SOUTHERN Co GAS - FORM 10-Q - November 9, 2015

Attached files

file	filename
EX-31.1 - EXHIBIT 31.1 - SOUTHERN Co GAS	q32015ex311.htm
EX-31.2 - EXHIBIT 31.2 - SOUTHERN Co GAS	q32015ex312.htm
EX-12 - EXHIBIT 12 - SOUTHERN Co GAS	q32015ex12.htm
EX-32.2 - EXHIBIT 32.2 - SOUTHERN Co GAS	q32015ex322.htm
EX-32.1 - EXHIBIT 32.1 - SOUTHERN Co GAS	q32015ex321.htm

Table of Contents




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).

Glossary of Key Terms

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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).

Glossary of Key Terms

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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