UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2011
OR
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from           to
Commission File Number 1-14174
AGL RESOURCES INC.
(Exact name of registrant as specified in its charter)
Georgia	58-2210952
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
Ten Peachtree Place NE,	404-584-4000
Atlanta, Georgia 30309
(Address and zip code of principal executive offices)	(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Name of each exchange on which registered
Common Stock, $5 Par Value	New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 under the Securities Act.  Yes þ  No  ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Act. Yes ¨  No  þ
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days. Yes þ  No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company Large accelerated filer  þ                 Accelerated filer  ¨                 Non-accelerated filer ¨                 Smaller reporting company ¨
(Do not check if smaller reporting company) Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes ¨  No þ
The aggregate market value of the registrant’s voting and non-voting common equity held by non-affiliates of the registrant, computed by reference to the price at which the registrant’s common stock was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter, was $3,193,375,611.
The number of shares of the registrant’s common stock outstanding as of February 15, 2012 was 117,099,662.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Proxy Statement for the 2012 Annual Meeting of Shareholders (“Proxy Statement”) to be held May 1, 2012, are incorporated by reference in Part III.

TABLE OF CONTENTS

		Page(s)
Glossary of Key Terms		3
Forward-Looking Statements		4
Part I
Item 1.	Business	4 – 17
	Distribution Operations	5 – 10
	Retail Operations	10 – 12
	Wholesale Services	12 - 14
	Midstream Operations	14 – 15
	Cargo Shipping	15 – 16
	Other	16 –17
Item 1A.	Risk Factors	17 – 29
Item 1B.	Unresolved Staff Comments	29
Item 2.	Properties	29
Item 3.	Legal Proceedings	30
Item 4.	Mine Safety Disclosures	30
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	30 – 31
Item 6.	Selected Financial Data	31 – 32
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33 – 53
	Executive Summary	33 – 34
	Results of Operations	34 – 40
	Liquidity and Capital Resources	40 – 48
	Critical Accounting Policies and Estimates	48 – 53
	Accounting Developments	53
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	54 – 57
Item 8.	Financial Statements and Supplementary Data	58 – 108
	Report of Independent Registered Public Accounting Firm	58
	Management’s Report on Internal Control Over Financial Reporting	59
	Consolidated Statements of Financial Position	60 – 61
	Consolidated Statements of Income	62
	Consolidated Statements of Comprehensive Income	63
	Consolidated Statements of Equity	64
	Consolidated Statements of Cash Flows	65
	Note 1 – Organization and Basis of Presentation	66
	Note 2 – Significant Accounting Policies and Methods of Application	66 – 79
	Note 3 – Merger with Nicor	79 – 81
	Note 4 – Fair Value Measurements	81 – 83
	Note 5 – Derivative Instruments	83 – 85
	Note 6 – Employee Benefit Plans	86 – 89
	Note 7 – Stock-based and Other Incentive Compensation Plans and Agreements	90 – 93
	Note 8 – Debt	94 – 96
	Note 9 – Equity	97
	Note 10 – Non-Wholly-Owned Entities	98 – 99
	Note 11 – Commitments, Guarantees and Contingencies	100 – 104
	Note 12 – Income Taxes	104 – 105
	Note 13 – Segment Information	106 – 108
	Note 14 – Selected Quarterly Financial Data (Unaudited)	108
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	109
Item 9A.	Controls and Procedures	109
Item 9B.	Other Information	109
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	110
Item 11.	Executive Compensation	110
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	110
Item 13.	Certain Relationships and Related Transactions and Director Independence	111
Item 14.	Principal Accounting Fees and Services	111
Part IV
Item 15.	Exhibits, Financial Statement Schedules	111 – 120
Signatures		121
Schedule II		122

2

GLOSSARY OF KEY TERMS

AGL Capital	AGL Capital Corporation
AGL Credit Facility	$1.3 billion credit agreement entered into by AGL Capital to support the AGL Capital commercial paper program
Atlanta Gas Light	Atlanta Gas Light Company
Bcf	Billion cubic feet
Bridge Facility	Credit agreement entered into by AGL Capital Corporation to finance a portion of the Nicor merger
Central Valley	Central Valley Gas Storage, LLC
Chattanooga Gas	Chattanooga Gas Company
Chicago Hub	A venture of Nicor Gas, which provides natural gas storage and transmission-related services to marketers and gas distribution companies
California Commission	California Public Utilities Commission, the agency that regulates utilities in California
EBIT	Earnings before interest and taxes, a non-GAAP measure that includes operating income and other income and excludes financing costs, including interest on debt and income tax expense each of which we evaluate on a consolidated level. As an indicator of our operating performance, EBIT should not be considered an alternative to, or more meaningful than, earnings before income taxes, or net income attributable to AGL Resources Inc. as determined in accordance with GAAP
ERC	Environmental remediation costs associated with our distribution operations segment which are generally recoverable through rate mechanisms
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
Florida Commission	Florida Public Service Commission, the state regulatory agency for Florida City Gas
GAAP	Accounting principles generally accepted in the United States of America
Georgia Commission	Georgia Public Service Commission, the state regulatory agency for Atlanta Gas Light
Georgia Natural Gas	The name under which SouthStar does business in Georgia
Golden Triangle Storage	Golden Triangle Storage, Inc.
Hampton Roads	Virginia Natural Gas’ pipeline project which connects its northern and southern pipelines
Heating Degree Days	A measure of the effects of weather on our businesses, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
Heating Season	The period from November through March when natural gas usage and operating revenues are generally higher because weather is colder
Henry Hub	A major interconnection point of natural gas pipelines in Erath, Louisiana where NYMEX natural gas future contracts are priced
Horizon Pipeline	Horizon Pipeline Company, LLC
Illinois Commission	Illinois Commerce Commission, the state regulatory agency for Nicor Gas
Jefferson Island	Jefferson Island Storage & Hub, LLC
LIBOR	London Inter-Bank Offered Rate
LNG	Liquefied natural gas
LOCOM	Lower of weighted average cost or current market price
Magnolia	Magnolia Enterprise Holdings, Inc.
Marketers	Marketers selling retail natural gas in Georgia and certificated by the Georgia Commission
Merger Agreement	Agreement and Plan of Merger, dated December 6, 2010, as amended by and among the Company, Nicor, Apollo Acquisition  Corp, an Illinois corporation and wholly owned subsidiary of the Company and Ottawa Acquisition LLC, an Illinois Limited Liability Company and a wholly owned subsidiary of the Company
MGP	Manufactured gas plant
Moody’s	Moody’s Investors Service
New Jersey BPU	New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas
Nicor	Nicor Inc. - an acquisition completed in December 2011 and former holding company of Nicor Gas
Nicor Advanced Energy	Prairie Point Energy, LLC, doing business as Nicor Advanced Energy
Nicor Gas	Northern Illinois Gas Company, doing business as Nicor Gas Company
Nicor Gas Credit Facility	$700 million credit facility entered into by Nicor Gas to support its commercial paper program
Nicor Services	Nicor Energy Services Company
Nicor Solutions	Nicor Solutions, LLC
NUI	NUI Corporation – an acquisition completed in November 2004
NYMEX	New York Mercantile Exchange, Inc.
OCI	Other comprehensive income
Operating margin	A non-GAAP measure of income, calculated as operating revenues minus cost of goods sold, that excludes operation and maintenance expense, depreciation and amortization, taxes other than income taxes, and gains or losses on the sale of our assets; these items are included in our calculation of operating income as reflected in our Consolidated Statements of Income. Operating margin should not be considered an alternative to, or more meaningful than, operating income as determined in accordance with GAAP
OTC	Over-the-counter
Pad gas	Volumes of non-working natural gas used to maintain the operational integrity of the natural gas storage facility
PBR	Performance-based rate, a regulatory plan that provided economic incentives based on natural gas cost performance
PGA	Purchased Gas Adjustment
Piedmont	Piedmont Natural Gas Company, Inc.
Pivotal Utility	Pivotal Utility Holdings, Inc., doing business as Elizabethtown Gas, Elkton Gas and Florida City Gas
PP&E	Property, plant and equipment
S&P	Standard & Poor’s Ratings Services
Sawgrass Storage	Sawgrass Storage, LLC
SEC	Securities and Exchange Commission
Sequent	Sequent Energy Management, L.P.
Seven Seas	Seven Seas Insurance Company, Inc.
SNG	Substitute natural gas, a synthetic form of gas manufactured from coal
SouthStar	SouthStar Energy Services LLC
STRIDE	Atlanta Gas Light’s Strategic Infrastructure Development and Enhancement program
Tennessee Authority	Tennessee Regulatory Authority, the state regulatory agency for Chattanooga Gas
Term Loan Facility	$300 million credit agreement entered into by AGL Capital to repay the $300 million senior notes due in 2011
TEU	Twenty-foot equivalent unit, a measure of volume in containerized shipping equal to one 20-foot-long container
Triton	Triton Container Investments LLC, a cargo container leasing company in which we have an investment
Tropical Shipping	A wholly owned business and a carrier of containerized freight in the Bahamas and the Caribbean region
VaR	Value at risk is defined as the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability
Virginia Natural Gas	Virginia Natural Gas, Inc.
Virginia Commission	Virginia State Corporation Commission, the state regulatory agency for Virginia Natural Gas
WACOG	Weighted average cost of gas
WNA	Weather normalization adjustment

3

Forward-Looking Statements

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

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

Such events, risks and uncertainties include, but are not limited to, changes in price, supply and demand for natural gas and related products; the impact of changes in state and federal legislation and regulation including any changes related to climate change; actions taken by government agencies on rates and other matters; concentration of credit risk; utility and energy industry consolidation; the impact on cost and timeliness of construction projects by government and other approvals, development project delays, adequacy of supply of diversified vendors, unexpected change in project costs, including the cost of funds to finance these projects; limits on pipeline capacity; the impact of acquisitions and divestitures; our ability to integrate successfully operations that we have or may acquire or develop in the future, including those of Nicor, and realize cost savings and any other synergies related to any such integration, or the risk that any such integration could be more difficult, time-consuming or costly than expected;  uncertainty of our expected financial performance following the recent completion of the Nicor merger; disruption from the recent Nicor merger making it more difficult to maintain relationships with customers, employees or suppliers; direct or indirect effects on our business, financial condition or liquidity resulting from any change in our credit ratings resulting from the recent merger with Nicor or otherwise or any change in the credit ratings of our counterparties or competitors; interest rate fluctuations; financial market conditions, including recent disruptions in the capital markets and lending environment and the current economic downturn; and general economic conditions; uncertainties about environmental issues and the related impact of such issues; the impact of changes in weather, including climate change, on the temperature-sensitive portions of our business; the impact of natural disasters such as hurricanes on the supply and price of natural gas; acts of war or terrorism; the outcome of litigation; and other factors discussed elsewhere herein and in our filings with the SEC.

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

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

PART I

ITEM 1. BUSINESS

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

Merger with Nicor

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. We are now the nation’s largest natural gas distribution company based on customer count. In accordance with the Merger Agreement, each share of Nicor common stock outstanding at the Effective Time (as defined in the Merger Agreement), other than shares to be cancelled, and Dissenting Shares (as defined in the Merger Agreement), was converted into the right to receive consideration consisting of (i) $21.20 in cash and (ii) 0.8382 shares of AGL Resources common stock. Fractional shares were not issued in connection with the merger as Nicor shareholders who would have been entitled to receive a fraction of a share of AGL Resources common stock received cash settlements. Additionally, cash was paid to repurchase stock options and restricted stock units that were awarded for pre-merger services. The total purchase consideration of $2.5 billion paid to Nicor shareholders was primarily based on the number of Nicor shares outstanding on December 9, 2011, and the volume-weighted average price of AGL Resources common stock on December 8, 2011.

4

In connection with the Nicor merger, the headquarters of our distribution operations segment moved to Naperville, Illinois during December 2011 and we agreed not to initiate a rate proceeding that would increase our base rates effective prior to December 7, 2014. We have committed to maintain 2,070 full-time equivalent employees involved in the operation of Nicor Gas for a period of three years and maintain the personnel numbers in specific areas of safety oversight of the Nicor Gas system for a period of at least five years. Additionally, we are required to maintain the same level of corporate philanthropy within the communities that Nicor Gas serves.

See the following discussions for more information on the impacts of the Nicor merger on our business. Additionally, see the Executive Summary within Management’s Discussion and Analysis of Financial Condition and Results of Operations, as well as Note 3 to our consolidated financial statements under Item 8 herein, for additional information on the merger. During 2011, we recorded approximately $68 million ($55 million net of tax) of transaction expenses associated with the merger with Nicor. These costs are expensed as incurred. The effects of Nicor’s results of operations and financial condition on our 2011 results include activity from December 10, 2011 through December 31, 2011.

Nature of Our Business

We are an energy services holding company whose principal business is the distribution of natural gas in seven states - Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee and Maryland – through our seven natural gas distribution utilities, including, as a result of the Nicor merger, Nicor Gas. At December 31, 2011, our seven utilities served approximately 4.5 million end-use customers.

In addition to our primary business of the distribution of natural gas, we are involved in several related and complementary businesses. Our retail operations segment serves more than one million retail customers and markets natural gas and related home services to end-use customers in Georgia, Illinois, Ohio, Florida and New York. Our wholesale services segment provides natural gas storage arbitrage and related activities, natural gas asset management and related logistics activities for each of our utilities as well as for non-affiliated companies. Our midstream operations segment provides natural gas storage arbitrage and related activities and engages in the development and operation of high-deliverability natural gas storage assets.

As a result of the Nicor merger we are also involved in the shipping industry through our cargo shipping segment, which owns and operates Tropical Shipping, one of the largest containerized cargo carriers serving the Bahamas and the Caribbean.

In connection with the completion of the Nicor merger on December 9, 2011, we revised our operating segments to be the following five operating and reporting segments — distribution operations, retail operations, wholesale services, midstream operations, cargo shipping and one non-operating segment — other. These segments are consistent with how management views and manages our businesses. For additional information on our segments, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Results of Operations” and Note 13 to our consolidated financial statements under Item 8 herein.

Distribution Operations

Our distribution operations segment is the largest component of our business and includes seven natural gas local distribution utilities. These utilities construct, manage and maintain intrastate natural gas pipelines and distribution facilities and include:

Utility	State	Number of customers (in thousands)		Approximate miles of pipe
Nicor Gas (1)	Illinois		2,188		34,000
Atlanta Gas Light	Georgia		1,541		32,250
Virginia Natural Gas	Virginia		278		5,500
Elizabethtown Gas	New Jersey		276		3,150
Florida City Gas	Florida		103		3,450
Chattanooga Gas	Tennessee		62		1,600
Elkton Gas	Maryland		6		100
Total			4,454		80,050

(1)   Customers as of December 31, 2011.

The focus on the design of our distribution operations is the delivery of safe and reliable natural gas to our end-users. In integrating Nicor Gas into our existing distribution operations, we plan to focus on the standardization of operational processes along with continuing to focus on delivering superior customer service.

5

Competition and Customer Demand

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

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

·   changes in the availability or price of natural gas and other forms of energy

·   general economic conditions

·   energy conservation

·   legislation and regulations

·   the capability to convert from natural gas to alternative fuels

·   weather

·   new commercial construction and

·   new housing starts.

Over the last two years there has been some improvement in the economic conditions within the areas we serve. However, there continue to be high rates of unemployment and depressed housing markets with high inventories, significantly reduced new home construction and a slow-down in new commercial development. As a result, we have experienced slight customer losses in our distribution operations segment. Excluding Nicor Gas, our year-over-year consolidated utility customer gain rate was 0.1% in 2011, compared to a loss rate of (0.1)% for 2010. We anticipate overall competition and customer trends in 2012 to be similar to our 2011 results. For the full year 2011 the customer count of Nicor Gas increased by 0.4% compared to 0.2% for 2010.

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

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

We work with regulators and state agencies in each of our jurisdictions to educate customers throughout the year about energy costs in advance of the Heating Season, and to ensure that those customers qualifying for the Low Income Home Energy Assistance Program and other similar programs receive any needed assistance. We expect to continue this focus for the foreseeable future. We have also worked with the Virginia Commission, the Tennessee Authority and the New Jersey BPU to educate our customers about energy efficiency and conservation and to provide rebates and other incentives for the purchase of high-efficiency natural gas-fueled equipment. Additionally, we provide rebates and other incentives to our Nicor Gas customers through similar energy efficiency plans.

Sources of Natural Gas Supply

We purchase natural gas supplies in the open market by contracting with producers and marketers. We also purchase transportation and storage services from interstate pipelines that are regulated by the FERC. When firm pipeline services are temporarily not needed, we may release the services in the secondary market under FERC-approved capacity release provisions, with proceeds reducing the cost of natural gas charged to customers for most of our utilities. Peak-use requirements are met through utilization of company-owned storage facilities, pipeline transportation capacity, purchased storage services and other supply sources, arranged by either our transportation customers or us. We have been able to obtain sufficient supplies of natural gas to meet customer requirements. We believe natural gas supply and pipeline capacity will be sufficiently available to meet market demands in the foreseeable future.

6

Utility Regulation and Rate Design

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

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

·   distributing natural gas for Marketers

·   constructing, operating and maintaining the gas system infrastructure, including responding to customer service calls and leaks

·   reading meters and maintaining underlying customer premise information for Marketers

·   planning and contracting for capacity on interstate transportation and storage systems

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

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

All of our utilities, excluding Atlanta Gas Light, are authorized to use natural gas cost recovery mechanisms that allow them to adjust their rates to reflect changes in the wholesale cost of natural gas and to ensure they recover all of the costs prudently incurred in purchasing gas for their customers. Since Atlanta Gas Light does not sell natural gas directly to its end-use customers, it does not need or utilize a natural gas cost recovery mechanism. However, Atlanta Gas Light does maintain inventory for the Marketers in Georgia and recovers the cost of this gas through recovery mechanisms approved by the Georgia Commission.

In addition to natural gas recovery mechanisms, we have other cost recovery mechanisms, such as riders, which vary by utility but allow us to recover certain costs such as environmental remediation and energy efficiency plans.

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

7

The following table provides regulatory information for our six largest utilities.

	Nicor Gas			Atlanta Gas Light			Virginia Natural Gas			Elizabethtown Gas			Florida City Gas			Chattanooga Gas
Authorized return on rate base (1)		8.09	%		8.10	%		7.38	%		7.64	%		7.36	%		7.41	%
Estimated 2011 return on rate base (2)		N/A			8.33	%		8.15	%		8.84	%		5.74	%		8.43	%
Authorized return on equity (1)		10.17	%		10.75	%		10.00	%		10.30	%		11.25	%		10.05	%
Estimated 2011 return on equity (2)		N/A			11.20	%		11.97	%		12.81	%		8.53	%		12.24	%
Authorized rate base % of equity (1)		51.1	%		51.0	%		45.4	%		47.9	%		36.8	%		46.1	%
Rate base included in 2011 return on equity (in millions) (2)	$	1,485		$	1,317		$	516		$	476		$	163		$	92
Weather normalization (3)							ü			ü						ü
Decoupled or straight-fixed-variable rates (4)				ü												ü
Regulatory infrastructure program rates (5)				ü						ü
Bad debt rider (6)	ü
Synergy sharing policy (7)				ü
Last decision on change in rates (8)	Oct. 2009			Oct. 2010			Dec 2011			Dec. 2009				N/A		May 2010

(1)   The authorized return on rate base, return on equity, and percentage of equity were those authorized as of December 31, 2011.

(2)   Estimates based on principles consistent with utility ratemaking in each jurisdiction.

(3)   Involves regulatory mechanisms that allow us to recover our costs in the event of unseasonal weather, but are not direct offsets to the potential impacts of weather and customer consumption on earnings. These mechanisms are designed to help stabilize operating results by increasing base rate amounts charged to customers when weather is warmer than normal and decreasing amounts charged when weather is colder than normal.

(4)   Decoupled and straight-fixed-variable rate designs allow for the recovery of fixed customer service costs separately from assumed natural gas volumes used by our customers. The decoupled rate design for Virginia Natural Gas expired in December 2011.

(5)   Includes programs that update or expand our distribution systems and liquefied natural gas facilities.

(6)   Involves the recovery (or refund) of the amount of bad debt expense over (or under) an established benchmark expense.

(7)   Involves the recovery of 50% of net synergy savings achieved on future acquisitions.

(8) In connection with the Nicor merger, we agreed not to initiate a rate proceeding that would increase our base rates for Nicor Gas effective prior to December 9, 2014.

Recent Regulatory Actions

Nicor Gas In May 2011, the Illinois Commission approved an energy efficiency plan for Nicor Gas pursuant to an Illinois law that requires local gas distribution utilities to establish plans to achieve specified energy savings goals and provides utilities with a rider to collect the costs from customers. Under its approved plan, we estimate that Nicor Gas would bill approximately $155 million to customers under the rider, over a three year period which commenced June 1, 2011, to fund the costs of various energy savings programs identified in the filing. This new energy efficiency plan rider replaced the rider previously in effect. The costs under the rider are subject to annual review by the Illinois Commission.

On July 1, 2009, Nicor Gas filed a petition seeking re-approval from the Illinois Commission of the operating agreement that governs many inter-company transactions between Nicor Gas and its affiliates. The petition was filed pursuant to a requirement contained in the Illinois Commission order approving Nicor Gas’s most recent general rate increase and requested that the operating agreement be re-approved without change. A number of parties intervened in the proceeding (the “operating agreement proceeding”) and sought modifications on a prospective basis to the operating agreement. Among the proposals were several by the Illinois Commission Staff and intervenors that would preclude Nicor Gas from continuing to provide certain services to support warranty products that are sold by Nicor Services. Specifically, Nicor Services had used Nicor Gas personnel to assist in some sales solicitation for these warranty products. The Illinois Commission was required to evaluate future transactions between Nicor Gas and its affiliates in connection with the joint application of AGL Resources, Nicor and Nicor Gas for approval of the merger of AGL Resources and Nicor (the “merger proceeding”). The Illinois Commission Administrative Law Judge assigned to the merger proceeding decided to address the matters raised in the operating agreement proceeding in the merger proceeding. As a result, Nicor Gas is no longer permitted to use its call center personnel to solicit its affiliates’ products, most notably the warranty products. This is not expected to have a material impact on our results of operations, cash flows and financial condition.

On January 1, 2000, Nicor Gas instituted a PBR plan for natural gas costs. Under the PBR plan, Nicor Gas’ total gas supply costs were compared to a market-sensitive benchmark. Savings and losses relative to the benchmark were determined annually and shared equally with sales customers. The PBR plan was terminated effective January 1, 2003. The PBR plan is currently under review by the Illinois Commission as there are allegations that Nicor Gas acted improperly in connection with the PBR plan. In February 2012, we committed to a stipulated resolution of issues with the Illinois Commission, which includes crediting Nicor Gas customers $64 million, but does not constitute an admission of fault. The stipulated resolution is subject to review and approval by the Illinois Commission. The Citizens Utility Board and the Illinois Attorney General's Office are not parties to the stipulation resolution and continue to pursue their claims in this proceeding. Evidentiary hearings on this matter are scheduled to begin on February 28, 2012. We do not expect the stipulated resolution to affect our 2011 or 2012 Consolidated Statements of Income, as the $64 million proposed credit is consistent with the estimated liability we recorded for this matter as part of our accounting for the merger with Nicor. For more information on the PBR plan see Note 11 to our consolidated financial statements under Item 8 herein.

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On February 2, 2010, the Illinois Commission approved Nicor Gas’ previously filed bad debt rider. This rider provides for the recovery from (or credit to) Nicor Gas customers of the difference between Nicor Gas’ actual bad debt experience on an annual basis and the $63 million benchmark bad debt expense included in its base rates for the respective year. Costs incurred for bad debt expense are subject to annual review by the Illinois Commission.

Virginia Natural Gas On December 20, 2011, the Virginia Commission approved an annual increase of $11 million in base rate revenues and established an authorized return on equity of 10% for Virginia Natural Gas with an overall return on rate base set at 7.38%. Additionally, $3.1 million of costs previously recovered through base rates will now be recovered through the company’s gas cost recovery rate. Customer’s bills will be credited to refund the difference between the final approved rates and an interim rate increase, which began with usage on and after October 1, 2011. The new rate is expected to increase the average residential customer’s monthly bill by less than $3.50 per month depending on usage.

Environmental Remediation Costs

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. The following table provides more information on the costs related to remediation of our former MGP operating sites.

In millions	Cost estimate range (1)		Amount recorded		Expected costs over next twelve months
Illinois		$134 - $216	$	134	$	19
Georgia and Florida		42 – 98		58		7
New Jersey		124 – 174		124		9
North Carolina		10 - 16		11		2
Total		$310 - $504	$	327	$	37

(1)   Our ERC liabilities are customarily reported estimates of future remediation costs for our former operating sites that are contaminated based on probabilistic models of potential costs and on an undiscounted basis. However, we have not yet performed these probabilistic models for all of our sites in Illinois, which will be completed in 2012.

As we continue to conduct the actual remediation and enter into cleanup contracts, we are increasingly able to provide conventional engineering estimates of the likely costs of many elements of the remediation program. These estimates contain various engineering uncertainties, and we regularly attempt to refine and update these engineering estimates. These costs are primarily recovered through rate riders.

See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Estimates”, for additional information about our environmental remediation liabilities. Also see Note 11 to our consolidated financial statements under Item 8, “Financial Statements and Supplementary Data” for information on our environmental remediation efforts.

Capital Projects

We continue to focus on capital discipline and cost control, while moving ahead with projects and initiatives that we expect will have current and future benefits to us and our customers, provide an appropriate return on invested capital and ensure the safety, reliability and integrity of our utility infrastructure.The following table and discussions provide updates on some of our larger capital projects at our distribution operations segment. These programs update or expand our distribution systems to improve system reliability and meet operational flexibility and growth. Our anticipated expenditures for these programs in 2012 are discussed in ‘Liquidity and Capital Resources’ under the caption ‘Cash Flows from Financing Activities’.

Dollars in millions	Utility	Expenditures in 2011		Expenditures to date		Miles of pipe replaced		Year project began		Anticipated year of completion
Pipeline replacement program	Atlanta Gas Light	$	70	$	568		2,531		1998		2013
Integrated System Reinforcement Program	Atlanta Gas Light		89		141		n/a		2009		2012
Integrated Customer Growth Program	Atlanta Gas Light		7		12		n/a		2010		2012
Enhanced infrastructure program	Elizabethtown Gas		22		90		88		2009		2012
Total		$	188	$	811		2,619

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Atlanta Gas Light Our STRIDE program is comprised of the ongoing pipeline replacement program, the Integrated System Reinforcement Program (i-SRP), and Integrated Customer Growth Program (i-CGP). The purpose of the i-SRP program under STRIDE is to upgrade our distribution system and liquefied natural gas facilities in Georgia, improve our system reliability and operational flexibility, and create a platform to meet long-term forecasted growth. Our i-CGP authorizes Atlanta Gas Light to extend its pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia. Under STRIDE, we are required to file an updated ten-year forecast of infrastructure requirements under i-SRP along with a new construction plan every three years for review and approval by the Georgia Commission.

Virginia Natural Gas In January 2012 Virginia Natural Gas filed an accelerated infrastructure replacement program with the Virginia Commission. The program was filed pursuant to a Virginia statute that provides a regulatory cost recovery mechanism to recover the costs associated with certain infrastructure replacement programs. Our proposed program is for a five-year period and includes a maximum allowance for capital expenditure of $25 million per year, not to exceed $105 million in total over the five-year period. The Virginia Commission has six months to review and render a decision on this proposed program.

Elizabethtown Gas The New Jersey BPU-approved accelerated enhanced infrastructure program was created in response to the New Jersey Governor’s request for utilities to assist in the economic recovery by increasing infrastructure investments. On May 16, 2011, the New Jersey BPU approved Elizabethtown Gas’ request to spend an additional $40 million under this program before the end of 2012. Costs associated with the investment in this program are recovered through periodic adjustments to base rates. We expect to file for an extension of the program in 2012.

Asset Management Agreements

Some of our utilities have entered into asset management agreements with Sequent, our affiliate. These agreements are designed to efficiently manage storage and transportation assets belonging to our utilities, including the purchase and sale of natural gas as well as excess transportation and storage capacity that may not be needed on a daily basis to meet system requirements. The agreements have either annual minimum guarantees within a profit sharing structure, a profit sharing structure without any annual minimum guarantee, or a fixed fee. Under the various types of agreements, Sequent made payments of $32 million in 2011. Our utilities began entering into these agreements with Sequent in 2001. From 2001 through 2011 Sequent has made sharing payments under these agreements totaling $192 million, which has reduced customers’ bills at all of our utilities except Atlanta Gas Light. For Atlanta Gas Light these payments have been made to the Universal Service Fund controlled by the Georgia Commission and utilized for infrastructure improvements and to fund heating assistance programs. The following table provides payments made by Sequent to our utilities under these agreements during the last three years.

	Total amount received
In millions	2011		2010		2009		Expiration Date
Atlanta Gas Light	$	9	$	4	$	16	March 2012
Virginia Natural Gas		9		5		7	March 2016
Elizabethtown Gas		9		10		11	March 2014
Florida City Gas		2		1		1	March 2013
Chattanooga Gas		3		4		4	March 2014
Total	$	32	$	24	$	39

On March 30, 2011, the New Jersey BPU authorized the renewal of the asset management agreement between Elizabethtown Gas and Sequent. The renewed agreement requires Sequent to pay minimum annual fees of $5 million to Elizabethtown Gas and includes overall margin sharing levels of 70% to Elizabethtown Gas and 30% to Sequent. In October 2011, the Virginia Commission authorized the renewal of the asset management agreement between Virginia Natural Gas and Sequent. The minimum and overall sharing levels of the renewed agreement are consistent with the prior agreement.

Retail Operations

The companies in our retail operations segment market natural gas and related home services, such as appliance repair and line protection plans to customers primarily in our utility service areas, but also in areas outside of our utility service areas. This segment also offers products that provide product protection and comfort services and natural gas price risk and utility bill management services. These companies include SouthStar, Nicor Advanced Energy, Nicor Solutions and Nicor Services. Nicor Solutions, Nicor Services and Nicor Advanced Energy joined our business on December 9, 2011 as part of the Nicor merger and are wholly owned businesses.

Our retail operations businesses, including SouthStar, Nicor Advanced Energy and Nicor Solutions, generate earnings through the sale of natural gas to residential, commercial and industrial customers, primarily in Georgia and Illinois where we capture spreads between wholesale and retail natural gas prices. We also offer our customers energy-related products that provide for natural gas price stability and utility bill management. These products mitigate and/or eliminate the risks to customers of colder than normal weather and/or changes in natural gas prices. We charge a fee or premium for these services.

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We also collect monthly service fees and customer late payment fees. We evaluate the combination of these two retail price components to ensure such pricing is structured to cover related retail customer costs, such as bad debt expense, customer service and billing, and lost and unaccounted-for gas, and to provide a reasonable profit, as well as being competitive to attract new customers and maintain market share.

Through our commercial operations we optimize storage and transportation assets and effectively manage commodity risk, which enables our energy solutions businesses to maintain competitive retail prices and operating margin. Through hedging transactions, we manage exposures arising from changing commodity prices by using natural gas storage transactions to capture operating margin from natural gas pricing differences that occur over time.

SouthStar, a joint venture currently owned 85% by us and 15% by Piedmont, markets natural gas and related services to retail customers on an unregulated basis, primarily in Georgia under the trade name Georgia Natural Gas. SouthStar also serves retail customers in Ohio, Florida and New York. We have no contractual rights to acquire Piedmont’s remaining 15% ownership interests.

SouthStar is governed by an executive committee, which is comprised of six members, three representatives from AGL Resources and three representatives from Piedmont. Under the joint venture agreement, all significant management decisions require the unanimous approval of the SouthStar executive committee; accordingly, our 85% financial interest is considered to be noncontrolling. We record the earnings allocated to Piedmont as a noncontrolling interest in our Consolidated Statements of Income, and we record Piedmont’s portion of SouthStar’s capital as a noncontrolling interest in our Consolidated Statements of Financial Position.

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

Nicor Solutions offers its residential and small commercial customers, primarily in the Nicor Gas service territory, energy-related products that provide for natural gas price stability and utility bill management. These products mitigate and/or eliminate the risks to customers of colder than normal weather and/or changes in natural gas prices. Nicor Advanced Energy is certified by the Illinois Commission as an Alternate Gas Supplier, authorizing it to be a non-utility marketer of natural gas for residential and small commercial customers. Nicor Advanced Energy presently operates in northern Illinois, offering customers an alternative to the utility as its natural gas supplier.

Our retail operations businesses also provide warranty protection solutions to customers through Nicor Services. Such services include a gas line repair plan and a heating, ventilation, and air conditioning repair and maintenance plan, whereby we, in return for a predetermined monthly amount collected from customers, provide repair and maintenance per the contracted terms. In addition, we also provide customer move connection services for utilities. Our retail operations businesses primarily provide warranty protection solutions to customers in Illinois and Ohio under the Nicor National brand.

CompetitionOur retail operations business competes with other energy marketers to provide natural gas and related services to customers in Georgia, Illinois, Ohio, New York and the Southeast. In the Georgia market, SouthStar operates as Georgia Natural Gas and is the largest of eleven Marketers, with average customers of approximately 495,000 over the last three years and market share of approximately 33%.

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

In addition, similar to our natural gas utilities, our retail operations businesses face competition based on customer preferences for natural gas compared to other energy products, primarily electricity, and the comparative prices of those products. Natural gas price volatility in the wholesale natural gas commodity market has also contributed to an increase in competition for residential and commercial customers. We continue to use a variety of targeted marketing programs to attract new customers and to retain existing customers. In October 2011, Georgia Natural Gas was named the exclusive natural gas partner for the Delta Air Lines Inc. Delta SkyMiles Program in Georgia. This is a long-term partnership and we expect it will help retain current customers as well as attract new customers from other Marketers in Georgia.

Our retail operations businesses also experience price, convenience and service competition from other warranty and HVAC companies. These businesses also bear risk from potential changes in the regulatory environment. As a condition of the merger, Nicor Gas is no longer permitted to use its call center personnel to solicit its affiliates’ products, most notably the warranty products.

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Wholesale Services

Our wholesale services segment consists of our wholly owned subsidiaries Sequent, Nicor Enerchange and Compass Energy (Compass). Sequent is involved in asset management and optimization, storage, transportation, producer and peaking services and wholesale marketing of natural gas across the United States and in Canada. Nicor Enerchange, which was integrated into Sequent as part of the Nicor merger, expands Sequent’s wholesale marketing of natural gas supply services in the Midwest, enables Sequent to serve commercial and industrial customers in the Midwest primarily in the northern Illinois market area and manage Nicor Solutions’ and Nicor Advanced Energy’s product risks, including the purchase of natural gas supplies. Compass, which we acquired in 2007, provides natural gas supply and services to commercial, industrial and governmental customers primarily in Kentucky, Ohio, Pennsylvania, Virginia and West Virginia.

Wholesale services utilizes a portfolio of natural gas storage assets, contracted supply from all of the major producing regions, as well as contracted storage and transportation capacity across the Gulf Coast, Eastern, Midwestern and Western sections of the United States and Canada to provide these services to its customers, consisting primarily of electric and natural gas utilities, power generators and large industrial customers. Our logistical expertise enables us to provide our customers with natural gas from the major producing regions and market hubs in the United States and Canada and meet our delivery requirements and customer obligations at competitive prices by leveraging our portfolio of natural gas storage assets and contracted natural gas supply, transportation and storage capacity.

Wholesale services portfolio of storage and transportation capacity also enables us to generate additional operating margin by optimizing the contracted assets through the application of our wholesale market knowledge and risk management skills as the opportunities arise in the Gulf Coast, Eastern, Midwestern and Western sections of the United States and Canada. These asset optimization opportunities focus on capturing the value from idle or underutilized assets, typically by participating in transactions to take advantage of volatility in pricing differences between varying geographic locations and time horizons (location and seasonal spreads) within the natural gas supply, storage and transportation markets to generate earnings. We seek to mitigate the commodity price and volatility risks and protect our operating margin through a variety of risk management and economic hedging activities.

CompetitionWholesale services competes for asset management, long-term supply and seasonal peaking service contracts with other energy wholesalers, often through a competitive bidding process. We are able to price competitively by utilizing our portfolio of contracted storage and transportation assets and by renewing and adding new contracts at prevailing market rates. We will further continue to broaden our market presence in sections of the United States and Canada where our portfolio of contracted storage and transportation assets provided us a competitive advantage, as well as continue our pursuit of additional opportunities with power generation companies located in the areas of the country we operate. We are also focused on building our fee based services in part to have a source of operating margin that is less impacted by volatility in the marketplace.

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

Transportation TransactionsWe enter into contracts for natural gas transportation capacity and participate in transactions that manage the natural gas commodity and transportation costs in an attempt to achieve the lowest cost to serve our various markets. We seek to optimize this process on a daily basis as market conditions change by evaluating all the natural gas supplies, transportation alternatives and markets to which we have access and identifying the lowest-cost alternatives to serve our markets. This enables us to capture geographic pricing differences across these various markets as delivered natural gas prices change.

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

Producer ServicesOur producer services activities focus on aggregating natural gas supply primarily from various small and medium-sized producers located throughout the natural gas production areas of the United States. We provide producers with certain logistical and risk management services that offer them attractive options to move their supply into the pipeline grid.

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

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

Natural Gas Storage Inventory and TransactionsWe maintain natural gas storage balances for volumes associated with energy marketing activities, parked gas transactions and sales to wholesale and commercial and industrial customers and record these within natural gas stored underground inventory on our Consolidated Statement of Financial Position. Further and generally in connection with non-affiliated asset management transactions, our recorded natural gas stored underground inventory includes volumes of natural gas we manage for our customers by purchasing the natural gas inventory from and physically delivering volumes of natural gas back to our customers based on specific delivery dates. The cost at which we purchase the volumes of natural gas from our customers or WACOG is also the same price at which we sell the natural gas volumes to the customer. Consequently, we make no margin on the purchase and sale of the natural gas but make operating margin through our natural gas storage optimization activities of these volumes under management. As of December 31, 2011, we had $269 million of natural gas stored underground inventory within our Consolidated Statement of Financial Position, representing 78 Bcf at an overall WACOG of $3.44.

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

We view our trading margins from two perspectives. First, we base our commercial decisions on economic value, which is defined as the locked-in operating revenue to be realized at the time the physical gas is withdrawn from storage and sold and the derivative instrument used to economically hedge natural gas price risk on that physical storage is settled. Second is the GAAP reported value both in periods prior to and in the period of physical withdrawal and sale of inventory. The GAAP amount is affected by the process of accounting for the financial hedging instruments in interim periods at fair value between the period when the natural gas is injected into storage and when it is ultimately withdrawn and the derivative instruments are settled. The change in the fair value of the hedging instruments is recognized in earnings in the period of change and is recorded as unrealized gains or losses. The actual value, less any interim recognition of gains or losses on hedges and adjustments for LOCOM, is realized when the natural gas is delivered to its ultimate customer.

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

Volatility in the natural gas market arises from a number of factors such as weather fluctuations or changes in supply or demand for natural gas in different regions of the country. The volatility of natural gas commodity prices have a significant impact on our customer rates, our long-term competitive position against other energy sources and the ability of our wholesale services segment to capture value from location and seasonal spreads. During 2008 and 2009, daily Henry Hub spot market prices for natural gas in the United States were extremely volatile. However, during 2010 and 2011, the volatility of natural gas prices was significantly lower than it had been for several prior years. This is the result of a robust natural gas supply, the weak economy, mild hurricane seasons, mild weather and ample storage. Our natural gas acquisition strategy is designed to secure sufficient supplies of natural gas to meet the needs of our utility customers and to hedge gas prices to effectively manage costs, reduce price volatility and maintain a competitive advantage. Additionally, our hedging strategies and physical natural gas supplies in storage enable us to reduce earnings risk exposure due to higher gas costs.

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It is possible that natural gas prices will remain low for an extended period based on current levels of excess supply relative to market demand for natural gas, in part due to abundant sources of new shale natural gas reserves, particularly in the Marcellus Shale producing region where Sequent has natural gas receipt requirements, and the lack of demand growth by commercial and industrial enterprises. However, as economic conditions improve the demand for natural gas may increase, natural gas prices could rise and higher volatility could return to the natural gas markets. Consequently, we are working to reposition Sequent’s business model with respect to fixed costs and the types of contracts pursued and executed.

Sequent’s expected natural gas withdrawals from physical salt-dome and reservoir storage are presented in the following table along with the operating revenues expected at the time of withdrawal. Sequent’s expected operating revenues are net of the estimated impact of profit sharing under our asset management agreements and reflect the amounts that are realizable in future periods based on the inventory withdrawal schedule and forward natural gas prices at December 31, 2011 and 2010. A portion of Sequent’s storage inventory is economically hedged with futures contracts, which results in realization of a substantially fixed margin, timing notwithstanding.

			Expected
	Total storage (in Bcf)		operating revenues
Withdrawal schedule	(WACOG $2.98)		(in millions)
2012
First quarter		30	$	1
Second quarter		4		0
Third quarter		1		0
Fourth quarter		1		1
2013		1		1
Total at Dec. 31, 2011		37	$	3
Total at Dec. 31, 2010		28	$	16

If Sequent’s storage withdrawals associated with existing inventory positions are executed as planned, it expects operating revenues from storage withdrawals of approximately $2 million during the next twelve months and $1 million in 2013. This will change as Sequent adjusts its daily injection and withdrawal plans in response to changes in market conditions in future months and as forward NYMEX prices fluctuate. For more information on Sequent’s energy marketing and risk management activities, see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk.”

Midstream Operations

Our midstream operations segment includes a number of businesses that are related and complementary to our primary business. The most significant of these businesses is our natural gas storage business, which develops, acquires and operates high-deliverability underground natural gas storage assets primarily in the Gulf Coast region of the United States and in Northern California. While this business can also generate additional revenue during times of peak market demand for natural gas storage services, the majority of our natural gas storage facilities are covered under a portfolio of short, medium and long-term contracts at a fixed market rate. Golden Triangle Storage began full commercial operations during the first quarter of 2011. Central Valley, located in northern California, is expected to begin commercial operations in the first half of 2012. The following table shows the working gas capacity and subscription amounts by storage facility as of December 31, 2011.

			Working Gas Capacity		Subscribed (3)
In Bcf	State	Type	Current	Additional Amount Expected in 2012	Amount	%
Jefferson Island	Louisiana	Salt-dome	7.5	0.0	5.0	69%
Golden Triangle Storage (1)	Texas	Salt-dome	6.0	7.3	4.0	67%
Central Valley (2)	California	Depleted field	0.0	11.0	3.0	27%
Total			13.5	18.3	12.0

(1)   We expect the second cavern construction to be complete and firm storage services to commence in mid-2012.

(2)   We expect construction to be complete and firm storage services to commence in the first half of 2012.

(3)   The amount and percentage of capacity under subscription does not include 2 Bcf of capacity under contract at Jefferson Island and 2 Bcf of capacity under contract at Golden Triangle Storage by Sequent at December 31, 2011.

Jefferson Island This wholly owned subsidiary operates a salt-dome storage and hub facility, approximately eight miles from the Henry Hub. The storage facility is regulated by the Louisiana Department of Natural Resources and by the FERC, which has regulatory authority over storage and transportation services. Jefferson Island provides storage and hub services through its direct connection to the Henry Hub and its interconnections with eight pipelines in the area. The level of firm subscription has remained consistent over the last three years. We will hold an open season for 3 Bcf of subscribed capacity that expires in March 2012 and expect the subscription rate to be significantly lower than the current contract.

In December 2009, the Louisiana Mineral and Energy Board approved an operating agreement between Jefferson Island and the State of Louisiana. In June 2010, Jefferson Island filed a permit application with the Louisiana Department of Natural Resources to expand its natural gas storage facility through the addition of two caverns. We continue to seek approval to expand our storage facility; however, we cannot predict when or if this approval will be obtained. The caverns would expand the total working gas capacity at Jefferson Island to approximately 19.5 Bcf of working gas capacity.

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Golden Triangle StorageThis wholly owned subsidiary is designed for an initial 13.3 Bcf of working natural gas capacity. The storage facility is regulated by the FERC. Golden Triangle Storage owns an approximately nine-mile dual 24” natural gas pipeline to connect the storage facility with three interstate and three intrastate pipelines.

Cavern 1, with 6 Bcf of working capacity, began commercial service in September 2010. We expect Cavern 2 will now consist of 7.3 Bcf of working capacity. Our estimate to complete the second cavern, based on current prices for labor, materials and pad gas, is approximately $28 million. We spent approximately $11 million in capital expenditures for this project in 2011. The total estimated construction cost for Caverns 1 and 2 remains consistent with prior estimates.

At December 31, 2011, of the approximate 6 Bcf of working natural gas capacity available for subscription, Golden Triangle Storage had 4 Bcf of capacity subscribed with a third party and 2 Bcf under contract with Sequent through March 2016. Accordingly, Cavern 1 at Golden Triangle Storage has no remaining capacity available for subscription until March 2013. Cavern 2 is currently unsubscribed, and we will be seeking contracts of varying durations as the in-service date approaches.

Central Valley This wholly owned subsidiary, which joined our business as part of the Nicor merger, is developing an underground natural gas storage facility in the Sacramento River valley of north-central California. We are converting the depleted Princeton Gas Field into a high-deliverability, multi-cycle storage field. This will include the addition of a 14.9 mile 24-inch diameter gas pipeline connecting the facility to a major pipeline. The storage facility is regulated by the California Commission.

Sawgrass Storage Our 50% owned joint venture (held by Cypress Creek Gas Storage, LLC) with Mill Creek Gas Storage, LLC (an affiliate of Samson Contour Energy E&P, LLC), which joined our business as part of the Nicor merger, is engaged in developing an underground natural gas storage facility northwest of Monroe, Louisiana. In July 2011, Sawgrass Storage applied for a Certificate of Public Convenience and Necessity with the FERC to construct and operate the natural gas storage facility and expects to receive the certificate during 2012.

Horizon Pipeline Our 50% owned joint venture with Natural Gas Pipeline Company of America, Horizon Pipeline, which joined our business as part of the Nicor merger, operates an approximate 70 mile natural gas pipeline stretching from Joliet, Illinois to near the Wisconsin/Illinois border. Nicor Gas has contracted for approximately 80% of Horizon Pipeline’s total throughput capacity of 0.38 Bcf under an agreement expiring in 2015 at rates that have been accepted by the FERC.

CompetitionOur natural gas storage facilities primarily compete with natural gas facilities in the Gulf Coast region of the United States 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. Salt caverns have also been leached from bedded salt formations in the Northeastern and Midwestern states. Competition for our Central Valley storage facility will primarily consist of storage facilities in northern California and western North America. Storage values have declined over the past two years due to low gas prices and low volatility and we expect this to continue in 2012 and potentially longer.

Cargo Shipping

Our cargo shipping segment, which joined our business as part of the Nicor merger, consists of Tropical Shipping, multiple wholly owned foreign subsidiaries of Tropical Shipping that are treated as disregarded entities for United States income tax purposes, Seven Seas, a wholly owned domestic cargo insurance company and an equity investment in Triton, a cargo container leasing business.

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

Tropical Shipping’s southbound cargo consists mainly of building materials, food and other necessities for developers, distributors and residents in the Caribbean and the Bahamas, as well as tourist-related shipments intended for use by hotels, resorts, and cruise ships. Tropical Shipping’s interisland shipments consist primarily of consumer staples and northbound shipments primarily consist of apparel, rum and agricultural products.

On average, approximately 70% to 75% of Tropical Shipping’s total volumes shipped are in the southbound market, 15% - 20% interisland and 5% - 10% northbound. Tropical Shipping’s largest contract consists of a southbound shipment of goods from Canada destined mainly for Puerto Rico. Tropical Shipping measures volumes and capacity of vessels and containers in TEU’s. Details of Tropical Shipping’s properties are discussed in Item 2 “Properties” - “Vessels and shipping containers”.

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Tropical Shipping’s operations are structured to allow it to take advantage of certain provisions of the American Jobs Creation Act of 2004 that provide the opportunity for certain tax savings. Generally, to the extent foreign shipping earnings are not repatriated to the United States, such earnings are not expected to be subject to current taxation. In addition, to the extent such earnings are expected to be indefinitely reinvested offshore, no deferred income tax expense is recorded by the company. For more information on management’s indefinite reinvestment assertion, see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, under the caption “Liquidity and Capital Resources”. See also Note 2 and Note 12 to our consolidated financial statements under Item 8 herein.

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

Seven Seas is a Florida domestic insurance corporation that provides cargo insurance policies mainly between Tropical Shipping and its customers. Approximately 70% of Seven Seas’ revenues are generated from Tropical Shipping’s customers. The policies’ coverage is from the point when the cargo leaves the shipper’s possession to the point when the customer takes delivery.

CompetitionCargo shipping has five main competitors that serve the same major transportation areas. Over the past several years, Tropical Shipping has maintained an average market share of approximately 40% for the ports in which it serves. Tropical Shipping has significantly more market penetration for certain islands versus others. For example, currently it has 45% of the southbound market share for the Virgin Islands versus 20% for the Windward Islands. Tropical Shipping continuously reviews new market opportunities. However, the ability to capture additional market share is difficult due to competition.

OperationsTropical Shipping’s operating results are cyclical and very much aligned with the level of global gross domestic product, tourism and the cost of fuel. Overall, the Bahamas and the Virgin Island economies are highly dependent on tourism from the United States. Whereas, the Caribbean’s Windward and Leeward Island economies have more tourism from Europe. Fuel price volatility also impacts our earnings. Bunker surcharge rates are charged to customers and are used to mitigate the fluctuations in fuel transportation costs.

Tropical Shipping generates revenues primarily by three main services, which include Full Container Load (FCL) service, Less-than Container Load (LCL) service, and break bulk service which is cargo that cannot ship in a container. Tropical Shipping also generates revenues from handling “project cargo”, which provides a coordinated service for construction projects. Tropical Shipping’s FCL cargo service revenues typically consist of an empty container delivery to the customer’s site via truck or rail or coordinating a customer pick up at the Port. The customer fills and seals the container and either requests Tropical to pick it up or delivers it back to the Port. Tropical Shipping generates revenues from LCL services primarily by providing packaging and transporting services for smaller cargos or customers, including individuals, who may have a few items to ship.

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

Other

Our other segment primarily includes our nonoperating business units. AGL Services Company is a service company we established to provide certain centralized shared services to our operating segments. We allocate substantially all of AGL Services Company’s operating expenses and interest costs to our operating segments in accordance with state regulations. However, merger related costs are not allocated to our operating segments.

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

Employees

As of February 1, 2012, we had approximately 6,400 employees, 5,850 of whom were in the United States.

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The following table provides information about our natural gas utilities’ collective bargaining agreements, which represent approximately 26% of our total employees.

	# of Employees		Contract Expiration Date
Nicor Gas International Brotherhood of Electrical Workers (Local No. 19)		1,344	Feb-14
Virginia Natural Gas International Brotherhood of Electrical Workers (Local No. 50)		129	May-12
Elizabethtown Gas Utility Workers Union of America (Local No. 424)		168	Nov-12
Total		1,641

The collective bargaining agreements at Virginia Natural Gas and Elizabethtown Gas expire in 2012. We believe that we have a good working relationship with our unionized employees and there have been no work stoppages at Virginia Natural Gas or Elizabethtown Gas since we acquired those operations in 2000 and 2004, 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 the company and our employees. Our current collective bargaining agreements do not require our participation in multiemployer retirement plans and we have no obligation to contribute to any such plans.

Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and proxy statements, and amendments to those reports that we file with, or furnish to, the SEC are available free of charge 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

 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 2012 annual meeting of shareholders. We expect to file that Proxy Statement with the SEC on or about March 16, 2012, 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. RISK FACTORS

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 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 regulatory authorities in Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee and Maryland.

These authorities regulate many aspects of our operations, including construction and maintenance of facilities, 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 program and environmental remediation activities, relationships with our affiliates, 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 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.

In 2011, Illinois enacted laws that required Nicor Gas and other large gas utilities in Illinois to elect either to file rate cases with the Illinois Commission in 2012, 2014 and 2016 or sign contracts to purchase SNG to be produced from two coal gasification plants proposed to be constructed in Illinois. On September 30, 2011, Nicor Gas signed an agreement to purchase approximately 25 Bcf of SNG annually from one of the proposed facilities for a 10-year term beginning as early as 2015. For additional information on the substitute natural gas plant legislation. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” - “Contractual Obligations and Commitments”

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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 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 such as “swap,” “swap dealer” and “major swap participant.” This may require increased use of working capital for Nicor Gas, SouthStar and Sequent if the regulations increase our collateral requirements related to derivatives utilized to manage risk in these businesses.

We could incur significant compliance costs if we must 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.

Our business is 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 are subject to extensive environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. Such environmental legislation imposes, among other things, restrictions, liabilities and obligations associated with storage, transportation, treatment and disposal of hazardous substances 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.

In addition, claims against us under environmental laws and regulations could result in material costs and liabilities. Existing environmental regulations could also be revised or reinterpreted, 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. 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 not 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 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 systems to continue the expansion of our customer base and improve system reliability, especially during peak usage. We 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 construction may be affected by the cost of obtaining government and other approvals, development project delays, adequacy of supply of diversified vendors, 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 projected construction schedule and completion timeline of a project. Our cash flows may not be fully adequate to finance the cost of this 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 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.

Climate change is receiving ever increasing attention from scientists and legislators alike. The debate is ongoing as to the extent to which our climate is changing, the potential causes of this 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.

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Presently there are no federally mandated greenhouse gas reduction requirements in the United States. However, there are a number of legislative and regulatory proposals to address greenhouse gas emissions, which are in various phases of discussion or implementation. The outcome of federal and state actions to address global climate change could result in a variety of regulatory programs including potential new regulations, additional charges to fund energy efficiency activities, or other regulatory actions. These actions could:

·   result in increased costs associated with our operations

·   increase other costs to our business

·   affect the demand for natural gas, and

·   impact the prices we charge our customers.

Because natural gas is a fossil fuel with low carbon content, it is possible that future carbon constraints could create additional demand for natural gas, both for production of electricity and direct use in homes and businesses.

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 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 these events not fully covered by insurance could adversely affect our financial position and results of operations.

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 retail businesses is affected by the competition from other energy marketers providing retail natural gas services in our service territories, most notably 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 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.

Retail energy markets fixed-price contracts that protect customers against higher natural gas prices, or protect customers against both higher natural gas prices and colder weather. The sale of these fixed-price contracts may be adversely affected if natural gas prices are, or are perceived to be, low and stable.

Our retail services business 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, and in fact regulatory-change risk was incurred in late 2011. As a condition of the merger, Nicor Gas is no longer permitted to use its call center personnel to solicit its affiliates’ products, most notably the warranty products offered by Nicor Services.

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 United States 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, will primarily consist of storage facilities in Northern California and western North America. Storage values have declined over the past two years due to low gas prices and low volatility and we expect this to continue in 2012.

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Our cargo shipping segment competes with international maritime companies. The current expansion of the Panama Canal, which is expected to be completed in 2014, 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 to 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. Primarily as a result of the current economic downturn there is increased pricing pressure and decreased shipping volumes for the islands that Tropical Shipping currently serves. Over the past several years Tropical Shipping has maintained an average market share of approximately 40% for the ports it serves. However, 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 in the United States economy, along with increased mortgage defaults, and significant decreases in new home construction, home values and investment assets, has adversely impacted 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 downturn. As a result, our customers may 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.

Tropical Shipping’s business consists primarily of the shipment of building materials, food and other necessities from the United States 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 and 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 United States, 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 United States and Canada, could significantly affect Tropical Shipping’s results of operations, cash flows and financial condition.

An adverse decision in the proceeding concerning Nicor Gas’ PBR plan could result in an obligation to credit additional amounts to customers which could adversely affect our results of operations, cash flows and financial condition.

On January 1, 2000, Nicor Gas instituted a PBR plan for natural gas costs. Under the PBR plan, Nicor Gas’ total gas supply costs were compared to a market-sensitive benchmark. Savings and losses relative to the benchmark were determined annually and shared equally with sales customers. There are allegations that Nicor Gas acted improperly in connection with the PBR plan, and the Illinois Commission is reviewing these allegations in a pending proceeding. In October 2011, rebuttal testimony was submitted requesting refunds of $85 million by Staff of the Illinois Commission, $255 million by the Illinois Attorney General’s Office and $305 million by the Citizens Utility Board. An adverse decision in this proceeding could result in a credit to ratepayers or other obligations which could adversely affect our business, results of operations, and financial condition.

In February 2012, we committed to a stipulated resolution of certain issues with the staff of the Illinois Commission, which includes crediting Nicor Gas customers $64 million, but does not constitute an admission of fault. The stipulated resolution is subject to review and approval by the Illinois Commission. The Citizens Utility Board and the Illinois Attorney General's Office are not parties to this stipulated resolution and continue to pursue their claims in this proceeding. Evidentiary hearings on this matter are scheduled to begin on February 28, 2012. We do not expect the stipulated resolution to affect our 2011 or 2012 Consolidated Statements of Income, as the $64 million proposed credit is consistent with the estimated liability we recorded for this matter as part of our accounting for the merger with Nicor. See Note 11 to the consolidated financial statements under Item 8 herein, for additional information regarding the PBR plan.

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A significant portion of our accounts receivable is subject to collection risks, due in part to a concentration of credit risk at Nicor Gas in Illinois, Atlanta Gas Light and SouthStar in Georgia 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. Approximately 60% of Sequent’s credit exposure 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.

We have accounts receivable collection risks in Georgia due to a concentration of credit risks related to the provision of natural gas services to Marketers. At December 31, 2011, Atlanta Gas Light provided services to eleven certificated and active Marketers in Georgia, four of which (based on customer count and including SouthStar) accounted for approximately 30%of our consolidated operating margin for 2011. 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 pay 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.

The asset management arrangements between Sequent and our local distribution companies, and between Sequent and its nonaffiliated 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, Virginia Natural Gas, Elizabethtown Gas, Florida City Gas, Chattanooga Gas, and Elkton Gas and shares profits it earns from the management of those assets with those customers and their respective customers, with the exception of Chattanooga Gas and Elkton Gas where Sequent is assessed annual fixed-fees. Entry into and renewal of these agreements are subject to regulatory approval. The agreement for Atlanta Gas Light is subject to renewal in March 2012. Additionally, the agreement with Florida City Gas expires in March 2013 and the agreements with Chattanooga Gas and Elizabethtown Gas expire in March 2014.

Sequent also has asset management agreements with certain nonaffiliated customers. Sequent’s results could be significantly impacted if these agreements are not renewed or are amended or renewed with less favorable terms.

We are exposed to market risk and may incur losses in wholesale services, midstream operations and retail 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 and employing a 1-day holding period for all positions, our portfolio of positions as of December 31, 2011 had a VaR of $2.2 million at wholesale services and less than $0.1 million at retail operations.

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 75% of the usage and revenues occur from October through March. Fluctuations in weather 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 impacts Nicor Gas’ margin, net of income taxes, by approximately $1 million under its current rate structure.

We have a WNA mechanism for Virginia Natural Gas, Elizabethtown Gas and Chattanooga Gas that partially offsets the impact of unusually cold or warm weather on residential and commercial customer billings and 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%.

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These WNA regulatory mechanisms are most effective in a reasonable temperature range relative to normal weather using historical averages. The protection afforded by the WNA depends on continued regulatory approval. The loss of this continued regulatory approval could make us more susceptible to weather-related earnings fluctuations.

Changes in weather conditions 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 has been significantly lower than it has been for several prior years 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 reduce 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.

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 affect to our results of operations, cash flows and financial condition.

A decrease in the availability of adequate pipeline transportation capacity 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.

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

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

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

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

We have confirmed eleven sites in Georgia and three in Florida where Atlanta Gas Light, or its predecessors, own all or part of an MGP site. We are required to investigate possible environmental contamination at those MGP sites and, if necessary, cleanup any contamination. As of December 31, 2011, 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, 2011, projected costs associated with the MGP sites associated with Atlanta Gas Light range from $42 million to $98 million. For elements of the MGP program where we still cannot provide engineering cost estimates, considerable variability remains in future cost estimates.

We have identified 26 sites in Illinois for which we may have some responsibility. Nicor Gas and Commonwealth Edison Company are parties to an agreement to cooperate in cleaning up residue at many of these sites. The agreement allocates to Nicor Gas 51.73% of cleanup costs for 23 sites, no portion of the cleanup costs for 14 other sites and 50% of general remediation program costs that do not relate exclusively to particular sites. In addition to the agreement with Commonwealth Edison Company there are 3 sites in which we have sole responsibility. Information regarding preliminary site reviews has been presented to the Illinois Environmental Protection Agency for certain sites.  The results of the detailed site-by-site investigations will determine the extent additional remediation is necessary and provide a basis for estimating additional future costs. Our ERC liabilities are customarily reported estimates of future remediation costs for our former operating sites that are contaminated based on our probabilistic models of potential costs and on an undiscounted basis.  However, we have not performed these probabilistic models for all of our sites. Based on the estimates we have performed the Illinois sites cleanup cost estimates range from $134 to $216 million. In accordance with Illinois Commission authorization, we have been recovering, and expect to continue to recover, these costs from our customers, subject to annual prudence reviews.

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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 $124 million to $174 million. Costs have been estimated for one site in North Carolina and range from $10 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 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 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 2012.

Finally, higher costs of natural gas can cause our utility customers to conserve their use of our gas services or switch to other competing products. Higher natural gas costs 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 equipment to equipment fueled by other energy sources. However, natural gas prices are expected to remain low and may continue to be lower than they have been historically as a result of a robust natural gas supply, the weak economy and ample storage.

The cost of providing retirement plan benefits to eligible employees and qualified retirees is subject to changes in pension fund values and changes in liabilities as a result of updated demographics and assumptions. These changes may have a material adverse effect on our financial results.

Nicor Gas maintains a noncontributory defined benefit pension plan for substantially all of its employees hired prior to 1998 and a retiree health care plan for the benefit of substantially all of its employees (Nicor Gas retirees make contributions to their health care plan. AGL Resources maintains a noncontributory defined benefit pension plan and retiree health care plan for its pre-Nicor merger full-time employees and qualified retirees. Further note that the AGL retiree health care plan only includes medical coverage for eligible AGL Resources employees who were employed as of June 30, 2002, if they reach retirement age while working for us; additionally the pre-65 retirees make contributions to their health care plan. Effective January 1, 2012, the AGL Retirement Plan was frozen with respect to participation for non-union employees hired on or after that date. Such employees will be entitled to employer provided benefits under their defined contribution plan, that exceed defined contribution benefits for employees who participate in the defined benefit plan. The cost of providing these 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. In these circumstances, we may be required to recognize an increased pension expense or a charge to our other comprehensive income to the extent that the pension fund values are 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 AGL plans, we would be required to make a minimum contribution to these plans of approximately $36 million in 2012. We may make additional contributions in 2012 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, 2011 our pension plans assets represented 78% of our total pension plan obligations.

For more information regarding some of these obligations, see Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" under the caption "Contractual Obligations and Commitments" and the subheading “Retirement Plan Obligations” and Note 6 to the consolidated financial statements under Item 8 herein.

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

Natural disasters may damage our assets. The threat of terrorism and the impact of retaliatory military and other action by the United States 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, 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. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms.

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, 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 ourresults 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 the 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 United States 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 recent legislative and regulatory initiatives, 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.

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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 involving anti-bribery and anti-corruption. The Foreign Corrupt Practices Act (“FCPA”) generally prohibits United States companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or maintaining business or obtaining an improper business benefit. Although our policies require compliance with these laws, we may be held liable for actions taken by our strategic or local partners in foreign jurisdictions, even though these partners may not be subject to the FCPA. 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.

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

·   adverse general capital market conditions

·   poor performance and health of the utility industry in general

·   bankruptcy or financial distress of unrelated energy companies or Marketers

·   significant decrease in the demand for natural gas

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

·   terrorist attacks on our facilities or our suppliers or

·   extreme weather conditions.

During 2011, our issuances of new debt along with our commercial paper borrowings were primarily used to fund the merger with Nicor, capital expenditures and purchase natural gas inventories for the 2011 / 2012 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 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.

The AGL Credit Facility and the 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 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, or may require us to provide additional collateral to certain counterparties.

Our senior 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 be required to provide additional support for certain customers. In December 2010, after we announced the proposed merger with Nicor, S&P lowered our outlook from stable to negative watch. In December 2011, related to our merger with Nicor, our credit ratings were graded as follows:

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·   Moody’s affirmed the senior unsecured and short-term ratings of the legacy subsidiaries of AGL Resources. Moody’s withdrew the short-term rating of Nicor and downgraded the long-term and short-term ratings of Nicor Gas (long-term to A3, from A2, and short-term to P-2 from P-1). Moody's affirmed the Stable outlook for all of our entities.

·   S&P affirmed its rating of AGL Capital (BBB+), while lowering the corporate credit ratings on AGL Resources and its subsidiaries (Atlanta Gas Light and Nicor Gas). The corporate credit rating of AGL Resources and Atlanta Gas Light was downgraded from A- to BBB+ while the corporate credit rating of Nicor Gas was downgraded from AA to BBB+. S&P indicated the downgrade primarily stems from our increased financial leverage resulting from the Nicor merger. S&P rated both the AGL Capital and Nicor Gas commercial paper programs at A-2. As a result of these actions, S&P removed the Negative Watch and noted the outlook is now Stable.

·   Fitch affirmed its ratings on AGL Resources and its subsidiaries (A-) and Nicor Gas (A), with a Stable outlook. Fitch noted that our consolidated financial profile is pressured, and that with the addition of acquisition-related debt, our consolidated credit metrics are weak for the ratings category. Fitch indicated that long-term ratings stability will depend on reduction in leverage through successful integration and the realization of operating synergies.

As of December 31, 2011, if our credit rating had fallen below investment grade, we would have been required to provide collateral of approximately $48 million to continue conducting business with certain counterparties.

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.” We cannot ensure that we will be successful in structuring such swap agreements to manage 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-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 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 cash in the form of dividends or other distributions from our subsidiaries to meet our cash requirements. The ability of our subsidiaries to pay dividends and make other distributions is subject to applicable state law. 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.

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, including futures, 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 the absence of actively quoted market prices and pricing information from external sources, the valuation of these derivative 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.

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

The AGL Credit Facility and 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 other of our debt agreements, obligated in such instance to satisfy a large portion of our outstanding indebtedness and unable to satisfy all our outstanding obligations simultaneously.

Changes in taxation could adversely affect our results of operations, cash flows and financial condition.

Various tax and fee increases may occur in locations in which we operate. For example, the Illinois corporate income tax rate was increased effective January 1, 2011. 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.

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We are involved in legal or administrative proceedings before various courts and governmental bodies that could adversely affect our results of operations, cash flows and financial condition.

We are involved in legal or administrative proceedings before various courts and governmental bodies with respect to general claims, rates, taxes, environmental issues, billing, credit and collection matters, intersegment services, gas cost prudence reviews and other matters. Adverse decisions regarding these matters, to the extent they require us to make payments in excess of amounts provided for in our financial statements, could adversely affect our results of operations, cash flows and financial condition.

Risks Related to Our Merger with Nicor

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 prior to the merger.

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 affecting the results of our operations prior to the merger.

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 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.

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:

·   the ability to combine certain of our 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 will present significant challenges that may result in a decline in the anticipated potential benefits of the merger.

The difficulties of combining operations include:

·   combining the best practices, including utility operations, non-regulated energy marketing operations and staff functions

·   the necessity of 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 our operations could have an adverse effect on our business, results of operations, financial condition or prospects of the combined company after the merger.

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

We continue to incur restructuring and integration costs in connection with the merger. We are assessing the magnitude of these costs and additional unanticipated costs may be incurred as we continue the integration of the businesses. The costs related to restructuring are expensed as a cost of the ongoing results of operations of 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 achieved in the near term, or at all.

The combined company recorded goodwill and intangible assets that could become impaired and adversely affect the combined company’s operating results.

We accounted for the merger as a purchase in accordance with GAAP. Under the purchase method of accounting, the assets and liabilities of Nicor were recorded, as of the date 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 reflect Nicor balances and results after completion of the merger, but do not restate retroactively to reflect the historical financial position or results of operations of Nicor for periods prior to the merger. The earnings of the combined company reflect purchase accounting adjustments.

Under the purchase method of accounting, the total purchase price was allocated to Nicor’s tangible assets and liabilities and identifiable intangible assets based on their fair values as of the date of the merger. Identifiable intangible assets of $103 million were recorded. The fair value of Nicor’s assets and liabilities subject to the rate setting practices of their regulators approximate their carrying value. The excess of the purchase price over identifiable fair values was recorded as goodwill in the amount of approximately $1.4 billion. To the extent the value of goodwill or intangibles becomes impaired, the combined company may be required to incur impairment charges that could have a material impact on the combined company’s operating results.

Our indebtedness following the merger is higher than our previous 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 assumed Nicor’s outstanding debt and incurred additional debt to pay the cash portion of the merger consideration and transactions expenses. Our total indebtedness as of December 31, 2011 was approximately $4.9 billion (including approximately $1.3 billion of short-term borrowings and approximately $3.6 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 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

·   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 remained outstanding after the merger; but there can be no assurance that we will be able to repay or refinance such borrowings and obligations.

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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. 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 upon a number of factors, including market conditions and forecasts at the time those decisions are made.

ITEM 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. 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 mains

Our distribution systems transport natural gas from our pipeline suppliers to our customers in our service areas. At December 31, 2011, our distribution operations segment owned approximately 80,000 miles of underground distribution and transmission mains. The 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. In addition to the facilities we own, we have about 40 Bcf of purchased storage services under contracts with Natural Gas Pipeline Company of America that expire in 2013. 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 Bcf of LNG storage capacity in five LNG plants located in Georgia, New Jersey and Tennessee. In addition, we own two propane storage facilities in Virginia that have a combined storage capacity of approximately 0.5 Bcf. The LNG plants and propane storage facilities are used by our distribution operations segment to supplement natural gas supply during peak usage periods.

Midstream Operations We currently own three high-deliverability natural gas storage and hub facilities which are operated by our midstream operations segment. Jefferson Island operates a salt-dome storage facility in Louisiana currently consisting of two salt dome gas storage caverns with approximately 10 Bcf of total capacity and about 7.2 Bcf of working gas capacity. Golden Triangle Storage operates a salt-dome storage facility in Texas designed for approximately 13.3 Bcf of working natural gas capacity and total cavern capacity of 20 Bcf. Cavern 1, with 6 Bcf of working capacity, was completed and began commercial service in September 2010. Cavern 2, with an expected 7.3 Bcf of working capacity, is expected to be placed into commercial service in mid-2012. Central Valley is developing an underground natural gas storage facility in California with an expected 11 Bcf of working natural gas capacity and is expected to be placed into commercial service in mid-2012.

Vessels and shipping containers

Our cargo shipping segment operates 12 owned vessels and 2 chartered vessels with a container capacity totaling approximately 5,500 TEUs. The owned vessels range in age from 1 – 35 years, and vary in length from 249 – 491 feet. In addition to the vessels, the company owns and/or leases containers, freight-handling equipment, chassis and other equipment.

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.

ITEM 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.

For more information regarding some of these proceedings, see Note 11 to our consolidated financial statements under Item 8 herein under the caption “Litigation”.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR 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. On December 16, 2011, our ticker symbol changed from AGL to GAS. At January 31, 2012, there were 17,770 record holders of our common stock, which represents an increase of approximately 8,500 from the same period in 2011. The increase in the number of record holders and the change in our ticker symbol were primarily the result of the completion of our merger with Nicor on December 9, 2011. Quarterly information concerning our high and low stock prices and cash dividends paid in 2011 and 2010 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, 2011	$	39.91	$	35.65	$	0.45	March 31, 2010	$	38.83	$	34.26	$	0.44
June 30, 2011		42.34		38.58		0.45	June 30, 2010		40.08		34.72		0.44
September 30, 2011		42.40		34.08		0.45	September 30, 2010		40.00		35.29		0.44
December 31, 2011 (1)		43.69		37.95		0.55	December 31, 2010		39.66		34.21		0.44
					$	1.90						$	1.76

(1)   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, accruing from November 19, 2011. For presentation purposes the amount in the table was rounded to $0.10.

We have historically paid dividends to common shareholders four times a year: March 1, June 1, September 1 and December 1. We have paid 256 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 our ability to satisfy our obligations under certain financing agreements, including debt-to-capitalization covenants.

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.

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Issuer Purchases of Equity Securities

There were no purchases of our common stock by us and any affiliated purchasers during the three months ended December 31, 2011, as set forth in the following table. 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.

Period	Total number of shares purchased (1)		Average price paid per common share		Total number of shares purchased as part of publicly announced plans or programs		Maximum number of shares that may yet be purchased under the publicly announced plans or programs
October 2011		0	$	0		0		0
November 2011		0		0		0		0
December 2011		0		0		0		0
Total fourth quarter		0	$	0		0		0

(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 did not purchase any shares for such purposes in the fourth quarter of 2011. As of December 31, 2011, we had purchased a total 383,591 of the 600,000 shares authorized for purchase, leaving 216,409 shares available for purchase under this program.

ITEM 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 2010 to 2011 are primarily due to the Nicor merger on December 9, 2011.  See Note 3 to our consolidated financial statements under Item 8 herein for additional merger related information.

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Dollars and shares in millions, except per share amounts	2011 (1)			2010			2009			2008			2007
Income statement data
Operating revenues	$	2,338		$	2,373		$	2,317		$	2,800		$	2,494
Operating expenses
Cost of goods sold		1,097			1,164			1,142			1,654			1,369
Operation and maintenance (2)		490			497			497			472			451
Depreciation and amortization		186			160			158			152			144
Nicor merger expenses (2)		68			6			0			0			0
Taxes other than income taxes		57			46			44			44			41
Total operating expenses		1,898			1,873			1,841			2,322			2,005
Operating income		440			500			476			478			489
Other income (expense)		7			(1	)		9			6			4
Earnings before interest and taxes (EBIT) (3)		447			499			485			484			493
Interest expenses		136			109			101			115			125
Earnings before income taxes		311			390			384			369			368
Income taxes		125			140			135			132			127
Net income		186			250			249			237			241
Less net income attributable to the noncontrolling interest		14			16			27			20			30
Net income attributable to AGL Resources Inc.	$	172		$	234		$	222		$	217		$	211
Common stock data
Weighted average common shares outstanding basic		80.4			77.4			76.8			76.3			77.1
Weighted average common shares outstanding diluted		80.9			77.8			77.1			76.6			77.4
Total shares outstanding (4)		117.0			78.0			77.5			76.9			76.4
Basic earnings per common share attributable to AGL Resources Inc. common shareholders	$	2.14		$	3.02		$	2.89		$	2.85		$	2.74
Diluted earnings per common share – attributable to AGL Resources Inc. common shareholders	$	2.12		$	3.00		$	2.88		$	2.84		$	2.72
Dividends declared per common share (5)	$	1.90		$	1.76		$	1.72		$	1.68		$	1.64
Dividend payout ratio		89	%		58	%		60	%		59	%		60	%
Dividend yield (6)		4.5	%		4.9	%		4.7	%		5.4	%		4.4	%
Price range:
High	$	43.69		$	40.08		$	37.52		$	39.13		$	44.67
Low	$	34.08		$	34.21		$	24.02		$	24.02		$	35.24
Close (4)	$	42.26		$	35.85		$	36.47		$	31.35		$	37.64
Market value (4)	$	4,946		$	2,800		$	2,826		$	2,411		$	2,876
Statements of Financial Position data (4)
Total assets	$	13,913		$	7,520		$	7,079		$	6,710		$	6,258
Property, plant and equipment – net		7,900			4,405			4,146			3,816			3,566
Short-term debt		1,338			1,033			602			866			580
Long-term debt		3,561			1,671			1,974			1,675			1,675
Total debt		4,899			2,704			2,576			2,541			2,255
Total equity		3,339			1,836			1,819			1,684			1,708
Cash flow data
Net cash flow provided by operating activities	$	451		$	526		$	592		$	227		$	377
Net cash flow used in investing activities		(1,339	)		(442	)		(476	)		(372	)		(253	)
Net cash flow (used in) provided by financing activities		933			(86	)		(106	)		142			(122	)
Net borrowings and (payments) of short-term debt		91			131			(264	)		286			52
Financial ratios (4)
Debt		59	%		60	%		59	%		60	%		57	%
Equity		41	%		40	%		41	%		40	%		43	%
Total		100	%		100	%		100	%		100	%		100	%
Return on average equity		6.6	%		12.8	%		12.7	%		12.8	%		12.6	%

(1)   Material changes from 2010 to 2011 are primarily due to the Nicor merger on December 9, 2011. The year ending December 31, 2011 includes only 22 days of Nicor activity from December 10, 2011 through December 31, 2011. See Note 3 for additional merger related information.

(2)   Transaction expenses associated with the Nicor merger were excluded from operation and maintenance expenses.

(3)   This is a non-GAAP measurement. A reconciliation of 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.”

(4)   As of the last day of the fiscal period.

(5)   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, accruing from November 19, 2011. For presentation purposes the amount in the table was rounded to $0.10.

(6)   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.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Executive Summary

Merger with Nicor On December 9, 2011, we closed the merger with Nicor. We are now the nation’s largest natural gas-only distribution company based on customer count. The merger created a combined company with increased scale and scope in both regulated utility and non-regulated businesses as indicated below:

·   Seven regulated natural gas distribution companies providing natural gas services to approximately 4.5 million customers in Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee and Maryland

·   Over 1 million retail customers in the unregulated businesses

·   Physical wholesale gas business delivering approximately 5.2 Bcf of natural gas per day

·   Natural gas storage facilities that are expected to provide approximately 31.8 Bcf of working gas storage capacity in 2012

As a result of our merger with Nicor some of our businesses have been reclassified to different segments. See Note 13 to our consolidated financial statements under Item 8 herein for additional segment information including recasted prior period information. The following table provides more information on our segments.

	EBIT (2)									Assets (3)									Capital Expenditures (2)
	2011			2010			2009			2011			2010			2009			2011			2010			2009
Distribution operations		80	%		70	%		67	%		79	%		73	%		74	%		85	%		70	%		74	%
Retail operations		18			21			22			4			3			4			1			1			1
Wholesale services		1			10			10			9			18			16			0			0			0
Midstream operations		2			1			1			4			6			5			8			25			23
Cargo shipping		0			n/a			n/a			5			n/a			n/a			0			n/a			n/a
Other (1)		(1	)		(2	)		0			(1	)		0			1			6			4			2
Total		100	%		100	%		100	%		100	%		100	%		100	%		100	%		100	%		100	%

(1)   The 2011 results exclude the effects of the $68 million of merger expenses which were reported within our other segment.

(2)   The year ending December 31, 2011 only includes 22 days of Nicor activity from December 10, 2011 through December 31, 2011.

(3)   The 2011 amounts include Nicor assets as of December 31, 2011.

Over the last three years, on average, we have derived 72% 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.

The increased impact of the rate-regulated distribution operations segment on our overall business is expected to reduce our exposure to market fluctuations.

For additional information on the Nicor merger see Item 1- Business as well as Note 3 to our consolidated financial statements under Item 8 herein.

Legislative and regulatory updateWe 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 proposals 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.

On December 20, 2011, the Virginia Commission approved an annual increase of $11 million in base rate revenues and established an authorized return on equity of 10% for Virginia Natural Gas with an overall return on rate base set at 7.38%. Additionally, $3.1 million of costs previously recovered through base rates will now be recovered through the company’s gas cost recovery rate. Customer’s bills will be credited to refund the difference between the final approved rates and interim rate increase, which began with usage on and after October 1, 2011. The new rate is expected to increase the average residential customer’s monthly bill by less than $3.50 per month depending on usage.

Customer growth initiatives While there has been some improvement in the economic conditions within the areas we serve, we continue to see higher 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 have experienced only slight customer gains in our distribution operations and retail operations segments throughout 2011. Our year-over-year consolidated utility customer gain rate was 0.1% in 2011, compared to a loss rate of (0.1)% for 2010. We anticipate overall competition and customer trends in 2012 to be similar to our 2011 results. In addition, for the full year 2011 Nicor Gas increased their customer count by 0.4% compared to 0.2% for 2010.

We use a variety of targeted marketing programs to attract new customers and to retain existing customers. These efforts include working to add residential customers, multifamily complexes and commercial customers who use natural gas for purposes other than space heating, as well as evaluating and launching new natural gas related programs, products and services to enhance customer growth, mitigate customer attrition and increase operating revenues. 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. On October 10, 2011, Georgia Natural Gas was named the exclusive natural gas partner for the Delta Air Lines Inc. Delta SkyMiles Program in Georgia. This is a long-term partnership and we expect it will help retain current customers as well as attract new customers from other Marketers in Georgia.

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Natural gas price volatility Volatility in the natural gas market arises from a number of factors such as weather fluctuations or changes in supply or demand for natural gas in different regions of the country. The volatility of natural gas commodity prices has a significant impact on our customer rates, our long-term competitive position against other energy sources and the ability of our wholesale services segment to capture value from location and seasonal spreads. During 2008 and 2009, daily Henry Hub spot market prices for natural gas in the United States were extremely volatile. However, during 2010 and 2011, the volatility of natural gas prices has been significantly lower than it had been for several prior years. This is the result of a robust natural gas supply, the weak economy, mild weather and ample storage. Our natural gas acquisition strategy is designed to secure sufficient supplies of natural gas to meet the needs of our utility customers and to hedge gas prices to effectively manage costs, reduce price volatility and maintain a competitive advantage. Additionally, our hedging strategies and physical natural gas supplies in storage enable us to reduce earnings risk exposure due to higher gas costs.

It is possible that natural gas prices will remain low for an extended period based on current levels of excess supply relative to market demand for natural gas, in part due to abundant sources of new shale natural gas reserves and the lack of demand by commercial and industrial enterprises. However, as economic conditions improve, the demand for natural gas may increase, natural gas prices could rise and higher volatility could return to the natural gas markets. Consequently, we are working to reposition our wholesales services business model with respect to fixed costs and the types of contracts pursued and executed.

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, retail operations and midstream 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 operations, wholesale services and 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. Occasionally in the summer, 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 of Financial Position items such as receivables, unbilled revenue, inventories and short-term debt across quarters. However, these items are comparable when reviewing our annual results.

Additionally, the revenues of 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 and consumer spending increases during traditional holiday periods.

Approximately 71% of these segments’ operating revenues and 92% of these segments’ EBIT for the year ended December 31, 2011 were generated during the first and fourth quarters of 2011, and are reflected in our Consolidated Statements of Income for the quarters ended March 31, 2011 and December 31, 2011. Our base operating expenses, excluding cost of 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 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, 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 significant portion of our revenues. As a result of our merger with Nicor, our results of operations for the year ending December 31, 2011 includes 22 days of Nicor activity from December 10, 2011 through December 31, 2011. See Note 3 for additional merger related information and Note 13 to our consolidated financial statements under Item 8 herein for additional information regarding reclassification of our business segments. The following table provides more information regarding the components of our operating revenues.

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In millions	2011		2010		2009
Residential	$	1,065	$	1,083	$	1,091
Commercial		467		521		467
Transportation		403		404		378
Industrial		289		205		185
Other		114		160		196
Total operating revenues	$	2,338	$	2,373	$	2,317

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 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 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 and 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 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 operations, wholesale services, midstream operations and cargo shipping 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 revenue and 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	2011			2010			2009
Operating revenues	$	2,338		$	2,373		$	2,317
Cost of goods sold		(1,097	)		(1,164	)		(1,142	)
Revenue tax expense (1)		(9	)		0			0
Operating margin		1,232			1,209			1,175
Operating expenses (2)		(733	)		(703	)		(699	)
Revenue tax expense (1)		9			0			0
Nicor merger expenses (3)		(68	)		(6	)		0
Operating income		440			500			476
Other income (expense)		7			(1	)		9
EBIT		447			499			485
Interest expenses		136			109			101
Earnings before income taxes		311			390			384
Income tax expenses		125			140			135
Net income		186			250			249
Less net income attributable to the noncontrolling interest		14			16			27
Net income attributable to AGL Resources Inc.	$	172		$	234		$	222

(1)   Adjusted for revenue tax expenses for Nicor Gas which are passed directly through to customers.

(2)   Excludes transaction expenses associated with the merger with Nicor of approximately $68 million ($55 million net of tax) in 2011 and $6 million ($4 million net of tax) in 2010.

(3)   Transaction expenses associated with the Nicor merger are part of operating expenses, but are shown separately to better compare year-over-year results.

In 2011, our net income attributable to AGL Resources Inc. decreased by $62 million or 26% compared to last year. The decrease was primarily the result of approximately $68 million ($55 million net of tax) of transaction expenses associated with the merger with Nicor in 2011, which were expensed as incurred. We incurred approximately $6 million ($4 million net of tax) of Nicor transaction costs in 2010. Additionally, we experienced reduced EBIT at wholesale services and retail energy operations due to decreased average customer usage, warmer weather, losses associated with pipeline constraints in the Marcellus shale gas region and significantly lower natural gas volatility. This decrease was partially offset by higher EBIT at distribution operations due to increased revenues from new rates at Atlanta Gas Light and increased regulatory infrastructure program revenues at Atlanta Gas Light and Elizabethtown Gas. The decrease in our net income attributable to AGL Resources Inc. was also unfavorably impacted by increased interest expenses resulting from higher average debt outstanding, primarily the result of the additional long-term debt issuance used to fund the Nicor merger.

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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 project by Virginia Natural Gas. 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 operations, midstream operations and other. The decrease in EBIT at retail operations was mainly attributable to increased operating expenses. The variances for each operating segment are contained within the year-over-year 2011 compared to year-over-year discussion on the following pages.

Interest expense In 2011, our interest expense increased by approximately $27 million. This increase was primarily the result of our prefunding the cash portion of the merger consideration through the issuance of approximately $975 million of long-term debt during the year. This increased our annual interest expense by approximately $17 million. The remaining increase during 2011 related primarily to fees paid on our Term Loan Facility and our Bridge Facility.

The increase in our interest expenses of $8 million in 2010 compared to 2009 was primarily the result of fluctuations in short-term interest rates 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	2011			2010			2009
Interest expenses	$	136		$	109		$	101
Average debt outstanding (1)	$	2,652		$	2,393		$	2,239
Average rate (2)		5.1	%		4.6	%		4.5	%

(1)   Daily average of all outstanding debt.

(2)   Increase in the 2011 average interest rate is due to our senior note issuances during the current year.

Income tax expense Our income tax expense in 2011 decreased by $15 million or 11% compared to 2010. The decrease was primarily due to lower consolidated earnings as previously discussed. Our effective tax rate was 42.1% in 2011, 37.5% in 2010 and 37.8% in 2009. The increased effective tax rate in 2011 was primarily due to non-deductible merger transaction expenses. Our income tax expense in 2010 increased by $5 million or 4% compared to 2009 primarily due to higher consolidated earnings.

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 our effective tax rate, see Note 12 to our consolidated financial statements under Item 8 herein.

Operating metrics Selected weather, customer and volume metrics for 2011, 2010 and 2009, which we consider to be some of the key performance indicators for our operating segments, are presented in the following tables. For the businesses that were acquired from the Nicor merger we only include the 22 days of activity from December 10, 2011 through December 31, 2011. 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 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 midstream operations segment, our natural gas storage businesses seek to have a significant percentage of their working natural gas capacity under firm subscription, but also take into account current and expected market conditions. This allows our natural gas storage business to generate additional revenue during times of peak market demand for natural gas storage services, but retain some consistency with their earnings and maximize the value of the investments.

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Weather									2011 vs.			2010 vs.			2011 vs.			2010 vs.			2009 vs.
Heating degree days (1)			Year ended December 31,						2010			2009			normal			normal			normal
	Normal		2011		2010		2009		colder (warmer)			colder (warmer)			colder (warmer)			colder (warmer)			colder (warmer)
Georgia		2,679		2,454		3,209		2,803		(24	)%		14	%		(8	)%		20	%		5	%
Virginia		3,182		2,945		3,601		3,312		(18	)%		9	%		(7	)%		13	%		4	%
New Jersey		4,639		4,275		4,445		4,755		(4	)%		(7	)%		(8	)%		(4	)%		3	%
Florida		551		310		1,108		548		(72	)%		102	%		(44	)%		101	%		(1	)%
Tennessee		3,085		2,953		3,594		3,154		(18	)%		14	%		(4	)%		16	%		2	%
Maryland		4,696		4,489		4,679		4,783		(4	)%		(2	)%		(4	)%		0	%		2	%
Ohio		4,898		4,656		5,181		4,919		(10	)%		5	%		(5	)%		6	%		0	%
									2011 vs.			2010 vs.			2011 vs.			2010 vs.			2009 vs.
			Quarter ended December 31,							2010			2009		normal			normal			normal
	Normal			2011		2010		2009	colder (warmer)			colder (warmer)			colder (warmer)			colder (warmer)			colder (warmer)
Georgia		1,036		852		1,187		1,182		(28	)%		0	%		(18	)%		15	%		14	%
Virginia		1,091		853		1,380		1,065		(38	)%		30	%		(22	)%		26	%		(2	)%
New Jersey		1,620		1,328		1,720		1,618		(23	)%		6	%		(18	)%		6	%		0	%
Florida		174		66		365		158		(82	)%		131	%		(62	)%		110	%		(9	)%
Tennessee		1,216		1,104