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 1-7296
NORTHERN ILLINOIS GAS COMPANY (Doing Business as NICOR GAS COMPANY)
(Exact name of registrant as specified in its charter)
Illinois	36-2863847
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1844 Ferry Road
Naperville, Illinois 60563	630-983-8888
(Address and zip code of principal executive offices)	(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) or 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 ¨  No  þ
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.  þ
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  ¨                 Accelerated filer  ¨                 Non-accelerated filer þ                 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
All shares of common stock are owned by AGL Resources Inc.
Northern Illinois Gas Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2)(b), (c) and (d) of Form 10-K.

TABLE OF CONTENTS

		Page(s)
Glossary of Key Terms		3-4
Forward-Looking Statements		5
Part I
Item 1.	Business	5-9
Item 1A.	Risk Factors	9-16
Item 1B.	Unresolved Staff Comments	16
Item 2.	Properties	16
Item 3.	Legal Proceedings	16
Item 4.	Mine Safety Disclosures	16
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	17
Item 6.	Selected Financial Data	*
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17-33
	Executive Summary	17-19
	Results of Operations	19-22
	Liquidity and Capital Resources	23-28
	Contingencies	28-29
	Critical Accounting Policies and Estimates	29-32
	Accounting Developments	33
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	33-34
Item 8.	Financial Statements and Supplementary Data	35-62
	Report of Independent Registered Public Accounting Firm	35-36
	Management’s Report on Internal Control Over Financial Reporting	37
	Consolidated Statements of Financial Position	38-39
	Consolidated Statements of Income	40
	Consolidated Statements of Comprehensive Income	41
	Consolidated Statements of Retained Earnings	41
	Consolidated Statements of Cash Flows	42
	Note 1 – Organization and Basis of Presentation	43
	Note 2 – Significant Accounting Policies and Methods of Application	43-49
	Note 3 – Fair Value Measurements	49-50
	Note 4 – Derivative Instruments	50-51
	Note 5 – Employee Benefit Plans	52-54
	Note 6 – Debt	55-56
	Note 7 – Commitments, Guarantees and Contingencies	56-60
	Note 8 – Income Taxes	60-61
	Note 9 – Related Party Transactions	61-62
	Note 10 – Regulatory Matters	62
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	63
Item 9A.	Controls and Procedures	63
Item 9B.	Other Information	63
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	*
Item 11.	Executive Compensation	*
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	*
Item 13.	Certain Relationships and Related Transactions, and Director Independence	*
Item 14.	Principal Accounting Fees and Services	64
Part IV
Item 15.	Exhibits, Financial Statement Schedules	65-67
Signatures		68
Schedule II		69
* The Registrant meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore omitting the information called for by the otherwise required item.

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GLOSSARY OF KEY TERMS

AGL Resources.  AGL Resources Inc., our parent company since the completion of the merger between AGL Resources and Nicor on December 9, 2011.

Bcf.  Billion cubic feet.

Chicago Hub.  A venture of Nicor Gas, which provides natural gas storage and transmission-related services to marketers and other gas distribution companies.

ERC.  Environmental remediation costs.

FASB.  Financial Accounting Standards Board.

FERC.  Federal Energy Regulatory Commission.

Fitch.  Fitch Ratings.

GAAP.  Accounting principles generally accepted in the United States of America.

Health Care Act.  Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010.

Heating Degree Days.  A measure of the effects of weather on our business, calculated when the average daily temperatures are less than 65 degrees Fahrenheit.  Normal weather for our service territory, for purposes of this report, is considered to be 5,600 Heating Degree Days per year.

Heating Season.  The period from November through March when natural gas usage and operating revenues are generally higher because weather is colder.

Horizon Pipeline.  Horizon Pipeline Company, L.L.C., a 50% owned joint venture of AGL Resources, operates an interstate regulated natural gas pipeline of approximately 70 miles stretching from Joliet, Illinois to near the Wisconsin/Illinois border.

Illinois Commission.  Illinois Commerce Commission, our state regulatory agency.

LIBOR.  London Inter-Bank Offered Rate.

LIFO.  Last-in, first-out.

Mcf.  Thousand cubic feet.

Moody’s.  Moody’s Investors Service.

Nicor.  Nicor Inc., our parent company prior to the completion of the merger between AGL Resources and Nicor on December 9, 2011.

Nicor Advanced Energy.  Prairie Point Energy, L.L.C. (doing business as Nicor Advanced Energy), a wholly owned business of AGL Resources that provides natural gas and related services on an unregulated basis to residential and small commercial customers.

Nicor Enerchange.  Nicor Enerchange, L.L.C., a wholly owned business of AGL Resources that engages in wholesale marketing of natural gas supply services primarily in the Midwest, administers the Chicago Hub for us, serves commercial and industrial customers in the northern Illinois market area, and manages Nicor Solutions’ and Nicor Advanced Energy’s product risks, including the purchase of natural gas supplies.

Nicor Gas.  Northern Illinois Gas Company (doing business as Nicor Gas Company), or the registrant.

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Nicor Services.  Nicor Energy Services Company,a wholly owned business of AGL Resources that, directly or through subsidiaries, provides customer move connection services for utilities and product warranty contracts, heating, ventilation and air conditioning repair, maintenance and installation services and equipment to retail markets, including residential and small commercial customers.

Nicor Solutions.  Nicor Solutions, L.L.C., a wholly owned business of AGL Resources that offers residential and small commercial customers energy-related products that provide for natural gas cost stability and management of their utility bill.

OCI.  Other comprehensive income.

Pad gas.  Volumes of non-working natural gas used to maintain the operational integrity of a natural gas storage facility.

PBR.  Performance-based rate, a regulatory plan which ended on January 1, 2003, that provided economic incentives based on natural gas cost performance.

PGA.  Purchased Gas Adjustment, a rate rider that passes natural gas costs directly through to customers without markup, subject to Illinois Commission review.

PP&E.  Property, plant and equipment.

Revenue taxes.  Revenue and use taxes.

Rider.  A rate adjustment mechanism that is part of a utility's tariff which authorizes it to provide specific services or assess specific charges.

SEC.  The United States Securities and Exchange Commission.

SNG.  Substitute natural gas, a synthetic form of gas manufactured from coal.

S&P.  Standard & Poor’s Ratings Services.

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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 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, 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 changes in project costs, including the cost of funds to finance these projects; the impact of acquisitions and divestitures; direct or indirect effects on our business, financial condition or liquidity resulting from any change in our credit ratings as a result of the recent merger between AGL Resources and 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; 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

Nature of Our Business

Unless the context requires otherwise, references to “we,” “us,” “our,” the “company” and “Nicor Gas” are intended to mean Nicor Gas and its subsidiary.  Nicor Gas is an Illinois corporation formed in 1954.  On December 9, 2011, the previously announced merger between AGL Resources and Nicor was consummated and we became a wholly owned subsidiary of AGL Resources.  Certain terms used herein are defined in the glossary on pages 3 and 4.

We are a regulated natural gas distribution utility that serves approximately 2.2 million customers in a service territory that encompasses most of the northern third of Illinois, excluding the city of Chicago.  Our primary business activity, and our only reportable segment, is the distribution of natural gas.  Our service territory is diverse, providing us with a well-balanced mix of residential, commercial and industrial customers.  Residential customers typically account for approximately 50% of natural gas deliveries, while commercial and industrial customers each typically account for approximately 25%.  See Operating Metrics on page 22 for operating revenues, deliveries and number of customers by customer classification.

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Customers have the option of purchasing their own natural gas supplies, with delivery of the gas by us.  The larger of these transportation customers also have options that include the use of our storage system and the ability to choose varying supply backup levels.  The choice of transportation service as compared to natural gas sales service results in less revenue for us but has no direct impact on net operating results.  We continue to deliver natural gas, maintain our distribution system and respond to emergencies.

We also operate the Chicago Hub, which provides natural gas storage and transmission-related services to marketers and other gas distribution companies.  The Chicago area is a major market hub for natural gas, and demand exists for storage and transmission-related services by marketers, other gas distribution companies and electric power-generation facilities.  Our Chicago Hub addresses that demand.  Chicago Hub revenues are passed directly through to customers as a credit to our PGA rider.

Regulation and Rate Design

Rate Structures.We operate subject to regulations and oversight of the Illinois Commission with respect to construction and maintenance of facilities, operations, safety, rates that we charge customers, relationships with our affiliates and other matters.  Rates charged to our customers vary according to customer class (residential, commercial or industrial). The Illinois Commission approves 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 shareholder. 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.  In accordance with the terms of the Illinois Commission’s order approving the merger of AGL Resources and Nicor, we are not permitted to initiate a rate case proceeding that would increase our rates effective prior to December 9, 2014.

Our earnings can be affected by customer consumption patterns that are a function of weather conditions and price levels for natural gas. Natural gas deliveries are temperature-sensitive and seasonal since about one-half of all deliveries are used for space heating.  Typically, about two-thirds of the deliveries and revenues occur in the Heating Season.  Fluctuations in weather have the potential to significantly impact year-to-year comparisons of operating income and cash flow.  It is estimated that a 100 degree-day variation from normal weather impacts our margin, net of income taxes, by approximately $1 million under our current rate structure and depending on weather patterns.

We are authorized to use a natural gas cost recovery mechanism that allows us to adjust our rates to reflect changes in the wholesale cost of natural gas and to ensure we recover all of the costs prudently incurred in purchasing gas for our customers.  Therefore, we do not profit from the sale of natural gas.  Rather, we earn income from fixed monthly charges and from variable transportation charges for delivering natural gas to customers.  Annually, the Illinois Commission initiates a review of our natural gas purchasing practices for prudence, and may disallow the pass-through of costs considered imprudent.  The annual prudence reviews for calendar years 1999-2011 are open pending resolution by the Illinois Commission of the proceeding concerning our PBR plan.  See Item 8 – Financial Statements and Supplementary Data – Note 7 – Commitments, Guarantees and Contingencies for additional information regarding the PBR plan.

In addition to the natural gas cost recovery mechanism, we have several other cost recovery mechanisms, known as riders, which allow us to recover 100% of certain costs, such as bad debt, environmental costs related to the remediation of former manufactured gas plant sites and energy efficiency program costs.  These riders are further discussed below under “Recent Regulatory Actions” and “Environmental Remediation Costs.”

Recent Regulatory Actions.  On March 25, 2009, the Illinois Commission issued an order approving an increase in our base revenues of approximately $69 million, a rate of return on rate base of 7.58% and a rate of return on equity of 10.17%.  On October 7, 2009, the Illinois Commission increased the annual base revenues approved in the March 25, 2009 order by approximately $11 million as a result of a rehearing decision and increased the rate of return on rate base to 8.09%.  Therefore, the total annual base revenue increase resulting from these Illinois Commission orders is approximately $80 million.  For additional information about the rate proceeding, see Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Legislative and Regulatory Update and Item 8 – Financial Statements and Supplementary Data – Note 10 – Regulatory Matters.

On February 2, 2010, the Illinois Commission approved a bad debt rider that provides for the recovery from (or refund to) customers of the difference between our actual bad debt experience on an annual basis and the benchmark bad debt expense included in our base rates for the respective year.  Costs incurred for bad debt are subject to annual Illinois Commission prudence review.  For additional information about the bad debt rider, see Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Legislative and Regulatory Update and Item 8 – Financial Statements and Supplementary Data – Note 10 – Regulatory Matters.

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As part of the rate order issued in 2009, the Illinois Commission approved an energy efficiency rider to fund the costs of energy savings programs.  In accordance with an Illinois law enacted in 2009 that requires local gas distribution utilities to establish plans to achieve specified energy savings goals beginning in June 2011, we filed an application with the Illinois Commission seeking approval of a new energy efficiency plan in September 2010.  The law provides utilities with a rider to collect the costs of the plan from customers.  In May 2011, the Illinois Commission approved our plan.  Under our approved plan, we estimate that we would bill approximately $155 million to customers under the rider, over a three year period commencing June 1, 2011, to fund the costs of various energy savings programs identified in our filing.  This new energy efficiency plan rider replaced the rider previously in effect.  The costs under the rider are subject to annual Illinois Commission review.

On July 1, 2009, we filed a petition seeking re-approval from the Illinois Commission of the operating agreement that governs many inter-company transactions between our affiliates and us.  The petition was filed pursuant to a requirement contained in the Illinois Commission order approving our most recent general rate increase and requested that the operating agreement be re-approved without change.  On December 9, 2011, the Illinois Commission issued its order approving the operating agreement with the modification that would preclude us from providing certain solicitation services for our affiliates.  For additional information regarding this proceeding, see Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Legislative and Regulatory Update.

On January 1, 2000, we instituted a PBR plan for natural gas costs.  Under the PBR plan, our 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 we acted improperly in connection with the PBR plan.  In February 2012, we committed to a stipulated resolution of issues with the Staff of the Illinois Commission, which includes crediting our customers $64 million, but does not constitute an admission of fault.  This resulted in a $37 million pretax charge to our results in the fourth quarter of 2011, which represents the difference between the $64 million proposed credit and our previously recorded $27 million liability.  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.  See Item 8 – Financial Statements and Supplementary Data – Note 7 – Commitments, Guarantees and Contingencies for additional information regarding the PBR plan.

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 former manufactured gas plant sites that were used in the 1800’s and early to mid 1900’s to produce manufactured gas from coal, creating a coal tar byproduct.

We report estimates of future environmental remediation costs on an undiscounted basis.  Our ERC liabilities for certain of our former manufactured gas plant sites are estimated based on probabilistic models of potential costs.  These probabilistic models have not been performed on all of our sites, but are expected to be completed in 2012.  Based on the estimates that we have performed, the cleanup cost estimates range from $134 million to $216 million.  Our liability for environmental remediation costs at December 31, 2011 is $134 million, of which $19 million is expected to be paid over the next twelve months.  As we continue to conduct the actual remediation and enter into cleanup contracts, we are increasingly able to provide conventional engineering estimates of the likely costs of many elements of the remediation program. These estimates contain various engineering uncertainties, and we regularly attempt to refine and update these engineering estimates.  We have an Illinois Commission-approved tariff that provides for the pass-through of prudently incurred environmental costs related to the remediation of these sites.  Costs incurred are subject to annual Illinois Commission prudence review.

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 costs and Item 8 – Financial Statements and Supplementary Data – Note 7 – Commitments, Guarantees and Contingencies for additional information about our environmental remediation efforts.

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Competition and Customer Demand

We are the largest natural gas distributor in Illinois.  We 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.

Our large residential customer base provides for a relatively stable level of natural gas deliveries during weak economic conditions.  Our industrial and commercial customer base is well diversified, lessening the impact of industry-specific economic swings.

While there has been some improvement in the economic conditions within the areas we serve, there continues to be high rates of unemployment and depressed housing markets with high inventories, significantly reduced new home construction and a decline in new commercial development. As a result, we have experienced only slight customer additions. Our year-over-year customer addition rate was 0.4% in 2011, compared to 0.2% for 2010. We anticipate overall competition and customer trends in 2012 to be similar to our 2011 results.

We work with regulators and state agencies 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 and we expect to continue this focus for the foreseeable future. We also have an energy efficiency program whereby we educate our customers about energy efficiency and conservation and provide rebates and other incentives for the purchase of high-efficiency natural gas-fueled equipment.

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.

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 us or our transportation customers.  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.

Natural gas supply.  We maintain a diversified portfolio of natural gas supply contracts.  Supply purchases are diversified by supplier, producing region, quantity, credit limits and available transportation.  Natural gas supply pricing is generally tied to published price indices so as to approximate current market prices.  These supply contracts also may require the payment of fixed demand charges to ensure the availability of supplies on any given day.  We also purchase natural gas supplies on the spot market to fulfill our supply requirements or to take advantage of favorable short-term pricing.

In 2011, Illinois enacted laws that required us 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. The price of the SNG that may be produced from both of the coal gasification plants may exceed market prices and is dependent upon a variety of factors, including plant construction costs, and is currently not estimable.  The Illinois laws provide that prices paid for SNG purchased from the plants are to be considered

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prudent and not subject to review or disallowance by the Illinois Commission.  See Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contractual Obligations and Commitments and Item 8 – Financial Statements and Supplementary Data – Note 7 – Commitments, Guarantees and Contingencies for additional information about the SNG plant legislation.

As part of our purchasing practices, we maintain a price risk hedging strategy to reduce the risk of price volatility.  A disciplined approach is used to systematically forward hedge a predetermined portion of forecasted monthly volumes.

As noted previously, transportation customers purchase their own natural gas supplies.  About one-half of the natural gas that we deliver is purchased by transportation customers directly from producers and marketers.

Pipeline transportation.  Our distribution and storage system is directly connected to eight interstate pipelines.  This provides us with direct access to most of the major natural gas producing regions in North America.  We have long-term transportation contracts with nearly all of these interstate pipelines and generally have a right-of-first-refusal for contract extensions.  The largest of these long-term transportation contracts is with Natural Gas Pipeline Company of America (“NGPL”) which provides approximately 65% of our firm transportation capacity.  In addition, we enter into short-term winter-only transportation contracts and market-area transportation contracts that enhance our operational flexibility.

Storage.  We own and operate eight underground natural gas storage facilities.  This storage system is one of the largest in the gas distribution industry.  The storage reservoirs have 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 our estimated peak-day deliveries and approximately 40% of our normal winter deliveries.  In addition to company-owned facilities, we have about 40 Bcf of purchased storage services under contracts with NGPL 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.

Employees

As of February, 1, 2012, we had approximately 2,050 employees.  In addition, our affiliate, AGL Services Company provides personnel services to us pursuant to a services agreement.  Many of these employees are located at Nicor Gas facilities.

Approximately 65% of our employees are represented under a collective bargaining agreement with the International Brotherhood of Electrical Workers (Local No. 19) that expires February 28, 2014.  We believe that we have a good working relationship with our unionized employees.

Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports that we file with, or furnish to, the SEC are available free of charge at AGL Resources’ website, www.aglresources.com, as soon as reasonably practicable after we electronically file such reports with or furnish such reports to the SEC. However, the 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

ITEM 1A.  RISK FACTORS

The following factors are the most significant factors that can impact year-to-year comparisons and may affect the future performance of the company.  New risks may emerge and we cannot predict those risks or estimate the extent to which they may affect our financial performance.

The risks described below should be carefully considered in addition to the other cautionary statements and risks described elsewhere, and the other information contained in this report and in our other filings with the SEC, including our subsequent reports on Forms 10-Q and 8-K.  The risks and uncertainties described below are not the only risks we face, although they are the most significant risks.

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Risks Related to Our Business

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

Our business is regulated by the Illinois Commission. This authority regulates many aspects of our operations, including construction and maintenance of facilities, operations, safety, rates that we charge customers, relationships with our affiliates and other matters.  Our ability to obtain rate increases to maintain our current rates of return and recover regulatory assets 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 continue receiving our currently authorized rates of return including the recovery of our regulatory assets and liabilities.

We are permitted by the Illinois Commission’s PGA regulation to adjust the charge to our sales customers on a monthly basis to recover our prudently incurred actual costs to acquire the natural gas we deliver.  Our gas costs are subject to subsequent prudence reviews by the Illinois Commission for which we make annual filings.  The annual prudence reviews for calendar years 1999-2011 are open for review and any disallowance of costs in those proceedings could adversely affect our results of operations, cash flows and financial condition.

Additionally, we are permitted by Illinois Commission regulations to periodically adjust the charge to our customers to recover our prudently incurred actual costs associated with environmental remediation at former manufactured gas plant sites, franchise payments to municipalities, energy efficiency programs, bad debt expense and municipal utility taxes.  Certain of these charges are subject to subsequent prudence reviews by the Illinois Commission and any disallowance of costs by the Illinois Commission could adversely affect our results of operations, cash flows and financial condition.

Most of our other charges are changed only through a rate case proceeding with the Illinois Commission.  The charges established in a rate case proceeding are based on an approved level of operating costs and investment in utility property and are designed to allow us an opportunity to recover those costs and to earn a fair return on that investment based upon an estimated volume of annual natural gas deliveries.  As a condition to the approval by the Illinois Commission of the merger of AGL Resources and Nicor, we are not allowed to initiate a rate case proceeding that would increase our rates effective prior to December 9, 2014.  To the extent our actual costs to provide utility service are higher than the levels approved by the Illinois Commission, or our actual natural gas deliveries are less than the annual volume estimated by the Illinois Commission, our results of operations, cash flows and financial condition could be adversely affected until such time as we file for and obtain Illinois Commission approval for new charges through a rate case proceeding.

In 2011, Illinois enacted laws that required us 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, we 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 SNG plant legislation, see Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Legislative and regulatory update.

We are subject to rules and regulations pertaining to the integrity of our distribution system and environmental compliance.  Our results of operations, cash flows and financial condition could be adversely affected by any additional laws or regulations that are enacted that require significant increases in the amount of expenditures for system integrity and environmental compliance.

The Illinois Commission has other rules that impact the operations of utilities in Illinois.  Changes in these rules could impact our results of operations, cash flows and financial condition.

We enter into various service agreements with AGL Resources and its affiliates.  We obtain the required Illinois Commission approvals for these agreements.  Our results of operations, cash flows and financial condition could be adversely affected if, as a result of a change in law or action by the Illinois Commission, new restrictions are imposed that limit or prohibit certain service agreements between us and our affiliates or rate recovery of costs incurred by us under those service agreements.

The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (“Dodd-Frank Act”) 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 our 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 our working capital if the regulations increase our collateral requirements related to derivatives utilized in our business.

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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 and our costs to comply could be 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 can be 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.

An adverse decision in the proceeding concerning our PBR plan could result in a refund obligation which could adversely affect our results of operations, cash flows and financial condition.

On January 1, 2000, we instituted a PBR plan for natural gas costs.  Under the PBR plan, our 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.  There are allegations that we 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 refund 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 issues with the Staff of the Illinois Commission, which includes crediting our customers $64 million, but does not constitute an admission of fault.  This resulted in a $37 million pretax charge to our results in the fourth quarter of 2011, which represents the difference between the $64 million proposed credit and our previously recorded $27 million liability.  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 stipulated resolution and continue to pursue their claims in this proceeding.  Evidentiary hearings on this matter are scheduled to begin on February 28, 2012.  See Item 8 – Financial Statements and Supplementary Data – Note 7 – Commitments, Guarantees and Contingencies for additional information regarding the PBR plan.

We rely on direct connections to eight interstate pipelines and extensive underground storage capacity. A decrease in the availability of adequate pipeline transportation and storage capacity could reduce our revenues and profits.

We meet our customers’ peak day, seasonal and annual gas requirements through deliveries of natural gas transported on interstate pipelines, with which we or our natural gas suppliers have contracts, and through withdrawals of natural gas from storage fields we own or lease.  We contract with multiple pipelines for transportation services.  If a pipeline were to fail to perform transportation or storage service, including as a result of war, acts or threats of terrorism, mechanical problems or natural disaster, on a peak day or other day with high volume gas requirements, our ability to meet all of our customers’ natural gas requirements may be impaired unless or until alternative arrangements for delivery of supply were put in place.  Likewise, if a storage field owned by the company, or a principal company-owned transmission or distribution pipeline used to deliver natural gas to the market, were to be out of service for any reason, including as a

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result of war, acts or threats of terrorism, mechanical problems or natural disaster, this could impair our ability to meet our customers’ full requirements which could adversely affect our results of operations, cash flows and financial condition.

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.

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 financial condition, results of operations or cash flows.

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.  When weather conditions are milder than normal, we have historically delivered less natural gas, and consequently may earn less income.  Our natural gas deliveries are temperature-sensitive and seasonal since about one-half of all deliveries are used for space heating.  Typically, about two-thirds of our deliveries and revenues occur in the Heating Season.  Fluctuations in weather have the potential to significantly impact year-over-year comparisons of operating income and cash flow.  We estimate that a 100 degree-day variation from normal weather impacts our margin, net of income taxes, by approximately $1 million under our current rate structure and depending upon weather patterns.

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 a cost recovery rider.  However, the adverse impact of lower deliveries and resulting reduced margin could adversely affect our results of operations, cash flows and financial condition until such time as we file for and obtain Illinois Commission approval for new charges through a rate case proceeding.  As a condition to the approval by the Illinois Commission of the merger of AGL Resources and Nicor, we are not allowed to initiate a rate case proceeding that would increase our rates effective prior to December 9, 2014.

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 and oil and propane providers.  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 and industrial 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.

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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.

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

Inflation has caused increases in certain operating expenses and has required us to replace assets at higher costs.  We attempt to control costs in part through implementation of best practices and business process improvements, many of which are facilitated through investments in information systems and technology. We have a process in place to continually review the adequacy of our rates in relation to the increasing cost of providing service and the inherent regulatory lag in adjusting those rates.  As a condition to the approval by the Illinois Commission of the merger of AGL Resources and Nicor, we are not allowed to initiate a rate case proceeding that would increase our rates effective prior to December 9, 2014.  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 together with the restriction imposed on our right to initiate a rate proceeding could 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 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.

We have credit risk that could adversely affect our results of operations, cash flows and financial condition.

We extend credit to our counterparties.  Despite performing credit analyses prior to extending credit and seeking to effectuate netting arrangements, we are exposed to the risk that we may not be able to collect amounts owed to us.  If the counterparty to such a transaction fails to perform and any collateral we have secured is inadequate, we could experience material financial losses.

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

Our 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 if not fully covered by insurance could adversely affect our results of operations, cash flows and financial condition.

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

We maintain a noncontributory defined benefit pension plan covering substantially all employees hired prior to 1998.  We also provide health care and life insurance benefits to eligible retired employees under our retiree medical benefit plan that includes a limit on our share of cost for employees hired after 1982.  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, including longer life expectancy of beneficiaries and changes in health care cost trends.

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Any sustained declines in equity markets and reductions in bond yields may have a material adverse effect on the value of investments held in the pension plan’s trust.  A reduction in the value of such investments unfavorably impacts the benefit costs associated with the pension plan and could adversely affect our liquidity if additional contributions to the trust are required.  These impacts, either individually or in aggregate, may adversely affect our results of operations, cash flows and financial condition.

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

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.

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.

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.  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

·   terrorist attacks on our facilities or our suppliers, or

·   extreme weather conditions.

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 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

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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 credit facility, our debt service obligations could be accelerated.

Our existing credit facility contains financial covenants. If we breach any of the financial covenants under this agreement, our debt repayment obligations 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 ratings fall to non-investment grade status, we will be required to provide additional support for certain counterparties. In December 2011, after the completion of the merger between AGL Resources and Nicor, our credit ratings were graded as follows:

·   S&P lowered our corporate credit rating from AA to BBB+ and our commercial paper rating from A-1+ to A-2 and noted the outlook is now Stable.

·   Moody’s lowered our senior unsecured rating from A2 to A3 and our commercial paper rating from P-1 to P-2.  Moody’s revised its outlook from Negative to Stable.

As of December 31, 2011, if our credit rating had fallen below investment grade, we would have been required to provide collateral of approximately $6 million to continue conducting business with certain counterparties.

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.

Our credit facility contains 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.

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

We use derivative instruments, including futures, options, forwards and swaps, to manage our commodity risk.  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 and the 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 values of these contracts.

We are subject to margin requirements in connection with the use of derivative financial instruments and these requirements could escalate if prices move adversely.

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, 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.

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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.

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

Our properties are located in the territory described under Item 1 – Business, and are suitable, adequate and utilized in our operations.

The gas distribution, transmission and storage system includes approximately 34,000 miles of steel, plastic and cast iron main; approximately two million steel, plastic/aluminum composite, plastic and copper services connecting the mains to customers’ premises; and eight underground storage fields.  Other properties include buildings, land, motor vehicles, meters, regulators, compressors, construction equipment, tools, communication and computer equipment, software and office equipment.

Most of our distribution and transmission property, and underground storage fields are located on property owned by others and used by us through easements, permits or licenses.  We own most of the buildings housing our administrative offices and the land on which they sit.

Substantially all gas distribution properties are subject to the lien of the indenture securing our first mortgage bonds.

Additional information about our business is presented in Item 1 – Business, Item 1A – Risk Factors, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8 – Notes to the Consolidated Financial Statements.

ITEM 3.  LEGAL PROCEEDINGS

See Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8 – Financial Statements and Supplementary Data – Note 7 – Commitments, Guarantees and Contingencies – Litigation, which are incorporated herein by reference.

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

All of our outstanding common stock is owned by AGL Resources since the completion of the merger between AGL Resources and Nicor on December 9, 2011.  There is no public trading market for our common stock.  Dividends declared on our common stock were $57 million in 2011 and $116 million in 2010.  We are restricted by regulation in the amount we can dividend to our parent company.  Dividends are allowed only to the extent of our retained earnings balance.

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

EXECUTIVE SUMMARY

We are one of the nation’s largest natural gas distribution companies.  Our operations are subject to regulation and oversight by the Illinois Commission.  The Illinois Commission approves natural gas rates designed to provide us the opportunity to generate revenues to recover the cost of natural gas delivered to our customers and our fixed and variable costs such as depreciation, interest, maintenance and overhead costs, and to earn a reasonable return.  Our earnings can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas and general economic conditions that may impact our customers’ ability to pay for gas consumed.

On December 9, 2011, the previously announced merger between AGL Resources and Nicor was consummated and we became a wholly owned subsidiary of AGL Resources.  As a condition to the Illinois Commission’s approval of the merger, we are not allowed to initiate a rate case proceeding that would increase our rates effective prior to December 9, 2014.

Because of our significant outstanding public debt, the impact of the acquisition (push-down accounting) is not required to be and has not been reflected in our consolidated financial statements.

Legislative and regulatory update

PBR plan.  The PBR plan is currently under review by the Illinois Commission as there are allegations that we acted improperly in connection with the PBR plan.  In February 2012, we committed to a stipulated resolution of issues with the Staff of the Illinois Commission related to our PBR plan.  The stipulated resolution includes crediting our customers $64 million, but does not constitute an admission of fault.  This resulted in a $37 million pretax charge to our results in the fourth quarter of 2011, which represents the difference between the $64 million proposed credit and our previously recorded $27 million liability.  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 stipulated resolution and continue to pursue their claims in this proceeding.  Evidentiary hearings on this matter are scheduled to begin on February 28, 2012.  See Item 8 – Financial Statements and Supplementary Data – Note 7 – Commitments, Guarantees and Contingencies for additional information regarding the PBR plan.

Rate proceeding.  On March 25, 2009, the Illinois Commission issued an order approving an increase in base revenues of approximately $69 million, a rate of return on rate base of 7.58% and a rate of return on equity of 10.17%.  The order also approved an energy efficiency rider.  We placed the rates approved in the March 25, 2009 order into effect on April 3, 2009.

On April 24, 2009, we filed a request for rehearing with the Illinois Commission concerning the capital structure contained in the Illinois Commission’s rate order contending our return on rate base should be higher.  On October 7, 2009, the Illinois Commission issued its decision on rehearing in which it increased our annual base revenues approved in the March 25, 2009 order by approximately $11 million, increasing the rate of return on rate base to 8.09%.  We placed the rates approved in the rehearing decision into effect on a prospective basis on October 15, 2009.  Therefore, the total annual base revenue increase authorized in the rate case we originally filed in April 2008 is approximately $80 million.

Bad debt rider.  In September 2009, we filed for approval of a bad debt rider with the Illinois Commission under an Illinois state law which took effect in July 2009.  On February 2, 2010, the Illinois Commission issued an order approving our proposed bad debt rider.  This rider provides for recovery from customers of the amount over the benchmark for bad debt expense established in our rate cases.  It also provides for refunds to customers if bad debt expense is below such benchmarks.

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As a result of the February 2010 order, we recorded in income a net recovery related to 2008 and 2009 of $32 million in the first quarter of 2010, all of which has been collected.  The benchmark, against which 2011 and 2010 actual bad debt experience is compared, is approximately $63 million.  Our actual 2011 bad debt experience was $31 million, resulting in a refund to customers of $32 million which will be refunded between June 2012 and May 2013.  Our actual 2010 bad debt experience was $36 million, resulting in a refund to customers of $27 million which is being refunded between June 2011 and May 2012.

Energy Efficiency Plan.  On September 29, 2010, we filed an application with the Illinois Commission seeking approval of an energy efficiency plan.  The filing was made pursuant to an Illinois law enacted in 2009 that requires local gas distribution utilities to establish plans to achieve specified energy savings goals beginning in June 2011 and provides utilities with a rider to collect the costs of the plan from customers.  In May 2011, the Illinois Commission approved our plan.  Under our approved plan, we estimate that our billings to customers under the rider will be approximately $155 million over a three year period commencing June 1, 2011.  These amounts will fund the costs of various energy savings programs identified in our filing.  This new energy efficiency plan rider replaced the rider previously in effect.  The costs under the rider are subject to annual Illinois Commission review.

Petition for Re-approval of Operating Agreement.  On July 1, 2009, we filed a petition seeking re-approval from the Illinois Commission of the operating agreement that governs many inter-company transactions between our affiliates and us.  The petition was filed pursuant to a requirement contained in the Illinois Commission order approving our 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 other things, those parties sought changes that would preclude us from continuing to provide sales solicitation services to support warranty products that are sold by Nicor Services.  We opposed this modification to the operating agreement.  As the Illinois Commission was required to evaluate future transactions between our affiliates and us 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 determined to address the matters raised in the operating agreement proceeding in the merger proceeding.  On December 9, 2011, the Illinois Commission issued its order in the merger proceeding approving the operating agreement with a modification that would preclude us from providing certain solicitation services for our affiliates.  This is not expected to have a material impact on our results of operations, cash flows and financial position.

Substitute Natural Gas Plant Legislation.  In 2011, Illinois enacted laws that required us 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. We signed an agreement on September 30, 2011 to purchase approximately 25 Bcf of SNG annually from one of the proposed facilities for a 10-year term beginning as early as 2015.  The price of the SNG under this contract could potentially be about $9.95 per Mcf or more.  The counterparty intends to construct a 60 Bcf per year coal gasification plant in southern Illinois.

Additionally, on October 11, 2011, the Illinois Power Agency (“IPA”) approved the form of a draft 30-year contract for the purchase by us of approximately 20 Bcf per year of SNG from a second proposed plant beginning as early as 2018.  In November 2011, we filed a lawsuit against the IPA and the developer of this second proposed plant contending that the draft contract approved by the IPA does not conform to certain requirements of the enabling legislation. The lawsuit is pending in circuit court in DuPage County, Illinois. In accordance with the enabling legislation, the draft contract approved by the IPA for the second proposed plant was submitted to the Illinois Commission for further approvals by that regulatory body. The Illinois Commission issued an order on January 10, 2012 approving a final form of contract for the second plant. The final form of contract approved by the Illinois Commission modified the draft contract submitted by the IPA in various respects. Both we and the developer of the plant have filed applications for rehearing with the Illinois Commission seeking changes to the final form of contract it approved.

The price of the SNG that may be produced from both of the coal gasification plants may exceed market prices and is dependent upon a variety of factors, including plant construction costs, and is currently not estimable. Illinois laws provide that prices paid for SNG purchased from the plants are to be considered prudent and not subject to review or disallowance by the Illinois Commission.

Financial Reform Legislation.  The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”) was enacted in July 2010, representing an overhaul of the framework for regulation of United States financial markets.  We are currently evaluating the provisions of the Dodd-Frank Act and the potential impact that it may have on us.  However, we believe that an aspect of the Dodd-Frank Act which requires that various regulatory agencies, including the SEC and the Commodities Futures Trading Commission, establish additional regulations for participating in financial markets for hedging certain risks inherent in our business, including commodity risks, may be applicable to us.  As a

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result, the costs of participating in financial markets for hedging certain risks may be increased as a result of the new legislation. We may also incur additional costs associated with our compliance with new regulations and anticipated additional reporting and disclosure obligations.

Health Care Reform Legislation.  In March 2010, the Health Care Act was signed into law resulting in comprehensive health care reform.  The Health Care Act contains a provision that eliminates the tax deduction related to Medicare Part D subsidies received after 2012.  Federal subsidies are provided to sponsors of retiree health benefit plans, such as Nicor Gas, that provide a benefit that is at least actuarially equivalent to the benefits under Medicare Part D.  Such subsidies have reduced our actuarially determined projected benefit obligation and annual net periodic benefit costs.  Due to the change in taxation, in the first quarter of 2010 we reduced deferred tax assets by $18 million, reversed an existing regulatory income tax liability of $10 million, established a regulatory income tax asset of $7 million and recognized a $1 million charge to income tax expense.  The change in taxation will reduce earnings by an estimated $2 million annually for periods subsequent to the enactment date.

Additionally, the Health Care Act contains other provisions that may impact our obligation for retiree health care benefits.  We do not currently believe these provisions will materially increase our retiree medical plan benefit obligation, but we will continue to evaluate the impact of future regulations and interpretations.

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 and our long-term competitive position against other energy sources.  Our natural gas acquisition strategy is designed to secure sufficient supplies of natural gas to meet the needs of our customers and to hedge gas prices to reduce price volatility.

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 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.

Seasonality.  Our operating revenues and operating income are seasonal.  Approximately 71% of operating revenues and 56% of operating income for the year ended December 31, 2011 were generated during the first and fourth quarters of 2011.  Seasonality also affects the comparison of certain Consolidated 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.  Our base operating expenses, excluding cost of gas sold, and interest expense are incurred relatively equally over any given year.  Our operating results, however, can vary significantly from quarter to quarter as a result of seasonality.

RESULTS OF OPERATIONS

We generate substantially all our operating revenues through the sale and distribution of natural gas.  We include in our consolidated revenues an estimate of revenues from natural gas distributed, but not yet billed, 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. The following table provides our operating income and net income.

In millions	2011		2010		2009
Operating income	$	83	$	136	$	111
Net income	$	50	$	101	$	75

Net income decreased $51 million in 2011 compared to the prior year due to lower margin ($44 million pretax decrease), an unfavorable adjustment to our previously recorded liability associated with our PBR plan ($37 million pretax), higher depreciation expense ($5 million pretax increase), partially offset by lower interest expense ($4 million pretax decrease), lower operating and maintenance expense ($2 million pretax decrease) and a lower effective income tax rate.

Net income increased $26 million in 2010 compared to the prior year due to higher margin ($47 million pretax increase).

The following discussion summarizes the major items impacting our operating income.

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Operating revenues.  Operating revenues are impacted by changes in natural gas costs, which are passed directly through to customers without markup, subject to Illinois Commission review, and cost recovery riders, which are generally offset by operating and maintenance expense with no impact on operating income.  Operating revenues decreased $140 million in 2011 compared to the prior year due to lower natural gas costs (approximately $115 million decrease) and lower revenue from cost recovery riders ($46 million decrease), partially offset by higher demand unrelated to weather (approximately $15 million increase).

Operating revenues increased $63 million in 2010 compared to the prior year due to higher natural gas costs (approximately $110 million increase), revenue from cost recovery riders ($43 million increase) and the impact of the increase in base rates (approximately $20 million increase), partially offset by warmer weather in 2010 (approximately $75 million decrease) and lower demand unrelated to weather (approximately $25 million decrease).

Margin.  We utilize a measure referred to as “margin” to evaluate the operating income impact of revenues.  Margin is a non-GAAP measure that is calculated as revenues minus cost of gas and revenue tax expense, which excludes operating and maintenance expense, depreciation, taxes other than income taxes and income tax expense.  These items are included in our calculation of operating income as reflected in our Consolidated Statements of Income.  Revenues include natural gas costs, which are passed directly through to customers without markup, subject to Illinois Commission review, and revenue taxes, for which we earn a small administrative fee.  We believe margin is a better indicator than operating revenues because these items often cause significant fluctuations in revenues, with equal and offsetting fluctuations in cost of gas and revenue tax expense, and no direct impact on margin.  Margin should not be considered an alternative to, or more meaningful indication of our operating performance than operating revenues, as determined in accordance with GAAP.  In addition, our margin may not be comparable to a similarly titled measure of another company.  We have a franchise gas cost recovery rider, a rider to recover the costs associated with energy efficiency programs, and effective February 2010, a bad debt rider.  Changes in revenue included in margin attributable to these riders are expected to generally be offset by changes within operating and maintenance expense with generally no impact on operating income.

A reconciliation of revenues and margin follows:

In millions	2011			2010			2009
Revenues	$	2,064		$	2,204		$	2,141
Cost of gas		(1,260	)		(1,364	)		(1,346	)
Revenue tax expense		(154	)		(146	)		(148	)
Margin	$	650		$	694		$	647

Margin decreased $44 million in 2011 compared to the prior year.  Margin includes the revenue from the riders noted above which totaled $3 million in 2011 and $49 million in 2010.  Margin excluding those riders increased $2 million compared to the prior year due to higher demand unrelated to weather (approximately $2 million increase) and colder weather (approximately $1 million increase), partially offset by lower interest on customer balances (approximately $1 million decrease).

Margin increased $47 million in 2010 compared to the prior year.  Revenues from the riders noted above totaled $49 million in 2010 and $6 million in 2009.  Margin excluding those riders increased $4 million compared to the prior year due primarily to the impact of the increase in base rates (approximately $20 million increase), partially offset by warmer weather in 2010 (approximately $8 million decrease), lower interest on customer balances ($6 million decrease) and lower demand unrelated to weather (approximately $4 million decrease).

Operating and maintenance expense.  Operating and maintenance expense decreased $2 million in 2011 compared to the prior year.  Operating and maintenance expense related to riders noted above decreased $46 million compared to the prior year.  Excluding the impact of such riders, operating and maintenance expense increased $44 million compared to the prior year due to the absence of 2010’s recovery of 2008 and 2009 bad debt expense under the bad debt rider ($32 million) and higher workers’ compensation and general claims expense ($11 million increase) principally due to changes in estimates as our methodologies were revised to reflect how our new management approaches such matters from a business standpoint.  Total bad debt expense, including the impact of the bad debt rider, was $46 million compared to $64 million in the prior year.  Bad debt expense includes $(17) million in 2011 and $33 million in 2010 of expense (income) which is equal to the revenue recognized under the bad debt rider and $63 million of expense assumed to be collected through base rates in both years.  Bad debt expense in 2010 also includes the recognition of the $32 million benefit associated with the net under recovery of bad debt expense from 2008 and 2009.

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Operating and maintenance expense decreased $1 million in 2010 compared to the prior year.  Operating and maintenance expense related to riders noted above increased $43 million compared to the prior year which includes $33 million related to the bad debt rider that was implemented in 2010.  Excluding the impact of such riders, operating and maintenance expense decreased $44 million compared to the prior year due primarily to the recognition of the $32 million benefit associated with the net under recovery of bad debt expense from 2008 and 2009.  Other factors contributing to the decrease include lower company use and storage-related gas costs ($8 million decrease), lower pension expense ($5 million decrease), lower billing and call center-related costs ($3 million decrease), lower costs on legal matters ($3 million decrease) and higher bad debt expense ($10 million increase).  Bad debt expense in 2010 was $64 million compared to $53 million in the prior year.

Other operating expenses.  In the fourth quarter of 2011, we recorded an unfavorable adjustment of $37 million to our previously recorded liability associated with our PBR plan.  Additional information about the PBR plan is presented in Item 8 – Financial Statements and Supplementary Data – Note 7 – Commitments, Guarantees and Contingencies.

Income tax expense.  The effective income tax rate was 35.5% in 2011, 37.0% in 2010 and 35.0% in 2009. The lower effective income tax rate in 2011 compared to 2010 is due primarily to the lower pretax income in 2011 (which causes a lower effective income tax rate since tax credits are a larger share of pretax income), partially offset by an increase in the Illinois state income tax rate from 7.3% in 2010 to 9.5% in 2011.  The higher effective income tax rate in 2010 compared to the prior year is due primarily to higher pretax income (which causes a higher effective income tax rate since permanent differences and tax credits are a smaller share of pretax income) and the unfavorable impact of the tax law change with respect to Medicare Part D subsidies.

Interest expense.  The following table provides additional detail on interest expense for the last three years.

In millions	2011			2010			2009
Interest expense	$	32		$	36		$	37
Average debt outstanding (1)	$	729		$	769		$	891
Average rate		4.4	%		4.7	%		4.2	%

(1)   Daily average of all outstanding debt.

Interest expense decreased $4 million in 2011 compared to the prior year due to lower average interest rates ($3 million decrease) and lower interest on income tax matters ($2 million decrease), partially offset by higher bank commitment fees ($1 million increase).  Lower average interest rates were due to the February 2011 refinancing of $75 million first mortgage bonds.  Interest expense decreased $1 million in 2010 compared to the prior year.  Factors contributing to the decrease were lower interest on income tax matters ($2 million decrease), higher average long-term debt borrowing levels ($1 million increase) and higher bank commitment fees ($1 million increase).

Operating metrics.Selected weather, revenue, customer and volume metrics for 2011, 2010 and 2009, which we consider to be some of the key performance indicators for our business, are presented in the following tables.  We measure the effects of weather on our business through Heating Degree Days. Generally, increased Heating Degree Days result in greater demand for gas on our distribution system. 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 present the effects of weather and our customers’ demand for natural gas.

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Weather
Heating Degree Days (1)
	Normal	2011	2010	2009	2011 vs. 2010 colder (warmer)	2010 vs. 2009 colder (warmer)	2011 vs. normal colder (warmer)	2010 vs. normal colder (warmer)	2009 vs. normal colder (warmer)
Year ended December 31,	5,600	5,892	5,720	6,106	3%	(6)%	5%	2%	9%
(1)  Obtained from the Chicago Midway Airport weather station.  Normal represents a ten-year average from 1998 through 2007, which was established in our last rate case.

Operating Revenues	Year ended December 31,			2011 vs. 2010	2010 vs. 2009
In millions	2011	2010	2009	% change	% change
Sales
Residential	$     1,327	$     1,444	$     1,378	(8.1)%	4.8 %
Commercial	334	356	351	(6.2)%	1.4 %
Industrial	38	40	38	(5.0)%	5.3 %
Total sales	1,699	1,840	1,767	(7.7)%	4.1 %
Transportation
Residential	43	46	47	(6.5)%	(2.1)%
Commercial	75	75	79	-	(5.1)%
Industrial	42	40	40	5.0 %	-
Other	2	2	4	-	(50.0)%
Total transportation	162	163	170	(.6)%	(4.1)%
Other revenues
Revenue taxes	155	148	150	4.7 %	(1.3)%
Customer late fees	17	18	24	(5.6)%	(25.0)%
Energy efficiency plan	12	12	3	-	300.0 %
Environmental cost recovery	6	11	12	(45.5)%	(8.3)%
Chicago Hub	2	4	8	(50.0)%	(50.0)%
Other	11	8	7	37.5 %	14.3 %
Total other revenues	203	201	204	1.0 %	(1.5)%
Total operating revenues	$     2,064	$     2,204	$     2,141	(6.4)%	2.9 %
In dollars
Average gas cost per Mcf sold	$       4.99	$       5.49	$       5.06	(9.1)%	8.5 %
Average Customers	Year ended December 31,			2011 vs. 2010	2010 vs. 2009
In thousands	2011	2010	2009	% change	% change
Sales
Residential	1,791	1,775	1,759	.9 %	.9 %
Commercial	134	131	130	2.3 %	.8 %
Industrial	8	8	7	-	14.3 %
Total sales	1,933	1,914	1,896	1.0 %	.9 %
Transportation
Residential	202	210	220	(3.8)%	(4.5)%
Commercial	46	48	52	(4.2)%	(7.7)%
Industrial	4	5	5	(20.0)%	-
Total transportation	252	263	277	(4.2)%	(5.1)%
Total customers	2,185	2,177	2,173	.4 %	.2 %
Volumes
In billion cubic feet (Bcf)	Year ended December 31,			2011 vs. 2010	2010 vs. 2009
	2011	2010	2009	% change	% change
Sales
Residential	192	188	200	2.1 %	(6.0)%
Commercial	50	49	53	2.0 %	(7.5)%
Industrial	6	6	6	-	-
Total sales	248	243	259	2.1 %	(6.2)%
Transportation
Residential	22	23	25	(4.3)%	(8.0)%
Commercial	85	83	90	2.4 %	(7.8)%
Industrial	107	105	102	1.9 %	2.9 %
Total transportation	214	211	217	1.4 %	(2.8)%
Total volumes	462	454	476	1.8 %	(4.6)%

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LIQUIDITY AND CAPITAL RESOURCES

Overview The acquisition of natural gas and pipeline capacity and working capital requirements are our most significant short-term financing requirements.  The need for long-term capital is driven primarily by capital expenditures and maturities of long-term debt. The liquidity required to fund our working capital, capital expenditures and other cash needs is primarily provided by our operating activities.  Our short-term cash requirements not met by cash from operations are primarily satisfied with short-term borrowings under our commercial paper program, which is supported by our credit facility.  We regularly evaluate our funding strategy and profile to ensure that we have sufficient liquidity for our short-term and long-term needs in a cost-effective manner.

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

Our issuance of long-term debt is subject to customary approval or review by state and federal regulatory bodies including the Illinois Commission and the SEC.

We believe the amounts available to us under our credit facility, through the issuance of debt securities, combined with cash provided by operating activities, will continue to allow us to meet our needs for working capital, capital expenditures, anticipated debt redemptions, interest payments on debt obligations, dividend payments and other cash needs through the next several years. Our ability to satisfy our working capital requirements and our debt service obligations, or fund planned capital expenditures, will substantially depend upon our future operating performance (which will be affected by prevailing economic conditions), and financial, business and other factors, some of which we are unable to control. These factors include, among others, regulatory changes, the price of and demand for natural gas and operational risks.

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

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

Credit ratings and outlooks are opinions subject to ongoing review by the rating agencies and may periodically change.  Each rating should be evaluated independently of other ratings.  The rating agencies regularly review our performance, prospects and financial condition and reevaluate their ratings of our long-term debt and short-term borrowings, our corporate ratings, including our ratings outlook.  There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant.  A credit rating is not a recommendation to buy, sell or hold securities.

Factors we consider important in assessing our credit ratings include our Consolidated Statements of Financial Position leverage, capital spending, earnings, cash flow generation, available liquidity and overall business risks.  We do not have any trigger events in our debt instruments that are tied to changes in our specified credit ratings. The following table summarizes our credit ratings as of December 31, 2011.

	S&P	Moody’s	Fitch
Corporate rating	BBB+	n/a	A
Commercial paper	A-2	P-2	F-1
Senior unsecured	BBB+	A3	A+
Senior secured	A	A1	AA-
Ratings outlook	Stable	Stable	Stable

In December 2011, subsequent to the completion of our merger with AGL Resources, all three of the rating agencies reassessed our credit ratings.  Fitch affirmed our ratings.  S&P downgraded our corporate rating from AA to BBB+ and our commercial paper rating from A-1+ to A-2.  Moody’s downgraded our senior unsecured rating from A2 to A3 and our commercial paper rating from P-1 to P-2.  The downgrades primarily resulted from the new ownership structure with AGL Resources and we do not expect them to materially impact our borrowing costs.

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Our credit ratings depend largely on our financial performance, and a downgrade in our current ratings, particularly below investment grade, will increase our borrowing costs and could limit our access to the commercial paper market.  In addition, we would likely be required to pay a higher interest rate in future financings, and our potential pool of investors and funding sources could decrease.

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

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

Our credit facility also includes a financial covenant that requires us to maintain a ratio of total debt to total capitalization of no more than 70% at the end of any fiscal month. Our ratio of total debt to total capitalization, as calculated in accordance with our debt covenant, includes standby letters of credit and surety bonds and excludes accumulated OCI.  Adjusting for these items, our total debt-to-total capitalization ratio for December 31, 2011 was 60%, which is within our required range.

We were in compliance with all of our debt provisions and covenants, both financial and non-financial, as of December 31, 2011.

Our ratio of total debt to total capitalization is typically greater at the beginning of the Heating Season as we make additional short-term borrowings to fund our natural gas purchases and meet our working capital requirements. Maintaining sufficient cash flow is necessary to maintain attractive credit ratings.  For more information on our default provisions, see Item 8 – Financial Statements and Supplementary Data – Note 6 – Debt.  The components of our total debt to total capitalization ratio, as calculated from our Consolidated Statements of Financial Position, are provided in the following table.

	December 31,
	2011			2010
Short-term debt		29	%		29	%
Long-term debt		31			31
Total debt		60			60
Equity		40			40
Total capitalization		100	%		100	%

Cash Flows

The following table provides a summary of our operating, investing and financing cash flows for the last three years.

In millions	2011			2010			2009
Net cash provided by (used in):
Operating activities	$	293		$	321		$	483
Investing activities		(194	)		(183	)		(188	)
Financing activities		(99	)		(139	)		(296	)
Net decrease in cash and cash equivalents		-			(1	)		(1	)
Cash and cash equivalent at beginning of period		-			1			2
Cash and cash equivalent at end of period	$	-		$	-		$	1

Cash flow from operating activities.  We prepare our Consolidated Statements of Cash Flows using the indirect method.  Under this method, we reconcile net income to cash flows from operating activities by adjusting net income for those items that impact net income but may not result in actual cash receipts or payments during the period.  These reconciling items include depreciation and amortization, deferred income taxes and changes in the Consolidated Statements of Financial Position for working capital from the beginning to the end of the period.

Year-over-year changes in our operating cash flows are due primarily to working capital changes resulting from the impact of weather, the price of natural gas, natural gas storage, the timing of customer collections, payments for natural gas purchases and deferred gas cost recoveries.

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We maintain margin accounts related to financial derivative transactions.  These margin accounts may cause large fluctuations in cash needs or sources in a relatively short period of time due to daily settlements resulting from changes in natural gas futures prices.  We manage these fluctuations with short-term borrowings and investments.

2011 compared to 2010  Net cash flow provided from operating activities decreased $28 million, or 9%, for the year ended December 31, 2011 compared to the prior year.  The significant factors contributing to the decrease in cash flow include:

·   a decrease of $52 million from changes in accounts payable resulting from lower natural gas purchases in December 2011 compared to December 2010;

·   a decrease of $20 million attributable to deferred compensation liabilities paid during 2011; and

·   an increase of $29 million from changes in receivables due to a decrease in volumes sold to our customers as a result of warmer weather in the fourth quarter of 2011 compared to the prior year.

2010 compared to 2009  Net cash flow provided from operating activities decreased $162 million, or 34%, for the year ended December 31, 2010 compared to the prior year.  The significant factors contributing to the decrease in cash flow are primarily a result of lower average natural gas prices at the beginning of the 2009/2010 Heating Season compared to the 2008/2009 Heating Season and include: 

·   a decrease of $155 million from changes in receivables due to higher receivable balances at the end of 2008 versus 2009; and

·   a decrease of $87 million from changes in margin accounts related to derivative instruments due to the decline in natural gas prices.

In addition, we had higher volumes of gas in storage at December 31, 2010 when compared to 2009.

Cash flow from investing activities.  Our net cash used in investing activities consists primarily of PP&E expenditures.  Our estimated capital expenditures for 2012 and our actual capital expenditures incurred are described below.

Capital expenditures increased $11 million, or 6%, to $198 million in 2011 from $187 million in 2010.  Factors contributing to the increase include higher facility construction (approximately $14 million increase) and lower information technology improvements (approximately $5 million decrease).

Capital expenditures decreased $6 million, or 3%, to $187 million in 2010 from $193 million in 2009.  Factors contributing to the decrease include lower expenditures associated with gas distribution, transmission and storage system improvements (approximately $6 million decrease), lower facility construction (approximately $3 million decrease), lower capitalized overhead costs attributable to lower retirement plan benefit costs (approximately $2 million decrease) and higher information technology improvements (approximately $8 million increase).

Capital expenditures are expected to increase $7 million, or 3%, to $205 million in 2012 from $198 million in 2011.  Factors contributing to this expected increase include higher expenditures associated with gas distribution, transmission and storage system improvements, partially offset by lower expenditures associated with facility construction.

Cash flow from financing activities.Our capitalization and financing strategy is intended to ensure that we are properly capitalized with the appropriate mix of equity and debt securities. This strategy includes active management of the percentage of total debt relative to total capitalization, as well as the term and interest rate profile of our debt securities.

Our cash used in financing activities was $99 million in 2011 compared to cash used of $139 million in 2010.  The decreased use of cash of $40 million, or 29%, was due primarily to a decrease in dividends paid.  Our cash used in financing activities was $139 million in 2010 compared to cash used of $296 million in 2009.  The decreased use of cash of $157 million, or 53%, was due primarily to our decreased commercial paper borrowings levels in 2009 as a result of lower working capital requirements.

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Short-term DebtOur short-term debt during 2011 was comprised of borrowings under our commercial paper program and a loan from our affiliate.

In millions	Year-end balance outstanding(1)		Daily average balance outstanding(2)		Minimum balance outstanding (2)		Largest balance outstanding(2)
Commercial paper	$	452	$	214	$	-	$	514
Loan from affiliate		-		15		-		54
Total short-term debt	$	452	$	229	$	-	$	568

(1)   As of December 31, 2011.

(2)   For the year ended December 31, 2011.

The largest, minimum and daily average balances borrowed under our commercial paper program is important when assessing the intra-period fluctuation of our short-term borrowings and any potential liquidity risk.  Our year-end short-term debt outstanding and our largest short-term debt balance outstanding were significantly higher than our average short-term debt outstanding during 2011 due to our seasonal cash requirements.

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

On December 15, 2011, we entered into a $700 million revolving credit facility, which matures on December 15, 2016 to replace the $400 million, 364-day revolving credit facility, which was set to expire in April 2012 and the $600 million, three-year revolving credit facility, which was set to expire in April 2013.  The credit facility supports our commercial paper program and provides the flexibility to meet working capital and other liquidity requirements.  The interest rate payable on borrowings under the credit facility is calculated either at the alternative base rate, plus an applicable interest margin, or LIBOR, plus an applicable interest margin.  The applicable interest margin used in both interest rate calculations will vary according to our current credit ratings.  At December 31, 2011 and 2010, we had no outstanding borrowings under these facilities.

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

The lenders under our credit facility are major financial institutions with investment grade credit ratings as of December 31, 2011. It is possible that one or more lending commitments could be unavailable to us if the lender defaults due to lack of funds or insolvency. However, based on our current assessment of our lenders’ creditworthiness, we believe the risk of lender default is minimal.

Prior to the merger between AGL Resources and Nicor, we participated in a cash management system with other subsidiaries of Nicor.  Under this system, at December 31, 2010, we owed $40 million to Nicor which was repaid in 2011.

Long-term DebtOur long-term debt matures more than one year from December 31, 2011 and consists of first mortgage bonds.  Our long-term cash requirements primarily depend upon the level of capital expenditures, long-term debt maturities and decisions to refinance long-term debt.

In February 2011, we issued $75 million first mortgage bonds at 2.86%, due in 2016 through a private placement and utilized the proceeds to retire the $75 million 6.625% first mortgage bond series which matured in February 2011.

In determining that the bonds issued in 2011 qualified for exemption from registration under Section 4(2) of the Securities Act of 1933, we relied on the facts that the bonds were offered only to a limited number of large institutional investors and each institutional investor that purchased the bonds represented that it was purchasing the bonds for its own account and not with a view to distribute them.

Substantially all gas distribution properties are subject to the lien of the indenture securing our first mortgage bonds.

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First mortgage bonds may be issued by Nicor Gas under an indenture dated as of January 1, 1954, as supplemented and modified, as necessary, among Northern Illinois Gas Company doing business as Nicor Gas Company and The Bank of New York Mellon Trust Company, N.A., as trustee.  At December 31, 2011, we had the capacity to issue approximately $480 million of additional first mortgage bonds under the terms of our indenture.

Dividends on Common Stock.  Our common stock dividend payments were $82 million in 2011, $106 million in 2010 and $70 million in 2009.

Other.  We are restricted by regulation in the amount we can dividend to our parent company.  Dividends are allowed only to the extent of our retained earnings balance.  We currently are prohibited by regulations of the Illinois Commission from loaning money to affiliates.

Off-balance sheet arrangements.  We have certain guarantees, as further described in Item 8 – Financial Statements and Supplementary Data – Note 7 – Commitments, Guarantees and Contingencies.  We believe the likelihood of any such payment under these guarantees is remote.  No liability has been recorded for these guarantees.

Contractual Obligations and Commitments

We have incurred various contractual obligations and financial commitments in the normal course of our operating and financing activities that are reasonably likely to have a material effect on liquidity or the availability of requirements for capital resources. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities. Contingent financial commitments represent obligations that become payable only if certain predefined events occur, such as financial guarantees, and include the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor. The following table illustrates our expected future contractual obligation payments, such as debt and lease agreements, and commitments and contingencies as of December 31, 2011.

In millions	Total		2012		2013 & 2014		2015 & 2016		2017 & thereafter
Recorded contractual obligations:
Long-term debt	$	500	$	-	$	-	$	125	$	375
Short-term debt		452		452		-		-		-
Environmental remediation liabilities (1)		134		19		53		36		26
Total	$	1,086	$	471	$	53	$	161	$	401
Unrecorded contractual obligations and commitments (2)
Gas supply, pipeline charges and storage capacity (3)	$	448	$	254	$	175	$	19	$	-
Interest charges (4)		454		28		56		51		319
Standby letters of credit, performance/surety bonds (5)		7		6		1		-		-
Operating leases (6)		3		1		1		1		-
Other (7)		11		3		4		4		-
Total	$	923	$	292	$	237	$	75	$	319

(1)   Costs are recoverable through a rate rider mechanism, subject to Illinois Commission review.

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

(3)   Costs are primarily recoverable through a natural gas cost recovery mechanism, subject to Illinois Commission review.  The gas supply amount includes amounts for our commodity purchase commitments of 56 Bcf at floating gas prices calculated using forward natural gas prices as of December 31, 2011.  Also includes $2 million of fixed price charges related to commodity purchase commitments that are recorded in our Consolidated Statements of Financial Position.

(4)   In addition, as of December 31, 2011, we have $6 million of accrued interest in our Consolidated Statements of Financial Position that will be paid in 2012.

(5)   We provide guarantees to certain municipalities and other agencies in support of payment obligations.

(6)   Operating leases are primarily for real estate licenses.

(7)   Includes purchase commitments related primarily to future equipment purchases.

In addition, we have $2 million of mandatorily redeemable preferred stock which is payable ratably between 2012 and 2017 and is recorded on our Consolidated Statements of Financial Position.

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We also have long-term obligations for retirement plan benefits which are not included in the above table.  In 2012, we expect to make no contributions to our pension plan and expect to contribute about $15 million (before Medicare subsidies) to our retiree medical plan.  Additional information regarding our obligations for retirement plan benefits can be found in Item 8 – Financial Statements and Supplementary Data – Note 5 – Employee Benefit Plans.

Pursuant to an Illinois law enacted in 2011, we signed an agreement in the third quarter of 2011 to purchase approximately 25 Bcf of SNG annually from a proposed coal gasification plant for a 10-year term beginning as early as 2015.  Since the agreement is contingent upon various milestones to be achieved by the counterparty to the agreement, our obligation is not certain at this time.  For additional information on the SNG plant legislation, see caption “Legislative and regulatory update.”

CONTINGENCIES

The following contingencies are in various stages of investigation or disposition.  Although in some cases we are unable to estimate the amount of loss reasonably possible in addition to any amounts already recognized, it is possible that the resolution of these contingencies, either individually or in aggregate, will require us to take charges against, or will result in reductions in, future earnings.  It is the opinion of our management that the resolution of these contingencies, either individually or in aggregate, could be material to earnings in a particular period but is not expected to have a material adverse impact on our liquidity or financial condition.

PBR plan.  Our PBR plan for natural gas costs went into effect on January 1, 2000 and was terminated by us effective January 1, 2003.  Under the PBR plan, our 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 is currently under Illinois Commission review.  There are allegations that we acted improperly in connection with the PBR plan, and the Illinois Commission and others are reviewing these allegations.  On June 27, 2002, the Citizens Utility Board (“CUB”) filed a motion to reopen the record in the Illinois Commission’s proceedings to review the PBR plan (the “Illinois Commission Proceedings”).  As a result of the motion to reopen, we entered into a stipulation with the staff of the Illinois Commission and CUB providing for additional discovery.  The Illinois Attorney General’s Office (“IAGO”) has also intervened in this matter.  In addition, the IAGO issued Civil Investigation Demands (“CIDs”) to CUB and the Illinois Commission staff.  The CIDs ordered that CUB and the Illinois Commission staff produce all documents relating to any claims that we may have presented, or caused to be presented, false information related to our PBR plan.  We have committed to cooperate fully in the reviews of the PBR plan.

In response to these allegations, on July 18, 2002, the Nicor Board of Directors appointed a special committee of independent, non-management directors to conduct an inquiry into issues surrounding natural gas purchases, sales, transportation, storage and such other matters as may come to the attention of the special committee in the course of its investigation.  The special committee presented the report of its counsel (“Report”) to Nicor’s Board of Directors on October 28, 2002.  

In response, the Nicor Board of Directors directed our management to, among other things, make appropriate adjustments to account for, and fully address, the adverse consequences to ratepayers of the items noted in the Report, and conduct a detailed study of the adequacy of internal accounting and regulatory controls.  The adjustments were made in prior years’ financial statements resulting in a $24.8 million liability.  Included in such $24.8 million liability is a $4.1 million loss contingency.  A $1.8 million adjustment to the previously recorded liability, which is discussed below, was made in 2004 increasing the recorded liability to $26.6 million.   By the end of 2003, we completed steps to correct the weaknesses and deficiencies identified in the detailed study of the adequacy of internal controls.

Pursuant to the agreement of all parties, including us, the Illinois Commission re-opened the 1999 and 2000 purchased gas adjustment filings for review of certain transactions related to the PBR plan and consolidated the reviews of the 1999-2002 purchased gas adjustment filings with the PBR plan review.

On February 5, 2003, CUB filed a motion for $27 million in sanctions against us in the Illinois Commission Proceedings.  In that motion, CUB alleged that our responses to certain CUB data requests were false.  Also on February 5, 2003, CUB stated in a press release that, in addition to $27 million in sanctions, it would seek additional refunds to consumers.  On March 5, 2003, the Illinois Commission staff filed a response brief in support of CUB’s motion for sanctions.  On May 1, 2003, the Administrative Law Judges assigned to the proceeding issued a ruling denying CUB’s motion for sanctions.  CUB has filed an appeal of the motion for sanctions with the Illinois Commission, and the Illinois Commission has indicated that it will not rule on the appeal until the final disposition of the Illinois Commission Proceedings.  It is not possible to determine how the Illinois Commission will resolve the claims of CUB or other parties to the Illinois Commission Proceedings.

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In 2004, we became aware of additional information relating to the activities of individuals affecting the PBR plan for the period from 1999 through 2002, including information consisting of third party documents and recordings of telephone conversations from Entergy-Koch Trading, LP (“EKT”), a natural gas, storage and transportation trader and consultant with whom we did business under the PBR plan.  Review of additional information completed in 2004 resulted in the $1.8 million adjustment to the previously recorded liability referenced above.

The evidentiary hearings on this matter were stayed in 2004 in order to permit the parties to undertake additional third party discovery from EKT.  In December 2006, the additional third party discovery from EKT was obtained and the Administrative Law Judges issued a scheduling order that provided for us to submit direct testimony by April 13, 2007.  We submitted direct testimony in April 2007, rebuttal testimony in April 2011 and surrebuttal testimony in December 2011.  In surrebuttal testimony, we sought approximately $6 million, which included interest due to us of $2.0 million as of December 31, 2011.  The staff of the Illinois Commission, IAGO and CUB submitted direct testimony to the Illinois Commission in April 2009 and rebuttal testimony in October 2011.  In rebuttal testimony, the staff of the Illinois Commission, IAGO and CUB requested refunds of $85 million, $255 million and $305 million, respectively.

In February 2012, we committed to a stipulated resolution of issues with the Staff of the Illinois Commission, which includes crediting our customers $64 million, but does not constitute an admission of fault.  This resulted in a $37.4 million pretax charge to our results in the fourth quarter of 2011, which represents the difference between the $64 million proposed credit and our previously recorded $26.6 million liability.  The stipulated resolution is subject to review and approval by the Illinois Commission.  CUB and IAGO are not parties to the 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 are unable to predict the outcome of the Illinois Commission’s review or our potential exposure.  Because the PBR plan and historical gas costs are still under Illinois Commission review, the final outcome could be materially different from the amounts reflected in our financial statements as of December 31, 2011.

Environmental remediation costs.  We are conducting environmental investigations and remedial activities at former manufactured gas plant sites.  Additional information about these sites is presented in Item 8 – Financial Statements and Supplementary Data – Note 7 – Commitments, Guarantees and Contingencies.

Municipal tax matters.  Information about municipal tax contingencies is presented in Item 8 – Financial Statements and Supplementary Data – Note 7 – Commitments, Guarantees and Contingencies.

Nicor Services Warranty Product Actions. Information about warranty product contingencies is presented in Item 8 – Financial Statements and Supplementary Data – Note 7 – Commitments, Guarantees and Contingencies.

Illinois Attorney General Subpoena.  Information about the Illinois Attorney General subpoena is presented in Item 8 – Financial Statements and Supplementary Data – Note 7 – Commitments, Guarantees and Contingencies.

Other.We are involved in legal or administrative proceedings before various courts and agencies with respect to general claims, taxes, environmental, gas cost prudence reviews and other matters.  See Item 8 – Financial Statements and Supplementary Data – Note 7 – Commitments, Guarantees and Contingencies.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

We believe that of our significant accounting policies described in Item 8 – Financial Statements and Supplementary Data – Note 2 – Significant Accounting Policies and Methods of Application, the following policies represent those that may involve a higher degree of uncertainty, judgment and complexity; these include Contingencies, Environmental remediation costs, Derivative and hedging activities, Pension and retiree medical plan benefits, Credit risk, Unbilled revenues and Regulatory assets and liabilities.

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Contingencies.  Our accounting policies for contingencies cover a variety of business activities, including contingencies for potentially uncollectible receivables, rate matters, and legal and environmental exposures.  We accrue for these contingencies, including related legal defense costs, when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered, and an amount can be reasonably estimated in accordance with authoritative guidance related to contingencies.  We base our estimates for these liabilities on currently available facts and our estimates of the ultimate outcome or resolution of the liability in the future.  When only a range of potential loss is estimable, we record a liability for the minimum amount of potential loss.

Actual results may differ from estimates, and estimates can be, and often are, revised either negatively or positively, depending on actual outcomes or changes in the facts or expectations surrounding each potential exposure.  Changes in the estimates related to contingencies could have a negative impact on our results of operations, cash flows or financial position.  Our contingencies are further discussed in Item 8 – Financial Statements and Supplementary Data – Note 7 – Commitments, Guarantees and Contingencies.

Environmental remediation costs.  We are subject to legislation and regulation by federal, state and local authorities with respect to environmental matters. Additionally, we owned and operated a number of manufactured gas plant sites at which hazardous substances may be present. We have identified 26 sites for which we may have some responsibility.  Most of these sites are not presently owned by us.  In accordance with GAAP, we have established reserves for environmental remediation obligations when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated. These estimates contain various engineering uncertainties, and we continuously attempt to refine these estimates.

We cannot perform precise engineering soil and groundwater cleanup estimates for certain of our former manufactured gas plant sites. As we continue to conduct the actual remediation and enter into cleanup contracts, we are increasingly able to provide conventional engineering estimates of the likely costs of many elements of the remediation program and the liabilities may increase as estimates are refined and remediation efforts proceed.  We report estimates of future environmental remediation costs on an undiscounted basis.  Our ERC liabilities for certain of our sites are estimated based on probabilistic models of potential costs.  These probabilistic models have not been performed on all of our sites, but are expected to be completed in 2012.  Based on the estimates that we have performed, the cleanup cost estimates range from $134 million to $216 million.  Our liability for environmental remediation costs at December 31, 2011 is $134 million, of which $19 million is expected to be paid over the next twelve months.  Our liability increased by $81 million in the fourth quarter of 2011 primarily as a result of the completion of a probabilistic model for one of our major sites.  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.

Details of our environmental remediation costs are discussed in Item 8 – Financial Statements and Supplementary Data – Note 2 – Significant Accounting Policies and Methods of Application and Note 7 – Commitments, Guarantees and Contingencies.

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

We use derivative instruments for the purchase of natural gas for our customers.  These derivatives are reflected at fair value and are not designated as hedges.  Realized gains or losses on such instruments are included in the cost of gas delivered and are passed through directly to customers, subject to review by the Illinois Commission, and therefore have no direct impact on earnings. Unrealized changes in the fair value of these derivative instruments are deferred as regulatory assets or liabilities.

We also enter into swap agreements to reduce the earnings volatility of certain forecasted operating costs arising from fluctuations in natural gas prices, such as the purchase of natural gas for use in company operations.  These derivative instruments are carried at fair value.  To the extent hedge accounting is not elected, changes in such fair values are immediately recorded in the current period as operating and maintenance expense.

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Additionally, as required by the authoritative guidance, we are required to classify our derivative assets and liabilities based on the lowest level of input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair value of our derivative instruments incorporates various factors required under the guidance. These factors include:

·   the creditworthiness of the counterparties involved

·   events specific to a given counterparty

·   the impact of our nonperformance risk on our liabilities.

We have recorded derivative instrument assets of $3 million at December 31, 2011 and $8 million at December 31, 2010.  Additionally, we have recorded derivative liabilities of $25 million at December 31, 2011 and $54 million at December 31, 2010.

If there is a significant change in the underlying market prices or pricing assumptions we use in pricing our derivative assets or liabilities, we may experience a significant impact on our financial position, results of operations and cash flows.  Our derivative and hedging activities are described in further detail in Item 8 – Financial Statements and Supplementary Data – Note 2 – Significant Accounting Policies and Methods of Application.

Pension and retiree medical plan benefits.  We maintain a noncontributory defined benefit pension plan and a defined benefit retiree medical plan that provides health care and life insurance benefits to eligible retired employees.Our pension and retiree medical plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates. We annually review the estimates and assumptions underlying our pension and retiree medical plan costs and liabilities and update them when appropriate. The critical actuarial assumptions used to develop the required estimates for our pension and retiree medical plan include the following key factors:

·   assumed discount rates

·   expected return on plan assets

·   the market value of plan assets

·   assumed mortality table

·   assumed health care costs

·   assumed compensation increases

·   assumed rates of retirement

·   assumed rates of termination

The discount rate is utilized in calculating the actuarial present value of our pension and retiree medical plan obligations and our annual net pension and retiree medical plan costs.  We based our discount rate on a yield curve provided by our actuaries that is derived from a portfolio of high quality (rated AA or better) corporate bonds and the equivalent annuity cash flows.

The expected long-term rate of return on assets is used to calculate the expected return on plan assets component of our annual pension plan cost.  We estimate the expected return on plan assets by evaluating expected bond returns, equity risk premiums, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical and projected returns for each investment asset category.  We also consider guidance from our investment advisors in making a final determination of our expected rate of return on assets. To the extent the actual rate of return on assets realized over the course of a year is greater than or less than the assumed rate, that year’s annual pension plan cost is not affected.  Rather, this gain or loss reduces or increases future pension plan costs.  Differences between actuarial assumptions and actual plan results are deferred and amortized into cost when the accumulated differences exceed 10% of the greater of the projected benefit obligation (PBO) or the fair value of plan assets.  If necessary, the excess is amortized over the remaining service period of active employees covered by the plans (approximately 9 years for the pension plan and 11 years for the retiree medical plan).

During 2011, we recorded net periodic benefit costs (net of capitalization) of $19 million related to our pension and retiree medical benefit plans.  We estimate that in 2012, we will record net periodic pension and retiree medical plan benefit costs (net of capitalization) of $27 million, an $8 million increase compared to 2011. In determining our estimated expenses for 2012, our actuarial consultant assumed an 8.25% expected return on plan assets and the following discount rates.

	Pension plan			Retiree medical plan
Discount rate		4.60	%		4.50	%

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

			In millions
Actuarial assumptions	Percentage-point change in assumption		Increase (decrease) in PBO/APBO		Increase (decrease) in cost
Expected long-term return on plan assets		+/- 1%	$	- / -	$	(4) / 4
Discount rate		+/- 1%		(79) / 86		(7) / 7

See Item 8 – Financial Statements and Supplementary Data – Note 5 – Employee Benefit Plans for additional information.

Credit risk.  We are required to estimate counterparty credit risk in estimating the fair values of certain derivative instruments.  Our counterparties consist primarily of major energy companies and financial institutions.  This concentration of counterparties may materially impact our exposure to credit risk resulting from market, economic or regulatory conditions.  To manage this credit risk, we believe we maintain prudent credit policies to determine and monitor the creditworthiness of our counterparties.  In doing so, we seek guarantees or collateral, in the form of cash or letters of credit, we limit our exposure to any one counterparty, and, in some instances, we enter into netting arrangements to mitigate counterparty credit risk.  However, the volatility in the capital markets over the past several years has made it more difficult for us to assess the creditworthiness of our counterparties.  Based on this uncertainty, actual losses relating to credit risk could materially vary from our estimates.

We maintain an allowance for doubtful accounts for estimated losses from the failure of our customers to make required payments.  Such estimates are based on historical experience, existing economic conditions and certain collection-related patterns.  Circumstances which could affect these estimates include, but are not limited to, customer credit issues, natural gas prices, customer deposits and economic conditions.  Actual credit losses could vary materially from our estimates.  Our allowance for doubtful accounts was $21 million at December 31, 2011, $25 million at December 31, 2010 and $31 million at December 31, 2009, as presented on Schedule II in Item 15 - Exhibits, Financial Statement Schedules.  The credit risk exposure is substantially mitigated by the bad debt rider that was approved by the Illinois Commission on February 2, 2010.  The bad debt rider provides for the recovery from (or refund to) customers of the difference between our actual bad debt experience on an annual basis and the benchmark bad debt expense included in our rates for the respective year.

Unbilled revenues.  We accrue revenues for estimated deliveries not yet billed to customers from the date of their last bill until the balance sheet date.  Accrued unbilled revenue estimates are dependent upon a number of customer-usage factors which require management judgment, including weather factors.  These estimates are adjusted when actual billings occur, and variances in estimates can be material.  Accrued unbilled revenues were $107 million at December 31, 2011 and $142 million at December 31, 2010.

Regulatory assets and liabilities.  We account for the financial effects of regulation in accordance with authoritative guidance related to regulated entities whose rates are designed to recover the costs of providing service.  In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense in the current period are capitalized and recorded as regulatory assets when it is probable that such costs or expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Generally, regulatory assets are amortized into expense and regulatory liabilities are amortized into income over the period authorized by the Illinois Commission.  If our operations become no longer subject to rate regulation, a write-off of net regulatory liabilities would be required.  Additional information on regulatory assets and liabilities is presented in Item 8 – Financial Statements and Supplementary Data – Note 2 – Significant Accounting Policies and Methods of Application.

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ACCOUNTING DEVELOPMENTS

On May 12, 2011, the FASB issued authoritative guidance related to fair value measurements. The guidance expands the qualitative and quantitative disclosures for Level 3 significant unobservable inputs, permits the use of premiums and discounts to value an instrument if it is standard practice and limits best use valuation to non-financial assets and liabilities. This guidance will be effective for us beginning January 1, 2012. We do not expect the guidance to have a material impact on our consolidated financial statements.

On June 16, 2011, the FASB issued authoritative guidance related to comprehensive income. The guidance eliminates the option to present OCI in the Statements of Equity, but instead allows companies to elect to present net income and OCI in one continuous statement (Statements of Comprehensive Income) or in two consecutive statements. This guidance does not change any of the components of net income or OCI. This guidance will be effective for us beginning January 1, 2012, and will not have a material impact on our consolidated financial statements.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to risks associated with natural gas prices, interest rates and credit. Natural gas price risk is defined as the potential loss that we may incur as a result of changes in the fair value of natural gas. Interest rate risk results from our portfolio of debt instruments that we issue to provide financing and liquidity for our business. Credit risk results from the extension of credit throughout all aspects of our business.

Natural Gas Price Risk

We are authorized to use a natural gas cost recovery mechanism that allows us to adjust rates to reflect changes in the wholesale cost of natural gas and to ensure we recover all of the costs prudently incurred in purchasing gas for our customers.  We enter into derivative instruments to hedge the impact of market fluctuations in natural gas prices for customers.  These derivatives are reflected at fair value and are not designated as hedges.  Realized gains or losses on such instruments are included in the cost of gas delivered and are passed through directly to customers and therefore have no direct impact on earnings.  Unrealized changes in the fair value of these derivative instruments are deferred as regulatory assets or liabilities.

Substantial changes in natural gas prices may impact our earnings by increasing or decreasing the cost of gas used, storage-related gas costs, and other operating and financing expenses. We expect to purchase about 2 Bcf of natural gas in 2012 for our own use and to cover storage-related gas costs.  The level of natural gas prices may also impact customer gas consumption and therefore margin. The actual impact of natural gas price fluctuations on our earnings is dependent upon several factors, including our hedging practices. We generally hedge a portion of our forecasted company use and storage-related gas costs through the use of swap agreements.

Interest Rate Risk

We manage interest rate risk by issuing primarily fixed-rate long-term debt with varying maturities, refinancing certain debt and, at times, hedging the interest rate on anticipated borrowings.  Interest rate fluctuations expose our commercial paper to changes in interest expense and cash flows. Based on the average variable-rate commercial paper for 2011, a 100 basis point change in market interest rates would have resulted in an increase in pretax interest expense of approximately $2 million on an annualized basis.

Credit Risk

We havea diversified customer base, which limits our exposure to concentrations of credit risk in any one industry or income class and we believe that we maintain prudent credit policies.  Additionally, we offer options to help customers manage their bills, such as energy assistance programs for low-income customers and a budget payment plan that spreads gas bills more evenly throughout the year.  Customer credit risk has been substantially mitigated by the bad debt rider approved by the Illinois Commission on February 2, 2010. The bad debt rider provides for the recovery from (or refund to) customers of the difference between our actual bad debt experience on an annual basis and the benchmark bad debt expense included in our rates for the respective year.

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We are also exposed to credit risk in the event a counterparty, customer or supplier defaults on a contract to pay for or deliver product at agreed-upon terms and conditions.  To manage this credit risk, we believe that we maintain prudent credit policies to determine and monitor the creditworthiness of counterparties.  In doing so, we seek guarantees or collateral, in the form of cash or letters of credit, we limit our exposure to any one counterparty, and, in some instances, we enter into netting arrangements to mitigate counterparty credit risk.  However, the volatility in the capital markets over the past three years has made it more difficult for us to assess the creditworthiness of our counterparties.  Based on this uncertainty, we have taken additional steps including, but not limited to, reducing available credit to some of our counterparties.

Certain of our derivative instruments contain credit-risk-related or other contingent features that could increase the payments for collateral we post in the normal course of business when our financial instruments are in net liability positions. As of December 31, 2011 for agreements with such features, our derivative instruments with liability fair values totaled approximately $6 million for which we had posted no collateral to our counterparties. If it was assumed that we had to post the maximum contractually specified collateral or settle the liability, we would have been required to pay approximately $6 million at December 31, 2011.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of Northern Illinois Gas Company

In our opinion, the accompanying consolidated statements of financial position and the related consolidated statements of income, retained earnings, comprehensive income, and cash flows present fairly, in all material respects, the financial position of Northern Illinois Gas Company and its subsidiary (the "Company")at December 31, 2011, and the results of their operations and their cash flows for the year ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America.  In addition, in our opinion, the financial statement schedule listed in the accompanying index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein for  the year ended December 31, 2011 when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit.  We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Chicago, Illinois

February 22, 2012

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of Northern Illinois Gas Company

We have audited the accompanying consolidated statements of financial position of Northern Illinois Gas Company and subsidiary (the "Company") as of December 31, 2010, and the related consolidated statements of income, retained earnings, comprehensive income, and cash flows for each of the two years in the period ended December 31, 2010. Our audits also included the 2010 and 2009 financial statement schedule at Item 15(a)(2). These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Northern Illinois Gas Company and subsidiary as of December 31, 2010, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the 2010 and 2009 basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Chicago, Illinois

February 24, 2011

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Management’s Report on Internal Control Over Financial Reporting

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

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

Based on our evaluation under the framework in Internal Control – Integrated Framework issued by COSO, our management concluded that our internal control over financial reporting was effective as of December 31, 2011, in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting.  Management’s report was not subject to attestation by our registered public accounting firm pursuant to the rules of the SEC that permit us to provide only management’s report in this annual report.

February 22, 2012

/s/ Henry P. Linginfelter

Henry P. Linginfelter

Chairman and Chief Executive Officer

/s/ Andrew W. Evans

Andrew W. Evans

Executive Vice President and Chief Financial Officer

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Nicor Gas Company
Consolidated Statements of Financial Position - Assets
	As of December 31,
In millions	2011		2010
Gas distribution plant, at cost	$	4,889	$	4,734
Less accumulated depreciation		1,961		1,879
Gas distribution plant, net (Note 2)		2,928		2,855
Current assets
Receivables, less allowances of $21 in 2011 and $25 in 2010 (Note 2)		328		378
Receivables - affiliates		8		10
Gas in storage (Note 2)		116		119
Deferred income taxes (Note 2 and Note 8)		41		26
Derivative instruments (Note 2, Note 3 and Note 4)		2		7
Margin accounts - derivative instruments (Note 2 and Note 4)		21		50
Other		60		73
Total current assets		576		663
Regulatory retirement plan asset (Note 2 and Note 5)		253		193
Other assets		191		144
Total assets	$	3,948	$	3,855
See Notes to Consolidated Financial Statements

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Nicor Gas Company
Consolidated Statements of Financial Position - Capitalization and Liabilities
	As of December 31,
In millions, except share amounts	2011			2010
Capitalization
Long-term debt, net of unamortized discount (Note 3 and Note 6)	$	499		$	498
Preferred stock, cumulative, $100 par value per share, 800,000 shares authorized
Mandatorily redeemable preferred stock, 4.48% and 5.00% series, 18,000 shares outstanding in 2011 and 21,000 shares
outstanding in 2010, net of amount due within one year		2			2
Nonredeemable preferred stock, 4.60% and 5.00% convertible series, 14,008 shares outstanding		1			1
Common equity
Common stock, $5 par value per share, 25,000,000 shares authorized, 32,365 shares reserved for share-based awards
and 15,232,414 shares outstanding		76			76
Paid-in capital		108			108
Retained earnings		465			472
Accumulated other comprehensive loss
Cash flow hedges		(1	)		(1	)
Retirement plans		(8	)		(6	)
Total accumulated other comprehensive loss		(9	)		(7	)
Total common equity		640			649
Total capitalization		1,142			1,150
Current liabilities
Short-term debt - affiliates (Note 6 and Note 9)		-			40
Short-term debt - other (Note 6)		452			425
Accounts payable		138			239
Customer credit balances and deposits		102			111
Derivative instruments (Note 2, Note 3 and Note 4)		25			50
Other		129			112
Total current liabilities		846			977
Deferred credits and other liabilities
Regulatory asset retirement liability (Note 2)		896			844
Deferred income taxes (Note 2 and Note 8)		401			365
Retiree medical plan benefits (Note 2 and Note 5)		269			230
Asset retirement obligation (Note 2 and Note 7)		200			191
Other		194			98
Total deferred credits and other liabilities		1,960			1,728
Commitments, guarantees and contingencies (Note 7)
Total capitalization and liabilities	$	3,948		$	3,855
See Notes to Consolidated Financial Statements

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Nicor Gas Company
Consolidated Statements of Income
	Years ended December 31,
In millions	2011			2010		2009
Operating revenues (includes revenue taxes of $155 in 2011, $148 in 2010 and $150 in 2009) (Note 2)	$	2,064		$	2,204	$	2,141
Operating expenses
Cost of gas (Note 2)		1,260			1,364		1,346
Operating and maintenance		295			297		299
Depreciation (Note 2)		189			184		177
Taxes, other than income taxes		172			164		168
Performance-based rate plan (Note 7)		37			-		-
Income tax expense (Note 8)		28			59		40
Total operating expenses		1,981			2,068		2,030
Operating income		83			136		111
Other income (expense), net		(1	)		1		1
Interest expense
Interest on debt, net of amounts capitalized		34			36		34
Other		(2	)		-		3
Total interest expense		32			36		37
Net income	$	50		$	101	$	75
See Notes to Consolidated Financial Statements

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Nicor Gas Company
Consolidated Statements of Comprehensive Income
	Years ended December 31,
In millions	2011			2010			2009
Net income	$	50		$	101		$	75
Other comprehensive income (loss)
Loss on cash flow hedges (net of income tax of $(1) in 2011 and 2010 and $(2) in 2009)		(1	)		(1	)		(2	)
Reclassifications of hedge losses to net income (net of income tax of $1 in 2011 and 2010 and $3 in 2009)		1			1			5
Gains (losses) on retirement plans (net of income tax of $(1) in 2011, $0 in 2010 and $1 in 2009)		(2	)		-			1
Other comprehensive income (loss), net of tax		(2	)		-			4
Comprehensive income	$	48		$	101		$	79
See Notes to Consolidated Financial Statements
Consolidated Statements of Retained Earnings
	Years ended December 31,
In millions	2011			2010			2009
Balance at beginning of year	$	472		$	487		$	480
Net income		50			101			75
Dividends on common stock		(57	)		(116	)		(68	)
Balance at end of year	$	465		$	472		$	487
See Notes to Consolidated Financial Statements

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Nicor Gas Company
Consolidated Statements of Cash Flows
	Years ended December 31,
In millions	2011			2010			2009
Cash flows from operating activities
Net income	$	50		$	101		$	75
Adjustments to reconcile net income to net cash flow provided by operating activities:
Depreciation (Note 2)		189			184			177
Deferred income taxes (Note 2 and Note 8)		19			22			26
Changes in certain assets and liabilities
Receivables, less allowances (Note 2)		52			23			178
Gas in storage (Note 2)		3			(15	)		69
Deferred/accrued gas costs (Note 2)		38			21			25
Derivative instruments (Note 2, Note 3 and Note 4)		(24	)		(14	)		(78	)
Margin accounts - derivative instruments (Note 2 and Note 4)		36			(2	)		85
Pension benefits (Note 5)		46			(15	)		(22	)
Regulatory retirement plan asset (Note 2 and Note 5)		(68	)		2			40
Deferred environmental costs (Note 2)		(109	)		(7	)		1
Other assets		19			28			8
Accounts payable		(99	)		(27	)		(48	)
Customer credit balances and deposits		(9	)		(31	)		(46	)
Retiree medical plan benefits (Note 2 and Note 5)		40			31			4
Accrued environmental remediation costs (Note 7)		106			5			2
Other liabilities		13			27			(4	)
Other items		(9	)		(12	)		(9	)
Net cash flow provided by operating activities		293			321			483
Cash flows from investing activities
Expenditures for property, plant and equipment (Note 2)		(198	)		(187	)		(193	)
Other investing activities		4			4			5
Net cash flow used in investing activities		(194	)		(183	)		(188	)
Cash flows from financing activities
Proceeds from issuing long-term debt		75			-			50
Disbursements to retire long-term obligations		(75	)		(1	)		(50	)
Net issuances (repayments) of commercial paper (Note 6)		27			(69	)		(224	)
Net proceeds (repayments) of loan from affiliates (Note 6)		(40	)		40			-
Dividends paid		(82	)		(106	)		(70	)
Other financing activities		(4	)		(3	)		(2	)
Net cash flow used in financing activities		(99	)		(139	)		(296	)
Net decrease in cash and cash equivalents		-			(1	)		(1	)
Cash and cash equivalents at beginning of period		-			1			2
Cash and cash equivalents at end of period	$	-		$	-		$	1
Cash paid during the period for
Income taxes, net	$	-		$	22		$	6
Interest, net of amounts capitalized		26			28			31
See Notes to Consolidated Financial Statements

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Notes to Consolidated Financial Statements

Note 1 – Organization and Basis of Presentation

General.  Nicor Gas is one of the nation’s largest distributors of natural gas, serving approximately 2.2 million customers in a service territory that encompasses most of the northern third of Illinois, excluding the city of Chicago.  Unless the context requires otherwise, references to “we,” “us,” “our,” the “company,” or “Nicor Gas” mean consolidated Nicor Gas and its wholly owned subsidiary.

On December 9, 2011, the previously announced merger between AGL Resources and Nicor was consummated and we became a wholly owned subsidiary of AGL Resources.  Because of our significant outstanding public debt, the impact of the acquisition (push-down accounting) is not required to be and has not been reflected in our consolidated financial statements.

Basis of Presentation.  Our consolidated financial statements as of and for the period ended December 31, 2011 are prepared in accordance with GAAP and under the rules of the SEC.  Our consolidated financial statements include our accounts and the accounts of our wholly owned subsidiary.  We have eliminated intercompany profits and transactions in consolidation.

Note 2 – Significant Accounting Policies and Methods of Application

General.  Nicor Gas and our affiliates reimburse each other for transactions between the companies.

Statement of Income presentation.  The focus of our Statement of Income presentation is the regulatory treatment of revenues and expenses.  Operating revenues and expenses (including income taxes) on which rate-regulated utility operating income is based are those that ordinarily are included in the determination of utility revenue requirements.

Cash and cash equivalents.  Cash equivalents are comprised of highly liquid investments with an initial maturity of three months or less.

Receivables and allowance for uncollectible accounts.  Our receivables primarily consist of natural gas sales and transportation services billed to residential, commercial and industrial customers.  We bill customers monthly and our accounts receivable are due within 30 days.  For the majority of our receivables, we establish an allowance for doubtful accounts based on our collection experience and other factors.  However, if circumstances change, our estimate of the recoverability of accounts receivable could change as well.  Circumstances that could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Customers’ accounts are written off once we deem them to be uncollectible.

We have a diversified customer base and we maintain prudent credit policies, which limits our exposure to concentrations of credit risk in any one industry or income class.  Additionally, we offer options to help customers manage their bills, such as energy assistance programs for low-income customers and a budget payment plan that spreads gas bills more evenly throughout the year.  Our credit risk exposure is further mitigated by the bad debt rider that was approved by the Illinois Commission on February 2, 2010.  The bad debt rider provides for the recovery from (or refund to) customers of the difference between our actual bad debt experience on an annual basis and the benchmark bad debt expense included in our rates for the respective year.

We accrue revenues for estimated deliveries not yet billed to customers from the date of their last bill until the balance sheet date.  Receivables include accrued unbilled revenues of $107 million at December 31, 2011 and $142 million at December 31, 2010.

Gas in storage.  Our inventory is carried at cost on a LIFO basis.  Based on the average cost of gas purchased in December 2011 and 2010, the estimated replacement cost of inventory exceeded the LIFO cost by $189 million at December 31, 2011 and $227 million at December 31, 2010.

During 2011, we liquidated 0.6 Bcf of our LIFO-based inventory at an average cost per Mcf of $4.61.  For gas purchased in 2011, our average cost per Mcf was $0.28 lower than the average LIFO liquidation rate.  Applying LIFO cost in valuing the liquidation, as opposed to using the average gas purchase cost, had the effect of increasing the cost of gas in 2011 by less than $1 million.

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During 2009, we liquidated 8.8 Bcf of our LIFO-based inventory at an average cost per Mcf of $7.83.  For gas purchased in 2009, our average cost per Mcf was $3.89 lower than the average LIFO liquidation rate.  Applying LIFO cost in valuing the liquidation, as opposed to using the average gas purchase cost, had the effect of increasing the cost of gas in 2009 by $34 million.

There was no liquidation of LIFO layers during 2010.

Since the cost of gas, including inventory costs, is charged to customers without markup, subject to Illinois Commission review, the LIFO liquidations in 2011 and 2009 had no impact on net income.

Fair value measurements.  The carrying values of cash and cash equivalents, receivables, derivative assets and liabilities, accounts payable, short-term debt, pension plan assets, and other current assets and liabilities approximate fair value. See Note 3 – Fair Value Measurements for additional fair value disclosures.

As defined in the authoritative guidance related to fair value measurements and disclosures, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).  We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique.  These inputs can be readily observable, market corroborated, or generally unobservable.  We primarily apply the market approach for recurring fair value measurements to utilize the best available information.  Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.  We are able to classify fair value balances based on the observance of those inputs.  The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).  The three levels of the fair value hierarchy defined by the guidance are as follows:

Level 1 Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.  Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.  Our Level 1 items consist of exchange-traded derivatives and pension plan assets.

Level 2Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.  Level 2 includes those financial and commodity instruments that are valued using valuation methodologies.  These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.  Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.  We obtain market price data from multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the market place.  Instruments in this category include non-exchange-traded derivatives such as over-the-counter swaps and options and pension plan assets.

Level 3Pricing inputs include significant inputs that are generally less observable from objective sources.  These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.  Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs.  Our Level 3 assets and liabilities are primarily related to our natural gas physical delivery contracts such as physical call options.  Transfers into and out of Level 3 reflect the liquidity at the relevant natural gas trading locations and settlement dates which affects the significance of unobservable inputs used in the valuation.  In accordance with accounting guidance, we have elected to determine both transfers into and out of Level 3 using values at the end of the interim period in which the transfer occurred.

The authoritative guidance related to fair value measurements and disclosures also includes a two-step process to determine if the market for a financial asset is inactive and a transaction is not distressed. Currently, this authoritative guidance does not affect us, as all of our derivative instruments are traded in active markets.

Asset retirement obligations.  We record asset retirement obligations associated with the anticipated interim retirement of services, mains and other components of the distribution system and with buildings.  We record legal obligations associated with the retirement of long-lived assets in the period in which the obligation is incurred, if sufficient information exists to reasonably estimate the fair value of the obligation.  When an asset retirement obligation is recorded as a liability, a corresponding amount is recorded as an asset retirement cost (an additional cost of the long-lived asset).  Subsequently, the asset retirement obligation is accreted to the expected settlement amount and the asset retirement cost is depreciated over the life of the asset on a straight-line basis.  We have not recognized an asset retirement obligation

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associated with gathering lines and storage wells because there is insufficient company or industry retirement history to reasonably estimate the fair value of the obligation.

Accumulated removal costs.  Subject to rate regulation, we continue to accrue all future asset retirement costs through depreciation over the lives of our assets even when a legal asset retirement obligation does not exist or insufficient information exists to determine the fair value of the obligation.  Amounts charged to depreciation for future retirement costs, in excess of the normal depreciation and accretion described above, are classified as a regulatory asset retirement liability.

Derivative instruments.As required by the authoritative guidance, derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values incorporates various factors required under the guidance. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our nonperformance risk on our liabilities.  To mitigate the risk that a counterparty to a derivative instrument defaults on settlement or otherwise fails to perform under contractual terms, we have established procedures to monitor the creditworthiness of counterparties, seek guarantees or collateral back-up in the form of cash or letters of credit and, in most instances, enter into netting arrangements.

Cash flows from derivative instruments are recognized in the Consolidated Statements of Cash Flows, and gains and losses are recognized in the Consolidated Statements of Income, in the same categories as the underlying transactions.

Cash flow hedge accounting may be elected only for highly effective hedges, based upon an assessment, performed at least quarterly, of the historical and probable future correlation of cash flows from the derivative instrument to changes in the expected future cash flows of the hedged item.  To the extent cash flow hedge accounting is applied, the effective portion of any changes in the fair value of the derivative instruments is reported as a component of accumulated OCI.  Ineffectiveness, if any, is immediately recognized in operating income.  The amount in accumulated OCI is reclassified to earnings when the forecasted transaction is recognized in the Consolidated Statements of Income, even if the derivative instrument is sold, extinguished or terminated prior to the transaction occurring.  If the forecasted transaction is no longer expected to occur, the amount in accumulated OCI is immediately reclassified to operating income.

Subject to review by the Illinois Commission, we enter into derivative instruments to hedge the impact of market fluctuations in natural gas prices. In accordance with the authoritative guidance related to derivatives and hedging, such derivative transactions are accounted for at fair value each reporting period in our Consolidated Statements of Financial Position.  In accordance with regulatory requirements, realized gains and losses related to these derivatives are reflected in natural gas costs and ultimately included in billings to customers.  Thus, hedge accounting is not elected and, in accordance with accounting guidance pertaining to rate-regulated entities, unrealized changes in the fair value of these derivative instruments are deferred or accrued as regulatory assets or liabilities.

We enter into swap agreements to reduce the earnings volatility of certain forecasted operating costs arising from fluctuations in natural gas prices, such as the purchase of natural gas for company use.  These derivative instruments are carried at fair value.  To the extent hedge accounting is not elected, changes in such fair values are immediately recorded in the current period as operating and maintenance expense.

We maintain margin accounts related to financial derivative transactions.  Our policy is not to offset the fair value of assets and liabilities recognized for derivative instruments or any related margin account.  See Note 4 – Derivative Instruments for additional derivative disclosures.

Debt.  Our long-term debt outstanding is recorded at the principal balance outstanding, net of unamortized discounts.At December 31,2011, we estimated the fair value of debt using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality and risk profile.  At December 31, 2010, we estimated the fair value of debt for our public first mortgage bonds using quoted market pricing information.  For our private first mortgage bonds, we estimate fair value through analysis and evaluation of existing public bonds issued by other utilities that we believe to be comparable in credit rating and bond maturity dates.

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Property, plant and equipment.  Our PP&E consists of property and equipment that is in use or under construction.  We report PP&E at its original cost, which includes:

·   material and labor

·   contractor costs

·   construction overhead costs

We record non-recoverable pad gas as depreciable PP&E and recoverable pad gas as non-depreciable PP&E.  We charge property retired or otherwise disposed of to accumulated depreciation since such costs are recovered in rates.

We recognized no gains or losses on depreciable utility property that is retired or otherwise disposed, as required under the composite depreciation method.  Such gains and losses are ultimately refunded to or recovered from customers through future rate adjustments.

Depreciation expense.  We compute depreciation expense by applying a composite, straight-line rate (approved by the Illinois Commission) to the investment in depreciable property.  The composite, straight-line depreciation rate is 4.1% for all periods, which includes estimated future asset retirement costs.

Taxes.  The reporting of our assets and liabilities for financial accounting purposes differs from the reporting for income tax purposes.  The principal differences between net income and taxable income relate to the timing of deductions, primarily due to the benefits of tax depreciation since we generally depreciate assets for tax purposes over a shorter period of time than for book purposes.  The determination of our provision for income taxes requires significant judgment, the use of estimates, and the interpretation and application of complex tax laws.  Significant judgment is required in assessing the timing and amounts of deductible and taxable items. We report the tax effects of depreciation and other differences in those items as deferred income tax assets or liabilities in our Consolidated Statements of Financial Position in accordance with authoritative guidance related to income taxes.

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

Investment and Other Tax CreditsInvestment tax credits are being amortized over the estimated life of the related properties as credits to income tax expense in our Consolidated Statements of Income.  The balance of unamortized investment tax credits was $22 million at December 31, 2011 and $24 million at December 31, 2010.

Accumulated Deferred Income Tax Assets and LiabilitiesAs noted above, we report some of our assets and liabilities differently for financial accounting purposes than we do for income tax purposes.  We report the tax effects of the differences in those items as deferred income tax assets or liabilities in our Consolidated Statements of Financial Position.  We measure these deferred income tax assets and liabilities using enacted income tax rates.  Temporary differences associated with regulatory assets and liabilities have been netted against related offsetting temporary differences.  When the statutory income tax rate declines before a temporary difference has fully reversed, the deferred income tax liability must be reduced to reflect the newly enacted income tax rates.  In accordance with authoritative guidance related to rate-regulated entities, the amount of such reduction is transferred to our regulatory income tax liability, which we are amortizing over the lives of the related properties as the temporary difference reverses.

Tax BenefitsThe authoritative guidance related to income taxes requires us to determine whether tax benefits claimed or expected to be claimed on our tax return should be recorded in our consolidated financial statements.  Under this guidance, we may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position.  The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement.  This guidance also addresses derecognition, classification, interest and penalties on income taxes and accounting in interim periods.

Uncertain Tax Positions We recognize accrued interest related to uncertain tax benefits in interest expense and interest income in the Consolidated Statements of Income.  Penalties, if any, are recorded in operating expenses in the Consolidated Statements of Income.

Tax Collections We do not collect income taxes from our customers on behalf of governmental authorities.  We charge customers for revenue taxes and remit amounts owed to various governmental authorities.  Our policy is to record all such taxes charged to customers as operating revenues and the related taxes incurred as operating expenses in our

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Consolidated Statements of Income, regardless of whether the tax is assessed on the company or the customer.  Revenue taxes included in operating expense were $154 million in 2011, $146 million in 2010 and $148 million in 2009.

Revenues.  We record revenues when natural gas is delivered to customers.  Those revenues are based on rates approved by the Illinois Commission.  Revenues are comprised principally of natural gas sales bundled with delivery, delivery-only (transportation) services and revenue taxes, as follows:

In millions	2011		2010		2009
Bundled sales	$	1,699	$	1,840	$	1,767
Transportation		162		163		170
Revenue taxes		155		148		150
Other		48		53		54
Total revenues	$	2,064	$	2,204	$	2,141

Cost of gas.  We charge our customers for natural gas consumed using a natural gas cost recovery mechanism in accordance with Illinois Commission regulations. Under this mechanism, all prudently incurred natural gas costs are passed through to customers without markup, subject to Illinois Commission review.  Therefore, in accordance with authoritative guidance for rate-regulated entities, we defer or accrue (that is, include as an asset or liability in the Consolidated Statements of Financial Position and exclude from or include in the Consolidated Statements of Income, respectively) the difference between the actual cost of gas incurred and the amount of commodity revenue earned in a given period such that no operating margin is recognized related to these costs. The deferred or accrued amount is either billed or refunded to our customers prospectively through adjustments to the commodity rate. These amounts are reflected as regulatory assets identified as deferred natural gas costs or regulatory liabilities which are identified as accrued natural gas costs within our Consolidated Statements of Financial Position.

Regulatory assets and liabilities.  We account for the financial effects of regulation in accordance with authoritative guidance related to regulated entities whose rates are designed to recover the costs of providing service.  In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense in the current period are capitalized as regulatory assets when it is probable that such costs or expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Generally, regulatory assets are amortized into expense and regulatory liabilities are amortized into income over the period authorized by the Illinois Commission.  Our regulatory assets and liabilities as of December 31 are summarized in the following table.

In millions	2011		2010
Regulatory assets - current
Regulatory retirement plan asset	$	29	$	21
Deferred gas costs		-		7
Other		7		7
Regulatory assets - noncurrent
Regulatory retirement plan asset		253		193
Deferred environmental costs		134		25
Unamortized losses on reacquired debt		12		13
Other		5		11
Total regulatory assets	$	440	$	277

Regulatory liabilities - current
Regulatory asset retirement liability	$	14	$	17
Accrued gas costs		29		-
Bad debt rider		30		16
Other		4		8
Regulatory liabilities - noncurrent
Regulatory asset retirement liability		896		844
Regulatory income tax liability		13		18
Bad debt rider		14		12
Other		1		1
Total regulatory liabilities	$	1,001	$	916

All items listed above are classified in Other on the Consolidated Statements of Financial Position, with the exception of the noncurrent portions of the regulatory retirement plan asset and the regulatory asset retirement liability, which are stated separately.

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Our regulatory assets are recoverable through either rate riders or base rates specifically authorized and reviewed by the Illinois Commission.  We are not aware of any evidence that these costs will not be recoverable through either rate riders or base rates, and we believe that we will be able to recover such costs, consistent with our historical recoveries.  In the event that the provisions of authoritative guidance related to regulated operations were no longer applicable, we would recognize a write-off of regulatory assets and liabilities that would result in net income. If the regulatory liability is included in base rates, the amount is reflected as a reduction to rate base in setting rates.

The Illinois Commission does not presently allow us the opportunity to earn a return on our regulatory retirement plan asset.  Our regulatory retirement plan asset is expected to be recovered from ratepayers over a period of approximately 9 to 11 years.  The regulatory assets related to debt are not included in rate base, but are recovered over the term of the debt through the rate of return authorized by the Illinois Commission.  Our rate riders for natural gas costs, certain environmental costs and energy efficiency costs provide a return on investment during the period of recovery.  However, there is no interest associated with the under or overcollections of bad debt expense.

Deferred environmental costs Our ERC liabilities are estimates of future remediation costs for investigation and cleanup of coal tar at certain former manufactured gas plant sites that are contaminated.  We report estimates of future environmental remediation costs on an undiscounted basis.  Our ERC liabilities for certain of our sites are estimated based on probabilistic models of potential costs.  These probabilistic models have not been performed on all of our sites, but are expected to be completed in 2012.  As cleanup options and plans mature and cleanup contracts are entered into, we are able to provide conventional engineering estimates of the likely costs of remediation at our former sites.  These estimates contain various engineering uncertainties, but we continuously attempt to refine and update them.  These liabilities do not include other potential expenses, such as unasserted property damage claims, personal injury or natural resource damage claims, unbudgeted legal expenses or other costs for which we may be held liable but for which we cannot reasonably estimate an amount.

Our paid and accrued ERC liabilities are deferred in a corresponding regulatory asset until the costs are recovered from customers.  We recover these deferred costs through a rate rider that authorizes dollar-for-dollar recovery.  For more information on our ERC liabilities, see Note 7 – Commitments, Guarantees and Contingencies.

Bad debt rider Our bad debt rider provides for the recovery from (or refund to) customers of the difference between our actual bad debt experience on an annual basis and the benchmark bad debt expense included in our base rates for the respective year.  The benchmark, against which 2011 and 2010 actual bad debt experience is compared, is approximately $63 million.  Our actual 2011 bad debt experience was $31 million, resulting in a refund to customers of $32 million which will be refunded between June 2012 and May 2013.  Our actual 2010 bad debt experience was $36 million, resulting in a refund to customers of $27 million which is being refunded between June 2011 and May 2012.

Regulatory asset retirement liability In accordance with regulatory treatment, our depreciation rates are determined based upon original cost, retirement costs, salvage and average service life.  We collect through rates the estimated retirement costs on certain regulated properties through straight-line depreciation expense, with a corresponding credit to accumulated depreciation.  To the extent that we believe the retirement activities are required by environmental or safety laws, we have reclassified the estimated accumulated retirement costs from accumulated depreciation to asset retirement obligations in our Consolidated Statements of Financial Position.  Because the remaining accumulated retirement costs meet the requirements of authoritative guidance related to regulated operations, we have reclassified such costs to a regulatory asset retirement liability.  In the rate setting process, the entire amount of accumulated retirement costs is treated as a reduction to the net rate base upon which we have the opportunity to earn an allowed rate of return.

Accounting for retirement benefit plans.  The authoritative guidance related to retirement benefits requires that we recognize all obligations related to our defined benefit retirement plans and quantify the plans’ funded status as an asset or a liability on our Consolidated Statements of Financial Position.  The guidance further requires that we measure the plans’ assets and obligations that determine our funded status as of the end of the fiscal year.  As a regulated utility, we expect continued rate recovery of the eligible costs of our defined benefit retirement plans and, accordingly, associated changes in the plans’ funded status have been deferred as a regulatory asset or liability until recognized in net income. However, to the extent our employees perform services for affiliates and to the extent such employees are eligible to participate in these plans, the affiliates are charged for the cost of these benefits and the changes in the funded status relating to these employees are recorded in accumulated OCI.  Our pension plan’s assets were accounted for at fair value and are classified in the fair value hierarchy in their entirety based on the lowest level of input that is significant to the fair value measurement.

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Use of accounting estimates.  The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities.  We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, and we evaluate our estimates on an ongoing basis.  Our estimates may involve complex situations requiring a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our financial statements.  The most significant estimates relate to our accrued unbilled revenues, derivative instruments, regulatory assets and liabilities, retirement plan benefit obligations, potential asset impairments, asset retirement obligations, loss contingencies including environmental contingencies, workers’ compensation, credit risk and income taxes.  Our actual results could differ from our estimates.  During 2011, we revised the manner in which we estimate our exposure on legal loss contingencies and workers’ compensation matters due to the manner in which our new management addresses such issues from a business standpoint.  This resulted in an increase of $14 million in these reserves during 2011 for such matters and such increase is reflected as a reduction in net income in 2011 of $11 million, net of $3 million capitalized.

Note 3 – Fair Value Measurements

The methods used to determine fair value of our assets and liabilities are fully described within Note 2 – Significant Accounting Policies and Methods of Application.

Derivative instruments.  A description of our objectives and strategies for using derivative instruments, and related accounting policies are fully described within Note 2 – Significant Accounting Policies and Methods of Application.  See Note 4 – Derivative Instruments for additional derivative disclosures.  The following table summarizes, by level within the fair value hierarchy, our derivative assets and liabilities that were accounted for at fair value on a recurring basis for the years ended December 31, 2011 and 2010.

	Recurring fair values Natural gas derivative instruments
	December 31, 2011					December 31, 2010
In millions	Assets		Liabilities			Assets		Liabilities
Quoted prices in active markets (Level 1)	$	-	$	(14	)	$	1	$	(27	)
Significant other observable inputs (Level 2)		1		(11	)		3		(27	)
Unobservable inputs (Level 3)		2		-			4		-
Total carrying value	$	3	$	(25	)	$	8	$	(54	)

The following is a reconciliation of our net derivative instrument assets (liabilities) in Level 3 of the fair value hierarchy.

In millions	2011			2010
Beginning balance	$	4		$	-
Net realized/unrealized gains (losses) included in regulatory assets and liabilities		-			(1	)
Settlements		(3	)		3
Purchases		-			1
Transfers into Level 3		-			1
Transfers out of Level 3		1			-
Ending balance	$	2		$	4

There were no transfers between Level 1 and Level 2 for any of the periods presented.

We maintain margin accounts related to financial derivative transactions.  The following table represents the balance sheet classification of margin accounts related to derivative instruments at December 31:

In millions	2011		2010
Assets
Margin accounts - derivative instruments	$	21	$	50
Other - noncurrent		-		7

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Pension benefits.  Our pension plan’s target asset allocation consists of approximately 60% equity securities and 40% fixed income securities. Our actual pension plan’s asset allocations by level within the fair value hierarchy are presented in the following table.  There were no fair values determined using unobservable inputs (Level 3) for the periods presented.

	Recurring fair values Pension plan
	December 31, 2011												December 31, 2010
In millions	Level 1			Level 2			Total			% of total			Level 1			Level 2			Total			% of total
Cash equivalents	$	1		$	-		$	1			-	%	$	1		$	-		$	1			-	%
Equity securities
U.S. large cap (1)		-			134			134			34	%		-			138			138			36	%
U.S. small cap (1)		-			25			25			7	%		-			24			24			6	%
International companies (2)		-			66			66			17	%		-			67			67			17	%
Emerging markets (3)		-			12			12			3	%		-			12			12			3	%
Fixed income securities
Corporate bonds (4)		-			125			125			32	%		-			124			124			32	%
Government issued bonds (5)		-			28			28			7	%		-			24			24			6	%
Total assets at fair value	$	1		$	390		$	391			100	%	$	1		$	389		$	390			100	%
% of fair value hierarchy		-	%		100	%		100	%					-	%		100	%		100	%

(1)   Includes collective trusts that invest primarily in United States common stocks.

(2)   Includes collective trusts that invest primarily in foreign equity and equity-related securities.

(3)   Includes collective trusts that invest primarily in common stocks of emerging markets.

(4)   Includes investment grade debt and fixed income securities.

(5)   Includes foreign and United States local and state bonds.

Long-term debt.  The following table presents the amortized cost and fair value of our long-term debt for the following periods.

	As of December 31,
In millions	2011		2010
Long-term debt amortized cost	$	499	$	498
Long-term debt fair value		610		554

Note 4 – Derivative Instruments

A description of our objectives and strategies for using derivative instruments, related accounting policies and methods used to determine their fair value are fully described in Note 2 – Significant Accounting Policies and Methods of Application.  See Note 3 – Fair Value Measurements for additional fair value disclosures.

Credit-risk-related contingent features.  Provisions within certain derivative agreements require us to post collateral if our net liability position exceeds a specified threshold.  Also, certain derivative agreements contain credit-risk-related contingent features, whereby we would be required to provide additional collateral or pay the amount due to the counterparty when a credit event occurs, such as if our credit rating was lowered.  For agreements with such features, derivative contracts with liability fair values totaled $6 million at December 31, 2011 and $12 million at December 31, 2010, for which we had posted no collateral to our counterparties.  If it was assumed that we had to post the maximum contractually specified collateral or settle the liability, we would have been required to pay $6 million at December 31, 2011 and $11 million at December 31, 2010.

Quantitative Disclosures Related to Derivative Instruments

As of December 31, 2011 and 2010, our derivative instruments were comprised of long natural gas positions.  A long position is a contract to purchase natural gas.  As of December 31, 2011 and 2010, we had long natural gas contracts outstanding in the following quantities:

	December 31,
In Bcf	2011 (1)		2010
Customer use – not designated as hedges		30.2		49.0
Company use – designated as cash flow hedges		.9		.8
Total		31.1		49.8

(1)   These contracts have durations of 23 months or less.

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The volumes above exclude contracts, such as variable-priced contracts, which are accounted for as derivatives but whose fair values are not directly impacted by changes in commodity prices.

Derivative Instruments on the Consolidated Statements of Financial Position

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

		December 31,
In millions	Consolidated Statements of Financial Position location	2011			2010
Designated as cash flow hedges
Liability Instruments
Current natural gas contracts	Derivative instruments	$	(1	)	$	(1	)
Total designated as cash flow hedges			(1	)		(1	)
Not designated as cash flow hedges
Asset Instruments
Current natural gas contracts	Derivative instruments		2			7
Noncurrent natural gas contracts	Other - noncurrent		1			1
Liability Instruments
Current natural gas contracts	Derivative instruments		(24	)		(49	)
Noncurrent natural gas contracts	Other - noncurrent		-			(4	)
Total not designated as cash flow hedges			(21	)		(45	)
Total derivative instruments		$	(22	)	$	(46	)

Derivative Instruments on the Consolidated Statements of Income

Changes in the fair value of derivatives designated as a cash flow hedge are recognized in OCI until the hedged transaction is recognized in the Consolidated Statements of Income.  We use cash flow hedges to hedge purchases of natural gas for company use.

Our earnings are subject to volatility for those derivatives not designated as hedges.  Non-designated derivatives used to hedge purchases of natural gas for company use, are recorded within operating and maintenance expense.

The following table presents the gain or (loss) on natural gas contracts in our Consolidated Statements of Income and Comprehensive Income for the twelve months ended December 31, 2011, 2010 and 2009.

In millions	2011			2010			2009
Designated as cash flow hedges
Pretax loss recognized in OCI	$	(2	)	$	(2	)	$	(4	)
Pretax loss reclassified from accumulated OCI into operating and maintenance expense for settlement of hedged item		(2	)		(2	)		(8	)
Not designated as hedges
Pretax net loss fair value adjustments recorded in operating and maintenance expense		-			(1	)		(2	)

Any amounts recognized in operating income, related to ineffectiveness or due to a forecasted transaction that is no longer expected to occur, were immaterial for the years ended December 31, 2011, 2010 and 2009.

Derivatives used to hedge the purchase of natural gas for our customers are also not designated as hedging instruments.  Gains or losses on these derivatives are not recognized in pretax earnings, but are deferred as regulatory assets or liabilities until the related revenue is recognized.  Net losses deferred were $64 million in 2011, $112 million in 2010 and $166 million in 2009.

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Note 5 - Employee Benefit Plans

Overview.  We maintain a noncontributory defined benefit pension plan covering substantially all employees hired prior to 1998.  Pension benefits are based on years of service and the highest average salary for management employees and job level for collectively bargained employees (referred to as pension bands).  The benefit obligation related to collectively bargained benefits considers our past practice of regular benefit increases.  We also provide health care and life insurance benefits to eligible retired employees under our retiree medical plan that includes a limit on our share of cost for employees hired after 1982.

Our pension and retiree medical plan benefit costs have historically been considered in rate proceedings in the period they are accrued.  As a regulated utility, we expect continued rate recovery of the eligible costs of these plans and, accordingly, associated changes in the plans’ funded status have been deferred as a regulatory asset or liability until recognized in net income, instead of being recorded in accumulated OCI.  However, to the extent our employees perform services for affiliates and to the extent such employees are eligible to participate in these plans, the affiliates are charged for the cost of these benefits and the changes in the funded status relating to these employees are recorded in accumulated OCI.

Our investment objective relating to pension plan assets is to provide a total investment return which will allow the pension plan to meet its remaining benefit obligations.  Our investment strategy is to diversify our investments among asset classes in order to minimize risk of large losses in a single asset class.  We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.  Our investments include domestic and international equities, fixed income investments (corporate and government issued bonds) and cash equivalents.  The fixed income portfolio is targeted to maintain an average credit quality rating of at least single-A and a weighted duration that approximates the duration of the expected benefit obligations.  Investment performance is measured against a targeted rate of return which reflects the asset allocation of the plan assets and an appropriate published index return for each asset class.  We will rebalance the investment portfolio periodically if the actual asset allocation is significantly out of tolerance from the target allocation.

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 continues to provide a prescription drug benefit as well as a potential federal subsidy to sponsors of certain retiree health care benefit plans whose prescription drug benefits are actuarially equivalent to the Medicare Part D benefit.  We have determined that the prescription drug benefits of our plan are actuarially equivalent and accordingly have reflected the effects of the subsidy in our determination of the benefit obligation and annual net benefit cost.

The Health Care Act contains provisions that may impact our obligation for retiree health care benefits.  We do not currently believe these provisions will materially increase our retiree medical plan benefit obligation, but we will continue to evaluate the impact of future regulations and interpretations.

Contributions.  Our employees do not contribute to the pension plan.  As of December 31, 2011 and 2010, our pension plan is overfunded, therefore, we made no contributions during these periods.  We do not expect to contribute to our pension plan in 2012.  The participants contributed $1 million to our retiree medical plan in 2011 and 2010.  We contributed $12 million in 2011 and $11 million in 2010 to our retiree medical plan and expect to contribute about $15 million (before Medicare subsidies) in 2012.

Assumptions.  We consider a number of factors in determining and selecting an assumption for the overall expected long-term rate of return on plan assets. We consider the historical long-term return experience of our assets, the current and expected allocation of our plan assets, and expected long-term rates of return.  We derive these expected long-term rates of return with the assistance of our investment advisors and generally base these rates on the various asset classes, our expected investments of plan assets and asset management.  We base our expected allocation of plan assets on a diversified portfolio consisting of domestic and international equity securities and fixed income securities. We have elected to apply the return on asset assumption to the fair value of plan assets, rather than a rolling-average fair value, in calculating the expected return on plan assets component of net annual benefit cost.

We consider a variety of factors in determining and selecting our assumptions for the discount rate at December 31.  We based our discount rate on a yield curve provided by our actuaries that is derived from a portfolio of high quality (rated AA or better) corporate bonds and the equivalent annuity cash flows.

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The following table presents details about our pension and retiree medical plans.

	Pension plan						Retiree medical plan
Dollars in millions	2011			2010			2011			2010
Change in plan assets
Fair value of plan assets, January 1,	$	390		$	364		$	-		$	-
Actual return on plan assets		19			45			-			-
Employer contributions		-			-			12			11
Participant contributions		-			-			1			1
Benefits paid		(18	)		(19	)		(13	)		(12	)
Fair value of plan assets, December 31,	$	391		$	390		$	-		$	-
Change in benefit obligation
Benefit obligation, January 1,	$	317		$	306		$	243		$	211
Service cost		10			10			2			2
Interest cost		16			16			13			12
Actuarial loss		39			4			36			27
Participant contributions		-			-			1			1
Medicare Part D reimbursements		-			-			1			2
Benefits paid		(18	)		(19	)		(13	)		(12	)
Benefit obligation, December 31,	$	364		$	317		$	283		$	243
Funded status at end of year	$	27		$	73		$	(283	)	$	(243	)
Amounts recognized in the Consolidated Statements of Financial Position consist of
Noncurrent assets	$	27		$	73		$	-		$	-
Current liabilities		-			-			(14	)		(13	)
Noncurrent liabilities		-			-			(269	)		(230	)
Total asset (liability) at December 31,	$	27		$	73		$	(283	)	$	(243	)
Accumulated benefit obligation (1)	$	340		$	280			n/a			n/a
Assumptions used to determine benefit obligations
Discount rate		4.60	%		5.40	%		4.50	%		5.20	%
Rate of compensation increase		3.75	%		3.75	%		3.75	%		3.75	%
Pension band increase		2.00	%		2.00	%		n/a			n/a

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

The components of our pension and retiree medical plan benefit costs are set forth in the following table.

	Pension plan									Retiree medical plan
Dollars in millions	2011			2010			2009			2011			2010			2009
Net benefit cost
Service cost	$	10		$	10		$	9		$	2		$	2		$	2
Interest cost		16			16			17			13			12			12
Expected return on plan assets		(31	)		(29	)		(25	)		-			-			-
Recognized actuarial loss		10			12			15			6			4			5
Net annual benefit cost	$	5		$	9		$	16		$	21		$	18		$	19
Assumptions used to determine benefit costs
Discount rate		5.40	%		5.45	%		6.35	%		5.20	%		5.75	%		6.00	%
Expected return on plan assets		8.25	%		8.25	%		8.50	%		n/a			n/a			n/a
Rate of compensation increase		3.75	%		3.75	%		3.75	%		3.75	%		3.75	%		3.75	%
Pension band increase		2.00	%		2.00	%		3.00	%		n/a			n/a			n/a

About one-fourth of the net benefit cost related to these plans has been capitalized as a cost of constructing gas distribution facilities and the remainder is included in operating and maintenance expense, net of amounts charged to affiliates.

Other assumptions used to determine the health care benefit cost for the years ended December 31 were as follows:

	2011			2010			2009
Health care cost trend rate assumed for next year		8.60	%		8.00	%		8.00	%
Ultimate rate to which the cost trend rate is assumed to decline		4.50	%		5.00	%		5.00	%
Year that reaches ultimate trend rate		2030			2017			2016

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

Dollars in millions	Increase (decrease)			Effect on service and interest cost			Effect on benefit obligation
Health care cost trend rate		1%		$	1		$	26
		(1%	)		(1	)		(22	)

The 2012 estimated amortization for these plans are set forth in the following table.

	Net regulatory assets				Accumulated OCI
In millions	Pension plan		Retiree medical plan		Pension plan		Retiree medical plan
Amortization of net loss	$	14	$	8	$	1	$	1

The following table presents the gross benefit payments and subsidies expected for the years ended December 31, 2012 through 2021 for our pension and retiree medical plans. There will be benefit payments under these plans beyond 2021.

In millions	Pension plan		Retiree medical plan		Expected Medicare subsidy
2012	$	26	$	15	$	2
2013		26		16		2
2014		29		17		2
2015		31		18		2
2016		33		19		2
2017-2021		192		106		12

Retirement plan benefit costs (credits) recorded within net regulatory assets and accumulated OCI, and changes thereto, were as follows:

	Net regulatory assets						Accumulated OCI					Total
In millions	Pension plan			Retiree medical plan			Pension plan			Retiree medical plan		Pension plan			Retiree medical plan
January 1, 2009	$	181		$	73		$	10		$	4	$	191		$	77
Current year actuarial gain		(20	)		-			(1	)		-		(21	)		-
Amortization of actuarial loss		(15	)		(4	)		(1	)		-		(16	)		(4	)
December 31, 2009		146			69			8			4		154			73
Current year actuarial (gain) loss		(11	)		25			(1	)		1		(12	)		26
Amortization of actuarial loss		(11	)		(4	)		(1	)		-		(12	)		(4	)
December 31, 2010		124			90			6			5		130			95
Current year actuarial loss		48			35			3			1		51			36
Amortization of actuarial loss		(9	)		(6	)		(1	)		-		(10	)		(6	)
December 31, 2011	$	163		$	119		$	8		$	6	$	171		$	125

The balances as of December 31 relate primarily to unrecognized net actuarial losses.

Supplemental retirement plan.  We sponsor a separate unfunded supplemental retirement plan that is noncontributory with defined benefits.  Plan costs for 2011, 2010 and 2009 were less than $1 million.  The projected benefit obligation associated with this plan was $2 million at December 31, 2011 and 2010.

Employee savings plan benefits.  We sponsor defined contribution plans that allow eligible participants to make contributions to their accounts up to specified limits.  Under these plans, our matching contributions to participant accounts were $6 million in 2011 and 2010 and $5 million in 2009.

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Note 6 - Debt

The following table provides maturity dates, weighted average interest rates and amounts outstanding for our various debt securities that are included in our Consolidated Statements of Financial Position.

			December 31, 2011					December 31, 2010
Dollars in millions	Year due		Weighted average interest rate			Outstanding		Weighted average interest rate			Outstanding
Commercial paper	2012			0.55	%	$	452		0.24	%	$	425
Long-term debt
First mortgage bonds
Issued February 2001	2011			n/a		$	-		6.625	%	$	75
Issued February 2011	2016			2.86	%		75		n/a			-
Issued May 2001	2016			7.20	%		50		7.20	%		50
Issued July 2009	2019			4.70	%		50		4.70	%		50
Issued December 2003	2023			5.80	%		50		5.80	%		50
Issued February 1998	2028			6.58	%		50		6.58	%		50
Issued December 2003	2032			5.90	%		50		5.90	%		50
Issued December 2003	2033			5.90	%		50		5.90	%		50
Issued December 2006	2036			5.85	%		50		5.85	%		50
Issued August 2008	2038			6.25	%		75		6.25	%		75
Less: Unamortized debt discount, net of premium		n/a		n/a			1		n/a			2
Total long-term debt				5.56	%	$	499		6.12	%	$	498
Total debt				3.18	%	$	951		3.42	%	$	923

Short-term Debt

Commercial paper.  We maintain a commercial paper program that consists of short-term, unsecured promissory notes that are used in conjunction with cash from operations to fund our seasonal working capital requirements.  Working capital needs fluctuate during the year and are highest during the injection period in advance of the Heating Season.  At December 31, 2011, our commercial paper maturities ranged from 3 to 30 days.

Credit facility.  On December 15, 2011, we entered into a $700 million revolving credit facility, which matures on December 15, 2016 to replace the $400 million, 364-day revolving credit facility, which was set to expire in April 2012 and the $600 million, three-year revolving credit facility, which was set to expire in April 2013.  The credit facility supports our commercial paper program and provides the flexibility to meet working capital and other liquidity requirements.  The interest rate payable on borrowings under the credit facility is calculated either at the alternative base rate, plus an applicable interest margin, or LIBOR, plus an applicable interest margin.  The applicable interest margin used in both interest rate calculations will vary according to our current credit ratings.  At December 31, 2011 and 2010, we had no outstanding borrowings under these facilities.

Affiliate loan.  Prior to the merger between AGL Resources and Nicor, we participated in a cash management system with other subsidiaries of Nicor.  Under this system, at December 31, 2010, we owed $40 million to Nicor which was repaid in 2011.  The weighted-average interest rate was 0.2% and interest expense related to this loan for 2011 and 2010 was immaterial.

Long-term Debt

In February 2011, we issued $75 million first mortgage bonds at 2.86%, due in 2016 through a private placement and utilized the proceeds to retire the $75 million 6.625% first mortgage bond series which matured in February 2011.  In determining that these bonds qualified for exemption from registration under Section 4(2) of the Securities Act of 1933, we relied on the facts that the bonds were offered only to a limited number of large institutional investors and each institutional investor that purchased the bonds represented that it was purchasing the bonds for its own account and not with a view to distribute them. 

Substantially all gas distribution properties are subject to the lien of the indenture securing our first mortgage bonds.

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Financial and Non-Financial Covenants

Our credit facility includes a financial covenant that requires us to maintain a ratio of total debt to total capitalization of no more than 70% at the end of any fiscal month.  Our ratio of total debt to total capitalization, as calculated in accordance with our debt covenant, includes standby letters of credit and surety bonds and excludes accumulated OCI. Adjusting for these items, our debt-to-capitalization ratio for December 31, 2011 was 60%, which is within our required range.

The credit facility contains certain non-financial covenants that, among other things, restrict liens and encumbrances, loans and investments, acquisitions, dividends and other restricted payments, asset dispositions, mergers and consolidations and other matters customarily restricted in such agreements.  We were in compliance with all existing debt provisions and covenants, both financial and non-financial, as of December 31, 2011.

Default Provisions

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

·   a maximum leverage ratio

·   insolvency events and nonpayment of scheduled principal or interest payments

·   acceleration of other financial obligations

·   change of control provisions

We have no trigger events in our debt instruments that are tied to changes in our specified credit ratings.

Note 7 - Commitments, Guarantees and Contingencies

We have incurred various contractual obligations and financial commitments in the normal course of our operating and financing activities that are reasonably likely to have a material effect on liquidity or the availability of capital resources.  Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements.  These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities.  The following table illustrates our expected future contractual payments, such as debt and lease agreements, and commitments as of December 31, 2011.

In millions	Total		2012		2013		2014		2015		2016		2017 & thereafter
Recorded contractual obligations:
Long-term debt	$	500	$	-	$	-	$	-	$	-	$	125	$	375
Short-term debt		452		452		-		-		-		-		-
Environmental remediation liabilities (1)		134		19		30		23		23		13		26
Total	$	1,086	$	471	$	30	$	23	$	23	$	138	$	401
Unrecorded contractual obligations and commitments (2):
Gas supply, pipeline charges and storage capacity (3)	$	448	$	254	$	127	$	48	$	16	$	3	$	-
Interest charges (4)		454		28		28		28		28		23		319
Standby letters of credit, performance/surety bonds (5)		7		6		1		-		-		-		-
Operating leases (6)		3		1		1		-		1		-		-
Other (7)		11		3		2		2		2		2		-
Total	$	923	$	292	$	159	$	78	$	47	$	28	$	319

(1)   Costs are recoverable through a rate rider mechanism, subject to Illinois Commission review.

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

(3)   Costs are primarily recoverable through a natural gas cost recovery mechanism, subject to Illinois Commission review.  The gas supply amount includes amounts for our commodity purchase commitments of 56 Bcf at floating gas prices calculated using forward natural gas prices as of December 31, 2011.  Also includes $2 million of fixed price charges related to commodity purchase commitments that are recorded in our Consolidated Statements of Financial Position.

(4)   In addition, as of December 31, 2011, we have $6 million of accrued interest in our Consolidated Statements of Financial Position that will be paid in 2012.

(5)   We provide guarantees to certain municipalities and other agencies in support of payment obligations.

(6)   Operating leases are primarily for real estate licenses.

(7)   Includes purchase commitments related primarily to future equipment purchases.

In addition, we have $2 million of mandatorily redeemable preferred stock which is payable ratably between 2012 and 2017 and is recorded on our Consolidated Statements of Financial Position.

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We also have long-term obligations for retirement plan benefits which are not included in the above table. In 2012, we expect to make no contributions to our pension plan and expect to contribute about $15 million (before Medicare subsidies) to our retiree medical plan. Additional information regarding our obligations for retirement plan benefits can be found in Note 5 – Employee Benefit Plans.

Substitute Natural Gas Plant Legislation.   On September 30, 2011, we signed an agreement to purchase approximately 25 Bcf of SNG annually for a 10-year term beginning as early as 2015.  The price of the SNG under this contract could potentially be about $9.95 per Mcf or more. The counterparty intends to construct a 60 Bcf per year coal gasification plant in southern Illinois.  The project is expected to be financed by the counterparty with external debt and equity.  This agreement complies with an Illinois statute that authorizes full recovery of the purchase costs; therefore we expect to recover such costs.  Since the purchase agreement is contingent upon various milestones to be achieved by the counterparty to the agreement, our obligation is not certain at this time.  While the purchase agreement is a variable interest in the counterparty, we have concluded, based on a qualitative evaluation, that we are not the primary beneficiary required to consolidate the counterparty.  No amount has been recognized on our Statement of Financial Position in connection with the purchase agreement.

Additionally, on October 11, 2011, the Illinois Power Agency (“IPA”) approved the form of a draft 30-year contract for the purchase by us of approximately 20 Bcf per year of SNG from a second proposed plant beginning as early as 2018.  In November 2011, we filed a lawsuit against the IPA and the developer of this second proposed plant contending that the draft contract approved by the IPA does not conform to certain requirements of the enabling legislation. The lawsuit is pending in circuit court in DuPage County, Illinois. In accordance with the enabling legislation, the draft contract approved by the IPA for the second proposed plant was submitted to the Illinois Commission for further approvals by that regulatory body. The Illinois Commission issued an order on January 10, 2012 approving a final form of the contract for the second plant. The final form of contract approved by the Illinois Commission modified the draft contract submitted by the IPA in various respects. Both we and the developer of the plant have filed applications for rehearing with the Illinois Commission seeking changes to the final form of contract it approved.

The price of the SNG that may be produced from both of the coal gasification plants may significantly exceed market prices and is dependent upon a variety of factors, including plant construction costs, and is currently not estimable.  The Illinois laws provide that prices paid for SNG purchased from the plants are to be considered prudent and not subject to review or disallowance by the Illinois Commission.  

Asset retirement obligations.  Substantially all of the asset retirement obligations are classified as a noncurrent liability.The following table presents a reconciliation of the beginning and ending asset retirement obligations for the years ended December 31:

In millions	2011			2010
Asset retirement obligations, January 1,	$	191		$	192
Liabilities incurred during the period		3			2
Liabilities settled during the period		(4	)		(4	)
Accretion		11			11
Revision in estimated cash flows		-			(10	)
Asset retirement obligations, December 31,	$	201		$	191

Contingencies and Guarantees

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

We have also indemnified, to the fullest extent permitted under the laws of the State of Illinois and any other applicable laws, our present and former directors, officers and employees against expenses they may incur in connection with litigation to which they are a party by reason of their association with us.  There is generally no limitation as to the amount.  While we do not expect to incur significant costs under these indemnifications, it is not possible to estimate the maximum future potential payments.

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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.

We have identified 26 former manufactured gas plant sites in Illinois for which we may have some responsibility.  Most of these sites are not presently owned by us.  We and Commonwealth Edison Company (“ComEd”) are parties to an agreement to cooperate in cleaning up residue at many of these sites.  The agreement allocates to us 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 sites from the agreement with ComEd, 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.  More detailed investigations and remedial activities are complete, in progress or planned at many of these 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.

In April 2002, we were named as a defendant, together with ComEd, in a lawsuit brought by the Metropolitan Water Reclamation District of Greater Chicago (the “MWRDGC”) under the Federal Comprehensive Environmental Response, Compensation and Liability Act seeking recovery of past and future remediation costs and a declaration of the level of appropriate cleanup for a former manufactured gas plant site in Skokie, Illinois now owned by the MWRDGC.  In January 2003, the suit was amended to include a claim under the Federal Resource Conservation and Recovery Act.  The suit was filed in the United States District Court for the Northern District of Illinois.  In September 2011, Nicor Gas and ComEd entered into a settlement with the MWRDGC addressing the appropriate level of cleanup for this former manufactured gas plant site and the lawsuit has been dismissed.

We report estimates of future environmental remediation costs on an undiscounted basis.  Our ERC liabilities for certain of our sites are estimated based on probabilistic models of potential costs.  These probabilistic models have not yet been performed on all of our sites, but are expected to be completed in 2012.  Based on the estimates that we have performed, the cleanup cost estimates range from $134 million to $216 million.  Our liability for environmental remediation costs at December 31, 2011 is $134 million, of which $19 million is expected to be paid over the next twelve months.  Our liability increased by $81 million in the fourth quarter of 2011 primarily as a result of the completion of a probabilistic model for one of our major sites.  We recover these costs through a rate rider and expect to collect $16 million in revenues over the next 12 months.  We recovered $6 million in 2011, $11 million in 2010 and $12 million in 2009 from our ERC rate rider.

Litigation

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

PBR Plan.  Our PBR plan for natural gas costs went into effect on January 1, 2000 and was terminated by us effective January 1, 2003.  Under the PBR plan, our 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 is currently under Illinois Commission review.  There are allegations that we acted improperly in connection with the PBR plan, and the Illinois Commission and others are reviewing these allegations.  On June 27, 2002, the Citizens Utility Board (“CUB”) filed a motion to reopen the record in the Illinois Commission’s proceedings to review the PBR plan (the “Illinois Commission Proceedings”).  As a result of the motion to reopen, we entered into a stipulation with the staff of the Illinois Commission and CUB providing for additional discovery.  The Illinois Attorney General’s Office (“IAGO”) has also intervened in this matter.  In addition, the IAGO issued Civil Investigation Demands (“CIDs”) to CUB and the Illinois Commission staff.  The CIDs ordered that CUB and the Illinois Commission staff produce all documents relating to any claims that we may have presented, or caused to be presented, false information related to our PBR plan.  We have committed to cooperate fully in the reviews of the PBR plan.

In response to these allegations, on July 18, 2002, the Nicor Board of Directors appointed a special committee of independent, non-management directors to conduct an inquiry into issues surrounding natural gas purchases, sales, transportation, storage and such other matters as may come to the attention of the special committee in the course of its investigation.  The special committee presented the report of its counsel (“Report”) to Nicor’s Board of Directors on October 28, 2002.

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In response, the Nicor Board of Directors directed our management to, among other things, make appropriate adjustments to account for, and fully address, the adverse consequences to ratepayers of the items noted in the Report, and conduct a detailed study of the adequacy of internal accounting and regulatory controls.  The adjustments were made in prior years’ financial statements resulting in a $24.8 million liability.  Included in such $24.8 million liability is a $4.1 million loss contingency.  A $1.8 million adjustment to the previously recorded liability, which is discussed below, was made in 2004 increasing the recorded liability to $26.6 million.   By the end of 2003, we completed steps to correct the weaknesses and deficiencies identified in the detailed study of the adequacy of internal controls.

Pursuant to the agreement of all parties, including us, the Illinois Commission re-opened the 1999 and 2000 purchased gas adjustment filings for review of certain transactions related to the PBR plan and consolidated the reviews of the 1999-2002 purchased gas adjustment filings with the PBR plan review.

On February 5, 2003, CUB filed a motion for $27 million in sanctions against us in the Illinois Commission Proceedings.  In that motion, CUB alleged that our responses to certain CUB data requests were false.  Also on February 5, 2003, CUB stated in a press release that, in addition to $27 million in sanctions, it would seek additional refunds to consumers.  On March 5, 2003, the Illinois Commission staff filed a response brief in support of CUB’s motion for sanctions.  On May 1, 2003, the Administrative Law Judges assigned to the proceeding issued a ruling denying CUB’s motion for sanctions.  CUB has filed an appeal of the motion for sanctions with the Illinois Commission, and the Illinois Commission has indicated that it will not rule on the appeal until the final disposition of the Illinois Commission Proceedings.  It is not possible to determine how the Illinois Commission will resolve the claims of CUB or other parties to the Illinois Commission Proceedings.

In 2004, we became aware of additional information relating to the activities of individuals affecting the PBR plan for the period from 1999 through 2002, including information consisting of third party documents and recordings of telephone conversations from Entergy-Koch Trading, LP (“EKT”), a natural gas, storage and transportation trader and consultant with whom we did business under the PBR plan.  Review of additional information completed in 2004 resulted in the $1.8 million adjustment to the previously recorded liability referenced above.

The evidentiary hearings on this matter were stayed in 2004 in order to permit the parties to undertake additional third party discovery from EKT.  In December 2006, the additional third party discovery from EKT was obtained and the Administrative Law Judges issued a scheduling order that provided for us to submit direct testimony by April 13, 2007.  We submitted direct testimony in April 2007, rebuttal testimony in April 2011 and surrebuttal testimony in December 2011.  In surrebuttal testimony, we sought approximately $6 million, which included interest due to us of $2.0 million as of December 31, 2011.  The staff of the Illinois Commission, IAGO and CUB submitted direct testimony to the Illinois Commission in April 2009 and rebuttal testimony in October 2011.  In rebuttal testimony, the staff of the Illinois Commission, IAGO, and CUB requested refunds of $85 million, $255 million and $305 million, respectively.

In February 2012, we committed to a stipulated resolution of issues with the Staff of the Illinois Commission, which includes crediting our customers $64 million, but does not constitute an admission of fault.  This resulted in a $37.4 million pretax charge to our results in the fourth quarter of 2011, which represents the difference between the $64 million proposed credit and our previously recorded $26.6 million liability.  The stipulated resolution is subject to review and approval by the Illinois Commission.  CUB and IAGO are not parties to the 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 are unable to predict the outcome of the Illinois Commission’s review or our potential exposure.  Because the PBR plan and historical gas costs are still under Illinois Commission review, the final outcome could be materially different from the amounts reflected in our financial statements as of December 31, 2011.

Municipal Tax Matters.  Many municipalities in our service territory have enacted ordinances that impose taxes on gas sales to customers within municipal boundaries.  Most of these municipal taxes are imposed on us based on revenues generated by us within the municipality.  Other municipal taxes are imposed on natural gas consumers within the municipality but are collected from consumers and remitted to the municipality by us.  A number of municipalities have instituted audits of our tax remittances.  In May 2007, five of those municipalities filed an action against us in state court in DuPage County, Illinois relating to these tax audits.  Following a dismissal of this action without prejudice by the trial court, the municipalities filed an amended complaint.  The amended complaint seeks, among other things, compensation for alleged unpaid taxes.  We are contesting the claims in the amended complaint.  In December 2007, 25 additional municipalities, all represented by the same audit firm involved in the lawsuit, issued assessments to us claiming that we failed to provide information requested by the audit firm and owed the municipalities back taxes.  We believe the assessments are improper and have challenged them.  While we are unable to predict the outcome of these matters or to reasonably estimate our potential exposure related thereto, if any, and have not recorded a liability associated with this

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contingency, the final disposition of these matters is not expected to have a material adverse impact on our liquidity or financial condition.

Nicor Services Warranty Product Actions.  In the first quarter of 2011, three putative class actions were filed against Nicor Services and us, and in one case against Nicor.  In September 2011, the three cases were consolidated into a single class action pending in state court in Cook County, Illinois.  The plaintiffs purport to represent a class of our customers who purchased appliance warranty and service plans from Nicor Services and/or a class of our customers who purchased the Gas Line Comfort Guard product from Nicor Services.  In the consolidated action, the plaintiffs variously allege that the marketing, sale and billing of the Nicor Services appliance warranty and service plans and Gas Line Comfort Guard violate the Illinois Consumer Fraud and Deceptive Business Practices Act, constitute common law fraud and result in unjust enrichment of Nicor Services and us.  The plaintiffs seek, on behalf of the classes they purport to represent, actual and punitive damages, interest, costs, attorneys fees and injunctive relief.  While we are unable to predict the outcome of this matter or to reasonably estimate our potential exposure related thereto, if any, and have not recorded a liability associated with this contingency, the final disposition of this matter is not expected to have a material adverse impact on our liquidity or financial condition.

Illinois Attorney General Subpoena.  On February 8, 2010, the IAGO issued us a subpoena to provide documents in connection with an IAGO investigation pursuant to the Illinois Whistleblower Reward and Protection Act.  On November 30, 2010, the IAGO issued to us an amended request for information.  According to the subpoena, the IAGO investigation relates to billing practices used with certain customer accounts involving government funds.  While we believe our billing practices comply with Illinois Commission requirements, we are unable to predict the outcome of this matter or reasonably estimate our potential exposure, if any, and have not recorded a liability associated with this matter.

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

Note 8 - Income Taxes

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

In millions	2011			2010			2009
Current income taxes
Federal	$	14		$	27		$	9
State		(3	)		11			6
Deferred income taxes
Federal		10			23			25
State		9			(1	)		1
Amortization of investment tax credits, net		(2	)		(1	)		(1	)
Total income tax expense on Consolidated Statements of Income	$	28		$	59		$	40

The reconciliations between the statutory federal income tax rate, the effective rate and the related amount of tax for the years ended December 31, 2011, 2010 and 2009 on our Consolidated Statements of Income are presented in the following table.

In millions	2011			2010			2009
Computed tax expense at statutory rate	$	27		$	56		$	40
State income tax, net of federal income tax benefit		3			7			5
Amortization of investment tax credits		(2	)		(2	)		(2	)
Amortization of regulatory income tax liability		(1	)		(2	)		(1	)
Medicare subsidy		-			-			(2	)
Other – net		1			-			-
Total income tax expense on Consolidated Statements of Income	$	28		$	59		$	40

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Accumulated deferred income tax assets and liabilities.  Components that give rise to the net accumulated deferred income tax liability are as follows.

	As of December 31,
In millions	2011		2010
Accumulated deferred income tax liabilities
Property, plant and equipment	$	390	$	350
Other		29		29
Total accumulated deferred income tax liabilities		419		379
Accumulated deferred income tax assets
Other		59		40
Total accumulated deferred income tax assets		59		40
Net accumulated deferred tax liability	$	360	$	339

Tax benefits.  At December 31, 2011, we did not have a liability for unrecognized tax benefits.  Based on current information, we do not anticipate that this will change materially for 2012.  A reconciliation of the beginning and ending amounts of the liability for unrecognized tax benefits for 2010 and 2009 is as follows.

In millions	2010			2009
Liability for unrecognized tax benefits, January 1,	$	3		$	7
Settlements		(3	)		(4	)
Liability for unrecognized tax benefits, December 31,	$	-		$	3

We are included in the United States federal and Illinois consolidated income tax returns of our parent company.  Income taxes are allocated to us based upon the tax liability that would have been incurred on a separate company basis.  We are no longer subject to income tax examinations by the Internal Revenue Service and Illinois Department of Revenue for years before 2008.

We recognized interest expense (income) on tax matters of $(2) million in 2011, $(1) million in 2010 and $1 million in 2009.  We had an insignificant interest payable at December 31, 2011 and $2 million interest receivable at December 31, 2010.  The decrease in interest receivable in 2011 when compared to the prior year is due primarily to the receipt of interest in the first quarter of 2011 related to a federal income tax settlement.  Amounts recognized in operating expense related to penalties were insignificant.

Other.  In March 2010, the Health Care Act was signed into law resulting in comprehensive health care reform.  The Health Care Act contains a provision that eliminates the tax deduction related to Medicare Part D subsidies received after 2012.  Federal subsidies are provided to sponsors of retiree health benefit plans, such as Nicor Gas, that provide a benefit that is at least actuarially equivalent to the benefits under Medicare Part D.  Such subsidies have reduced our actuarially determined projected benefit obligation and annual net periodic benefit costs.  Due to the change in taxation, in the first quarter of 2010, we reduced deferred tax assets by $18 million, reversed an existing regulatory income tax liability of $10 million, established a regulatory income tax asset of $7 million and recognized a $1 million charge to income tax expense.  The change in taxation will reduce earnings by an estimated $2 million annually for periods subsequent to the enactment date.

Note 9 – Related Party Transactions

In the ordinary course of business, under the terms of agreements approved by the Illinois Commission, we enter into transactions with our affiliates for the use of facilities and services.  The charges for these transactions are cost-based, except in certain circumstances where the charging party has a prevailing price for which the facility or service is provided to the general public.  We had net charges to Nicor of $9 million in 2011 and 2010 and $5 million in 2009.  We had net charges from AGL Services Company of $1 million in 2011.

Prior to the completion of the merger between AGL Resources and Nicor, our key executives and managerial employees participated in Nicor’s stock-based compensation plans.  We recognized compensation expense of $5 million in 2011, $6 million in 2010 and $4 million in 2009 in operating and maintenance expense related to these stock-based compensation plans.

There are Illinois Commission regulations addressing the amount and circumstances under which we can deposit or advance to and from our affiliates.  We currently are prohibited by regulations of the Illinois Commission from loaning money to affiliates.  However, we are permitted to receive cash advances from AGL Resources.  The balance of any such

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advances may not exceed the balance of funds available to us under our existing credit agreements or commercial paper facilities with unaffiliated third parties.

Prior to the completion of the merger between AGL Resources and Nicor, we participated in a cash management system with other subsidiaries of Nicor.  Under this system, we could receive advances from Nicor.  Such advances were due on demand.  Our practice provided that the balance of cash advances from Nicor to us may not exceed the unused balance of funds actually available to us under our existing credit agreements or commercial paper facilities with unaffiliated third parties.  At December 31, 2010 we owed $40 million to Nicor which was repaid in 2011.  We recorded interest expense from such loans at the lower of our commercial paper rate or Nicor’s actual interest cost for the funds obtained or used to provide us the cash advance.  Interest expense on advances from Nicor for 2011, 2010 and 2009 was immaterial.

Under its utility-bill management products, Nicor Solutions pays us for the utility bills issued to the utility-bill management customers.  We recorded revenues of $32 million in 2011, $34 million in 2010 and $35 million in 2009 associated with the payments Nicor Solutions makes to us on behalf of its customers.

As a natural gas supplier, Nicor Advanced Energy pays us for delivery charges, administrative charges and applicable taxes.  Nicor Advanced Energy paid us $6 million in 2011 and $7 million in 2010 and 2009 for such items.  Additionally, Nicor Advanced Energy may pay or receive inventory imbalance adjustments.  Nicor Advanced Energy received from us $3 million in 2011 and 2010 and $6 million in 2009 for such items.

We enter into routine transactions with Nicor Enerchange that are governed by terms of an Illinois Commission order.  Net commodity-based charges to (from) Nicor Enerchange were $1 million in 2011, $(5) million in 2010 and $(7) million in 2009.  Additionally, Nicor Enerchange administers the Chicago Hub for us in accordance with an agreement approved by the Illinois Commission.  Charges from Nicor Enerchange for administration of the Chicago Hub were less than $1 million in 2011, 2010 and 2009.  We also charged Nicor Enerchange $1 million in 2009 for certain storage services at the Chicago Hub.  Such charges for 2011 and 2010 were immaterial.

Horizon Pipeline charged us $10 million in 2011, 2010 and 2009 for natural gas transportation under rates that have been accepted by the FERC.

In addition, certain related parties may acquire regulated utility services at rates approved by the Illinois Commission.

Note 10 – Regulatory Matters

Rate proceeding.  On March 25, 2009, the Illinois Commission issued an order approving an increase in base revenues of approximately $69 million, a rate of return on rate base of 7.58% and a rate of return on equity of 10.17%.  The order also approved an energy efficiency rider.  We placed the rates approved in the March 25, 2009 order into effect on April 3, 2009.

On April 24, 2009, we filed a request for rehearing with the Illinois Commission concerning the capital structure contained in the Illinois Commission’s rate order contending our return on rate base should be higher.  On October 7, 2009, the Illinois Commission issued its decision on rehearing in which it increased our annual base revenues approved in the March 25, 2009 order by approximately $11 million, increasing the rate of return on rate base to 8.09%.  We placed the rates approved in the rehearing decision into effect on a prospective basis on October 15, 2009.  Therefore, the total annual base revenue increase authorized in the rate case we originally filed in April 2008 is approximately $80 million.

Bad debt rider.  In September 2009, we filed for approval of a bad debt rider with the Illinois Commission under an Illinois state law which took effect in July 2009. On February 2, 2010, the Illinois Commission issued an order approving our proposed bad debt rider.  This rider provides for recovery from customers of the amount over the benchmark for bad debt expense established in our rate cases.  It also provides for refunds to customers if bad debt expense is below such benchmarks.

Dividends and other restrictions.  We are restricted by regulation in the amount we can dividend to our parent company.  Dividends are allowed only to the extent of our retained earnings balance.  We currently are prohibited by regulations of the Illinois Commission from loaning money to affiliates.  For discussion of restrictions regarding cash deposits from or advances to affiliates, see Note 9 – Related Party Transactions.

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

None.

ITEM 9A.  CONTROLS AND PROCEDURES

Conclusions Regarding the Effectiveness of Disclosure Controls and Procedures

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

Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2011, in providing a reasonable level of assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods in SEC rules and forms, including a reasonable level of assurance that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and our principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the fourth quarter ended December 31, 2011, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Report of Management on Internal Control Over Financial Reporting

Management has assessed our internal control over financial reporting as of December 31, 2011.  The unqualified report of management thereon is included in Item 8 of this Annual Report on Form 10-K and is incorporated by reference herein.

ITEM 9B.  OTHER INFORMATION

None.

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PART III

ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES

In December 2011, we engaged PricewaterhouseCoopers LLP (“PwC”) and dismissed Deloitte & Touche LLP (“Deloitte”) as our independent public accountants.  The following is a summary of fees for professional services rendered by PwC during 2011 and Deloitte during 2011 and 2010 in their respective capacities as our independent auditor during such years:

In millions	2011 - PwC		2011 - Deloitte		2010 - Deloitte
Audit fees	$	.3	$	.9	$	1.2
Audit-related fees		-		.1		.1
Total fees	$	.3	$	1.0	$	1.3

Audit Fees.  Represents fees billed to us for the audit of our annual financial statements and the review of our quarterly financial statements and for services normally provided in connection with statutory and regulatory filings.

Audit-Related Fees.  Represents fees billed to us for audit and review-related services, and the audit of employee benefit plan financial statements.

Audit Committee Pre-Approval Policies and Procedures

Consistent with rules and regulations pursuant to the Sarbanes-Oxley Act of 2002 regarding registered public accounting firm independence, the Audit Committee of AGL Resources (“Audit Committee”) has responsibility for appointing, setting compensation and overseeing the work of our independent registered public accounting firm. In recognition of this responsibility, the Audit Committee adopted a policy that requires specific Audit Committee approval before any services are provided by the independent registered public accounting firm.

Prior to engagement of the independent registered public accounting firm for the next year’s audit, management submits to the Audit Committee for approval a summary of services expected to be rendered during that year and an estimate of the related fees for (1) audit services, (2) audit-related services, (3) tax services, and (4) all other services. The Audit Committee pre-approves these services by category of service and budget amount. The services and fees must be deemed compatible with the maintenance of the independent registered public accounting firm’s independence. The Audit Committee requires the independent registered public accounting firm and management to report actual fees versus the budget periodically throughout the year by category of service. During the year, circumstances may arise when it may become necessary to engage the independent registered public accounting firm for additional services not contemplated in the original pre-approval. In those instances, the Audit Committee requires that management obtain specific approval from the Audit Committee before engaging the independent registered public accounting firm.

The Audit Committee may delegate approval authority to one or more of its members. The member to whom such authority is delegated must present for ratification any approval decisions to the Audit Committee at its next scheduled meeting.

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PART IV

ITEM 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)  Documents Filed as Part of This Report.

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

·   Report of Independent Registered Public Accounting Firm

·   Consolidated Statements of Financial Position as of December 31, 2011 and 2010

·   Consolidated Statements of Income for the years ended December 31, 2011, 2010 and 2009

·   Consolidated Statements of Comprehensive Income for the years ended December 31, 2011, 2010 and 2009

·   Consolidated Statements of Retained Earnings for the years ended December 31, 2011, 2010 and 2009

·   Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009

·   Notes to Consolidated Financial Statements

(2)  Financial Statement Schedules

Financial Statement Schedule II. Valuation and Qualifying Accounts for Each of the Three Years in the Period Ended December 31, 2011.

Schedules other than those referred to above are omitted and are not applicable or not required, or the required information is shown in the financial statements or notes thereto.

(3)  Exhibits

Where an exhibit is filed by incorporation by reference to a previously filed registration statement or report, such registration statement or report is identified in parentheses.

3.01	Restated Articles of Incorporation of the company as filed with the Illinois Secretary of State on July 21, 2006.  (File No. 1-7296, Form 10-Q for June 30, 2006, Nicor Gas Company, Exhibit 3.01.)
3.02	Nicor Gas Company Amended and Restated By-laws effective as of December 9, 2011.  (File No. 1-7296, Form 8-K for December 15, 2011, Nicor Gas Company, Exhibit 3.1.)
4.01	Indenture of Commonwealth Edison Company to Continental Illinois National Bank and Trust Company of Chicago, Trustee, dated as of January 1, 1954.  (File No. 1-7296, Form 10-K for 1995, Nicor Gas Company, Exhibit 4.01.)
4.02	Indenture of Adoption of the company to Continental Illinois National Bank and Trust Company of Chicago, Trustee, dated February 9, 1954.  (File No. 1-7296, Form 10-K for 1995, Nicor Gas Company, Exhibit 4.02.)
4.03	Supplemental Indenture, dated February 15, 1998, of the company to Harris Trust and Savings Bank, Trustee, under Indenture dated as of January 1, 1954.  (File No. 1-7296, Form 10-K for 1997, Nicor Gas Company, Exhibit 4.19.)
4.04	Supplemental Indenture, dated May 15, 2001, of the company to BNY Midwest Trust Company, Trustee, under Indenture dated as of January 1, 1954.  (File No. 1-7296, Form 10-Q for June 2001, Nicor Gas Company, Exhibit 4.01.)
4.05	Supplemental Indenture, dated December 1, 2003, of the company to BNY Midwest Trust Company, Trustee, under Indenture dated as of January 1, 1954.  (File No. 1-7296, Form 10-K for 2003, Nicor Gas Company, Exhibit 4.09.)
4.06	Supplemental Indenture, dated December 1, 2003, of the company to BNY Midwest Trust Company, Trustee, under Indenture dated as of January 1, 1954.  (File No. 1-7296, Form 10-K for 2003, Nicor Gas Company, Exhibit 4.10.)
4.07	Supplemental Indenture, dated December 1, 2003, of the company to BNY Midwest Trust Company, Trustee, under Indenture dated as of January 1, 1954.  (File No. 1-7296, Form 10-K for 2003, Nicor Gas Company, Exhibit 4.11.)

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4.08	Supplemental Indenture, dated December 1, 2006, of Nicor Gas to BNY Midwest Trust Company, Trustee, under Indenture dated as of January 1, 1954.  (File No. 1-7296, Form 10-K for 2006, Nicor Gas Company, Exhibit 4.11.)
4.09	Supplemental Indenture, dated August 1, 2008, of Nicor Gas to BNY Mellon Trust Company, Trustee, under Indenture dated January 1, 1954.  (File No. 1-7296, Form 10-Q for September 30, 2008, Nicor Gas Company, Exhibit 4.01.)
4.10	Supplemental Indenture, dated July 23, 2009, of Nicor Gas to BNY Mellon Trust Company, Trustee, under Indenture dated as of January 1, 1954.  (File No. 1-7296, Form 10-Q for June 30, 2009, Nicor Gas Company, Exhibit 4.01.)
4.11	Supplemental Indenture, dated February 1, 2011, of Nicor Gas to BNY Mellon Trust Company, Trustee, under Indenture dated as of January 1, 1954.  (File No. 1-7296, Form 10-K for 2010, Nicor Gas Company, Exhibit 4.12.)
10.01	Nicor Gas Supplementary Savings Plan (as Amended and Restated for Post-2004 Benefits, Effective January 1, 2008.)  (File No. 1-7296, Form 10-K for 2008, Nicor Gas Company, Exhibit 10.01.)
10.02	Amendment and Restatement of Nicor Gas Supplementary Retirement Plan.  (File No. 1-7297, Form 10-Q for March 2000, Nicor Inc., Exhibit 10.01.)
10.03	Amendment to Nicor Gas Supplementary Retirement Plan (as in Effect on October 3, 2004, for Pre-2005 Benefits). (File No. 1-7297, Form 8-K for July 28, 2008, Nicor Inc., Exhibit 10.12.)
10.04	Nicor Gas Supplementary Retirement Plan (as Amended and Restated for Post-2004 Benefits, Effective January 1, 2008). (File No. 1-7297, Form 8-K for July 28, 2008, Nicor Inc., Exhibit 10.11.)
10.05	Nicor Gas Annual Incentive Compensation Plan for Officers.  (File No. 1-7296, Form 10-K for 2008, Nicor Gas Company, Exhibit 10.06.)
10.06	Final Allocation Agreement between Nicor Gas and Commonwealth Edison Company dated as of January 3, 2008.  (File No. 1-7296, Form 10-K for 2007, Nicor Gas Company, Exhibit 10.15.)
10.07	Agreement between Nicor Gas and Local Union 19 of the International Brotherhood of Electrical Workers 2009-2014.  (File No. 1-7296, Form 10-K for 2009, Nicor Gas Company, Exhibit 10.13.)
10.08	5-Year Credit Agreement dated as of December 15, 2011.  (File No. 1-7296, Form 8-K for December 15, 2011, Nicor Gas Company, Exhibit 10.1.)
12.01	Statement of Computation of Ratio of Earnings to Fixed Charges.
23.01	Consent of PricewaterhouseCoopers LLP, independent registered public accounting firm.
23.02	Consent of Deloitte & Touche LLP, independent registered public accounting firm.

24.01	Powers of Attorney (included on signature page hereto).
31.01	Certification of Henry P. Linginfelter pursuant to Rule 13a – 14(a).
31.02	Certification of Andrew W. Evans pursuant to Rule 13a – 14(a).
32.01	Certification of Henry P. Linginfelter pursuant to 18 U.S.C. Section 1350.
32.02	Certification of Andrew W. Evans pursuant to 18 U.S.C. Section 1350.
101.INS	XBRL Instance Document. (1)
101.SCH	XBRL Taxonomy Extension Schema. (1)

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101.CAL	XBRL Taxonomy Extension Calculation Linkbase. (1)
101.LAB	XBRL Taxonomy Extension Label Linkbase. (1)
101.PRE	XBRL Taxonomy Extension Presentation Linkbase. (1)

(1) Furnished, not filed   Attached as Exhibit 101 to this Annual Report are the following documents formatted in extensible business reporting language (XBRL): (i) Document and Entity Information; (ii) Consolidated Statements of Financial Position at December 31, 2011 and 2010; (iii) Consolidated Statements of Income for the years ended December 31, 2011, 2010 and 2009; (iv) Consolidated Statements of Comprehensive Income for the years ended December 31, 2011, 2010 and 2009; (v) Consolidated Statements of Retained Earnings for the years ended December 31, 2011, 2010 and 2009; (vi) Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009; and (vii) Notes to Consolidated Financial Statements.   Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability. We also make available on our web site the Interactive Data Files submitted as Exhibit 101 to this Annual Report.

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

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SIGNATURES

In accordance with Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned; thereunto duly authorized, on February 22, 2012.

NICOR GAS COMPANY

By: /s/ Henry P. Linginfelter

Henry P. Linginfelter

Chairman and Chief Executive Officer

Power of Attorney

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Henry P. Linginfelter, Andrew W. Evans, Bryan E. Seas, Paul R. Shlanta and John W. Somerhalder II, and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K for the year ended December 31, 2011, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite or necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February 22, 2012.

Signatures	Title
/s/ Henry P. Linginfelter	Chairman and Chief Executive Officer
Henry P. Linginfelter	(Principal Executive Officer)
/s/ Andrew W. Evans	Executive Vice President
Andrew W. Evans	and Chief Financial Officer
	(Principal Financial Officer)
/s/ Bryan E. Seas	Senior Vice President
Bryan E. Seas	and Chief Accounting Officer
	(Principal Accounting Officer)
/s/ Paul R. Shlanta	Executive Vice President
Paul R. Shlanta	and General Counsel
/s/ John W. Somerhalder II	Director
John W. Somerhalder II

Supplemental Information

Supplemental Information to be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act:

No annual report or proxy material has been sent to security holders as Nicor Gas is a wholly owned subsidiary of AGL Resources.

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Schedule II
Nicor Gas Company
VALUATION AND QUALIFYING ACCOUNTS - FOR EACH OF THE THREE YEARS IN THE PERIOD ENDED DECEMBER 31, 2011
			Additions
	Balance at		Charged to			Charged to					Balance
	beginning		costs and			other					at end
Description	of period		expenses			accounts		Deductions			of period
2011
Allowance for uncollectible accounts	$	25	$	31	(b)	$	-	$	35	(a)	$	21
2010
Allowance for uncollectible accounts	$	31	$	36	(b)	$	-	$	42	(a)	$	25
2009
Allowance for uncollectible accounts	$	43	$	53		$	-	$	65	(a)	$	31
(a) Accounts receivable written off, net of recoveries.
(b) Amount excludes refunds to / recoveries from customers attributable to the bad debt rider.

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