Edgar Filing: AGL RESOURCES INC

forrm_10-q.htm

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 June 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 July 23, 2015, was 120,087,776.

Glossary of Key Terms

Table of Contents

AGL RESOURCES INC.

Quarterly Report on Form 10-Q

For the Quarter Ended June 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 - Significant Accounting Policies and Methods of Application		9
			Note 3 - Regulated Operations		13
			Note 4 - Fair Value Measurements		14
			Note 5 - Derivative Instruments		15
			Note 6 - Employee Benefit Plans		16
			Note 7 - Debt and Credit Facilities		17
			Note 8 - Equity		18
			Note 9 - Non-Wholly Owned Entities		19
			Note 10 - Commitments, Guarantees and Contingencies		21
			Note 11 - Segment Information		23
			Note 12 - Discontinued Operations		25
	2		Management’s Discussion and Analysis of Financial Condition and Results of Operations		26
			Forward-Looking Statements		26
			Executive Summary		26
			Results of Operations		28
			Liquidity and Capital Resources		34
			Critical Accounting Policies and Estimates		37
			Accounting Developments		37
	3		Quantitative and Qualitative Disclosures About Market Risk		37
	4		Controls and Procedures		40
			PART II - OTHER INFORMATION

	1		Legal Proceedings		40
	1	A	Risk Factors		40
	2		Unregistered Sales of Equity Securities and Use of Proceeds		40
	6		Exhibits		40

			SIGNATURE		41

Glossary of Key Terms

Table of Contents

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
2014 Form 10-Q/A	Our Quarterly Report on Form 10-Q/A for the period ended June 30, 2014, filed with the SEC on November 26, 2014
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 financing costs, including 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 the effects of weather on our businesses, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
Heating Season	The period from November through March when natural gas usage and operating revenues are generally higher
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
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.
S&P	Standard & Poor’s Ratings Services
SEC	Securities and Exchange Commission
Sequent	Sequent Energy Management, L.P.
SouthStar	SouthStar Energy Services, LLC
Triton	Triton Container Investments, LLC
Tropical Shipping	Tropical Shipping and Construction Company Limited
U.S.	United States
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

Table of Contents

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
	June 30,			December 31,			June 30,
In millions, except share amounts	2015			2014			2014
Current assets
Cash and cash equivalents	$	25		$	31		$	122
Receivables
Natural gas, unbilled revenues and other		445			797			520
Energy marketing		430			779			677
Less allowance for uncollectible accounts		46			35			51
Total receivables, net		829			1,541			1,146
Inventories
Natural gas		395			694			441
Other		26			22			19
Total inventories		421			716			460
Derivative instruments		158			245			105
Prepaid expenses		51			223			67
Regulatory assets		48			83			165
Assets held for sale		-			-			257
Other		40			47			58
Total current assets		1,572			2,886			2,380
Long-term assets and other deferred debits
Property, plant and equipment		11,903			11,552			11,188
Less accumulated depreciation		2,524			2,462			2,400
Property, plant and equipment, net		9,379			9,090			8,788
Goodwill		1,827			1,827			1,827
Regulatory assets		642			631			726
Intangible assets		112			125			135
Other		303			329			303
Total long-term assets and other deferred debits		12,263			12,002			11,779
Total assets	$	13,835		$	14,888		$	14,159
Current liabilities
Short-term debt	$	459		$	1,175		$	448
Energy marketing trade payables		455			777			724
Other accounts payable – trade		272			312			319
Accrued expenses		183			229			213
Regulatory liabilities		154			112			149
Current portion of long-term debt		125			200			200
Customer deposits and credit balances		115			125			107
Accrued environmental remediation liabilities		83			87			90
Derivative instruments		43			88			50
Temporary LIFO liquidation		38			-			116
Liabilities held for sale		-			-			39
Other		120			114			140
Total current liabilities		2,047			3,219			2,595
Long-term liabilities and other deferred credits
Long-term debt		3,452			3,581			3,585
Accumulated deferred income taxes		1,780			1,724			1,675
Regulatory liabilities		1,622			1,601			1,565
Accrued pension and retiree welfare benefits		526			525			405
Accrued environmental remediation liabilities		346			327			379
Other		73			83			95
Total long-term liabilities and other deferred credits		7,799			7,841			7,704
Total liabilities and other deferred credits		9,846			11,060			10,299
Commitments, guarantees and contingencies (see Note 10)
Equity
Common stock, $5 par value; 750,000,000 shares authorized; outstanding: 120,081,995 shares at June 30, 2015, 119,647,149 shares at December 31, 2014, and 119,464,063 shares at June 30, 2014		601			599			598
Additional paid-in capital		2,099			2,087			2,073
Retained earnings		1,425			1,312			1,288
Accumulated other comprehensive loss		(169	)		(206	)		(133	)
Treasury shares, at cost: 216,523 shares at June 30, 2015, December 31, 2014, and June 30, 2014		(8	)		(8	)		(8	)
Total common shareholders’ equity		3,948			3,784			3,818
Noncontrolling interest		41			44			42
Total equity		3,989			3,828			3,860
Total liabilities and equity	$	13,835		$	14,888		$	14,159
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						Six months ended
	June 30,						June 30,
In millions, except per share amounts	2015			2014			2015			2014
Operating revenues (includes revenue taxes of $18 and $74 for the three and six months in 2015 and $26 and $94 for the three and six months in 2014)	$	674		$	889		$	2,395		$	3,351
Operating expenses
Cost of goods sold		222			402			1,157			1,802
Operation and maintenance		209			211			458			500
Depreciation and amortization		98			95			195			188
Taxes other than income taxes		38			42			114			130
Total operating expenses		567			750			1,924			2,620
Operating income		107			139			471			731
Other income		4			2			7			5
Interest expense, net		(42	)		(45	)		(86	)		(91	)
Income before income taxes		69			96			392			645
Income tax expense		25			37			143			240
Income from continuing operations		44			59			249			405
Income (loss) from discontinued operations, net of tax		-			1			-			(49	)
Net income		44			60			249			356
Less net income attributable to noncontrolling interest		2			2			14			14
Net income attributable to AGL Resources Inc.	$	42		$	58		$	235		$	342

Net income attributable to AGL Resources Inc.
Income from continuing operations	$	42		$	57		$	235		$	391
Income (loss) from discontinued operations, net of tax		-			1			-			(49	)
Net income attributable to AGL Resources Inc.	$	42		$	58		$	235		$	342

Per common share information
Basic earnings (loss) per common share
Continuing operations	$	0.35		$	0.48		$	1.97		$	3.30
Discontinued operations		-			0.01			-			(0.42	)
Basic earnings per common share attributable to AGL Resources Inc.	$	0.35		$	0.49		$	1.97		$	2.88
Diluted earnings (loss) per common share
Continuing operations	$	0.35		$	0.48		$	1.96		$	3.29
Discontinued operations		-			0.01			-			(0.42	)
Diluted earnings per common share attributable to AGL Resources Inc.	$	0.35		$	0.49		$	1.96		$	2.87
Cash dividends declared per common share	$	0.51		$	0.49		$	1.02		$	0.98
Weighted average number of common shares outstanding
Basic		119.5			118.8			119.4			118.7
Diluted		119.8			119.2			119.7			119.1

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					Six months ended
	June 30,					June 30,
In millions	2015		2014			2015		2014
Net income	$	44	$	60		$	249	$	356
Other comprehensive income (loss), net of tax
Retirement benefit plans
Reclassification of actuarial losses to net benefit cost (net of income tax of $2 and $4 for the three and six months ended June 30, 2015, and $2 and $3 for the three and six months ended June 30, 2014)		4		4			7		5
Reclassification of prior service credits to net benefit cost		-		(1	)		-		(1	)
Retirement benefit plans, net		4		3			7		4
Cash flow hedges, net of tax
Net derivative instruments gain arising during the period (net of income tax of $16 and $17 for the three and six months ended June 30, 2015)		25		-			27		4
Reclassification of realized derivative instruments (gain) loss to net income (net of income tax of $(1) for the three and six months ended June 30, 2014)		4		(1	)		4		(5	)
Cash flow hedges, net		29		(1	)		31		(1	)
Other comprehensive income, net of tax		33		2			38		3
Comprehensive income		77		62			287		359
Less comprehensive income attributable to noncontrolling interest		3		2			15		14
Comprehensive income attributable to AGL Resources Inc.	$	74	$	60		$	272	$	345

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 Inc. Shareholders
	Common stock				Additional			Retained			Accumulated other			Treasury			Noncontrolling
In millions, except per share amounts	Shares		Amount		paid-in capital			earnings			comprehensive loss			shares			interest			Total
Balance as of December 31, 2013		118.9	$	595	$	2,054		$	1,063		$	(136	)	$	(8	)	$	45		$	3,613
Net income		-		-		-			342			-			-			14			356
Other comprehensive income		-		-		-			-			3			-			-			3
Dividends on common stock ($0.98 per share)		-		-		-			(117	)		-			-			-			(117	)
Distribution to noncontrolling interest		-		-		-			-			-			-			(17	)		(17	)
Stock granted, share-based compensation, net of forfeitures		-		-		(12	)		-			-			-			-			(12	)
Stock issued, dividend reinvestment plan		-		-		6			-			-			-			-			6
Stock issued, share-based compensation, net of forfeitures		0.6		3		17			-			-			-			-			20
Stock-based compensation expense, net of tax		-		-		8			-			-			-			-			8
Balance as of June 30, 2014		119.5	$	598	$	2,073		$	1,288		$	(133	)	$	(8	)	$	42		$	3,860

	AGL Resources Inc. Shareholders
	Common stock				Additional			Retained			Accumulated other			Treasury			Noncontrolling
In millions, except per share amounts	Shares		Amount		paid-in capital			earnings			comprehensive loss			shares			interest			Total
Balance as of December 31, 2014		119.6	$	599	$	2,087		$	1,312		$	(206	)	$	(8	)	$	44		$	3,828
Net income		-		-		-			235			-			-			14			249
Other comprehensive income		-		-		-			-			37			-			1			38
Dividends on common stock ($1.02 per share)		-		-		-			(122	)		-			-			-			(122	)
Distribution to noncontrolling interest		-		-		-			-			-			-			(18	)		(18	)
Stock granted, share-based compensation, net of forfeitures		-		-		(13	)		-			-			-			-			(13	)
Stock issued, dividend reinvestment plan		0.1		1		5			-			-			-			-			6
Stock issued, share-based compensation, net of forfeitures		0.4		1		14			-			-			-			-			15
Stock-based compensation expense, net of tax		-		-		6			-			-			-			-			6
Balance as of June 30, 2015		120.1	$	601	$	2,099		$	1,425		$	(169	)	$	(8	)	$	41		$	3,989

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)

	Six months ended
	June 30,
In millions	2015			2014
Cash flows from operating activities
Net income	$	249		$	356
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization		195			188
Change in derivative instrument assets and liabilities		42			(13	)
Deferred income taxes		27			13
Loss from discontinued operations, net of tax		-			49
Changes in certain assets and liabilities
Receivables, other than energy marketing		363			238
Inventories, net of temporary LIFO liquidation		333			314
Prepaid and miscellaneous taxes		150			(12	)
Accrued/deferred natural gas costs		43			(129	)
Energy marketing receivables and trade payables, net		27			162
Accrued expenses		(28	)		11
Trade payables, other than energy marketing		(41	)		(61	)
Other, net		125			55
Net cash flow provided by operating activities of discontinued operations		-			4
Net cash flow provided by operating activities		1,485			1,175
Cash flows from investing activities
Expenditures for property, plant and equipment		(452	)		(332	)
Net decrease in short-term investments		-			41
Other, net		5			4
Net cash flow used in investing activities of discontinued operations		-			(13	)
Net cash flow used in investing activities		(447	)		(300	)
Cash flows from financing activities
Net repayments of commercial paper		(716	)		(723	)
Payment of senior notes		(200	)		-
Dividends paid on common shares		(122	)		(117	)
Distribution to noncontrolling interest		(18	)		(17	)
Other, net		12			14
Net cash flow used in financing activities		(1,044	)		(843	)
Net (decrease) increase in cash and cash equivalents – continuing operations		(6	)		41
Net decrease in cash and cash equivalents – discontinued operations		-			(9	)
Cash and cash equivalents (including held for sale) at beginning of period		31			105
Cash and cash equivalents (including held for sale) at end of period		25			137
Less cash and cash equivalents held for sale at end of period		-			15
Cash and cash equivalents (excluding held for sale) at end of period	$	25		$	122
Cash paid (received) during the period for
Interest	$	93		$	95
Income taxes		(57	)		207

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 Statements of Financial Position as of December 31, 2014 were 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, the accounts of our majority owned or otherwise controlled subsidiaries and the accounts of our VIE, SouthStar, 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 the unaudited Condensed Consolidated Statements of Income. See Note 9 for additional information. 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 November 2014, we filed a Form 10-Q/A to revise our June 30, 2014 financial statements and other affected disclosures for items related to the recognition of revenues for certain of our regulatory infrastructure programs and the amortization of our intangible assets as originally filed in our Form 10-Q for the period ended June 30, 2014. Our financial statements for the period ended June 30, 2014, reflect the revised amounts reported in our 2014 Form 10-Q/A.

In September 2014, we closed on the sale of Tropical Shipping, which operated within our former cargo shipping segment. The assets and liabilities of these businesses as of June 30, 2014 are classified as held for sale on the unaudited Condensed Consolidated Statements of Financial Position, and the financial results of these businesses for the three and six months ended June 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 assets held for sale and discontinued operations. Cargo shipping 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 12 for additional information on the sale of Tropical Shipping.

Note 2 - Significant Accounting Policies and Methods of Application

Our accounting policies are described in Note 2 to our consolidated financial statements and related notes included in Item 8 of our 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.

Cash and Cash Equivalents

Our cash and cash equivalents primarily consist of cash on deposit, money market accounts and certificates of deposit held by domestic subsidiaries with original maturities of three months or less. As of June 30, 2014, there was $15 million of cash and cash equivalents held by Tropical Shipping that was excluded from cash and cash equivalents within our unaudited Condensed Consolidated Statements of Financial Position and included in assets held for sale. For more information on the sale of Tropical Shipping, see Note 12.

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Energy Marketing Receivables and Payables

Our wholesale services segment provides services to retail and wholesale marketers and utility and industrial customers. These customers, also known as counterparties, utilize netting agreements that enable our wholesale services segment to net receivables and payables by counterparty upon settlement. Wholesale services also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, wholesale services’ counterparties are settled net, they are recorded on a gross basis in our unaudited Condensed Consolidated Statements of Financial Position as energy marketing receivables and energy marketing trade payables.

Wholesale services has trade and credit contracts that contain 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, wholesale services would need to post collateral to continue transacting business with some of its counterparties. To date, our credit ratings have exceeded the minimum requirements. As of June 30, 2015 and 2014, and December 31, 2014, the collateral that wholesale services would have been required to post if our credit ratings had been downgraded to non-investment grade status would not have had a material impact to our consolidated results of operations, cash flows or financial condition. If such collateral were not posted, wholesale services’ ability to continue transacting business with these counterparties would be negatively impacted.

Inventories

For our regulated utilities, except Nicor Gas, our natural gas inventories and the inventories we hold for Marketers in Georgia are carried at cost on a WACOG basis. In Georgia’s competitive environment, Marketers sell natural gas to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation and provides this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. On a monthly basis, Atlanta Gas Light assigns the majority of the pipeline storage services that it has under contract to Marketers, along with a corresponding amount of inventory. Atlanta Gas Light also retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand. See Note 10 for information regarding an approved regulatory filing to resolve a natural gas inventory imbalance at Atlanta Gas Light.

Nicor Gas’ inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are expected to be restored prior to year-end are charged to cost of goods sold at the estimated annual replacement cost, and the difference between this cost and the actual liquidated LIFO layer cost is recorded as a temporary LIFO inventory liquidation. Any temporary LIFO liquidation is included as a current liability in our unaudited Condensed Consolidated Statements of Financial Position. Interim inventory decrements that are not expected to be restored prior to year-end are charged to cost of goods sold at the actual LIFO cost of the layers liquidated. The inventory decrement as of June 30, 2015 is expected to be restored prior to year-end and the inventory decrement as of June 30, 2014 was restored prior to December 31, 2014.

Our retail operations, wholesale services and midstream operations segments carry inventory at LOCOM, where cost is determined on a WACOG basis. For these segments, we evaluate the weighted average cost of their natural gas inventories against market prices to determine whether any declines in market prices below the WACOG are other than temporary. For any declines considered to be other than temporary, we record pre-tax adjustments to our unaudited Condensed Consolidated Statements of Income to reduce the weighted average cost of the natural gas inventory to market value. 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 June 30,				Six months ended June 30,
In millions	2015		2014		2015		2014
LOCOM adjustments	$	-	$	4	$	10	$	6

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 in the second half of 2015, and to be fully recovered, the timing of withdrawal of this gas may be impacted by operational issues.

Regulated Operations

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

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Goodwill

We perform an annual impairment test on our reporting units that contain goodwill during the fourth quarter of each year, or more frequently if impairment indicators arise. There were no triggering events during the current period that would require us to perform an interim goodwill impairment test. The amounts of goodwill as of June 30, 2015 and 2014, and December 31, 2014 are provided below.

In millions		Distribution operations				Retail operations				Midstream operations				Consolidated
Goodwill		$	1,640			$	173			$	14			$	1,827

Earnings Per Common Share

We compute basic earnings per common share attributable to AGL Resources Inc. by dividing our net income attributable to the common shareholders of AGL Resources Inc. by the daily weighted average number of common shares outstanding. Diluted earnings per common share attributable to AGL Resources Inc. reflect the potential reduction in earnings per common share attributable to AGL Resources Inc. that occurs when the exercise and/or conversion of all potentially dilutive common shares is added to the common shares outstanding.

We derive our potentially dilutive common shares by calculating the number of shares issuable under restricted stock, restricted stock units and stock options award programs. The vesting of certain shares of the restricted stock and restricted stock units depends on the satisfaction of defined performance and/or time-based criteria. The future issuance of shares underlying the outstanding stock options depends on whether the market price of the common shares underlying the options exceeds the respective exercise prices of the stock options. The following table shows the calculation of our diluted shares attributable to AGL Resources Inc. 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 June 30,				Six months ended June 30,
In millions (except per share amounts)	2015		2014		2015		2014
Income from continuing operations attributable to AGL Resources Inc.	$	42	$	57	$	235	$	391
Income (loss) from discontinued operations, net of tax		-		1		-		(49	)
Net income attributable to AGL Resources Inc.	$	42	$	58	$	235	$	342
Denominator:
Basic weighted average number of shares outstanding (1)		119.5		118.8		119.4		118.7
Effect of dilutive securities		0.3		0.4		0.3		0.4
Diluted weighted average number of shares outstanding (2)		119.8		119.2		119.7		119.1

Basic earnings (loss) per share
Continuing operations	$	0.35	$	0.48	$	1.97	$	3.30
Discontinued operations		-		0.01		-		(0.42	)
Basic earnings per share attributable to AGL Resources Inc.	$	0.35	$	0.49	$	1.97	$	2.88
Diluted earnings (loss) per share
Continuing operations	$	0.35	$	0.48	$	1.96	$	3.29
Discontinued operations		-		0.01		-		(0.42	)
Diluted earnings per share attributable to AGL Resources Inc.	$	0.35	$	0.49	$	1.96	$	2.87

(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.

Fair Value Measurements

We have financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value include cash and cash equivalents, and derivative assets and liabilities. The carrying values of receivables, short- and long-term investments, accounts payable, short-term debt, other current assets and liabilities, and accrued interest approximate fair value. Our nonfinancial assets and liabilities include pension and other retirement benefits, which are presented in Note 4 to our consolidated financial statements and in related notes included in Item 8 of our 2014 Form 10-K.

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

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Derivative Instruments

The fair values of the natural gas and certain weather derivative instruments that we use to manage exposures arising from changing natural gas prices and weather risk reflect the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. 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 time it is amortized to interest expense over the life of the related debt. We use external market quotes and indices to value substantially all of our derivative instruments. See Note 4 and Note 5 for additional derivative disclosures.

Subsequent Events

Except as disclosed in Note 3 related to the July 20, 2015 receipt of the second installment of the insurance settlement associated with environmental claims at certain MGP sites, in Note 10 concerning the Administrative Law Judge’s proposed order on the 2003 gas cost prudence review at Nicor Gas and below in Accounting Developments, no events occurred subsequent to the balance sheet date that would require recognition or disclosure in the financial statements.

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 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. 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 did not have a material impact on our unaudited condensed consolidated financial statements. See Note 7 for additional information on the impact of adopting this accounting standard.

Other newly issued accounting standards

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. 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 may elect to apply the new guidance either retrospectively to each prior period presented or via a cumulative effect adjustment 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 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 light of the new guidance.

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 3 - Regulated Operations

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	June 30, 2015		December 31, 2014		June 30, 2014
Regulatory assets
Recoverable ERC	$	27	$	49	$	33
Recoverable pension and retiree welfare benefit costs		11		12		9
Deferred natural gas costs		-		3		79
Other		10		19		44
Regulatory assets – current		48		83		165
Recoverable ERC		350		329		458
Recoverable pension and retiree welfare benefit costs		105		110		94
Recoverable regulatory infrastructure program costs		77		69		65
Long-term debt fair value adjustment		70		74		78
Other		40		49		31
Regulatory assets – long-term		642		631		726
Total regulatory assets	$	690	$	714	$	891
Regulatory liabilities
Accrued natural gas costs	$	67	$	27	$	41
Bad debt over collection		27		33		39
Accumulated removal costs		25		25		27
Deferred seasonal rates		8		-		8
Other		27		27		34
Regulatory liabilities – current		154		112		149
Accumulated removal costs		1,544		1,520		1,478
Regulatory income tax liability		27		34		27
Unamortized investment tax credit		21		22		24
Bad debt over collection		18		12		9
Other		12		13		27
Regulatory liabilities – long-term		1,622		1,601		1,565
Total regulatory liabilities	$	1,776	$	1,713	$	1,714

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 in 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
June 30, 2015	$	126	$	11	$	3	$	1	$	141
December 31, 2014		113		12		2		-		127
June 30, 2014		96		12		1		-		109

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. Deferred natural gas costs are reflected as regulatory assets and accrued natural gas costs are reflected as regulatory liabilities.

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 our 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.

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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 a corresponding regulatory asset 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 $27 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 June 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	$	37	$	242	$	37	As incurred
New Jersey		6		105 - 177		13		118		9	7 years
Georgia and Florida		13		34 - 58		25		59		29	5 years
North Carolina (2)		1		n/a		10		10		8	No recovery
Total		46	$	344 - $698	$	85	$	429	$	83

(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 of our 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 the $45 million installment in the third quarter of 2014 and this payment was primarily recorded as a reduction to our recoverable ERC regulatory asset. The remaining $32 million was paid to us in July 2015, and as of June 30, 2015, this amount was recorded as a receivable in our unaudited Condensed Consolidated Statements of Financial Position. We will file for approval with the New Jersey BPU to utilize the insurance proceeds related to the New Jersey sites to reduce the ERC expenditures that otherwise would have been recovered from our customers in future periods. If approved, the settlement is expected to reduce our recoverable ERC regulatory asset and have a favorable impact on the rates for our Elizabethtown Gas customers.

Note 4 - Fair Value Measurements

The methods used to determine the fair values of our assets and liabilities are described within Note 2.

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 in our unaudited Condensed Consolidated Statements of Financial Position as of the dates presented. See Note 5 for additional information on our derivative instruments.

	June 30, 2015					December 31, 2014					June 30, 2014
In millions	Assets (1)		Liabilities			Assets (1)		Liabilities			Assets (1)		Liabilities
Quoted prices in active markets (Level 1)	$	3	$	(53	)	$	58	$	(80	)	$	8	$	(38	)
Significant other observable inputs (Level 2)		128		(45	)		174		(94	)		57		(60	)
Netting of cash collateral		64		53			52		81			46		36
Total carrying value (2)	$	195	$	(45	)	$	284	$	(93	)	$	111	$	(62	)

(1)	Balances of $2 million at June 30, 2015, $3 million at December 31, 2014 and $3 million at June 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.

Debt

Our long-term debt is recorded at amortized cost, with the exception of Nicor Gas’ first mortgage bonds, which were 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	June 30, 2015		December 31, 2014		June 30, 2014
Long-term debt carrying amount	$	3,577	$	3,781	$	3,785
Long-term debt fair value (1)		3,857		4,231		4,191

(1)	Fair value determined using Level 2 inputs.

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Note 5 - 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 in Note 2 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K. See Note 4 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 June 30, 2015, December 31, 2014 and June 30, 2014, for agreements with such features, derivative instruments with liability fair values totaled $45 million, $93 million and $62 million, respectively, for which we had posted no collateral to our counterparties. The maximum collateral that could be required with these features is $7 million. For more information, see “Energy Marketing Receivables and Payables” in Note 2, which also have credit-risk-related contingent features. Our derivative instrument activities are included within operating cash flows as an increase (decrease) to net income of $42 million and $(13) million for the six months ended June 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 a net long natural gas contracts position outstanding in the following quantities:

In Bcf (1)	June 30, 2015 (2)			December 31, 2014			June 30, 2014
Cash flow hedges		6			9			6
Not designated as hedges		24			75			140
Total volumes		30			84			146
Short position – cash flow hedges		(8	)		(7	)		(4	)
Short position – not designated as hedges		(2,930	)		(2,825	)		(2,524	)
Long position – cash flow hedges		14			16			10
Long position – not designated as hedges		2,954			2,900			2,664
Net long position		30			84			146

(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 the remaining 4% expire between two and five years.

Derivative Instruments in our Unaudited Condensed Consolidated Statements of Financial Position

In accordance with regulatory requirements, gains and losses on derivative instruments used to hedge 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 in our unaudited Condensed Consolidated Statements of Financial Position represent the net realized gains (losses) related to these natural gas cost hedges as of the periods presented.

	Three months ended June 30,					Six months ended June 30,
In millions	2015			2014		2015			2014
Nicor Gas	$	(18	)	$	10	$	(21	)	$	12
Elizabethtown Gas		(4	)		2		(8	)		5

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.

		June 30, 2015						December 31, 2014						June 30, 2014
In millions	Classification	Assets			Liabilities			Assets			Liabilities			Assets			Liabilities
Designated as cash flow or fair value hedges
Natural gas contracts	Current	$	-		$	(4	)	$	6		$	(11	)	$	2		$	(1	)
Natural gas contracts	Long-term		-			(1	)		-			(1	)		-			-
Interest rate swap agreements	Current		24			-			-			-			-			-
Interest rate swap agreements	Long-term		23			-			-			-			-			-
Total designated as cash flow or fair value hedges		$	47		$	(5	)	$	6		$	(12	)	$	2		$	(1	)
Not designated as hedges
Natural gas contracts	Current	$	473		$	(481	)	$	1,061		$	(1,020	)	$	702		$	(721	)
Natural gas contracts	Long-term		92			(91	)		145			(119	)		77			(89	)
Total not designated as hedges		$	565		$	(572	)	$	1,206		$	(1,139	)	$	779		$	(810	)
Gross amounts of recognized assets and liabilities (1) (2)			612			(577	)		1,212			(1,151	)		781			(811	)
Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position (2)			(415	)		532			(925	)		1,058			(667	)		749
Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position (3)		$	197		$	(45	)	$	287		$	(93	)	$	114		$	(62	)

(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 $117 million as of June 30, 2015, $133 million as of December 31, 2014, and $82 million as of June 30, 2014. Cash collateral is included in the “Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position” line of this table.

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

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Derivative Instruments in 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 June 30,						Six months ended June 30,
In millions	2015			2014			2015			2014
Designated as cash flow or fair value hedges
Natural gas contracts - net gain (loss) reclassified from OCI into cost of goods sold	$	(3	)	$	2		$	(4	)	$	5
Natural gas contracts - net gain (loss) reclassified from OCI into operation and maintenance expense		(1	)		-			(1	)		1
Interest rate swaps - net loss reclassified from OCI into interest expense		-			-			1			-
Income tax benefit		-			(1	)		-			(1	)
Total designated as cash flow or fair value hedges, net of tax		(4	)		1			(4	)		5

Not designated as hedges (1)
Natural gas contracts - net gain (loss) recorded in operating revenues		3			30			(21	)		-
Natural gas contracts - net gain (loss) recorded in cost of goods sold (2)		1			(1	)		(1	)		1
Income tax benefit		(1	)		(11	)		9			-
Total not designated as hedges, net of tax		3			18			(13	)		1
Total gains (losses) on derivative instruments, net of tax	$	(1	)	$	19		$	(17	)	$	6

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

(2)	Excludes (gains) losses recorded in cost of goods sold associated with weather derivatives of $(1) million and $1 million for the three and six months ended June 30, 2015 and $1 million and $6 million for the three and six months ended June 30, 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 six months ended June 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 in our unaudited Condensed Consolidated Statements of Income over the next 12 months are $4 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 June 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 in our unaudited Condensed Consolidated Statements of Income. See Note 8 for these amounts.

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

Note 6 - 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 June 30,						Six months ended June 30,
In millions	2015			2014			2015			2014
Service cost	$	7		$	6		$	14		$	12
Interest cost		12			11			23			23
Expected return on plan assets		(17	)		(16	)		(33	)		(32	)
Net amortization of prior service cost (credit)		-			(1	)		(1	)		(1	)
Recognized actuarial loss		7			6			15			11
Net periodic pension benefit cost	$	9		$	6		$	18		$	13

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.

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	Three months ended June 30,						Six months ended June 30,
In millions	2015			2014			2015			2014
Service cost	$	-		$	-		$	1		$	1
Interest cost		3			3			6			7
Expected return on plan assets		(2	)		(1	)		(4	)		(3	)
Net amortization of prior service (credit) cost		(1	)		-			(1	)		(1	)
Recognized actuarial loss		2			2			3			3
Net periodic welfare benefit cost	$	2		$	4		$	5		$	7

Note 7 - Debt and Credit Facilities

Effective April 1, 2015, we adopted new authoritative guidance related to debt issuance costs, which 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 $19 million, $21 million and $22 million as of June 30, 2015, December 31, 2014 and June 30, 2014, respectively. See “Accounting Developments” in Note 2 for additional information.

The following table provides maturity dates, 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, see Note 8 to our consolidated financial statements and related notes in Item 8 of our 2014 Form 10-K.

		June 30, 2015									June 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	%	$	269		$	590			0.3	%	$	236
Commercial paper - Nicor Gas (2)	2015		0.4			190			585			0.2			212
Total short-term debt			0.4	%	$	459		$	1,175			0.3	%	$	448
Current portion of long-term debt	2016		4.6	%	$	125		$	200			5.0	%	$	200
Long-term debt - excluding current portion
Senior notes	2016-2043		5.0	%	$	2,625		$	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			4.9			3,381			3,506			4.9			3,506
Unamortized fair value adjustment of long-term debt (3)	n/a		n/a			74			80			n/a			85
Unamortized debt premium and issuance costs, net	n/a		n/a			(3	)		(5	)		n/a			(6	)
Total non-principal long-term debt			n/a			71			75			n/a			79
Total long-term debt - excluding current portion					$	3,452		$	3,581					$	3,585
Total debt					$	4,036		$	4,956					$	4,233

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

(2)	As of June 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 4 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 six months of 2015, our commercial paper maturities ranged from 1 to 58 days, and at June 30, 2015, remaining terms to maturity ranged from 1 to 21 days. During the first six months of 2015, we had no commercial paper issuances with original maturities over three months. Total borrowings and repayments during the first six months of 2015 netted to a payment of $716 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 second half 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 June 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
	June 30,			Dec. 31,			June 30,			June 30,			Dec. 31,			June 30,
	2015			2014			2014			2015			2014			2014
Debt covenants (1)		49	%		55	%		51	%		49	%		62	%		52	%

(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

·	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.

Note 8 - 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 June 30
As of beginning of period	$	(4	)	$	(197	)	$	(201	)	$	1		$	(136	)	$	(135	)
OCI, before reclassifications		25			-			25			-			-			-
Amounts reclassified from accumulated OCI		3			4			7			(1	)		3			2
Net current-period other comprehensive income (loss)		28			4			32			(1	)		3			2
As of end of period	$	24		$	(193	)	$	(169	)	$	-		$	(133	)	$	(133	)

For the six months ended June 30
As of beginning of period	$	(6	)	$	(200	)	$	(206	)	$	1		$	(137	)	$	(136	)
OCI, before reclassifications		27			-			27			4			-			4
Amounts reclassified from accumulated OCI		3			7			10			(5	)		4			(1	)
Net current-period other comprehensive income (loss)		30			7			37			(1	)		4			3
As of end of period	$	24		$	(193	)	$	(169	)	$	-		$	(133	)	$	(133	)

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

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

	Three months ended June 30,						Six months ended June 30,
In millions (1)	2015			2014			2015			2014
Cash flow hedges
Cost of goods sold (natural gas contracts)	$	(3	)	$	2		$	(4	)	$	5
Operation and maintenance expense (natural gas contracts)		(1	)		-			(1	)		1
Interest expense (interest rate contracts)		-			-			1			-
Total before income tax		(4	)		2			(4	)		6
Income tax benefit		-			(1	)		-			(1	)
Cash flow hedges, net of income tax		(4	)		1			(4	)		5
Less noncontrolling Interest		(1	)		-			(1	)		-
Total cash flow hedges, net of income tax		(3	)		1			(3	)		5
Retirement benefit plans
Operation and maintenance expense (actuarial losses) (2)		(6	)		(6	)		(11	)		(8	)
Operation and maintenance expense (prior service credits) (2)		-			1			-			1
Total before income tax		(6	)		(5	)		(11	)		(7	)
Income tax benefit		2			2			4			3
Total retirement benefit plans		(4	)		(3	)		(7	)		(4	)
Total reclassification for the period	$	(7	)	$	(2	)	$	(10	)	$	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 6 for additional details about net periodic benefit cost.

Note 9 - 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 $2 million for the six months ended June 30, 2015, and $4 million for the six months ended June 30, 2014. 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 six months ended June 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.

	June 30, 2015							December 31, 2014							June 30, 2014
In millions	Consolidated		SouthStar (1)		%			Consolidated		SouthStar (1)		%			Consolidated		SouthStar (1)		%
Current assets	$	1,572	$	192	12		%	$	2,886	$	236		8	%	$	2,380	$	195		8	%
Goodwill and other intangible assets		1,939		117		6			1,952		125		6			1,962		129		7
Long-term assets and other deferred debits		10,324		17		-			10,050		17		-			9,817		17		-
Total assets	$	13,835	$	326		2	%	$	14,888	$	378		3	%	$	14,159	$	341		2	%
Current liabilities	$	2,047	$	40		2	%	$	3,219	$	71		2	%	$	2,595	$	55		2	%
Long-term liabilities and other deferred credits		7,799		1		-			7,841		-		-			7,704		-		-
Total Liabilities		9,846		41		-			11,060		71		1			10,299		55		1
Equity		3,989		285		7			3,828		307		8			3,860		286		7
Total liabilities and equity	$	13,835	$	326		2	%	$	14,888	$	378		3	%	$	14,159	$	341		2	%

(1)	These amounts reflect information for SouthStar and exclude intercompany eliminations and the balances of our wholly owned subsidiary with an 85% ownership interest in SouthStar.

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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 June 30,				Six months ended June 30,
In millions	2015		2014		2015		2014
Operating revenues	$	122	$	145	$	433	$	519
Operating expenses
Cost of goods sold		89		111		292		381
Operation and maintenance		18		20		41		43
Depreciation and amortization		3		2		5		5
Taxes other than income taxes		-		1		1		1
Total operating expenses		110		134		339		430
Operating income	$	12	$	11	$	94	$	89

Equity Method Investments

For more information about our equity method investments, see Note 10 to our consolidated financial statements and related notes in Item 8 of our 2014 Form 10-K. 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:

	June 30,		December 31,		June 30,
In millions	2015		2014		2014
Triton	$	53	$	62	$	65
Horizon Pipeline		14		14		15
Other (1)		8		4		1
Total	$	75	$	80	$	81

(1)	Primarily includes our current investments of $3 million in PennEast Pipeline and $4 million in Atlantic Coast Pipeline as of June 30, 2015 and $1 million and $2 million, respectively, as of December 31, 2014.

Income from our equity method investments is classified as other income in 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 June 30,				Six months ended June 30,
In millions	2015		2014		2015		2014
Triton	$	1	$	1	$	1	$	3
Horizon Pipeline		-		-		1		1

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 in 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 in 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 a new interstate pipeline company formed to develop and operate a 108-mile natural gas pipeline between New Jersey and Pennsylvania with initial transportation capacity of 1 Bcf per day, which may be expanded to 1.2 Bcf per day. Subject to FERC approval, 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 550-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, construction is scheduled to begin in the second half of 2016.

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Note 10 - 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. The following table illustrates our expected contractual obligations and commitments as of June 30, 2015.

													2020 &
In millions	Total		2015		2016		2017		2018		2019		thereafter
Recorded contractual obligations:
Long-term debt	$	3,506	$	-	$	545	$	22	$	155	$	350	$	2,434
Short-term debt		459		459		-		-		-		-		-
Environmental remediation liabilities (1)		429		47		86		80		65		44		107
Total	$	4,394	$	506	$	631	$	102	$	220	$	394	$	2,541

Unrecorded contractual obligations and commitments (2) (7):
Pipeline charges, storage capacity and gas supply (3)	$	5,341	$	527	$	706	$	491	$	369	$	343	$	2,905
Interest charges (4)		2,670		87		171		147		146		141		1,978
Operating leases (5)		172		13		26		28		21		16		68
Asset management agreements (6)		33		5		11		9		6		2		-
Standby letters of credit, performance/surety bonds (7)		48		37		11		-		-		-		-
Other		8		3		3		1		1		-		-
Total	$	8,272	$	672	$	928	$	676	$	543	$	502	$	4,951

(1)	Includes charges recoverable through base rates or rate rider mechanisms.

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

(3)

Includes charges recoverable through a natural gas cost recovery mechanism or alternatively billed to marketers and demand charges associated with Sequent. The gas supply balance includes amounts for Nicor Gas and SouthStar gas commodity purchase commitments of 87 Bcf at floating gas prices calculated using forward natural gas prices as of June 30, 2015, and is valued at $222 million. As we do for other subsidiaries, we provide guarantees to certain gas suppliers for SouthStar in support of payment obligations.

(4)

Floating rate interest charges are calculated based on the interest rate as of June 30, 2015 and the maturity date of the underlying debt instrument. As of June 30, 2015, we have $48 million of accrued interest on our unaudited Condensed Consolidated Statements of Financial Position that will be paid in the next 12 months.

(5)

We have certain operating leases with provisions for step rent or escalation payments and certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms, in accordance with GAAP. However, this lease accounting treatment does not affect the future annual operating lease cash obligations as shown herein. Our operating leases are primarily for real estate.

(6)	Represent fixed-fee minimum payments for Sequent’s affiliated asset management agreements.

(7)	We provide guarantees to certain municipalities and other agencies and certain gas suppliers of SouthStar in support of payment obligations.

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 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.

Regulatory Matters

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 is also obligated to resolve 25% of the 4.6 Bcf imbalance, or approximately 1.15 Bcf of natural gas, through system injections. As of June 30, 2015, Atlanta Gas Light had replaced substantially its entire obligation.

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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. According to the current procedural schedule, we expect a final order to be issued by the Illinois Commission in the second half of 2015, in which the Illinois Commission may accept, reject or modify the proposed order of the Administrative Law Judge. As of June 30, 2015 we have not recorded a liability associated with this contingency.

In February 2015, Atlanta Gas Light made a filing with the Georgia Commission for a true-up recovery of $178 million related to our 15-year pipeline replacement program that ended on December 31, 2013. This filing is for unrecovered revenue through December 2014. The filing proposed an initial one-time $2.46 rate increase collected from 2016 through 2025, or an alternative phased-in schedule of four $0.58 cumulative increases in 2017, 2018, 2019 and 2020 collected through 2030. The company believes that all incurred costs deferred for future recovery will be collected in future revenues. The staff of the Georgia Commission is evaluating this matter; however, no hearing schedule or date of any final order has been established.

Additionally, one of the capital projects under Atlanta Gas Light’s pipeline replacement program 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. Atlanta Gas Light is pursuing contractual and legal claims against third party contractors responsible for the construction issues. In August 2014, Atlanta Gas Light reached an agreement with the Georgia Commission whereby it would delay recovery of the mitigation costs to a future rate proceeding after completion of litigation and the amount of recoveries from third party contractors was known. The company believes all costs were prudently incurred and intends to seek recovery in a future rate proceeding.

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 current and former operating sites. See Note 3 for additional information on our environmental remediation costs.

Litigation

We are involved in litigation arising in the normal course of business. Although in some cases we are unable to estimate the amount of loss reasonably possible in addition to any amounts already recognized, it is possible that the resolution of these contingencies, either individually or in aggregate, will require us to take charges against, or will result in reductions in, future earnings. 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 in Item 8 of our 2014 Form 10-K.

PBR Proceeding Nicor Gas’ PBR plan was a regulatory plan that provided economic incentives based on natural gas cost performance. The PBR plan went into effect in 2000 and was terminated effective January 1, 2003, following allegations that Nicor Gas acted improperly in connection with the plan. Under this plan, Nicor Gas’ total gas supply costs were compared to a market-sensitive benchmark. Savings and losses relative to the benchmark were determined annually and shared equally with sales customers. Since 2002, the amount of the savings and losses required to be shared had been disputed by the CUB and others, with the Illinois Attorney General intervening, and had been subject to extensive contested discovery and other regulatory proceedings before administrative law judges and the Illinois Commission. In 2009, the staff of the Illinois Commission, Illinois Attorney General and CUB requested refunds of $85 million, $255 million and $305 million, respectively.

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. The period for the CUB to appeal this decision has expired.

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Note 11 - 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. Items we do not include in EBIT are income taxes and financing costs, including interest expense, each of 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.

Three months ended June 30, 2015

In millions	Distribution operations		Retail operations		Wholesale services (1)			Midstream operations			Other segments			Intercompany eliminations			Consolidated
Operating revenues from external parties	$	506	$	153	$	4		$	11		$	3		$	(3	)	$	674
Intercompany revenues		40		-		-			-			-			(40	)		-
Total operating revenues		546		153		4			11			3			(43	)		674
Operating expenses
Cost of goods sold		166		95		-			2			-			(41	)		222
Operation and maintenance		160		34		11			6			-			(2	)		209
Depreciation and amortization		83		6		1			4			4			-			98
Taxes other than income taxes		34		1		-			1			2			-			38
Total operating expenses		443		136		12			13			6			(43	)		567
Operating income (loss)		103		17		(8	)		(2	)		(3	)		-			107
Other income		3		-		-			-			1			-			4
EBIT	$	106	$	17	$	(8	)	$	(2	)	$	(2	)		-		$	111
Capital expenditures	$	248	$	2	$	-		$	7		$	7		$	-		$	264

Three months ended June 30, 2014

In millions	Distribution operations		Retail operations		Wholesale services (1)			Midstream operations			Other segments			Intercompany eliminations			Consolidated
Operating revenues from external parties	$	656	$	176	$	47		$	17		$	1		$	(8	)	$	889
Intercompany revenues		43		1		-			-			-			(44	)		-
Total operating revenues		699		177		47			17			1			(52	)		889
Operating expenses
Cost of goods sold		315		119		7			11			-			(50	)		402
Operation and maintenance		159		34		13			7			-			(2	)		211
Depreciation and amortization		78		6		1			4			6			-			95
Taxes other than income taxes		40		1		-			2			(1	)		-			42
Total operating expenses		592		160		21			24			5			(52	)		750
Operating income (loss)		107		17		26			(7	)		(4	)		-			139
Other income (expense)		3		-		(2	)		-			1			-			2
EBIT	$	110	$	17	$	24		$	(7	)	$	(3	)	$	-		$	141
Capital expenditures	$	158	$	3	$	-		$	5		$	5		$	-		$	171

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Six months ended June 30, 2015

In millions	Distribution operations		Retail operations		Wholesale services (1)		Midstream operations			Other segments			Intercompany eliminations			Consolidated
Operating revenues from external parties	$	1,791	$	494	$	94	$	30		$	9		$	(23	)	$	2,395
Intercompany revenues		96		-		-		-			-			(96	)		-
Total operating revenues		1,887		494		94		30			9			(119	)		2,395
Operating expenses
Cost of goods sold		942		305		9		12			5			(116	)		1,157
Operation and maintenance		345		71		35		12			(2	)		(3	)		458
Depreciation and amortization		165		12		1		9			8			-			195
Taxes other than income taxes		105		2		1		2			4			-			114
Total operating expenses		1,557		390		46		35			15			(119	)		1,924
Operating income (loss)		330		104		48		(5	)		(6	)		-			471
Other income		4		-		-		1			2			-			7
EBIT	$	334	$	104	$	48	$	(4	)	$	(4	)		-		$	478
Identifiable and total assets (2)	$	11,796	$	636	$	806	$	686		$	9,190		$	(9,279	)	$	13,835
Capital expenditures	$	418	$	4	$	1	$	10		$	19		$	-		$	452

Six months ended June 30, 2014

In millions	Distribution operations		Retail operations		Wholesale services (1)			Midstream operations			Other segments			Intercompany eliminations			Consolidated
Operating revenues from external parties	$	2,382	$	582	$	378		$	61		$	4		$	(56	)	$	3,351
Intercompany revenues		118		1		-			-			-			(119	)		-
Total operating revenues		2,500		583		378			61			4			(175	)		3,351
Operating expenses
Cost of goods sold		1,517		399		10			47			-			(171	)		1,802
Operation and maintenance		370		71		49			13			1			(4	)		500
Depreciation and amortization		156		14		1			9			8			-			188
Taxes other than income taxes		122		2		1			3			2			-			130
Total operating expenses		2,165		486		61			72			11			(175	)		2,620
Operating income (loss)		335		97		317			(11	)		(7	)		-			731
Other income (expense)		4		-		(2	)		1			2			-			5
EBIT	$	339	$	97	$	315		$	(10	)	$	(5	)	$	-		$	736
Identifiable and total assets (2)	$	11,511	$	671	$	1,207		$	699		$	9,482		$	(9,668	)	$	13,902
Capital expenditures	$	308	$	6	$	1		$	5		$	12		$	-		$	332

(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 June 30, 2015	$	1,291	$	89	$	1,380	$	1,376	$	4
Three months ended June 30, 2014		2,379		160		2,539		2,492		47
Six months ended June 30, 2015		3,436		239		3,675		3,581		94
Six months ended June 30, 2014		6,428		458		6,886		6,508		378

(2)	Identifiable and total assets exclude assets held for sale.

Identifiable assets are those used in each segment’s operations. Information by segment on our Consolidated Statements 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
Identifiable and total assets		$	12,037			$	670			$	1,402			$	694			$	9,706			$	(9,621	)		$	14,888

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Note 12 - 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 also recorded a 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 for assets that we were not compensated for by the buyer. The assets and liabilities of Tropical Shipping classified as held for sale on the unaudited Condensed Consolidated Statements of Financial Position are as follows:

In millions	June 30, 2014
Current assets
Cash and cash equivalents	$	15
Short-term investments		3
Receivables		35
Inventories		9
Other		2
Total current assets		64
Long-term assets and other deferred debits
Property, plant and equipment, net		127
Goodwill		42
Intangible assets		19
Other		5
Total long-term assets and other deferred debits		193
Total assets held for sale	$	257
Current liabilities
Other accounts payable – trade	$	9
Accrued expenses		7
Other		23
Total liabilities held for sale	$	39

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		Six months ended
In millions	June 30, 2014		June 30, 2014
Operating revenues	$	92	$	181
Operating expenses
Cost of goods sold		57		111
Operation and maintenance		27		55
Depreciation and amortization		-		5
Taxes other than income taxes		3		4
Loss on sale and goodwill impairment		4		23
Total operating expenses		91		198
Operating income (loss)		1		(17	)
Income (loss) before income taxes		1		(17	)
Income tax expense		-		(32	)
Income (loss) from discontinued operations, net of tax	$	1	$	(49	)

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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 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, 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, development 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; the impact of natural disasters, such as hurricanes, on the supply and price of natural gas; acts of war or terrorism; the outcome of litigation; and 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 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 – distributions 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 11 to our unaudited condensed consolidated financial statements herein and Item 1, “Business” of our 2014 Form 10-K.

For the second quarter of 2015, our net income from continuing operations attributable to AGL Resources Inc. was $42 million, a decrease of $15 million compared to the same period in 2014. This decrease was the result of decreased EBIT primarily in our wholesale services segment largely due to lower commercial activity compared to the same period in 2014.

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For the first six months of 2015, our net income from continuing operations attributable to AGL Resources Inc. was $235 million, a decrease of $156 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. 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 leading to record earnings. Additionally, the effect of additional weather-related EBIT due to colder-than-normal weather during the first quarter of 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.

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 filed the first annual update under the program with the Illinois Commission on April 1, 2015. Our current cost estimates are approximately $200 million to $260 million in each of 2015, 2016 and 2017, which are within the program requirements. We have placed into service $74 million of qualifying projects under this plan.

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 will 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 February 2015, we filed for true-up recovery of $178 million related to our 15-year pipeline replacement program that ended on December 31, 2013. This filing relates to unrecovered revenue through December 2014. The filing proposed an initial one-time $2.46 rate increase collected from 2016 through 2025, or an alternative phased-in schedule of four $0.58 cumulative rate increases in 2017, 2018, 2019 and 2020 collected through 2030.

Virginia Natural Gas In April 2014, the Governor of Virginia signed into law legislation that enables the state's natural gas utilities to acquire long-term supplies of natural gas and make capital investments to facilitate the delivery of low-cost shale and coal-bed methane gas to Virginia homeowners and businesses. The statute also allows us to build pipelines and other infrastructure that deliver shale and coal-bed methane gas into the state's markets that seek to reduce natural gas supply costs or reduce price volatility for consumers. All filings under this legislation require approval by the Virginia Commission and we have not made any filings to date.

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

Florida City Gas In April 2015, Florida City Gas filed a petition with the Florida Commission for approval of its Safety, Access and Facility Enhancement program (SAFE). Under the proposed program, Florida City Gas would spend $10 million per year over a 10-year period on infrastructure relocation and enhancement projects. Costs incurred under the program would be recovered through a rate rider with annual rate adjustments and true-ups. Based on the current procedural schedule, a decision from the Florida Commission is expected in September 2015.

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 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 first half of 2014, we experienced increased natural gas price volatility that enabled us to capture unprecedented value in wholesale services leading to record earnings. While EBIT for the six months ended June 30, 2015 is lower than EBIT for the same period in 2014, wholesale services has maintained strong earnings results for 2015 due to increased 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 was lower than the levels experienced from the extreme and prolonged cold weather in 2014.

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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 9 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.

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 are not 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 six 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. Items that we do not include in EBIT are financing costs, including interest expense, and income taxes, each of 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. These items 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 Inc. 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 June 30,									Six months ended June 30,
In millions, except per share amounts	2015			2014			Change			2015			2014			Change
Operating revenues (1)	$	674		$	889		$	(215	)	$	2,395		$	3,351		$	(956	)
Cost of goods sold		(222	)		(402	)		180			(1,157	)		(1,802	)		645
Revenue tax expense (2)		(18	)		(25	)		7			(73	)		(92	)		19
Operating margin		434			462			(28	)		1,165			1,457			(292	)
Operating expenses		(345	)		(348	)		3			(767	)		(818	)		51
Revenue tax expense (2)		18			25			(7	)		73			92			(19	)
Operating income		107			139			(32	)		471			731			(260	)
Other income		4			2			2			7			5			2
EBIT		111			141			(30	)		478			736			(258	)
Interest expense, net		(42	)		(45	)		3			(86	)		(91	)		5
Income before income taxes		69			96			(27	)		392			645			(253	)
Income tax expense		(25	)		(37	)		12			(143	)		(240	)		97
Income from continuing operations		44			59			(15	)		249			405			(156	)
Income (loss) from discontinued operations, net of tax		-			1			(1	)		-			(49	)		49
Net income		44			60			(16	)		249			356			(107	)
Less net income attributable to noncontrolling interest		2			2			-			14			14			-
Net income attributable to AGL Resources Inc.	$	42		$	58		$	(16	)	$	235		$	342		$	(107	)
Net income attributable to AGL Resources Inc.
Income from continuing operations	$	42		$	57		$	(15	)	$	235		$	391		$	(156	)
Income (loss) from discontinued operations, net of tax		-			1			(1	)		-			(49	)		49
Net income attributable to AGL Resources Inc.	$	42		$	58		$	(16	)	$	235		$	342		$	(107	)
Diluted earnings (loss) per common share
Continuing operations	$	0.35		$	0.48		$	(0.13	)	$	1.96		$	3.29		$	(1.33	)
Discontinued operations (3)		-			0.01			(0.01	)		-			(0.42	)		0.42
Diluted earnings per common share attributable to AGL Resources Inc.	$	0.35		$	0.49		$	(0.14	)	$	1.96		$	2.87		$	(0.91	)

(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 six 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)	In September 2014, we closed on the sale of Tropical Shipping. See Note 12 to our unaudited condensed consolidated financial statements under Part I, Item 1 herein for additional information.

Operating Metrics

Weather We measure the effects of weather 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.

	Three months ended June 30,						2015 vs. 2014			2015 vs. normal			Six months ended June 30,						2015 vs. 2014			2015 vs. normal
	Normal (1)		2015		2014		(warmer)			(warmer)			Normal (1)		2015		2014		(warmer)			colder
Illinois (1) (2)		623		535		610		(12	)%		(14	)%		3,679		3,892		4,366		(11	)%		6	%
Georgia (1)		140		61		146		(58	)%		(56	)%		1,604		1,653		1,879		(12	)%		3	%

(1)

Normal represents the 10-year average from January 1, 2005, through June 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 617 for the second quarter and 3,519 for the first six months from 1998 through 2007.

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.

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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 June 30,						2015 vs. 2014			Six months ended June 30,						2015 vs. 2014
In thousands	2015			2014			% change			2015			2014			% change
Distribution operations (1)		4,534			4,508			0.6	%		4,545			4,520			0.6	%
Retail operations
Energy customers		657			631			4.1	%		647			634			2.1	%
Service contracts		1,155			1,201			(3.8	)%		1,157			1,199			(3.5	)%
Market share in Georgia		30	%		31	%		(3.2	)%		30	%		31	%		(3.2	)%

(1)

In 2014, we implemented a process change at Nicor Gas that adversely impacted our customer count. This had the effect of immaterial growth at Nicor Gas for the three and six months ended June 30, 2014. Excluding Nicor Gas, our year-over-year customer growth rates were 1.1% for both the three and six months ended June 30, 2015.

We anticipate overall utility customer growth trends for 2015 to continue improving based on an expectation of continued improvement in the economy, the related housing market and relatively 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. For the remainder of 2015, 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 June 30,				2015 vs. 2014			Six months ended June 30,				2015 vs. 2014
	2015		2014		% change			2015		2014		% change
Distribution operations (In Bcf)
Firm		99		105		(5.7	)%		444		467		(4.9	)%
Interruptible		24		26		(7.7	)%		51		54		(5.6	)%
Total		123		131		(6.1	)%		495		521		(5.0	)%
Retail operations (In Bcf)
Georgia firm		4		5		(20.0	)%		23		25		(8.0	)%
Illinois		2		2		-	%		9		12		(25.0	)%
Other (including Florida, Maryland, New York and Ohio)		2		2		-	%		6		6		-	%
Wholesale services
Daily physical sales (Bcf / day)		5.9		5.7		3.5	%		6.9		6.5		6.2	%

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, we expect the rates at which we re-contract expiring capacity in 2015 to be higher than re-contracting rates in 2014, but 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/or 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:

	June 30, 2015				June 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		0.098		7.0		0.114		5.0
Central Valley		0.047		4.0		0.062		2.5

(1)	Rates are per dekatherm. Firm capacity under subscription excludes 5.0 Bcf contracted by Sequent as of June 30, 2015, at an average monthly rate of $0.072 and 7.0 Bcf as of June 30, 2014, at an average monthly rate of $0.050.

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

	Three months ended June 30, 2015									Three months ended June 30, 2014
In millions	Operating margin (1) (2)			Operating expenses (2)			EBIT (1)			Operating margin (1) (2)			Operating expenses (2)			EBIT (1)
Distribution operations	$	362		$	259		$	106		$	359		$	252		$	110
Retail operations		58			41			17			58			41			17
Wholesale services		4			12			(8	)		40			14			24
Midstream operations		9			11			(2	)		6			13			(7	)
Other segments		3			6			(2	)		1			5			(3	)
Intercompany eliminations		(2	)		(2	)		-			(2	)		(2	)		-
Consolidated	$	434		$	327		$	111		$	462		$	323		$	141

	Six months ended June 30, 2015									Six months ended June 30, 2014
In millions	Operating margin (1) (2)			Operating expenses (2)			EBIT (1)			Operating margin (1) (2)			Operating expenses (2)			EBIT (1)
Distribution operations	$	872		$	542		$	334		$	891		$	556		$	339
Retail operations		189			85			104			184			87			97
Wholesale services		85			37			48			368			51			315
Midstream operations		18			23			(4	)		14			25			(10	)
Other segments		4			10			(4	)		4			11			(5	)
Intercompany eliminations		(3	)		(3	)		-			(4	)		(4	)		-
Consolidated	$	1,165		$	694		$	478		$	1,457		$	726		$	736

(1)

Operating margin is a non-GAAP measure. 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 11 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.

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 six months ended June 30, 2015, distribution operations’ EBIT decreased by $4 million and $5 million, or 4% and 1%, respectively, compared to the same periods during the prior year, as shown in the following table.

In millions	Three months ended			Six months ended
EBIT - June 30, 2014	$	110		$	339
Operating margin
Increase from regulatory infrastructure programs, primarily at Atlanta Gas Light and Nicor Gas		5			11
Higher customer usage and customer growth		2			10
Warmer weather compared to prior year		(2	)		(13	)
Energy efficiency program recoveries at Nicor Gas, offset by decreased operating expenses below		(3	)		(28	)
Other		1			1
Increase (decrease) in operating margin		3			(19	)
Operating expenses
Increased depreciation expense from additional assets placed in service		5			9
Increased benefit expenses primarily as a result of changes in actuarial gains and losses		3			6
Increased incentive compensation costs and increased payroll expense due to annual salary increases; year-to-date results offset by decreased payroll expense due to warmer weather than the prior year		5			-
Decreased rider expenses primarily as a result of energy efficiency program expenses at Nicor Gas, offset by increased operating margin above		(3	)		(28	)
Other, including decreased fleet expenses from lower fuel prices and decreased outside services		(3	)		(1	)
Increase (decrease) in operating expenses		7			(14	)
EBIT - June 30, 2015	$	106		$	334

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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. Retail operations’ EBIT remained flat for the three months ended June 30, 2015 and increased by $7 million, or 7%, for the six months ended June 30, 2015, compared to the same periods last year, as shown in the following table. During the three and six months ended June 30, 2015, we recovered $2 million and $10 million, respectively, of hedge losses and for the six months ended June 30, 2015 we recovered $3 million of LOCOM adjustments that were recorded during 2014. We expect to recover the remaining $3 million of hedge losses that were recorded in 2014 during the remainder of 2015.

In millions	Three months ended			Six months ended
EBIT - June 30, 2014	$	17		$	97
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		-			13
Warranty product mix and service counts combined with lower claims expense, partially offset by lower HVAC job counts		1			1
Favorable retail fixed price spreads and increased customer count for the quarter; unfavorable customer mix for year-to-date		2			(2	)
Lower usage primarily in Georgia due to warmer weather compared to prior year		(3	)		(7	)
Increase in operating margin		-			5
Operating expenses
Decreased bad debt expense related to warmer weather and lower natural gas prices		(2	)		(3	)
Increased marketing and other expenses, partially offset by lower incentive compensation costs		2			1
Decrease in operating expenses		-			(2	)
EBIT - June 30, 2015	$	17		$	104

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 six months ended June 30, 2015, wholesale services delivered strong EBIT due to increased levels of volatility in commodity and transportation prices. However, volatility was lower than the levels experienced from the extreme and prolonged cold weather in 2014 driving decreases in EBIT by $32 million and $267 million for the three and six months ended June 30, 2015, respectively, compared to the same periods last year, as shown in the following table.

In millions	Three months ended			Six months ended
EBIT - June 30, 2014	$	24		$	315
Operating margin
Change in commercial activity largely driven by lower price volatility resulting from extremely cold weather in 2014		(29	)		(293	)
Change in value of storage derivatives as a result of changes in NYMEX natural gas prices		(9	)		(2	)
Change in value of transportation and forward commodity derivatives from price movements related to natural gas transportation positions		(2	)		14
Change in LOCOM adjustment		4			(2	)
Decrease in operating margin		(36	)		(283	)
Operating expenses
Decreased variable compensation costs related to lower earnings and decreased other expenses		(2	)		(14	)
Decrease in operating expenses		(2	)		(14	)
Decrease in charitable contribution expenses compared to prior year		(2	)		(2	)
EBIT - June 30, 2015	$	(8	)	$	48

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

	Three months ended June 30,						Six months ended June 30,
In millions	2015			2014			2015			2014
Commercial activity recognized	$	1		$	30		$	108		$	401
(Loss) gain on storage derivatives		(4	)		5			1			3
Gain (loss) on transportation and forward commodity derivatives		7			9			(17	)		(31	)
Inventory LOCOM adjustment, net of estimated current period recoveries		-			(4	)		(7	)		(5	)
Operating margin	$	4		$	40		$	85		$	368

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 three and six months ended June 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 resulting from the withdrawal of storage inventory hedged at the end of 2014 that was included in the storage withdrawal schedule with a value of $(3) million as of December 31, 2014.

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 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 benefitting 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 losses in the second quarter of 2015 and slight gain in the first six months of 2015 are primarily due to changes in natural gas prices applicable to the locations of our specific storage assets. Losses in our transportation and forward commodity derivative positions for the first six 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 approximately half is expected to be recovered in the second half of 2015 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 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 June 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.

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	Storage withdrawal schedule
Dollars in millions	Total storage (in Bcf) (WACOG $2.32)		Expected net operating gains (losses) (1)			Physical transportation transactions – expected net operating gains (losses) (2)
2015		16	$	9		$	8
2016		28		16			9
Total at June 30, 2015 (3)		44	$	25		$	17
Total at December 31, 2014 (3)		71	$	(3	)	$	(38	)
Total at June 30, 2014		29	$	13		$	31

(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 half of 2015.

(3)

Includes 5 Bcf in storage with expected operating margin of $4 million and $2 million at June 30, 2015 and December 31, 2014, respectively, that is currently 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 be operational during 2015. While we expect this inventory to be fully recovered, the timing of withdrawal of this gas may be impacted by 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 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 six months ended June 30, 2015, midstream operations’ EBIT increased by $5 million and $6 million, respectively, compared to the same periods during the prior year, as shown in the following table.

In millions	Three months ended			Six months ended
EBIT - June 30, 2014	$	(7	)	$	(10	)
Operating margin
True-up of retained fuel at one of our storage facilities in 2014		2			9
Lower interruptible revenues largely at Golden Triangle due to optimizing the facilities during the colder weather in 2014		-			(6	)
Higher sales of LNG		1			1
Increase in operating margin		3			4
Decrease in operating expenses largely driven by a property tax settlement, lower outside services and other costs		(2	)		(2	)
EBIT - June 30, 2015	$	(2	)	$	(4	)

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.

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, pension and retiree welfare benefits, capital expenditures, anticipated debt redemptions, interest payments on debt obligations, dividend payments and other cash needs through the next several years.

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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 June 30, 2015, our variable-rate debt was 20% of our total debt compared to 31% as of December 31, 2014, and 16% as of June 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 second half 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 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 and cost control 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 in 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	$	269	$	367	$	106	$	787
Commercial paper – Nicor Gas		190		309		133		585
Current portion of long-term debt (3)		125		92		-		200
Total	$	584	$	768	$	239	$	1,572

(1)	As of June 30, 2015.

(2)	For the six months ended June 30, 2015.

(3)	$200 million of senior notes matured in January 2015 and were repaid using commercial paper.

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 $122 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 June 30, 2015, and our maximum 70% debt to total capitalization allowed under our financial covenants, we could potentially borrow an additional $1.0 billion of commercial paper under the AGL Credit Facility and an additional $510 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.

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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. The following table summarizes our credit ratings as of June 30, 2015, and reflects no change from what was reported in our 2014 Form 10-K.

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+

A+

Senior secured

n/a

Aa3

AA-

Ratings outlook

Stable

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

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.

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 7 to our unaudited condensed consolidated financial statements under Part I, Item 1 herein.

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

	Six months ended June 30,
In millions	2015			2014 (1)			Variance
Net cash provided by (used in):
Operating activities	$	1,485		$	1,175		$	310
Investing activities		(447	)		(300	)		(147	)
Financing activities		(1,044	)		(843	)		(201	)
Net (decrease) increase in cash and cash equivalents – continuing operations		(6	)		41			(47	)
Net decrease in cash and cash equivalents – discontinued operations		-			(9	)		9
Cash and cash equivalents (including held for sale) at beginning of period		31			105			(74	)
Cash and cash equivalents (including held for sale) at end of period		25			137			(112	)
Less cash and cash equivalents held for sale at end of period		-			15			(15	)
Cash and cash equivalents (excluding held for sale) at end of period	$	25		$	122		$	(97	)

(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, during 2015, we received a tax refund related to the extension of bonus depreciation late in 2014, which occurred after our estimated payment was made, resulting in a $150 million refund in January 2015.

Cash Flow from Investing Activities The increased use of cash for our investing activities was the result of increased rider investment, primarily relating to the start of Nicor Gas’ Investing in Illinois program during the first half of 2015 combined with increased spending for other rate-based investments at distribution operations.

Cash Flow from Financing Activities The increased use of cash for our financing activities was primarily the result of repaying the current portion of our senior notes that matured in the first quarter of 2015. For more information on our debt, see Note 7 to our unaudited condensed consolidated financial statements under Part I, Item 1 herein.

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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 10 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 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

· Income Taxes

Accounting Developments

See “Accounting Developments” in Note 2 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 (RMC), which prohibits the use of derivatives for speculative purposes.

Our RMC 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 RMC 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 RMC to perform its monitoring functions. Our risk management activities and related accounting treatment for our derivative instruments are described in further detail in Note 5 of our unaudited condensed consolidated financial statements 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 six months ended June 30, 2015 and 2014.

	Derivative instruments average values at June 30, (1)
In millions	2015		2014
Asset	$	190	$	166
Liability		96		131

(1) Excludes cash collateral amounts.

	Derivative instruments fair values netted with cash collateral at
In millions	June 30, 2015		December 31, 2014		June 30, 2014
Asset	$	197	$	287	$	114
Liability		45		93		62

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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						Six months ended
	June 30,						June 30,
In millions	2015			2014			2015			2014
Net fair value of derivative instruments outstanding at beginning of period	$	(25	)	$	(44	)	$	61		$	(82	)
Derivative instruments realized or otherwise settled during period		32			(15	)		(38	)		43
Change in net fair value of derivative instruments		28			29			12			9
Net fair value of derivative instruments outstanding at end of period		35			(30	)		35			(30	)
Netting of cash collateral		117			82			117			82
Cash collateral and net fair value of derivative instruments outstanding at end of period (1)	$	152		$	52		$	152		$	52

(1)	Net fair value of derivative instruments outstanding includes $2 million and $3 million premium and associated intrinsic value at June 30, 2015 and 2014, respectively, associated with weather derivatives.

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

In millions	Prices actively quoted (Level 1) (1)			Significant other observable inputs (Level 2) (2)
Mature through 2015	$	(44	)	$	26
Mature 2016 – 2017		(6	)		59
Total derivative instruments (3)	$	(50	)	$	85

(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 six months ended June 30, 2015 and 2014 were less than $0.1 million and wholesale services had the following VaRs.

	Three months ended June 30,				Six months ended June 30,
In millions	2015		2014		2015		2014
Period end	$	3.4	$	3.5	$	3.4	$	3.5
Average		3.3		3.0		3.7		4.6
High		4.6		3.7		7.3		19.7
Low		2.6		2.2		2.6		2.2

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 $779 million of variable-rate debt outstanding at June 30, 2015, a 100 basis point change in market interest rates would have resulted in an increase in pre-tax interest expense of $7 million on an annualized basis.

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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 may 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 5 to our unaudited condensed consolidated financial statements included under Part 1, Item 1 herein.

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 debt issuances in 2015 and in 2016. 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 June 30, 2015 and concluded that the hedges remain highly effective.

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 June 30, 2015, our top 20 counterparties represented 55% of the total counterparty exposure of $350 million, excluding $6 million of customer deposits.

As of June 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
	June 30,		Dec. 31,		June 30,		June 30,		Dec. 31,		June 30,
In millions	2015		2014		2014		2015		2014		2014
Netting agreements in place:
Counterparty is investment grade	$	307	$	482	$	439	$	146	$	276	$	248
Counterparty is non-investment grade		5		4		2		11		7		9
Counterparty has no external rating		114		263		199		297		494		450
No netting agreements in place:
Counterparty is investment grade		4		30		32		1		-		4
Counterparty has no external rating		-		-		5		-		-		13
Amount recorded on unaudited Condensed Consolidated Statements of Financial Position	$	430	$	779	$	677	$	455	$	777	$	724

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 $7 million at June 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 June 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 June 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 June 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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 10 to our unaudited condensed consolidated financial statements in this quarterly filing 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. 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 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.

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 second quarter of 2015, and no unregistered sales of equity securities were made during this period.

Item 6. Exhibits.

Exhibit Number	Description of Exhibit	Filer	The Filings Referenced for Incorporation by Reference
10.1	First Amendment to the Amended and Restated Credit Agreement dated as of February 26, 2013	AGL Resources	Filed herewith
10.2	First Amendment to the Credit Agreement dated as of February 26, 2013	AGL Resources	Filed herewith
10.3	Amended and Restated Common Stock Equivalent Plan for Non-Employee Directors	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: July 29, 2015 /s/ Elizabeth W. Reese

Elizabeth W. Reese

Executive Vice President and Chief Financial Officer

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