based on the funded status of our defined benefit pension and postretirement benefit plans as of December 31, 2010, we reported an after-tax loss to our OCI of $28 million ($48 million before tax), a net increase of $25 million to accrued pension and postretirement obligations and a decrease of $20 million to accumulated deferred income taxes.

Assumptions

We consider a number of factors in determining and selecting assumptions for the overall expected long-term rate of return on plan assets. We consider the historical long-term return experience of our assets, the current and expected allocation of our plan assets, and expected long-term rates of return. We derive these expected long-term rates of return with the assistance of our investment advisors and generally base these rates on a 10-year horizon for various asset classes, our expected investments of plan assets and active asset management as opposed to investment in a passive index fund. We base our expected allocation of plan assets on a diversified portfolio consisting of domestic and international equity securities, fixed income, real estate, private equity securities and alternative asset classes.

We consider a variety of factors in determining and selecting our assumptions for the discount rate at December 31. We consider certain market indices including Moody’s Corporate AA long-term bond rate, the Citigroup Pension Liability rate, and other high-grade bond indices a single equivalent discount rate derived with the assistance of our actuaries by matching expected future cash flows in each year to the appropriate spot rates based in high quality (rated AA or better) corporate bonds.
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The following tables present details about our AGL Retirement Plan and the NUI RetirementPlan. No contributions were made to the Nicor Plan (retirement plans) and the AGL Postretirement Plan (postretirement plan).
  Retirement plans  Postretirement plan 
Dollars in millions 2010  2009  2010  2009 
Change in plan assets            
Fair value of plan assets, January 1, $303  $242  $63  $49 
Actual return on plan assets  37   61   8   14 
Employer contribution  31   26   7   7 
Benefits paid  (27)  (26)  (7)  (7)
Fair value of plan assets, December 31, $344  $303  $71  $63 
Change in benefit obligation                
Benefit obligation, January 1, $463  $442  $101  $95 
Service cost  11   8   -   - 
Interest cost  27   26   6   6 
Plan amendment  -   -   -   1 
Actuarial loss  57   13   7   6 
Benefits paid  (27)  (26)  (7)  (7)
Benefit obligation, December 31, $531  $463  $107  $101 
Funded status at end of year $(187) $(160) $(36) $(38)
Amounts recognized in the Consolidated Statements of Financial Position consist of                
Current liability $(1) $(1) $-  $- 
Long-term liability  (186)  (159)  (36)  (38)
Total liability at December 31, $(187) $(160) $(36) $(38)
Assumptions used to determine benefit obligations                
Discount rate  5.2 - 5.4%  5.8 - 6.0%  5.2%  5.8%
Rate of compensation increase  3.7%  3.7%  3.7%  3.7%
Accumulated benefit obligation $506  $448  Not applicable 

The components of our pension and postretirement benefit costs are set forth in the following table.2012. 

  Retirement plans  Postretirement plan 
Dollars in millions 2010  2009  2008  2010  2009  2008 
Net benefit cost                  
Service cost $11  $8  $7  $-  $-  $- 
Interest cost  27   26   26   6   6   6 
Expected return on plan assets  (28)  (29)  (32)  (5)  (4)  (6)
Net amortization  (2)  (2)  (2)  (4)  (4)  (4)
Recognized actuarial loss  10   9   3   2   2   1 
Net annual pension cost $18  $12  $2  $(1) $-  $(3)
Assumptions used to determine benefit costs                        
Discount rate  5.8 - 6.0%  6.2%  6.4%  5.8%  6.2%  6.4%
Expected return on plan assets  8.75%  9.0%  9.0%  8.75%  9.0%  9.0%
Rate of compensation increase  3.7%  3.7%  3.7%  3.7%  3.7%  3.7%

There were no other changes in plan assets and benefit obligations recognized for our retirement and postretirement plans for the year ended December 31, 2010. The 2011 estimated OCI amortization for these plans are set forth in the following table.

In millions Retirement plans  Postretirement plan 
Amortization of prior service credit $(2) $(4)
Amortization of net loss  14   2 
The following table presents expected benefit payments for the years ended December 31, 2011 through 2020 for our retirement and postretirement plans. There will be benefit payments under these plans beyond 2020.
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In millions  Retirement plans  Postretirement plan 
2011  $29  $8 
2012   29   8 
2013   29   7 
2014   30   7 
2015   31   7 
2016-2020   168   38 
Total  $316  $75 

The following table presents the amounts not yet reflected in net periodic benefit cost and included in accumulated OCI as of December 31, 2010.

In millions Retirement plans  Postretirement plan 
Prior service credit $(15) $(8)
Net loss  226   35 
Accumulated OCI  211   27 
Net amount recognized in Consolidated Statements of Financial Position  (187)  (36)
Prepaid (accrued) cumulative employer contributions in excess of net periodic benefit cost $24  $(9)

There were no other changes in plan assets and benefit obligations recognized in our retirement and postretirement plans for the year ended December 31, 2010.

Employee Savings Plan Benefits

We sponsor the Retirement Savings Plus Plan (RSP), a defined contribution retirement benefit planplans that allowsallow eligible participants to make contributions to their accounts up to specified limits. Under the RSP, we madethese plans, our matching contributions to participant accounts ofwere $16 million in 2013, $14 million in 2012 and $7 million in 2010, $7 million in 2009 and $6 million in 2008.2011.

Note 6 – Stock-based and Other Incentive Compensation Plans and Agreements

General

We currently sponsor the following stock-based and other incentive compensation plans and agreements:

  
Shares issuable upon exercise of outstanding stock options (1)
  Shares available for future issuance Details
Omnibus Performance Incentive Plan  1,109,284   3,693,004 Grants of incentive and nonqualified stock options, stock appreciation rights (SARs), shares of restricted stock, restricted stock units and performance cash awards to key employees.
Long-Term Incentive Plan (1999) (2)
  1,745,377   - Grants of incentive and nonqualified stock options, shares of restricted stock and performance units to key employees.
Officer Incentive Plan  41,438   211,409 Grants of nonqualified stock options and shares of restricted stock to new-hire officers.
2006 Non-Employee Directors Equity Compensation Plan not applicable   140,812 Grants of stock to non-employee directors in connection with non-employee director compensation (for annual retainer, chair retainer and for initial election or appointment).
1996 Non-Employee Directors Equity Compensation Plan  29,653   14,304 Grants of nonqualified stock options and stock to non-employee directors in connection with non-employee director compensation (for annual retainer and for initial election or appointment). The plan was amended in 2002 to eliminate the granting of stock options.
Employee Stock Purchase Plan not applicable   198,048 Nonqualified, broad-based employee stock purchase plan for eligible employees.
(1)  As of December 31, 2010.
(2)  Following shareholder approval of the Omnibus Performance Incentive Plan in 2008, no further grants will be made except for reload options that may be granted under the plan’s outstanding options.

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

The authoritative guidance related to stock compensation requires us toWe measure and recognize stock-based compensation expense for our stock-based awards over the requiredrequisite service period in our financial statements based on the estimated fair value at the date of grant for our stock-based awards whichusing the modified prospective method. These stock awards include:

·  stock optionsoptions;
·  stock awardsand 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 requiredrequisite 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 premium on common stock.additional paid-in capital.

We granthave 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 most recent 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 on compensation costs and income tax benefits and excess tax benefits related to our cash and stock-based compensation awards.

In millions 2010  2009  2008  2013  2012  2011 
Compensation costs (1)
 $11  $11  $10  $22  $9  $14 
Income tax benefits (1)
  2   2   1   1   1   1 
Excess tax benefits (2)
  2   2   1   -   1   1 
(1)  Recorded in our Consolidated Statements of Income.
(2)  
Recorded in our Consolidated Statements of Cash Flows.Financial Position.

Incentive and Nonqualified Stock Options

NonqualifiedThe 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, 2010,2013 and 2012, we had an immaterial amount ofno unrecognized compensation costs related to stock options. Cash received from stock option exercises for 20102013 was $9$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 less than $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.

Stock Options          
  Number of options  Weighted average exercise price  
Weighted average remaining life
(in years)
 Aggregate intrinsic value (in millions)
Outstanding – December 31, 2007  2,517,498  $33.28     
Granted  258,017   38.70     
Exercised  (212,600)  23.53     
Forfeited (1)
  (86,926)  38.01     
Outstanding – December 31, 2008  2,475,989  $34.52     
Granted  250,440   31.09     
Exercised  (119,126)  27.20     
Forfeited (1)
  (55,735)  36.50     
Outstanding – December 31, 2009  2,551,568  $34.48   6.0  
Granted  -   -   -  
Exercised  (296,008)  31.33   3.9  
Forfeited (1)
  (26,448)  37.85   6.3  
Outstanding – December 31, 2010  2,229,112  $34.85   5.2 $5
Exercisable – December 31, 2010  1,799,334  $34.92   4.9 $4
(1) Includes 14,692 shares which expired in 2010, 13,716 in 2009 and 4,226 in 2008.  

7884

Unvested Stock Options            
  Number of unvested options  Weighted average exercise price  Weighted average remaining vesting period(in years)  Weighted average fair value 
Outstanding – December 31, 2009  784,320  $35.68   1.2  $3.29 
Granted  -   -   -   - 
Forfeited  (3,820)  32.67   1.5   1.97 
Vested  (350,722)  37.07   -   3.52 
Outstanding – December 31, 2010  429,778  $34.58   0.5  $3.11 

Information about outstanding and exercisable options as of December 31, 2010, is as follows.
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.

   Options outstanding  Options Exercisable 
Range of Exercise Prices  Number of options  
Weighted average remaining contractual life
(in years)
  Weighted average exercise price  Number of options  Weighted average exercise price 
$ 20.69 to $24.49   126,229   1.1  $21.99   126,229  $21.99 
$ 24.50 to $28.30   117,925   2.6   26.86   117,925   26.86 
$ 28.31 to $32.11   251,285   7.6   30.87   93,924   30.51 
$ 32.12 to $35.92   887,910   4.7   35.03   687,910   34.80 
$ 35.93 to $39.73   806,767   6.0   38.76   734,350   38.76 
$ 39.74 to $43.54   38,996   5.6   41.45   38,996   41.45 
Outstanding - Dec. 31, 2010   2,229,112   5.2  $34.85   1,799,334  $34.92 

Summarized below are outstanding options that are fully exercisable.

Exercisable at: Number of options  Weighted average exercise price 
December 31, 2008  1,447,508  $32.18 
December 31, 2009  1,767,248  $33.94 
December 31, 2010  1,799,334  $34.92 

We measure compensation expensecost related to stock options based on the fair value of these awards at their date of grant using the Black-Scholes option-pricing model. The following table shows the ranges for per share value and information about the underlying assumptions used in developing the grant date value for each of the grants made during 2009 and 2008. There were no options granted in 2010.

  2009  2008 
Expected life (years)  7   7 
Risk-free interest rate % (1)
  2.30%  2.93 - 3.31%
Expected volatility % (2)
  12.9%  12.8 - 13.0%
Dividend yield % (3)
  5.5%  4.3 - 4.84%
Fair value of options granted (4)
 $1.24  $0.19 - $2.69 
(1)  United States Constant Maturity Treasury Rate.
(2)  Weighted average volatility.
(3)  Weighted average dividend yield.
(4)  Represents per share value.

Intrinsic value for options is defined as the difference between the current market value2013 and 2012, and the grant price. Total intrinsic valuenumber of options exercised during 2010granted in 2011 was $2 million. With the implementation of our share repurchase program in 2006, weimmaterial. We use shares purchased under thisour 2006 share repurchase program to satisfy share-based exercises to the extent that repurchased shares are available. Otherwise, we issue new shares from our authorized common stock.

Performance Units

The dollar value of restricted stock unit awards is equal to the grant date fair value of the awards, over the required service period, determined according to the authoritative guidance related to stock compensation. The dollar value of performance cash unit awards is equal to the grant date fair value of the awards measured against progress towards the performance measure, over the required service period, determined according to the authoritative guidance related to stock compensation. No other assumptions are used to value these awards. 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. Perf ormancePerformance 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.

79

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 2010,2013, we granted to a select group a total of 154,250 43,830 restricted stock units to certain employees, all of which 149,500 of these units were outstanding as of December 31, 2010.2013. These restricted stock units had a performance measurement period that ended December 31, 2010, which was achieved, and a2013. The performance measure, which related to a basic earnings per common share attributable to AGL Resources Inc. common shareholders goal thatbefore interest, income tax, depreciation and amortization, was met. As such, the related restricted stock awards will occur in 2014.

Performance Cash Awards In general, a performance cash award represents the opportunity to receive cash, subject to the achievement of certain pre-established performance criteria. In 2010, we did not grant any performance cash awards. These awards have a performance measure that is related to annual growth in basic earnings per common share attributable to AGL Resources Inc. common shareholders and the average dividend yield. Accruals in connection with these grants are as follows:

In millions
Measurement
period end date
 
Accrued at
Dec. 31, 2010
  Maximum aggregate payout 
Year of grant       
2008 (1)
Dec. 31, 2010 $2  $3 
2009 (1)
Dec. 31, 2011  1   4 
(1)  Adjusted to reflect the effect of economic value created during the performance measurement period by our wholesale services segment.

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. In 2010 weWe granted performance share unit awards to a select group ofcertain officers. These awards have a performance measure that relates to the company’sCompany’s relative total shareholder return relative to a group of peer companies. Accruals in connection with theseThe recorded liability and maximum potential liability related to the 2013, 2012 and 2011 grants are as follows:

In millionsMeasurement period end date 
Accrued at
Dec. 31, 2010
  Maximum aggregate payout Measurement period end date Fair value accrued at December 31, 2013  Maximum aggregate payout 
Granted in 2010Dec. 31, 2012 $2  $10 
Granted in 2011December 31, 2013 $7  $12 
Granted in 2012December 31, 2014 $6  $18 
Granted in 2013December 31, 2015 $3  $18 

Stock and Restricted Stock Awards

The dollar valuecompensation cost of both stock awards and restricted stock awards areis equal to the grant date fair value of the awards, recognized over the requiredrequisite service period, determined in accordance with the authoritative guidance related to stock compensation.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 nonforfeitablenon-forfeitable as of the date of grant. The following table summarizes activity during 2010, relatedDuring 2013 we issued 26,915 shares with a weighted average fair value of $44.04 to stock awards for our non-employee directors.
  Shares of restricted stock  Weighted average fair value 
Issued  11,928  $39.16 
Forfeited  -   - 
Vested  11,928  $39.16 
Outstanding  -   - 
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Restricted Stock Awards - Employees The following table summarizes the restricted stock awards activity for our employees during the last threetwo years.

 Shares of restricted stock  Weighted average remaining vesting period (in years)  Weighted average fair value  
Shares of
restricted stock
  
Weighted average remaining vesting period (in years)
  
Weighted average
fair value
 
Outstanding – December 31, 2008 (1)
  300,378     $38.20 
Outstanding - December 31, 2011 (1)
  477,354     $34.40 
Issued  191,300      31.09   268,840      40.08 
Forfeited  (15,616)     36.03   (28,829)     39.07 
Vested  (134,817)     39.17   (214,274)     36.45 
Outstanding – December 31, 2009 (1)
  341,245   1.0  $33.93 
Outstanding - December 31, 2012 (1)
  503,091   1.8  $39.44 
Issued  205,030   3.0   36.34   175,935   2.8   42.41 
Forfeited  (16,153)  1.8   34.13   (33,352)  2.0   40.64 
Vested  (129,222)  -   35.19   (204,421)  0.0   38.71 
Outstanding – December 31, 2010 (1) (2)
  400,900   2.4  $30.80 
Outstanding - December 31, 2013 (1)
  441,253   1.8  $40.82 
(1)  Subject to restriction.
(2)Includes 82,222 restricted shares with nonforfeitable dividend rights.
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Employee Stock Purchase Plan (ESPP)

Under theWe have a nonqualified, broad based ESPP employeesfor 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.value, and we record an expense for the 15% purchase price discount. Employee ESPP contributions under the ESPP may not exceed $25,000 per employee during any calendar year.

 2010  2009  2008  2013  2012  2011 
Shares purchased on the open market  60,017   63,847   66,247   103,343   108,132   65,843 
Average per-share purchase price $37.07  $31.45  $33.22  $42.96  $38.96  $40.55 
Purchase price discount $333,639  $298,968  $326,615 
Total purchase price discount $664,286  $618,278  $401,346 


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Note 7 8- Debt and Credit Facilities

Our short-term and long-term borrowing arrangements provide the liquidity and capital we need to execute our business strategy, conduct business operations and pursue long-term growth opportunities. Our issuance of various securities,financing activities, including long-term and short-term debt, isare subject to customary approval authorization or review by state and federal regulatory bodies, including public service commissions inbodies. Our wholly-owned subsidiary, AGL Capital, was established to provide for our ongoing financing needs through a commercial paper program, the states where we conduct business, the SECissuance of various debt and the FERC.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 shows allprovides maturity dates, year-to-date weighted average interest rates and amounts outstanding for our various debt obligationssecurities and facilities that are included in our Consolidated Statements of Financial Position.

   December 31, 2010  December 31, 2009 
Dollars in millionsYear(s) due Weighted average interest rate  Outstanding  Weighted average interest rate  Outstanding 
Short-term debt             
Commercial paper2011  0.4% $732   0.7% $601 
Current portion of long-term debt2011  7.1   300   -   - 
Current portion of capital leases2011  4.9   1   4.9   1 
Total short-term debt   3.2% $1,033   0.8% $602 
Long-term debt                
                  
Senior notes                 
Issued February 20012011  -% $-   7.1% $300 
Issued July 20032013  4.5   225   4.5   225 
Issued December 20042015  5.0   200   5.0   200 
Issued June 2006 & December 20072016  6.4   300   6.4   300 
Issued August 20092019  5.3   300   5.3   300 
Issue September 20042034  6.0   250   6.0   250 
Total   5.5% $1,275   5.8% $1,575 
Gas facility revenue bonds                 
Issued July 19942022  0.3% $46   0.2% $46 
Issued July 19942024  0.4   20   0.6   20 
Issued June 19922026  0.2   39   0.2   39 
Issued June 19922032  0.3   55   0.2   55 
Issued July 19972033  5.3   40   5.3   40 
Total   1.3% $200   1.2% $200 
Medium-term notes                 
Issued June 19922012  8.3 - 8.4% $15   8.3 - 8.4% $15 
Issued July 19972017  7.2   22   7.2   22 
Issued February 19912021  9.1   30   9.1   30 
Issued April - May 19922022  8.6 - 8.7   46   8.6 - 8.7   46 
Issued November 19962026  6.6   30   6.6   30 
Issued July 19972027  7.3   53   7.3   53 
Total   7.8% $196   7.8% $196 
Capital leases2013  4.9% $2   4.9% $3 
Total long-term debt   5.2% $1,673   5.5% $1,974 
                  
Total debt   4.6% $2,706   4.6% $2,576 
     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.

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Short-term Debt

Short-termOur short-term debt at December 31, 2013 and 2012 was composed of borrowings primarily supportunder 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 that exceed cash generated from operations.requirements. Working capital needs fluctuate significantly during the year and are highest during the injection period in advance of the Heating Season, as we build upSeason. The Nicor Gas commercial paper program supports working capital needs at Nicor Gas, while all of our natural gas inventoryother subsidiaries and purchase additional pipeline capacitySouthStar participate in the AGL Capital commercial paper program. During 2013, our commercial paper maturities ranged from 1 to meet customer demand.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.

Our short-termCredit 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, 2010 and 20092012 was composed of borrowings under our commercial paper program andthe current portions of our long-term debt and capital lease obligations.

Commercial Paper Our commercial paper consistscapital leases consisted primarily of short-term, unsecured promissory notesa sale/leaseback transaction of gas meters and other equipment that have fixed maturities rangingwas 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 3 to 18 days. Commercial paper proceeds are used in conjunction with cash from operations to fund seasonal working capital requirements. Several of our subsidiaries, including SouthStar, participate in our commercial paper program.

Senior Notes We had $300 million of senior notes issued in 2001 that matured in January 2011, which are reported as current portion of long-term debt on our December 31, 2010 Consolidated Statements of Financial Position.the lessor at their fair market value, but it did not exercise this option.

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In December 2010, we amended the Credit Facility to adjust total available principal from $1.25 billion to $1.75 billion, amended our financial debt covenant to exclude the Bridge Facility and reset the maturity date to September 2013. At December 31, 2010, we had no outstanding borrowings under this facility.

SouthStar Credit Facility SouthStar’s five-year $75 million unsecured credit facility expires in November 2011. SouthStar uses this line of credit for working capital and general corporate needs. SouthStar had no outstanding borrowings on this line of credit at December 31, 2010 or 2009. We do not guarantee or provide any other form of security for the repayment of this credit facility.
Long-term Debt

Our long-term debt arrangements are structured to provide sufficient financing to support current business operations and fund capital investments for future growth. We seek to maintain investment grade ratings and to satisfy our financial and non-financial covenants.

Our long-term debt at December 31, 20102013 and 20092012 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 capital leases. The trusteeeach institutional investor that purchased the bonds represented that it was purchasing the bonds for its own account and not with respecta view to our senior notes is The Bank of New York Trust Company, N.A., in accordance with an indenture dated February 20, 2001.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 excluding capital leases of $2 million,and thereafter are as follows:

Year 
Amount
(in millions)
  % of total  
Amount
(in millions)
 
2011 $300   15%
2012  15   1 
2013  225   11 
2014  -   -  $- 
2015  200   10   200 
2016  545 
2017  22 
2018  155 
Thereafter  1,231   63   2,784 
Total $1,971   100% $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. In June and September 2010, the letters of credit supporting the gas revenue bonds were set to expire, and according to the terms of the bond indentures, we repurchased the bonds before the expiration of the letters of credit using the proceeds of commercial paper issuances.

In October 2010,During 2013 we successfully remarketed $160refinanced $200 million inof 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 ratesthe syndicate of banks regarding the bonds is governed by an agreement that reset daily.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 weighted average interest rates during 2010 ranged from 0.23% to 5.25%. New letters of credit which will expire in years 2022-2033,providing credit support for the outstanding revenue bonds along with other related agreements were issued by the banks to support eachterminated as a result of the four series of gas revenue bonds. We also amended our loan agreements with the state organizations in order to eliminate third party guaranty insurance on the bonds.

In December 2010, we amended certain provisions in the letters of credit agreements, the most significant of which excludes the Bridge Facility from the calculation of the consolidated total debt to total capitalization ratio.
82

Term Loan Credit Facility In December 2010, we entered into a $300 million unsecured 180-day Term Loan Facility, which was intended to help pay our 7.125% senior notes that matured in January 2011. Borrowings under the Term Loan Facility will expire 180 days from issuance, and amounts that are repaid cannot be re-borrowed. The Term Loan Facility bears interest at a floating base rate or floating Eurodollar interest rate, plus a spread ranging from 0.5% to 2.5%, based on our credit ratings and interest rate option. At December 31, 2010, we had no borrowings outstanding under this Term Loan Facility.
Proposed Merger Financing

In anticipation of the proposed merger with Nicor, we amended our existing Credit Facility to increase its accordion feature from $250 million to $750 million, and entered into a Bridge Facility to ensure we have adequate liquidity and financing in place to complete the proposed merger.

In December 2010, we entered into a 364-day Bridge Facility to provide temporary financing in the event that permanent financing cannot be secured prior to completion of the merger. We may borrow up to $1.05 billion under the Bridge Facility, and proceeds may be used to fund the cash portion of our proposed merger and pay related fees and expenses. We had no borrowings outstanding under this Bridge Facility at December 31, 2010.refinancing.

The interest rate is defined as the higher of the following:
·  
the highest rate we or our subsidiaries pay on any similar facility; or,
·  at our option, either a floating base rate or floating Eurodollar rate, plus 0.5%-2.5% margin based on our credit ratings and interest rate option and an additional 0.25% margin for every 90-day period past the maturity date that we fail to pay the balance of loans outstanding.

Financial and Non-Financial Covenants

The AGL Credit Facility includesand the Nicor Gas Credit Facility each include a financial covenant that requires us to maintain a ratio on a consolidated basis, of total debt to total capitalization of no more than 70% (excluding for these purposes, debt incurred to partially refinanceat the Bridge Facility during the period prior to funding under the Bridge Facility);end of any fiscal month; however, our goal is to maintain this ratiothese ratios at levels between 50% and 60%. Our ratio, on a consolidated basis, of total debt to total capitalizationThese ratios, as calculated in accordance with ourthe debt covenant includescovenants, include standby letters of credit and surety bonds and excludes other comprehensive incomeexclude accumulated OCI items related to non-cash pension adjustments.adjustments, welfare benefits liability adjustments and accounting adjustments for cash flow hedges. Adjusting for these items, the following table contains our debt-to-capitalization ratio was 58% at December 31, 2010 and 57% at December 31, 2009. These amountsratios for the dates presented, which are within our required and targeted ranges.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 Facility containscredit 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.We are currently in compliance with all existing debt provisions and covenants.


Our Bridge Facility and Term Loan Facility each contain the same financial covenant and similar non-financial covenants and default provisions; however, these are not effective until we draw under the facilities.
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Default Provisions

Our debt instrumentscredit facilities and other financial obligations include provisions that, if not complied with, could require early payment additional collateral support or similar actions. OurThe 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 triggertriggering 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 triggertriggering 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, 20102013 and 2009,2012, 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.

Capital Leases

Our capital leases consist primarily of a sale/leaseback transaction completed in 2002 by Florida City Gas. The sale/leaseback of its gas meters and other equipment will be repaid at approximately $1 million per year until 2013. Based on the terms of the lease agreement, Florida City Gas is required to insure the leased equipment during the lease term. At the expiration of the lease term, Florida City Gas has the option to purchase the leased meters from the lessor at their fair market value. The fair market value of the equipment will be determined based on an arm’s-length transaction between an informed and willing buyer.

Note 8 –9 - Equity

Treasury Shares

Our Board of Directors has authorized us to purchase up to 8 million treasury shares through our repurchase plan.plan, which expired on January 31, 2011. This plan iswas 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 may bewere made in the open market or in private transactions at times, and in amounts that we deemdeemed appropriate. There is no guarantee as to the exact number of shares that we will purchase, and we can terminate or limit the program at any time. We will holdheld the purchased shares as treasury shares and accountaccounted for them using the cost method. In 2010, we spent $7 million to purchase approximately 0.2 millionWe purchased no treasury shares at a weighted average price per share of $36.01. We did not make any treasury share purchases in 20092013 or 2008. As of December 31, 2010, we had approximately 5 million remaining authorized shares available for purchase. This repurchase plan expires on January 31, 2011.2012.

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 oblig ationsobligations 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 and net income attributable to AGL Resources Inc. plus OCI, which includes changes in fair value of certain derivatives designated as cash flow hedges, certain changes in pension and other postretirementretirement benefit plans and reclassifications for amounts included in net income andless net income and OCI attributable to AGL Resources Inc.the noncontrolling interest. For more information on our derivative financial instruments, see Note 4.5. For more information on our pensions and postretirementretirement benefit obligations, see Note 5.6. 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, andnet of the related tax effects allocated to each component of OCI.

  Derivative financial instruments  Pensions and postretirement obligations   Accumulated 
In millions Before tax amount  Tax expense (benefit)  After tax amount  Before tax amount  Tax expense (benefit)  After tax amount  other comprehensive loss 
As of Dec. 31, 2007 $12  $5  $7  $(33) $(13) $(20) $(13)
Other comprehensive loss  (16)  (6)  (10)  (184)  (73)  (111)  (121)
As of Dec. 31, 2008  (4)  (1)  (3)  (217)  (86)  (131)  (134)
Other comprehensive income  3   2   1   27   10   17   18 
As of Dec. 31, 2009  (1)  1   (2)  (190)  (76)  (114)  (116)
Other comprehensive loss  (9)  (4)  (5)  (48)  (20)  (28)  (33)
Purchase of additional 15% ownership interest in SouthStar  (1)  -   (1)  -   -   -   (1)
As of Dec. 31, 2010 $(11) $(3) $(8) $(238) $(96) $(142) $(150)
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.

Note 9 – Non-Wholly-Owned EntityThe 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, markets natural gas and related services underis the trade name GNG to retail customers primarily in Georgia, and under various other trade names to retail customers in Ohio and Florida and to commercial and industrial customers, principally in Alabama, Florida, Georgia, North Carolina, South Carolina and Tennessee.

The primary risks associated with SouthStar are discussed in our risk factors included in Item 1A. SouthStar utilizes derivative financial instruments to manage natural gas price and weather risks. See Note 3 and Note 4 for additional disclosures of these instruments. SouthStar is involved in litigation arising from the normal course of business. For more information see Note 10.

In July 2009, we entered into an amended joint venture agreement with Piedmont pursuant to which we purchased an additional 15% ownership interest in SouthStar for $58 million, effective January 1, 2010, thus increasing our ownership interest to 85%. This was accounted for as an acquisition of equity interests. Piedmont retained the remaining 15% share. We have no further option rights to purchase Piedmont’s remaining 15% ownership interest and all significant management decisions continue to require approval by both owners. The following table provides the effects the purchase had on our equity.
In millions Premium on common stock  Accumulated other comprehensive loss  Total 
Purchase of additional 15% ownership interest $(51) $(1) $(52)

Earnings in 2010 were allocated entirely in accordance with the ownership interests. Earnings in 2009 were allocated 75% to us and 25% to Piedmont except for earnings related to customers in Ohio and Florida, which were allocated 70% to us and 30% to Piedmont. We account for our ownership of SouthStar in accordance with authoritative accounting guidance which is fully described within Note 2.

Through our evaluation of our partnership interests, we have concluded that SouthStar is aonly VIE for which we are the primary beneficiary. 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
 
Operations
Our wholly-owned subsidiary,wholly owned subsidiaries, Nicor Gas and Atlanta Gas Light, providesprovide the following services, in accordance with Georgia Commission authorization thatwhich affect SouthStar’s operations:

·  provides meter reading services for SouthStar’s customers in Illinois and Georgia
·  maintainsmaintenance and expandsexpansion of the natural gas infrastructure in Illinois and Georgia
·  markets the benefits of natural gas, performs outreach to residential and commercial developers, offers natural gas appliance rebates and billboard and print advertising, all of which support SouthStar’s efforts to maintain and expand its residential, commercial and industrial customers in its largest market, Georgia
·  assignsassigning storage and transportation capacity used in delivering natural gas to SouthStar’s customers

Liquidity and capital resources

·  we provide guarantees forof SouthStar’s activities with, its counterparties,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 utilizes ourhas adequate liquidity and working capital resources by allowing SouthStar to utilize the AGL Capital commercial paper program for its liquidity and working capital requirements. We support SouthStar’s daily cash management activities and assistrequirements in accordance with ensuring SouthStar has adequate liquidity and working capital resourcesour services agreement.

Back office functions

·  Accounting, information technology, credit and internal controls services in accordance with our services agreement we provide services to SouthStar with respect to accounting, information technology, credit and internal controls

See Note 12 for summarized statementsSouthStar’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 income, statements of financial position and capital expenditure information related to the retail energy operations segment, which is primarily comprised of SouthStar.

each year. SouthStar’s current assets consist primarily of natural gas inventory, derivative financial instruments and receivables from its customers. SouthStar also has receivables from us due to its participation in ourAGL Capital’s commercial paper program. See Note 2 for additional discussions of SouthStar’s inventories. The nature of restrictions on SouthStar’s assets is immaterial, and make up less than one tenth of one percent of our consolidated net assets for the years ended December 31, 2010 and 2009. SouthStar’s current liabilities consist primarily of accrued natural gas costs, other accrued expenses, customer deposits, derivative financial instruments and payables to us from its participation in our commerc ialAGL Capital’s commercial paper program.

As of December 31, 2010, SouthStar’s current assets, which approximate fair value, exceeded its current liabilities, long-term assets and other deferred debits, long-term liabilities and other deferred credits by approximately $137 million. Further, SouthStar’s other 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 n ono 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.

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 financial instruments.

Cash flows used in our investing activities includesinclude capital expenditures of $3 million for SouthStar for the year ended December 31, 2010,of $3 million for 2013, $1 million for 2012 and $2 million for the same period of 2009.2011. Cash flows used in our financing activities includesinclude SouthStar’s distributions to the noncontrolling interest, which reflects the cash distribution to Piedmont for its applicable portion of SouthStar’s annual earnings from the priorprevious year. Generally, this distribution occurs in the first or second quarter.quarter of each fiscal year. For the yearyears ended December 31, 2010,2013, 2012 and 2011, SouthStar distributed $27$17 million, $14 million and $16 million to Piedmont, and $20 million during the year ended December 31, 2009. The increase of $7respectively.

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 distributions that SouthStar madeto 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 wasregarding the resultvalue of higher earnings.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 tables providetable provides additional information on SouthStar’s assets and liabilities as of December 31, 2010 and 2009,the dates presented, which are consolidated within our Consolidated Statements of Financial Position.
  As of December 31, 2010    
In millions Consolidated  
SouthStar (1)
   % (2) 
Current assets $2,162  $239   11%
Long-term assets and other deferred debits  5,356   9   - 
Total assets $7,518  $248   3%
Current liabilities $2,428  $93   4%
Long-term liabilities and other deferred credits  3,254   -   - 
Equity  1,836   155   8 
Total liabilities and equity $7,518  $248   3%

 As of December 31, 2009     December 31, 2013  December 31, 2012 
In millions Consolidated  
SouthStar (1)
   % (2)  Consolidated  
SouthStar (1)
   %(2)  Consolidated  
SouthStar (1)
   %(2) 
Current assets $2,000  $238   12% $2,733  $264   10% $2,668  $201   8%
Long-term assets and other deferred debits  5,074   9   - 
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 $7,074  $247   3% $14,656  $415   3% $14,141  $211   1%
Current liabilities $1,772  $96   5% $3,122  $95   3% $3,338  $62   2%
Long-term liabilities and other deferred credits  3,483   -   -   7,858   -   -   7,368   -   - 
Total liabilities  10,980   95   1   10,706   62   1 
Equity  1,819   151   8   3,676   320   9   3,435   149   4 
Total liabilities and equity $7,074  $247   3% $14,656  $415   3% $14,141  $211   1%
(1)(1) These amounts reflect information for SouthStar and do not includeexclude intercompany eliminations and the balances of a wholly-ownedour wholly owned subsidiary with thean 85% ownership interest for 2010, and 70% ownership for 2009, in SouthStar. Accordingly, the amounts will not agree to the identifiable and total assets for our retail energy operations segment reported in Note 12.
(2)(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.

Note 10 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- Commitments and Contingenciesmile 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.



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 such as debtunder our obligations and lease agreements, and commitment and contingenciesother commitments as of December 31, 2010.2013.

       2012 &  2014 &  2016 &                    2019 & 
In millions Total  2011  2013  2015  thereafter  Total  2014  2015  2016  2017  2018  thereafter 
Recorded contractual obligations:                                    
               
Long-term debt $1,673  $-  $242  $200  $1,231 
Short-term debt (1)
  1,033   1,033   -   -   - 
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)
  228   62   166   -   -   5   5   -   -   -   -   - 
Environmental remediation liabilities (2)
  143   14   62   53   14 
Total $3,077  $1,109  $470  $253  $1,245  $5,329  $1,246  $282  $625  $70  $218  $2,888 

Unrecorded contractual obligations and commitments (3) (9):
               
               
Unrecorded contractual obligations and commitments (3) (8):
                     
Pipeline charges, storage capacity and gas supply (4)
 $1,899  $523  $663  $262  $451  $2,298  $733  $507  $299  $138  $102  $519 
Interest charges (5)
  897   89   166   144   498   2,899   185   175   161   147   145   2,086 
Operating leases (6)
  95   22   30   13   30   233   39   34   28   25   18   89 
Pension contributions (7)
  30   30   -   -   - 
Asset management agreements (8)  15   10   3   2   - 
Standby letters of credit, performance / surety bonds  14   12   2   -   - 
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 $2,950  $686  $864  $421  $979  $5,493  $1,000  $724  $495  $314  $266  $2,694 
(1)  Includes current portionExcludes the $82 million step up to fair value of long-termfirst mortgage bonds, $16 million unamortized debt of $300premium and $9 million which matures in January 2011.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 amountbalance includes amounts for Nicor Gas and SouthStar gas commodity purchase commitments of 1431 Bcf at floating gas prices calculated using forward natural gas prices as of December 31, 2010,2013, and is valued at $63$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 debt isinterest charges are calculated based on the interest rate as of December 31, 20102013 and the maturity date of the underlying debt instrument. As of December 31, 2010,2013, we have $40$52 million of accrued interest on our Consolidated Statements of Financial Position that will be paid in 2011.2014.
(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 authoritative guidance related to leases.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)  Based on the current funding status of the plans, we would be required to make a minimum contribution to our pension plans of approximately $30 million in 2011. We may make additional contributions in 2011.
(8)  
Represent fixed-fee minimum payments for Sequent’s affiliated asset management agreements.
agreements.
(9)(8)  The Merger Agreement with Nicor contains termination rights for both usWe provide guarantees to certain municipalities and Nicorother agencies and provides that, if we terminate the agreement under specified circumstances, we may be required to pay a termination feecertain gas suppliers of $67 million. In addition, if we terminate the agreement due to a failure to obtain the necessary financing for the transaction, we may also be required to pay Nicor $115 million.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.

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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 Remediation CostsMatters

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. The following table provides more information on the costs related to remediation of our former operating sites.

In millions Cost estimate range  Amount recorded  Expected costs over next twelve months 
Georgia and Florida $57 - $105  $57  $4 
New Jersey  75 - 138   75   10 
North Carolina  11 - 16   11   - 
Total $143 - $259  $143  $14 

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We have confirmed 14 former operating sites in Georgia and Florida where Atlanta Gas Light owned or operated all or part of these sites. Precise engineering soil and groundwater clean up estimates are not available and considerable variability exists with this potential new site. As of December 31, 2010, the soil and sediment remediation program was substantially completeSee Note 3 for all Georgia sites, except for a few remaining areas of recently discovered impact, although groundwater cleanup continues. Investigation is concluded for one phase of the Orlando, Florida site; however, the Environmental Protection Agency has not approved the clean up plans. For elements of the Georgia and Florida sites where we still cannot provide engineering cost estimates, considerable variability remains in future cost estimates.
We have identified 6 former operating sites in New Jersey where Elizabethtown Gas owned or operated all or part of these sites. Material cleanups of these sites have not been completed nor are precise estimates available for future cleanup costs and therefore considerable variability remains in future cost estimates. We have also identified a site in North Carolina, which is subject to a remediation order by the North Carolina Department of Energy and Natural Resources, and there are no cost recovery mechanisms for the environmental remediation.

Our ERC liabilities are included as a corresponding regulatory asset. These recoverable ERC assets are a combination of accrued ERC liabilities and recoverable cash expenditures for investigation and cleanup costs. We primarily recover these costs through rate riders and expect to collect $7 million in revenues over the next 12 months which is reflected as a current asset. We recovered $13 million in 2010, $20 million in 2009 and $23 million in 2008 from our ERC rate riders.

Rental Expenseadditional information.

We incurred rental expenseare involved in an investigation by the EPA regarding the applicable regulatory requirements for polychlorinated biphenyl in the amountsNicor Gas distribution system. While we are unable to predict the outcome of $20 million in 2010, $20 million in 2009this matter or to reasonably estimate our potential exposure related thereto, if any, and $21 million in 2008.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. We believeAlthough in some cases we are unable to estimate the ultimateamount of loss reasonably possible in addition to any amounts already recognized, it is possible that the resolution of such litigationthese 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.

In February 2008, a class action lawsuit was filed in the Superior Court of Fulton County in the State of Georgia against GNG alleging that it charged its customers of variable rate plans pricesPBR 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 in excesscompared 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 published price, failedsavings and losses required to give proper notice regardingbe shared has been disputed by the availability of potentially lower price plansCitizens Utility Board (CUB) and that it changed its methodology for computing variable rates. GNG asserts that no violation ofothers, with the Illinois Attorney General (IAG) intervening, and subject to extensive contested discovery and other regulatory proceedings before administrative law or Georgia Commission rules has occurred. This lawsuit was dismissed in September 2008. The plaintiffs appealedjudges and the dismissalIllinois Commission. In 2009, the staff of the lawsuitIllinois Commission, the staff of the IAG and in May 2009, the Georgia CourtCUB requested refunds of Appeals reversed the lower court’s order. $85 million, $255 million and $305 million, respectively. 

In June 2009, GNG filedFebruary 2012, we committed to a petition for reconsiderationstipulation with the Georgia Supreme Court.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 October 2009 the Georgia Supreme Court agreed to review the Courtfourth quarter of Appeals’ decision. Accordingly, the Georgia Supreme Court held oral arguments in January 2010. In March 2010 the Georgia Supreme Court upheld the Court2012, we increased our accrual for this dispute by $8 million for a total of Appeals’ decision. The case has been remanded back to the Superior Court of Fulton County for further proceedings. GNG asserts that no violation of law or Georgia Commission rules has occurred. This case has not had, and is not expected to have, a material impact on our results of operation or financial condition.
We have been named$72 million as a defendantresult 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 several class action lawsuits brought by purported Nicor shareholders challenging Nicor’s proposed merger with us.2013. The complaints allege that we aided and abetted alleged breaches of fiduciary duty by Nicor’s Board of Directors. The shareholder actions seek, among other things, declaratory and injunctive relief, including orders enjoining the defendants from completing the proposed merger and, in certain circumstances, damages. We believe the claims asserted in each lawsuitCUB is continuing to be without merit and intend to vigorously defend against them.pursue its claim.

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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 11 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 shown in the Consolidated Statements of Income are shown in the following table.

In millions 2010  2009  2008  2013  2012  2011 
Current income taxes                  
Federal $37  $23  $37  $166  $9  $(89)
State  12   8   7   35   4   1 
Deferred income taxes                        
Federal  86   94   77   2   134   196 
State  6   11   12   (9)  20   18 
Amortization of investment tax credits  (1)  (1)  (1)  (3)  (3)  (1)
Total $140  $135  $132  $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, 2010, 2009 and 2008 onin our Consolidated Statements of Income are presented in the following table.

In millions 2010  2009  2008  2013  2012  2011 
Computed tax expense at statutory rate $136  $134  $129  $178  $158  $109 
State income tax, net of federal income tax benefit  15   16   15   21   19   14 
Sale of Compass Energy  6   -   - 
Tax effect of net income attributable to the noncontrolling interest  (6)  (11)  (8)  (7)  (6)  (6)
Amortization of investment tax credits  (1)  (1)  (1)  (3)  (3)  (1)
Affordable housing credits  (2)  (2)  (2)  (2)  (2)  (1)
Flexible dividend deduction  (2)  (2)  (2)  (2)  (2)  (2)
Other – net  -   1   1 
Change in control payments  -   -   9 
Merger transaction costs  -   -   3 
Total income tax expense on Consolidated Statements of Income $140  $135  $132  $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. Because of the regulated nature of the utilities’ business, we recorded a regulatory tax liability in accordance with authoritative guidance related to income taxes, which we are amortizing over approximately 30 years (see Note 2). Our deferred tax assets include $94 million related to an unfunded pension and postretirement benefit obligation, an increase of $20 million from 2009.

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.

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 As of December 31,  As of December 31, 
In millions 2010  2009  2013  2012 
Accumulated deferred income tax liabilities            
Property – accelerated depreciation and other property-related items $863  $760 
Mark to market  11   9 
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  -   2   128   126 
Total accumulated deferred income tax liabilities  874   771   1,800   1,763 
Accumulated deferred income tax assets                
Unfunded pension and retiree welfare benefit obligation  92   145 
Deferred investment tax credits  4   5   7   9 
Unfunded pension and postretirement benefit obligation  94   74 
Mark-to-market  4   - 
Other  11   -   44   43 
Total accumulated deferred income tax assets  109   79   147   197 
Valuation allowances (1)
  (3)  (3)  (14)  (22)
Total accumulated deferred income tax assets, net of valuation allowance  106   76   133   175 
Net accumulated deferred tax liability $768  $695 
Net non-current accumulated deferred tax liability $1,667  $1,588 
(1)  Valuation
The total valuation allowance is $22 million, which is comprised of $3 million valuation allowance is due to the net operating losses onof a former non-operating subsidiary that are not allowed in New Jersey.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, 20102013 and December 31, 2009,2012, we did not have a liability for unrecognized tax benefits. Based on current information, we do not anticipate that this will change materially in 2011.2014. As of December 31, 2010,2013, we did not have a liability recorded for payment of interest andor penalties associated with uncertain tax positions.positions nor did we have any such interest or penalties during 2013 or 2012.

We file a United StatesU.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 for years before 2008 or in any state for years before 2006.2008.
89

Note 12 13 - Segment Information

We generate nearly all our operating revenues through the sale, distribution, transportation and storage of natural gas. 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 fourfive operating segments - distribution operations, retail energy operations, wholesale services, midstream operations, cargo shipping and energy investments and a nonoperating corporate segment.one non-operating segment, other.

Our distribution operations segment is the largest component of our business and includes natural gas local distribution utilities in six states - Florida, Georgia, Maryland, New Jersey, Tennessee and Virginia.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 energy operations segment includes retail natural gas marketing to end-use customers primarily in Georgia.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 includesengages in natural gas storage and gas pipeline arbitrage and related activities. Additionally, they provide natural gas asset management andand/or related logistics activitiesservices for each of our utilities, as well as for nonaffiliatednon-affiliated companies, natural gas storage arbitrage and related activities. Our energy investmentsmidstream operations segment includes a number of aggregated businesses that are relatedour non-utility storage and complementary to our primary business, the most significant of which ispipeline operations, including the development and operation of high-deliverability natural gas storage assets.

96

Our cargo shipping segment transports containerized cargo between Florida, the eastern coast of Canada, the Bahamas and the Caribbean region. Our corporatecargo 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 a reare not significant enough on a stand-alone basis to warrant treatment as an operating segment, and that do not fit into one of our fourother five operating segmentssegments..

We evaluate segment performance based primarily onThe chief operating decision maker of the non-GAAPcompany is the Chairman, President and Chief Executive Officer who utilizes EBIT as the primary measure of EBIT, which includesprofit and loss in assessing the effectsresults of corporate expense allocationsour 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 level. We believe EBIT is a useful measurement of our performance because it provides information that can be used to evaluate the effectiveness of our businesses from an operational perspective, exclusive of the costs to finance those activities and exclusive of income taxes, neither of which is directly relevant to the efficiency of those operations.basis.

You should not consider EBIT an alternative to, or a more meaningful indicator of, our operating performance than operating income or net income as determined in accordance with GAAP. In addition, our EBIT may not be comparable to a similarly titled measure of another company. The reconciliations of EBIT to operating income, earnings before income taxes and net income for 2010, 2009 and 2008 are presented below.

In millions 2010  2009  2008 
Operating income $500  $476  $478 
Other (expense) income  (1)  9   6 
EBIT  499   485   484 
Interest expense  109   101   115 
Earnings before income taxes  390   384   369 
Income taxes  140   135   132 
Net income $250  $249  $237 
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Summarized StatementStatements of Income, Statements of Financial Position and capital expenditure information by segment as of and for the years ended December 31, 2010, 20092013, 2012 and 20082011 are shown in the following tables.
2010                  
In millions Distribution operations  Retail energy operations  Wholesale services  Energy investments  
Corporate and intercompany eliminations (3)
  Consolidated AGL Resources 
Operating revenues from external parties $1,352  $840  $121  $56  $4  $2,373 
Intercompany revenues (1)
  145   -   -   -   (145)  - 
Total operating revenues  1,497   840   121   56   (141)  2,373 
Operating expenses                        
Cost of gas  615   657   16   17   (141)  1,164 
Operation and maintenance  358   76   52   23   (6)  503 
Depreciation and amortization  138   2   2   7   11   160 
Taxes other than income taxes  35   2   3   2   4   46 
Total operating expenses  1,146   737   73   49   (132)  1,873 
Operating income (loss)  351   103   48   7   (9)  500 
Other income (expense)  4   -   1   (3)  (3)  (1)
EBIT $355  $103  $49  $4  $(12) $499 
Identifiable and total assets (2)
 $5,494  $259  $1,326  $479  $(40) $7,518 
Goodwill $404  $-  $-  $14  $-  $418 
Capital expenditures $357  $3  $2  $126  $22  $510 

2009                  
2013                     
In millions Distribution operations  Retail energy operations  Wholesale services  Energy investments  
Corporate and intercompany eliminations (3)
  Consolidated AGL Resources  Distribution operations  
Retail
operations
  
Wholesale
services
  
Midstream
operations
  
Cargo
shipping
  
Other and intercompany eliminations (4)
  Consolidated 
Operating revenues from external parties $1,344  $801  $121  $47  $4  $2,317  $3,275  $858  $45  $74  $365  $-  $4,617 
Intercompany revenues (1)
  138   -   -   -   (138)  -   182   -   13   -   -   (195)  - 
Total operating revenues  1,482   801   121   47   (134)  2,317   3,457   858   58   74   365   (195)  4,617 
Operating expenses                                                    
Cost of gas  646   620   10   1   (135)  1,142 
Cost of goods sold  1,687   564   21   33   222   (195)  2,332 
Operation and maintenance  351   71   59   25   (9)  497   690   132   48   24   115   (10)  999 
Depreciation and amortization  134   4   3   6   11   158   346   22   1   17   19   13   418 
Taxes other than income taxes  34   1   2   2   5   44   167   3   3   5   6   9   193 
Total operating expenses  1,165   696   74   34   (128)  1,841   2,890   721   73   79   362   (183)  3,942 
Gain on sale of Compass Energy  -   -   11   -   -   -   11 
Operating income (loss)  317   105   47   13   (6)  476   567   137   (4)  (5)  3   (12)  686 
Other income (expense)  9   -   -   (1)  1   9   15   -   -   (5)  9   (2)  17 
EBIT $326  $105  $47  $12  $(5) $485  $582  $137  $(4) $(10) $12  $(14) $703 
Identifiable and total assets (2)
 $5,230  $261  $1,168  $454  $(39) $7,074 
Goodwill $404  $-  $-  $14  $-  $418 
Identifiable and total assets (3)
 $11,727  $694  $1,166  $713  $445  $(89) $14,656 
Capital expenditures $354  $2  $1  $110  $9  $476  $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 


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2008                  
In millions Distribution operations  Retail energy operations  Wholesale services  Energy investments  
Corporate and intercompany eliminations (3)
  Consolidated AGL Resources 
Operating revenues from external parties $1,581  $987  $170  $55  $7  $2,800 
Intercompany revenues (1)
  187   -   -   -   (187)  - 
Total operating revenues  1,768   987   170   55   (180)  2,800 
Operating expenses                        
Cost of gas  950   838   48   5   (187)  1,654 
Operation and maintenance  330   67   55   24   (4)  472 
Depreciation and amortization  128   4   5   6   9   152 
Taxes other than income taxes  35   2   2   1   4   44 
Total operating expenses  1,443   911   110   36   (178)  2,322 
Operating income (loss)  325   76   60   19   (2)  478 
Other income  4   1   -   -   1   6 
EBIT $329  $77  $60  $19  $(1) $484 
Identifiable and total assets (2)
 $5,138  $315  $970  $353  $(66) $6,710 
Goodwill $404  $-  $-  $14  $-  $418 
Capital expenditures $278  $6  $1  $75  $12  $372 
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)  Intercompany revenues – wholesaleWholesale services records its energy marketing and risk management revenues on a net basis and its total operating revenues include intercompany revenues of $473$417 million in 2010, $4252013, $350 million in 20092012 and $982$449 million in 2008.2011.
(2)  Transaction expenses associated with the Nicor merger are shown separately to better compare year-over-year results.
(3)  Identifiable assets are those used indedicated to each segment’s operations.
(3)(4)  Our corporateother segment’s assets consist primarily of cash and cash equivalents, property, plant and equipmentPP&E and the effect of intercompany eliminations.


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Note 13 –14 - Selected Quarterly Financial Data (Unaudited)

Our quarterly financial data for 2010, 2009 and 2008 are summarized below. 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 primary business.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.

In millions, except per share amounts March 31  June 30  Sept. 30  Dec. 31 
2010            
Operating revenues $1,003  $359  $346  $665 
Operating income  253   48   62   137 
Net income attributable to AGL Resources Inc.  134   14   22   64 
Basic earnings per common share attributable to AGL Resources Inc. common shareholders  1.74   0.17   0.29   0.82 
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders  1.73   0.17   0.29   0.81 
2009                
Operating revenues $995  $377  $307  $638 
Operating income  230   55   43   148 
Net income attributable to AGL Resources Inc.  119   20   12   71 
Basic earnings per common share attributable to AGL Resources Inc. common shareholders  1.55   0.26   0.16   0.92 
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders  1.55   0.26   0.16   0.92 
2008                
Operating revenues $1,012  $444  $539  $805 
Operating income  188   6   126   158 
Net income (loss) attributable to AGL Resources Inc.  89   (11)  65   74 
Basic earnings (loss) per common share attributable to AGL Resources Inc. common shareholders  1.17   (0.15)  0.85   0.97 
Diluted earnings (loss) per share attributable to AGL Resources Inc. common shareholders  1.16   (0.15)  0.85   0.97 
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.
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Note 14 – Proposed Merger with Nicor

In December 2010, we entered into an Agreement and Plan of Merger (Merger Agreement) with Nicor, a copy of which was filed with the SEC. In accordance with the Merger Agreement, each share of Nicor stock, other than shares to be cancelled and Dissenting Shares (as defined in the Merger Agreement), outstanding at the Effective Time (as defined in the Merger Agreement) will be converted into the right to receive consideration consisting of (i) 0.8382 of a share of our common stock and (ii) $21.20 in cash, subject to adjustments in certain circumstances, resulting in Nicor stockholders owning approximately 33% of the combined company. We will also assume all outstanding Nicor debt. The Merger Agreement was unanimously approved by our Board of Directors and those directors present at the meeting of the Board of Directors of Nicor.

Completion of the proposed merger is conditioned upon, among other things, shareholder approval by both companies, the SEC’s clearance of a registration statement registering our common stock to be issued in connection with the proposed merger, expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvement Act and regulatory approval by the Illinois Commerce Commission.

The Merger Agreement provides certain termination rights for both Nicor and us, and provides for the payment of fees and expenses upon the termination of the Merger Agreement under certain circumstances. We currently anticipate completing the merger in the second half of 2011. Although we and Nicor believe that we will receive the required authorizations, approvals and consents to complete the proposed merger, there can be no assurance as to the timing of these authorizations, approvals and consents or as to our ultimate ability to obtain such authorizations, consents or approvals (or any additional authorizations, approvals or consents which may otherwise become necessary) or that such authorizations, approvals or consents will be obtained on terms and subject to conditions satisfactory to us and Nicor.

During the fourth quarter of 2010, we recorded approximately $6 million ($4 million net of tax) of expenses associated with non-recurring transaction costs associated with the proposed merger. For additional information concerning the proposed merger please see our Form 8-K filed with the SEC on December 7, 2010 and our Form S-4 registration statement filed with the SEC on February 4, 2011.

Note 15 – Subsequent Events

We have evaluated subsequent events through the time that our financial statements were issued and determined that the following significant events have occurred subsequent to period end.

In January 2011, we paid the $300 million current portion of our senior notes with $150 million of commercial paper borrowings and $150 million borrowed under our Term Loan Facility.

On February 4, 2011, we filed with the SEC a registration statement on Form S-4 containing a preliminary joint proxy statement/prospectus relating to the proposed merger with Nicor. After the registration statement has been declared effective by the SEC, we and Nicor expect to send the joint proxy statement/prospectus contained in the registration statement to our respective shareholders and each hold a special shareholder meeting to approve proposals related to the merger.

ITEM 9.9. 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.

99

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, 2010,2013, 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.
93


Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting identified in connection with the above-referenced evaluation by management of the effectiveness of our internal control over financial reporting that occurred during the fourth quarter ended December 31, 2010,2013, 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, 2010.2013. 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.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 companyPeriods served
  
John W. Somerhalder II, Age 55 (1)58
 
Chairman, President and Chief Executive OfficerOctober 2007 - Present
President and Chief Executive OfficerMarch 2006 – October 2007
Ralph Cleveland, Age 48
Executive Vice President, Engineering and OperationsDecember 2008 – Present
Senior Vice President, Engineering and OperationsFebruary 2005 – December 2008
  
Andrew W. Evans, Age 4447
 
Executive Vice President and Chief Financial OfficerNovember 2010 - Present
Executive Vice President, Chief Financial Officer and TreasurerJune 2009 - November 2010
Executive Vice President and Chief Financial OfficerMay 2006 - June 2009
Senior Vice President and Chief Financial OfficerSeptember 2005 – May 2006
  
Henry P. Linginfelter, Age 5053
 
Executive Vice President, Distribution OperationsDecember 2011 - Present
Executive Vice President, Utility OperationsJune 2007 – Present
Senior Vice President, Mid-Atlantic OperationsNovember 2004– June 2007- December 2011
  
Melanie M. Platt, Age 5659
 
Executive Vice President, Chief People OfficerDecember 2011 - Present
Senior Vice President, Human Resources and Marketing CommunicationsNovember 2008 – Present
Senior Vice President, Human ResourcesSeptember 2004 – November 2008- December 2011
  
Paul R. Shlanta, Age 5356
 
Executive Vice President, General Counsel and Chief Ethics and Compliance OfficerSeptember 2005 - Present
  
Peter I. Tumminello, Age 4851
 
Executive Vice President, Wholesale Services, and President SequentDecember 2011 - Present
President, SequentApril 2010 – Present- December 2011
Executive Vice President, Business Development and Support, SequentFebruary 2007 - April 2010
Vice President, Corporate Business DevelopmentNovember 2005 – February 2007
(1)  Mr. Somerhalder was executive vice president of El Paso Corporation (NYSE: EP) from 2000 until May 2005, and he continued service under a professional services agreement from May 2005 until March 2006.


The other information required by this item with respect to directors will be set forth under the captions “Proposal I1 -Election of Directors”Directors, - “Corporate Governance - Ethics and Compliance Program,” “Committees of the Board” and “- Audit“Audit Committee” in the Proxy Statement for our 20112014 Annual Meeting of Shareholders or in a subsequent amendment to this report. The information required by this item with respect to the executive officers is set forth at Part I, Item 4 of this report under the caption “Executive Officers of the Registrant.” 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 Statemen tStatement or subsequent amendment referred to above. All such information that is provided in the Proxy Statement is incorporated herein by reference.


94100

ITEM 11.11. 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 12.12. 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 “Share Ownership”“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 13.13. 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 ACCOUNTANTACCOUNTING 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 2011”2014” in the Proxy Statement or subsequent amendment to referred to in Item 10 above. All such information that is provided in the Proxy Statement is incorporated herein by reference.

PART IVIV

ITEM 15.15. EXHIBITS AND, FINANCIAL STATEMENT SCHEDULES

(a)  Documents Filed as Part of This Report.

(1)
(1) Financial Statements IncludedIncluded 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, 20102013 and 20092012
·  Consolidated Statements of Income for the years ended December 31, 2010, 20092013, 2012 and 2008
·  Consolidated Statements of Equity for the years ended December 31, 2010, 2009 and 20082011
·  Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2010, 20092013, 2012 and 20082011
·  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, 2010, 20092013, 2012 and 20082011
·  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, 2010.

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

Where an exhibit is filed by incorporation by reference to a previously filed registration statement or report, such registration statement or report is identified in parentheses.
Exhibit NumberDescription of ExhibitFilerThe Filings Referenced for Incorporation by Reference
2.1Agreement and Plan of Merger, by and between AGL Resources Inc., Apollo Acquisition Corp, Ottawa Acquisition LLC and Nicor,as amended, dated December 6, 2010 (Exhibit 2.1, AGL Resources Inc.December 7, 2010, Form 8-K, dated December 7, 2010).Exhibit 2.1
 2.2
3.1.aWaiver entered into as of February 4, 2011Amended and Restated Articles of Incorporation filed November 2, 2005, with the Secretary of State of the state of Georgia (Exhibit 3.1, AGL Resources Inc.February 9, 2011, Form 8-K, dated November 2, 2005).
3.1.bArticles of Amendment to the Amended and Restated Articles of Incorporation filed May 4, 2009, with the Secretary of State of the state of Georgia. (Exhibit 3.1.b, AGL Resources Inc. Form 10-Q for the quarter ended June 30, 2009).
3.2Bylaws, as amended on April 27, 2010 (Exhibit 3.2, AGL Resources Inc. Form 10-Q for the quarter ended June 30, 2010).Exhibit 2.1


3.1Amended and Restated Articles of Incorporation filed December 9, 2011AGL ResourcesDecember 13, 2011, Form 8-K, Exhibit 3.1
4.1.a3.2Bylaws, as amended on July 31, 2012AGL ResourcesAugust 6, 2012, Form 8-K, Exhibit 3.1
4.1Specimen form of Common Stock certificate (Exhibit 4.1, AGL Resources Inc.September 30, 2007, Form 10-Q, for the fiscal quarter ended September 30, 2007).Exhibit 4.1

4.1.b4.2.aSpecimenForm of AGL Capital Corporation 6.00% Senior Notes due 2034 (Exhibit 4.1, AGL Resources Inc.September 27, 2004, Form 8-K, dated September 27, 2004).
4.1.cSpecimen AGL Capital Corporation 4.95% Senior Notes due 2015 (ExhibitExhibit 4.1 AGL Resources Inc. Form 8-K dated December 21, 2004).
4.1.dSpecimen AGL Capital Corporation 6.375% Senior Secured Notes due 2016 (Exhibit 4.1, AGL Resources Inc. Form 8-K dated December 11, 2007).
4.1.eSpecimen AGL Capital Corporation 4.45% Senior Secured Notes due 2013 (Exhibit 4.1.g, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2007).
4.1.fSpecimen AGL Capital Corporation, 5.25% Senior Notes due 2019 (Exhibit 4.1, AGL Resources Inc. Form 8-K dated August 5, 2009).
4.2.aIndenture, dated as of December 1, 1989, between Atlanta Gas Light Company and Bankers Trust Company, as Trustee (Exhibit 4(a), Atlanta Gas Light Company registration statement on Form S-3, No. 33-32274).
4.2.bFirst Supplemental Indenture dated as of March 16, 1992, between Atlanta Gas Light Company and NationsBank of Georgia, National Association, as Successor Trustee (Exhibit 4(a), Atlanta Gas Light Company registration statement on Form S-3, No. 33-46419).
4.2.cIndenture, dated February 20, 2001 among AGL Capital Corporation, AGL Resources Inc. and The Bank of New York, as Trustee (Exhibit 4.2, AGL Resources Inc. registration statement on Form S-3, filed on September 17, 2001, No. 333-69500).
4.2.dForm of Guarantee of AGL Resources Inc. dated asSeptember 27, 2004AGL ResourcesSeptember 27, 2004, Form 8-K, Exhibit 4.3
4.3.aAGL Capital Corporation 4.95% Senior Notes due 2015AGL ResourcesDecember 21, 2004, Form 8-K, Exhibit 4.1
4.3.bGuarantee of August 10, 2009 regarding the AGL Resources Inc. dated December 20, 2004AGL ResourcesDecember 21, 2004, Form 8-K, Exhibit 4.3
4.4.aAGL Capital Corporation 6.375% Senior Notes due 2016AGL ResourcesDecember 14, 2007, Form 8-K, Exhibit 4.1
4.4.bGuarantee of AGL Resources Inc. dated December 14, 2007AGL ResourcesDecember 14, 2007, Form 8-K, Exhibit 4.2
4.5.aAGL Capital Corporation 5.25% Senior Notes due 2019 (Exhibit 4.2,AGL ResourcesAugust 10, 2009, Form 8-K, Exhibit 4.1
4.5.bGuarantee of AGL Resources Inc. dated August 10, 2009AGL ResourcesAugust 10, 2009, Form 8-K, dated August 5, 2009).

Exhibit 4.2
4.3.a4.6.aAGL Capital Corporation 5.875% Senior Notes due 2041AGL ResourcesMarch 21, 2011, Form 8-K, Exhibit 4.1
4.6.bGuarantee of AGL Resources Inc. dated March 21, 2011AGL ResourcesMarch 21, 2011, Form 8-K, Exhibit 4.2
4.7.aForm of AGL Capital Corporation 3.50% Senior Notes due 2021AGL ResourcesSeptember 20, 2011, Form 8-K, Exhibit 4.1
4.7.bForm of Guarantee of AGL Resources Inc. dated asSeptember 2011AGL ResourcesSeptember 20, 2011, Form 8-K, Exhibit 4.2
4.8.aForm of December 14, 2007 regarding the AGL Capital Corporation 6.375%Series A Senior NoteNotes due 2016 (Exhibit 4.2, AGL Resources Inc.September 7, 2011, Form 8-K, dated December 14, 2007).Exhibit 4.1
4.3.b4.8.bForm of Guarantee of AGL Resources Inc. dated as of September 27, 2004 regarding the AGL Capital Corporation 6.00%Series B Senior NoteNotes due 2034 (Exhibit 4.1, 2018AGL Resources Inc.September 7, 2011, Form 8-K, dated September 27, 2004).Exhibit 4.2
4.9.a
4.3.cForm of Guarantee of AGL Resources Inc. dated as of December 20, 2004 regarding the AGL Capital Corporation 4.95%4.40% Senior NoteNotes due 2015 (Exhibit 4.1, 2043AGL Resources Inc.May 16, 2013, Form 8-K, dated December 21, 2004).Exhibit 4.2
4.3.dForm of Guarantee of AGL Resources Inc. dated as of July 2, 2003 regarding the AGL Capital Corporation 4.45% Senior Note due 2013 (Exhibit 4.3.e, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2007).
10.1Director and Executive Compensation Contracts, Plans and Arrangements.
Director Compensation Contracts, Plans and Arrangements
10.1.a4.9.bAGL Resources Inc. Amended and Restated 1996 Non-Employee Directors Equity Compensation Plan (Exhibit 10.1, Guarantee related to the 4.40% Senior Notes due 2043AGL Resources Inc.May 16, 2013, Form 8-K, Exhibit 4.2
4.10.aIndenture dated December 1, 1989Atlanta Gas LightFile No. 33-32274, Form S-3, Exhibit 4(a)
4.10.bFirst Supplemental Indenture dated March 16, 1992Atlanta Gas LightFile No. 33-46419, Form S-3, Exhibit 4(a)
4.11Indenture dated February 20, 2001AGL ResourcesSeptember 17, 2001, File No. 333-69500, Form S-3, Exhibit 4.2
4.12.aIndenture dated January 1, 1954Nicor GasDecember 31, 1995, Form 10-K, Exhibit 4.01
4.12.bIndenture dated February 9, 1954Nicor GasDecember 31, 1995, Form 10-K, Exhibit 4.02
4.12.cSupplemental Indenture dated February 15, 1998Nicor GasDecember 31, 1997, Form 10-K, Exhibit 4.19
4.12.dSupplemental Indenture dated May 15, 2001Nicor GasJuly 20, 2001, File No. 333-65486, Form S-3, Exhibit 4.18
4.12.eSupplemental Indenture dated December 1, 2003Nicor GasDecember 31, 2003, Form 10-K, Exhibit 4.09
4.12.fSupplemental Indenture dated December 1, 2003Nicor GasDecember 31, 2003, Form 10-K, Exhibit 4.10
4.12.gSupplemental Indenture dated December 1, 2003Nicor GasDecember 31, 2003, Form 10-K, Exhibit 4.11
4.12.hSupplemental Indenture dated December 1, 2006Nicor GasDecember 31, 2006, Form 10-K, Exhibit 4.11
4.12.iSupplemental Indenture dated August 1, 2008Nicor GasSeptember 30, 2008, Form 10-Q, for the quarter ended Exhibit 4.01
4.12.jSupplemental Indenture dated July 23, 2009Nicor GasJune 30, 2009, Form 10-Q, Exhibit 4.01
4.12.kSupplemental Indenture dated February 1, 2011Nicor GasDecember 31, 2010, Form 10-K, Exhibit 4.12
4.12.lSupplemental Indenture dated October 26, 2012Nicor GasSeptember 30, 2002).2012, Form 10-Q, Exhibit 4
10.1.a +
10.1.bFirst Amendment to the AGL Resources Inc. Amended and Restated 1996 Non-Employee Directors Equity Compensation Plan (Exhibit 10.1.o, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2002).
10.1.cSecond Amendment to the AGL Resources Inc. Amended and Restated 1996 Non-Employee Directors Equity Compensation Plan (Exhibit 10.1.k, AGL Resources Inc. Form 10-Q for the quarter ended June 30, 2007).
10.1.dAGL Resources Inc. 2006 Non-Employee Directors Equity Compensation Plan, (incorporated herein by reference to Annex Camended and restated as of the December 9, 2011AGL Resources Inc. Proxy Statement for the Annual Meeting of Shareholders held May 3, 2006 filed on March 20, 2006).December 15, 2011, Form 8-K, Exhibit 10.2
10.1.b +1998 Common Stock Equivalent Plan for Non-Employee DirectorsAGL ResourcesDecember 31, 1997, Form 10-Q, Exhibit 10.1.b
10.1.e10.1.c +First Amendment to the 1998 Common Stock Equivalent Plan for Non-Employee DirectorsAGL Resources Inc. 2006 Non-Employee Directors Equity Compensation Plan (Exhibit 10.1.i, AGL Resources Inc.March 31, 2000, Form 10-Q, Exhibit 10.5
10.1.d +Second Amendment to the 1998 Common Stock Equivalent Plan for the quarter ended JuneNon-Employee DirectorsAGL ResourcesSeptember 30, 2007).2002, Form 10-Q, Exhibit 10.4
 
96102

10.1.e +
10.1.fSecondThird Amendment to the AGL Resources Inc. 2006 Non-Employee Directors Equity Compensation Plan. (Exhibit 10.1.f, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2008).
10.1.gAGL Resources Inc. 1998 Common Stock Equivalent Plan for Non-Employee Directors (Exhibit 10.1.b, AGL Resources Inc.September 30, 2002, Form 10-Q, for the quarter ended December 31, 1997).Exhibit 10.5
10.1.f +
10.1.hFirstFourth Amendment to the AGL Resources Inc. 1998 Common Stock Equivalent Plan for Non-Employee Directors (Exhibit 10.5, AGL Resources Inc.June 30, 2007, Form 10-Q, for the quarter ended March 31, 2000).Exhibit 10.1.m
10.1.g +
10.1.iSecondFifth Amendment to the AGL Resources Inc. 1998 Common Stock Equivalent Plan for Non-Employee Directors (Exhibit 10.4, AGL Resources Inc.December 31, 2008, Form 10-Q for the quarter ended September 30, 2002).10-K, Exhibit 10.1.l
10.1.jThird Amendment to the AGL Resources Inc. 1998 Common Stock Equivalent Plan for Non-Employee Directors (Exhibit 10.5, AGL Resources Inc. Form 10-Q for the quarter ended September 30, 2002).
10.1.kFourth Amendment to the AGL Resources Inc. 1998 Common Stock Equivalent Plan for Non-Employee Directors (Exhibit 10.1.m, AGL Resources Inc. Form 10-Q for the quarter ended June 30, 2007).
10.1.lFifth Amendment to the AGL Resources Inc. 1998 Common Stock Equivalent Plan for Non-Employee Directors. (Exhibit 10.1.l, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2008).
10.1.mDescription of Non-Employee Directors’ Compensation (incorprated herein by reference to the Director Compensation section of the AGL Resources Inc. Proxy Statement for the Annual Meeting of Shareholders held April 27, 2010 and filed March 15, 2010).
10.1.n10.1.h +Form of Stock Award Agreement for Non-Employee Directors (Exhibit 10.1.aj, AGL Resources Inc.December 31, 2004, Form 10-K, for the fiscal year ended December 31, 2004).Exhibit 10.1.aj
10.1.o10.1.i +Form of Nonqualified Stock Option Agreement for Non-Employee Directors (Exhibit 10.1.ak, AGL Resources Inc.December 31, 2004, Form 10-K, for the fiscal year ended December 31, 2004).Exhibit 10.1.ak
10.1.p10.1.j +Form of Director Indemnification Agreement dated April 28, 2004 between AGL Resources Inc., on behalf of itself and the Indemnities named therein (Exhibit 10.3, AGL Resources Inc.June 30, 2004, Form 10-Q, for the quarter ended June 30, 2004).Exhibit 10.3
10.1.k +
Executive Compensation Contracts, Plans and Arrangements
10.1.aaAGL Resources Inc. Long-Term Incentive Plan, (1999), as amended and restated as of January 1, 2002 (Exhibit 99.2, AGL Resources Inc.March 31, 2002, Form 10-Q, for the quarter ended March 31, 2002).Exhibit 99.2
10.1.ab10.1.l +First amendment to the AGL Resources Inc. Long-Term Incentive Plan, (1999), as amended and restated (Exhibit 10.1.b, AGL Resources Inc.December 31, 2004, Form 10-K, for the fiscal year ended December 31, 2004).Exhibit 10.1.b
10.1.ac10.1.m +Second amendment to the AGL Resources Inc. Long-Term Incentive Plan, (1999), as amended and restated (Exhibit 10.1.l, AGL Resources Inc.June 30, 2007, Form 10-Q, for the quarter ended June 30, 2007).Exhibit 10.1.l
10.1.ad10.1.n +Third amendment to the AGL Resources Inc. Long-Term Incentive Plan, (1999), as amended and restated. (Exhibit 10.1.ad, restatedAGL Resources Inc.December 31, 2008, Form 10-K, for the fiscal year ended December 31, 2008).Exhibit 10.1.ad
10.1.o +
10.1.aeOmnibus Performance Incentive Plan, as amended and restatedAGL Resources Inc. OfficerMarch 14, 2011, Schedule 14A, Annex A
10.1.p +Form of Restricted Stock Unit Agreement under Omnibus Performance Incentive Plan, (Exhibit 10.2, AGL Resources Inc. Form 10-Q for the quarter ended June 30, 2001).
10.1.afFirst amendment to the AGL Resources Inc. Officer Incentive Plan (Exhibit 10.1.j, AGL Resources Inc. Form 10-Q for the quarter ended June 30, 2007).
10.1.agSecond amendment to the AGL Resources Inc. Officer Incentive Plan. (Exhibit 10.1.ag, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2008).
10.1.ahas amended and RestatedAGL Resources Inc.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 restatedAGL ResourcesDecember 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 restatedAGL ResourcesFiled herewith
10.1.s +2007 Omnibus Performance Incentive PlanAGL ResourcesMarch 19, 2007, Schedule 14A, Annex A
10.1.t +First Amendment to the 2007 Omnibus Performance Incentive Plan, (Annex A of as amended and restatedAGL Resources Inc.’s Schedule 14A, File No. 001-14174, filed with the Securities and Exchange Commission on March 19, 2007).December 31, 2008, Form 10-K, Exhibit 10.1.ai
10.1.aiFirst Amendment to the AGL Resources Inc. 2007 Omnibus Performance Incentive Plan (Exhibit 10.1.ai, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2008).
10.1.aj10.1.u +Form of Incentive Stock Option Agreement - AGL Resources Inc. 2007 Omnibus Performance Incentive Plan (Exhibit 10.1.b, AGL Resources Inc.June 30, 2007, Form 10-Q, for the quarter ended June 30, 2007).
Exhibit 10.1.b
10.1.ak10.1.v +Form of Nonqualified Stock Option Agreement - AGL Resources Inc. 2007 Omnibus Performance Incentive Plan (Exhibit 10.1.c, AGL Resources Inc.June 30, 2007, Form 10-Q, for the quarter ended June 30, 2007).Exhibit 10.1.c
10.1.alForm of Performance Cash Award Agreement - AGL Resources Inc. 2007 Omnibus Performance Incentive Plan (Exhibit 10.1.al, AGL Resources Inc. Form 10-K for the year ended December 31, 2009).
10.1.amForm of Restricted Stock Agreement (performance based) - AGL Resources Inc. 2007 Omnibus Performance Incentive Plan (Exhibit 10.1.e, AGL Resources Inc. Form 10-Q for the quarter ended June 30, 2007).
10.1.anForm of Restricted Stock Agreement (time based) - AGL Resources Inc. 2007 Omnibus Performance Incentive Plan (Exhibit 10.1.f, AGL Resources Inc. Form 10-Q for the quarter ended June 30, 2007).
10.1.aoForm of Restricted Stock Unit Agreement - AGL Resources Inc. 2007 Omnibus Performance Incentive Plan (Exhibit 10.1.ao, AGL Resources Form 10-K for the fiscal year ended December 31, 2009).
10.1.apForm of Stock Appreciation Rights Agreement - AGL Resources Inc. 2007 Omnibus Performance Incentive Plan (Exhibit 10.1.h, AGL Resources Inc. Form 10-Q for the quarter ended June 30, 2007).
10.1.aq10.1.w +Form of Incentive Stock Option Agreement and Nonqualified Stock Option Agreement and Restricted Stock Agreement for key employees (Exhibit 10.1, (LTIP)AGL Resources Inc.September 30, 2004, Form 10-Q, for the quarter ended September 30, 2004).Exhibit 10.1
10.1.arForm of Performance Unit Agreement for key employees (Exhibit 10.1.e, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2004).
10.1.as10.1.x +Forms of Nonqualified Stock Option Agreement without the reload provision (LTIP and Officer Plan) (Exhibit 10.1, (LTIP)AGL Resources Inc.March 18, 2005, Form 8-K, dated March 15, 2005).Exhibit 10.1
10.1.at10.1.y +Form of Nonqualified Stock Option Agreement with the reload provision (Officer Incentive Plan) (Exhibit 10.2, AGL Resources Inc.March 18, 2005, Form 8-K, dated March 15, 2005).Exhibit 10.2
10.1.z +
10.1.auForm of Restricted Stock Unit Agreement and Performance Cash Unit Agreement for key employees (Exhibit 10.1 and 10.2, respectively, AGL Resources Inc. Form 8-K dated February 24, 2006).
10.1.avAGL Resources Inc. Nonqualified Savings Plan as amended and restated as of January 1, 2009. (Exhibit 10.1.av, 2009AGL Resources Inc.December 31, 2008, Form 10-K, for the fiscal year ended December 31, 2008).Exhibit 10.1.av
10.1.aa +
10.1.awFirst Amendment to the Nonqualified Savings PlanAGL Resources Inc. Annual Incentive Plan - 2007 (Exhibit 10.1, AGL Resources Inc. Form 8-K dated August 6, 2007).Filed herewith
10.1.ab +Second Amendment to the Nonqualified Savings PlanAGL ResourcesFiled herewith
10.1.ax10.1.ac +Third Amendment to the Nonqualified Savings PlanAGL ResourcesFiled herewith
10.1.ad +Description of Supplemental Executive Retirement Plan for John W. Somerhalder II. (Exhibit 10.1.ay, IIAGL Resources Inc.December 31, 2008, Form 10-K, for the fiscal year ended December 31, 2008).Exhibit 10.1.ay
10.1.ae +
10.1.ayAGL Resources Inc. Excess Benefit Plan as amended and restated as of January 1, 2009. (Exhibit 10.1.az, 2009AGL Resources Inc.December 31, 2008, Form 10-K, for the fiscal year ended December 31, 2008).Exhibit 10.1.az
10.1.af +
10.1.azForm of Continuity Agreement dated December 1, 2007, by and between 19, 2013AGL Resources Inc., on behalf of itself and AGL Services Company (its wholly-owned subsidiary) and Kevin P. Madden (Exhibit 10.1.c, AGL Resources Inc.December 19, 2013, Form 10-K for the fiscal year ended December 31, 2007).8-K, Exhibit 10.1
10.1.baContinuity Agreement, entered into as of December 1, 2009, by and between AGL Resources Inc., on behalf of itself and AGL Services Company (its wholly-owned subsidiary) and John W. Somerhalder (Exhibit 10.1.a AGL Resources Inc. Form 8-K dated January 21, 2010).
10.1.bbContinuity Agreement, entered into as of December 1, 2009, by and between AGL Resources Inc., on behalf of itself and AGL Services Company (its wholly-owned subsidiary) and Andrew W. Evans (Exhibit 10.1.b AGL Resources Inc. Form 8-K dated January 21, 2010).
10.1.bcContinuity Agreement, entered into as of December 1, 2009, by and between AGL Resources Inc., on behalf of itself and AGL Services Company (its wholly-owned subsidiary) and Henry P. Linginfelter (Exhibit 10.1.c AGL Resources Inc. Form 8-K dated January 21, 2010).
10.1.bdContinuity Agreement, entered into as of December 1, 2009, by and between AGL Resources Inc., on behalf of itself and AGL Services Company (its wholly-owned subsidiary) and Douglas N. Schantz (Exhibit 10.1.d AGL Resources Inc. Form 8-K dated January 21, 2010).
10.1.beContinuity Agreement, entered into as of December 1, 2009, by and between AGL Resources Inc., on behalf of itself and AGL Services Company (its wholly owned subsidiary) and Paul R. Shlanta (Exhibit 10, AGL Resources Inc. Form 10-Q for the quarter ended March 31, 2010).
10.1.bfForm of AGL Resources Inc. Executive Post Employment Medical Benefit Plan (Exhibit 10.1.d, AGL Resources Inc. Form 10-Q for the quarter ended June 30, 2003).

10.1.bg10.1.ag +Description of compensation for each of John W. Somerhalder II, Andrew W. Evans, Henry P. Linginfelter, Douglas N. Schantz and Paul R. Shlanta and Peter I. Tumminello (our Named Executive Officers for the year ended December 31, 2009) (incorporated herein by reference to the 2013)AGL ResourcesCompensation Discussion and Analysis section of the AGL Resources Inc. Proxy Statement for the Annual Meeting of Shareholders held April 27, 201030, 2013 filed on March 15, 2010).2013.
10.1.bhRetirement Enhancement Agreement, dated March 4, 2009, between Kevin P. Madden and AGL Resources Inc. (Exhibit 10.1, AGL Resources Inc. Form 8-K dated October 31, 2008).
10.2Guaranty Agreement, effective December 13, 2005, by and between Atlanta Gas Light Company and AGL Resources Inc. (Exhibit 10.2, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2007).
10.310.2.aForm of Commercial Paper Dealer Agreement between AGL Capital Corporation, as Issuer, AGL Resources Inc., as Guarantor, and the Dealers named therein, dated September 25,30, 2000, (Exhibit 10.79, AGL Resources Inc. Form 10-K, for the fiscal year ended September 30, 2000).
10.4Guarantee of AGL Resources Inc., dated October 5, 2000, of payments on promissory notes issued by AGL Capital Corporation (AGLCC) pursuant to the Issuing and Paying Agency Agreement dated September 25, 2000, between AGLCC and The Bank of New York (Exhibit 10.80, AGL Resources Inc. Form 10-K for the fiscal year ended September 30, 2000).
10.5Issuing and Paying Agency Agreement, dated September 25, 2000, between AGL Capital Corporation and The Bank of New York (Exhibit 10.81, AGL Resources Inc. Form 10-K for the fiscal year ended September 30, 2000).
10.6.aAmended and Restated Master Environmental Management Services Agreement, dated July 25, 2002 by and between Atlanta Gas Light Company and The RETEC Group, Inc. (Exhibit 10.2, AGL Resources Inc. Form 10-Q for the quarter ended June 30, 2003). (Confidential treatment pursuant to 17 CFR Sections 200.80 (b) and 240.24-b has been granted regarding certain portions of this exhibit, which portions have been filed separately with the Commission).
10.6.bModification to the Amended and Restated Master Environmental Management Services Agreement, dated February 1, 2005 by and between Atlanta Gas Light Company and The RETEC Group, Inc. (Exhibit 10.6.b, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2008).
10.6.cTerm Extension to the Amended and Restated Master Environmental Management Services Agreement, dated August 1, 2005 by and between Atlanta Gas Light Company and The RETEC Group, Inc. (Exhibit 10.6.c, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2008).
10.6.dModification to the Amended and Restated Master Environmental Management Services Agreement, dated June 30, 2005 by and between Atlanta Gas Light Company and The RETEC Group, Inc. (Exhibit 10.6.d, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2008).
10.6.eSecond Modification to the Amended and Restated Master Environmental Management Services Agreement, dated February 1, 2006 by and between Atlanta Gas Light Company and The RETEC Group, Inc. (Exhibit 10.6.e, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2008).Exhibit 10.79

10.2.bGuarantee dated October 5, 2000 of payments on promissory notesAGL ResourcesSeptember 30, 2000, Form 10-K, Exhibit 10.80
10.6.f10.4Third Modification to theNote Purchase Agreement dated August 31, 2011AGL ResourcesSeptember 7, 2011, Form 8-K, Exhibit 10.1
10.5Final Allocation Agreement dated January 3, 2008NicorDecember 31, 2007, Form 10-K, Exhibit 10.64
10.6Second Amended and Restated Master Environmental Management ServicesLimited Liability Company Agreement dated February 1, 2008 by and between Atlanta Gas Light Company and The RETEC Group, Inc. (Exhibit 10.6.f, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2008).
10.6.gFourth Modification to the amended and Restated Master Environmental Management Services Agreement dated as of February 1, 2009 by and between Atlanta Gas Light Company and the RETEC Group, Inc. (Exhibit 10.6, AGL Resources Inc. Form 10-Q for the quarter ended March 31, 2009).
10.6.hEnvironmental Services Agreement, dated July 16, 2009, by and between Atlanta Gas Light Company and MACTEC Engineering and Consulting, Inc. (Exhibit 10.2, AGL Resources Inc. Form 10-Q for the quarter ended September 30, 2009).
10.7.aSouthStar Energy Services LLC Amended and Restated Agreement, dated April 1, 2004September 6, 2013 by and between Georgia Natural Gas Company and Piedmont Energy Company (Exhibit 10, AGL Resources Inc.September 30, 2013, Form 10-Q, for the quarter ended March 31, 2004).Exhibit 10
10.7
10.7.bThird Amendment to Amended and Restated Limited Liability Company Agreement, dated July 29, 2009, by and between Georgia Natural Gas Company and Piedmont Energy Company (Exhibit 10, AGL Resources Inc. Form 10-Q for the quarter ended June 30, 2009).
10.8Credit Agreement as of September 30, 2008 by and among AGL Resources Inc., AGL Capital Corporation, Wachovia Bank, N.A. as Administrative Agent, Wachovia Capital Markets, LLC as sole lead arranger and sole lead bookrunner. SunTrust Bank, NA, The Bank of Tokyo-Mitsubishi UFJ, LTD., Calyon New York Brand and The Royal Bank of Scotland PLC as Co-Documentation Agents (Exhibit 10.1, AGL Resources Inc. Form 8-K/A dated May 26, 2010).
10.9.aCredit Agreement as of September 15, 2010 by and among AGL Resources Inc., AGL Capital Corporation, Wells Fargo Bank, National Association, as administrative agent, Wells Fargo Securities, LLC, Banc of America Securities LLC and SunTrust Robinson Humphrey, Inc., as joint arrangers and joint bookrunners, and the several other banks and other financial institutions named therein, Bank of America, N.A. and SunTrust Bank, as Co-Syndication Agents, and The Bank of Tokyo-Mitsubishi, UFJ, Ltd., and JPMorgan Chase Bank, N.A., as Co-Documentation Agents. (Exhibit 10.1, AGL Resources Inc. Form 8-K dated September 20, 2010).
10.9.bFirst Amendment as of December 21, 2010 to Credit Agreement as of September 15, 2010 by and among AGL Resources Inc., AGL Capital Corporation, Wells Fargo Bank, National Association, as administrative agent, Wells Fargo Securities, LLC, Banc of America Securities LLC and SunTrust Robinson Humphrey, Inc., as joint arrangers and bookrunners, and the several other banks and other financial institutions named therein, Bank of America, N.A. and SunTrust Bank, as co-syndication agents, and The Bank of Tokyo-Mitsubishi, UFJ, Ltd., and JPMorgan Chase Bank, N.A., as co-documentation agents (Exhibit 10.5, AGL Resources Inc. Form 8-K, dated December 23, 2010).
10.10Guarantee, dated as of September 15, 2010 made by AGL Resources Inc., the guarantor, in favor of Wells Fargo Bank, National Association, as administrative agent for the lenders parties to the Credit Agreement, dated as of September 15, 2010, among Guarantor, AGL Capital Corporation, the borrower, the lenders named therein, and Wells Fargo Bank, National Association, as administrative agent (Exhibit 10.2, AGL Resources Inc. Form 8-K dated September 20, 2010).
10.11Bridge Term Loan
Credit Agreement dated as of December 21, 2010 among 15, 2011(1)
AGL Resources Inc., AGL Capital Corporation, Goldman Sachs Bank USA, as administrative agent, sole lead arranger and sole bookrunner, SunTrust Bank, N.A. and Wells Fargo Bank, National Association, as co-syndication agents, Bank of America, N.A. and Morgan Stanley Senior Funding, Inc., as co-documentation agents, and the several lenders named therein (Exhibit 10.1, AGL Resources Inc.December 15, 2011, Form 8-K, dated December 23, 2010).
Exhibit 10.1
10.1210.8.aGuarantee, dated as of December 21, 2010, made by AGL Resources Inc. in favor of Goldman Sachs Bank USA, as administrative agent for the several banks
Amended and other financial institutions or entities from time to time party to the Bridge Term LoanRestated Credit Agreement dated as of the date thereof, among November 10, 2011(2)
AGL Resources Inc., AGL Capital Corporation, the Lenders, and Goldman Sachs Bank USA, as Administrative Agent (Exhibit 10.2, AGL Resources Inc.November 17, 2011, Form 8-K, dated December 23, 2010).Exhibit 10.1
10.8.b
10.13
Term Loan CreditGuarantee Agreement dated as of December 21, 2010 among November 10, 2011
AGL Resources Inc., AGL Capital Corporation, Goldman Sachs Bank USA, as administrative agent, sole lead arranger and sole bookrunner, JPMorgan Chase Bank, N.A. and Bank of America, N.A., as co-syndication agents, The Royal Bank of Scotland PLC and Morgan Stanley Senior Funding, Inc., as co-documentation agents, and the several lenders named therein. (Exhibit 10.3, AGL Resources Inc.November 17, 2011, Form 8-K, dated December 23, 2010).Exhibit 10.2
10.9
10.14Guarantee, dated as of December 21, 2010, made by AGL Resources Inc. in favor of Goldman Sachs Bank USA, as administrative agent for the several banks and other financial institutions or entities from time to time party to the Term Loan CreditRate Mode Covenants Agreement, dated as of the date thereof, among February 26, 2013AGL Resources Inc., AGL Capital Corporation, the Lenders, and Goldman Sachs Bank USA, as Administrative Agent (Exhibit 10.4, AGL Resources Inc.March 1, 2013, Form 8-K, dated December 23, 2010).Exhibit 10.1
10.10
10.15.aReimbursementLoan Agreement dated as of October 14, 2010, by and among Pivotal Utility Holdings, Inc., February 1, 2013AGL Resources Inc., JPMorgan Chase Bank, N.A., as administrative agent and lead arranger, and the several other banks and other financial institutions named therein (Exhibit 10.1, AGL Resources Inc.March 1, 2013, Form 10-Q for the quarter ended September 30, 2010).8-K, Exhibit 10.2
10.11
10.15.bFirst Amendment dated as of December 17, 2010 to ReimbursementLoan Agreement dated as of October 14, 2010, by and among Pivotal Utility Holdings, Inc., March 1, 2013AGL Resources Inc., JPMorgan Chase Bank, N.A., as administrative agent and lead arranger, and the several other banks and other financial institutions named therein (Exhibit 10.9, AGL Resources Inc.March 27, 2013, Form 8-K, dated December 23, 2010).Exhibit 10.1
10.12
10.15.cReimbursementAmended and Restated Loan Agreement dated as of October 14, 2010, by and among Pivotal Utility Holdings, Inc., March 1, 2013AGL Resources Inc., The Bank of Tokyo-Mitsubishi UFJ, Ltd, New York Branch, as administrative agent and lead arranger, and the several other banks and other financial institutions named therein. (ExhibitMarch 27, 2013, Form 8-K, Exhibit 10.2 AGL Resources Inc. Form 10-Q for the quarter ended September 30, 2010).
10.13
10.15.dFirst Amendment, dated as of December 17, 2010 to ReimbursementAmended and Restated Loan Agreement dated as of October 14, 2010, by and among Pivotal Utility Holdings, Inc., March 1, 2013AGL Resources Inc., and The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, as administrative agent and lead arranger, and the several other banks and other financial institutions named therein (Exhibit 10.8, AGL Resources Inc.March 27, 2013, Form 8-K, dated December 23, 2010).Exhibit 10.3
10.14
10.15.eReimbursementAmended and Restated Loan Agreement dated as of October 14, 2010, by and among Pivotal Utility Holdings, Inc., March 1, 2013AGL Resources Inc., The Bank of Tokyo-Mitsubishi UFJ, Ltd, New York Branch, as administrative agent and lead arranger, and the several other banks and other financial institutions named therein. (Exhibit 10.3, AGL Resources Inc. Form 10-Q for the quarter ended September 30, 2010).
10.15.fFirst Amendment dated as of December 17, 2010 to Reimbursement Agreement dated as of October 14, 2010, by and among Pivotal Utility Holdings, Inc., AGL Resources Inc., and The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, as administrative agent and lead arranger, and the several other banks and other financial institutions named therein (Exhibit 10.7, AGL Resources Inc.March 27, 2013, Form 8-K, dated December 23, 2010).
10.15.gReimbursement Agreement dated as of October 14, 2010, by and among Pivotal Utility Holdings, Inc., AGL Resources Inc., JPMorgan Chase Bank, N.A., as administrative agent and lead arranger, and the several other banks and other financial institutions named therein. (ExhibitExhibit 10.4 AGL Resources Inc. Form 10-Q for the quarter ended September 30, 2010).
10.15.hFirst Amendment, dated as of December 17, 2010 to Reimbursement Agreement dated as of October 14, 2010, by and among Pivotal Utility Holdings, Inc., AGL Resources Inc. and JPMorgan Chase Bank, N.A., as administrative agent and the several other banks and other financial institutions named therein (Exhibit 10.6, AGL Resources Inc. Form 8-K, dated December 23, 2010).
12Statement of Computation of Ratio of Earnings to Fixed Charges.
ChargesAGL ResourcesFiled herewith
14AGL Resources Inc. Code of Ethics for itsthe Chief Executive Officer and its Senior Financial Officers (Exhibit 14, AGL Resources Inc.December 31, 2004, Form 10-K, for the year ended December 31, 2004).
Exhibit 14
21Subsidiaries of AGL Resources Inc.
AGL ResourcesFiled herewith
23Consent of PricewaterhouseCoopers LLP independent registered public accounting firm.
AGL ResourcesFiled herewith
24Powers of Attorney (includedAGL ResourcesIncluded on signature page hereto).
hereto
31.1Certification of John W. Somerhalder II pursuant to Rule 13a – 14(a).
AGL ResourcesFiled herewith
31.2Certification of Andrew W. Evans pursuant to Rule 13a – 14(a).
AGL ResourcesFiled herewith
32.1Certification of John W. Somerhalder II pursuant to 18 U.S.C. Section 1350.
AGL ResourcesFiled herewith
32.2Certification of Andrew W. Evans pursuant to 18 U.S.C. Section 1350.AGL ResourcesFiled herewith

101.INS
XBRL Instance Document. (1)
DocumentAGL ResourcesFiled herewith
101.SCH
XBRL Taxonomy Extension Schema. (1)
SchemaAGL ResourcesFiled herewith
101.CAL
XBRL Taxonomy Extension Calculation Linkbase. (1)
LinkbaseAGL ResourcesFiled herewith
101.DEF
XBRL Taxonomy Definition Linkbase. (1)
LinkbaseAGL ResourcesFiled herewith
101.LAB
XBRL Taxonomy Extension Labels Linkbase. (1)
LinkbaseAGL ResourcesFiled herewith
101.PRE
XBRL Taxonomy Extension Presentation Linkbase. (1)Linkbase
AGL ResourcesFiled herewith
 +      Management contract, compensatory plan or arrangement.
(1)  In November 2013, the Credit Agreement commitment terms were extended to a maturity date of December 15, 2017 via an approved extension request.
(2)  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.

(1)
Furnished, not filed
Attached as Exhibit 101 to this Annual Report are the following documents formatted in extensible business reporting language (XBRL): (i) Document and Entity Information; (ii) Consolidated Statements of Financial Position at December 31, 2010 and 2009; (iii) Consolidated Statements of Income for the years ended December 31, 2010, 2009 and 2008; (iv) Consolidated Statements of Equity for the years ended December 31, 2010, 2009 and 2008; (v) Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2010, 2009 and 2008; (vi) Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008; and (vii) Notes to Consolidated Financial Statements.
Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability. We also make available on our web site the Interactive Data Files submitted as Exhibit 101 to this Annual Report.
(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).



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;undersigned, thereunto duly authorized, on February 9, 2011.6, 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, 2010,2013, 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 o ror 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 9, 2011.
6, 2014.
SignaturesTitle
  
/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 Controller and Chief Accounting Officer
    (Principal Accounting Officer)
Bryan E. Seas
  
/s/ Sandra N. BaneDirector
Sandra N. Bane 
  
/s/ Thomas D. Bell, Jr.Jr.
Director
Thomas D. Bell, Jr.
/s/ Norman R. BobinsDirector
Norman R. Bobins
  
/s/ Charles R. CrispDirector
Charles R. Crisp
 
/s/ Brenda J. GainesDirector
Brenda J. Gaines
/s/ Arthur E. JohnsonDirector
Arthur E. Johnson
  
/s/ Wyck A. Knox, Jr.Director
Wyck A. Knox, Jr.
 
/s/ Dennis M. Love
Director
Dennis M. Love
Director
  
/s/ Charles H. McTierDirector
Charles H. McTier 
  
/s/ Dean R. O’HareDirector
Dean R. O’Hare
/s/ Armando J. OliveraDirector
Armando J. Olivera
/s/ John E. RauDirector
John E. Rau 
  
/s/ James A. RubrightDirector
James A. Rubright 
  
/s/ Bettina M. WhyteDirector
Bettina M. Whyte 
  
/s/ Henry C. WolfDirector
Henry C. Wolf 




AGL Resources Inc. and Subsidiaries

VALUATION AND QUALIFYING ACCOUNTS - ALLOWANCE FOR UNCOLLECTIBLE ACCOUNTS AND INCOME TAX VALUATION FOR EACH OF THE THREE YEARS IN THE PERIOD ENDED DECEMBER 31, 2010.
 
In millions
  Allowance for uncollectible accounts   Income tax valuation 
Balance at December 31, 2007 $14  $3 
Provisions charged to income in 2008  27   - 
Accounts written off as uncollectible, net in 2008  (25)  - 
Balance at December 31, 2008  16   3 
Provisions charged to income in 2009  25   - 
Accounts written off as uncollectible, net in 2009  (27)  - 
Balance at December 31, 2009  14   3 
Provisions charged to income in 2010  22   - 
Accounts written off as uncollectible, net in 2010  (20)  - 
Balance at December 31, 2010 $16  $3 
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 


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