Edgar Filing: AGL RESOURCES INC

10-Q




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

FORM 10-Q

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

For the Quarterly Period Ended March 31, 2016



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 April 29, 2016, was 120,680,030.

AGL RESOURCES INC.

Quarterly Report on Form 10-Q

For the Quarter Ended March 31, 2016

TABLE OF CONTENTS



		Page
	Glossary of Key Terms	3
Item Number.
	PART I - FINANCIAL INFORMATION

1.	Condensed Consolidated Financial Statements (Unaudited)	4
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Income	5
	Condensed Consolidated Statements of Comprehensive Income	6
	Condensed Consolidated Statements of Equity	7
	Condensed Consolidated Statements of Cash Flows	8
	Notes to Condensed Consolidated Financial Statements (Unaudited)	9
	Note 1 - Organization and Basis of Presentation	9
	Note 2 - Proposed Merger with Southern Company	9
	Note 3 - Significant Accounting Policies and Methods of Application	10
	Note 4 - Regulated Operations	12
	Note 5 - Fair Value Measurements	14
	Note 6 - Derivative Instruments	14
	Note 7 - Employee Benefit Plans	16
	Note 8 - Debt and Credit Facilities	17
	Note 9 - Equity	18
	Note 10 - Non-Wholly Owned Entities and Contingently Redeemable Noncontrolling Interest	19
	Note 11 - Commitments, Guarantees and Contingencies	20
	Note 12 - Segment Information	21
2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	23
	Forward-Looking Statements	23
	Executive Summary	24
	Results of Operations	26
	Liquidity and Capital Resources	31
	Critical Accounting Policies and Estimates	34
	Accounting Developments	34
3.	Quantitative and Qualitative Disclosures About Market Risk	34
4.	Controls and Procedures	37

	PART II - OTHER INFORMATION

1.	Legal Proceedings	37
1A	Risk Factors	37
2.	Unregistered Sales of Equity Securities and Use of Proceeds	37
6.	Exhibits	37

	SIGNATURE	38

Glossary of Key Terms

Table of Contents



GLOSSARY OF KEY TERMS
2015 Form 10-K	Our Annual Report on Form 10-K for the year ended December 31, 2015, filed with the SEC on February 11, 2016
AGL Capital	AGL Capital Corporation
AGL Credit Facility	$1.3 billion credit agreement entered into by AGL Capital to support its commercial paper program
AGL Resources	AGL Resources Inc., together with its consolidated subsidiaries
Atlanta Gas Light	Atlanta Gas Light Company
Atlantic Coast Pipeline	Atlantic Coast Pipeline, LLC
Bcf	Billion cubic feet
Central Valley	Central Valley Gas Storage, LLC
CUB	Citizens Utility Board
EBIT	Earnings before interest and taxes, the primary measure of our reportable segments’ profit or loss, which includes operating income and other income and excludes interest on debt and income tax expense
ERC	Environmental remediation costs
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
Florida Commission	Florida Public Service Commission, the state regulatory agency for Florida City Gas
GAAP	Accounting principles generally accepted in the United States of America
Georgia Commission	Georgia Public Service Commission, the state regulatory agency for Atlanta Gas Light
Golden Triangle	Golden Triangle Storage, Inc.
Heating Degree Days	A measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
Heating Season	The period from November through March when natural gas usage and operating revenues are generally higher
Horizon Pipeline	Horizon Pipeline Company, LLC
Illinois Commission	Illinois Commerce Commission, the state regulatory agency for Nicor Gas
Jefferson Island	Jefferson Island Storage & Hub, LLC
LIFO	Last-in, first-out
LOCOM	Lower of weighted average cost or current market price
Marketers	Marketers selling retail natural gas in Georgia and certificated by the Georgia Commission
Maryland Commission	Maryland Public Service Commission, the state regulatory agency for Elkton Gas
Merger Agreement	Agreement and Plan of Merger entered into on August 23, 2015 by Southern Company, AMS Corp., a subsidiary of Southern Company, and AGL Resources
MGP	Manufactured Gas Plant
Moody’s	Moody’s Investors Service
New Jersey BPU	New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas
Nicor Gas	Northern Illinois Gas Company, doing business as Nicor Gas Company
Nicor Gas Credit Facility	$700 million credit facility entered into by Nicor Gas to support its commercial paper program
NYMEX	New York Mercantile Exchange, Inc.
OCI	Other comprehensive income
Operating margin	A non-GAAP measure of income, calculated as operating revenues minus cost of goods sold and revenue tax expense
PennEast Pipeline	PennEast Pipeline Company, LLC
PGA	Purchased gas adjustment
Piedmont	Piedmont Natural Gas Company, Inc.
Pivotal Utility	Pivotal Utility Holdings, Inc., doing business as Elizabethtown Gas, Elkton Gas and Florida City Gas
PRP	Pipeline Replacement Program, Atlanta Gas Light's 15-year infrastructure replacement program, which ended in December 2013
S&P	Standard & Poor’s Ratings Services
SEC	Securities and Exchange Commission
Sequent	Sequent Energy Management, L.P.
Southern Company	The Southern Company
SouthStar	SouthStar Energy Services, LLC
Triton	Triton Container Investments, LLC
U.S.	The United States of America
VaR	Value-at-risk
VIE	Variable interest entity
Virginia Commission	Virginia State Corporation Commission, the state regulatory agency for Virginia Natural Gas
Virginia Natural Gas	Virginia Natural Gas, Inc.
WACOG	Weighted average cost of gas

Glossary of Key Terms

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITIED)



	As of
In millions, except share and per share amounts	March 31, 2016			December 31, 2015			March 31, 2015
Current assets
Cash and cash equivalents	$	20		$	19		$	41
Receivables
Natural gas, unbilled revenues and other	564			516			834
Energy marketing	365			445			611
Less allowance for uncollectible accounts	36			29			48
Total receivables, net	893			932			1,397
Inventories	335			651			302
Derivative instruments, including cash collateral	160			206			189
Prepaid expenses	62			218			38
Regulatory assets	50			68			63
Other	17			21			49
Total current assets	1,537			2,115			2,079
Long-term assets and other deferred debits
Property, plant and equipment	12,777			12,566			11,689
Less accumulated depreciation	2,833			2,775			2,515
Property, plant and equipment, net	9,944			9,791			9,174
Goodwill	1,813			1,813			1,827
Regulatory assets	661			670			634
Intangible assets	105			109			116
Other	276			256			289
Total long-term assets and other deferred debits	12,799			12,639			12,040
Total assets	$	14,336		$	14,754		$	14,119
Current liabilities
Short-term debt	$	557		$	1,010		$	526
Current portion of long-term debt	470			545			75
Energy marketing trade payables	363			418			586
Other accounts payable – trade	250			255			285
Accrued expenses	231			200			259
Regulatory liabilities	159			134			168
Customer deposits and credit balances	141			165			109
Accrued environmental remediation liabilities	68			67			93
Derivative instruments, including cash collateral	64			44			48
Temporary LIFO liquidation	48			—			87
Current deferred income taxes	20			31			—
Other	118			131			135
Total current liabilities	2,489			3,000			2,371
Long-term liabilities and other deferred credits
Long-term debt	3,273			3,275			3,505
Accumulated deferred income taxes	1,921			1,912			1,738
Regulatory liabilities	1,632			1,611			1,612
Accrued pension and retiree welfare benefits	513			515			526
Accrued environmental remediation liabilities	355			364			326
Other	83			102			77
Total long-term liabilities and other deferred credits	7,777			7,779			7,784
Total liabilities and other deferred credits	10,266			10,779			10,155
Commitments, guarantees and contingencies (see Note 11)
Contingently redeemable noncontrolling interest	38			—			—
Equity
Common stock, $5 par value; 750,000,000 shares authorized; outstanding: 120,679,004 shares at March 31, 2016, 120,376,721 shares at December 31, 2015, and 119,927,459 shares at March 31, 2015	604			603			601
Additional paid-in capital	2,110			2,099			2,090
Retained earnings	1,539			1,421			1,444
Accumulated other comprehensive loss	(213		)	(186		)	(201		)
Treasury shares, at cost: 216,523 shares at March 31, 2016, December 31, 2015, and March 31, 2015	(8		)	(8		)	(8		)
Total common shareholders’ equity	4,032			3,929			3,926
Noncontrolling interest	—			46			38
Total equity	4,032			3,975			3,964
Total liabilities, redeemable noncontrolling interest and equity	$	14,336		$	14,754		$	14,119

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 March 31,
In millions, except per share amounts	2016			2015
Operating revenues (includes revenue taxes of $40 and $56 for the three months ended March 31, 2016 and 2015, respectively)	$	1,334		$	1,721
Operating expenses
Cost of goods sold	578			935
Operation and maintenance	241			249
Depreciation and amortization	102			97
Taxes other than income taxes	62			76
Merger-related expenses	3			—
Total operating expenses	986			1,357
Operating income	348			364
Other income	3			3
Interest expense, net	(47		)	(44		)
Income before income taxes	304			323
Income tax expense	111			118
Net income	193			205
Less net income attributable to noncontrolling interest	11			12
Net income attributable to AGL Resources	$	182		$	193
Per common share information
Basic earnings per common share attributable to AGL Resources	$	1.52		$	1.62
Diluted earnings per common share attributable to AGL Resources	$	1.51		$	1.62
Cash dividends declared per common share	$	0.53		$	0.51
Weighted average number of common shares outstanding
Basic	120.1			119.3
Diluted	120.4			119.6

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 March 31,
In millions	2016			2015
Net income	$	193		$	205
Other comprehensive (loss) income, net of tax
Retirement benefit plans, net of tax
Reclassification of actuarial losses to net benefit cost (net of income tax of $2 and $2 for the three months ended March 31, 2016 and 2015, respectively)	3			3
Retirement benefit plans, net	3			3
Cash flow hedges, net of tax
Net derivative (loss) gain arising during the period (net of income tax of $16 and $1 for the three months ended March 31, 2016 and 2015, respectively)	(29		)	2
Reclassification of realized derivative gain to net income (net of income tax of less than $1 million)	(1		)	—
Cash flow hedges, net	(30		)	2
Other comprehensive (loss) income, net of tax	(27		)	5
Comprehensive income	166			210
Less comprehensive income attributable to noncontrolling interest	11			12
Comprehensive income attributable to AGL Resources	$	155		$	198

See Notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Key Terms

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AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(UNAUDITED)



	AGL Resources Shareholders
	Common stock			Additional paid-in capital			Retained earnings			Accumulated other comprehensive loss			Treasury shares			Noncontrolling interest			Total
In millions, except per share amounts	Shares	Amount		Additional paid-in capital			Retained earnings			Accumulated other comprehensive loss			Treasury shares			Noncontrolling interest			Total
Balance as of December 31, 2014	119.6	$	599	$	2,087		$	1,312		$	(206	)	$	(8	)	$	44		$	3,828
Net income	—	—		—			193			—			—			12			205
Other comprehensive income	—	—		—			—			5			—			—			5
Dividends on common stock ($0.51 per share)	—	—		—			(61		)	—			—			—			(61		)
Distribution to noncontrolling interest	—	—		—			—			—			—			(18		)	(18		)
Stock granted, share-based compensation, net of forfeitures	—	—		(12		)	—			—			—			—			(12		)
Stock issued, dividend reinvestment plan	0.1	—		3			—			—			—			—			3
Stock issued, share-based compensation, net of forfeitures	0.2	2		10			—			—			—			—			12
Share-based compensation expense, net of tax	—	—		2			—			—			—			—			2
Balance as of March 31, 2015	119.9	$	601	$	2,090		$	1,444		$	(201	)	$	(8	)	$	38		$	3,964



	AGL Resources Shareholders
	Common stock			Additional paid-in capital			Retained earnings			Accumulated other comprehensive loss			Treasury shares			Noncontrolling interest			Total
In millions, except per share amounts	Shares	Amount		Additional paid-in capital			Retained earnings			Accumulated other comprehensive loss			Treasury shares			Noncontrolling interest			Total
Balance as of December 31, 2015	120.4	$	603	$	2,099		$	1,421		$	(186	)	$	(8	)	$	46		$	3,975
Net income attributable to AGL Resources	—	—		—			182			—			—			—			182
Other comprehensive loss	—	—		—			—			(27		)	—			—			(27		)
Dividends on common stock ($0.53 per share)	—	—		—			(64		)	—			—			—			(64		)
Stock granted, share-based compensation, net of forfeitures	—	—		(9		)	—			—			—			—			(9		)
Stock issued, dividend reinvestment plan	—	—		3			—			—			—			—			3
Stock issued, share-based compensation, net of forfeitures	0.3	1		14			—			—			—			—			15
Share-based compensation expense, net of tax	—	—		3			—			—			—			—			3
Reclassification of noncontrolling interest	—	—		—			—			—			—			(46		)	(46		)
Balance as of March 31, 2016	120.7	$	604	$	2,110		$	1,539		$	(213	)	$	(8	)	$	—		$	4,032

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)



	Three Months Ended March 31,
In millions	2016			2015
Cash flows from operating activities:
Net income	$	193		$	205
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization	102			97
Change in derivative instrument assets and liabilities	51			33
Deferred income taxes	15			5
Changes in certain assets and liabilities
Inventories, net of temporary LIFO liquidation	364			501
Prepaid and miscellaneous taxes	231			267
Energy marketing receivables and trade payables, net	25			(23		)
Accrued natural gas costs, net	—			22
Trade payables, other than energy marketing	(8		)	(13		)
Receivables, other than energy marketing	(39		)	(24		)
Accrued expenses	(53		)	(54		)
Other, net	(40		)	104
Net cash flow provided by operating activities	841			1,120
Cash flows from investing activities:
Expenditures for property, plant and equipment	(235		)	(188		)
Other, net	(3		)	4
Net cash flow used in investing activities	(238		)	(184		)
Cash flows from financing activities:
Net repayments of commercial paper	(453		)	(649		)
Payment of long-term debt	(75		)	(200		)
Dividends paid on common shares	(64		)	(61		)
Distribution to noncontrolling interest	(19		)	(18		)
Other, net	9			2
Net cash flow used in financing activities	(602		)	(926		)
Net increase in cash and cash equivalents	1			10
Cash and cash equivalents at beginning of period	19			31
Cash and cash equivalents at end of period	$	20		$	41
Cash paid (received) during the period for
Interest	$	53		$	57
Income taxes	(132		)	(140		)

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 Balance Sheet as of December 31, 2015 was derived from our audited consolidated financial statements. We have prepared the accompanying unaudited condensed consolidated financial statements under the rules and regulations of the SEC. In accordance with such rules and regulations, we have condensed or omitted certain information and notes that would typically be 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 2015 Form 10-K.

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

Basis of Presentation

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

Certain amounts from prior periods have been reclassified to conform to the current period presentation. These reclassifications had no material impact on our prior period balances.

Note 2 - Proposed Merger with Southern Company

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

We and Southern Company have made joint filings seeking regulatory approval with all of the required state regulatory agencies. Completion of the merger remains subject to various closing conditions, including (i) the receipt of remaining required regulatory approvals from the Illinois Commission and New Jersey BPU, and such approvals having become final orders and (ii) the absence of a judgment, order, decision, injunction, ruling or other finding or agency requirement of a governmental entity prohibiting the closing of the merger.

To date, the proposed merger has been approved by the Maryland Commission, the Georgia Commission, the California Public Utilities Commission, the Virginia Commission and our shareholders. Additionally, we received consent from the Federal Communications Commission to transfer parent company control of radio licenses held by certain of our subsidiaries and the waiting period under the Hart-Scott-Rodino Act has expired.

On April 28, 2016, Southern Company, AGL Resources, Nicor Gas, the Illinois Attorney General’s Office, and the CUB filed a settlement agreement with the Illinois Commission that resolves all remaining contested issues with regards to the merger approval. This settlement agreement, along with the other resolved matters, is still subject to approval by the Illinois Commission.

The Merger Agreement contains certain termination rights for each party. In addition, the Merger Agreement, in certain circumstances, provides for the payment by AGL Resources of a $201 million termination fee to Southern Company and, in certain circumstances, provides for the reimbursement of expenses up to $5 million upon termination of the erger Agreement (which reimbursement would reduce on a dollar-for-dollar basis any termination fee subsequently paid by us). As of March 31, 2016, we had recorded no liability for termination fees.

During the three months ended March 31, 2016, we recorded $3 million ($2 million, net of tax) of merger-related costs on the accompanying unaudited Condensed Consolidated Statements of Income, which consisted primarily of legal expenses and additional share-based compensation expenses associated with the proposed merger. These costs are treated as tax deductible since the requisite closing conditions to the merger have not yet been satisfied. Once the merger is closed, we will evaluate the tax deductibility of all merger-related costs and adjust for any non-deductible amounts in the effective tax rate.

Glossary of Key Terms

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Note 3 - Significant Accounting Policies and Methods of Application

Our significant accounting policies are described in Note 3 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. There have been no significant changes to our accounting policies during the three months ended March 31, 2016.

Use of Accounting Estimates

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

Inventories

For our regulated utilities, except Nicor Gas, natural gas inventories and the inventories we hold for Marketers in Georgia are carried at cost on a WACOG basis.

Nicor Gas’ inventory is carried at cost on a LIFO basis. Under the LIFO method, 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 liquidation on our unaudited Condensed Consolidated Balance Sheets. 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 March 31, 2016 is expected to be restored prior to year-end and the inventory decrement as of March 31, 2015 was restored prior to December 31, 2015.

Our retail operations, wholesale services and midstream operations segments carry inventory at LOCOM, where cost is determined on a WACOG basis. For the periods presented, we recorded LOCOM adjustments to cost of goods sold in the following amounts to reduce the value of our natural gas inventories to market value.



	Three Months Ended March 31,
In millions	2016		2015
LOCOM adjustments	$	3	$	10

Goodwill

We perform an annual impairment test on our reporting units that contain goodwill during the fourth fiscal quarter of each year or more frequently if impairment indicators arise. The amounts of goodwill as of March 31, 2016 and 2015, and December 31, 2015 are provided in the following table.



In millions	Distribution operations		Retail operations		Midstream operations			Consolidated
Goodwill - March 31, 2015	$	1,640	$	173	$	14		$	1,827
Impairment ⁽¹⁾	—		—		(14		)	(14		)
Goodwill - December 31, 2015	1,640		173		—			1,813
Goodwill - March 31, 2016	$	1,640	$	173	$	—		$	1,813

(1) Based on the result of an interim impairment test performed as of September 30, 2015, we recorded a non-cash impairment charge of the full $14 million ($9 million, net of tax) of goodwill at midstream operations.

Earnings per Common Share

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

Glossary of Key Terms

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	Three Months Ended March 31,
In millions, except per share amounts	2016		2015
Net income attributable to AGL Resources	$	182	$	193
Denominator:
Basic weighted average number of shares outstanding ⁽¹⁾	120.1		119.3
Effect of dilutive securities	0.3		0.3
Diluted weighted average number of shares outstanding ⁽²⁾	120.4		119.6
Earnings per common share
Basic earnings per common share attributable to AGL Resources	$	1.52	$	1.62
Diluted earnings per common share attributable to AGL Resources	$	1.51	$	1.62


(1)	Daily weighted average shares outstanding.


(2)	Excludes all outstanding stock options whose effect would have been anti-dilutive.

Accounting Developments

Accounting standards adopted in 2016

Effective January 1, 2016, we adopted the accounting guidance described below, none of which had a material impact on our unaudited condensed consolidated financial statements. For additional information on these accounting standards, see Note 3 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K.


•	accounting for a share-based compensation performance target that could be achieved after the requisite service period;


•	consolidation of other legal entities into our financial statements;


•	accounting for fees paid in connection with arrangements with cloud-based software providers; and


•	reducing the diversity in fair value measurements hierarchy disclosures.

Other newly issued accounting standards and updated authoritative guidance

In March 2016, the FASB issued updated authoritative guidance related to accounting for certain aspects of share-based payment transactions. The new guidance changes the income tax accounting related to the tax "windfall" or "shortfall" on share-based compensation, increases the tax withholding level allowed before triggering liability classification of the award and allows for a policy election to account for forfeitures as they occur. This guidance is effective for us beginning January 1, 2017, and early adoption is permitted. We are currently evaluating the potential impact of this new guidance.

In February 2016, the FASB issued updated authoritative guidance related to accounting for lease transactions. The new guidance will require all organizations that use leased assets, referred to as "lessees," to recognize all leases with terms of more than 12 months on the balance sheet as right of use assets and corresponding liabilities. Lessees will continue to recognize lease expense based on classification of the lease, using a straight-line expense pattern for operating leases and a front-loaded expense pattern for financing leases. The accounting for lessors is substantially equivalent to the existing guidance. It also requires additional disclosures, both qualitative and quantitative, including amount, timing, and uncertainty of cash flows arising from leases. The new guidance is effective for us beginning January 1, 2019 and must be applied using the modified retrospective approach to each prior period presented. Early adoption of this new guidance is permitted. We are currently evaluating the potential impact of this new guidance.

In January 2016, the FASB issued updated authoritative guidance related to classification and measurement of financial instruments. The amendments modify the accounting and presentation for certain financial liabilities and equity investments not consolidated or reported using the equity method. The guidance is effective for us beginning January 1, 2018, and limited early adoption is permitted. We are currently evaluating the potential impact of this new guidance, but do not anticipate that it will have a material impact on our consolidated financial statements.

In November 2015, the FASB issued updated authoritative guidance related to the balance sheet classification of deferred taxes, which requires companies to present deferred income tax assets and deferred income tax liabilities as noncurrent on a classified balance sheet instead of the current requirement to separate deferred income tax liabilities and assets into current and noncurrent amounts. The guidance is effective for us beginning January 1, 2017, and early application is permitted either prospectively or retrospectively. We have determined that this new guidance will not have a material impact on our 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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In May 2014, the FASB issued an update to authoritative guidance related to revenue from contracts with customers. The update replaces most of the existing guidance with a single set of principles for recognizing revenue from contracts with customers. In July 2015, the FASB delayed the effective date by one year and the guidance will now be effective for us beginning January 1, 2018. Early adoption of the standard is permitted, but not before the original effective date of December 15, 2016. The new guidance must be applied retrospectively to each prior period presented or via a cumulative effect upon the date of initial application. We have not determined the impact of this new guidance, nor have we selected a transition method.

Note 4 - Regulated Operations

The accounting policies for our regulated operations are described within "Regulated Operations" in Note 3 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. Our regulatory assets and liabilities reflected within our unaudited Condensed Consolidated Balance Sheets as of the dates presented are summarized in the following table.



In millions	March 31, 2016		December 31, 2015		March 31, 2015
Regulatory assets
Recoverable ERC	$	21	$	31	$	37
Recoverable pension and retiree welfare benefit costs	12		12		11
Deferred natural gas costs	2		6		7
Recoverable seasonal rates	—		10		—
Other	15		9		8
Regulatory assets – current	50		68		63
Recoverable ERC	364		370		331
Recoverable pension and retiree welfare benefit costs	111		113		108
Recoverable regulatory infrastructure program costs	83		83		73
Long-term debt fair value adjustment	64		66		72
Other	39		38		50
Regulatory assets – long-term	661		670		634
Total regulatory assets	$	711	$	738	$	697
Regulatory liabilities
Accumulated removal costs	$	53	$	53	$	25
Bad debt over collection	47		42		30
Accrued natural gas costs	20		24		53
Deferred seasonal rates	20		—		20
Other	19		15		40
Regulatory liabilities – current	159		134		168
Accumulated removal costs	1,551		1,538		1,524
Bad debt over collection	28		21		19
Regulatory income tax liability	26		27		27
Unamortized investment tax credit	19		20		22
Other	8		5		20
Regulatory liabilities – long-term	1,632		1,611		1,612
Total regulatory liabilities	$	1,791	$	1,745	$	1,780

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 agency 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.

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Unrecognized Ratemaking Amounts The following table illustrates our authorized ratemaking amounts that are not recognized on our unaudited Condensed Consolidated Balance Sheets. 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	March 31, 2016		December 31, 2015		March 31, 2015
Atlanta Gas Light ⁽¹⁾	$	105	$	103	$	119
Virginia Natural Gas	12		12		12
Elizabethtown Gas	4		4		2
Nicor Gas	3		3		—
Total	$	124	$	122	$	133


(1)	In October 2015, Atlanta Gas Light received an order from the Georgia Commission, which included a final determination of the true-up recovery related to the PRP that allows Atlanta Gas Light to recover $144 million of the $178 million of incurred and allowed costs that were deferred for future recovery.

Deferred/Accrued 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 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.

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

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

Our accrued environmental remediation liabilities are not regulatory liabilities; however, the associated expenses are deferred as corresponding regulatory assets until the costs are recovered from customers. We primarily recover these deferred costs through rate riders that authorize dollar-for-dollar recovery. We expect to collect $21 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 March 31, 2016.



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	$200 - $457	$	46	$	246	$	30	As incurred
New Jersey	6	115 - 195	7		122		25		7 years
Georgia and Florida	13	29 - 52	21		50		13		5 years
North Carolina ⁽²⁾	1	n/a	5		5		—		No recovery
Total	46	$344 - $704	$	79	$	423	$	68


(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.

Regulatory Infrastructure Programs An update to our infrastructure improvement programs at our utilities is as follows.

Virginia Natural Gas In March 2016, the Virginia Commission approved an extension to our original Steps to Advance Virginia's Energy (SAVE) program, under which Virginia Natural Gas is allowed to invest up to $210 million on qualifying infrastructure projects through 2021 to replace more than 200 miles of aging pipeline infrastructure.

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Note 5 - Fair Value Measurements

The methods used to determine the fair values of our assets and liabilities are described within "Fair Value Measurements" in Note 3 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K.

Derivative Instruments

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



	March 31, 2016					December 31, 2015					March 31, 2015
In millions	Assets ⁽¹⁾		Liabilities			Assets ⁽¹⁾		Liabilities			Assets⁽¹⁾		Liabilities
Quoted prices in active markets (Level 1)	$	—	$	(96	)	$	53	$	(63	)	$	—	$	(106	)
Significant other observable inputs (Level 2)	108		(65		)	122		(46		)	108		(52		)
Netting of counterparty offset and cash collateral	69		96			33		63			104		106
Total carrying value ⁽²⁾	$	177	$	(65	)	$	208	$	(46	)	$	212	$	(52	)


(1)	Balances of $9 million at March 31, 2016, $10 million at December 31, 2015 and $1 million at March 31, 2015, 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 are recorded at their acquisition-date fair value. We amortize the fair value adjustment of Nicor Gas’ first mortgage bonds over the lives of the bonds. The following table lists the carrying amount and fair value of our long-term debt as of the dates presented.



In millions	March 31, 2016		December 31, 2015		March 31, 2015
Long-term debt carrying amount ⁽¹⁾	$	3,743	$	3,820	$	3,580
Long-term debt fair value ⁽²⁾	4,156		4,066		4,102


(1)	The change in the March 31, 2015 balance is related to our adoption of new accounting guidance in 2015 that resulted in the reclassification of debt issuance costs from other long-term assets to offset the related debt balances in long-term debt.


(2)	Fair value determined using Level 2 inputs.

Note 6 - Derivative Instruments

Our objectives and strategies for using derivative instruments, and the related accounting policies and methods used to determine their fair values are described within "Fair Value Measurements" in Note 3 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. See Note 5 herein for additional information on the fair value of 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 March 31, 2016, December 31, 2015 and March 31, 2015, for agreements with such features, derivative instruments with liability fair values totaled $65 million, $46 million and $52 million, respectively, for which we had posted no collateral to our counterparties as we exceed the minimum credit rating requirements. As of March 31, 2016, the maximum collateral that could have been required with these features was less than $1 million. For additional information on our credit-risk-related contingent features, see “Energy Marketing Receivables and Payables” in Note 3 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. Our derivative instrument activities are included within operating cash flows as increases to net income of $51 million and $33 million for the three months ended March 31, 2016 and 2015, respectively.

Quantitative Disclosures Related to Derivative Instruments

Our derivative instruments include 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 natural gas contracts outstanding in the following quantities:



In Bcf⁽¹⁾	March 31, 2016 ⁽²⁾		December 31, 2015		March 31, 2015
Cash flow hedges	5		5		9
Not designated as hedges	81		(14	)	231
Total volumes	86		(9	)	240
Short position – cash flow hedges	(6	)	(6	)	(6	)
Short position – not designated as hedges	(2,974	)	(3,089	)	(2,735	)
Long position – cash flow hedges	11		11		15
Long position – not designated as hedges	3,055		3,075		2,966
Net long (short) position	86		(9	)	240


(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)	99% of these contracts have durations of two years or less and 1% expire between two and five years.

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Derivative Instruments on our Unaudited Condensed Consolidated Balance Sheets

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



	Three Months Ended March 31,
In millions	2016			2015
Nicor Gas	$	(2	)	$	(3	)
Elizabethtown Gas	(6		)	(4		)

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



		March 31, 2016						December 31, 2015						March 31, 2015
In millions	Classification	Assets			Liabilities			Assets			Liabilities			Assets			Liabilities
Designated as cash flow hedges
Natural gas contracts	Current	$	1		$	(4	)	$	3		$	(5	)	$	—		$	(6	)
Natural gas contracts	Long-term	—			(1		)	—			(2		)	—			(1		)
Interest rate swap agreements	Current	—			(36		)	9			—			1			—
Interest rate swap agreements	Long-term	—			—			—			—			3			—
Total designated as cash flow hedges		$	1		$	(41	)	$	12		$	(7	)	$	4		$	(7	)
Not designated as hedges
Natural gas contracts	Current	$	419		$	(432	)	$	751		$	(672	)	$	557		$	(592	)
Natural gas contracts	Long-term	92			(83		)	179			(187		)	98			(109		)
Total not designated as hedges		$	511		$	(515	)	$	930		$	(859	)	$	655		$	(701	)
Gross amounts of recognized assets and liabilities ^{(1) (2)}		$	512		$	(556	)	$	942		$	(866	)	$	659		$	(708	)
Gross amounts offset on our unaudited Condensed Consolidated Balance Sheets⁽²⁾		(326		)	491			(724		)	820			(446		)	656
Net amounts of assets and liabilities presented on our unaudited Condensed Consolidated Balance Sheets⁽³⁾		$	186		$	(65	)	$	218		$	(46	)	$	213		$	(52	)


(1)	The gross amounts of recognized assets and liabilities are netted within our unaudited Condensed Consolidated Balance Sheets 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 $165 million as of March 31, 2016, $96 million as of December 31, 2015, and $210 million as of March 31, 2015. Cash collateral is included in the “Gross amounts offset on our unaudited Condensed Consolidated Balance Sheets” line of this table.


(3)	As of March 31, 2016, December 31, 2015, and March 31, 2015, we held letters of credit from counterparties that under master netting arrangements would offset an insignificant portion of these assets.

Derivative Instruments on the Unaudited Condensed Consolidated Statements of Income

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



	Three Months Ended March 31,
In millions	2016			2015
Designated as cash flow hedges ⁽¹⁾
Natural gas contracts - net loss reclassified from OCI into cost of goods sold	$	—		$	(1	)
Interest rate swaps - net gain reclassified from OCI into interest expense	1			1
Total designated as cash flow hedges, net of tax	1			—
Not designated as hedges ⁽¹⁾
Natural gas contracts - net fair value adjustments recorded in operating revenues	20			(24		)
Natural gas contracts - net fair value adjustments recorded in cost of goods sold ⁽²⁾	(1		)	(2		)
Income tax	(7		)	10
Total not designated as hedges, net of tax	12			(16		)
Total gains (losses) on derivative instruments, net of tax	$	13		$	(16	)


(1)	Associated with the fair value of derivative instruments held at March 31, 2016 and 2015.


(2)	Excludes gains (losses) recorded in cost of goods sold associated with weather derivatives of $3 million and $(2) million for the three months ended March 31, 2016 and 2015, respectively, as they are accounted for based on intrinsic value rather than fair value.

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 months ended March 31, 2016 and 2015. Our expected net losses to be

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reclassified from OCI into cost of goods sold, operation and maintenance expense, interest expense and operating revenues to be recognized on our unaudited Condensed Consolidated Statements of Income over the next 12 months are $4 million. These deferred losses are related to natural gas derivative contracts associated with retail operations’ and Nicor Gas’ system use and our interest rate swaps. The expected losses are based upon the fair values of these financial instruments at March 31, 2016. The effective portions of gains and losses on derivative instruments qualifying as cash flow hedges that were recognized in OCI during the periods are presented on our unaudited Condensed Consolidated Statements of Income. See Note 9 for these amounts.

There have been no other significant changes to our derivative instruments, as described in Note 3, Note 5, Note 6 and Note 10 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K.

Note 7 - Employee Benefit Plans

Pension Benefits

We sponsor the AGL Resources Inc. Retirement Plan, a tax-qualified defined benefit retirement plan for our eligible employees, which is described in Note 7 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. Following are the components of our pension costs for the periods indicated.



	Three Months Ended March 31,
In millions	2016			2015
Service cost ⁽¹⁾	$	6		$	7
Interest cost ⁽¹⁾	10			11
Expected return on plan assets	(16		)	(16		)
Net amortization of prior service credit	—			(1		)
Recognized actuarial loss	6			8
Net periodic pension benefit cost	$	6		$	9

(1) Effective January 1, 2016, we use a spot rate approach to estimate the service cost and interest cost components. Historically, we estimated these components using a single weighted-average discount rate.

Welfare Benefits

The benefits of our Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. are described in Note 7 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. Following are the components of our welfare costs for the periods indicated.



	Three Months Ended March 31,
In millions	2016			2015
Service cost ⁽¹⁾	$	1		$	1
Interest cost ⁽¹⁾	3			3
Expected return on plan assets	(2		)	(2		)
Net amortization of prior service credit	(1		)	—
Recognized actuarial loss	1			1
Net periodic welfare benefit cost	$	2		$	3

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Note 8 - Debt and Credit Facilities

The following table provides maturity dates or ranges, year-to-date weighted average interest rates and amounts outstanding for our various debt securities and facilities for the periods presented. We fully and unconditionally guarantee all debt issued by AGL Capital and the gas facility revenue bonds issued by Pivotal Utility. Additionally, substantially all of Nicor Gas' properties are subject to the lien of the indenture securing its first mortgage bonds. For additional information on our debt and credit facilities, see Note 9 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K.



		March 31, 2016								March 31, 2015
Dollars in millions	Year(s) due	Weighted average interest rate ⁽¹⁾		Outstanding			December 31, 2015			Weighted average interest rate ⁽¹⁾		Outstanding
Short-term debt
Commercial paper - AGL Capital ⁽²⁾	2016	0.8	%	$	204		$	471		0.5	%	$	176
Commercial paper - Nicor Gas ⁽²⁾	2016	0.6		353			539			0.4		350
Total short-term debt		0.7	%	$	557		$	1,010		0.4	%	$	526
Current portion of long-term debt	2016	5.2	%	$	470		$	545		2.9	%	$	75
Long-term debt - excluding current portion
Senior notes	2018-2043	4.9	%	$	2,455		$	2,455		5.0	%	$	2,625
First mortgage bonds	2019-2038	5.9		375			375			6.0		425
Gas facility revenue bonds	2022-2033	1.1		200			200			0.8		200
Medium-term notes	2017-2027	7.8		181			181			7.8		181
Total principal long-term debt		4.8	%	$	3,211		$	3,211		4.9	%	$	3,431
Unamortized fair value adjustment of long-term debt	n/a	n/a		66			68			n/a		77
Unamortized debt premium, net	n/a	n/a		16			16			n/a		16
Unamortized debt issuance costs	n/a	n/a		(20		)	(20		)	n/a		(19		)
Total non-principal long-term debt	n/a	n/a		$	62		$	64		n/a		$	74
Total long-term debt - excluding current portion				$	3,273		$	3,275				$	3,505
Total debt				$	4,300		$	4,830				$	4,106


(1)	Interest rates are calculated based on the daily weighted average balance outstanding for the three months ended March 31, 2016 and 2015.


(2)	As of March 31, 2016, the effective interest rates on our commercial paper borrowings were 0.8% for AGL Capital and 0.6% for Nicor Gas.

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 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 three months of 2016, our commercial paper maturities ranged from 1 to 59 days, and at March 31, 2016, remaining terms to maturity ranged from 1 to 46 days. During the first three months of 2016, there were no commercial paper issuances with original maturities over three months.

Long-Term Debt

On February 1, 2016, $75 million of Nicor Gas first mortgage bonds matured and were repaid using the proceeds from commercial paper borrowings.

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 our senior note issuance in the fourth quarter of 2015 and our anticipated issuances in 2016. We have designated the forward-starting interest rate swaps, which are settled on the respective debt issuance dates, as cash flow hedges. We settled $200 million of these interest rate swaps on November 18, 2015, in conjunction with the aforementioned senior note issuance. We performed a qualitative assessment of effectiveness on the remaining interest rate swaps as of March 31, 2016 and concluded that the remaining hedges are highly effective.

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. The following table contains our debt-to-capitalization ratios for the dates presented, which are below the maximum allowed.

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	AGL Resources						Nicor Gas
	March 31, 2016		December 31, 2015		March 31, 2015		March 31, 2016		December 31, 2015		March 31, 2015
Debt covenants ⁽¹⁾	50	%	54	%	50	%	47	%	56	%	54	%


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

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

Default Provisions

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


•	a maximum leverage ratio;


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


•	acceleration of other financial obligations; and


•	change of control provisions.

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

Note 9 - Equity

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



	2016									2015
In millions ⁽¹⁾	Cash flow hedges			Retirement benefit plans			Total			Cash flow hedges			Retirement benefit plans			Total
For the three months ended March 31
As of beginning of period	$	2		$	(188	)	$	(186	)	$	(6	)	$	(200	)	$	(206	)
OCI, before reclassifications	(29		)	—			(29		)	2			—			2
Amounts reclassified from accumulated OCI	(1		)	3			2			—			3			3
Net current-period other comprehensive (loss) income	(30		)	3			(27		)	2			3			5
As of end of period	$	(28	)	$	(185	)	$	(213	)	$	(4	)	$	(197	)	$	(201	)


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

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



	Three Months Ended March 31,
In millions⁽¹⁾	2016			2015
Cash flow hedges:
Cost of goods sold (natural gas contracts)	$	—		$	(1	)
Interest expense (interest rate contracts)	1			1
Total cash flow hedges, net of income tax	1			—
Retirement benefit plans:
Operation and maintenance expense (actuarial losses) ⁽²⁾	(5		)	(5		)
Total retirement benefit plans	(5		)	(5		)
Income tax benefit	2			2
Total retirement benefit plans, net of income tax	(3		)	(3		)
Total reclassification for the period	$	(2	)	$	(3	)


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


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

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Note 10 - Non-Wholly Owned Entities and Contingently Redeemable Noncontrolling Interest

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 11 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. Earnings from SouthStar in 2016 and 2015 were allocated entirely in accordance with the ownership interests.

On December 9, 2015, we notified Piedmont of our election, in accordance with the change in control provisions in the Second Amended and Restated Limited Liability Company Agreement of SouthStar, to purchase Piedmont’s remaining 15% interest in SouthStar at fair market value. This purchase is contingent upon the closing of the merger between Piedmont and Duke Energy Corporation, which is subject to various closing conditions that are beyond our control and is expected to be completed in 2016. On February 12, 2016, we and Piedmont agreed to various terms of this purchase, including a fair market value of $160 million. During the first quarter of 2016, we reclassified the noncontrolling interest related to Piedmont's 15% interest in SouthStar, whose redemption is beyond our control, as a contingently redeemable noncontrolling interest. Previously, this noncontrolling interest was included in equity. If our purchase of this noncontrolling interest is completed, the difference between the purchase price and the amount of noncontrolling interest will be recorded in equity.

A roll-forward of the contingently redeemable noncontrolling interest is detailed below:



In millions
Balance as of December 31, 2015	$	—
Reclassification of noncontrolling interest	46
Net income attributable to noncontrolling interest	11
Distribution to noncontrolling interest	(19		)
Balance as of March 31, 2016	$	38

Cash flows used in our investing activities include capital expenditures for SouthStar of $1 million and $1 million for the three months ended March 31, 2016 and 2015, respectively. Cash flows used in our financing activities include SouthStar’s distribution to Piedmont for its portion of SouthStar’s annual earnings from the previous year, which generally occurs in the first quarter of each fiscal year. For the three months ended March 31, 2016 and 2015, SouthStar distributed $19 million and $18 million, respectively, to Piedmont. SouthStar’s counterparties have no recourse to our general credit beyond our corporate guarantees that we have provided to SouthStar’s counterparties and natural gas suppliers. The following table provides additional information on SouthStar’s assets and liabilities as of the dates presented. The SouthStar amounts exclude intercompany eliminations and the balances of our wholly-owned subsidiary with an 85% ownership interest in SouthStar.



	March 31, 2016						December 31, 2015						March 31, 2015
In millions	Consolidated		SouthStar		%		Consolidated		SouthStar		%		Consolidated		SouthStar		%
Current assets	$	1,537	$	177	12	%	$	2,115	$	245	12	%	$	2,079	$	182	9	%
Goodwill and other intangible assets	1,918		113		6		1,922		114		6		1,943		119		6
Long-term assets and other deferred debits	10,881		17		—		10,717		16		—		10,097		17		—
Total assets	$	14,336	$	307	2	%	$	14,754	$	375	3	%	$	14,119	$	318	2	%
Current liabilities	$	2,489	$	41	2	%	$	3,000	$	54	2	%	$	2,371	$	46	2	%
Long-term liabilities and other deferred credits	7,777		1		—		7,779		—		—		7,784		1		—
Total liabilities	10,266		42		—		10,779		54		1		10,155		47		—
Contingently redeemable noncontrolling interest	38		—		—		—		—		—		—		—		—
Equity	4,032		265		7		3,975		321		8		3,964		271		7
Total liabilities, redeemable noncontrolling interest and equity	$	14,336	$	307	2	%	$	14,754	$	375	3	%	$	14,119	$	318	2	%

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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 March 31,
In millions	2016		2015
Operating revenues	$	254	$	311
Operating expenses
Cost of goods sold	157		203
Operation and maintenance	22		23
Depreciation and amortization	2		2
Taxes other than income taxes	—		1
Total operating expenses	181		229
Operating income	$	73	$	82

Equity Method Investments

For more information about our equity method investments, see Note 11 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K.

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



	March 31,		December 31,		March 31,
In millions	2016		2015		2015
Triton	$	48	$	49	$	57
Horizon Pipeline	14		14		14
PennEast Pipeline	12		9		2
Atlantic Coast Pipeline	9		7		3
Other	1		1		—
Total	$	84	$	80	$	76

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



	Three Months Ended March 31,
In millions	2016		2015
Horizon Pipeline	$	1	$	1

Note 11 - Commitments, Guarantees and Contingencies

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

We are also involved in legal or administrative proceedings before various courts and agencies with respect to general claims, environmental remediation and other matters. While 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 12 to our consolidated financial statements and related notes included in Item 8 of our 2015 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 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

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Illinois Commission and the CUB were based on hindsight speculation, which is expressly prohibited in a prudence review examination. In November 2015, the Illinois Commission granted the CUB's petition for a rehearing on this matter. In February 2016, the Administrative Law Judge issued a proposed order on the rehearing affirming the original order by the Illinois Commission, which was approved by the Illinois Commission in March 2016.

Environmental Matters

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control that require us to remove or remedy the effect on the environment of the disposal or release of specified substances at our current and former operating sites. See Note 4 herein for additional information on our environmental remediation costs.

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

Litigation

We are involved in litigation arising in the normal course of business. Although in some cases we are unable to estimate the amount of loss reasonably possible in addition to any amounts already recognized, it is possible that the resolution of these 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 possibly be material to earnings in a particular quarter, they will not have a material adverse effect on our consolidated balance sheets or cash flows for the year. For additional litigation information, see Note 12 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K.

Note 12 - Segment Information

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

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 have similar economic and risk characteristics as they are regulated utilities with rates determined by individual state regulatory agencies.

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 segment includes subsidiaries that 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 President 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 (loss) and other income and expenses and excludes income taxes and interest expense, which we evaluate on a consolidated basis. Summarized statements of income, balance sheets and capital expenditure information by segment as of, and for the periods presented, are shown in the following tables.

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Three months ended March 31, 2016



In millions	Distribution operations		Retail operations		Wholesale services⁽¹⁾		Midstream operations			Other			Intercompany eliminations			Consolidated
Operating revenues from external parties	$	983	$	286	$	63	$	15		$	2		$	(15	)	$	1,334
Intercompany revenues	45		—		—		—			—			(45		)	—
Total operating revenues	1,028		286		63		15			2			(60		)	1,334
Operating expenses
Cost of goods sold	464		162		3		6			—			(57		)	578
Operation and maintenance	185		37		16		7			(2		)	(2		)	241
Depreciation and amortization	89		6		—		4			3			—			102
Taxes other than income taxes	56		1		1		1			3			—			62
Merger-related expenses	—		—		—		—			3			—			3
Total operating expenses	794		206		20		18			7			(59		)	986
Operating income (loss)	234		80		43		(3		)	(5		)	(1		)	348
Other income	—		—		1		2			—			—			3
EBIT	$	234	$	80	$	44	$	(1	)	$	(5	)	$	(1	)	$	351
Total assets	$	12,405	$	717	$	723	$	715		$	9,342		$	(9,566	)	$	14,336
Capital expenditures	$	204	$	2	$	—	$	18		$	11		$	—		$	235

Three months ended March 31, 2015



In millions	Distribution operations		Retail operations		Wholesale services ⁽¹⁾		Midstream operations			Other			Intercompany eliminations			Consolidated
Operating revenues from external parties	$	1,285	$	341	$	90	$	19		$	6		$	(20	)	$	1,721
Intercompany revenues	56		—		—		—			—			(56		)	—
Total operating revenues	1,341		341		90		19			6			(76		)	1,721
Operating expenses
Cost of goods sold	776		210		9		10			5			(75		)	935
Operation and maintenance	185		37		24		6			(2		)	(1		)	249
Depreciation and amortization	82		6		—		5			4			—			97
Taxes other than income taxes	71		1		1		1			2			—			76
Total operating expenses	1,114		254		34		22			9			(76		)	1,357
Operating income (loss)	227		87		56		(3		)	(3		)	—			364
Other income	1		—		—		1			1			—			3
EBIT	$	228	$	87	$	56	$	(2	)	$	(2	)	$	—		$	367
Total assets	$	11,896	$	698	$	1,100	$	693		$	9,036		$	(9,304	)	$	14,119
Capital expenditures	$	170	$	2	$	1	$	3		$	12		$	—		$	188


(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 are 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 March 31, 2016	$	1,443	81	1,524	1,461	$	63
Three months ended March 31, 2015	$	2,146	150	2,296	2,206	$	90

Identifiable assets are those used in each segment’s operations. Information by segment on our Consolidated Balance Sheet as of December 31, 2015, is as follows:



In millions	Distribution operations		Retail operations		Wholesale services		Midstream operations		Other		Intercompany eliminations			Consolidated
Total assets	$	12,517	$	686	$	935	$	692	$	9,664	$	(9,740	)	$	14,754

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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 2015 Form 10-K. Results for the interim periods presented are not necessarily indicative of the results to be expected for the full fiscal period due to seasonal and other factors.

Forward-Looking Statements

Certain expectations and projections regarding our future performance referenced in this section and elsewhere in this report, as well as in other reports and proxy statements we file with the SEC or otherwise release to the public and on our website, are forward-looking statements and are subject to uncertainties and risks. Senior officers and other employees may also make verbal statements to analysts, investors, regulators, the media and others that are forward-looking.

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

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


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


•	the possibility that the proposed merger does not close due to the failure to satisfy the closing conditions, including, but not limited to, a failure to obtain the remaining required regulatory approvals;


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


•	disruption from the proposed merger making it more difficult to maintain our business and operational relationships and the risk that unexpected costs will be incurred during this process;


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


•	the timing of our last quarterly dividend to holders of our common stock, if any, declared prior to the potential closing of the proposed merger with Southern Company;


•	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, including our pipeline projects, from government and other approvals, project delays, adequacy of supply of diversified vendors and unexpected changes in project costs;


•	the cost of funds to finance our construction projects and our ability to recover certain 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 weather 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;


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


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

There also may be other factors that we do not anticipate or that we do not recognize as material that could cause results to differ materially from our expectations. Forward-looking statements speak only as of the date they are made. We expressly

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disclaim any obligation to update or revise any forward-looking statement, whether as a result of future events, new information or otherwise, except as required by law.

Executive Summary

We are an energy services holding company whose principal business is the safe, reliable and cost-effective 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 businesses that are complementary to our primary business. We have four reportable segments – distribution operations, retail operations, wholesale services and midstream operations - and one non-reportable segment – other. These segments are consistent with how management views and operates our business. For additional information on our reportable segments, see Note 12 to our unaudited condensed consolidated financial statements under Part I, Item 1 herein and Item 1, “Business” of our 2015 Form 10-K.

Proposed Merger With Southern Company In August 2015, we entered into the Merger Agreement with Southern Company, which, based on the number of common shares and the fair value of debt outstanding as of March 31, 2016, reflects an estimated business enterprise value of AGL Resources of $12.7 billion that includes an equity value of $8.0 billion. When the merger becomes effective, which is expected to occur in the second half of 2016, each share of our common stock, other than certain excluded shares, will convert into the right to receive $66 in cash, without interest, less any applicable withholding taxes. Completion of the merger is conditioned upon, among other things, the approval of certain state regulatory agencies. At closing, the transaction is expected to create the second largest utility in the U.S. based on customer base, and we will become a wholly owned subsidiary of Southern Company, but continue to maintain our own management team.

To date, the proposed merger has been approved by the Maryland Commission, the Georgia Commission, the California Public Utilities Commission, the Virginia Commission and our shareholders. Additionally, we received consent from the Federal Communications Commission to transfer parent company control of radio licenses held by certain of our subsidiaries, and the waiting period under the Hart-Scott-Rodino Act has expired.

For additional information relating to this transaction, see Note 2 to our unaudited condensed consolidated financial statements under Part I, Item 1 herein and the definitive proxy statement contained in Schedule 14A filed with the SEC on October 13, 2015.

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

•

Distribution Operations: Invest necessary capital to enhance and maintain safety and reliability in delivering natural gas; remain an efficiency leader within the industry while maintaining a focus on customer satisfaction; expand the natural gas distribution system and educate energy consumers on the benefits of converting to natural gas. We continue to invest in our regulatory infrastructure programs to minimize the lag in recovery of our capital expenditures. Additionally, we continue to effectively manage our costs and leverage our shared services model across our businesses to combat inflationary effects.

Nicor Gas In July 2014, the Illinois Commission approved our nine-year regulatory infrastructure program, Investing in Illinois, under which we implemented monthly surcharge rates beginning March 2015. As of March 31, 2016, we have placed into service $276 million of qualifying assets under this program, $26 million of which was related to the first quarter of 2016. We expect to invest $281 million during 2016.

Atlanta Gas Light Atlanta Gas Light's Strategic Infrastructure Development and Enhancement (STRIDE) program, which started in 2009, consists of three individual programs that update and expand distribution systems and liquefied natural gas facilities as well as improve system reliability to meet operational flexibility and customer growth. Through the programs under STRIDE, we expect to invest $169 million during 2016, $30 million of which was incurred during the first quarter of 2016.

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

The New Jersey BPU approved the extension of our Aging Infrastructure Replacement (AIR) program in August 2013, under which we expect to invest $29 million in 2016, $7 million of which was incurred during the first quarter of 2016. As part of this approval, we agreed and are on track to file a general rate case by September 2016.

Virginia Natural Gas In March 2016, the Virginia State Commission approved the SAVE II infrastructure replacement project, under which Virginia Natural Gas expects to invest $30 million on qualifying infrastructure projects in 2016, $7 million of which was incurred during the first quarter of 2016, and up to $35 million annually thereafter through 2021 to replace more than 200 miles of aging pipeline infrastructure.

Florida City Gas The Florida Commission approved Florida City Gas' Safety, Access and Facility Enhancement (SAFE) program in September 2015. Under the program, Florida City Gas will spend approximately $10 million

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annually over a 10-year period on infrastructure relocation and enhancement projects. Expenditures of $1 million were incurred during the first quarter of 2016. Costs incurred under the program will be recovered through a rate rider with annual rate adjustments and true-ups.


•	Retail Operations: Maintain our current customer base in Georgia and Illinois while continuing to expand into other profitable retail markets and expand our warranty businesses through partnership opportunities with affiliates and third parties. We will focus on products that are responsive to our customers' needs.

We entered into an agreement with Piedmont to purchase its remaining 15% interest in SouthStar for $160 million. This transaction is contingent upon the closing of the merger between Piedmont and Duke Energy Corporation, which is expected to occur in 2016.


•	Wholesale Services: 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 relative to other marketers.

•

Midstream Operations: Invest in natural gas based projects, some of which remain subject to regulatory approvals, along with our existing pipelines and storage facilities to 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.

During the first quarter of 2016, FERC staff announced that it intends to release the final environmental review for the PennEast Pipeline project in December 2016. Given this updated timing, we expect to receive FERC approval in 2017.

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 may not be designated, for hedge accounting treatment. As a result, our reported earnings for wholesale services, retail operations and midstream operations reflect changes in the fair values of certain derivatives. A general 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.

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 in 2016 as compared to 2015 primarily due to lower volumes of gas sold to customers and hedge losses due to weather in the first three months of 2016 that was warmer than the colder-than-normal weather in the first three months of 2015 and the resulting lower natural gas prices in 2016 compared to 2015.

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 and certain incentive compensation costs, are incurred relatively evenly over any given year, resulting in variability in the quarterly pattern of earnings.

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

We believe that the presentation of operating margin provides useful information to management and investors regarding 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 further believe that operating margin at our retail operations, wholesale services and midstream operations segments allows us to focus on a direct measure of operating margin before overhead costs.

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We present the non-GAAP measure of diluted earnings per share - as adjusted, which excludes merger-related expenses as we do not regularly engage in transactions of the magnitude of the proposed merger with Southern Company. Consequently, we do not regularly incur merger expenses and believe that presenting diluted earnings per share excluding merger-related expenses provides investors with an additional measure of our core operating performance.

Operating margin and diluted earnings per share - as adjusted should not be considered as alternatives to, or more meaningful indicators of, our operating performance than net income attributable to AGL Resources, operating income or diluted earnings per share as determined in accordance with GAAP. In addition, our operating margin and diluted earnings per share - as adjusted may not be comparable to similarly titled measures of other companies.

Summary of Results:

The table below reconciles (i) operating revenues and operating margin to operating income, (ii) EBIT to income before income taxes and net income and (iii) diluted earnings per share - as adjusted to diluted earnings per common share as calculated in accordance with GAAP, together with other consolidated financial information for the periods presented.



	Three months ended March 31,
In millions, except per share amounts	2016			2015			Change
Operating revenues	$	1,334		$	1,721		$	(387	)
Cost of goods sold	(578		)	(935		)	357
Revenue tax expense ⁽¹⁾	(39		)	(55		)	16
Operating margin	717			731			(14		)
Operating expenses ⁽²⁾	(408		)	(422		)	14
Revenue tax expense ⁽¹⁾	39			55			(16		)
Operating income	348			364			(16		)
Other income	3			3			—
EBIT	351			367			(16		)
Interest expense, net	(47		)	(44		)	(3		)
Income before income taxes	304			323			(19		)
Income tax expense	(111		)	(118		)	7
Net income	193			205			(12		)
Less net income attributable to noncontrolling interest	11			12			(1		)
Net income attributable to AGL Resources	$	182		$	193		$	(11	)
Per common share data
Diluted earnings per common share	$	1.51		$	1.62		$	(0.11	)
Merger-related expenses	$	0.02		$	—		$	0.02
Diluted earnings per common share - as adjusted	$	1.53		$	1.62		$	(0.09	)


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


(2)	Operating expenses for the three months ended March 31, 2016 include $3 million of merger-related expenses.

2016 Results For the first quarter of 2016, our net income attributable to AGL Resources was $182 million, a decrease of $11 million compared to the same period in 2015. This decrease was due primarily to lower consolidated EBIT of $16 million largely driven by a $22 million negative weather impact, net of hedge costs, due to warmer-than-normal weather during 2016 compared to colder-than-normal weather in 2015, a $12 million EBIT decrease at wholesale services and $3 million in merger-related expenses in 2016. The remaining net EBIT increase of $21 million in 2016 over 2015 was due primarily to higher operating margin at distribution operations from infrastructure programs and increased non-weather consumption through usage and customer growth. Further discussion of the year-over-year drivers are detailed at the segment level within "Results of Operations" below.

Results of Operations

Operating Metrics

Weather We measure weather and its effect on our business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for gas on our distribution systems. With the exception of Nicor Gas and Florida City Gas, we have regulatory mechanisms, such as weather normalization, which limit our exposure to weather changes within typical ranges in each of our utilities’ respective service areas. However, our utility customers in Illinois and our retail operations customers primarily in Georgia can be impacted by warmer- or colder-than-normal weather. Additionally, we utilize weather hedges to reduce negative earnings impacts in the event of warmer-than-normal weather, while retaining all of the earnings upside in the event of colder-than-normal weather for distribution operations in Illinois and most of the earnings upside for our retail operations. We also consider operating costs that may vary with the effects of weather, particularly in periods that are significantly colder-than-normal. The following table presents the Heating Degree Days information for those locations.

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	Three months ended March 31,			2016 vs. 2015		2016 vs. normal
	Normal ⁽¹⁾	2016	2015	warmer		warmer
Illinois ⁽²⁾	3,097	2,701	3,357	(20	)%	(13	)%
Georgia	1,484	1,334	1,592	(16	)%	(10	)%


(1)	Normal represents the 10-year average from January 1, 2006 through March 31, 2015 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 2,902 for the first three months from 1998 through 2007.

In the first quarter of 2016, the unfavorable weather-related EBIT impact from the warmer-than-normal weather on distribution operations was limited to $6 million, net of the impact of our weather hedging. Our retail operations in Georgia did not experience an unfavorable weather-related EBIT impact in the current quarter. The total net unfavorable weather impact on the first quarter of 2016 was $5 million, compared to a $17 million favorable weather impact for the same period in 2015, when weather was significantly colder-than-normal.

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 for the specified periods.



	Three months ended March 31,				2016 vs. 2015
In thousands	2016		2015		% change
Distribution operations	4,585		4,557		0.6	%
Retail operations
Energy customers	658		637		3.3	%
Service contracts ⁽¹⁾	1,201		1,159		3.6	%
Market share of energy customers in Georgia	29.3	%	30.0	%

(1) Includes approximately 43,000 customer warranty contracts acquired in Connecticut and Massachusetts during the second half of 2015.

We anticipate overall customer growth trends at distribution operations for 2016 to continue improving based on an expectation of continued improvement in the housing market and continued low natural gas prices.

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

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



	Three months ended March 31,		2016 vs. 2015
	2016	2015	% change
Distribution operations (In Bcf)
Firm	289	345	(16.2	)%
Interruptible	26	27	(3.7	)
Total	315	372	(15.3	)%
Retail operations (In Bcf)
Firm:
Georgia	17	19	(10.5	)%
Illinois	6	8	(25.0	)
Other emerging markets	5	4	25.0
Interruptible:
Large commercial and industrial customers	4	4	—
Total	32	35	(8.6	)%
Wholesale services
Daily physical sales (Bcf/day)	7.9	7.8	1.3	%

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 its investments.

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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. 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 liquefied natural gas, and projected demand increases in response to low prices and expanded uses for natural gas. Annual subscription rates are typically recontracted on March 31 of each fiscal year and the following table illustrates the overall monthly average firm subscription rates per storage facility and the amount of firm capacity subscription as of April 1, 2016 and 2015. These amounts exclude 5.0 Bcf contracted by Sequent as of April 1, 2015, at an average monthly rate of $0.070. Sequent had no capacity subscribed as of April 1, 2016.



	April 1, 2016			April 1, 2015
	Average rates (per dekatherm)		Firm capacity under subscription (Bcf)	Average rates (per dekatherm)		Firm capacity under subscription (Bcf)
Jefferson Island	$	0.103	2.2	$	0.092	4.2
Golden Triangle⁽¹⁾	0.051		2.5	0.098		7.0
Central Valley	0.058		2.5	0.047		4.0

(1) The 2016 decline in rates is the result of a 2 Bcf contract at $0.24 that expired in August 2015. The 2016 decrease in capacity subscribed is due to delayed re-contracting until the second half of 2016 to allow for completion of routine maintenance activities. However, we have contracted 5 Bcf at an average rate of $0.06 to start in the second half of the year of which 2.75 Bcf at an average rate of $0.054 relates to capacity contracted by Sequent.

Segment information Operating margin, operating expenses and EBIT information for each of our segments is contained in the table below.



	Three months ended March 31, 2016									Three months ended March 31, 2015
In millions	Operating margin ^{(1) (2)}			Operating expenses ^{(2) (3)}			EBIT^{(1) (3)}			Operating margin ^{(1) (2)}			Operating expenses ⁽²⁾			EBIT⁽¹⁾
Distribution operations	$	525		$	291		$	234		$	510		$	283		$	228
Retail operations	124			44			80			131			44			87
Wholesale services	60			17			44			81			25			56
Midstream operations	9			12			(1		)	9			12			(2		)
Other	2			7			(5		)	1			4			(2		)
Intercompany eliminations	(3		)	(2		)	(1		)	(1		)	(1		)	—
Consolidated	$	717		$	369		$	351		$	731		$	367		$	367


(1)	A reconciliation of operating revenue and operating margin to operating income, and EBIT to income before income taxes and net income is contained in “Results of Operations” herein.


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


(3)	Includes $3 million of merger-related expenses recorded within our other segment.

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 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 and weather derivative instruments, that limit our exposure to weather changes within typical ranges in their respective service areas. For the three months ended March 31, 2016, distribution operations’ EBIT increased by $6 million, or 3%, compared to the same period during the prior year, as shown in the following table.

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In millions	Three months ended
EBIT - March 31, 2015	$	228
Operating margin
Increase from regulatory infrastructure programs, primarily at Atlanta Gas Light and Nicor Gas	17
Increase mainly driven by non-weather-related customer usage and growth	7
Increase in rider program recoveries at Nicor Gas, offset by operating expenses below	6
Decrease in weather-related customer usage, net of weather hedges	(15		)
Increase in operating margin	15
Operating expenses
Increase in rider program recoveries at Nicor Gas, offset by operating margin above	6
Increase in depreciation expense primarily due to additional assets placed in service	6
Increase in outside services expenses primarily due to legal and other services	2
Decrease in benefit expenses primarily related to lower pension costs in 2016	(2		)
Decrease in variable incentive compensation costs	(4		)
Increase in operating expenses	8
Decrease in other income primarily due to tax gross-up of contributions received	(1		)
EBIT - March 31, 2016	$	234

Retail Operations

Our retail operations segment consists of several businesses that provide energy related products and services to retail markets. Retail operations is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to partially mitigate potential weather impacts. For the three months ended March 31, 2016, retail operations’ EBIT decreased by $7 million, compared to the same period during the prior year, as shown in the following table.



In millions	Three months ended
EBIT - March 31, 2015	$	87
Operating margin
Lower cost of goods sold partially offset by lower customer count	4
Acquisition of warranty service contracts in the second half of 2015 and improved warranty margins	3
LOCOM adjustments, net of recoveries	(1		)
Offset of prior period hedge losses	(5		)
Decrease in weather-related customer usage, net of weather hedging	(6		)
Other	(2		)
Decrease in operating margin	(7		)
Operating expenses
Increase in outside services and marketing expenses	1
Decrease in bad debt expenses primarily related to lower gas prices and warmer weather	(1		)
Increase in operating expenses	—
EBIT - March 31, 2016	$	80

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 2015, we are well positioned to capture significant value and generate stronger results. For the three months ended March 31, 2015, wholesale services delivered strong EBIT due to increased levels of

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volatility in commodity and transportation prices. For the three months ended March 31, 2016, EBIT decreased by $12 million compared to the same period last year, as shown in the following table.



In millions	Three months ended
EBIT - March 31, 2015	$	56
Operating margin
Change in value of transportation and forward commodity derivatives from price movements related to natural gas transportation positions	50
Change in LOCOM adjustment	5
Change in value of storage derivatives as a result of changes in NYMEX natural gas prices	(6		)
Change in commercial activity driven by lower price volatility	(70		)
Decrease in operating margin	(21		)
Operating expenses
Decrease in variable incentive compensation costs driven by variance in earnings compared to prior year	(8		)
Decrease in operating expenses	(8		)
Increase in other income due to tax refund settlement	1
EBIT - March 31, 2016	$	44

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



	Three months ended March 31,
In millions	2016			2015
Commercial activity recognized	$	43		$	113
(Loss) gain on storage derivatives	(2		)	4
Gain (loss) on transportation and forward commodity derivatives	22			(28		)
Inventory LOCOM adjustment, net of estimated current period recoveries	(3		)	(8		)
Operating margin	$	60		$	81

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 months ended March 31, 2016, commercial activity decreased due to:


•	Lower price volatility as compared to last year due to the colder-than-normal weather in 2015; and


•	Higher operating margin of $8 million resulting from the withdrawal of storage inventory hedged at the end of 2015 that was included in the storage withdrawal schedule.

While we experienced unusually high and low volatility in natural gas prices in early 2015 and 2016, respectively, due partly to weather, in the near term we anticipate low volatility in certain areas of our portfolio. 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 existing supply constraints in the shale areas of the Northeast U.S. To the extent these pipelines are delayed or not built, volatility could increase. Natural gas supply increases during the 2015/2016 Heating Season along with the warmer-than-normal weather we experienced resulted in record natural gas inventories that contributed to reduced natural gas prices. 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 or 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 little price volatility in 2016 to benefit wholesale services’ portfolio of pipeline transportation and storage capacity assets throughout the country. Although we do not expect a high level of price volatility, we see the potential for market fundamentals indicating some level of increased volatility that would potentially benefit wholesale services’ portfolio of pipeline transportation capacity should this occur. The storage derivative gains for the three months ended March 31, 2016 are primarily due to a decline in natural gas prices applicable to the locations of our specific storage assets. Gains in our transportation and forward commodity derivative positions for the first three months of 2016 are the result primarily of narrowing transportation basis spreads associated with warmer-than-normal weather in the first quarter of 2016 and lower demand, which impacted forward prices at natural gas receipt and delivery points, primarily in the Northeast region. These gains are temporary and more than half is expected to be realized in 2016 and the balance thereafter with the physical flow of natural gas and utilization of the contracted transportation capacity at their lower rates.

Withdrawal schedule and physical transportation transactions The expected natural gas withdrawals from storage and expected offset to prior hedge losses/gains associated with the transportation portfolio of wholesale services are presented in the following table, along with the net operating revenues expected at the time of withdrawal from storage and the physical flow of

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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 March 31, 2016. A portion of wholesale services’ storage inventory and transportation capacity is economically hedged with futures contracts, which results in the realization of substantially fixed net operating revenues, timing notwithstanding.



	Storage withdrawal schedule
Dollars in millions	Total storage (in Bcf) (WACOG $1.99)	Expected net operating gains ⁽¹⁾		Physical transportation transactions – expected net operating losses ⁽²⁾
2016	27.0	$	5	$	(10	)
2017 and thereafter	13.9	10		(12		)
Total at March 31, 2016	40.9	$	15	$	(22	)


(1)	Represents expected operating gains 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) during which the derivatives will be settled and the physical transportation transactions will occur that offset the derivative (gains) recognized during the first three months of 2016.

The unrealized storage and transportation derivative gains do not change the underlying economic value of our storage and transportation positions and, based on current expectations, will primarily be reversed in the remainder of 2016 and 2017 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 2015 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 months ended March 31, 2016, midstream operations’ EBIT increased by $1 million compared to the same period during the prior year.

Other

Our "other" segment includes our investment in Triton, AGL Services Company and AGL Capital as well as various corporate operating expenses that we do not allocate to our reportable segments. For the three months ended March 31, 2016, such operating expenses included $3 million of merger-related expenses.

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 generally 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. For more information on the seasonality of our short-term borrowings, see "Short-term Debt" later in this section. 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, subject to certain limitations. We regularly evaluate our funding strategy and profile to ensure that we have sufficient liquidity for our short-term and long-term needs in a cost-effective manner.

Our financing activities, including long-term and short-term debt and equity, are subject to customary approval or review by the state regulatory agencies in which we conduct business as well as the FERC. 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 may be subject to regulation. By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. Additionally, Elizabethtown Gas is restricted by its dividend policy as established by the New Jersey BPU in the amount it can dividend to AGL Resources to the extent of 70% of its quarterly net income.

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

The ability to satisfy our working capital requirements and our debt service obligations, or fund planned capital expenditures, substantially depends upon our future operating performance (which will be affected by prevailing economic conditions) and

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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 March 31, 2016, our variable-rate debt was 21% of our total debt, compared to 28% as of December 31, 2015 and 21% as of March 31, 2015. The decrease from December 31, 2015 was primarily due to decreased commercial paper borrowings resulting from customer collections on winter sales of natural gas and other seasonal working capital needs.

On February 1, 2016, $75 million of Nicor Gas first mortgage bonds matured and were repaid using the proceeds from commercial paper borrowings.

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 our issuance of senior notes in the fourth quarter of 2015 and anticipated issuances of long-term debt in 2016. We designated the forward-starting interest rate swaps, which mature on the respective debt issuance dates, as cash flow hedges. We settled $200 million of these interest rate swaps on November 18, 2015. The remaining $600 million of interest rate swaps, which represent a fair value liability of $36 million as of March 31, 2016, are expected to be settled in 2016 as we issue long-term debt as planned. See Part I, Item 3, “Quantitative and Qualitative Disclosures About Market Risk,” under the caption “Interest Rate Risk” herein 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. Upon closing, if any, of the proposed merger with Southern Company, we do not expect to pay a prorated dividend. We have not yet determined the timing of our last quarterly dividend to existing public holders of our common stock, if any, declared prior to the potential closing of the proposed merger with Southern Company. See Item 1A, “Risk Factors,” in our 2015 Form 10-K for additional information on items that could impact our liquidity and capital resource requirements.

Capital Projects We continue to focus on capital discipline while moving forward with projects and initiatives that we expect will have current and future benefits to us and our customers, provide an appropriate return on invested capital and ensure the safety, reliability and integrity of our utility infrastructure. These capital projects update or expand our distribution systems to improve system reliability and meet operational flexibility and growth. Our anticipated expenditures for these programs in 2016 are discussed in “Liquidity and Capital Resources” under the caption "Cash Flow from Investing Activities" under Item 7 of our 2015 Form 10-K. For additional information on our capital projects, see Item 1 “Business” in our 2015 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	$	204	$	341	$	166	$	471
Commercial paper – Nicor Gas	353		494		353		550
Current portion of long-term debt	470		496		470		545
Total	$	1,027	$	1,331	$	989	$	1,566


(1)	As of March 31, 2016.


(2)	For the three months ended March 31, 2016.

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. Therefore, the total balances are not indicative of actual borrowings on any one day during the period.

As the current portions of long-term debt mature throughout the remainder of 2016, we expect to refinance the maturing bonds with new issuances of long-term debt.

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 $194 million change of working capital requirements during 2016. This range is sensitive to the timing of storage injections and withdrawals, collateral

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requirements and our portfolio position. Based upon our total debt outstanding as of March 31, 2016, and our maximum 70% debt to total capitalization allowed under our financial covenants, we could potentially borrow an additional $1.1 billion of commercial paper under the AGL Credit Facility and an additional $347 million of commercial paper under the Nicor Gas Credit Facility. As a result, based on current natural gas prices and our expected purchases as we make natural gas storage injections in advance of the upcoming Heating Season, we believe that we have sufficient liquidity to cover our working capital needs for the upcoming injection season.

Credit Ratings Our borrowing costs and our ability to obtain adequate and cost-effective financing are directly impacted by our credit ratings and 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 condensed consolidated balance sheets, leverage, capital spending, earnings, cash flow generation, available liquidity and overall business risks. We do not have any triggering events in our debt instruments that are tied to changes in our specified credit ratings or our stock price and have not entered into any agreements that would require us to issue equity based on credit ratings or other trigger events. A downgrade in our current ratings, particularly below investment grade, would increase our borrowing costs and could limit our access to the commercial paper market. In addition, we would likely be required to pay a higher interest rate in future financings, and our potential pool of investors and funding sources could decrease. The table below summarizes our credit ratings as of March 31, 2016, and reflects no change from December 31, 2015.

AGL Resources

Nicor Gas

S&P

Moody’s ⁽¹⁾

Fitch

S&P

Moody’s

Fitch

Corporate rating

BBB+

n/a

BBB+

n/a

Commercial paper

A-2

P-2

A-2

P-1

Senior unsecured

BBB+

Baa1

BBB+

A+

Senior secured

n/a

Aa3

AA-

Ratings outlook

Positive

Stable

Positive

Stable


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

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

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



	Three months ended March 31,
In millions	2016			2015			Variance
Net cash provided by (used in):
Operating activities	$	841		$	1,120		$	(279	)
Investing activities	(238		)	(184		)	(54		)
Financing activities	(602		)	(926		)	324
Net increase in cash and cash equivalents	1			10			(9		)
Cash and cash equivalents at beginning of period	19			31			(12		)
Cash and cash equivalents at end of period	$	20		$	41		$	(21	)

Cash Flow from Operating Activities Cash provided by operating activities decreased during the current period primarily due to lower usage of natural gas inventory during 2016 compared to 2015 as a result of warmer weather and the timing of recoveries of related gas costs and weather normalization adjustments from customers.

Cash Flow from Investing Activities The increased use of cash for our investing activities was the result of increased infrastructure investment, primarily relating to our infrastructure replacement programs as well as increased spending for other rate-based investments at distribution operations.

Cash Flow from Financing Activities The decreased use of cash for our financing activities was driven primarily by lower net repayments of debt during 2016 as a result of less cash from operations due to weather that was warmer in the first quarter of 2016 compared to the same period of 2015.

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

Critical Accounting Policies and Estimates

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

Our critical accounting estimates often involve complex situations that require a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. There have been no significant changes to our critical accounting estimates from those disclosed in our Management’s Discussion and Analysis of Financial Condition and Results of Operations as filed on our 2015 Form 10-K. Our critical accounting estimates used in the preparation of our unaudited condensed consolidated financial statements include those related to our accounting for:


•	Rate-Regulated Subsidiaries;


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


•	Derivatives and Hedging Activities;


•	Contingencies;


•	Pension and Welfare Plans; and


•	Income Taxes.

Accounting Developments

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Natural Gas Price Risk

The following tables include the fair values and average values of our consolidated derivative instruments as of the dates indicated. We base the average values on monthly averages for the three months ended March 31, 2016 and 2015.



	Derivative instruments average values for the three months ended ⁽¹⁾
In millions	March 31, 2016		March 31, 2015
Asset	$	189	$	208
Liability	102		118

(1) Excludes cash collateral amounts.

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	Derivative instruments fair values netted with cash collateral at
In millions	March 31, 2016		December 31, 2015		March 31, 2015
Asset	$	186	$	218	$	213
Liability	65		46		52

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 March 31,
In millions	2016			2015
Net fair value of derivative instruments outstanding at beginning of period	$	75		$	61
Derivative instruments realized or otherwise settled during period	(85		)	(70		)
Change in net fair value of derivative instruments	(34		)	(40		)
Net fair value of derivative instruments outstanding at end of period	(44		)	(49		)
Netting of cash collateral	165			210
Cash collateral and net fair value of derivative instruments outstanding at end of period ⁽¹⁾	$	121		$	161


(1)	Net fair value of derivative instruments outstanding includes $9 million and $1 million premium and associated intrinsic value at March 31, 2016 and 2015, respectively, associated with weather derivatives.

The sources of our net fair value at March 31, 2016, are as follows.



In millions	Prices actively quoted (Level 1) ⁽¹⁾			Significant other observable inputs (Level 2) ⁽²⁾
Mature through 2016	$	(73	)	$	27
Mature 2017 - 2018	(15		)	22
Mature 2019 and thereafter	(8		)	3
Total derivative instruments ⁽³⁾	$	(96	)	$	52


(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 companies 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.

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 three months ended March 31, 2016 and 2015 was less than $0.1 million and wholesale services had the following VaRs.



	Three months ended March 31,
In millions	2016		2015
Period end	$	2.2	$	4.2
Average	1.9		4.1
High	2.5		7.3
Low	1.6		2.9

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 $877 million of variable-rate debt outstanding at March 31, 2016, a 100 basis point change in market interest rates would have resulted in an increase in pre-tax interest expense of $8 million on an annualized basis.

We utilize interest rate swaps to help us achieve our desired mix of variable to fixed-rate debt. Our variable-rate debt target generally ranges from 20% to 45% of total debt. We also use forward-starting interest rate swaps and interest rate lock agreements to lock in fixed interest rates on our forecasted issuances of debt. The objective of these hedges is to offset the variability of future payments associated with the interest rate on debt instruments we expect to issue. The gain or loss on the

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interest rate swaps designated as cash flow hedges is generally deferred in accumulated OCI until settlement, at which point it is amortized to interest expense over the life of the related debt. For additional information, see Note 6 to our unaudited condensed consolidated financial statements included under Part I, 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 our senior note issuance in the fourth quarter of 2015 and our anticipated issuances in 2016. We have designated the forward-starting interest rate swaps, which are settled on the respective debt issuance dates, as cash flow hedges. We settled $200 million of these interest rate swaps on November 18, 2015, in conjunction with our November 2015 issuance of $250 million in senior notes. The remaining $600 million of interest rate swaps are expected to be settled in 2016 as we issue long-term debt as planned.

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.

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 March 31, 2016, our top 20 counterparties represented 54%, or $166 million, of our total counterparty exposure and 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 provides credit risk information related to our third-party natural gas contracts receivable and payable positions as of the periods presented.



	Gross receivables						Gross payables
	Mar. 31,		Dec. 31,		Mar. 31,		Mar. 31,		Dec. 31,		Mar. 31,
In millions	2016		2015		2015		2016		2015		2015
Netting agreements in place:
Counterparty is investment grade	$	236	$	299	$	394	$	103	$	136	$	211
Counterparty is non-investment grade	5		8		4		15		17		12
Counterparty has no external rating	119		133		190		244		265		361
No netting agreements in place:
Counterparty is investment grade	5		5		22		1		—		1
Counterparty has no external rating	—		—		1		—		—		1
Amount recorded on unaudited Condensed Consolidated Balance Sheets	$	365	$	445	$	611	$	363	$	418	$	586

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 less than $1 million at March 31, 2016, 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 2015 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 March 31, 2016, the end of the period covered by this report. No system of controls, no matter how well-designed and operated, can provide absolute assurance that the objectives of the system of controls are met, and no evaluation of controls can provide assurance that the system of controls has operated effectively in all cases. Our disclosure controls and procedures, however, are designed to provide reasonable assurance that the objectives of disclosure controls and procedures are met.

Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective as of March 31, 2016. 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 March 31, 2016 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 while the resolutions of these regulatory proceedings and litigation, whether individually or in the aggregate, could possibly be material to earnings in a particular quarter, they will not have a material adverse effect on our consolidated balance sheets or cash flows for the year. For more information regarding our regulatory proceedings and litigation, see Note 11 to our unaudited condensed consolidated financial statements under Part I, Item 1 herein.

Item 1A. Risk Factors

For information regarding our risk factors, see the factors discussed in Part I, Item 1A, “Risk Factors” in our 2015 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 2015 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 first quarter of 2016, 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
12	Computation of Ratio of Earnings to Fixed Charges	AGL Resources	Filed herewith
31.1	Certification of Andrew W. Evans	AGL Resources	Filed herewith
31.2	Certification of Elizabeth W. Reese	AGL Resources	Filed herewith
32.1	Certification of Andrew W. Evans	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:	May 4, 2016	/s/ Elizabeth W. Reese
		Elizabeth W. Reese
		Executive Vice President and Chief Financial Officer

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