Edgar Filing: AGL RESOURCES INC

10-Q




UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OF
THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended September 30, 2015



Commission File Number 1-14174

AGL RESOURCES INC.
Ten Peachtree Place NE, Atlanta, Georgia 30309
404-584-4000

Georgia	58-2210952
(State of incorporation)	(I.R.S. Employer Identification No.)


AGL Resources Inc. (1) has filed all reports required to be filed by Section 13 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.

AGL Resources Inc. has submitted electronically and posted on its corporate website every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months.

AGL Resources Inc. is a large accelerated filer and is not a shell company.

The number of shares of AGL Resources Inc.’s common stock, $5.00 Par Value, outstanding as of November 4, 2015, was 120,239,934.

Table of Contents

AGL RESOURCES INC.

Quarterly Report on Form 10-Q

For the Quarter Ended September 30, 2015

TABLE OF CONTENTS



		Page
	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	6
	Condensed Consolidated Statements of Equity	7
	Condensed Consolidated Statements of Cash Flows	8
	Notes to Condensed Consolidated Financial Statements (Unaudited)	9
	Note 1 - Organization and Basis of Presentation	9
	Note 2 - Proposed Merger with Southern Company	9
	Note 3 - Significant Accounting Policies and Methods of Application	10
	Note 4 - Regulated Operations	12
	Note 5 - Fair Value Measurements	14
	Note 6 - Derivative Instruments	15
	Note 7 - Employee Benefit Plans	17
	Note 8 - Debt and Credit Facilities	17
	Note 9 - Equity	19
	Note 10 - Non-Wholly Owned Entities	20
	Note 11 - Commitments, Guarantees and Contingencies	22
	Note 12 - Segment Information	24
	Note 13 - Discontinued Operations	27
2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	28
	Forward-Looking Statements	28
	Executive Summary	29
	Results of Operations	31
	Liquidity and Capital Resources	38
	Critical Accounting Policies and Estimates	38
	Accounting Developments	41
3.	Quantitative and Qualitative Disclosures About Market Risk	41
4.	Controls and Procedures	44

	PART II - OTHER INFORMATION

1.	Legal Proceedings	45
1A	Risk Factors	45
2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
6.	Exhibits	47

	SIGNATURE	48

Glossary of Key Terms

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GLOSSARY OF KEY TERMS
2014 Form 10-K	Our Annual Report on Form 10-K for the year ended December 31, 2014, filed with the SEC on February 12, 2015
AGL Capital	AGL Capital Corporation
AGL Credit Facility	$1.3 billion credit agreement entered into by AGL Capital to support its commercial paper program
AGL Resources	AGL Resources Inc., together with its consolidated subsidiaries
Atlanta Gas Light	Atlanta Gas Light Company
Atlantic Coast Pipeline	Atlantic Coast Pipeline, LLC
Bcf	Billion cubic feet
Central Valley	Central Valley Gas Storage, LLC
CUB	Citizens Utility Board
EBIT	Earnings before interest and taxes, the primary measure of our reportable segments’ profit or loss, which includes operating income and other income and excludes interest on debt and income tax expense
ERC	Environmental remediation costs
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
Florida Commission	Florida Public Service Commission, the state regulatory agency for Florida City Gas
GAAP	Accounting principles generally accepted in the United States of America
Georgia Commission	Georgia Public Service Commission, the state regulatory agency for Atlanta Gas Light
Golden Triangle	Golden Triangle Storage, Inc.
Heating Degree Days	A measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
Heating Season	The period from November through March when natural gas usage and operating revenues are generally higher
Horizon Pipeline	Horizon Pipeline Company, LLC
Illinois Commission	Illinois Commerce Commission, the state regulatory agency for Nicor Gas
Jefferson Island	Jefferson Island Storage & Hub, LLC
LIFO	Last-in, first-out
LNG	Liquefied natural gas
LOCOM	Lower of weighted average cost or current market price
Marketers	Marketers selling retail natural gas in Georgia and certificated by the Georgia Commission
Maryland Commission	Maryland Public Service Commission, the state regulatory agency for Elkton Gas
Merger Agreement	Agreement and Plan of Merger entered into on August 23, 2015 by Southern Company, AMS Corp., a subsidiary of Southern Company, and AGL Resources
MGP	Manufactured Gas Plant
Moody’s	Moody’s Investors Service
New Jersey BPU	New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas
Nicor Gas	Northern Illinois Gas Company, doing business as Nicor Gas Company
Nicor Gas Credit Facility	$700 million credit facility entered into by Nicor Gas to support its commercial paper program
NYMEX	New York Mercantile Exchange, Inc.
OCI	Other comprehensive income
Operating margin	A non-GAAP measure of income, calculated as operating revenues minus cost of goods sold and revenue tax expense
PBR	Performance-based rate
PennEast Pipeline	PennEast Pipeline Company, LLC
PGA	Purchased gas adjustment
Piedmont	Piedmont Natural Gas Company, Inc.
Pivotal Utility	Pivotal Utility Holdings, Inc., doing business as Elizabethtown Gas, Elkton Gas and Florida City Gas
PRP	Pipeline Replacement Program, Atlanta Gas Light's 15-year infrastructure replacement program, which ended in December 2013
S&P	Standard & Poor’s Ratings Services
SEC	Securities and Exchange Commission
Sequent	Sequent Energy Management, L.P.
Southern Company	The Southern Company
SouthStar	SouthStar Energy Services, LLC
Triton	Triton Container Investments, LLC
Tropical Shipping	Tropical Shipping and Construction Company Limited
U.S.	The United States of America
VaR	Value-at-risk
VIE	Variable interest entity
Virginia Commission	Virginia State Corporation Commission, the state regulatory agency for Virginia Natural Gas
Virginia Natural Gas	Virginia Natural Gas, Inc.
WACOG	Weighted average cost of gas

Glossary of Key Terms

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PART I – FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(UNAUDITED)



	As of
In millions, except share and per share amounts	September 30, 2015			December 31, 2014			September 30, 2014
Current assets
Cash and cash equivalents	$	19		$	31		$	32
Receivables
Energy marketing	475			779			544
Natural gas, unbilled revenues and other	339			797			409
Less allowance for uncollectible accounts	34			35			37
Total receivables, net	780			1,541			916
Inventories
Natural gas	632			694			777
Other	27			22			19
Total inventories	659			716			796
Derivative instruments	151			245			102
Prepaid expenses	74			223			78
Regulatory assets	64			83			105
Other	29			47			60
Total current assets	1,776			2,886			2,089
Long-term assets and other deferred debits
Property, plant and equipment	12,141			11,552			11,352
Less accumulated depreciation	2,560			2,462			2,427
Property, plant and equipment, net	9,581			9,090			8,925
Goodwill	1,813			1,827			1,827
Regulatory assets	637			631			637
Intangible assets	113			125			130
Other	286			329			324
Total long-term assets and other deferred debits	12,430			12,002			11,843
Total assets	$	14,206		$	14,888		$	13,932
Current liabilities
Short-term debt	$	886		$	1,175		$	681
Current portion of long-term debt	425			200			200
Energy marketing trade payables	502			777			612
Other accounts payable – trade	274			312			298
Accrued expenses	177			229			173
Customer deposits and credit balances	150			125			122
Regulatory liabilities	139			112			118
Accrued environmental remediation liabilities	73			87			82
Derivative instruments	58			88			45
Other	118			114			131
Total current liabilities	2,802			3,219			2,462
Long-term liabilities and other deferred credits
Long-term debt	3,150			3,581			3,584
Accumulated deferred income taxes	1,767			1,724			1,655
Regulatory liabilities	1,608			1,601			1,567
Accrued pension and retiree welfare benefits	528			525			406
Accrued environmental remediation liabilities	346			327			372
Other	95			83			84
Total long-term liabilities and other deferred credits	7,494			7,841			7,668
Total liabilities and other deferred credits	10,296			11,060			10,130
Commitments, guarantees and contingencies (see Note 11)
Equity
Common stock, $5 par value; 750,000,000 shares authorized; outstanding: 120,249,058 shares at September 30, 2015, 119,647,149 shares at December 31, 2014, and 119,564,666 shares at September 30, 2014	602			599			599
Additional paid-in capital	2,095			2,087			2,080
Retained earnings	1,375			1,312			1,222
Accumulated other comprehensive loss	(195		)	(206		)	(133		)
Treasury shares, at cost: 216,523 shares at September 30, 2015, December 31, 2014, and September 30, 2014	(8		)	(8		)	(8		)
Total common shareholders’ equity	3,869			3,784			3,760
Noncontrolling interest	41			44			42
Total equity	3,910			3,828			3,802
Total liabilities and equity	$	14,206		$	14,888		$	13,932

See Notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Key Terms

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AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)



	Three Months Ended September 30,						Nine Months Ended September 30,
In millions, except per share amounts	2015			2014			2015			2014
Operating revenues (includes revenue taxes of $9 and $83 for the three and nine months in 2015, respectively, and $9 and $103 for the three and nine months in 2014, respectively)	$	584		$	589		$	2,979		$	3,940
Operating expenses
Cost of goods sold	146			198			1,303			2,000
Operation and maintenance	204			193			662			693
Depreciation and amortization	98			93			293			281
Taxes other than income taxes	28			30			142			160
Merger-related expenses	35			—			35			—
Goodwill impairment	14			—			14			—
Total operating expenses	525			514			2,449			3,134
Gain on disposition of assets	—			3			—			3
Operating income	59			78			530			809
Other income	2			3			9			8
Interest expense, net	(42		)	(44		)	(128		)	(135		)
Income before income taxes	19			37			411			682
Income tax expense	7			14			150			254
Income from continuing operations	12			23			261			428
Loss from discontinued operations, net of tax	—			(31		)	—			(80		)
Net income (loss)	12			(8		)	261			348
Less net income attributable to noncontrolling interest	1			—			15			14
Net income (loss) attributable to AGL Resources	$	11		$	(8	)	$	246		$	334
Net income (loss) attributable to AGL Resources
Income from continuing operations	$	11		$	23		$	246		$	414
Loss from discontinued operations, net of tax	—			(31		)	—			(80		)
Net income (loss) attributable to AGL Resources	$	11		$	(8	)	$	246		$	334
Per common share information
Basic earnings (loss) per common share
Continuing operations	$	0.09		$	0.19		$	2.06		$	3.48
Discontinued operations	—			(0.25		)	—			(0.67		)
Basic earnings (loss) per common share attributable to AGL Resources	$	0.09		$	(0.06	)	$	2.06		$	2.81
Diluted earnings (loss) per common share
Continuing operations	$	0.09		$	0.19		$	2.05		$	3.47
Discontinued operations	—			(0.25		)	—			(0.67		)
Diluted earnings (loss) per common share attributable to AGL Resources	$	0.09		$	(0.06	)	$	2.05		$	2.80
Cash dividends declared per common share	$	0.51		$	0.49		$	1.53		$	1.47
Weighted average number of common shares outstanding
Basic	119.6			119.0			119.5			118.8
Diluted	120.0			119.4			119.8			119.2

See Notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Key Terms

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AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(UNAUDITED)



	Three Months Ended September 30,						Nine Months Ended September 30,
In millions	2015			2014			2015			2014
Net income (loss)	$	12		$	(8	)	$	261		$	348
Other comprehensive (loss) income, net of tax
Retirement benefit plans
Reclassification of actuarial losses to net benefit cost (net of income tax of $3 and $7 for the three and nine months ended September 30, 2015, respectively, and $2 and $5 for the three and nine months ended September 30, 2014, respectively)	3			2			10			7
Reclassification of prior service credits to net benefit cost (net of income tax of $1 for the three and nine months ended September 30, 2015)	(1		)	—			(1		)	(1		)
Retirement benefit plans, net	2			2			9			6
Cash flow hedges, net of tax
Net derivative instruments gain (loss) arising during the period (net of income tax of $18 and $1 for the three and nine months ended September 30, 2015, respectively, and $0 for the three and nine months ended September 30, 2014)	(30		)	(2		)	(3		)	2
Reclassification of realized derivative instruments (gain) loss to net income (net of income tax of $0 for the three and nine months ended September 30, 2015, and $0 and $1 for the three and nine months ended September 30, 2014, respectively)	1			—			5			(5		)
Cash flow hedges, net	(29		)	(2		)	2			(3		)
Other comprehensive (loss) income, net of tax	(27		)	—			11			3
Comprehensive (loss) income	(15		)	(8		)	272			351
Less comprehensive income attributable to noncontrolling interest	—			—			15			14
Comprehensive (loss) income attributable to AGL Resources	$	(15	)	$	(8	)	$	257		$	337

See Notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Key Terms

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AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(UNAUDITED)



	AGL Resources Shareholders
	Common stock			Additional paid-in capital			Retained earnings			Accumulated other comprehensive loss			Treasury shares			Noncontrolling interest			Total
In millions, except per share amounts	Shares	Amount		Additional paid-in capital			Retained earnings			Accumulated other comprehensive loss			Treasury shares			Noncontrolling interest			Total
Balance as of December 31, 2013	118.9	$	595	$	2,054		$	1,063		$	(136	)	$	(8	)	$	45		$	3,613
Net income	—	—		—			334			—			—			14			348
Other comprehensive income	—	—		—			—			3			—			—			3
Dividends on common stock ($1.47 per share)	—	—		—			(175		)	—			—			—			(175		)
Distribution to noncontrolling interest	—	—		—			—			—			—			(17		)	(17		)
Stock granted, share-based compensation, net of forfeitures	—	—		(11		)	—			—			—			—			(11		)
Stock issued, dividend reinvestment plan	0.1	1		8			—			—			—			—			9
Stock issued, share-based compensation, net of forfeitures	0.6	3		19			—			—			—			—			22
Stock-based compensation expense, net of tax	—	—		10			—			—			—			—			10
Balance as of September 30, 2014	119.6	$	599	$	2,080		$	1,222		$	(133	)	$	(8	)	$	42		$	3,802



	AGL Resources Shareholders
	Common stock			Additional paid-in capital			Retained earnings			Accumulated other comprehensive loss			Treasury shares			Noncontrolling interest			Total
In millions, except per share amounts	Shares	Amount		Additional paid-in capital			Retained earnings			Accumulated other comprehensive loss			Treasury shares			Noncontrolling interest			Total
Balance as of December 31, 2014	119.6	$	599	$	2,087		$	1,312		$	(206	)	$	(8	)	$	44		$	3,828
Net income	—	—		—			246			—			—			15			261
Other comprehensive income	—	—		—			—			11			—			—			11
Dividends on common stock ($1.53 per share)	—	—		—			(183		)	—			—			—			(183		)
Distribution to noncontrolling interest	—	—		—			—			—			—			(18		)	(18		)
Stock granted, share-based compensation, net of forfeitures	—	—		(13		)	—			—			—			—			(13		)
Stock issued, dividend reinvestment plan	0.2	1		8			—			—			—			—			9
Stock issued, share-based compensation, net of forfeitures	0.4	2		12			—			—			—			—			14
Stock-based compensation expense, net of tax	—	—		1			—			—			—			—			1
Balance as of September 30, 2015	120.2	$	602	$	2,095		$	1,375		$	(195	)	$	(8	)	$	41		$	3,910

See Notes to Condensed Consolidated Financial Statements (Unaudited).

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AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)



	Nine Months Ended September 30,
In millions	2015			2014
Cash flows from operating activities
Net income	$	261		$	348
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization	293			281
Change in derivative instrument assets and liabilities	85			(27		)
Deferred income taxes	39			47
Goodwill impairment	14			—
Loss from discontinued operations, net of tax	—			80
Gain on disposition of assets	—			(3		)
Changes in certain assets and liabilities
Receivables, other than energy marketing	457			335
Prepaid and miscellaneous taxes	123			(113		)
Inventories	57			(138		)
Energy marketing receivables and trade payables, net	29			183
Accrued/deferred natural gas costs	10			(66		)
Accrued expenses	(33		)	(1		)
Trade payables, other than energy marketing	(39		)	(81		)
Other, net	114			39
Net cash flow provided by operating activities of discontinued operations	—			(10		)
Net cash flow provided by operating activities	1,410			874
Cash flows from investing activities
Expenditures for property, plant and equipment	(745		)	(543		)
Disposition of assets	—			225
Other, net	4			47
Net cash flow used in investing activities of discontinued operations	—			(13		)
Net cash flow used in investing activities	(741		)	(284		)
Cash flows from financing activities
Net repayments of commercial paper	(289		)	(490		)
Payment of senior notes	(200		)	—
Dividends paid on common shares	(183		)	(175		)
Distribution to noncontrolling interest	(18		)	(17		)
Other, net	9			19
Net cash flow used in financing activities	(681		)	(663		)
Net decrease in cash and cash equivalents - continuing operations	(12		)	(50		)
Net decrease in cash and cash equivalents - discontinued operations	—			(23		)
Cash and cash equivalents at beginning of period	31			105
Cash and cash equivalents at end of period	$	19		$	32
Cash paid (received) during the period for
Interest	$	145		$	150
Income taxes	(26		)	317

See Notes to Condensed Consolidated Financial Statements (Unaudited).

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AGL RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 - Organization and Basis of Presentation

General

AGL Resources Inc. is an energy services holding company that conducts substantially all of its operations through its subsidiaries. Unless the context requires otherwise, references to “we,” “us,” “our,” the “company,” or “AGL Resources” mean consolidated AGL Resources Inc. and its subsidiaries.

Our Condensed Consolidated Statement of Financial Position as of December 31, 2014 was derived from our audited consolidated financial statements. 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 included in our annual audited financial statements. 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 statement of our financial results for the interim periods and should be read in conjunction with our consolidated financial statements and related notes included in Item 8 of our 2014 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 or financial condition to be expected for, or as of, any other period.

Basis of Presentation

Our unaudited condensed consolidated financial statements include our accounts, the accounts of our wholly owned subsidiaries and the accounts of our VIE for which we are the primary beneficiary. For unconsolidated entities that we do not control, we use the equity method of accounting and our proportionate share of income or loss is recorded on our unaudited Condensed Consolidated Statements of Income. See Note 10 for additional information on our non-wholly owned entities. We have eliminated intercompany profits and transactions in consolidation except for intercompany profits where recovery of such amounts is probable under the affiliates’ rate regulation process.

In September 2014, we closed on the sale of Tropical Shipping, which operated within our former cargo shipping segment. The financial results of these businesses for the three and nine months ended September 30, 2014 are reflected as discontinued operations on the unaudited Condensed Consolidated Statements of Income. Amounts shown in the following notes, unless otherwise indicated, exclude discontinued operations. Our former cargo shipping segment also included our investment in Triton, which was not part of the sale and has been reclassified into our “other” non-reportable segments. See Note 13 for additional information on the sale of Tropical Shipping.

Note 2 - Proposed Merger with Southern Company

On August 23, 2015, we entered into the Merger Agreement with Southern Company and a new wholly owned subsidiary of Southern Company (Merger Sub), providing for the merger of Merger Sub with and into the Company, with the Company surviving as a wholly owned subsidiary of Southern. At the effective time of the merger, which is expected to occur in the second half of 2016, each share of our common stock, other than certain excluded shares, will convert into the right to receive $66 in cash, without interest, less any applicable withholding taxes. Following the effective time of the merger, we will become a wholly owned, direct subsidiary of Southern Company.

Completion of the merger is subject to various closing conditions, including, among others (i) the approval of the Merger Agreement by the affirmative vote of the holders of a majority of all outstanding shares of our common stock, (ii) the receipt of required regulatory approvals, including expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act, as amended (the Hart-Scott-Rodino Act), and approvals from the Federal Communications Commission, California Public Utilities Commission, Georgia Commission, Illinois Commission, Maryland Commission, New Jersey BPU and Virginia Commission, and such approvals having become final orders and (iii) the absence of a judgment, order, decision, injunction, ruling or other finding or agency requirement of a governmental entity prohibiting the closing of the merger.

The Merger Agreement contains certain termination rights for each party. In addition, the Merger Agreement, in certain circumstances, provides for the payment by AGL Resources of a $201 million termination fee to Southern Company and, in certain circumstances, provides for the reimbursement of expenses up to $5 million upon termination of the Merger Agreement (which reimbursement would reduce on a dollar-for-dollar basis any termination fee subsequently paid by us).

In connection with this transaction, we recorded merger-related costs in the accompanying unaudited Condensed Consolidated Statements of Income of $35 million ($21 million, net of tax) for both the three and nine months ended September 30, 2015. The transaction costs incurred to date are comprised of $19 million of additional stock-based compensation expense associated with the proposed merger as we remeasured our performance share unit awards based upon the increase in trading price of our common stock since the announcement of the Merger Agreement, $13 million of expenses associated with financial advisory, legal and other merger-related costs and $3 million of board of directors stock-based compensation related to the aforementioned increase in the trading price of our common stock. We treated these costs as tax deductible since the requisite

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closing conditions to the merger have not yet been satisfied. Once the merger is closed, we will evaluate the tax deductibility of these costs and reflect any non-deductible amounts in the effective tax rate.

Additionally, since the announcement of the merger, AGL Resources and each member of the board of directors have been named as defendants in four purported shareholder class action lawsuits relating to the merger. See Note 11 for additional information. AGL Resources and its directors believe that the claims are without merit and intend to vigorously defend against all of the claims.

Subsequent Events

On October 13, 2015, we filed a definitive proxy statement with the SEC to notify our shareholders of a special meeting to be held on November 19, 2015 to vote on the proposed merger. We and Southern Company have made joint filings seeking regulatory approval of the proposed merger with the Illinois Commission, the New Jersey BPU, the Virginia Commission and the Maryland Commission on October 8, 16, 26 and November 3, respectively. Both parties previously filed notification and report forms under the Hart-Scott-Rodino Act. Effective November 2, 2015, Southern Company withdrew its notification and report forms and refiled them on November 4, 2015. The applicable waiting period for both parties now expires on December 4, 2015.

Note 3 - Significant Accounting Policies and Methods of Application

Our significant accounting policies are described in Note 2 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K. While we adopted the revised guidance related to debt issuance costs during the second quarter of 2015, there have been no significant changes to our accounting policies during the year.

Use of Accounting Estimates

The preparation of our financial statements in conformity with GAAP requires us to use judgment and make estimates 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 accounting literature or in the development of estimates that impact our financial statements. The most significant estimates relate to the accounting for our rate-regulated subsidiaries, goodwill and other intangible assets, derivatives and hedging activities, uncollectible accounts and other allowances for contingent losses, retirement plan benefit obligations and provisions for income taxes. We evaluate our estimates on an ongoing basis, and our actual results could differ from our estimates.

Inventories

For our regulated utilities, except Nicor Gas, natural gas inventories and the inventories we hold for Marketers in Georgia are carried at cost on a WACOG basis. Nicor Gas’ inventory is carried at cost on a LIFO basis. Our retail operations, wholesale services and midstream operations segments carry inventory at LOCOM, where cost is determined on a WACOG basis. For the periods presented, we recorded LOCOM adjustments to cost of goods sold in the following amounts to reduce the value of our inventories to market value.



	Three Months Ended September 30,				Nine Months Ended September 30,
In millions	2015		2014		2015		2014
LOCOM adjustments	$	2	$	5	$	12	$	11

We have $12 million of inventory at wholesale services that is currently inaccessible due to operational issues at a third party storage facility. The owner of this storage facility is working to resolve these issues. While we expect this inventory to be accessible during the fourth quarter of 2015 and to be fully recovered, the timing of withdrawal of this gas may be impacted by the operational issues.

Goodwill

We perform an annual impairment test on our reporting units that contain goodwill during the fourth fiscal quarter of each year or more frequently if impairment indicators arise. Our 2014 annual impairment test indicated that the estimated fair value of the storage and fuels reporting unit, with $14 million of goodwill, within our midstream operations segment exceeded its carrying value by less than 5% and would be at risk of failing step one of the goodwill impairment test if a further decline in the estimated fair value were to occur. While preparing our third quarter 2015 financial statements, and in connection with our 2016 annual budget process, we assessed various market factors and projections prepared by both internal and external sources related to subscription rates for contracting capacity at our storage facilities as well as the profitability of our storage and fuels reporting unit. Based on this assessment, we concluded that a decline in projected storage subscription rates as well as a reduction in the near-term projection of the reporting unit's profitability required us to perform an interim goodwill impairment test as of September 30, 2015.

Step one of the goodwill impairment test compared the fair value of the reporting unit to its carrying value utilizing the income approach, under which the fair value was estimated based on the present value of estimated future cash flows discounted at an

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appropriate interest rate. The result of our step one test revealed that the estimated fair value of our storage and fuels reporting unit was below its carrying value.

Step two of the goodwill impairment test compared the implied fair value of goodwill in our storage and fuels reporting unit, which was calculated as the residual amount from the reporting unit's overall fair value after assigning fair values to its assets and liabilities under a hypothetical purchase price allocation as if the reporting unit had been acquired in a business combination, to its carrying value. Based on the result of our step two test we recorded a non-cash impairment charge of the full $14 million ($9 million, net of tax) of goodwill. The amounts of goodwill as of September 30, 2015 and 2014, and December 31, 2014 are provided below.



In millions	Distribution operations		Retail operations		Midstream operations			Consolidated
Goodwill - September 30, 2014	$	1,640	$	173	$	14		$	1,827
Goodwill - December 31, 2014	1,640		173		14			1,827
Impairment	—		—		(14		)	(14		)
Goodwill - September 30, 2015	$	1,640	$	173	$	—		$	1,813

Earnings Per Common Share

The following table shows the calculation of our diluted shares attributable to AGL Resources for the periods presented as if performance units currently earned under the plan ultimately vest and as if stock options currently exercisable at prices below the average market prices are exercised.



	Three Months Ended September 30,					Nine Months Ended September 30,
In millions, except per share amounts	2015		2014			2015		2014
Income from continuing operations attributable to AGL Resources	$	11	$	23		$	246	$	414
Loss from discontinued operations, net of tax	—		(31		)	—		(80		)
Net income (loss) attributable to AGL Resources	$	11	$	(8	)	$	246	$	334
Denominator:
Basic weighted average number of shares outstanding ⁽¹⁾	119.6		119.0			119.5		118.8
Effect of dilutive securities	0.4		0.4			0.3		0.4
Diluted weighted average number of shares outstanding ⁽²⁾	120.0		119.4			119.8		119.2
Basic earnings (loss) per common share
Continuing operations	$	0.09	$	0.19		$	2.06	$	3.48
Discontinued operations	—		(0.25		)	—		(0.67		)
Basic earnings (loss) per common share attributable to AGL Resources	$	0.09	$	(0.06	)	$	2.06	$	2.81
Diluted earnings (loss) per common share
Continuing operations	$	0.09	$	0.19		$	2.05	$	3.47
Discontinued operations	—		(0.25		)	—		(0.67		)
Diluted earnings (loss) per common share attributable to AGL Resources	$	0.09	$	(0.06	)	$	2.05	$	2.80


(1)	Daily weighted average shares outstanding.


(2)	All outstanding stock options whose effect would have been anti-dilutive were excluded from the computation of diluted earnings per common share.

Accounting Developments

Accounting standards adopted in 2015

In April 2015, the FASB issued updated authoritative guidance related to debt issuance costs. The amendment modifies the presentation of unamortized debt issuance costs on our unaudited Condensed Consolidated Statements of Financial Position. Under the new guidance, we present such amounts as a direct deduction from the face amount of the debt, similar to unamortized debt discounts and premiums, rather than as an asset. Amortization of the debt issuance costs continues to be reported as interest expense on the unaudited Condensed Consolidated Statements of Income. While the guidance would have been effective for us beginning January 1, 2016, we elected to adopt its provisions effective April 1, 2015, and have applied its provisions to each prior period presented for comparative purposes. This new guidance resulted in an adjustment to the presentation of debt issuance costs primarily from other long-term assets to offset the related debt balances in long-term debt totaling $18 million, $21 million and $21 million as of September 30, 2015, December 31, 2014 and September 30, 2014, respectively. The April 2015 guidance did not address the classification of debt issuance costs related to line-of-credit arrangements and, consequently, we continued to report such costs as assets subject to amortization over the term of the arrangement. In August 2015, the FASB issued clarifying guidance supporting the deferral and presentation of line-of-credit

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related debt issuance costs as an asset and subsequently amortizing these costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the arrangement.

Other newly issued accounting standards and updated authoritative guidance

In May 2014, the FASB issued an update to authoritative guidance related to revenue from contracts with customers. The update replaces most of the existing guidance with a single set of principles for recognizing revenue from contracts with customers. In July 2015, the FASB delayed the effective date by one year and the guidance will now be effective for us beginning January 1, 2018. Early adoption of the standard is permitted, but not before the original effective date of December 15, 2016. The new guidance must be applied retrospectively to each prior period presented or via a cumulative effect upon the date of initial application. We have not yet determined the impact of this new guidance, nor have we selected a transition method.

In February 2015, the FASB issued updated authoritative guidance related to the consolidation of other legal entities into our financial statements. The amendments modify aspects of the consolidation determination that could potentially impact us, including the analysis of limited partnerships and similar legal entities, fee arrangements, and related party relationships. The guidance is effective for us beginning January 1, 2016, and early adoption is permitted. We have determined that this new guidance will not have a material impact on our unaudited condensed consolidated financial statements.

In April 2015, the FASB issued authoritative guidance related to the accounting for fees paid in connection with arrangements with cloud-based software providers. Under the new guidance, unless a software arrangement includes specific elements enabling customers to possess and operate software on platforms other than that offered by the cloud-based provider, the cost of such arrangements is to be accounted for as an operating expense of the period incurred. The new guidance may be applied either prospectively or retrospectively, is effective for us beginning January 1, 2016, and early adoption is permitted. We are currently evaluating our software arrangements.

In May 2015, the FASB issued updated authoritative guidance to reduce the diversity in fair value measurements hierarchy disclosures. This amendment removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share. This guidance is effective for us beginning January 1, 2016, and early adoption is permitted. We have determined that this new guidance will not have a material impact on our unaudited condensed consolidated financial statements.

In July 2015, the FASB issued an update to authoritative guidance to simplify the measurement of certain inventories. Under the new guidance, inventories are required to be measured at the lower of cost and net realizable value, the latter representing the estimated selling price in the ordinary course of business, reduced by costs of completion, disposal, and transportation. Under current guidance, inventories are required to be measured at the lower of cost or market, but depending upon specific circumstances, market could refer to replacement cost, net realizable value, or net realizable value reduced by a normal profit margin. The amendments do not apply to inventories carried on a LIFO basis, which for us applies only to our Nicor Gas inventories. The guidance is to be applied prospectively, is effective for us beginning January 1, 2017, and early adoption is permitted. We are currently evaluating the potential impact of this new guidance.

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Note 4 - Regulated Operations

The accounting policies for our regulated operations are described in Note 2 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K. Our regulatory assets and liabilities reflected within our unaudited Condensed Consolidated Statements of Financial Position as of the dates presented are summarized in the following table.



In millions	September 30, 2015		December 31, 2014		September 30, 2014
Regulatory assets
Recoverable ERC	$	28	$	49	$	41
Recoverable pension and retiree welfare benefit costs	11		12		9
Deferred natural gas costs	4		3		4
Other	21		19		51
Regulatory assets – current	64		83		105
Recoverable ERC	348		329		367
Recoverable pension and retiree welfare benefit costs	103		110		91
Recoverable regulatory infrastructure program costs	80		69		72
Long-term debt fair value adjustment	68		74		76
Other	38		49		31
Regulatory assets – long-term	637		631		637
Total regulatory assets	$	701	$	714	$	742
Regulatory liabilities
Accumulated removal costs	$	48	$	25	$	27
Accrued natural gas costs	38		27		29
Bad debt over collection	28		33		31
Other	25		27		31
Regulatory liabilities – current	139		112		118
Accumulated removal costs	1,532		1,520		1,499
Regulatory income tax liability	26		34		26
Unamortized investment tax credit	20		22		23
Bad debt over collection	18		12		7
Other	12		13		12
Regulatory liabilities – long-term	1,608		1,601		1,567
Total regulatory liabilities	$	1,747	$	1,713	$	1,685

Base rates are designed to provide the opportunity to recover cost and earn a return on investment during the period rates are in effect. As such, all of our regulatory assets recoverable through base rates are subject to review by the respective state regulatory commission during future rate proceedings. We are not aware of evidence that these costs will not be recoverable through either rate riders or base rates, and we believe that we will be able to recover such costs consistent with our historical recoveries.

Unrecognized Ratemaking Amounts The following table illustrates our authorized ratemaking amounts that are not recognized on our unaudited Condensed Consolidated Statements of Financial Position. These amounts are primarily composed of an allowed equity rate of return on assets associated with certain of our regulatory infrastructure programs. These amounts will be recognized as revenues in our financial statements in the periods they are billable to our customers.



In millions	Atlanta Gas Light			Virginia Natural Gas		Elizabethtown Gas		Nicor Gas		Total
September 30, 2015	$	99	⁽¹⁾	$	12	$	3	$	2	$	116
December 31, 2014	113			12		2		—		127
September 30, 2014	104			12		2		—		118

(1) In October 2015, Atlanta Gas Light received an order from the Georgia Commission, which included a final determination of the true-up recovery related to the PRP. The order allows Atlanta Gas Light to recover $144 million of the $178 million of incurred and allowed costs that were deferred for future recovery. These deferred costs were originally requested in a February 2015 filing for a true-up of unrecovered revenue. See Note 11 for additional information on Atlanta Gas Light's global resolution of this and other matters that were previously raised before the Georgia Commission.

Natural Gas Costs We charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms established by the state regulatory agencies. Under these mechanisms, all prudently incurred natural gas costs are passed through to customers without markup, subject to regulatory review. We defer or accrue the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period, such that no operating margin is recognized related to these costs. The deferred or accrued amount is either billed or refunded to our customers prospectively through adjustments to the commodity rate.

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Environmental Remediation Costs We are subject to federal, state and local laws and regulations governing environmental quality and pollution control that 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, substantially all of which is related to former MGP sites. The ERC assets and liabilities are associated with our distribution operations segment and remediation costs are generally recoverable from customers through rate mechanisms approved by regulators. Accordingly, both costs incurred to remediate the former MGP sites, plus the future estimated cost recorded as liabilities, net of amounts previously collected, are recognized as a regulatory asset until recovered from customers.

Our accrued environmental remediation liabilities are estimates of future remediation costs for investigation and cleanup of our current and former operating sites that are contaminated. These estimates are determined using engineering-based estimates and probabilistic models of potential costs when such estimates cannot be made, on an undiscounted basis. These estimates contain various assumptions, which we refine and update on an ongoing basis. These liabilities do not include other potential expenses, such as unasserted property damage claims, personal injury or natural resource damage claims, legal expenses or other costs for which we may be held liable but for which we cannot reasonably estimate an amount.

Our accrued environmental remediation liabilities are not regulatory liabilities; however, the associated expenses are deferred as corresponding regulatory assets until the costs are recovered from customers. We primarily recover these deferred costs through three rate riders that authorize dollar-for-dollar recovery. We expect to collect $28 million in revenues over the next 12 months, which is reflected as a current regulatory asset. The following table provides additional information on the estimated costs to remediate our current and former operating sites as of September 30, 2015.



In millions	# of sites	Probabilistic model cost estimates	Engineering-based estimates		Amount recorded		Expected costs over next 12 months		Cost recovery period
Illinois ⁽¹⁾	26	$205 - $463	$	34	$	239	$	34	As incurred
New Jersey	6	105 - 177	9		114		13		7 years
Georgia and Florida	13	34 - 58	22		56		18		5 years
North Carolina ⁽²⁾	1	—	10		10		8		No recovery
Total	46	$344 - $698	$	75	$	419	$	73


(1)	Nicor Gas is responsible in whole or in part for 26 MGP sites, two of which have been remediated and their use is no longer restricted by the environmental condition of the property. Nicor Gas and Commonwealth Edison Company are parties to an agreement to cooperate in cleaning up residue at 23 of the sites. Nicor Gas’ allocated share of cleanup costs for these sites is 52%.


(2)	We have no regulatory recovery mechanism for the site in North Carolina and there is no amount included within our regulatory assets. Changes in estimated costs are recognized in income during the period of change.

In July 2014, we reached a settlement with an insurance company for environmental claims relating to potential contamination at several MGP sites in New Jersey and North Carolina. The terms of the settlement required the insurance company to pay us a total of $77 million in two installments. We received a $45 million installment in the third quarter of 2014 and the remaining $32 million was paid in the second quarter of 2015. The New Jersey BPU has approved the use of the insurance proceeds that were received in the third quarter of 2014 to reduce the ERC expenditures that otherwise would have been recovered from our customers in future periods. This will reduce our recoverable ERC regulatory assets and have a favorable impact on the rates for our Elizabethtown Gas customers. We have filed with the New Jersey BPU for approval to use the $32 million received in 2015 to reduce future ERC expenditures. If approved, this will further reduce our recoverable ERC regulatory assets and the rates charged to our Elizabethtown Gas customers.

Note 5 - Fair Value Measurements

The methods used to determine the fair values of our assets and liabilities are described within "Fair Value Measurements" in Note 2 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K.

Derivative Instruments

The following table summarizes, by level within the fair value hierarchy, our derivative assets and liabilities that were carried at fair value, net of counterparty offset and collateral, on a recurring basis on our unaudited Condensed Consolidated Statements of Financial Position as of the dates presented. See Note 6 for additional information on our derivative instruments.



	September 30, 2015					December 31, 2014					September 30, 2014
In millions	Assets ⁽¹⁾		Liabilities			Assets ⁽¹⁾		Liabilities			Assets⁽¹⁾		Liabilities
Quoted prices in active markets (Level 1)	$	40	$	(57	)	$	58	$	(80	)	$	4	$	(72	)
Significant other observable inputs (Level 2)	92		(60		)	174		(94		)	57		(51		)
Netting of counterparty offset and cash collateral	33		56			52		81			49		76
Total carrying value ⁽²⁾	$	165	$	(61	)	$	284	$	(93	)	$	110	$	(47	)


(1)	Balances of $6 million at September 30, 2015, $3 million at December 31, 2014 and $3 million at September 30, 2014, associated with certain weather derivatives have been excluded, as they are accounted for based on intrinsic value rather than fair value.


(2)	There were no significant unobservable inputs (Level 3) or significant transfers between Level 1, Level 2 or Level 3 for any of the dates presented.

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Debt

Our long-term debt is recorded at amortized cost, with the exception of Nicor Gas’ first mortgage bonds, which are recorded at their acquisition-date fair value. We amortize the fair value adjustment of Nicor Gas’ first mortgage bonds over the lives of the bonds. The following table lists the carrying amount and fair value of our long-term debt as of the dates presented.



In millions	September 30, 2015		December 31, 2014		September 30, 2014
Long-term debt carrying amount	$	3,575	$	3,781	$	3,784
Long-term debt fair value ⁽¹⁾	3,883		4,231		4,165


(1)	Fair value determined using Level 2 inputs.

Note 6 - Derivative Instruments

Our objectives and strategies for using derivative instruments, and the related accounting policies and methods used to determine their fair values are described within "Fair Value Measurements" in Note 2 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K. See Note 5 herein for additional information on fair value and our derivative instruments.

Certain of our derivative instruments contain credit-risk-related or other contingent features that could require us to post collateral in the normal course of business when our financial instruments are in net liability positions. As of September 30, 2015, December 31, 2014 and September 30, 2014, for agreements with such features, derivative instruments with liability fair values totaled $61 million, $93 million and $47 million, respectively, for which we had posted no collateral to our counterparties as we exceed the minimum credit rating requirements. As of September 30, 2015, the maximum collateral that could have been required with these features was $5 million. For additional information on our credit-risk-related contingent features, see “Energy Marketing Receivables and Payables” in Note 2 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K. Our derivative instrument activities are included within operating cash flows as an increase (decrease) to net income of $85 million and $(27) million for the nine months ended September 30, 2015 and 2014, respectively.

Quantitative Disclosures Related to Derivative Instruments

Our derivative instruments are comprised of both long and short natural gas positions. A long position is a contract to purchase natural gas, and a short position is a contract to sell natural gas. As of the dates presented, we had net (short) and long natural gas contracts positions outstanding in the following quantities:



In Bcf⁽¹⁾	September 30, 2015⁽²⁾		December 31, 2014		September 30, 2014
Cash flow hedges	6		9		7
Not designated as hedges	(9	)	75		97
Total volumes	(3	)	84		104
Short position – cash flow hedges	(9	)	(7	)	(7	)
Short position – not designated as hedges	(3,109	)	(2,825	)	(2,749	)
Long position – cash flow hedges	15		16		14
Long position – not designated as hedges	3,100		2,900		2,846
Net (short) long position	(3	)	84		104


(1)	Volumes related to Nicor Gas exclude variable-priced contracts, which are carried at fair value, but whose fair values are not directly impacted by changes in commodity prices.


(2)	Approximately 96% of these contracts have durations of two years or less and approximately 4% expire between two and five years.

Derivative Instruments on our Unaudited Condensed Consolidated Statements of Financial Position

In accordance with regulatory requirements, gains and losses on derivative instruments used in hedging activities of natural gas purchases for customer use at distribution operations are reflected in accrued natural gas costs within our unaudited Condensed Consolidated Statements of Financial Position until billed to customers. The following amounts deferred as a regulatory asset or liability on our unaudited Condensed Consolidated Statements of Financial Position represent the net realized gains (losses) related to these natural gas cost hedging activities as of the periods presented.



	Three Months Ended September 30,						Nine Months Ended September 30,
In millions	2015			2014			2015			2014
Nicor Gas	$	(15	)	$	(4	)	$	(36	)	$	8
Elizabethtown Gas	(4		)	(1		)	(12		)	4

The following table presents the fair values and unaudited Condensed Consolidated Statements of Financial Position classifications of our derivative instruments as of the dates presented.

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		September 30, 2015						December 31, 2014						September 30, 2014
In millions	Classification	Assets			Liabilities			Assets			Liabilities			Assets			Liabilities
Designated as cash flow or fair value hedges
Natural gas contracts	Current	$	4		$	(7	)	$	6		$	(11	)	$	2		$	(2	)
Natural gas contracts	Long-term	—			(1		)	—			(1		)	—			—
Interest rate swap agreements	Current	—			(5		)	—			—			—			—
Interest rate swap agreements	Long-term	6			—			—			—			—			—
Total designated as cash flow or fair value hedges		$	10		$	(13	)	$	6		$	(12	)	$	2		$	(2	)
Not designated as hedges
Natural gas contracts	Current	$	689		$	(663	)	$	1,061		$	(1,020	)	$	834		$	(891	)
Natural gas contracts	Long-term	103			(105		)	145			(119		)	78			(80		)
Total not designated as hedges		$	792		$	(768	)	$	1,206		$	(1,139	)	$	912		$	(971	)
Gross amounts of recognized assets and liabilities ^{(1) (2)}		802			(781		)	1,212			(1,151		)	914			(973		)
Gross amounts offset on our unaudited Condensed Consolidated Statements of Financial Position⁽²⁾		(631		)	720			(925		)	1,058			(801		)	926
Net amounts of assets and liabilities presented on our unaudited Condensed Consolidated Statements of Financial Position⁽³⁾		$	171		$	(61	)	$	287		$	(93	)	$	113		$	(47	)


(1)	The gross amounts of recognized assets and liabilities are netted within our unaudited Condensed Consolidated Statements of Financial Position to the extent that we have netting arrangements with the counterparties.

(2)

As required by the authoritative guidance related to derivatives and hedging, the gross amounts of recognized assets and liabilities do not include cash collateral held on deposit in broker margin accounts of $89 million as of September 30, 2015, $133 million as of December 31, 2014, and $125 million as of September 30, 2014. Cash collateral is included in the “Gross amounts offset on our unaudited Condensed Consolidated Statements of Financial Position” line of this table.


(3)	As of September 30, 2015, December 31, 2014, and September 30, 2014, we held letters of credit from counterparties that under master netting arrangements would offset an insignificant portion of these assets.

Derivative Instruments on the Unaudited Condensed Consolidated Statements of Income

The following table presents the impacts of our derivative instruments on our unaudited Condensed Consolidated Statements of Income for the periods presented.



	Three Months Ended September 30,						Nine Months Ended September 30,
In millions	2015			2014			2015			2014
Designated as cash flow or fair value hedges
Natural gas contracts - net (loss) gain reclassified from OCI into cost of goods sold	$	(2	)	$	(1	)	$	(6	)	$	4
Natural gas contracts - net gain (loss) reclassified from OCI into operation and maintenance expense	—			1			(1		)	2
Interest rate swaps - net gain reclassified from OCI into interest expense	1			—			2			—
Income tax	—			—			—			(1		)
Total designated as cash flow or fair value hedges, net of tax	(1		)	—			(5		)	5
Not designated as hedges⁽¹⁾
Natural gas contracts - net fair value adjustments recorded in operating revenues	28			(6		)	7			(6		)
Natural gas contracts - net fair value adjustments recorded in cost of goods sold ⁽²⁾	(3		)	(1		)	(4		)	—
Income tax	(10		)	2			(1		)	2
Total not designated as hedges, net of tax	15			(5		)	2			(4		)
Total gains (losses) on derivative instruments, net of tax	$	14		$	(5	)	$	(3	)	$	1


(1)	Associated with the fair values of derivative instruments held at September 30, 2015 and 2014.


(2)	Excludes losses recorded in cost of goods sold associated with weather derivatives of $(1) million and $(6) million for the nine months ended September 30, 2015 and 2014, respectively. There were no amounts recorded for the three months ended September 30, 2015 and 2014.

Any amounts recognized in operating income related to ineffectiveness or due to a forecasted transaction that is no longer expected to occur were immaterial for the three and nine months ended September 30, 2015 and 2014. Our expected gains to be reclassified from OCI into cost of goods sold, operation and maintenance expense, interest expense and operating revenues and recognized on our unaudited Condensed Consolidated Statements of Income over the next 12 months are $5 million. These deferred gains are related to natural gas derivative contracts associated with retail operations’ and Nicor Gas’ system use. The expected gains are based upon the fair values of these financial instruments at September 30, 2015. The effective portions of gains and losses on derivative instruments qualifying as cash flow hedges that were recognized in OCI during the periods are presented on our unaudited Condensed Consolidated Statements of Income. See Note 9 for these amounts.

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There have been no other significant changes to our derivative instruments, as described in Note 2, Note 4, Note 5 and Note 8 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K.

Note 7 - Employee Benefit Plans

Pension Benefits

We sponsor the AGL Resources Inc. Retirement Plan, a tax-qualified defined benefit retirement plan for our eligible employees, which is described in Note 6 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K. Following are the components of our pension costs for the periods indicated.



	Three Months Ended September 30,						Nine Months Ended September 30,
In millions	2015			2014			2015			2014
Service cost	$	7		$	6		$	21		$	18
Interest cost	11			12			34			35
Expected return on plan assets	(16		)	(16		)	(49		)	(48		)
Net amortization of prior service credit	(1		)	(1		)	(2		)	(2		)
Recognized actuarial loss	8			5			23			16
Net periodic pension benefit cost	$	9		$	6		$	27		$	19

Welfare Benefits

The benefits of our Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. are described in Note 6 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K. Following are the components of our welfare costs for the periods indicated.



	Three Months Ended September 30,						Nine Months Ended September 30,
In millions	2015			2014			2015			2014
Service cost	$	—		$	1		$	1		$	2
Interest cost	4			4			10			11
Expected return on plan assets	(1		)	(2		)	(5		)	(5		)
Net amortization of prior service credit	(1		)	(1		)	(2		)	(2		)
Recognized actuarial loss	1			1			4			4
Net periodic welfare benefit cost	$	3		$	3		$	8		$	10

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Note 8 - Debt and Credit Facilities

The following table provides maturity dates or ranges, year-to-date weighted average interest rates and amounts outstanding for our various debt securities and facilities for the periods presented. We fully and unconditionally guarantee all debt issued by AGL Capital. For additional information on our debt and credit facilities, see Note 8 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K.



		September 30, 2015								September 30, 2014
Dollars in millions	Year(s) due	Weighted average interest rate ⁽¹⁾		Outstanding			December 31, 2014			Weighted average interest rate ⁽¹⁾		Outstanding
Short-term debt
Commercial paper - AGL Capital ⁽²⁾	2015	0.5	%	$	450		$	590		0.3	%	$	292
Commercial paper - Nicor Gas ⁽²⁾	2015	0.4		436			585			0.2		389
Total short-term debt		0.4	%	$	886		$	1,175		0.3	%	$	681
Current portion of long-term debt	2016	5.9	%	$	425		$	200		5.0	%	$	200
Long-term debt - excluding current portion
Senior notes	2016-2043	4.8	%	$	2,325		$	2,625		5.0	%	$	2,625
First mortgage bonds	2019-2038	5.9		375			500			5.6		500
Gas facility revenue bonds	2022-2033	0.9		200			200			0.9		200
Medium-term notes	2017-2027	7.8		181			181			7.8		181
Total principal long-term debt		4.7	%	3,081			3,506			4.9	%	3,506
Unamortized fair value adjustment of long-term debt ⁽³⁾	n/a	n/a		71			80			n/a		83
Unamortized debt premium, net	n/a	n/a		16			16			n/a		16
Unamortized debt issuance costs	n/a	n/a		(18		)	(21		)	n/a		(21		)
Total non-principal long-term debt		n/a		69			75			n/a		78
Total long-term debt - excluding current portion				$	3,150		$	3,581				$	3,584
Total debt				$	4,461		$	4,956				$	4,465


(1)	Interest rates are calculated based on the daily weighted average balance outstanding for the nine months ended September 30.


(2)	As of September 30, 2015, the effective interest rates on our commercial paper borrowings were 0.5% for AGL Capital and 0.4% for Nicor Gas.


(3)	See Note 5 herein for additional information on our fair value measurements.

Commercial Paper Programs

We maintain commercial paper programs at AGL Capital and at Nicor Gas that consist of short-term, unsecured promissory notes used in conjunction with cash from operations to fund our seasonal working capital requirements. Working capital needs fluctuate during the year and are generally highest during the injection period in advance of the Heating Season. Nicor Gas’ commercial paper program supports working capital needs at Nicor Gas, while all of our other subsidiaries and SouthStar participate in AGL Capital’s commercial paper program. During the first nine months of 2015, our commercial paper maturities ranged from 1 to 58 days, and at September 30, 2015, remaining terms to maturity ranged from 1 to 34 days. During the first nine months of 2015, we had no commercial paper issuances with original maturities over three months. Total borrowings and repayments during the first nine months of 2015 netted to a payment of $289 million.

Senior Notes

On January 15, 2015, $200 million of senior notes matured and were repaid using the proceeds from commercial paper borrowings.

Interest Rate Swaps

On January 23, 2015, we executed $800 million in notional value of 10 year and 30 year fixed-rate, forward-starting interest rate swaps to hedge potential interest rate volatility prior to anticipated issuances of senior notes during the fourth quarter of 2015 and in 2016. These debt issuances will be used to reduce our commercial paper for the amount that was borrowed to repay our senior notes that matured in January 2015 and to fund upcoming debt maturities as well as increased capital expenditures associated with utility investments, including infrastructure programs, and construction of our new pipeline projects. We have designated the forward-starting interest rate swaps, which will be settled on the debt issuance dates, as cash flow hedges. We performed a qualitative assessment of effectiveness as of September 30, 2015 and concluded that the hedges remain highly effective.

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Financial and Non-Financial Covenants

The AGL Credit Facility and the Nicor Gas Credit Facility each include 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 month; however, our goal is to maintain these ratios at levels between 50% and 60%, except for temporary increases related to the timing of acquisition and financing activities. The following table contains our debt-to-capitalization ratios for the dates presented, which are below the maximum allowed.



	AGL Resources						Nicor Gas
	September 30, 2015		December 31, 2014		September 30, 2014		September 30, 2015		December 31, 2014		September 30, 2014
Debt covenants ⁽¹⁾	52	%	55	%	53	%	56	%	62	%	57	%


(1)	As defined in our credit facilities, includes standby letters of credit and performance/surety bonds and excludes accumulated OCI items related to non-cash pension adjustments, welfare benefits liability adjustments and accounting for cash flow hedges.

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

Default Provisions

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


•	a maximum leverage ratio;


•	insolvency events and/or nonpayment of scheduled principal or interest payments;


•	acceleration of other financial obligations; and


•	change of control provisions.

We have no triggering events in our debt instruments that are tied to changes in our specified credit ratings or our stock price and have not entered into any transaction that requires us to issue equity based on credit ratings or other triggering events. We were in compliance with all existing debt provisions and covenants, both financial and non-financial, for all periods presented.

Subsequent Event

On October 30, 2015, we entered into agreements to amend and extend the AGL Credit Facility and Nicor Gas Credit Facility. Under the terms of these agreements, we extended the maturity dates of the AGL Credit Facility and Nicor Gas Credit Facility to November 9, 2018 and December 14, 2018, respectively. We also modified the event of default triggered by a change of control upon the closing of the proposed merger with Southern Company and we made similar changes to our Bank Rate Mode Covenants Agreement.

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Note 9 - Equity

Our OCI (loss) amounts are aggregated within our accumulated other comprehensive loss on our unaudited Condensed Consolidated Statements of Financial Position. The following table provides changes in the components of our accumulated other comprehensive loss balances, net of the related income tax effects.



	2015									2014
In millions ⁽¹⁾	Cash flow hedges			Retirement benefit plans			Total			Cash flow hedges			Retirement benefit plans			Total
For the three months ended September 30
As of beginning of period	$	24		$	(193	)	$	(169	)	$	—		$	(133	)	$	(133	)
OCI, before reclassifications	(30		)	—			(30		)	(2		)	—			(2		)
Amounts reclassified from accumulated OCI	2			2			4			—			2			2
Net current-period other comprehensive (loss) income	(28		)	2			(26		)	(2		)	2			—
As of end of period	$	(4	)	$	(191	)	$	(195	)	$	(2	)	$	(131	)	$	(133	)
For the nine months ended September 30
As of beginning of period	$	(6	)	$	(200	)	$	(206	)	$	1		$	(137	)	$	(136	)
OCI, before reclassifications	(3		)	—			(3		)	2			—			2
Amounts reclassified from accumulated OCI	5			9			14			(5		)	6			1
Net current-period other comprehensive income (loss)	2			9			11			(3		)	6			3
As of end of period	$	(4	)	$	(191	)	$	(195	)	$	(2	)	$	(131	)	$	(133	)


(1)	All amounts are net of income taxes and noncontrolling interest. Amounts in parentheses indicate debits to accumulated other comprehensive loss.

The following table provides details of the reclassifications out of accumulated other comprehensive loss and the favorable (unfavorable) impact on net income for the periods presented.



	Three Months Ended September 30,						Nine Months Ended September 30,
In millions⁽¹⁾	2015			2014			2015			2014
Cash flow hedges
Cost of goods sold (natural gas contracts)	$	(2	)	$	(1	)	$	(6	)	$	4
Operation and maintenance expense (natural gas contracts)	—			1			(1		)	2
Interest expense (interest rate contracts)	1			—			2			—
Total before income tax	(1		)	—			(5		)	6
Income tax	—			—			—			(1		)
Cash flow hedges, net of income tax	(1		)	—			(5		)	5
Less noncontrolling interest	1			—			—			—
Total cash flow hedges, net of income tax	(2		)	—			(5		)	5
Retirement benefit plans
Operation and maintenance expense (actuarial losses) ⁽²⁾	(6		)	(4		)	(17		)	(12		)
Operation and maintenance expense (prior service credits) ⁽²⁾	2			—			2			1
Total before income tax	(4		)	(4		)	(15		)	(11		)
Income tax	2			2			6			5
Total retirement benefit plans, net of income tax	(2		)	(2		)	(9		)	(6		)
Total reclassification for the period	$	(4	)	$	(2	)	$	(14	)	$	(1	)


(1)	Amounts in parentheses indicate debits, or reductions, to our net income and credits to accumulated other comprehensive loss. Except for retirement benefit plan amounts, the net income impacts are immediate.


(2)	Amortization of these accumulated other comprehensive loss components is included in the computation of net periodic benefit cost. See Note 7 herein for additional details about net periodic benefit cost.

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Note 10 - Non-Wholly Owned Entities

SouthStar, a joint venture owned by us and Piedmont, is our only VIE for which we are the primary beneficiary. For additional information on SouthStar, see Note 10 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K. Earnings from SouthStar in 2015 and 2014 were allocated entirely in accordance with the ownership interests.

Cash flows used in our investing activities include capital expenditures for SouthStar of $3 million and $6 million for the nine months ended September 30, 2015 and 2014, respectively. Cash flows used in our financing activities include SouthStar’s distribution to Piedmont for its portion of SouthStar’s annual earnings from the previous year, which generally occurs in the first quarter of each fiscal year. For the nine months ended September 30, 2015 and 2014, SouthStar distributed $18 million and $17 million, respectively, to Piedmont. SouthStar’s counterparties have no recourse to our general credit beyond our corporate guarantees that we have provided to SouthStar’s counterparties and natural gas suppliers. The following table provides additional information on SouthStar’s assets and liabilities as of the dates presented. The SouthStar amounts exclude intercompany eliminations and the balances of our wholly-owned subsidiary with an 85% ownership interest in SouthStar.



	September 30, 2015						December 31, 2014						September 30, 2014
In millions	Consolidated		SouthStar		%		Consolidated		SouthStar		%		Consolidated		SouthStar		%
Current assets	$	1,776	$	202	11	%	$	2,886	$	236	8	%	$	2,089	$	188	9	%
Goodwill and other intangible assets	1,926		116		6		1,952		125		6		1,957		127		6
Long-term assets and other deferred debits	10,504		16		—		10,050		17		—		9,886		17		—
Total assets	$	14,206	$	334	2	%	$	14,888	$	378	3	%	$	13,932	$	332	2	%
Current liabilities	$	2,802	$	45	2	%	$	3,219	$	71	2	%	$	2,462	$	47	2	%
Long-term liabilities and other deferred credits	7,494		1		—		7,841		—		—		7,668		—		—
Total Liabilities	10,296		46		—		11,060		71		1		10,130		47		—
Equity	3,910		288		7		3,828		307		8		3,802		285		7
Total liabilities and equity	$	14,206	$	334	2	%	$	14,888	$	378	3	%	$	13,932	$	332	2	%

The following table provides information on SouthStar’s operating revenues and operating expenses for the periods presented, which are consolidated within our unaudited Condensed Consolidated Statements of Income.



	Three Months Ended September 30,				Nine Months Ended September 30,
In millions	2015		2014		2015		2014
Operating revenues	$	103	$	113	$	536	$	633
Operating expenses
Cost of goods sold	78		89		370		470
Operation and maintenance	18		19		59		62
Depreciation and amortization	2		3		7		8
Taxes other than income taxes	—		—		1		1
Total operating expenses	98		111		437		541
Operating income	$	5	$	2	$	99	$	92

Equity Method Investments

For more information about our equity method investments, see Note 10 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K. In the third quarter of 2014, we entered into partnerships to form two new interstate pipeline companies within our midstream operations segment, as described below. The capacity from these pipelines will further enhance system reliability as well as provide access to a more diverse supply of natural gas. We have concluded that, at present, both companies are VIEs. We are not considered the primary beneficiary and, therefore, we have not consolidated the financial statements for these companies on our unaudited condensed consolidated financial statements because we share in the ability to direct the activities that most significantly impact their economic performance with their other member companies. We have accounted for our investments in these companies using the equity method of accounting, and have classified the investments within other noncurrent assets on our unaudited Condensed Consolidated Statements of Financial Position.

PennEast Pipeline In August 2014, we entered into a partnership in which we hold a 20% ownership interest in an interstate pipeline company formed to develop and operate a 118-mile natural gas pipeline between New Jersey and Pennsylvania. The initial transportation capacity of 1.0 Bcf per day, which may be expanded to 1.2 Bcf per day, is under long-term contracts, mainly by public utilities and other market-serving entities, such as electric generation companies, in New Jersey, Pennsylvania

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and New York. Subject to FERC approval, the application for which was filed in September 2015, construction is scheduled to begin in the first quarter of 2017.

Atlantic Coast Pipeline In September 2014, we entered into a project in which we hold a 5% ownership interest to develop and operate a 564-mile natural gas pipeline in North Carolina, Virginia and West Virginia with initial transportation capacity of 1.5 Bcf per day, which may be expanded to 2.0 Bcf per day. Subject to FERC approval, the application for which was filed in September 2015, construction is scheduled to begin in the second half of 2016.

The carrying amounts within our unaudited Condensed Consolidated Statements of Financial Position of our investments that are accounted for under the equity method were as follows:



	September 30,		December 31,		September 30,
In millions	2015		2014		2014
Triton	$	51	$	62	$	64
Horizon Pipeline	14		14		14
PennEast Pipeline	6		1		—
Atlantic Coast Pipeline	5		2		—
Other	1		1		2
Total	$	77	$	80	$	80

Income from our equity method investments is classified as other income on our unaudited Condensed Consolidated Statements of Income. The following table provides the income from our equity method investments for the periods presented.



	Three Months Ended September 30,				Nine Months Ended September 30,
In millions	2015		2014		2015		2014
Triton	$	2	$	2	$	3	$	5
Horizon Pipeline	—		—		1		1

Note 11 - Commitments, Guarantees and Contingencies

We incur 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 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 commercial arrangements that are directly supported by related revenue-producing activities. In April 2015, Nicor Gas entered into a series of 10-year agreements with natural gas purchase obligations of $978 million. Under these agreements, which were entered into in the normal course of business, payments will be made through 2026 as follows:



Year	Amount (in millions)
2016	$	59
2017	93
2018	98
2019	100
2020 - 2026	628
Total	$	978

We are also involved in legal or administrative proceedings before various courts and agencies with respect to general claims, environmental remediation and other matters. Although we are unable to determine the ultimate outcomes of these contingencies, we believe that our financial statements appropriately reflect these amounts, including the recording of liabilities when a loss is probable and reasonably estimable. For more information on these matters, see Note 11 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K.

Contingencies and Guarantees

Contingent financial commitments, such as financial guarantees, represent obligations that become payable only if certain predefined events occur. We have certain subsidiaries that enter into various financial and performance guarantees and indemnities providing assurance to third parties. We believe the likelihood of payment under our guarantees is remote. No liabilities have been recorded for such guarantees and indemnifications, as the fair values were inconsequential at inception.

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Regulatory Matters

In February 2015, Atlanta Gas Light made a filing with the Georgia Commission for a rate true-up of allowed unrecovered revenue of $178 million through December 2014 related to its PRP. In October 2015, Atlanta Gas Light received a final order from the Georgia Commission, which represented a global resolution of all matters previously outstanding before the Georgia Commission, including a final determination of the true-up recovery related to the PRP. This order allows Atlanta Gas Light to recover $144 million of the $178 million unrecovered program revenue that was requested in its February 2015 filing. The remaining unrecovered amount relates primarily to recoveries of previously allowed rate of return amounts, which are included in our unrecognized ratemaking amount and does not have a material impact on our unaudited condensed consolidated financial statements as of September 30, 2015. Provisions in the order resulted in the recognition of $1 million of interest expense related to the PRP true-up for the three and nine months ended September 30, 2015 on our unaudited Condensed Consolidated Statements of Income.

We began recovering the $144 million in October 2015 through the monthly PRP surcharge, which increases by $0.82, $0.81 and $0.81 on October 1, 2015, October 1, 2016, and October 1, 2017, respectively. The cumulative total monthly increase to the PRP surcharge will remain at $2.44 and be effective until the earlier of the full recovery of the under-recovered amount or December 31, 2025.

Additionally, one of the capital projects under the PRP experienced construction issues on certain segments in late 2013, and prior to these segments being placed into service it was necessary to complete mitigation work. The order from the Georgia Commission allows for the recovery of these mitigation costs in future base rates, but delayed such recovery until at least March 31, 2017. Provisions in the order resulted in the recognition of $5 million in operation and maintenance expense for the three and nine months ended September 30, 2015 on our unaudited Condensed Consolidated Statements of Income. Atlanta Gas Light continues to pursue contractual and legal claims against certain third-party contractors in connection with the mitigation costs incurred for construction issues experienced in finalizing the PRP. Any amounts recovered through the legal process will be retained by Atlanta Gas Light. As of September 30, 2015, the total capitalized mitigation cost to be included in future rates is approximately $28 million.

In August 2014, staff of the Illinois Commission and the CUB filed testimony in the Nicor Gas 2003 gas cost prudence review disputing certain gas loan transactions offered by Nicor Gas under its Chicago Hub services and requesting refunds of $18 million and $22 million, respectively. We filed surrebuttal testimony in December 2014 disputing that any refund is due, as Nicor Gas was authorized to enter into these transactions, and revenues associated with such transactions reduced ratepayers’ costs as either credits to the PGA or reductions to base rates consistent with then-current Illinois Commission orders governing these activities. In July 2015, the Administrative Law Judge issued a proposed order concluding that Nicor Gas’ supply costs and purchases in 2003 were prudent, its reconciliation of the related costs was proper, and the propositions by the staff of the Illinois Commission and the CUB were based on hindsight speculation, which is expressly prohibited in a prudence review examination. In September 2015, the Illinois Commission issued a final order approving the proposal of the Administrative Law Judge. In November 2015, the Illinois Commission granted the CUB's petition for a rehearing on this matter.

In December 2012, we filed a petition with the Georgia Commission for approval to resolve a volumetric imbalance of natural gas related to Atlanta Gas Light’s use of retained storage assets to operationally balance the system for the benefit of the natural gas market. In September 2014, we filed a stipulation that was entered between us, staff of the Georgia Commission and several Marketers that included a resolution of the 4.6 Bcf imbalance over a five-year period from January 1, 2015 through December 31, 2019, which was approved by the Georgia Commission in December 2014. During the first half of 2015, discretionary funds available to the Universal Service Fund, which is controlled by the Georgia Commission, were used to resolve their obligation of 25% of the imbalance, or approximately 1.15 Bcf of natural gas. Atlanta Gas Light was also obligated to resolve 25% of the 4.6 Bcf imbalance, or approximately 1.15 Bcf of natural gas, through system injections, which was fully replaced as of September 30, 2015. We expect that the Marketers will utilize the entire five-year period permitted by the stipulation to replace their obligation in full.

Environmental Matters

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control that 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. See Note 4 herein for additional information on our environmental remediation costs.

On September 15, 2015, the Environmental Protection Agency filed an administrative complaint and notice of opportunity for hearing against Nicor Gas. The complaint alleges violation of the regulatory requirements applicable to polychlorinated biphenyls in the Nicor Gas distribution system and the Environmental Protection Agency seeks a total civil penalty of approximately $0.3 million. While we are unable to predict the ultimate outcome of this matter, the final disposition of this matter is not expected to have a material adverse impact on our liquidity or financial condition.

Litigation

We are involved in litigation arising in the normal course of business. 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

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contingencies, either individually or in aggregate, will require us to take charges against, or will result in reductions in, future earnings. Management believes that while the resolutions of these contingencies, whether individually or in aggregate, could be material to earnings in a particular quarter, they will not have a material adverse effect on our consolidated financial position or cash flows for the year. For additional litigation information, see Note 11 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K.

The company and each member of the Board have been named as defendants in four purported shareholder class action lawsuits filed in the United States District Court for the Northern District of Georgia, Atlanta Division, which we refer to as the “Court”: Patrick Baker v. AGL Resources Inc., et al., which we refer to as the “Baker Action”, Jeff Morton v. AGL Resources Inc., et al., which we refer to as the “Morton Action”, Sarah Halberstam and Baruch Z. Halberstam (as custodian for Benjamin Halberstam) v. AGL Resources Inc., et al., which we refer to as the “Halberstam Action”, and Manuel Abt v. AGL Resources, Inc., et al., which we refer to as the “Abt Action”, filed on September 16, 2015, September 22, 2015, September 28, 2015 and October 9, 2015, respectively. Southern Company and Merger Sub were also named as defendants in the Baker Action and the Morton Action. We refer to the Baker Action, the Morton Action, the Halberstam Action and the Abt Action, collectively, as the “Actions”. The Actions allege that our preliminary proxy statement contains false and misleading statements and omits material information in violation of certain provisions under the Exchange Act. The Actions also allege that the members of the Board are liable for those alleged misstatements and omissions. The Morton Action further alleges that the members of the Board breached their fiduciary duties owed to the shareholders of the company in connection with the merger and that Southern Company and Merger Sub aided and abetted such breaches. The Actions seek, among other things, preliminary and permanent injunctive relief enjoining the merger, rescission or rescissory damages in the event the merger is implemented and an award of attorneys’ and experts’ fees and costs. On October 23, 2015, the Court consolidated the four actions, which we refer to as the “Consolidated Action.” On October 26, 2015, plaintiff Baker filed an Emergency Motion to Expedite Proceedings, which the Court denied on November 4, 2015. The plaintiffs filed a consolidated and amended complaint on November 4, 2015. The company and the Board believe that the claims in the Consolidated Action are without merit, and intend to vigorously defend the Consolidated Action.

PBR Proceeding On June 7, 2013, the Illinois Commission issued an order requiring us to refund $72 million to current Nicor Gas customers through our PGA mechanism based upon natural gas throughput. All refunds were completed in the first half of 2014. The CUB’s February 28, 2014 appeal of the Illinois Commission’s order requesting refunds consistent with its 2009 request was rejected by the appellate court in Illinois on March 18, 2015.

Note 12 - Segment Information

Our reportable segments comprise revenue-generating components of the company for which we produce separate financial information internally that we regularly use to make operating decisions and assess performance. Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. We manage our businesses through four reportable segments – distribution operations, retail operations, wholesale services and midstream operations. Our non-reportable segments are combined and presented as “other segments.”

Our distribution operations segment is the largest component of our business and includes natural gas local distribution utilities that construct, manage and maintain intrastate natural gas pipelines and distribution facilities in seven states. Although the operations of this segment are geographically dispersed, the operating subsidiaries within the segment are regulated utilities with rates determined by individual state regulatory commissions. These natural gas distribution utilities have similar economic and risk characteristics.

We are also involved in several related and complementary businesses. Our retail operations segment includes retail natural gas marketing to end-use customers primarily in Georgia and Illinois. Additionally, retail operations provides home equipment protection products and services. Our wholesale services segment engages in natural gas storage and gas pipeline arbitrage and related activities. Additionally, this segment provides natural gas asset management and/or related logistics services for each of our utilities except Nicor Gas, as well as for non-affiliated companies. Our midstream operations segment includes our non-utility storage and pipeline operations, including the operation of high-deliverability natural gas storage assets. Our “other” non-reportable segments include subsidiaries that individually are not significant on a stand-alone basis and that do not align with one of our reportable segments.

The chief operating decision maker of the company is the Chairman and Chief Executive Officer, who utilizes EBIT as the primary measure of profit and loss in assessing the results of each segment’s operations. EBIT includes operating income and other income and expenses and excludes income taxes and interest expense, which we evaluate on a consolidated basis. Summarized statements of income, statements of financial position and capital expenditure information by segment as of and for the periods presented are shown in the following tables.

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Three months ended September 30, 2015



In millions	Distribution operations		Retail operations		Wholesale services ⁽¹⁾		Midstream operations			Other segments			Intercompany eliminations			Consolidated
Operating revenues from external parties	$	410	$	134	$	34	$	12		$	—		$	(6	)	$	584
Intercompany revenues	35		—		—		—			—			(35		)	—
Total operating revenues	445		134		34		12			—			(41		)	584
Operating expenses
Cost of goods sold	96		86		1		3			—			(40		)	146
Operation and maintenance	158		29		14		6			(2		)	(1		)	204
Depreciation and amortization	83		7		—		4			4			—			98
Taxes other than income taxes	23		1		1		1			2			—			28
Merger-related expenses	—		—		—		—			35			—			35
Goodwill impairment	—		—		—		14			—			—			14
Total operating expenses	360		123		16		28			39			(41		)	525
Operating income (loss)	85		11		18		(16		)	(39		)	—			59
Other income	1		—		—		—			1			—			2
EBIT	$	86	$	11	$	18	$	(16	)	$	(38	)	$	—		$	61
Capital expenditures	$	273	$	2	$	1	$	8		$	9		$	—		$	293

Three months ended September 30, 2014



In millions	Distribution operations		Retail operations		Wholesale services ⁽¹⁾			Midstream operations			Other segments			Intercompany eliminations			Consolidated
Operating revenues from external parties	$	439	$	146	$	5		$	4		$	1		$	(6	)	$	589
Intercompany revenues	35		—		—			—			—			(35		)	—
Total operating revenues	474		146		5			4			1			(41		)	589
Operating expenses
Cost of goods sold	138		99		3			(3		)	—			(39		)	198
Operation and maintenance	145		34		10			5			1			(2		)	193
Depreciation and amortization	79		7		—			5			2			—			93
Taxes other than income taxes	24		1		1			1			3			—			30
Total operating expenses	386		141		14			8			6			(41		)	514
Gain on disposition of assets	—		—		3			—			—			—			3
Operating income (loss)	88		5		(6		)	(4		)	(5		)	—			78
Other income (expense)	1		—		(1		)	—			3			—			3
EBIT	$	89	$	5	$	(7	)	$	(4	)	$	(2	)	$	—		$	81
Capital expenditures	$	196	$	3	$	—		$	3		$	9		$	—		$	211

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Nine months ended September 30, 2015



In millions	Distribution operations		Retail operations		Wholesale services⁽¹⁾		Midstream operations			Other segments			Intercompany eliminations			Consolidated
Operating revenues from external parties	$	2,201	$	628	$	128	$	42		$	9		$	(29	)	$	2,979
Intercompany revenues	131		—		—		—			—			(131		)	—
Total operating revenues	2,332		628		128		42			9			(160		)	2,979
Operating expenses
Cost of goods sold	1,038		391		10		15			5			(156		)	1,303
Operation and maintenance	503		100		49		18			(4		)	(4		)	662
Depreciation and amortization	248		19		1		13			12			—			293
Taxes other than income taxes	128		3		2		3			6			—			142
Merger-related expenses	—		—		—		—			35			—			35
Goodwill impairment	—		—		—		14			—			—			14
Total operating expenses	1,917		513		62		63			54			(160		)	2,449
Operating income (loss)	415		115		66		(21		)	(45		)	—			530
Other income	5		—		—		1			3			—			9
EBIT	$	420	$	115	$	66	$	(20	)	$	(42	)	$	—		$	539
Total assets	$	12,096	$	645	$	913	$	680		$	9,307		$	(9,435	)	$	14,206
Capital expenditures	$	691	$	6	$	2	$	18		$	28		$	—		$	745

Nine months ended September 30, 2014



In millions	Distribution operations		Retail operations		Wholesale services ⁽¹⁾			Midstream operations			Other segments			Intercompany eliminations			Consolidated
Operating revenues from external parties	$	2,821	$	728	$	383		$	65		$	5		$	(62	)	$	3,940
Intercompany revenues	153		1		—			—			—			(154		)	—
Total operating revenues	2,974		729		383			65			5			(216		)	3,940
Operating expenses
Cost of goods sold	1,655		498		13			44			—			(210		)	2,000
Operation and maintenance	515		105		59			18			2			(6		)	693
Depreciation and amortization	235		21		1			14			10			—			281
Taxes other than income taxes	146		3		2			4			5			—			160
Total operating expenses	2,551		627		75			80			17			(216		)	3,134
Gain on disposition of assets	—		—		3			—			—			—			3
Operating income (loss)	423		102		311			(15		)	(12		)	—			809
Other income (expense)	5		—		(3		)	1			5			—			8
EBIT	$	428	$	102	$	308		$	(14	)	$	(7	)	$	—		$	817
Total assets	$	11,624	$	663	$	1,056		$	692		$	9,150		$	(9,253	)	$	13,932
Capital expenditures	$	504	$	9	$	1		$	8		$	21		$	—		$	543


(1)	The revenues for wholesale services are netted with costs associated with its energy and risk management activities. A reconciliation of our operating revenues and our intercompany revenues is shown in the following table.



In millions	Third party gross revenues		Intercompany revenues	Total gross revenues	Less gross gas costs	Operating revenues
Three months ended September 30, 2015	$	1,440	90	1,530	1,496	$	34
Three months ended September 30, 2014	$	1,885	126	2,011	2,006	$	5
Nine months ended September 30, 2015	$	4,876	329	5,205	5,077	$	128
Nine months ended September 30, 2014	$	8,313	584	8,897	8,514	$	383

Identifiable assets are those used in each segment’s operations. Information by segment on our Consolidated Statement of Financial Position as of December 31, 2014, is as follows:



In millions	Distribution operations		Retail operations		Wholesale services		Midstream operations		Other segments		Intercompany eliminations			Consolidated
Total assets	$	12,037	$	670	$	1,402	$	694	$	9,706	$	(9,621	)	$	14,888

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Note 13 - Discontinued Operations

On September 1, 2014, we closed on the sale of Tropical Shipping to an unrelated third party. The after-tax cash proceeds and distributions from the transaction were approximately $225 million. We determined that the cumulative foreign earnings of Tropical Shipping would no longer be indefinitely reinvested offshore. Accordingly, we recognized income tax expense of $60 million, of which $31 million was recorded in the first quarter of 2014, and the remaining $29 million was recorded in the third quarter of 2014 related to the cumulative foreign earnings for which no tax liabilities had been previously recorded, resulting in our repatriation of $86 million in cash.

During the first quarter of 2014, based upon the negotiated sales price, we recorded a non-cash goodwill impairment charge of $19 million, for which there was no income tax benefit. Additionally, we recognized a total charge of $7 million in the second and third quarters of 2014 related to the suspension of depreciation and amortization on assets for which we were not compensated by the buyer. The financial results of these businesses are reflected as discontinued operations, and the prior period presented has been recast to reflect the discontinued operations. The components of discontinued operations recorded on the unaudited Condensed Consolidated Statements of Income are as follows:



	Three months ended			Nine Months Ended
In millions	September 30, 2014			September 30, 2014
Operating revenues	$	62		$	243
Operating expenses
Cost of goods sold	38			149
Operation and maintenance	20			75
Depreciation and amortization	—			5
Taxes other than income taxes	1			5
Loss on sale and goodwill impairment	5			28
Total operating expenses	64			262
Operating loss	(2		)	(19		)
Income tax expense	(29		)	(61		)
Loss from discontinued operations, net of tax	$	(31	)	$	(80	)

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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 related notes in this quarterly filing, as well as with our 2014 Form 10-K. Results for the interim periods presented are not necessarily indicative of the results to be expected for the full fiscal period 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 and proxy statements we file with the SEC or otherwise release to the public and on our website are forward-looking statements and are subject to uncertainties and risks. Senior officers and other employees may also make verbal statements to analysts, investors, regulators, the media and others that are forward-looking.

Forward-looking statements often include words such as "anticipate," "assume," “believe,” "can," "could," "estimate," "expect," "forecast," "future," “goal,” "indicate," "intend," "may," “outlook,” "plan," “potential,” "predict," "project,” “proposed,” "seek," "should," "target," "would" or similar expressions. You are cautioned not to place undue reliance on forward-looking statements.

While we believe that our expectations are reasonable in view of the information that we currently have, these expectations are subject to future events, risks and uncertainties, and there are numerous factors – many of which are beyond our control – that could cause actual results to vary materially from these expectations. Such events, risks and uncertainties include, but are not limited to:


•	certain risks and uncertainties associated with the proposed merger with Southern Company, including, without limitation:


•	the possibility that the proposed merger does not close due to the failure to satisfy the closing conditions, including, but not limited to, a failure of our shareholders to approve the Merger Agreement or a failure to obtain the required regulatory approvals;


•	delays caused by required regulatory approvals, which may delay the proposed merger or cause the companies to abandon the transaction;


•	disruption from the proposed merger making it more difficult to maintain our business and operational relationships as well as maintaining our relationships with employees, suppliers or customers, and the risk that unexpected costs will be incurred during this process;


•	the diversion of management time on merger-related issues; and


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


•	changes in price, supply and demand for natural gas and related products;


•	the impact of changes in state and federal legislation and regulation, including any changes related to climate matters;


•	actions taken by government agencies on rates and other matters;


•	concentration of credit risk;


•	utility and energy industry consolidation;


•	the impact on cost and timeliness of construction projects by government and other approvals, project delays, adequacy of supply of diversified vendors, and unexpected changes in project costs, including the cost of funds to finance these projects and our ability to recover our project costs from our customers;


•	limits on pipeline capacity;


•	the impact of acquisitions and divestitures;


•	our ability to successfully integrate operations that we have or may acquire or develop in the future;


•	direct or indirect effects on our business, financial condition or liquidity resulting from a change in our credit ratings or the credit ratings of our counterparties or competitors;


•	interest rate fluctuations;


•	financial market conditions, including disruptions in the capital markets and lending environment;


•	general economic conditions;


•	uncertainties about environmental issues and the related impact of such issues, including our environmental remediation plans;


•	the capacity of our gas storage caverns, which are subject to natural settling and other occurrences;


•	contracting rates at our midstream operations storage business;


•	the impact of our construction projects and related capital expenditures, including our pipeline projects;


•	the development, timing and anticipated costs relating to our pipeline projects;


•	the impact of changes in weather, including climate change, on the temperature-sensitive portions of our business;

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•	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;


•	the effect of accounting pronouncements issued periodically by standard-setting bodies; and


•	the other factors discussed elsewhere herein and in our other filings with the SEC.

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

Executive Summary

We are an energy services holding company whose principal business is the safe and reliable distribution of natural gas in seven states – Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee and Maryland – through our seven natural gas distribution utilities. We are also involved in several other businesses that are complementary to the distribution of natural gas. We manage our businesses through four reportable segments – distribution operations, retail operations, wholesale services and midstream operations. Our non-reportable segments are aggregated and presented as “other segments.” These segments are consistent with how management views and operates our business. For additional information on our reportable segments, see Note 12 to our unaudited condensed consolidated financial statements herein and Item 1, “Business” of our 2014 Form 10-K.

Proposed Merger With Southern Company In August 2015, we entered into the Merger Agreement with Southern Company, which, based on the number of common shares and the fair value of debt outstanding as of September 30, 2015, reflects an estimated business enterprise value of AGL Resources of $12.7 billion, including a total equity value of $7.9 billion. When the merger becomes effective, which is expected to occur in the second half of 2016, each share of our common stock, other than certain excluded shares, will convert into the right to receive $66 in cash, without interest and less any applicable withholding taxes. Completion of the merger is conditioned upon, among other things, the approval by the affirmative vote of the holders of a majority of our common stock as well as certain state utility and other regulatory commissions. At closing, the transaction is expected to create the second largest utility in the U.S. by customer base and we will become a wholly owned subsidiary of Southern Company and continue to maintain our own management team.

For additional information relating to this transaction, see Note 2 and Note 11 to our unaudited condensed consolidated financial statements under Item I, Part 1 herein and the definitive proxy statement contained in Schedule 14A filed with the SEC on October 13, 2015. This proxy statement provided notice and information about the special meeting of our shareholders to vote on the Merger Agreement that will be held on November 19, 2015. See Item 1A - Risk Factors, herein for information on the merger-related risks.

Operating Results For the third quarter of 2015, our net income from continuing operations attributable to AGL Resources was $11 million, a decrease of $12 million compared to the same period in 2014. This reduction was primarily the result of $35 million ($21 million, net of tax) of merger-related expenses recorded in our other segments and a $14 million ($9 million, net of tax) non-cash impairment of goodwill at midstream operations during the current period. This reduction was partly offset by higher EBIT at wholesale services largely related to hedge gains in the current period.

For the first nine months of 2015, our net income from continuing operations attributable to AGL Resources was $246 million, a decrease of $168 million compared to the same period in 2014. This decrease was primarily the result of performance at wholesale services that was lower than the record earnings we reported in the same period in 2014 when we experienced increased natural gas price volatility primarily during the first three months of 2014 associated with the effect of the polar vortex, which enabled us to capture unprecedented value in wholesale services and led to record earnings. Additionally, the effect of additional weather-related EBIT due to colder-than-normal weather during 2015 is muted when compared to the prior year period due to the higher weather-related EBIT associated with the effect of the polar vortex in 2014. Also contributing to the decreased EBIT were the costs associated with the proposed merger with Southern Company and the impairment of goodwill at midstream operations.

Business Objectives Several of our specific business objectives are detailed as follows:

•

Distribution Operations: Invest necessary capital to enhance and maintain safety and reliability; remain a low-cost leader within the industry; expand the natural gas distribution system and capitalize on potential customer conversions as opportunities arise. We intend to continue investing in our regulatory infrastructure programs to minimize regulatory lag and the recovery cycle. We continue to manage costs effectively and leverage our shared services model across our businesses to largely overcome inflationary effects.

Nicor Gas In July 2014, the Illinois Commission approved our nine-year regulatory infrastructure program, Investing in Illinois, under which we implemented rates that became effective in March 2015. We have placed into service $180 million of qualifying projects under this plan as of September 30, 2015.

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Atlanta Gas Light In accordance with an order issued by the Georgia Commission, when AGL Resources makes a business acquisition that reduces the costs allocated or charged to Atlanta Gas Light for shared services, the net savings to Atlanta Gas Light will be shared equally between the firm customers of Atlanta Gas Light and our shareholders for a ten-year period. In March 2015, the Georgia Commission approved the Report of Synergy Savings that we filed in connection with the Nicor Inc. acquisition. The net savings result in annual rate reductions to the firm customers of Atlanta Gas Light of $5 million. These surcredit adjustments are now a component of the Atlanta Gas Light base charge and began appearing on customers’ bills in June 2015.

In October 2015, the Georgia Commission issued a final order that represented a global resolution of all matters previously outstanding before the Georgia Commission, including a final determination of the true-up recovery related to the PRP. Under this order, in October 2015, Atlanta Gas Light began recovering $144 million of the $178 million unrecovered program revenue that was requested in its February 2015 filing. This order also permits Atlanta Gas Light to recover mitigation costs in future base rate after March 2017. See Note 11 to our unaudited condensed consolidated financial statements herein for additional information on this regulatory order.

Elizabethtown Gas In September 2015, Elizabethtown Gas filed the Safety, Modernization and Reliability Tariff (SMART) plan with the New Jersey BPU seeking approval to invest more than $1.1 billion to replace 630 miles of vintage cast iron, steel and copper pipeline, as well as 240 regulator stations. If approved, the program is expected to be completed by 2027. As currently proposed, costs incurred under the program would be recovered primarily through a rider surcharge over a period of 10 years.

Virginia Natural Gas In April 2015, the Virginia Commission issued an order approving a two-year extension to the asset management agreement with Sequent, which is now set to expire on March 31, 2018.

Florida City Gas The Florida Commission approved Florida City Gas' Safety, Access and Facility Enhancement program in September 2015. Under the program, Florida City Gas will spend approximately $10 million annually over a 10-year period on infrastructure relocation and enhancement projects. Costs incurred under the program will be recovered through a rate rider with annual rate adjustments and true-ups. During October 2015, Florida City Gas began spending under the program and plant in service associated with work in the fourth quarter of 2015 will be included in the calculation of rates beginning January 1, 2016.

•

Retail Operations: Maintain operating margins in Georgia and Illinois while continuing to expand into other profitable retail markets and expand our warranty businesses through strategic contract acquisitions and partnership opportunities with our affiliates. We expect the Georgia natural gas retail market to remain highly competitive; however, our operating margins are forecasted to remain stable with modest growth and expansion into new markets.

•

Wholesale Services: Maximize strong storage and transportation positions; effectively perform on existing asset management agreements; expand customer base and maintain cost structure in line with market fundamentals. We anticipate volatility to remain low to moderate in certain areas of our portfolio; however, we expect near-term volatility in the supply-constrained Northeast corridor until expected new pipeline projects are completed and additional capacity is placed into service. We continue to position our business to secure sufficient supplies of natural gas to meet the needs of our utility and third-party customers and to hedge natural gas prices to manage costs effectively, reduce price volatility and maintain a competitive advantage. During the nine months of 2014, we experienced increased natural gas price volatility that enabled us to capture unprecedented value in wholesale services leading to record earnings. Wholesale services has maintained strong earnings results for 2015 due to high levels of volatility in commodity and transportation prices in the first quarter, driving performance by our asset-based transportation and storage portfolios and higher volumes to our power generation customers and service-based transactions, including producer and utility asset management transactions. However, volatility in 2015 was lower than the levels experienced from the extreme and prolonged cold weather in 2014, and as a result EBIT for the nine months ended September 30, 2015 was lower than EBIT for the same period in 2014.

•

Midstream Operations: Optimize storage portfolio, including contracts that have expired or will expire; evaluate alternate uses for our storage facilities; pursue natural gas pipeline and LNG transportation opportunities and the sales of LNG for high horsepower engine applications. We participate in three pipeline projects that will provide a regulated-type return on our investments and that also provide needed transportation capacity in our utility service territories. These projects, which remain subject to regulatory approvals, along with our existing pipelines, will support our efforts to provide diverse sources of natural gas supplies to our customers, resolve current and long-term supply planning for new capacity, enhance system reliability and generate economic development in the areas served. See Note 10 to our unaudited condensed consolidated financial statements herein and Item 1, “Business” of our 2014 Form 10-K for additional information.

Natural Gas Market Fundamentals Volatility in the natural gas market arises from a number of factors, such as weather fluctuations or changes in supply or demand for natural gas in different regions of the country. The volatility of natural gas commodity prices has a significant impact on our customer rates, our long-term competitive position against other energy sources and the ability of our retail operations and wholesale services segments to capture value from location and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of our operations to earnings variability.

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Our non-utility businesses principally use physical and financial arrangements to reduce the risks associated with fluctuations in market conditions and changing commodity prices. These economic hedges may not qualify, or may not be designated, for hedge accounting treatment. As a result, our reported earnings for wholesale services, retail operations and midstream operations reflect changes in the fair values of certain derivatives. A decline in natural gas prices or a narrowing of transportation spreads generally results in derivative gains and corresponding increases in EBIT, while an increase in natural gas prices or a widening of transportation spreads generally results in derivative losses and corresponding decreases in EBIT. These values may change significantly from period to period and are reflected as gains or losses within our operating revenues or our OCI for those derivative instruments that qualify, and are designated, as accounting hedges.

Results of Operations

We generate the majority of our operating revenues through the sale, distribution and storage of natural gas. We include in our consolidated revenues an estimate of revenues from natural gas distributed, but not yet billed to residential, commercial and industrial customers from the date of the last bill to the end of the reporting period. No individual customer or industry accounts for a significant portion of our revenues. Our revenues declined significantly in 2015 as compared to 2014 primarily due to lower natural gas prices and lower volumes of gas sold to customers due to weather in the first nine months of 2015 that was warmer than the extreme cold experienced in 2014.

Our operating results can vary significantly from quarter to quarter as a result of the seasonality of operating revenues and EBIT at distribution operations and retail operations. During the Heating Season, natural gas usage and operating revenues are generally higher, as more customers are connected to our distribution systems and natural gas usage is higher in periods of colder weather. Alternatively, our base operating expenses, excluding cost of gas, revenue taxes, interest expense and certain incentive compensation costs, are incurred relatively evenly over any given year, resulting in variability in the quarterly pattern of earnings.

We evaluate segment performance using the measures of EBIT and operating margin. EBIT includes operating income and other income and expenses and excludes interest expense and income taxes, which we evaluate on a consolidated basis. Operating margin is a non-GAAP measure that is calculated as operating revenues minus cost of goods sold and revenue tax expense in distribution operations. Operating margin excludes operation and maintenance expense, depreciation and amortization, taxes other than income taxes, and the gain or loss on the sale of assets, which are included in our calculation of operating income as reflected in our unaudited Condensed Consolidated Statements of Income.

We believe operating margin is a better indicator than operating revenues of the contribution resulting from customer growth in our distribution operations segment since the cost of goods sold and revenue tax expenses can vary significantly and are generally billed directly to our customers. We also consider operating margin to be a better indicator in our retail operations, wholesale services and midstream operations segments since it is a direct measure of operating margin before overhead costs. You should not consider operating margin an alternative to, or a more meaningful indicator of, our operating performance than operating income or net income attributable to AGL Resources as determined in accordance with GAAP. In addition, operating margin may not be comparable to similarly titled measures of other companies. The following table reconciles operating revenues and operating margin to operating income, and EBIT to income before income taxes and net income, together with other consolidated financial information for the periods presented.

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	Three months ended September 30,									Nine months ended September 30,
In millions, except per share amounts	2015			2014			Change			2015			2014			Change
Operating revenues ⁽¹⁾	$	584		$	589		$	(5	)	$	2,979		$	3,940		$	(961	)
Cost of goods sold	(146		)	(198		)	52			(1,303		)	(2,000		)	697
Revenue tax expense ⁽²⁾	(8		)	(9		)	1			(81		)	(101		)	20
Operating margin	430			382			48			1,595			1,839			(244		)
Goodwill impairment	(14		)	—			(14		)	(14		)	—			(14		)
Operating expenses ⁽³⁾	(365		)	(316		)	(49		)	(1,132		)	(1,134		)	2
Revenue tax expense ⁽²⁾	8			9			(1		)	81			101			(20		)
Gain on disposition of assets	—			3			(3		)	—			3			(3		)
Operating income	59			78			(19		)	530			809			(279		)
Other income	2			3			(1		)	9			8			1
EBIT	61			81			(20		)	539			817			(278		)
Interest expense, net	(42		)	(44		)	2			(128		)	(135		)	7
Income before income taxes	19			37			(18		)	411			682			(271		)
Income tax expense	(7		)	(14		)	7			(150		)	(254		)	104
Income from continuing operations	12			23			(11		)	261			428			(167		)
Loss from discontinued operations, net of tax ⁽⁴⁾	—			(31		)	31			—			(80		)	80
Net income (loss)	12			(8		)	20			261			348			(87		)
Less net income attributable to noncontrolling interest	1			—			1			15			14			1
Net income (loss) attributable to AGL Resources	$	11		$	(8	)	$	19		$	246		$	334		$	(88	)
Net income (loss) attributable to AGL Resources
Income from continuing operations	$	11		$	23		$	(12	)	$	246		$	414		$	(168	)
Loss from discontinued operations, net of tax ⁽⁴⁾	—			(31		)	31			—			(80		)	80
Net income (loss) attributable to AGL Resources	$	11		$	(8	)	$	19		$	246		$	334		$	(88	)
Diluted earnings (loss) per common share
Continuing operations	$	0.09		$	0.19		$	(0.10	)	$	2.05		$	3.47		$	(1.42	)
Discontinued operations ⁽⁴⁾	—			(0.25		)	0.25			—			(0.67		)	0.67
Diluted earnings (loss) per common share attributable to AGL Resources	$	0.09		$	(0.06	)	$	0.15		$	2.05		$	2.80		$	(0.75	)


(1)	Our revenues declined significantly in 2015 as compared to 2014 primarily due to lower natural gas prices and lower volumes of gas sold to customers due to weather in the first nine months of 2015 that was warmer than the extreme cold experienced in 2014.


(2)	Adjusted for Nicor Gas’ revenue tax expenses, which are passed through directly to our customers.


(3)	Operating expenses for the three and nine months ended September 30, 2015 include $35 million of merger-related expenses.


(4)	In September 2014, we closed on the sale of Tropical Shipping. See Note 13 to our unaudited condensed consolidated financial statements under Part I, Item 1 herein for additional information.

Operating Metrics

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



	Nine months ended September 30,			2015 vs. 2014		2015 vs. normal
	Normal ⁽¹⁾	2015	2014	warmer		colder
Illinois ⁽²⁾	3,744	3,918	4,453	(12	)%	5	%
Georgia	1,606	1,654	1,879	(12	)%	3	%


(1)	Normal represents the 10-year average from January 1, 2005 through September 30, 2014 for Illinois at Chicago Midway International Airport and for Georgia at Atlanta Hartsfield-Jackson International Airport, as obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center.


(2)	The 10-year average Heating Degree Days established by the Illinois Commission in our last rate case is 3,580 for the first nine months from 1998 through 2007.

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For our weather risk in Illinois and Georgia associated with Nicor Gas and our retail operations segment, we have weather hedging programs that utilize weather derivatives to reduce the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather.

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



	Three months ended September 30,				2015 vs. 2014		Nine months ended September 30,				2015 vs. 2014
In thousands	2015		2014		% change		2015		2014		% change
Distribution operations	4,488		4,455		0.7	%	4,526		4,498		0.6	%
Retail operations
Energy customers	642		619		3.7	%	646		629		2.7	%
Service contracts	1,164		1,166		(0.2	)%	1,159		1,188		(2.4	)%
Market share in Georgia	30	%	31	%	(3.2	)%	30	%	31	%	(3.2	)%

We anticipate overall customer growth trends at distribution operations for 2015 to continue improving based on an expectation of continued improvement in the economy, the related housing market and low natural gas prices.

Retail operations’ market share in Georgia has decreased slightly primarily as a result of a highly competitive marketing environment, which we expect to continue for the foreseeable future. We will continue efforts in our retail operations segment to enter into targeted markets and expand our energy customers and service contracts.

Volumes Our natural gas volume metrics for distribution operations and retail operations, as shown in the following table, illustrate the effects of weather and customer demand for natural gas compared to the prior year. Wholesale services’ physical sales volumes represent the daily average natural gas volumes sold to its customers.



	Three months ended September 30,		2015 vs. 2014		Nine months ended September 30,		2015 vs. 2014
	2015	2014	% change		2015	2014	% change
Distribution operations (In Bcf)
Firm	75	72	4.2	%	519	539	(3.7	)%
Interruptible	23	25	(8.0	)%	74	78	(5.1	)%
Total	98	97	1.0	%	593	617	(3.9	)%
Retail operations (In Bcf)
Georgia firm	4	3	33.3	%	27	28	(3.6	)%
Illinois	1	1	—	%	10	13	(23.1	)%
Other (including Florida, Maryland, New York and Ohio)	1	1	—	%	8	7	14.3	%
Wholesale services (Bcf / day)
Daily physical sales	6.4	5.6	14.3	%	6.7	6.2	8.1	%

Within midstream operations, our natural gas storage businesses seek to have a significant portion of their working natural gas capacity under firm subscription, but also take into account current and expected market conditions. This allows our natural gas storage business to generate additional revenue during times of peak market demand for natural gas storage services, but retain some consistency with its earnings and maximize the value of the investments.

Our midstream operations storage business is cyclical, and the abundant supply of natural gas in recent years and resulting lack of market and price volatility have negatively impacted the profitability of our storage facilities. We anticipate lower natural gas prices to continue for the remainder of 2015 as compared to historical averages. However, preliminary rates indicate that the rates at which we re-contract expiring capacity in 2015 may not be as high as we expected and may also remain below historical averages. The prices for natural gas storage capacity are expected to increase as supply and demand quantities reach equilibrium with continued economic improvement, expected exports of LNG, and projected increases in natural gas demand in response to low prices and expanded uses for natural gas. As of the periods presented, the overall monthly average firm subscription rates per facility and amount of firm capacity subscription were as follows:



	September 30, 2015			September 30, 2014
	Average rates ⁽¹⁾		Firm capacity under subscription ⁽¹⁾	Average rates ⁽¹⁾		Firm capacity under subscription ⁽¹⁾
Jefferson Island	$	0.092	4.2	$	0.108	4.6
Golden Triangle	0.041		5.0	0.114		5.0
Central Valley	0.047		4.0	0.062		2.5

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(1)	Rates are per dekatherm. Firm capacity under subscription excludes 5.0 Bcf contracted by Sequent as of September 30, 2015, at an average monthly rate of $0.080 and 7.0 Bcf as of September 30, 2014, at an average monthly rate of $0.050.

Segment Information Operating margin, operating expenses and EBIT information for each of our segments is contained in the following tables:



	Three months ended September 30, 2015									Three months ended September 30, 2014
In millions	Operating margin ^{(1) (2)}			Operating expenses⁽²⁾			EBIT ⁽¹⁾			Operating margin ^{(1) (2)}			Operating expenses ⁽²⁾			EBIT⁽¹⁾
Distribution operations	$	341		$	256		$	86		$	327		$	239		$	89
Retail operations	48			37			11			47			42			5
Wholesale services	33			15			18			2			11			(7		)
Midstream operations ⁽³⁾	9			25			(16		)	7			11			(4		)
Other segments ⁽⁴⁾	—			39			(38		)	1			6			(2		)
Intercompany eliminations	(1		)	(1		)	—			(2		)	(2		)	—
Consolidated	$	430		$	371		$	61		$	382		$	307		$	81



	Nine months ended September 30, 2015									Nine months ended September 30, 2014
In millions	Operating margin ^{(1) (2)}			Operating expenses ⁽²⁾			EBIT⁽¹⁾			Operating margin ^{(1) (2)}			Operating expenses ⁽²⁾			EBIT⁽¹⁾
Distribution operations	$	1,213		$	798		$	420		$	1,218		$	795		$	428
Retail operations	237			122			115			231			129			102
Wholesale services	118			52			66			370			62			308
Midstream operations ⁽³⁾	27			48			(20		)	21			36			(14		)
Other segments ⁽⁴⁾	4			49			(42		)	5			17			(7		)
Intercompany eliminations	(4		)	(4		)	—			(6		)	(6		)	—
Consolidated	$	1,595		$	1,065		$	539		$	1,839		$	1,033		$	817


(1)	A reconciliation of operating revenue and operating margin to operating income, and EBIT to income before income taxes and net income is contained in “Results of Operations” herein. See Note 12 to our unaudited condensed consolidated financial statements under Part I, Item 1 herein for additional segment information.


(2)	Operating margin and operating expenses are adjusted for revenue tax expenses, which are passed through directly to our customers.


(3)	Includes $14 million goodwill impairment recorded during the third quarter of 2015.


(4)	Includes $35 million of merger-related costs.

Distribution Operations

Our distribution operations segment is the largest component of our business and is subject to regulation and oversight by agencies in each of the seven states we serve. These agencies approve natural gas rates designed to provide us the opportunity to generate revenues to recover the cost of natural gas delivered to our customers and our fixed and variable costs, such as depreciation, interest, maintenance and overhead costs, and to earn a reasonable return for our shareholders.

With the exception of Atlanta Gas Light, our second largest utility, the earnings of our regulated utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas and general economic conditions that may impact our customers’ ability to pay for natural gas consumed. We have various weather mechanisms, such as weather normalization mechanisms at our utilities and weather derivative instruments, that limit our exposure to weather changes within typical ranges in their respective service areas. For the three and nine months ended September 30, 2015, distribution operations’ EBIT decreased by $3 million and $8 million, or 3% and 2%, respectively, compared to the same periods during the prior year, as shown in the following table.

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In millions	Three months ended			Nine months ended
EBIT - September 30, 2014	$	89		$	428
Operating margin
Increase from infrastructure programs, primarily at Atlanta Gas Light and Nicor Gas	7			18
Change in energy efficiency program recoveries primarily at Nicor Gas, offset by operating expenses below	5			(23		)
Higher customer usage and customer growth	4			14
Warmer weather compared to prior year	(1		)	(14		)
Other	(1		)	—
Increase (decrease) in operating margin	14			(5		)
Operating expenses
Write-off of PRP-related costs at Atlanta Gas Light from the settlement	5			5
Change in energy efficiency program expenses primarily at Nicor Gas, offset by operating margin above	5			(23		)
Increased depreciation expense from additional assets placed in service	4			13
Increased benefit expenses primarily as a result of changes in actuarial gains and losses	3			9
Decreased fleet expenses from lower fuel prices	(1		)	(3		)
Other, primarily payroll expenses	1			2
Increase in operating expenses	17			3
EBIT - September 30, 2015	$	86		$	420

Retail Operations

Our retail operations segment, which consists of several businesses that provide energy-related products and services to retail markets, is also weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to partially mitigate potential weather impacts. For the three and nine months ended September 30, 2015, retail operations’ EBIT increased by $6 million and $13 million, respectively, compared to the same periods during the prior year, as shown in the following table. Certain prior period hedge losses were recovered in the current period as the underlying transactions were recognized at higher margins. The net effect is that the transaction ultimately resulted in the expected economic outcome at the time the derivative transaction was executed to manage the associated price risk. During the three and nine months ended September 30, 2015, we recovered $1 million and $11 million, respectively, of hedge losses and for the nine months ended September 30, 2015, we recovered $3 million of LOCOM adjustments that were recorded during 2014. We expect to recover the remaining $2 million of hedge losses that were recorded in 2014 during the fourth quarter of 2015 and the first quarter of 2016.



In millions	Three months ended			Nine months ended
EBIT - September 30, 2014	$	5		$	102
Operating margin
Favorable gas costs and storage optimization due primarily to the recovery of hedge losses and LOCOM recorded in the prior year, as discussed above	2			15
Unfavorable customer mix, offset in the quarter by favorable retail price spreads and increased customer count	1			(3		)
Lower usage primarily in Georgia and Illinois due to warmer weather compared to prior year	—			(7		)
Unrealized losses on fixed price hedges	(2		)	(2		)
Other	—			3
Increase in operating margin	1			6
Operating expenses
Decreased outside services, partially offset by increased marketing expenses	(5		)	(3		)
Decreased depreciation and amortization expense primarily related to lower amortization of customer relationship intangibles	(1		)	(2		)
Increased bad debt expense for the quarter due to a change in the provision rate; year-to-date decrease related to warmer weather and lower natural gas prices	1			(2		)
Decrease in operating expenses	(5		)	(7		)
EBIT - September 30, 2015	$	11		$	115

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Wholesale Services

Our wholesale services segment is involved in asset management and optimization, storage, transportation, producer and peaking services, natural gas supply, natural gas services and wholesale marketing. We have positioned the business to generate positive economic earnings even under low volatility market conditions that can result from a number of factors, including weather fluctuations and changes in supply or demand for natural gas in different regions of the country. However, when market price volatility increases as we experienced in both 2015 and 2014, we are well positioned to capture significant value and generate stronger results. For the three and nine months ended September 30, 2015, wholesale services delivered strong EBIT due to increased levels of volatility in commodity and transportation prices. For the three months ended September 30, 2015, EBIT increased by $25 million compared to the same period last year. However, on a year-to-date basis, volatility was lower than the levels experienced from the extreme and prolonged cold weather in 2014, driving a decrease in EBIT of $242 million for the nine months ended September 30, 2015 compared to the same period last year, as shown in the following table.



In millions	Three months ended			Nine months ended
EBIT - September 30, 2014	$	(7	)	$	308
Operating margin
Change in value of storage derivatives as a result of changes in NYMEX natural gas prices	17			21
Change in commercial activity driven by favorable price spreads during the quarter; year-to-date change driven by lower price volatility resulting from extremely cold weather in 2014	7			(301		)
Change in value of transportation and forward commodity derivatives from price movements related to natural gas transportation positions	5			31
Change in LOCOM adjustment	2			(3		)
Increase (decrease) in operating margin	31			(252		)
Operating expenses
Change primarily related to variable compensation costs driven by variances in earnings	4			(10		)
Increase (decrease) in operating expenses	4			(10		)
Decrease in other income related to the prior year gain on sale of Compass Energy, partially offset by decrease in charitable contribution expenses	(2		)	—
EBIT - September 30, 2015	$	18		$	66

The following table illustrates the components of wholesale services’ operating margin for the periods presented.



	Three months ended September 30,						Nine months ended September 30,
In millions	2015			2014			2015			2014
Commercial activity recognized	$	9		$	2		$	111		$	412
Gain on storage derivatives	19			2			21			—
Gain (loss) on transportation and forward commodity derivatives	7			2			(6		)	(37		)
Inventory LOCOM adjustment, net of estimated current period recoveries	(2		)	(4		)	(8		)	(5		)
Operating margin	$	33		$	2		$	118		$	370

Change in commercial activity The commercial activity at wholesale services includes recognized storage and transportation values that were generated in prior periods, which reflect the impact of prior period hedge gains and losses as associated physical transactions occur in the period. Additionally, the commercial activity includes operating margin generated and recognized in the current period. For the nine months ended September 30, 2015, commercial activity decreased significantly due to:


•	Lower price volatility as compared to last year due to the extreme and prolonged cold weather in 2014, and


•	Lower operating margin of $3 million resulting from the withdrawal of storage inventory hedged at the end of 2014 that was included in the storage withdrawal schedule.

While market conditions in 2014 and early 2015 experienced more natural gas price volatility, in the near term, we anticipate low volatility in certain areas of our portfolio, but expect a continuation of some volatility in the supply-constrained Northeast corridor. Over the longer term, we expect volatility to be low to moderate and locational or transportation spreads to decrease over time as new pipelines are built to reduce the bottleneck in the currently constrained shale areas of the Northeast U.S. To the extent these pipelines are delayed or not built, our expectations are that volatility would increase. Natural gas supply increases during the 2013/2014 and 2014/2015 Heating Seasons in the U.S. were not enough to meet the increased demand, resulting in storage levels that were lower than historical periods. U.S. storage levels are in the process of being restored and are relatively consistent with the historic five-year average of storage levels, but changes in storage levels could lead to higher natural gas prices in the future. Additional economic factors may contribute to this environment, including the significant drop in oil and natural gas prices, which could lead to consolidation of natural gas producers and reduced levels of natural gas

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production. Further, if economic conditions continue to improve, the demand for natural gas may increase, which may cause natural gas prices to rise and drive higher volatility in the natural gas markets on a longer-term basis.

Change in storage and transportation derivatives There was continued price volatility in 2015 benefiting wholesale services’ portfolio of pipeline transportation and storage capacity assets throughout the country, primarily in the Northeast market. Although we do not expect this high level of price volatility to continue, we see the potential for market fundamentals indicating some level of increased volatility that would continue to benefit wholesale services’ portfolio of pipeline transportation capacity should this occur. The storage derivative gains for the three and nine months ended September 30, 2015 are primarily due to a decline in natural gas prices applicable to the locations of our specific storage assets. Gains in our transportation and forward commodity derivative positions for the three months ended September 30, 2015 are primarily due to the tightening of transportation basis spreads in part driven by growing shale production and forecasts for a warmer winter. Losses in our transportation and forward commodity derivative positions for the first nine months of 2015 are the result primarily of widening transportation basis spreads associated with colder-than-normal weather in the first quarter and higher demand together with natural gas transportation constraints due to growing shale production, which impacted forward prices at natural gas receipt and delivery points, primarily in the Northeast region. These losses are temporary and more than half is expected to be recovered in 2016 and the balance thereafter with the physical flow of natural gas and utilization of the contracted transportation capacity.

Withdrawal schedule and physical transportation transactions The expected natural gas withdrawals from storage and expected offset to prior hedge losses/gains associated with the transportation portfolio of wholesale services are presented in the following table, along with the net operating revenues expected at the time of withdrawal from storage and the physical flow of natural gas between contracted transportation receipt and delivery points. Wholesale services’ expected net operating revenues exclude storage and transportation demand charges, as well as other variable fuel, withdrawal, receipt and delivery charges, but are net of the estimated impact of profit sharing under our asset management agreements. Further, the amounts that are realizable in future periods are based on the inventory withdrawal schedule, planned physical flow of natural gas between the transportation receipt and delivery points and forward natural gas prices at September 30, 2015. A portion of wholesale services’ storage inventory and transportation capacity is economically hedged with futures contracts, which results in realization of substantially fixed net operating revenues, timing notwithstanding.



	Storage withdrawal schedule
Dollars in millions	Total storage (in Bcf) (WACOG $2.48)	Expected net operating gains (losses) ⁽¹⁾			Physical transportation transactions – expected net operating gains (losses) ⁽²⁾
2015	14	$	3		$	—
2016 and thereafter	44	12			6
Total at September 30, 2015 ⁽³⁾	58	$	15		$	6
Total at December 31, 2014 ⁽³⁾	71	$	(3	)	$	(38	)
Total at September 30, 2014	56	$	18		$	37

(1) Represents expected operating gains (losses) from planned storage withdrawals associated with existing inventory positions and could change as wholesale services adjusts its daily injection and withdrawal plans in response to changes in future market conditions and forward NYMEX price fluctuations.

(2) Represents the periods associated with the transportation derivative (gains) losses during which the derivatives will be settled and the physical transportation transactions will occur that offset the derivative (gains) losses recognized in 2014 and during the first nine months of 2015.

(3) Includes 5 Bcf in storage with expected operating margin of $3 million and $2 million at September 30, 2015 and December 31, 2014, respectively, that is inaccessible due to operational issues at a third party storage facility. The owner of this facility is working to resolve these issues and the facility is expected to return to full operational performance during the fourth quarter of 2015. While we expect this inventory to be fully recovered, the timing of withdrawal of this gas may be impacted by the operational issues.

The unrealized storage and transportation derivative losses do not change the underlying economic value of our storage and transportation positions and, based on current expectations, will primarily be reversed in the remainder of 2015 and 2016 when the related transactions occur and are recognized. For more information on wholesale services’ energy marketing and risk management activities, see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” under the caption “Weather and Natural Gas Price Risks” of our 2014 Form 10-K.

Midstream Operations

Our midstream operations segment’s primary activity is operating non-utility storage and pipeline facilities, including the development and operation of high-deliverability underground natural gas storage and pipeline assets. While this business can also generate additional revenue during times of peak market demand for natural gas storage services, certain of our storage services are covered under short-, medium- and long-term contracts at fixed market rates. For the three and nine months ended September 30, 2015, midstream operations’ EBIT decreased by $12 million and $6 million, respectively, compared to the same periods during the prior year, largely due to the non-cash goodwill impairment that was recorded in the third quarter of 2015, as shown in the following table.

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In millions	Three months ended			Nine months ended
EBIT - September 30, 2014	$	(4	)	$	(14	)
Operating margin
True-up of retained fuel	2			11
Lower interruptible revenues due to optimizing facilities during the colder weather in 2014	—			(6		)
Higher sales of LNG	—			1
Increase in operating margin	2			6
Goodwill impairment	14			14
Property tax settlement, lower outside services and other costs	—			(2		)
Increase in operating expenses	14			12
EBIT - September 30, 2015	$	(16	)	$	(20	)

Liquidity and Capital Resources

Overview The acquisition of natural gas and pipeline capacity, payment of dividends and funding of working capital needs primarily related to our natural gas inventory are our most significant short-term financing requirements. The liquidity required to fund these short-term needs is primarily provided by our operating activities, and any needs not met are primarily satisfied with short-term borrowings under our commercial paper programs, which are supported by the AGL Credit Facility and the Nicor Gas Credit Facility. The need for long-term capital is driven primarily by capital expenditures and maturities of long-term debt. Periodically, we raise funds supporting our long-term cash needs from the issuance of long-term debt or equity securities. We regularly evaluate our funding strategy and capitalization profile to ensure that we have sufficient liquidity for our short-term and long-term needs in a cost-effective manner.

Our financing activities, including long-term and short-term debt and equity, are subject to customary approval or review by state and federal regulatory bodies, including the various commissions of the states in which we conduct business. Certain financing activities we undertake may also be subject to approval by state regulatory agencies. A substantial portion of our consolidated assets, earnings and cash flows is derived from the operation of our regulated utility subsidiaries, whose legal authority to pay dividends or make other distributions to us is subject to regulation. By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. Additionally, Elizabethtown Gas is restricted by their dividend policy as established by the New Jersey BPU in the amount it can dividend to AGL Resources to the extent of 70% of its quarterly net income.

We believe the amounts available to us under our long-term debt and credit facilities as well as through the issuance of debt and equity securities, combined with cash provided by operating activities, will continue to allow us to meet our needs for working capital, capital expenditures, anticipated debt redemptions, interest payments on debt obligations, dividend payments and other cash needs through the next several years.

Our ability to satisfy our working capital requirements and our debt service obligations, or fund planned capital expenditures, will substantially depend upon our future operating performance (which will be affected by prevailing economic conditions), and financial, business and other factors, some of which we are unable to control. These factors include, among others, regulatory changes, the price of and demand for natural gas, and operational risks.

Our capitalization and financing strategy is intended to ensure that we are properly capitalized with the appropriate mix of debt and equity securities. This strategy includes active management of the percentage of total debt relative to total capitalization, as well as the term and interest rate profile of our debt securities and maintenance of an appropriate mix of debt with fixed and floating interest rates. Our variable-rate debt target is 20% to 45% of total debt. As of September 30, 2015, our variable-rate debt was 27% of our total debt compared to 31% as of December 31, 2014, and 20% as of September 30, 2014. The decrease from December 31, 2014 was primarily due to decreased commercial paper borrowings resulting from the timing of customer collections for inventory recoveries.

In January 2015, we executed $800 million in notional value of 10 year and 30 year fixed-rate, forward-starting interest rate swaps to hedge potential interest rate volatility prior to anticipated issuances of senior notes in the fourth quarter of 2015 and in 2016. These debt issuances will be used to reduce our commercial paper for the amount that was borrowed to repay our senior notes that matured in January 2015 and to fund upcoming debt maturities as well as the capital expenditures associated with increased utility investment and construction of our new pipeline projects. We have designated the forward-starting interest rate swaps, which will mature on the debt issuance dates, as cash flow hedges. See Part I, Item 3, “Quantitative and Qualitative Disclosures About Market Risk,” under the caption “Interest Rate Risk” for additional information.

Our objective remains to maintain a strong balance sheet and liquidity profile, solid investment grade ratings and annual dividend growth. Additionally, 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

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agencies, acquisitions and other factors. See Item 1A, “Risk Factors,” in our 2014 Form 10-K for additional information on items that could impact our liquidity and capital resource requirements.

Capital Projects We continue to focus on capital discipline while moving forward with projects and initiatives that we expect will have current and future benefits to us and our customers, provide an appropriate return on invested capital and ensure the safety, reliability and integrity of our utility infrastructure. These capital projects update or expand our distribution systems to improve system reliability and meet operational flexibility and growth. Our anticipated expenditures for these programs in 2015 are discussed in “Liquidity and Capital Resources” under the caption "Cash Flow from Investing Activities" under Item 7 of our 2014 Form 10-K. For additional information on our capital projects, see Item 1 “Business” in our 2014 Form 10-K.

Short-Term Debt Our short-term debt table includes information relating to borrowings under our commercial paper programs and the current portion of our long-term debt. Our commercial paper borrowings are supported by the $1.3 billion AGL Credit Facility and $700 million Nicor Gas Credit Facility. The Nicor Gas Credit Facility can only be used for the working capital needs of Nicor Gas.



In millions	Period end balance outstanding⁽¹⁾		Daily average balance outstanding ⁽²⁾		Minimum balance outstanding ⁽²⁾		Largest balance outstanding ⁽²⁾
Commercial paper – AGL Capital	$	450	$	358	$	106	$	787
Commercial paper – Nicor Gas	436		299		133		585
Current portion of long-term debt	425		189		—		425
Total	$	1,311	$	846	$	239	$	1,797


(1)	As of September 30, 2015.


(2)	For the nine months ended September 30, 2015.

The largest, minimum and daily average balances borrowed under our commercial paper programs are important when assessing the intra-period fluctuations of our short-term borrowings and potential liquidity risk. The fluctuations are due to our seasonal cash requirements to fund working capital needs, in particular the purchase of natural gas inventory, margin calls and collateral posting requirements. The largest and minimum balances outstanding for each debt instrument occurred at different times during the period. Consequently, the total balances are not indicative of actual borrowings on any one day during the period.

Increasing natural gas commodity prices can significantly impact our commercial paper borrowings. Based on current natural gas prices and our expected injection plan, a $1 NYMEX price increase could result in a $29 million change of working capital requirements during the 2015 injection season. This range is sensitive to the timing of storage injections and withdrawals, collateral requirements and our portfolio position. Based upon our total debt outstanding as of September 30, 2015, and our maximum 70% debt to total capitalization allowed under our financial covenants, we could potentially borrow an additional $825 million of commercial paper under the AGL Credit Facility and an additional $264 million of commercial paper under the Nicor Gas Credit Facility. As a result, based on current natural gas prices and our expected purchases during the remainder of the injection season, we believe that we have sufficient liquidity to cover our working capital needs for the upcoming Heating Season.

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 and enhance our ability to raise additional capital on favorable terms.

Credit ratings and outlooks are opinions subject to ongoing review by the rating agencies and may periodically change. The rating agencies regularly review our performance 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 to assessing our credit ratings include our statements of financial position, leverage, capital spending, earnings, cash flow generation, available liquidity and overall business risks. We do not have any triggering events in our debt instruments that are tied to changes in our specified credit ratings or our stock price and have not entered into any agreements that would require us to issue equity based on credit ratings or other trigger events. 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.

The following table summarizes our credit ratings as of September 30, 2015, and reflects a downgrade by Moody's of AGL Capital's senior unsecured rating to Baa1 from A3 during the third quarter of 2015, which primarily reflects the predictable cash flow and stable operating profile of our natural gas distribution business. Additionally, during the third quarter of 2015 S&P

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revised both AGL Resources' and Nicor Gas' ratings outlooks to positive from stable and Fitch revised AGL Resources' outlook to positive.

AGL Resources

Nicor Gas

S&P

Moody’s ⁽¹⁾

Fitch

S&P

Moody’s

Fitch

Corporate rating

BBB+

n/a

BBB+

n/a

Commercial paper

A-2

P-2

A-2

P-1

Senior unsecured

BBB+

Baa1

BBB+

A+

Senior secured

n/a

Aa3

AA-

Ratings outlook

Positive

Stable

Positive

Stable


(1)	Credit ratings are for AGL Capital, whose obligations are fully and unconditionally guaranteed by AGL Resources.

Debt Covenants and Default Provisions We were in compliance with all of our debt provisions and covenants, both financial and non-financial, for all periods presented. For additional information on our debt covenants and default provisions, see Note 8 to our unaudited condensed consolidated financial statements under Part I, Item 1 herein.

Cash Flows The following table provides a summary of our cash flows for the periods presented.



	Nine months ended September 30,
In millions	2015			2014 ⁽¹⁾			Variance
Net cash provided by (used in):
Operating activities	$	1,410		$	874		$	536
Investing activities	(741		)	(284		)	(457		)
Financing activities	(681		)	(663		)	(18		)
Net decrease in cash and cash equivalents - continuing operations	(12		)	(50		)	38
Net decrease in cash and cash equivalents - discontinued operations	—			(23		)	23
Cash and cash equivalents at beginning of period	31			105			(74		)
Cash and cash equivalents at end of period	$	19		$	32		$	(13	)


(1)	Includes activity for discontinued operations.

Cash Flow from Operating Activities Cash provided by operating activities increased during the current period primarily due to higher working capital needs during 2014, which was driven by higher prices and volumes for natural gas and the timing of recoveries of related gas costs from customers. In addition, we received a tax refund of $150 million in January 2015 related to the extension of bonus depreciation late in 2014, which occurred after our estimated payment was made.

Cash Flow from Investing Activities The increased use of cash for our investing activities was the result of increased infrastructure investment, primarily relating to the start of Nicor Gas’ Investing in Illinois program during the nine months of 2015 combined with increased spending for other rate-based investments at distribution operations. Additionally, the variance was driven by the $225 million proceeds from the sale of Tropical Shipping during the third quarter of 2014.

Cash Flow from Financing Activities The increased use of cash for our financing activities was primarily driven by our annual dividend increase.

Contractual Obligations and Commitments We incur 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. For additional information, see Note 11 to our unaudited condensed consolidated financial statements under Part I, Item 1 herein.

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.

Our critical accounting estimates often involve complex situations that require 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

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Discussion and Analysis of Financial Condition and Results of Operations as filed on our 2014 Form 10-K. Our critical accounting estimates used in the preparation of our unaudited condensed consolidated financial statements include those related to our accounting for:


•	Rate-Regulated Subsidiaries;


•	Goodwill and Long-Lived Assets, including Intangible Assets;


•	Derivatives and Hedging Activities;


•	Contingencies;


•	Pension and Welfare Plans; and


•	Income Taxes.

Accounting Developments

See “Accounting Developments” in Note 3 to our unaudited condensed consolidated financial statements under Part I, Item 1 herein.

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 results from changes in the fair value of natural gas. Interest rate risk is caused by fluctuations in interest rates related to our portfolio of debt instruments and equity that we issue to provide financing and liquidity for our business. Credit risk results from the extension of credit throughout all aspects of our business, but is particularly concentrated in wholesale services and at Atlanta Gas Light in distribution operations. We generally use derivative instruments to manage these risks. Our use of derivative instruments is governed by a risk management policy, approved and monitored by our Risk Management Committee, which prohibits the use of derivatives for speculative purposes.

Our Risk Management Committee is responsible for establishing the overall risk management policies and monitoring compliance with, and adherence to, the terms within these policies, including approval and authorization levels and delegation of these levels. Our Risk Management Committee consists of members of senior management who monitor open natural gas price risk positions and other types of risk, corporate exposures, credit exposures and overall results of our risk management activities. It is chaired by our chief risk officer, who is responsible for ensuring that appropriate reporting mechanisms exist for the Risk Management Committee to perform its monitoring functions. Our risk management activities and related accounting treatment for our derivative instruments are described in further detail in Note 6 of our unaudited condensed consolidated financial statements under Part I, Item 1 included herein.

Natural Gas Price Risk

The following tables include the fair values and average values of our consolidated derivative instruments as of the dates indicated. We base the average values on monthly averages for the nine months ended September 30, 2015 and 2014.



	Derivative instruments average values at ⁽¹⁾
In millions	September 30, 2015		September 30, 2014
Asset	$	185	$	144
Liability	87		106

(1) Excludes cash collateral amounts.



	Derivative instruments fair values netted with cash collateral at
In millions	September 30, 2015		December 31, 2014		September 30, 2014
Asset	$	171	$	287	$	113
Liability	61		93		47

The following table illustrates the change in the net fair value of our derivative instruments during the periods presented, and provides details of the net fair value of contracts outstanding as of the dates presented.



	Three months ended September 30,						Nine months ended September 30,
In millions	2015			2014			2015			2014
Net fair value of derivative instruments outstanding at beginning of period	$	35		$	(30	)	$	61		$	(82	)
Derivative instruments realized or otherwise settled during period	21			(19		)	(17		)	24
Change in net fair value of derivative instruments	(35		)	(10		)	(23		)	(1		)
Net fair value of derivative instruments outstanding at end of period	21			(59		)	21			(59		)
Netting of cash collateral	89			125			89			125
Cash collateral and net fair value of derivative instruments outstanding at end of period (1)	$	110		$	66		$	110		$	66

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(1)	Net fair value of derivative instruments outstanding includes $6 million and $3 million premium and associated intrinsic value at September 30, 2015 and 2014, respectively, associated with weather derivatives.

The sources of our net fair value at September 30, 2015, are as follows.



In millions	Prices actively quoted (Level 1) ⁽¹⁾			Significant other observable inputs (Level 2) ⁽²⁾
Mature through 2015	$	(9	)	$	8
Mature 2016 - 2017	(6		)	29
Mature 2018 and thereafter	(2		)	1
Total derivative instruments ⁽³⁾	$	(17	)	$	38


(1)	Valued using NYMEX futures prices.


(2)	Valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers.


(3)	Excludes cash collateral amounts.

VaR VaR is the maximum potential loss in portfolio value over a specified time-period that is not expected to be exceeded within a given degree of probability. Our VaR may not be comparable to that of other entities due to differences in the factors used to calculate VaR. Our VaR is determined on a 95% confidence interval and a 1-day holding period, which means that 95% of the time, the risk of loss in a day from a portfolio of positions is expected to be less than or equal to the amount of VaR calculated. Our open exposure is managed in accordance with established policies that limit market risk and require daily reporting of potential financial exposure to senior management, including the chief risk officer. Because we generally manage physical gas assets and economically protect our positions by hedging in the futures markets, our open exposure is generally mitigated. We employ daily risk testing, using both VaR and stress testing, to evaluate the risks of our open positions.

Natural gas markets experienced unprecedented levels of high volatility and prices due to the extended extreme cold weather during 2014, resulting in our VaR to be at elevated levels during the prior year period. We actively managed and monitored the open positions and exposures that were driving the elevated VaR levels to not only remain in compliance with established policies, but also to mitigate the operational risks of not being able to meet customer needs under these extreme conditions. As conditions moderated at the end of the first quarter of 2014, our period-end VaR was consistent with historical periods. We actively monitor open commodity positions and the resulting VaR. We also continue to maintain a relatively matched book, where our total buy volume is close to our sell volume, with minimal open natural gas price risk. Based on a 95% confidence interval and employing a 1-day holding period, SouthStar’s portfolio of positions for the nine months ended September 30, 2015 and 2014 were less than $0.1 million and wholesale services had the following VaRs.



	Three months ended September 30,				Nine months ended September 30,
In millions	2015		2014		2015		2014
Period end	$	2.0	$	7.2	$	2.0	$	7.2
Average	2.6		3.1		3.4		4.1
High	3.9		8.0		7.3		19.7
Low	1.8		1.8		1.8		1.8

Interest Rate Risk

Interest rate fluctuations expose our variable-rate debt to changes in interest expense and cash flows. Our policy is to manage interest expense using a combination of fixed-rate and variable-rate debt. Based on $1.2 billion of variable-rate debt outstanding at September 30, 2015, a 100 basis point change in market interest rates would have resulted in an increase in pre-tax interest expense of $12 million on an annualized basis.

We utilize interest rate swaps to help us achieve our desired mix of variable to fixed-rate debt. Our variable-rate debt target generally ranges from 20% to 45% of total debt. We also use forward-starting interest rate swaps and interest rate lock agreements to lock in fixed interest rates on our forecasted issuances of debt. The objective of these hedges is to offset the variability of future payments associated with the interest rate on debt instruments we expect to issue. The gain or loss on the interest rate swaps designated as cash flow hedges is generally deferred in accumulated OCI until settlement, at which point it is amortized to interest expense over the life of the related debt. For additional information, see Note 6 to our unaudited condensed consolidated financial statements included under Part 1, Item 1 herein.

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Credit Risk

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

Additionally, we may require counterparties to pledge additional collateral when deemed necessary. We conduct credit evaluations and obtain appropriate internal approvals for a counterparty’s line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody’s and BBB- from S&P. Generally, we require credit enhancements by way of guaranty, cash deposit or letter of credit for transaction counterparties that do not have investment grade ratings.

We have a concentration of credit risk as measured by our 30-day receivable exposure plus forward exposure. As of September 30, 2015, our top 20 counterparties represented 51% of the total counterparty exposure of $373 million, excluding $12 million of customer deposits.

As of September 30, 2015, our counterparties or the counterparties’ guarantors had a weighted average S&P equivalent credit rating of A-, which is consistent with the prior year. The S&P equivalent credit rating is determined by a process of converting the lower of the S&P or Moody’s ratings to an internal rating ranging from 9 to 1, with 9 being equivalent to AAA/Aaa by S&P and Moody’s, respectively, and 1 being D or Default by S&P and Moody’s, respectively. A counterparty that does not have an external rating is assigned an internal rating based on the strength of the financial ratios of that counterparty. To arrive at the weighted average credit rating, each counterparty is assigned an internal ratio, which is multiplied by their credit exposure and summed for all counterparties. The sum is divided by the aggregate total counterparties’ exposures, and this numeric value is then converted to an S&P equivalent. The following table shows our third-party natural gas contracts receivable and payable positions as of the periods presented.



	Gross receivables						Gross payables
	Sep. 30,		Dec. 31,		Sep. 30,		Sep. 30,		Dec. 31,		Sep. 30,
In millions	2015		2014		2014		2015		2014		2014
Netting agreements in place:
Counterparty is investment grade	$	336	$	482	$	308	$	162	$	276	$	192
Counterparty is non-investment grade	10		4		6		9		7		8
Counterparty has no external rating	125		263		207		331		494		383
No netting agreements in place:
Counterparty is investment grade	4		30		13		—		—		1
Counterparty has no external rating	—		—		10		—		—		28
Amount recorded on unaudited Condensed Consolidated Statements of Financial Position	$	475	$	779	$	544	$	502	$	777	$	612

We have certain trade and credit contracts that have explicit minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, we would need to post collateral to continue transacting business with some of our counterparties. If such collateral were not posted, our ability to continue transacting business with these counterparties would be impaired. If our credit ratings had been downgraded to non-investment grade status, the required amounts to satisfy potential collateral demands under such agreements with our counterparties would have totaled $5 million at September 30, 2015, which would not have had a material impact on our consolidated results of operations, cash flows or financial condition.

There have been no significant changes to our credit risk related to any of our segments other than wholesale services, as described in Item 7A ”Quantitative and Qualitative Disclosures about Market Risk” of our 2014 Form 10-K.

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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 the effectiveness 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 September 30, 2015, 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 September 30, 2015. Our disclosure controls and procedures are designed to ensure 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 and that such information 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 September 30, 2015 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 various state and federal authorities. In addition, we are party as both plaintiff and defendant to a number of lawsuits related to our business on an ongoing basis. Management believes that the outcome of all regulatory proceedings and litigation in which we are currently involved will not have a material adverse effect on our consolidated financial condition or results of operations. For more information regarding our regulatory proceedings and litigation, see Note 11 to our unaudited condensed consolidated financial statements under Part I, Item 1 herein 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 2014 Form 10-K. These risk factors could materially affect our business, financial condition or future results. Other than the merger-related risk factors noted below, there have been no significant changes to our risk factors included in Item 1A of our 2014 Form 10-K. The risks described in the referenced document and below are not the only risks facing the company. Additional risks and uncertainties not currently known to us or that we currently do not recognize as material may also materially adversely affect our business, financial condition or future results.

Risk Factors Related to the Merger Agreement

The merger is subject to receipt of consent or approval from our shareholders and various governmental entities that could delay or prevent the completion of the merger or, in order to receive such consent or approval, the governmental entities may impose restrictions or conditions that could have a material adverse effect on the combined company or that could cause abandonment of the transaction.

Completion of the merger is contingent upon, among other things, satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger Agreement by the holders of a majority of the outstanding shares of our common stock, (ii) the receipt of required regulatory approvals, including expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Act and approvals from the Federal Communications Commission, California Public Utilities Commission, Georgia Commission, Illinois Commission, Maryland Commission, New Jersey BPU and Virginia Commission, and such approvals having become final orders and (iii) the absence of a judgment, order, decision, injunction, ruling or other finding or agency requirement of a governmental entity prohibiting the consummation of the merger.

We may not receive the required statutory approvals and other clearances for the merger, or we may not receive them in a timely manner. If such approvals and clearances are received, they may impose terms, conditions or restrictions (i) that cause a failure of the closing conditions set forth in the Merger Agreement, which could permit us or Southern Company to terminate the Merger Agreement and abandon the transaction or (ii) that could reasonably be expected to have a detrimental impact on the combined company following completion of the merger. A substantial delay in obtaining the required authorizations, approvals or consents or the imposition of unfavorable terms, conditions or restrictions contained in such authorizations, approvals or consents could prevent the completion of the merger or have an adverse effect on the anticipated benefits of the merger, thereby impacting the business, financial condition or results of operations of the combined company.

Even after the expiration of the waiting period under the Hart-Scott-Rodino Act, governmental authorities could seek to block or challenge the merger as they deem necessary or desirable in the public interest.

Failure to complete the merger could adversely affect our stock price and future business operations and financial results.

Completion of the merger is subject to risks, including the risks that approval of the transaction by our shareholders or by governmental agencies will not be obtained or that certain other closing conditions will not be satisfied. If we are unable to complete the merger, our ongoing business may be adversely affected and we would be subject to a number of risks, including the following:


•	we will have paid certain significant transaction costs, including legal, financial advisory and filing, printing and mailing fees, and in certain circumstances, a termination fee to Southern Company of $201 million;


•	the attention of our management may have been diverted to the merger rather than to our operations and the pursuit of other opportunities that could have been beneficial to us;


•	the potential loss of key personnel during the pendency of the merger as employees may experience uncertainty about their future roles with the combined company;


•	we will have been subject to certain restrictions on the conduct of our business, which may prevent us from making certain acquisitions or dispositions or pursuing certain business opportunities while the merger is pending; and


•	the trading price of our common stock may decline to the extent that the current market price reflects a market assumption that the merger will be completed.

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A failure to complete the merger may also result in negative publicity, additional litigation against the company or its directors and officers, and a negative impression of the company in the investment community. The occurrence of any of these events individually or in combination could have a material adverse effect on our results of operations or the trading price of our common stock.

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

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

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

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

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

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

The company and each member of the Board have been named as defendants in four purported shareholder class action lawsuits filed in the United States District Court for the Northern District of Georgia, Atlanta Division, which we refer to as the “Court”: Patrick Baker v. AGL Resources Inc., et al., which we refer to as the “Baker Action”, Jeff Morton v. AGL Resources Inc., et al., which we refer to as the “Morton Action”, Sarah Halberstam and Baruch Z. Halberstam (as custodian for Benjamin Halberstam) v. AGL Resources Inc., et al., which we refer to as the “Halberstam Action”, and Manuel Abt v. AGL Resources, Inc., et al., which we refer to as the “Abt Action”, filed on September 16, 2015, September 22, 2015, September 28, 2015 and October 9, 2015, respectively. Southern Company and Merger Sub were also named as defendants in the Baker Action and the Morton Action. We refer to the Baker Action, the Morton Action, the Halberstam Action and the Abt Action, collectively, as the “Actions”. The Actions allege that our preliminary proxy statement contains false and misleading statements and omits material information in violation of certain provisions under the Exchange Act. The Actions also allege that the members of the Board are liable for those alleged misstatements and omissions. The Morton Action further alleges that the members of the Board breached their fiduciary duties owed to the shareholders of the company in connection with the merger and that Southern Company and Merger Sub aided and abetted such breaches. The Actions seek, among other things, preliminary and permanent injunctive relief enjoining the merger, rescission or rescissory damages in the event the merger is implemented and an award of attorneys’ and experts’ fees and costs. On October 23, 2015, the Court consolidated the four actions, which we refer to as the “Consolidated Action.” On October 26, 2015, plaintiff Baker filed an Emergency Motion to Expedite Proceedings, which the Court denied on November 4, 2015. The plaintiffs filed a consolidated and amended complaint on November 4, 2015. These lawsuits could result in such an injunction being issued which could prevent or delay the closing of the Merger Agreement or otherwise adversely impact our business and operations, but the Company and the Board believe that the claims in the Consolidated Action are without merit, and intend to vigorously defend the Consolidated Action.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

There were no purchases of our common stock by us or any affiliated purchasers during the third quarter of 2015, and no unregistered sales of equity securities were made during this period.

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Item 6. Exhibits.



Exhibit Number	Description of Exhibit	Filer	The Filings Referenced for Incorporation by Reference
2.1	Agreement and Plan of Merger, dated as of August 23, 2015	AGL Resources	August 24, 2015 Form 8-K, Exhibit 2.1
10.1	Second Amendment and Extension Agreement, dated as of October 30, 2015	AGL Resources	November 5, 2015 Form 8-K, Exhibit 10.1
10.2	Second Amendment and Extension Agreement, dated as of October 30, 2015	AGL Resources	November 5, 2015 Form 8-K, Exhibit 10.2
10.3	First Amendment to Bank Rate Mode Covenants Agreement, dated as of October 30, 2015	AGL Resources	November 5, 2015 Form 8-K, Exhibit 10.3
12	Computation of Ratio of Earnings to Fixed Charges	AGL Resources	Filed herewith
31.1	Certification of John W. Somerhalder II	AGL Resources	Filed herewith
31.2	Certification of Elizabeth W. Reese	AGL Resources	Filed herewith
32.1	Certification of John W. Somerhalder II	AGL Resources	Filed herewith
32.2	Certification of Elizabeth W. Reese	AGL Resources	Filed herewith
101.INS	XBRL Instance Document	AGL Resources	Filed herewith
101.SCH	XBRL Taxonomy Extension Schema	AGL Resources	Filed herewith
101.CAL	XBRL Taxonomy Extension Calculation Linkbase	AGL Resources	Filed herewith
101.DEF	XBRL Taxonomy Definition Linkbase	AGL Resources	Filed herewith
101.LAB	XBRL Taxonomy Extension Labels Linkbase	AGL Resources	Filed herewith
101.PRE	XBRL Taxonomy Extension Presentation Linkbase	AGL Resources	Filed herewith

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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.



	AGL RESOURCES INC.
	(Registrant)

Date:	November 9, 2015	/s/ Elizabeth W. Reese
		Elizabeth W. Reese
		Executive Vice President and Chief Financial Officer

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