UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 2012
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
(Address and zip code of principal executive offices)
630-983-8888
(Registrant’s telephone number, including area code)
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 (or for such shorter period that the registrant was required to file such reports), 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 (§232.405 of this chapter)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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. 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 H(1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with a reduced disclosure format specified in General Instruction H(2)(b) of Form 10-Q.

NICOR GAS COMPANY

Quarterly Report on Form 10-Q

For the Quarter Ended June 30, 2012

TABLE OF CONTENTS

		Page(s)
Glossary of Key Terms		3
Item Number
	PART I – FINANCIAL INFORMATION
1	Condensed Consolidated Financial Statements (Unaudited)	4
	Condensed Consolidated Statements of Financial Position	4
	Condensed Consolidated Statements of Income	5
	Condensed Consolidated Statements of Comprehensive Income	5
	Condensed Consolidated Statements of Cash Flows	6
	Notes to Condensed Consolidated Financial Statements (Unaudited)	7
	Note 1 – Organization and Basis of Presentation	7
	Note 2 – Significant Accounting Policies and Methods of Application	7
	Note 3 – Fair Value Measurements	10
	Note 4 – Derivative Instruments	11
	Note 5 – Employee Benefit Plans	12
	Note 6 – Debt and Credit Facility	13
	Note 7 – Commitments, Guarantees and Contingencies	14
	Note 8 – Related Party Transactions	16
2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
	Forward-Looking Statements	17
	Executive Summary	17
	Results of Operations	18
	Liquidity and Capital Resources	19
	Contingencies	22
	Critical Accounting Policies and Estimates	23
3	Quantitative and Qualitative Disclosures About Market Risk	23
4	Controls and Procedures	23
	PART II – OTHER INFORMATION
1	Legal Proceedings	24
1A	Risk Factors	24
6	Exhibits	24
	SIGNATURE	25

GLOSSARY OF KEY TERMS

2011 Form 10-K	Our Annual Report on Form 10-K for the year ended December 31, 2011, filed with the SEC on February 22, 2012
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
EBIT	Earnings before interest and taxes, a non-GAAP measure that includes operating income and other income and excludes financing costs, including interest on debt and income tax expense. As an indicator of our operating performance, EBIT should not be considered an alternative to, or more meaningful than, earnings before income taxes, or net income as determined in accordance with GAAP
ERC	Environmental remediation costs
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 businesses, calculated as the extent to which the average daily temperature is 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, LLC
Illinois Commission	Illinois Commerce Commission, our state regulatory agency
LIBOR	London Inter-Bank Offered Rate
LIFO	Last-in, first-out, an accounting method used to value inventory
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, LLC, doing business as Nicor Advanced Energy
Nicor Gas	Northern Illinois Gas Company, doing business as Nicor Gas Company
Nicor Services	Nicor Energy Services Company
Nicor Solutions	Nicor Solutions, LLC
OCI	Other comprehensive income
Operating margin	A non-GAAP measure of income, calculated as operating revenues minus cost of goods sold and revenue tax expense, that excludes operation and maintenance expense, depreciation and amortization, certain taxes other than income taxes and gains or losses on the sale of our assets, if any; these items are included in our calculation of operating income as reflected in our Condensed Consolidated Statements of Income. Operating margin should not be considered an alternative to, or more meaningful than, operating income as determined in accordance with GAAP
PBR	Performance-based rate, a regulatory plan that ended in 2003, which 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 charged to customers
Rider	A rate adjustment mechanism that is part of a utility’s tariff which authorizes it to provide specific services or assess specific charges
S&P	Standard & Poor’s Ratings Services
SEC	Securities and Exchange Commission
SNG	Substitute natural gas, a synthetic form of gas manufactured from coal

3

PART I – Financial Information

Item 1. Financial Statements

NICOR GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(UNAUDITED)

	As of
In millions	June 30, 2012			December 31, 2011			June 30, 2011
Current assets
Cash and cash equivalents	$	6		$	0		$	0
Receivables
Gas, unbilled and other receivables		164			357			251
Less allowance for uncollectible accounts		24			21			39
Total receivables		140			336			212
Regulatory assets – current portion		56			36			32
Margin accounts – derivative instruments		18			21			34
Inventories		14			123			17
Derivative instruments – current portion		4			2			6
Deferred income taxes and other assets – current portion		49			58			40
Total current assets		287			576			341
Long-term assets and other deferred debits
Property, plant and equipment		4,951			4,889			4,795
Less accumulated depreciation		2,003			1,961			1,922
Property, plant and equipment, net		2,948			2,928			2,873
Regulatory assets – noncurrent portion		458			404			252
Derivative instruments – noncurrent portion		1			1			3
Other long-term assets and other deferred debits		41			39			89
Total long-term assets and other deferred debits		3,448			3,372			3,217
Total assets	$	3,735		$	3,948		$	3,558
Current liabilities
Regulatory liabilities – current portion	$	111		$	77		$	48
Accounts payable – trade		105			91			160
Customer deposits and credit balances		96			102			84
Temporary LIFO inventory liquidation		41			0			89
Accrued expenses		30			36			73
Derivative instruments – current portion		19			25			30
Short-term debt		0			452			66
Other current liabilities		94			63			55
Total current liabilities		496			846			605
Long-term liabilities and other deferred credits
Regulatory liabilities – noncurrent portion		972			946			916
Long-term debt		499			499			499
Accumulated deferred income taxes		413			401			384
Accrued other retirement benefit costs		250			269			231
Accrued environmental remediation liabilities		216			134			53
Asset retirement obligation		205			200			195
Other long-term liabilities and other deferred credits		10			12			13
Total long-term liabilities and other deferred credits		2,565			2,461			2,291
Total liabilities and other deferred credits		3,061			3,307			2,896
Commitments, guarantees and contingencies (see Note 7)
Equity
Common stock		76			76			76
Non-redeemable preferred stock		1			1			1
Retained earnings		497			465			483
Paid in capital		108			108			108
Accumulated other comprehensive loss		(8	)		(9	)		(6	)
Total equity		674			641			662
Total liabilities and equity	$	3,735		$	3,948		$	3,558

 See Notes to Condensed Consolidated Financial Statements (Unaudited). 

4

NICOR GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)

	Three months ended				Six months ended
	June 30,				June 30,
In millions	2012		2011		2012		2011
Operating revenues (includes revenue taxes of $22, $31, $82 and $106, respectively)	$	240	$	359	$	862	$	1,275
Operating expenses
Cost of goods sold		80		182		451		822
Operation and maintenance		68		66		156		149
Depreciation and amortization		48		47		97		94
Taxes other than income taxes		25		36		90		115
Total operating expenses		221		331		794		1,180
Operating income		19		28		68		95
Interest expense, net		8		8		16		15
Earnings before income taxes		11		20		52		80
Income tax expense		4		7		20		30
Net income	$	7	$	13	$	32	$	50

 See Notes to Condensed Consolidated Financial Statements (Unaudited).

NICOR GAS COMPANY

 CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(UNAUDITED)

	Three months ended				Six months ended
	June 30,				June 30,
In millions	2012		2011		2012		2011
Comprehensive income	$	8	$	13	$	33	$	51

 See Notes to Condensed Consolidated Financial Statements (Unaudited).

5

                                                                                                              NICOR GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Six months ended
	June 30,
In millions	2012			2011
Cash flows from operating activities
Net income	$	32		$	50
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization		97			94
Deferred income taxes		10			12
Change in derivative instrument assets and liabilities		(7	)		(23	)
Changes in certain assets and liabilities
Receivables		196			176
Inventories		109			109
Temporary LIFO inventory liquidation		41			89
Accounts payable		14			(18	)
Other – net		45			31
Net cash flow provided by operating activities		537			520
Cash flows from investing activities
Expenditures for property, plant and equipment		(82	)		(84	)
Other investing activities		3			2
Net cash flow used in investing activities		(79	)		(82	)
Cash flows from financing activities
Net repayments and borrowings of short-term debt		(452	)		(359	)
Proceeds from issuing long–term debt		0			75
Payments of long–term debt		0			(75	)
Dividends paid		0			(46	)
Net repayments of loan from affiliates		0			(31	)
Other financing activities		0			(2	)
Net cash flow used in financing activities		(452	)		(438	)
Net increase in cash and cash equivalents		6			0
Cash and cash equivalents at beginning of period		0			0
Cash and cash equivalents at end of period	$	6		$	0
Cash paid (received) during the period for
Interest	$	15		$	16
Income taxes	$	0		$	(10	)

 See Notes to Condensed Consolidated Financial Statements (Unaudited).

6

NICOR GAS COMPANY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 – Organization and Basis of Presentation

General

Nicor Gas is a natural gas distribution company 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. 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, AGL Resources and Nicor merged 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 unaudited Condensed Consolidated Financial Statements.

The December 31, 2011 Condensed Consolidated Statement of Financial Position data was derived from our audited financial statements, but does not include all disclosures required by GAAP. We have prepared the accompanying unaudited Condensed Consolidated Financial Statements under the rules and regulations of the SEC. In accordance with such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with GAAP. Our unaudited Condensed Consolidated Financial Statements reflect all adjustments of a normal recurring nature that are, in the opinion of management, necessary for a fair presentation of our financial results for the interim periods. You should read these unaudited Condensed Consolidated Financial Statements in conjunction with our Consolidated Financial Statements and related notes included in Item 8 of our 2011 Form 10-K.

Due to the seasonal nature of our business and other factors, our results of operations and our financial condition for the periods presented are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

Basis of Presentation

Our unaudited Condensed Consolidated Financial Statements include our accounts and the accounts of our wholly owned subsidiary. We have eliminated intercompany profits and transactions in consolidation. Certain amounts from prior periods have been reclassified and revised to conform to the current period presentation. The reclassifications and revisions had no material impact on our prior period balances.

Note 2 – Significant Accounting Policies and Methods of Application

Our accounting policies are described in Note 2 to our Consolidated Financial Statements and related notes included in Item 8 of our 2011 Form 10-K. There were no significant changes to our accounting policies during the six months ended June 30, 2012.

Use of Accounting Estimates

The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures. Our estimates are based on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Our estimates may involve complex situations requiring a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. The most significant estimates relate to our accrued unbilled revenues, environmental liability accruals, uncollectible accounts and other allowances for contingent losses, regulatory assets and liabilities, retirement plan benefit obligations, asset retirement obligations, derivative and hedging activities and provisions for income taxes. We evaluate our estimates on an ongoing basis and our actual results could differ from our estimates.

Inventory

Our inventory is carried at cost on a LIFO basis. Inventory decrements occurring during interim periods that are expected to be restored prior to year-end are charged to cost of goods sold at the estimated annual replacement cost, and the difference between this cost and the actual liquidated LIFO layer cost is recorded on the unaudited Condensed Consolidated Statements of Financial Position as a temporary LIFO inventory liquidation. Interim inventory decrements not expected to be restored prior to year-end are charged to cost of goods sold at the actual LIFO cost of the layers liquidated. The inventory decrement as of June 30, 2012 is expected to be restored prior to year-end.

Fair Value Measurements

We have several financial and nonfinancial assets and liabilities subject to fair value measures. The financial assets and liabilities include cash and cash equivalents, receivables, derivative assets and liabilities, accounts payable and debt. The carrying values of cash and cash equivalents, derivative assets and liabilities, short-term debt and other current assets and liabilities approximate fair value. The nonfinancial assets and liabilities include pension and other retirement benefits, which are presented in Note 3 to our Consolidated Financial Statements and related notes included in Item 8 of our 2011 Form 10-K.

As defined in the authoritative guidance related to fair value measurements and disclosures, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the reliability of those inputs in accordance with the fair value hierarchy.

7

Revenue Taxes

We charge customers for revenue taxes and remit amounts owed to various governmental authorities. Our policy is torecord all such taxes charged to customers as operating revenues and the related taxes incurred as operating expenses in our unaudited Condensed Consolidated Statements of Income, regardless of whether the tax is assessed on the company or the customer. Revenue taxes included in operating expenses were $21 million and $81 million for the three and six months ended June 30, 2012 and $31 million and $105 million for the three and six months ended June 30, 2011.

Natural Gas Derivative Instruments

As required by the authoritative guidance, derivative assets and liabilities are classified in the fair value hierarchy in their entirety based on the least reliable 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 unaudited Condensed Consolidated Statements of Cash Flows, and gains and losses are recognized in the unaudited Condensed 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 Condensed 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.

The fair value of natural gas derivative instruments we use to manage exposures arising from changing natural gas prices reflects the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date. We use external market quotes and indices to value substantially all of our derivative instruments. See Note 4 for additional derivative disclosures.

Subject to review by the Illinois Commission, we enter into derivative instruments to hedge the purchase of natural gas for our customers. The costs and impacts associated with each instrument is collected from customers through the PGA mechanism as a component of the cost of gas. 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 unaudited Condensed 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, changes in the fair value of these derivative instruments are deferred or accrued as regulatory assets or liabilities until the related revenue is recognized.

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 company use. These derivative instruments are carried at fair value. To the extent hedge accounting is not elected, changes in such fair values are recorded in the current period as operation 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.

8

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. We are not aware of any evidence that these costs will not be recoverable through either rate riders or base rates, and we believe that we will be able to recover these costs, consistent with our historical recoveries. In the event that the 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.

Our regulatory assets and liabilities are summarized in the following table.

In millions	June 30, 2012		December 31, 2011		June 30, 2011
Regulatory assets – current
Recoverable retirement benefit costs	$	27	$	29	$	21
Recoverable ERC		23		0		0
Other		6		7		11
Total regulatory assets – current		56		36		32
Regulatory assets – noncurrent
Recoverable retirement benefit costs		224		253		186
Recoverable ERC		217		134		46
Unamortized losses on reacquired debt		11		12		13
Other		6		5		7
Total regulatory assets – noncurrent		458		404		252
Total regulatory assets	$	514	$	440	$	284

Regulatory liabilities – current
Bad debt rider	$	31	$	30	$	27
Accrued natural gas costs		60		29		1
Regulatory asset retirement liability		14		14		17
Other		6		4		3
Total regulatory liabilities – current		111		77		48
Regulatory liabilities – noncurrent
Regulatory asset retirement liability		920		896		867
Unamortized investment tax credit		21		22		23
Regulatory income tax liability		12		13		14
Bad debt rider		18		14		11
Other		1		1		1
Total regulatory liabilities – noncurrent		972		946		916
Total regulatory liabilities	$	1,083	$	1,023	$	964

Other than the increase in the estimates of recoverable ERC, there have been no significant changes to our regulatory assets or liabilities from those discussed in Note 2 to our Consolidated Financial Statements and related notes in Item 8 of our 2011 Form 10-K. See Note 7 – Commitment, Guarantees and Contingencies for additional ERC disclosures.

We do not earn a return on our recoverable retirement benefit costs. Our recoverable retirement benefit costs are 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 under or over collections of bad debt expense.

9

Accounting Developments

On January 1, 2012, we adopted authoritative guidance related to fair value measurements. The guidance expands the qualitative and quantitative disclosures required for Level 3 significant unobservable inputs. The guidance also limits the application of the highest and best use premise to non-financial assets and liabilities. This guidance had no impact on our unaudited Condensed Consolidated Financial Statements. See Note 3 for additional fair value disclosures.

On January 1, 2012, we adopted authoritative guidance related to comprehensive income. The guidance eliminates the option to present OCI in the unaudited Condensed Consolidated Statements of Equity, but allows companies to elect to present net income and OCI in one continuous statement (unaudited Condensed Consolidated Statements of Comprehensive Income) or in two consecutive statements. This guidance does not change any of the components of net income or OCI and earnings per share will continue to be calculated based on net income. This guidance did not have a material impact on our unaudited Condensed Consolidated Financial Statements.

Note 3 – Fair Value Measurements

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

Derivative Instruments

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 as of the periods presented. See Note 4 – Derivative Instruments for additional derivative instrument information.

	Recurring fair values
	Derivative instruments
	June 30, 2012					December 31, 2011					June 30, 2011
In millions	Assets		Liabilities			Assets		Liabilities			Assets		Liabilities
Natural gas derivatives
Quoted prices in active markets (Level 1)	$	2	$	(10	)	$	0	$	(14	)	$	1	$	(20	)
Significant other observable inputs (Level 2)		3		(10	)		1		(11	)		1		(12	)
Unobservable inputs (Level 3)		0		0			2		0			7		0
Total carrying value	$	5	$	(20	)	$	3	$	(25	)	$	9	$	(32	)

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 presents the unaudited Condensed Consolidated Statements of Financial Position classification of margin accounts related to derivative instruments.

In millions	June 30, 2012		December 31, 2011		June 30, 2011
Assets
Margin accounts - derivative instruments	$	18	$	21	$	34
Other long-term assets and other deferred debits		1		0		4

Money Market Funds

Our investments in debt and equity securities are classified as cash and cash equivalents on the unaudited Condensed Consolidated Statements of Financial Position. These investments are classified as trading and recorded at fair value.

In millions	June 30, 2012		December 31, 2011		June 30, 2011
Money market funds (1)	$	6	$	0	$	0

(1)  Valued using Level1 inputs.

Debt

Our long-term debt is recorded at amortized cost. At June 30, 2012 and December 31, 2011, we estimated the fair value of our debt using a discounted cash flow technique that incorporated a market interest yield curve with adjustments for duration, optionality and risk profile. At June 30, 2011, we estimated the fair value of debt for our public first mortgage bonds using quoted market pricing information. The following table presents the amortized cost and fair value of our long-term debt as of the following periods.

In millions	June 30, 2012		December 31, 2011		June 30, 2011
Long-term debt amortized cost	$	499	$	499	$	499
Long-term debt fair value (1)	$	621	$	610	$	566

(1)   Valued using Level 2 inputs.

10

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 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 June 30, 2012, $6 million at December 31, 2011 and $5 million at June 30, 2011, 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 $5 million at June 30, 2012, $6 million at December 31, 2011 and $4 million at June 30, 2011.

Quantitative Disclosures Related to Derivative Instruments

As of the periods presented,our derivative instruments were comprised of long natural gas positions. A long position is a contract to purchase natural gas. We had long natural gas contracts outstanding in the following quantities.

In Bcf	June 30, 2012 (1)		December 31, 2011		June 30, 2011
Hedge designation:
Customer use – not designated as hedges		35		30		43
Company use – designated as cash flow hedges		1		1		1
Company use – not designated as hedges		1		0		0
Total		37		31		44

(1)   These contracts have durations of three years or less.

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

Derivative Instruments Impact on the Unaudited Condensed Consolidated Statements of Financial Position

The following table presents the fair value and unaudited Condensed Consolidated Statements of Financial Position classification of our derivative instruments as of the periods presented.

In millions	Unaudited Condensed Consolidated Statements of Financial Position Location	June 30, 2012			December 31, 2011			June 30, 2011
Designated as cash flow hedges
Liability Instruments
Current natural gas contracts	Derivative instrument liabilities – current portion	$	(1	)	$	(1	)	$	(1	)
Total designated as cash flow hedges			(1	)		(1	)		(1	)
Not designated as cash flow hedges
Asset Instruments
Current natural gas contracts	Derivative instrument assets – current portion		4			2			6
Noncurrent natural gas contracts	Derivative instrument assets – noncurrent portion		1			1			3
Liability Instruments
Current natural gas contracts	Derivative instrument liabilities – current portion		(18	)		(24	)		(29	)
Noncurrent natural gas contracts	Other long-term liabilities and deferred credits		(1	)		0			(2	)
Total not designated as cash flow hedges			(14	)		(21	)		(22	)
Total derivative instruments		$	(15	)	$	(22	)	$	(23	)

Derivative Instruments on the Unaudited Condensed Consolidated Statements of Income

Derivatives used to hedge the purchase of natural gas for our customers are 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 gains (losses) deferred were $11 million and $(18) million for the three and six months ended June 30, 2012 and $(8) million and $(4) million for the three and six months ended June 30, 2011.

Non-designated derivatives used to hedge purchases of natural gas for company use are recorded within operation and maintenance expense. Our earnings are subject to volatility for other derivatives not designated as hedges. Gains and losses recognized in income were immaterial for the three and six months ended June 30, 2012 and 2011.

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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. We also provide health care and life insurance benefits to eligible retired employees under our other retirement benefit plan that includes a limit on our share of cost for employees hired after 1982.

Our pension and other retirement 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 such services are recorded in accumulated OCI.

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 operation and maintenance expense, net of amounts charged to affiliates.

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 other retirement plan benefit obligation, but we will continue to evaluate the impact of future regulations and interpretations.

In July 2012, the Pension Protection Act of 2006, was changed to provide near-term funding relief to certain pension plans and to increase Pension Benefit Guaranty Corporation premiums. As a result, any required cash contributions, which statutorily was based on the two-year average of interest rates, will be adjusted so that they are within 10% of the discount rate derived using a 25-year average and 30% of the 25-year average interest rate beginning in 2016. Due to our plan’s current funding status, we do not believe this legislation will have a material impact to us.

Pension Benefits

Following are the cost components of our defined benefit pension plan for the periods indicated:

	Three months ended June 30,						Six months ended June 30,
In millions	2012			2011			2012			2011
Service cost	$	3		$	2		$	6		$	5
Interest cost		4			4			8			8
Expected return on plan assets		(8	)		(8	)		(16	)		(16	)
Recognized actuarial loss		4			3			8			5
Net pension benefit cost	$	3		$	1		$	6		$	2

Other Retirement Benefits

Following are the cost components of our other retirement plan for the periods indicated:

	Three months ended June 30,				Six months ended June 30,
In millions	2012		2011		2012		2011
Service cost	$	0	$	0	$	1	$	1
Interest cost		3		3		6		6
Recognized actuarial loss		2		2		4		3
Net benefit cost	$	5	$	5	$	11	$	10

In the second quarter of 2012, the estimated benefit obligation for our retiree medical plan decreased to $263 million as a result of final updated census data and claims costs. As of December 31, 2011, our retiree medical plan benefit obligation was $283 million.

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Note 6 – Debt and Credit Facility

The following table provides maturity dates, weighted average interest rates and amounts outstanding for our various debt securities that are included in our unaudited Condensed Consolidated Statements of Financial Position. For additional information on our debt, see Note 6 in our Consolidated Financial Statements and related notes in Item 8 of our 2011 Form 10-K.

	June 30, 2012									June 30, 2011
Dollars in millions	Year(s) due		Weighted average interest rate (1)			Outstanding		Outstanding at  December 31, 2011		Weighted average interest rate (1)			Outstanding
Commercial paper (2)		n/a		0.5	%	$	0	$	452		0.2	%	$	66
Long-term debt
First mortgage bonds		2016-2038		5.6	%	$	500	$	500		5.7	%	$	500
Less: Unamortized debt discount, net of premium		n/a		n/a			1		1		n/a			1
Total long-term debt				5.6	%	$	499	$	499		5.7	%	$	499
Total debt						$	499	$	951				$	565

(1)   Interest rates are calculated based on the daily average balance outstanding for the six months ended June 30.

(2)   The weighted average interest rate as of June 30, 2011 was 0.1%.

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, 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 June 30, 2012 was 43%, which is within our required range.

The credit facility also 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.

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 triggering events in our debt instruments that are tied to changes in our specified credit ratings. We were in compliance with all existing debt provisions and covenants, both financial and non-financial, for all periods presented.

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Note 7 - Commitments, Guarantees and Contingencies

There were no significant changes to our contractual obligations described in Note 7 to our Consolidated Financial Statements and related notes in Item 8 of our 2011 Form 10-K other than those related to ERC remediation costs and  SNG contracts as described below.

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.

Substitute Natural Gas

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

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 agreement required, among other things, the developer to begin construction of the SNG plant by July 1, 2012. The developer did not meet this deadline and, as a result, the agreement automatically terminated.

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 filed applications for a rehearing with the Illinois Commission seeking changes to the final form of the contract. The Illinois Commission agreed to grant a rehearing. On July 11, 2012, the Illinois Commission issued its order on rehearing in which it modified its earlier order to change certain of the terms of the approved form of SNG purchase contract. We have appealed the Illinois Commission’s decision to an Illinois appellate court. Neither Nicor Gas nor the developer has yet signed the form of contract approved by the Illinois Commission. In May 2012, the Illinois legislature passed a bill that directs the Illinois Commission to approve a final form of contract that differs in certain respects from the form the Illinois Commission approved in its July 11, 2012 order and that purports to address issues raised in the DuPage County litigation. Unless vetoed by the Governor of Illinois by August 10, 2012, this bill will become law. If the bill becomes law, it is not clear what, if any, effect it will have on the pending litigation concerning this SNG project.

The purchase price of the SNG that may be produced from this proposed coal gasification plant may significantly exceed market prices for natural gas and is expected to be dependent upon a variety of factors, including the developer’s financing, plant construction costs and volumes sold, which is currently not determinable. The Illinois law pertaining to this plant provides that the price paid for SNG purchased from the plant is to be considered prudent and not subject to review or disallowance by the Illinois Commission. As such, Illinois law effectively requires our customers to provide subordinated financial support to the developer.

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 remediation of MGP sites, as discussed in Environmental Matters. We believe that the likelihood of payment under our other environmental indemnifications is remote. No liability has been recorded for such indemnifications.

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 Matters

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at our 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 are party 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, 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.

Our ERC liabilities are estimates of future remediation costs for our former operating sites that are contaminated. Our estimates are based on conventional engineering estimates and the use of probabilistic models of potential costs when such estimates cannot be made, which is generally the case when remediation has not commenced or during the early years of a remediation effort. For those elements of the program where we cannot perform engineering estimates, there remains considerable variability in future cost estimates. Accordingly, we have established a probabilistic model to determine a range of potential expenditures to remediate and monitor our former operating sites. We cannot at this time identify any single number within this range as a better estimate of likely future costs, and we generally have recorded the low end of the range for our probabilistic cost estimates.

As we 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 assumptions, which we refine and update on an ongoing basis. During the second quarter of 2012, we completed our probabilistic models and engineering estimates, which resulted in a $109 million increase from the amount recorded at December 31, 2011. In accordance with Illinois Commission authorization, the company has been recovering, and expects to continue to recover, these costs from our customers subject to annual prudence reviews and, accordingly, we have recorded a regulatory asset associated with the recorded liabilities. The following table provides more information on the costs related to remediation of our former operating sites.

In millions	Probabilistic model cost estimate range		Engineering estimates		Amount recorded		Expected costs over next twelve months
	$	193 – $443	$	50	$	243	$	27

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 consolidated financial position or cash flows. For additional litigation information, see Note 7 in our Consolidated Financial Statements and related notes in Item 8 of our 2011 Form 10-K.

PBR Proceeding Our PBR plan for natural gas costs went into effect in 2000 and was terminated by us effective January 1, 2003. Under this 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 review by the Illinois Commission as there are allegations that we acted improperly in connection with the PBR plan. 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. 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, regarding false information related to our PBR plan. 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. We have committed to cooperate fully in the reviews of 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, which is not recoverable from our customers. This liability is reflected in our unaudited Condensed Consolidated Statements of Financial Position at June 30, 2012 and December 31, 2011. The stipulated resolution does not constitute an admission of fault, and it is not final and 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 before the Administrative Law Judge were held during the first quarter of 2012 and post-trial legal briefs from the parties were submitted during the second quarter of 2012. Following the submission of legal briefs, the Administrative Law Judges will issue a proposed decision. There is no date scheduled for the issuance of that proposed decision.

We are unable to predict the outcome of the Illinois Commission’s review or our potential exposure. Since the PBR plan and historical gas costs are still under Illinois Commission review, the final outcome could be materially different than the amount reflected in our financial statements as of June 30, 2012.

Other We are also involved in service warranty product actions, municipal tax matters, an IAGO investigation and an investigation by the United States Environmental Protection Agency regarding the presence of polychlorinated biphenyl (PCB) contaminated liquids in our distribution system. 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 these contingencies, the final disposition of these matters is not expected to have a material adverse impact on our liquidity or financial condition. For additional litigation information on these matters, see Note 7 in our Consolidated Financial Statements and related notes in Item 8 of our 2011 Form 10-K.

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

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Note 8 – 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 from affiliates of $15 million and $18 million for the three and six months ended June 30, 2012 and net charges to affiliates of $3 million and $10 million for the three and six months ended June 30, 2011.

Our key executives and managerial employees participate in our parent company’s stock-based compensation plans. We recognized the compensation expense related to these plans in operation and maintenance expense. Charges related to these plans from AGL Services Company were less than $1 million for the three and six months ended June 30, 2012 and charges from Nicor were $1 million and $2 million for the three and six months ended June 30, 2011.

We currently are prohibited by regulations of the Illinois Commission from loaning money to affiliates. However, we are permitted under these regulations to receive cash advances from AGL Resources. The balance of any such advances may not exceed the balance of funds available to us under our existing credit agreements or commercial paper facilities with unaffiliated third parties. Interest is charged on such loans at the lower of our commercial paper rate or AGL Resources’ actual interest cost for the funds obtained or used to provide us the cash advance. We received no cash advances from AGL Resources during the first half of 2012. Prior to the completion of the merger, we participated in a cash management system with other subsidiaries of Nicor. At June 30, 2011 we owed $9 million to Nicor which was repaid in 2011. Interest expense on advances from Nicor for the three and six months ended June 30, 2011 was immaterial.

Under its utility-bill management products, Nicor Solutions pays us for the utility bills issued to their utility-bill management customers. We recorded revenues of $4 million and $14 million for the three and six months ended June 30, 2012 and $7 million and $21 million for the three and six months ended June 30, 2011 associated with the payments Nicor Solutions made 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 $1 million and $3 million for the three and six months ended June 30, 2012 and 2011 for such items. Additionally, Nicor Advanced Energy may pay or receive inventory imbalance adjustments. The amounts Nicor Advanced Energy received from us for the three and six months ended June 30, 2012 were immaterial. There were no such charges for the three and six months ended June 30, 2011.

Horizon Pipeline charged us $2 million and $5 million for the three and six months ended June 30, 2012 and 2011 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.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our unaudited Condensed Consolidated Financial Statements and the notes to our unaudited Condensed Consolidated Financial Statements in this quarterly filing, as well as our 2011 Form 10-K. Results for the interim periods presented are not necessarily indicative of the results to be expected for the full fiscal year due to seasonal and other factors.

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. 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; limits on pipeline capacity; 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 resulting from the 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 disruptions in the capital markets and lending environment and the economic downturn; general economic conditions; uncertainties about environmental issues and the related impact of such issues, including our environmental remediation plans; the impact of changes in weather, including climate change; 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 our actual 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.

Executive Summary

We are a natural gas distribution company. 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, AGL Resources and Nicor merged 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 prior to December 9, 2014.

Because of our significant outstanding public debt, the impact of the acquisition (push-down accounting) was not required to be, and has not been, reflected in our unaudited Condensed Consolidated Financial Statements.

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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, to residential, commercial and industrial customers, from the date of the last bill to the end of the reporting period. No individual customer or industry accounts for a significant portion of our revenues.

We evaluate our performance using the measures of operating margin and EBIT. Operating margin is a non-GAAP measure that is calculated as operating revenues minus cost of goods sold and revenue tax expense. Operating margin excludes operation and maintenance expense, depreciation and amortization, certain taxes other than income taxes, and the gain or loss on the sale of our assets, if any. These items are included in our calculation of operating income as reflected in our unaudited Condensed Consolidated Statements of Income. EBIT is also a non-GAAP measure that includes operating income and other income and expenses. Items that we do not include in EBIT are financing costs, including interest and debt expense and income taxes.

We believe operating margin is a better indicator than operating revenues for the contribution resulting from customer growth since the cost of goods sold and revenue tax expense can vary significantly and are generally billed directly to our customers. We have a franchise gas cost rider, an energy efficiency rider and a bad debt rider. Changes in revenue and operating margin attributable to these riders are generally expected to be offset by changes within operation and maintenance expense with generally no impact on operating income.

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

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

	Three months ended June 30,									Six months ended June 30,
In millions	2012			2011			Change			2012			2011			Change
Operating revenues	$	240		$	359		$	(119	)	$	862		$	1,275		$	(413	)
Cost of goods sold		(80	)		(182	)		102			(451	)		(822	)		371
Revenue tax expense (1)		(21	)		(31	)		10			(81	)		(105	)		24
Operating margin		139			146			(7	)		330			348			(18	)
Revenue tax expense (1)		21			31			(10	)		81			105			(24	)
Operating expenses		(141	)		(149	)		8			(343	)		(358	)		15
Total operating expenses (2)		(120	)		(118	)		(2	)		(262	)		(253	)		(9	)
Operating income and EBIT		19			28			(9	)		68			95			(27	)
Interest expense, net		(8	)		(8	)		0			(16	)		(15	)		(1	)
Earnings before income taxes		11			20			(9	)		52			80			(28	)
Income tax expense		(4	)		(7	)		3			(20	)		(30	)		10
Net income	$	7		$	13		$	(6	)	$	32		$	50		$	(18	)

(1)   Adjustment for revenue tax expenses which are passed directly through to our customers.

(2)   Excludes cost of goods sold and revenue tax expense.

Our EBIT in the second quarter decreased by $9 million or 45% compared to last year as shown in the following table.

In millions
EBIT – for second quarter of 2011	$	28
Operating margin
Reduced revenues primarily from warmer weather and reduced demand		(7	)
Decrease in operating margin		(7	)
Operating expenses
Increased depreciation expenses		1
Increased retirement benefit costs and other		1
Increase in operating expenses		2
EBIT – for second quarter of 2012	$	19

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Our EBIT for the six months ended June 30, 2012 decreased by $27 million or 28% compared to last year as shown in the following table.

In millions
EBIT – for six months of 2011	$	95
Operating margin
Reduced revenues primarily from warmer weather and reduced demand		(24	)
Increased revenues due to the impact of cost-recovery riders which are offset in operation and maintenance expense		6
Decrease in operating margin		(18	)
Operating expenses
Increased expenses due to the impact of cost-recovery riders which are offset in revenue and operating margin		6
Increased depreciation expense		3
Increase in operating expenses		9
EBIT – for six months of 2012	$	68

Our income tax expense decreased by $3 million or 43% for the second quarter 2012, compared to the same period in 2011 primarily due to lower earnings. Income tax expense decreased by $10 million or 33% for the six months ended June 30, 2012 compared to the same period in 2011 primarily due to lower earnings.

Selected weather, customer and volume metrics as of and for the three and six months ended June 30, 2012 and 2011, 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 warm weather during the first quarter of 2012 had 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. Volumes delivered to customers, as shown in the following table, reflect the effects of warmer weather and our customers’ demand for natural gas compared to the prior year.

Weather Heating degree days (1)
	Three months ended June 30,						2012 vs. normal			2012 vs. 2011			Six months ended June 30,						2012 vs. normal			2012 vs. 2011
	Normal		2012		2011		colder / (warmer)			colder / (warmer)			Normal		2012		2011		colder / (warmer)			colder / (warmer)
Illinois		617		542		755		(12	)%		(28	)%		3,519		2,900		3,954		(18	)%		(27	)%

Customers (in thousands)	Three months ended June 30,				2012 vs. 2011			Six months ended June 30,				2012 vs. 2011
	2012		2011		% change			2012		2011		% change
Average end-use customers		2,190		2,189		0.05	%		2,191		2,190		0.05	%

Volumes (In Bcf)	Three months ended June 30,				2012 vs. 2011			Six months ended June 30,				2012 vs. 2011
	2012		2011		% change			2012		2011		% change
Delivered		68		77		(12	)%		232		281		(17	)%

(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.

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 at times the SEC.

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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 for the foreseeable future. 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 in our 2011 Form 10-K 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. 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 in order to manage our existing financing costs.

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

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 June 30, 2012 and reflects no change from 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

Our credit ratings depend largely on our financial performance, and a downgrade in our current ratings, particularly below investment grade, would 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, judgments in excess of specified amounts and certain impairments to the guarantee.

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. This ratio, as defined within our debt agreements, includes standby letters of credit and surety bonds and excludes accumulated OCI. Adjusting for these items, our debt-to-capitalization ratio for June 30, 2012 was 43%, which is within our required range.

We were in compliance with all of our debt provisions and covenants, both financial and non-financial, for all periods presented.

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 Note 6 to our unaudited Condensed Consolidated Financial Statements under item 1 herein.

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Cash Flows

The following table provides a summary of our operating, investing and financing cash flows for the periods presented.

	Six months ended June 30,
In millions	2012			2011			Variance
Net cash provided by (used in):
Operating activities	$	537		$	520		$	17
Investing activities		(79	)		(82	)		3
Financing activities		(452	)		(438	)		(14	)
Net increase in cash and cash equivalents	$	6		$	0		$	6

Cash Flow from Operating ActivitiesYear-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.

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.

Net cash flow provided from operating activities increased $17 million, or 3%, for the six months ended June 30, 2012 compared to the prior year. The increase in operating cash flow is primarily related to a $20 million increase in cash provided from changes in accounts receivable and a $10 million decrease in taxes paid. These changes were partially offset by other changes in working capital, most significantly the decrease in cash provided from the temporary LIFO liquidation in 2012 compared to the prior year.

Cash Flow from Investing ActivitiesNet cash flow used for investing activities, which primarily consists of our PP&E expenditures, decreased $3 million, or 4%, for the six months ended June 30, 2012 compared to the prior year.

Cash Flow from Financing Activities Information regarding our short-term debt for the six months ended June 30, 2012 is summarized below.

In millions	Period end balance outstanding(1)		Daily average balance outstanding(2)		Minimum balance outstanding (2)		Largest balance outstanding(2)
Commercial paper	$	0	$	144	$	0	$	456

(1)   As of June 30, 2012.

(2)   For the six months ended June 30, 2012.

The largest, minimum and daily average balances borrowed under our commercial paper program are important when assessing the intra-period fluctuation of our short-term borrowings and any potential liquidity risk. The fluctuations are due to our seasonal cash requirements.

Increasing natural gas commodity prices can have a significant impact on our commercial paper borrowings. Based on current natural gas prices and our expected injection plan, a $1 NYMEX price change could result in a $91 million change of working capital requirements. This range is sensitive to the timing of storage injections and withdrawals, collateral requirements and our portfolio position. 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 June 30, 2012. It is possible that one or more lending commitments could be unavailable to us if the lender defaulted due to lack of funds or insolvency. However, based on our current assessment of our lenders’ creditworthiness, we believe the risk of lender default is minimal.

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

There were no significant changes to our contractual obligations described in Note 7 of our Consolidated Financial Statements and related notes in Item 8 of our 2011 Form 10-K other than the revised ERC remediation costs and termination of the SNG contract.

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

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 agreement required, among other things, the developer to begin construction of the SNG plant by July 1, 2012. The developer did not meet this deadline and, as a result, the agreement automatically terminated.

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 filed applications for a rehearing with the Illinois Commission seeking changes to the final form of the contract. The Illinois Commission agreed to grant a rehearing. On July 11, 2012, the Illinois Commission issued its order on rehearing in which it modified its earlier order to change certain of the terms of the approved form of SNG purchase contract. We have appealed the Illinois Commission’s decision to an Illinois appellate court. Neither Nicor Gas nor the developer has yet signed the form of contract approved by the Illinois Commission. In May 2012, the Illinois legislature passed a bill that directs the Illinois Commission to approve a final form of contract that differs in certain respects from the form the Illinois Commission approved in its July 11, 2012 order and that purports to address issues raised in the DuPage County litigation. Unless vetoed by the Governor of Illinois by August 10, 2012, this bill will become law. If the bill becomes law, it is not clear what, if any, effect it will have on the pending litigation concerning this SNG project.

The purchase price of the SNG that may be produced from this proposed coal gasification plant may significantly exceed market prices for natural gas and is expected to be dependent upon a variety of factors, including the developer’s financing, plant construction costs and volumes sold, which is currently not determinable. The Illinois law pertaining to this plant provides that the price paid for SNG purchased from the plant is to be considered prudent and not subject to review or disallowance by the Illinois Commission. As such, Illinois law effectively requires our customers to provide subordinated financial support to the developer.

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 proceeding Our PBR plan for natural gas costs went into effect in 2000 and was terminated by us effective January 1, 2003. Under this 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 review by the Illinois Commission as there are allegations that we acted improperly in connection with the PBR plan. 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. 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, regarding false information related to our PBR plan. 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. We have committed to cooperate fully in the reviews of 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, which is not recoverable from our customers. The stipulated resolution does not constitute an admission of fault, and it is not final and 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 before the Administrative Law Judge were held during the first quarter of 2012 and post-trial legal briefs from the parties were submitted during the second quarter of 2012. Following the submission of legal briefs, the Administrative Law Judges will issue a proposed decision. There is no date scheduled for the issuance of that proposed decision.

We are unable to predict the outcome of the Illinois Commission’s review or our potential exposure. Since the PBR plan and historical gas costs are still under Illinois Commission review, the final outcome could be materially different than the amount reflected in our financial statements as of June 30, 2012. For additional information on our PBR proceedings, see Note 7 in our Consolidated Financial Statements and related notes in Item 8 of our 2011 Form 10-K.

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Environmental remediation costs We have conducted environmental investigations and remedial activities at our former manufactured gas plant sites. Additional information about these sites is presented in Item 1 – Notes to the Condensed Consolidated Financial Statements – 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 unaudited Condensed Consolidated Financial Statements and accompanying notes. Those judgments and estimates have a significant effect on our financial statements primarily due to the need to make estimates about the effects of matters that are inherently uncertain. Actual results could differ from those estimates. We frequently reevaluate our judgments and estimates that are based upon historical experience and various other assumptions that we believe to be reasonable under the circumstances.

Each of our critical accounting estimates involves 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. There have been no significant changes to our critical accounting estimates from those disclosed in our Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2011 Form 10-K, except for the $109 million increase to our ERC liabilities.

Our critical accounting estimates used in the preparation of our unaudited Condensed Consolidated Financial Statements include the following:

·Environmental Remediation Costs

·Derivatives and Hedging Activities

·Contingencies

·Pension and Other Retirement Plans

·Credit Risk

·Unbilled Revenues

·Regulatory Assets and Liabilities

ITEM 3. 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. Our practice is to manage these risks utilizing derivative instruments and other methods, as deemed appropriate.

There have been no significant changes in our exposure to market risk from those disclosed in our Quantitative and Qualitative Disclosures About Market Risk in our 2011 Form 10-K.

Item 4. Controls and Procedures

(a) Evaluation 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), as of June 30, 2012, the end of the period covered by this report. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2012, 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.

(b) Changes in Internal Control over Financial Reporting. There were no changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2012, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings

The nature of our business ordinarily results in periodic regulatory proceedings before the Illinois Commission. In addition, we are party, as both plaintiff and defendant, to a number of lawsuits related to our business on an ongoing basis. Management believes that the outcome of all regulatory proceedings and litigation in which we are currently involved will not have a material adverse effect on our consolidated financial condition. For more information regarding some of these proceedings, see Note 7 to our unaudited Condensed Consolidated Financial Statements under the caption “Litigation.”

Item 1A. Risk Factors

For information regarding our risk factors see the factors discussed in Part I, Item 1A - Risk Factors in our 2011 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in our 2011 Form 10-K are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

Item 6. Exhibits

Exhibit
Number	Description of Document
12.01	Statement of Computation of Ratio of Earnings to Fixed Charges.
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)
101.CAL	XBRL Taxonomy Extension Calculation Linkbase. (1)
101.DEF	XBRL Taxonomy Definition Linkbase. (1)
101.LAB	XBRL Taxonomy Extension Labels Linkbase. (1)
101.PRE	XBRL Taxonomy Extension Presentation Linkbase. (1)

(1) Furnished, not filed   Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in extensible business reporting language (XBRL): (i) Document and Entity Information; (ii) unaudited Condensed Consolidated Statements of Financial Position at June 30, 2012, December 31, 2011 and June 30, 2011; (iii) unaudited Condensed Consolidated Statements of Income for the three and six months ended June 30, 2012 and 2011; (iv) unaudited Condensed Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2012 and 2011; (v) unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2012 and 2011; and (vi) Notes to unaudited Condensed 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 Quarterly Report.  

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SIGNATURE

Pursuant to the requirements 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.

NICOR GAS COMPANY

(Registrant)

Date: August 1, 2012	/s/ Andrew W. Evans
	Executive Vice President and Chief Financial Officer