We believe that we have a good working relationship with our ~~segments, see Item 7, “Management’s Discussion~~unionized employees and ~~Analysis~~there 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 Condition~~the 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 our~~Our 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 reports~~SEC 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 ~~2011~~2014 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.

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.

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 businesses~~We 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 ~~the~~regulatory authorities in Illinois, Georgia, ~~Tennessee,~~Virginia, New Jersey, Florida, ~~Virginia~~Tennessee 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 e~~able 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. Although~~liabilities, 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 ~~must~~are 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 is~~We 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 properties~~We are subject to extensive environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. Such environmental ~~legislation~~regulation imposes, among other things, restrictions, liabilities and obligations ~~in connection~~associated with storage, transportation, treatment and disposal of ~~hazardous substances~~MGP 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 are~~and 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 d~~could have a material adverse effect on our business, results of operations or financial condition.

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 ~~system~~systems 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 ~~this~~such 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, ~~and~~the projected construction schedule and the completion timeline of a project. Our cash flows may not be fully adequate to finance the cost of ~~this~~such 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.

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

Climate change is ~~receiving ever~~expected to receive increasing attention from ~~scientists~~the current federal administration, non-governmental organizations and ~~legislators alike. The debate is ongoing~~legislators. Debate continues as to the extent to which our climate is changing, the potential causes of ~~this~~any 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 in~~The EPA has begun using provisions of the ~~United States. However, there are a number of legislative and regulatory proposals~~Clean Air Act to ~~address~~regulate greenhouse gas emissions, ~~which are in various phases~~including 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 ~~possible~~likely that future carbon constraints ~~could~~will 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, these~~These 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 ese~~these events not fully covered by insurance could adversely affect our financial position and results of operations.

~~Glossary~~Our retail operations segment markets fixed-price and fixed-bill contracts that protect customers against higher natural gas prices, or protect customers against both higher natural gas prices and colder weather. The sale of ~~Key Terms~~

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 SouthStar~~retail 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.

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 ~~continuation~~current expansion of ~~recent economic conditions~~the 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 ~~slowdown~~overall economy in the ~~United States economy, along with increased mortgage defaults, and~~U.S. has a significant ~~decreases in new home construction, home values and investment assets, has adversely impacted~~impact 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 ~~may~~to 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.

A significant portion of our accounts receivable is subject to collection risks, due in part to a concentration of credit risk ~~in Georgia~~at 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 ~~risk~~risks in Georgia due to a concentration of credit ~~risk~~risks related to the provision of natural gas services to Marketers. At December 31, ~~2010,~~2013, Atlanta Gas Light ~~had eleven~~provided 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 ~~nonaffiliated~~non-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, ~~Chattanooga~~Virginia Natural Gas, Elizabethtown ~~Gas, Elkton~~ Gas, Florida City Gas, ~~and Virginia Natural~~Chattanooga Gas and ~~shares~~Elkton Gas. The profits it earns from the management of those assets with ~~those customers and~~these affiliates are shared with their respective customers ~~except at~~and 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 for~~agreements with Elizabethtown Gas ~~expires~~and Elkton Gas expire in March ~~2011~~2014 and we ~~are currently working with~~cannot 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 ~~nonaffiliated~~non-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.

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 interval~~For 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 ~~mechanism~~mechanisms for Virginia Natural Gas, Elizabethtown Gas and Chattanooga Gas that partially ~~offsets~~offset 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~~

Table of unusually cold or warm weather. In September 2007, the Virginia Commission approved Virginia Natural Gas’ application for an Experimental Weather Normalization Adjustment Rider (the Rider) for its commercial customers. The Rider applied to the 2007 and 2008 Heating Seasons. In September 2009 the Rider was extended to September 2011.Contents

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.

Table of ~~a robust natural gas supply, the weak economy and ample storage.~~Contents

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 of~~can cause our utility customers to conserve ~~in the~~their use of our gas services ~~and could lead to even more customers utilizing such conservation methods~~ or ~~switching~~switch to other competing products. ~~The higher~~Higher natural gas costs ~~have also allowed~~may 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 ~~fired~~fueled 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 result~~Glossary

The cost of providing ~~pension and postretirement health care~~retirement plan benefits to eligible employees and qualified retirees is subject to changes in pension fund values and ~~changing~~changes 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 ~~these~~retirement 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 are~~is 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 million~~additional 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 in~~6 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 States~~U.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 ~~conditions~~conditions;

·	adverse general capital market ~~conditions~~conditions;

·	poor performance and health of the utility industry in ~~general~~general;

·	bankruptcy or financial distress of unrelated energy companies or ~~Marketers~~Marketers;

·	significant decrease in the demand for natural ~~gas~~gas;

·	adverse regulatory actions that affect our local gas distribution companies and our natural gas storage ~~business~~business;

·	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 ~~facility~~facilities 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 existing~~The AGL Credit ~~Facility, Bridge Facility, Term Loan~~ Facility and the ~~SouthStar line of credit~~Nicor 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 ~~will~~would 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 that~~However, we ~~will be successful in structuring such~~may not structure these swap agreements ~~to manage~~in 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 erm~~short-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-owned~~wholly 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 form~~flows 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.

~~Our~~The AGL Credit Facility ~~Bridge Facility~~ and ~~Term Loan~~the 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, which~~Changes 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.UNRESOLVED~~1B.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 ~~assets~~mains

~~At December 31, 2010, our distribution operations and energy investment segments owned approximately 46,000 miles of underground distribution and transmission mains.~~ Our distribution ~~networks~~systems transport natural gas from our pipeline suppliers to our customers in our service areas. ~~The~~At 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 ~~7.5~~7.6 Bcf of LNG storage capacity in five LNG plants located in Georgia, New Jersey and Tennessee. In addition, we own ~~two~~one propane storage ~~facilities~~facility in Virginia ~~that have~~with a ~~combined~~ storage capacity of approximately ~~0.5~~0.3 Bcf. The LNG plants and propane storage ~~facilities~~facility are used by our distribution operations segment to supplement natural gas supply during peak usage periods.

Midstream Operations We ~~currently~~ own ~~two~~three high-deliverability natural gas storage and hub facilities which are operated by our ~~energy investments~~midstream operations segment. ~~Our wholly-owned subsidiary,~~ Jefferson Island ~~is located~~operates a salt-dome storage facility in Louisiana ~~and contains~~currently consisting of two salt dome gas storage caverns with approximately 10 Bcf of total capacity and ~~about 8~~7.3 Bcf of working gas capacity. ~~Our wholly-owned subsidiary,~~ Golden Triangle ~~Storage, is located~~operates 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 cavern~~Cavern 1, with 6 Bcf of working capacity, was completed and began commercial service in September 2010. ~~The second cavern~~Cavern 2, with ~~an expected 6~~7.5 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 ~~mid~~June 2012. ~~Our energy investments segment also owns a pro pane storage~~In 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 supply~~produces 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 brought~~will cooperate with any investigation by ~~purported Nicor shareholders challenging Nicor’s proposed merger with us. The complaints allege that we aided and abetted alleged breaches~~the DOJ or the SEC. We presently are unable to predict the duration, scope or result of ~~fiduciary duty by Nicor’s Board~~this 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 these~~our regulatory proceedings and litigation, see Note 1011 to our consolidated financial statements under the caption ~~“Litigation.”~~“Litigation” under Item 8 herein.

~~Glossary of Key Terms~~ITEM 4. MINE SAFETY DISCLOSURES

25Not applicable.

PART II

ITEM 5. 5.

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 ~~9,277~~20,598 record holders of our common stock. Quarterly information concerning our high and low stock prices and cash dividends paid in ~~2010~~2013 and ~~2009~~2012 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 ~~shareholders~~shareholders.

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 ~~dividends~~dividends.

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 regarding~~There were no purchases of our common stock by us ~~and~~or 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)

~~These~~Material changes from 2011 to 2012 are ~~non-GAAP measurements. A reconciliation of operating margin~~primarily 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

~~Overview~~Executive Summary

~~Our distribution operations segment~~We 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 to~~in 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 impact~~reporting 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 limit~~business. 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 potential~~in 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 volatility~~margins during 2013 primarily as a result of ~~extreme weather. Our energy investments segment’s primary~~contributions 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, acquires~~wholesale 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 assets~~expected to be recovered primarily in 2014.

In 2014, our priorities are consistent with the ~~Gulf Coast region of~~direction 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 ~~majority~~last three years. We will remain focused on efficient operations across all of our ~~storage services~~businesses, 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 medium~~detailed 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 ~~more~~additional information on our operating segments, see Note 13 to our consolidated financial statements under Item 8 herein and Item 1, “Business”.

~~Executive Summary~~Results of Operations

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 residential~~Proposed 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 in~~significant portion of our revenues. The following table provides more information regarding the ~~second half~~components 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 in~~Our results of operations for the ~~unregulated businesses~~year 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 ~~believe~~do 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 aspect~~is calculated as operating revenues minus cost of ~~the Dodd-Frank Act which requires that various regulatory agencies, including the SEC~~goods 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 inherent~~gain 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 costs~~calculation of ~~participating~~operating income as reflected in ~~financial markets for hedging certain risks may be increased as a result~~our 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.

~~Customer~~We 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 strategies~~since it is a direct measure of operating margin before overhead costs. You should not consider operating margin an alternative to, ~~retain existing customers at all~~or 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 ~~expect~~also 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 environment~~more 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 throughout~~operating 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.

Operating metrics

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 add~~adding 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 against~~from other energy sources ~~and~~emphasizing 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 ~~volatility~~pricing advantage of natural ~~gas prices was lower than it~~gas. 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 years~~decreased slightly primarily as a result of a ~~robust natural gas supply,~~highly competitive marketing environment, which we expect will continue for the ~~weak economy~~foreseeable 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 supplies~~volume metrics for distribution operations and retail operations, present the effects of weather and customers’ demand for natural gas compared to ~~meet~~prior 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 physical~~daily average natural gas ~~supplies in storage enable us~~volumes sold to ~~reduce earnings risk exposure due to higher gas costs.~~

~~It is possible that~~its customers. Within our midstream operations segment, our natural gas ~~prices will remain low for an extended period based on~~storage businesses seek to have a significant percentage of their working natural gas capacity under firm subscription, but also take into account current ~~levels~~and expected market conditions. This allows our natural gas storage business to generate additional revenue during times of ~~excess supply relative to~~peak 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 sources~~TEUs. In 2013 we successfully increased our number of ~~new shale natural gas reserves~~TEUs and therefore the ~~lack~~utilization of ~~demand by commercial~~our containers and ~~industrial enterprises. However, as economic conditions improve~~vessels. 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 information~~Our 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 services~~cargo 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’s~~wholesale 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 ~~statements~~Consolidated Statements of ~~financial position~~Financial Position items ~~such as~~across quarters, including receivables, unbilled revenue, inventories and short-term ~~debt across quarters.~~debt. However, these items are comparable when reviewing our annual results.

~~Glossary~~Additionally, the revenues of ~~Key Terms~~

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.

Approximately ~~70%~~66% of these segments’ operating revenues and ~~78%~~69% of these segments’ EBIT for the year ended December 31, ~~2010~~2013 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, ~~2010~~2013 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.

~~Results of Operations~~

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 ~~2011~~2014 and discussion of commercial activity, see ~~description of the inventory roll-out schedule in~~ Item 1 “Business.” under the caption Wholesale Services.

~~Energy Investments~~Midstream 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.

3435

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 ~~requirements~~needs primarily related to our natural gas inventory are our most significant ~~short-term~~short-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 ~~are~~is 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 and~~long-term debt, AGL Credit Facility ~~Bridge~~and 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, construction~~and 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, our~~Our 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 her~~other factors, some of which we are unable to control. These factors include, among others, regulatory changes, the price of ~~natural gas, the~~and demand for natural gas, and operational risks.

~~We will continue to evaluate our need to increase available liquidity based~~As 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 from~~use by the ~~beginning~~Company 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 increase~~2012. The decrease was ~~principally~~primarily due to ~~increased~~decreased 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 compared~~requirements 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 by~~following 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, credit~~Credit 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 ~~cost~~costs 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 ~~statements~~Consolidated Statements of ~~financial position~~Financial Position, leverage, capital spending, earnings, cash flow generation, available liquidity and overall business risks. We do not have any ~~trigger~~triggering events in our debt instruments that are tied to changes in our specified credit ratings or our stock price and have not entered into any 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 Resources

Nicor Gas

S&P

Moody’s

Fitch

S&P

Moody’s

Fitch

Corporate rating

A-BBB+

n/a

A-

BBB+

n/a

Commercial paper

A-2

P-2

A-2

P-1

Senior unsecured

BBB+

~~Baa1~~

BBB+

A-

A+

Senior secured

n/a

Aa3

AA-

Ratings outlook

~~Negative~~Stable

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 a~~A downgrade in our current ratings, particularly below investment grade, ~~could adversely affect~~would increase our borrowing costs and ~~significantly~~could 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 contains~~credit 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, fundamental~~and 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 contains~~credit facilities contain certain non-financial covenants that, among other things, restrict liens and encumbrances, loans and investments, acquisitions, dividends and other restricted payments, asset dispositions, mergers and consolidations, and other matters customarily restricted in such agreements.

Our ~~Credit Facility also includes~~credit facilities each include a financial covenant that ~~does not permit our~~requires us to maintain a ratio ~~on a consolidated basis,~~ of total debt to total capitalization ~~to exceed~~of 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 letters~~However, 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 bonds~~acquisition 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, we~~We 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 same~~default provisions, see Note 8 to our consolidated financial ~~covenant and similar non-financial covenants and default provisions; however, these are not effective until we draw~~statements 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)	~~For~~Only includes Nicor expenditures subsequent to the ~~year ended~~merger 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 Bonds~~Light and $9 million for accelerated infrastructure replacement program projects at Virginia Natural Gas.

~~In June~~Our 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 of~~outstanding 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 agreements~~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 ~~remarketing agents to resell~~the syndicate of banks regarding the bonds ~~to investors. We established new~~is 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 provide~~providing credit ~~enhancement to~~support for the ~~bonds.~~ ~~The weighted average interest rates on our variable rate~~retired 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-year~~in 30-year senior notes ~~at an interest rate of 5.25%. The~~with net proceeds ~~from the offering were approximately $297 million. We~~of $494 million used ~~the net proceeds from the sale of the senior notes~~ to repay a portion of ~~our short-term debt.~~

~~We had $300~~AGL 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 of~~at December 31, ~~2010,~~2011 had principal balances totaling $500 million and maturity dates between 2016 and 2038. These bonds were ~~reported as~~recorded at their estimated fair value of $599 million on the ~~current~~date 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 paper~~within “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, $20~~2013, $14 million in ~~2009~~2012 and ~~$30~~$16 million in ~~2008~~2011 in our Consolidated ~~Statement~~Statements 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, $127~~2013, $203 million in ~~2009~~2012 and ~~$124~~$148 million in ~~2008.~~2011. The increases were generally the result of the annual dividend ~~increases~~increase 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.

~~Treasury Shares~~ ~~In February 2006, our Board~~Table of Directors authorized a plan to purchase up to 8 million shares of our outstanding common stock over a five-year period. These purchases are intended principally to offset share issuances under our employee and non-employee director incentive compensation plans and our dividend reinvestment and stock purchase plans. Stock purchases under this program may be made in the open market or in private transactions at times and in amounts that we deem appropriate. There is no guarantee as to the exact number of common shares that we will purchase, and we can terminate or limit the program at any time. This program expired in January 2011.Contents

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. Debt~~2016. 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 ~~Capital~~Resources 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 ~~covenants~~covenant 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 activities~~business 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 portion~~Excludes the $82 million step up to fair value of ~~long-term~~first mortgage bonds, $16 million unamortized debt ~~of $300~~premium 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 ~~amount~~balance 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 is~~interest charges are calculated based on the interest rate as of December 31, ~~2010~~2013 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 annual~~Our 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 ~~postretirement~~other 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, we~~We 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 ~~postretirement~~other 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 ~~postretirement~~retirement benefit ~~expense~~expenses 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, ~~2010~~2013 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 expected~~Illinois, 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 ~~postretirement~~other retirement plans.

In ~~2010, we contributed $31 million~~2013, no contributions were required to our qualified pension ~~plans.~~plans. In ~~2009,~~2012, we contributed ~~$24~~$40 million to ~~our~~these 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 funding~~estimated funded status of the ~~plans,~~merged AGL Pension plan, we ~~would be~~do not expect any required ~~to make a minimum~~ contribution to the ~~plans of approximately $30 million~~plan in ~~2011.~~2014. We ~~are planning~~may, at times, elect to ~~make~~contribute additional ~~contributions in 2011 up~~amounts to ~~$31 million, for a total of up to $61 million, in order to preserve~~ the ~~current level of benefits under the plans and~~AGL 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 ~~from~~due 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-evaluate~~reevaluate 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 ~~significant~~most critical accounting policies, ~~described in Note 2 of the Notes to Consolidated Financial Statements, the following represents~~which 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 Liabilities~~Accounting for Rate-Regulated Subsidiaries

We ~~record regulatory assets and liabilities in our Consolidated Statements~~account for the financial effects of ~~Financial Position~~regulation in accordance with authoritative guidance related to regulated ~~entities. We record~~entities whose rates are designed to recover the costs of providing service. In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense in the current period are capitalized as regulatory assets when it is probable that such costs or expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for ~~costs~~estimated expenditures that have not yet been ~~deferred for which~~incurred. 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 probable~~rate proceedings. We are not aware of any evidence that these costs will not be recoverable through either rate riders or base rates, ~~specifically authorized~~and we believe that we will be able to recover such costs consistent with our historical recoveries. In the event that the provisions of authoritative guidance related to regulated operations were no longer applicable, we would recognize a write-off of regulatory assets that would result in a charge to net income and be classified as an extraordinary item. Additionally, while some regulatory liabilities would be written off, others 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 record~~commissions. 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 is~~assets 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 the~~are 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 date~~liabilities that do not represent revenue collected from customers for expenditures that have not yet been ~~recovered~~incurred are refunded to ratepayers through a rate ~~riders, and (ii)~~rider or base rates. If the ~~future expected costs~~regulatory liability is included in base rates, the amount is reflected as a reduction to ~~be recovered through~~the 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 ~~discussed~~included 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 legislation~~recovered 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, state~~natural 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 reserves~~return on investment during the recovery period. Nicor Gas’ rate riders for environmental ~~remediation obligations when it~~costs 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 and~~no interest associated with the ~~amount~~under or ~~range~~over 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 Georgia~~Our natural gas distribution operations and ~~Florida, we have confirmed 14 former MGP sites where Atlanta Gas Light owned or operated all or part~~certain 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 liability~~operations 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 ~~included~~probable that they can be recovered through rates. Further, regulation may impact the period in ~~its corresponding~~which 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 recovery~~assets 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 sites~~rate 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 sites~~period 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 Environment~~6% and ~~Natural Resources. There is one other site~~15% decreases in ~~North Carolina where investigation~~total 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 ~~accordance~~the 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 recorded~~a market participant’s perspective.

Under the ~~lower~~income 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 be~~The 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. Details~~fair values of our ~~environmental remediation costs~~reporting units are ~~discussed~~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 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 ~~statements~~Consolidated Statements of ~~financial position~~Financial 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 ~~and~~or 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’s~~derivatives’ 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’s~~derivative 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 use~~used to manage ~~exposures arising from~~our 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 ~~counterparty~~counterparty; 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, ~~2010~~2013 and ~~$238~~$144 million at December 31, ~~2009.~~2012. Additionally, we have recorded derivative ~~financial~~ liabilities of ~~$48~~$80 million at December 31, ~~2010~~2013 and ~~$62~~$39 million at December 31, ~~2009. In 2010, we~~2012. 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, ~~result~~results 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, including~~and 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 ~~Postretirement~~Retirement Plans

Our pension and other ~~postretirement~~retirement 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 ~~postretirement~~retirement plan costs and liabilities and update them when ~~appropriate.~~

appropriate.The critical actuarial assumptions used to develop the required estimates for our pension and ~~postretirement~~other 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 ~~postretirement~~other retirement obligations and our annual net pension and ~~postretirement~~other 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 a~~indices. The single equivalent discount rate is derived ~~utilizing the forecasted future cash flows in each year to~~by 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 ~~postretirement~~other retirement plan cost is not ~~affected. Rather,~~affected; rather, this gain or loss reduces or increases future pension or ~~postretirement~~other retirement plan costs.

Equity market performance and corporate bond rates have a significant effect on our reported results. For ~~our largest~~the AGL pension plan, market performance ~~also effects~~affects 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 ~~moving~~smoothing weighted average methodology. Gains and losses on plan assets are spread through the MRVPA based on the five-year ~~moving~~smoothing weighted average methodology, which affects the expected return on plan assets component of pension expense.

In addition, differences between actuarial assumptions and actual plan ~~results~~experience 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 largest~~the AGL pension plan. ~~If necessary, the~~The 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 ~~postretirement~~other retirement benefit ~~costs.~~plans. We estimate that in ~~2011,~~2014, we will record net periodic pension and other ~~postretirement~~retirement 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 increase~~decrease 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 ~~postretirement~~other retirement plans while holding all other assumptions ~~constant.~~constant:

Dollars in millions

Percentage-point

change in assumption

~~In millions~~

~~Actuarial assumptions~~

~~Percentage-point change~~

Increase (decrease)

in ~~assumption~~PBO/ 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 ~~asset~~assets will not be ~~realized.~~realized.

~~This liability is~~Deferred 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 ~~audit~~audits 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 ~~net~~gross 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.

~~Accounting Developments~~

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 and~~determine whether tax benefits claimed or expected to ~~disclose~~be 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 on~~recorded 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 when~~tax 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. Although~~that the ~~guidance~~tax position will be ~~effective for us~~sustained on ~~January 1, 2011, our goodwill impairment analysis for~~examination by the ~~years ended~~taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement.

Additionally, we recognize accrued interest related to uncertain tax positions in interest expense, and penalties in operating expense in the Consolidated Statements of Income. As of December 31, ~~2010 and 2009 indicates that the fair values of our reporting units substantially exceed their carrying values, and~~2013, 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.~~

~~Glossary~~liability recorded for payment of ~~Key Terms~~

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

Our ~~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 ~~Risk~~Risks

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

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

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

Retail Operationsand Wholesale Services We routinely ~~utilizes~~utilize various types of derivative ~~financial~~ instruments to mitigate certain natural gas price and weather ~~risk~~risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and OTC energy contracts, such as forward contracts, futures contracts, options contracts and swap agreements. ~~This includes the active management of~~Retail operations and wholesale services also actively manage storage positions through a variety of hedging transactions for the purpose of managing exposures arising from changing natural gas prices. ~~SouthStar uses these~~These hedging instruments are used to substantially lock in economic margins (as spreads between wholesale and retail natural gas prices widen between periods) and thereby minimize ~~its~~our 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 Investments~~Midstream Operations ~~Golden Triangle Storage uses~~We use derivative ~~financial~~ instruments to reduce ~~its~~our exposure to the risk of changes in the price of natural gas that will be purchased in future periods for pad gas, conditioning gas and additional volumes of gas used to de-water ~~the cavern~~our 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, ~~2010~~2013 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

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

The following ~~tables illustrate~~table illustrates the change in the net fair value of our derivative ~~financial~~ instruments during the ~~twelve~~12 months ended December 31, ~~2010, 2009~~2013, 2012 and ~~2008,~~2011, and ~~provide details~~provides detail of the net fair value of contracts outstanding as of December 31, ~~2010, 2009~~2013, 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 and~~2013, $4 million at December 31, ~~2008~~2012 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, 2009~~2013, 2012 and ~~2008~~2011 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 ~~pretax~~pre-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 ~~eleven~~12 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.

4749

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 obtains~~We obtain credit scores for ~~its~~our firm residential and small commercial customers using a national credit reporting agency, enrolling only those customers that meet or exceed ~~SouthStar’s~~our credit threshold.

~~SouthStar considers~~ We consider potential interruptible and large commercial customers based on ~~a review~~reviews of publicly available financial statements and ~~review of~~ commercially available credit reports. Prior to entering into a physical transaction, ~~SouthStar~~we also ~~assigns~~assign physical wholesale counterparties an internal credit rating and credit limit based on the counterparties’ Moody’s, S&P and Fitch ratings, commercially available credit reports and audited financial statements.

Wholesale Services ~~Sequent has~~We have established credit policies to determine and monitor the creditworthiness of counterparties, as well as the quality of pledged collateral. ~~Sequent~~We also ~~utilizes~~utilize master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When ~~Sequent is~~we are engaged in more than one outstanding derivative transaction with the same counterparty and itwe also ~~has~~have a legally enforceable netting agreement with that counterparty, the “net” mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of ~~Sequent’s~~our credit risk. ~~Sequent~~We also ~~uses~~use other netting agreements with certain counterparties with whom ~~it conducts~~we conduct significant ~~transactions .~~transactions. Master netting agreements enable ~~Sequent~~us to net certain assets and liabilities by counterparty. ~~Sequent~~We also ~~nets~~net across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions.

Additionally, ~~Sequent~~we may require counterparties to pledge additional collateral when deemed necessary. ~~Sequent conducts~~We conduct credit evaluations and ~~obtains~~obtain appropriate internal approvals for ~~its~~a counterparty’s line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody’s and BBB- from S&P. Generally, ~~Sequent requires~~we 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 has~~We have a concentration of credit risk as measured by ~~its~~our 30-day receivable exposure plus forward exposure. As of December 31, ~~2010,~~2013, excluding ~~$61~~$8 million of customer deposits, ~~Sequent’s~~our 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’s~~2013, 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’s~~our third-party natural gas contracts receivable and payable ~~positions.~~positions.

4850

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 has~~We have certain trade and credit contracts that have explicit minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, ~~Sequent~~we would need to post collateral to continue transacting business with some of ~~its~~our counterparties. If such collateral were not posted, ~~Sequent’s~~our ability to continue transacting business with these counterparties would be impaired. If our credit ratings had been downgraded to non-investment grade status, the required amounts to satisfy potential collateral demands under such agreements ~~between Sequent and its~~with 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.

4951

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, ~~2010~~2013 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, ~~2010~~2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the ~~Com pany~~Company 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 ~~Over~~over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United ~~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 ~~Company~~company are being made only in accordance with ~~authoriz ations~~authorizations 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’s~~company’s assets that could have a material effect on the financial statements.

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

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Atlanta, ~~Georgia~~GA

February ~~9, 2011~~6, 2014

5052

~~Management’s~~Management’s Report on Internal Control Over Financial Reporting

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

Based on our evaluation under the framework in the Internal Control –- Integrated Framework (1992) issued by COSO, our management concluded that our internal control over financial reporting was effective as of December 31, ~~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, 2011~~6, 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

~~Consolidated Statements of Financial Position - Assets~~

~~AGL Resources Inc.~~

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.~~

~~Consolidated Statements of Income~~CONSOLIDATED STATEMENTS OF FINANCIAL POSITION - ASSETS

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

~~Consolidated Statements of Equity~~

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 ~~SUBSIDIARIES~~SUBISIDIARIES

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 Flows~~CONSOLIDATED 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, ~~2010~~2013 are prepared in accordance with GAAP and under the rules of the SEC. Our consolidated financial statements include our accounts, the accounts of our wholly owned subsidiaries, the accounts of our majority-owned and other controlled subsidiaries and the accounts of our variable interest entity for which we are the primary beneficiary. ~~This means~~For 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 with~~proportionate 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 eliminated~~consolidation except for intercompany profits ~~when~~where 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 ~~Allowance~~2012, we had $80 million of cash and short and long-term investments in our Consolidated Statements of Financial Position held by Tropical Shipping. These cash and investment amounts are available for ~~Uncollectible Accounts~~

~~Our receivables consist~~use by us or our other operations only if we repatriate a portion of ~~natural gas sales~~Tropical 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 majority~~pay a significant amount of ~~our receivables, we establish an allowance~~U.S. income tax that has been previously deferred. See Note 12 for ~~doubtful accounts based~~additional 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 Light~~Concentration 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. ~~The~~While the amounts due from, or owed to, wholesale services’ counterparties are ~~netted and~~settled net, they are recorded on a gross basis in our Consolidated Statements of Financial Position as energy marketing receivables and energy marketing payables.

Our wholesale services segment has ~~some~~ trade and credit contracts that ~~have explicit~~contain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale services would need to post collateral to continue transacting business with some of its counterparties. ~~No collateral has been posted under such provisions since~~To date, our credit ratings have ~~always~~ exceeded the minimum requirements. As of December 31, ~~2010~~2013 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 ncial~~financial condition. ~~However, if~~If such collateral were not posted, wholesale services’ ability to continue transacting business with these counterparties would be negatively impacted.

~~Sequent~~

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 evaluates~~exposure. We evaluate the credit risk of ~~its~~our 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 ~~9.00~~9 to ~~1.00,~~1, with ~~9.00~~9 being equivalent to AAA/Aaa by S&P and Moody’s and ~~1.00~~1 being equivalent to ~~D or~~ D/Default by S&P and Moody’s. ~~For a customer without~~A counterparty that does not have an external rating ~~Sequent assigns~~is 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 total~~The 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’s~~counterparty’s assigned internal rating by its credit exposure and then ~~adding~~summing the individual results for all counterparties. ~~That total~~The sum is divided by the aggregate total ~~exposure. This~~exposure and this numeric value is then converted to an S&P equivalent.

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

~~Fair value measurements~~Receivables and Allowance for Uncollectible Accounts

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

Nicor Gas Credit risk exposure at Nicor Gas is mitigated by a bad debt rider approved by the Illinois Commission. The bad debt rider provides for the recovery from (or refund to) customers of the difference between Nicor Gas’ actual bad debt experience on an annual basis and the benchmark bad debt expense used to establish its base rates for the respective year. See Note 3 for additional information on the bad debt rider.

Atlanta Gas Light Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 12 Marketers in Georgia. The credit risk exposure to Marketers varies seasonally, with the lowest exposure in the nonpeak summer months and the highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. The functions of the retail sale of gas include the purchase and sale of natural gas, customer service, billings and collections. We obtain credit security support in an amount equal to no less than two times a Marketer’s highest month’s estimated bill from Atlanta Gas Light.

Inventories

For our regulated utilities, except Nicor Gas, our natural gas inventories and the inventories we hold for Marketers in Georgia are carried at cost on a WACOG basis. In Georgia’s competitive environment, Marketers sell natural gas to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation and provides this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. On a monthly basis, Atlanta Gas Light assigns the majority of the pipeline storage services that it has under contract to Marketers, along with a corresponding amount of inventory. Atlanta Gas Light also retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand. See Note 11 for information regarding a regulatory filing by Atlanta Gas Light related to gas inventory.

Nicor Gas’ inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of goods sold at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of goods sold at the actual LIFO cost of the layers liquidated. Since the cost of gas, including inventory costs, is charged to customers without markup, subject to Illinois Commission review, LIFO liquidations have no impact on net income. At December 31, 2013, the Nicor Gas LIFO inventory balance was $168 million. Based on the average cost of gas purchased in December 2013, the estimated replacement cost of Nicor Gas’ inventory at December 31, 2013 was $402 million, which exceeded the LIFO cost by $234 million.

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 ~~cash~~receivables, short and ~~cash equivalents, receivables, derivative financial~~long-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 assify~~classify fair value balances based on the observance of those inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by the guidance are as follows:

~~Level 1~~

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 iple~~multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the market place. As we aggregate our disclosures by counterparty, the underlying transactions for a given counterparty may be a combination of exchange-traded derivatives and values based on other sources.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 in~~to 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 as~~Transfers into and out of Level 3 ~~except for~~reflect the liquidity at the relevant natural gas trading locations and dates, which affects the significance of unobservable inputs used in the valuation applied to natural gas derivatives. Our Level 3 assets, liabilities and any applicable transfers are primarily related to our pension and other retirement benefit plan assets as described in Note 3, Note 4 and Note 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 ~~established~~includes a two-step process to determine ifwhether the market for a financial asset is inactive ~~and~~or 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 Hierarchy~~As 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 formance~~own nonperformance risk on our liabilities. To mitigate the risk that a counterparty to a derivative instrument defaults on settlement or otherwise fails to perform under contractual terms, we have established procedures to monitor the creditworthiness of counterparties, seek guarantees or collateral backup in the form of cash or letters of credit and, in most instances, enter into netting arrangements. See Note 4 for additional fair value disclosures.

~~Glossary~~For our Illinois weather risk associated with Nicor Gas, we implemented a corporate weather hedging program in the second quarter of ~~Key Terms~~

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 related~~We have elected to ~~derivatives~~net derivative assets and ~~hedging requires~~liabilities under master netting arrangements on our Consolidated Statements of Financial Position. With that election, we are also required to offset cash collateral held in our broker accounts ~~on our Consolidated Statements of Financial Position~~ with the associated net fair value of the instruments in the accounts. ~~Our~~See 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 enters~~enter 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, these~~As 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 hedges~~elected 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.

Retail ~~Energy~~ Operations We have designated a portion of ~~SouthStar’s~~our 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 of~~that the underlying hedged ~~item.~~item is recognized in earnings.

~~SouthStar~~We currently ~~has~~have minimal hedge ineffectiveness ~~defined as~~, which occurs when the gains or losses on the hedging instrument ~~do not~~more than offset the losses or gains on the hedged item. ~~This~~Any 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’s~~our derivative ~~financial~~ instruments as hedges ~~under the authoritative guidance related to derivatives and hedging~~for accounting purposes and, accordingly, we record changes in ~~their~~the fair ~~value~~values of such instruments within cost of ~~gas~~goods sold in our Consolidated Statements of Income in the period of change.

We also enter into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather in the Heating Season. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non exchange-traded options are accounted for using the intrinsic value method and do not qualify for hedge accounting designation. Changes in the intrinsic value for non exchange-traded contracts are also reflected in operating revenues in our Consolidated Statements of Income.

Wholesale Services We purchase natural gas for storage when ~~the 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 ~~derivatives~~contracts to sell natural gas at that future price to substantially lock in the operating margin we will ultimately realize when the stored natural gas is ~~sold.~~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 for~~carried 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 futures~~These 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 ~~date~~dates the transactions were consummated.

~~Energy Investments~~Debt 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 ~~considered~~consider 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, ~~2010~~2013 and ~~2009~~2012 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 consist~~consists of property and equipment that is currently in use, being held for future use and currently under construction. We report PP&E at its original cost, which includes:

·	material and ~~labor~~labor;

·	contractor ~~costs~~costs;

·	construction overhead ~~costs~~costs;

·	~~an allowance for funds used during construction (AFUDC) which represents~~AFUDC; and,

Nicor Gas’ pad gas - the ~~estimated cost of funds, from both debt and equity sources, used~~portion considered to ~~finance~~be non-recoverable is recorded as depreciable PP&E, while the ~~construction of major projects and~~portion considered to be recoverable is ~~capitalized in rate base for ratemaking purposes when the completed projects are placed in service~~recorded as non-depreciable PP&E.

We ~~charge~~recognize 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 are~~or recovered from, customers through future rate adjustments. Our natural gas utilities also hold property, primarily land; this is not presently used and useful in ~~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 Investments~~Midstream Operations, Cargo Shipping and ~~Corporate~~Other PP&E ~~expenditures include~~includes property that is in use and under construction, and we report it at cost. We record a gain or loss within operation and maintenance expense for retired or otherwise disposed-of property. Natural gas in salt-dome storage at Jefferson Island and Golden Triangle ~~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 equipment~~PP&E and is ~~valued~~carried at cost. Central Valley has two types of pad gas in its depleted reservoir storage facility. The first is non-depreciable PP&E, which is carried at cost, and the second is non-recoverable, over which we have no contractual ownership.

Depreciation Expense

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 depreciation~~More information on our rates ~~for depreciable property -- excluding transportation equipment for Atlanta Gas Light, Virginia Natural Gas and Chattanooga Gas~~used and the ~~composite, straight-line rates for Elizabethtown Gas, Florida City Gas and Elkton Gas are listed~~rate 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 ~~life~~lives 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 years	Estimated useful life
Transportation equipment		5 - 10
Shipping vessels		20 - 25
Storage caverns		40 - 60
Other	up to 40

AFUDC and Capitalized Interest

~~Four of our utilities~~Atlanta Gas Light, Nicor Gas, Chattanooga Gas and Elizabethtown Gas are authorized by applicable state regulatory agencies or legislatures to ~~record~~capitalize the cost of debt and equity funds as part of the cost of PP&E construction projects in our Consolidated Statements of Financial Position. 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 ended~~Amount recorded in ~~2009. VNG received no AFUDC interest for 2010.~~the Consolidated Statements of Income.

~~Within~~The 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.

~~Goodwill~~Asset Retirement Obligations

~~Goodwill is~~We record a liability at fair value for an asset retirement obligation (ARO) when a legal obligation to retire the ~~excess~~asset has been incurred, with an offsetting increase to the carrying value of the ~~purchase price over~~related asset. Accretion of the ARO due to the passage of time is recorded as an operating expense. We have recorded an ARO of $3 million at December 31, 2013 and 2012 principally for our storage facilities. For our distribution PP&E, we cannot reasonably estimate the fair value of ~~identifiable net~~this obligation because we have determined that we have insufficient internal or industry information to reasonably estimate the potential settlement dates or costs.

Impairment of Assets

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

Goodwill We perform an annual goodwill ~~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 a~~To estimate the fair value of our reporting units, we use two generally accepted valuation approaches, the income approach and the market approach, using assumptions consistent with a market participant’s perspective.

Under the income approach, fair value is estimated based on the present value of estimated future cash flows discounted at an appropriate risk-free rate that takes into consideration the time value of money, inflation and the risks inherent in ownership of the business being valued. The cash flow estimates contain a ~~reporting unit level which generally equates to our operating segments, as discussed~~degree of uncertainty, and changes in ~~Note 12 “Segment Information,” and an impairment charge is recognized if~~ the ~~carrying~~projected cash flows could significantly increase or decrease the estimated fair value of a reporting ~~unit’s goodwill exceeds its~~unit. 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.

6265

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

We weight the ~~years ended December 31, 2010 and 2009 indicated that~~results of the two valuation approaches to estimate the fair value of each reporting ~~unit is substantially~~unit. Our goodwill impairment testing also develops a baseline test and performs a sensitivity analysis to calculate a reasonable valuation range. The sensitivities are derived by altering those assumptions that are subjective in nature and inherent to a discounted cash flows calculation.

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

Within our midstream operations segment, the estimated fair value of our storage and fuels reporting unit with $14 million of goodwill, exceeded its carrying value by less than 5% and is at risk of failing the step one test. The discounted cash flow model used in the goodwill impairment ~~charges~~test 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 taking~~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 ~~charges~~test.

The cash flow forecast for the storage and fuels reporting unit assumed earnings growth over the next eight years. Should this growth not occur, this reporting unit may fail step one of a goodwill impairment test in a future period. Along with any reductions to our cash flow forecast, changes in other key assumptions used in our 2013 annual impairment analysis may result in the ~~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 ~~differences~~difference between net income and taxable income ~~relate~~relates to the timing of deductions, primarily due to the benefits of tax depreciation since we generally depreciate assets for tax purposes over a shorter period of time than for book purposes. The determination of our provision for income taxes requires significant judgment, the use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items. We report the tax effects of depreciation and other temporary differences ~~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 Taxes~~We have ~~two categories of~~current 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 liability~~of 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 ~~the~~these deferred income tax assets and liabilities using enacted income tax ~~rates~~rates.

A deferred income tax liability is not recorded on undistributed foreign earnings that are ~~currently~~expected to be indefinitely reinvested offshore. We consider, among other factors, actual cash investments offshore as well as projected cash requirements in ~~effect. Because~~making this determination. Changes in our investment or repatriation plans or circumstances could result in a different deferred income tax liability. We had $80 million of ~~the regulated nature~~such 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 ~~recorded~~would be required to record a ~~regulatory~~deferred tax liability ~~in accordance with authoritative guidance related to income taxes, which~~of $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 ~~expenses~~expense in ~~the~~our 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 which~~Position. In other instances, we are ~~required~~allowed to ~~include in revenues~~recover from customers other taxes that are imposed upon us. We record such taxes as operating expenses and record the corresponding customer charges as operating ~~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 billing~~bills 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 ~~implemented~~bills Marketers for capacity costs utilizing a seasonal rate design for the calculation of each residential end-use customer’s annual straight-fixed-variable (SFV) ~~capacity~~ charge, which ~~is billed to Marketers and~~ reflects the historic volumetric usage pattern for the entire residential class. Generally, this ~~change~~seasonal rate design results in ~~residential customers being billed by~~billing the Marketers ~~for~~ a higher capacity charge in the winter months and a lower charge in the summer ~~months. This requirement has an~~months, which impacts our operating cash ~~flow impact but~~flows. However, this seasonal billing requirement does not ~~change revenue recognition. As~~impact 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 Gas~~have rate structures that include volumetric rate designs ~~that~~which allow recovery of certain costs ~~through~~based on gas usage. Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. Additionally, revenues are ~~recorded~~recognized for estimated deliveries of gas not yet billed to these customers, from the last ~~meter reading~~bill date to the end of the accounting period. These are included in the Consolidated Statements of Financial Position as unbilled revenue. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries to the ~~en d~~end of the period.

The tariffs for ~~Elizabethtown~~Virginia Natural Gas, ~~Virginia Natural~~Elizabethtown Gas and Chattanooga Gas contain ~~WNA’s~~WNAs 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 ~~reduce~~mitigate the effect of weather on customer bills by reducing bills when winter weather is colder-than-normal and increasing bills when weather is warmer-than-normal. In addition, the ~~tariff~~tariffs for Virginia Natural Gas, ~~contains a~~Chattanooga Gas and Elkton Gas contain revenue normalization ~~mechanism~~mechanisms that ~~mitigates~~mitigate the impact of conservation and declining customer usage.

Revenue Taxes We charge customers for gas revenue and gas use taxes imposed on us and remit amounts owed to various governmental authorities. Our policy for gas revenue taxes is to record the amounts charged to customers, which for some taxes includes a small administrative fee, as operating revenues, and to record the related taxes incurred as operating expenses in our Consolidated Statements of Income. Our policy for gas use taxes is to exclude these taxes from revenue and expense, aside from a small administrative fee that is included in operating revenues. As a result, the amount recorded in operating revenues will exceed the amount recorded in operating expenses by the amount of administrative fees that are retained by the Company. Revenue taxes included in operating expenses were $110 million in 2013, $85 million in 2012 and $9 million in 2011.

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 ~~recorded~~recognized for estimated deliveries of gas not yet billed to these customers, from the most recent meter reading date to the end of the accounting period. ~~These~~The related receivables are included in the Consolidated Statements of Financial Position as unbilled revenue. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual ~~deliv eries~~deliveries during the period.

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

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

~~Energy investments~~Midstream operations We record operating revenues ~~at Jefferson Island~~for storage and ~~Golden Triangle Storage~~transportation 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 ~~gas~~goods 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 current~~an 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 ~~gas~~goods sold and ~~what is collected from or billed to customers~~the 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 amounts~~Deferred natural gas costs are reflected as regulatory assets ~~identified as recoverable~~and 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 within~~Within our cost of ~~gas amounts for~~goods sold, we also include costs of fuel and lost and unaccounted for gas, adjustments to reduce the value of our inventories to market value and ~~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, this~~This accounting treatment does not affect the future annual operating lease cash obligations. For more information, see Note 11.

6469

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 occur~~occurs when potentially dilutive common shares are added to common shares outstanding. The increase in weighted average shares in 2012 compared to 2011 is primarily due to the issuance of 38.2 million shares in connection with the Nicor merger on December 9, 2011.

We derive our potentially dilutive common shares by calculating the number of shares issuable under restricted stock, restricted stock units and stock options. The ~~future issuance~~vesting of certain shares ~~underlying~~of the restricted stock and restricted ~~share~~stock units depends on the satisfaction of ~~certain~~defined performance criteria. The future issuance of shares underlying the outstanding stock options depends on whether the ~~exercise prices of the stock options are less than the average~~ market price of the common shares ~~for~~underlying 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 average~~The 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 contains~~remaining $5 million of contingent cash consideration will be determined and would be received from the ~~weighted average shares~~buyer annually over a five-year earn out period based upon the financial performance of Compass Energy.

Non-Wholly Owned Entities

We hold ownership interests in a number of business ventures with varying ownership structures. We evaluate all of our partnership interests and other variable interests to determine if each entity is a variable interest entity (VIE), as defined in the authoritative accounting guidance. If a venture is a VIE for which we are the primary beneficiary, we consolidate the assets, liabilities and results of operations of the entity. We reassess our conclusion as to whether an entity is a VIE upon certain occurrences, which are deemed reconsideration events under the guidance. We have concluded that the only venture that we are required to consolidate as a VIE, as we are the primary beneficiary, is SouthStar. On our Consolidated Statements of Financial Position, we recognize Piedmont’s share of the non-wholly owned entity as a separate component of equity entitled “noncontrolling interest.” Piedmont’s share of current operations is reflected in “net income attributable to ~~outstanding stock options that were excluded from~~ the ~~computation~~noncontrolling interest” on our Consolidated Statements of Income. The consolidation of SouthStar has no effect on our calculation of basic or diluted earnings per common share amounts, which are based upon net income attributable to AGL Resources ~~Inc. because their effect would~~Inc.

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 accounts. All such investments are required to be accounted for under the equity method unless our interest is so minor that there is virtually no influence over operating and financial policies, as ~~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 ~~decrease~~preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures. Our estimates are based on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Our estimates may involve complex situations requiring a high degree of judgment either in the ~~number~~application and interpretation of ~~shares that were excluded from the computation for the year ended December 31, 2010 is the result of an increase~~existing literature or in the ~~average market value~~development of estimates that impact our ~~common shares~~financial 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 2009~~contingent losses, goodwill and ~~2008. While the market value of~~intangible 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.

~~Regulatory~~Accounting Developments

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

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

Note 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 incurred~~such 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 liabilities~~as 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 ~~these~~such costs ~~consistently~~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, ~~the~~while some regulatory liabilities would ~~not~~ be ~~written-off but~~written 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 e~~the amount is reflected as a reduction to the rate base ~~in setting~~used to periodically set base rates.

~~All the~~

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

Nicor Gas’ pension and retiree welfare benefit costs have historically been considered in rate proceedings in the same period they are accrued under GAAP. As a regulated utility, Nicor Gas expects to continue rate recovery of the eligible costs of these defined benefit retirement plans and, accordingly, associated changes in the funded status of Nicor Gas’ plans have been deferred as a regulatory asset or liability until recognized in net income, instead of being recognized in OCI. The Illinois Commission presently does not allow Nicor Gas the opportunity to earn a return on its recoverable retirement benefit costs. Such costs are expected to be recovered over a period of 11 years. The regulatory assets related to debt are also not included in rate base, but the costs are recovered over the term of the debt through the authorized rate of return component of base rates.

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

Our accrued ERC ~~liabilities~~costs are ~~included~~not 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 two~~three rate riders that authorize dollar-for-dollar recovery. We expect to collect $45 million in revenues over the ~~recovery of these costs. The~~next 12 months, which is reflected as a current regulatory asset. We recovered $24 million in 2013, $13 million in 2012 and $5 million in 2011 from our ERC rate 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 Instruments~~Bad Debt Rider ~~Elizabethtown~~Nicor Gas’ ~~derivative financial instrument asset and liability reflect unrealized losses or gains that will be recovered~~bad debt rider provides for the recovery from, or ~~passed~~refund 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 costs~~Income and a regulatory liability on ~~a dollar for dollar basis, once~~our Consolidated Statements of Financial Position until refunded to customers. In the ~~losses or gains~~period 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 Assets~~Accumulated Removal Costs In accordance with regulatory treatment, our depreciation rates are comprised of two cost components - historical cost and ~~Liabilities~~ ~~Our recoverable postretirement benefit~~the estimated cost of removal, net of estimated salvage, of certain regulated properties. We collect these costs in base rates through straight-line depreciation expense, with a corresponding credit to accumulated depreciation. Because the accumulated estimated removal costs are ~~recoverable through base rates over~~not a generally accepted component of depreciation, but meet the ~~next 3~~requirements 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 ~~collection~~accumulated removal cost regulatory liability in our Consolidated Statements of Financial Position. In the ~~revenues over~~rate setting process, the liability for these accumulated removal costs is treated as a ~~seasonal pattern. These amounts are fully recoverable through~~reduction 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-term~~current 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 ~~2010~~2013

·	$4151 million in ~~2009~~2012

·	$3048 million in ~~2008~~2011

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’s~~Our 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 the~~The purpose of the i-SRP ~~program~~ is to upgrade ~~Atlanta Gas Light’s~~our distribution system and liquefied natural gas facilities in Georgia, improve ~~its~~our 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 ~~required~~recovered 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.

~~Under~~The purpose of the ~~i-CGP~~i-VPR program is to replace aging plastic pipe that was installed primarily in the mid-1960’s to the early 1980’s. We have identified approximately 3,300 miles of vintage plastic mains in our system that potentially should be considered for replacement over the next 15 - 20 years as it reaches the end of its useful life. On August 6, 2013, the Georgia Commission approved the replacement of 756 miles of vintage plastic pipe over four years at an estimated cost of $275 million. Additional reporting requirements and monitoring by the staff of the Georgia Commission were also included in the stipulation, which authorized ~~Atlanta Gas Light~~a phased-in approach to ~~extend~~funding the ~~company’s pipeline facilities~~program 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 opportunities~~to $1.45 beginning in ~~Georgia. The i-CGP was approved as a three-year pilot program under STRIDE,~~January 2016 and will ~~be recovered~~continue 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 at~~In May 2011, the ~~beginning of each year. At~~New Jersey BPU approved Elizabethtown Gas’ request to spend an additional $40 million under this program before the end of 2012. Costs associated with the investment in this program are recovered through periodic adjustments to base rates that are approved by the ~~regulatory cost~~New 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 in~~of 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

6774

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

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

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

Investment Tax Credits Deferred investment tax credits associated with distribution operations are included as ~~an asset or~~ a regulatory liability onin our Consolidated Statements of Financial Position. ~~The guidance further requires that~~These investment tax credits are being amortized over the estimated lives of the related properties as credits to income tax expense.

Regulatory Income Tax Liability For our regulated utilities, we also measure ~~the plans’~~deferred income tax assets and ~~obligations that determine our funded status as~~liabilities using enacted income tax rates. Thus, when the statutory income tax rate declines before a temporary difference has fully reversed, the deferred income tax liability must be reduced to reflect the newly enacted income tax rates. However, the amount of the ~~end~~reduction is transferred to our regulatory income tax liability, which we are amortizing over the lives of the ~~fiscal year. We are also required to recognize~~related 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 to~~temporary differences reverse over approximately 30 years.

Other Regulatory Assets and Liabilities Our recoverable pension and ~~postretirement benefits. Our retirement and postretirement plans’ assets were accounted~~retiree welfare benefit plan costs for ~~at fair value and~~our utilities other than Nicor Gas are ~~classified in their entirety~~expected to be recovered through base rates over the next 2 to 21 years, based on the ~~lowest level~~remaining recovery periods as designated by the applicable state regulatory commissions. This category also includes recoverable seasonal rates, which reflect the difference between the recognition of ~~input that is significant~~a 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 Entities~~collection of the revenues over a seasonal pattern. These amounts are fully recoverable through base rates within one year.

~~We hold ownership interests~~In September 2013, Nicor Gas filed its second Energy Efficiency Plan, which outlines program offerings and therm reduction goals with spending of $93 million over the three-year period June 2014 through May 2017. Nicor Gas’ first Energy Efficiency Program is currently in ~~a number~~its 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 defined~~gas utility plans, Nicor Gas requested approval in the ~~authoritative accounting guidance. If a venture is a VIE~~same 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 January~~electric 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.

6875

Note ~~3 –~~4 - Fair Value Measurements

Retirement benefit plans

The ~~methods used to determine fair value~~allocations of the AGL Resources Inc. Retirement Plan (AGL Plan), the Employees’ Retirement Plan of NUI Corporation (NUI Plan), and the Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. (AGL Welfare Plan) were approximately 74% equity and 26% fixed income at December 31, 2013. The plans’ investment policies provide for some variation in these targets. The actual asset allocations of our ~~assets and liabilities~~retirement plans are ~~fully described within Note 2.~~

~~Derivative Financial Instruments~~

~~The~~presented in the following table ~~summarizes,~~ by ~~level~~Level 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 States~~U.S. common stocks.

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

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

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

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

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

(8)

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

~~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