SOUTHERN CO - FORM 8-K - EX-99.1 - EXHIBIT 99.1

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8-K - 8-K - SOUTHERN CO	so-aglprofomafin8xk5x16.htm
EX-99.2 - EXHIBIT 99.2 - SOUTHERN CO	ex99-2soxaglproformafin8xk.htm
EX-23.1 - EXHIBIT 23.1 - SOUTHERN CO	ex23-1soxaglproformafin8xk.htm
EX-99.3 - EXHIBIT 99.3 - SOUTHERN CO	proformafinancials-q12016.htm

Exhibit 99.1

AGL RESOURCES INC. ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2015

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of AGL Resources Inc.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, equity and cash flows present fairly, in all material respects, the financial position of AGL Resources Inc. and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Atlanta, Georgia

February 11, 2016

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of our principal executive officer and principal financial officer, management conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2015, using the criteria described in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”).

Based on our evaluation under the COSO Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2015.

The effectiveness of our internal control over financial reporting as of December 31, 2015 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February 11, 2016

/s/ Andrew W. Evans

Andrew W. Evans

President and Chief Executive Officer

/s/ Elizabeth W. Reese

Elizabeth W. Reese

Executive Vice President and Chief Financial Officer

AGL RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS - ASSETS



	As of December 31,
In millions	2015		2014
Current assets
Cash and cash equivalents	$	19	$	31
Short-term investments	8		8
Receivables
Energy marketing	445		779
Natural gas	266		391
Unbilled revenues	140		256
Other	110		150
Less allowance for uncollectible accounts	29		35
Total receivables, net	932		1,541
Inventories
Natural gas	622		694
Other	29		22
Total inventories	651		716
Prepaid expenses	218		223
Derivative instruments	206		245
Regulatory assets	68		83
Other	13		39
Total current assets	2,115		2,886
Long-term assets and other deferred debits
Property, plant and equipment	12,566		11,552
Less accumulated depreciation	2,775		2,462
Property, plant and equipment, net	9,791		9,090
Goodwill	1,813		1,827
Regulatory assets	670		631
Intangible assets	109		125
Long-term investments	103		105
Pension assets	78		97
Derivative instruments	12		42
Other	63		85
Total long-term assets and other deferred debits	12,639		12,002
Total assets	$	14,754	$	14,888

See Notes to Consolidated Financial Statements.

AGL RESOURCES INC. AND SUBISIDIARIES

CONSOLIDATED BALANCE SHEETS - LIABILITIES AND EQUITY



	As of December 31,
In millions, except share and per share amounts	2015			2014
Current liabilities
Short-term debt	$	1,010		$	1,175
Current portion of long-term debt	545			200
Energy marketing trade payables	418			777
Other accounts payable – trade	255			312
Customer deposits and credit balances	165			125
Regulatory liabilities	134			112
Accrued wages and salaries	92			97
Accrued environmental remediation liabilities	67			87
Accrued taxes	59			79
Accrued interest	49			53
Derivative instruments	44			88
Current deferred income taxes	31			2
Other	131			112
Total current liabilities	3,000			3,219
Long-term liabilities and other deferred credits
Long-term debt	3,275			3,581
Accumulated deferred income taxes	1,912			1,724
Regulatory liabilities	1,611			1,601
Accrued pension and retiree welfare benefits	515			525
Accrued environmental remediation liabilities	364			327
Other	102			83
Total long-term liabilities and other deferred credits	7,779			7,841
Total liabilities and other deferred credits	10,779			11,060
Commitments, guarantees and contingencies (see Note 12)
Equity
Common stock, $5 par value; 750,000,000 shares authorized; outstanding: 120,376,721 shares at December 31, 2015 and 119,647,149 shares at December 31, 2014	603			599
Additional paid-in capital	2,099			2,087
Retained earnings	1,421			1,312
Accumulated other comprehensive loss	(186		)	(206		)
Treasury shares, at cost: 216,523 shares at December 31, 2015 and 2014	(8		)	(8		)
Total common shareholders’ equity	3,929			3,784
Noncontrolling interest	46			44
Total equity	3,975			3,828
Total liabilities and equity	$	14,754		$	14,888

See Notes to Consolidated Financial Statements.

AGL RESOURCES INC. AND SUBISIDIARIES

CONSOLIDATED STATEMENTS OF INCOME



	Years ended December 31,
In millions, except per share amounts	2015			2014			2013
Operating revenues (includes revenue taxes of $103 for 2015, $133 for 2014 and $112 for 2013, respectively)	$	3,941		$	5,385		$	4,209
Operating expenses
Cost of goods sold	1,645			2,765			2,110
Operation and maintenance	914			939			887
Depreciation and amortization	397			380			397
Taxes other than income taxes	181			208			187
Merger-related expenses	44			—			—
Goodwill impairment	14			—			—
Total operating expenses	3,195			4,292			3,581
Gain on disposition of assets	—			2			11
Operating income	746			1,095			639
Other income	13			14			16
Interest expense, net	(173		)	(179		)	(170		)
Income before income taxes	586			930			485
Income tax expense	213			350			177
Income from continuing operations	373			580			308
(Loss) income from discontinued operations, net of tax	—			(80		)	5
Net income	373			500			313
Less net income attributable to the noncontrolling interest	20			18			18
Net income attributable to AGL Resources	$	353		$	482		$	295
Net income attributable to AGL Resources
Income from continuing operations attributable to AGL Resources	$	353		$	562		$	290
(Loss) income from discontinued operations, net of tax	—			(80		)	5
Net income attributable to AGL Resources	$	353		$	482		$	295
Per common share information
Basic earnings (loss) per common share
Continuing operations	2.95			4.73			2.46
Discontinued operations	—			(0.67		)	0.04
Basic earnings per common share attributable to AGL Resources common shareholders	2.95			4.06			2.50
Diluted earnings (loss) per common share
Continuing operations	2.94			4.71			2.45
Discontinued operations	—			(0.67		)	0.04
Diluted earnings per common share attributable to AGL Resources common shareholders	2.94			4.04			2.49
Cash dividends declared per common share	2.04			1.96			1.88
Weighted average number of common shares outstanding
Basic	119.6			118.8			117.9
Diluted	119.9			119.2			118.3

See Notes to Consolidated Financial Statements.

AGL RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Years Ended December 31,
In millions	2015			2014			2013
Net income	$	373		$	500		$	313
Other comprehensive income (loss), net of tax
Retirement benefit plans, net of tax
Actuarial (loss) gain arising during the period (net of income tax of $0, $48 and $46)	—			(71		)	66
Reclassification of actuarial loss to net benefit cost (net of income tax of $9, $6 and $10)	14			9			15
Reclassification of prior service cost to net benefit cost (net of income tax of $0, $1 and $2)	(2		)	(1		)	(3		)
Retirement benefit plans, net	12			(63		)	78
Cash flow hedges, net of tax
Net derivative instrument (loss) gain arising during the period (net of income tax of $3, $2 and $1)	—			(6		)	1
Reclassification of realized derivative loss (gain) to net income (net of income tax of $1, $2 and $1)	8			(3		)	3
Cash flow hedges, net	8			(9		)	4
Other comprehensive income (loss), net of tax	20			(72		)	82
Comprehensive income	393			428			395
Less comprehensive income attributable to noncontrolling interest	20			16			18
Comprehensive income attributable to AGL Resources	$	373		$	412		$	377

See Notes to Consolidated Financial Statements.

AGL RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY



	AGL Resources Inc. Shareholders
	Common stock				Additional paid-in capital				Retained earnings				Accumulated other comprehensive loss						Treasury shares				Noncontrolling interest
In millions, except per share amounts	Shares	Amount			Additional paid-in capital				Retained earnings				Accumulated other comprehensive loss						Treasury shares				Noncontrolling interest			Total
As of December 31, 2012	117.9		$	590		$	2,015			$	990					$	(218	)		$	(8	)	$	22		$	3,391
Net income	—	—			—				295					—					—				18			313
Other comprehensive income	—	—			—				—					82					—				—			82
Dividends on common stock ($1.88 per share)	—	—			—				(222			)		—					—				—			(222		)
Distribution to noncontrolling interest	—	—			—				—					—					—				(17		)	(17		)
Contribution from noncontrolling interest	—	—			—				—					—					—				22			22
Stock granted, share-based compensation, net of forfeitures	—	—			(6			)	—					—					—				—			(6		)
Stock issued, dividend reinvestment plan	0.3	1			10				—					—					—				—			11
Stock issued, share-based compensation, net of forfeitures	0.7	4			24				—					—					—				—			28
Stock-based compensation expense, net of tax	—	—			11				—					—					—				—			11
As of December 31, 2013	118.9		$	595		$	2,054			$	1,063			$	(136			)		$	(8	)	$	45		$	3,613
Net income	—	—			—				482					—					—				18			500
Other comprehensive loss	—	—			—				—					(70				)	—				(2		)	(72		)
Dividends on common stock ($1.96 per share)	—	—			—				(233			)		—					—				—			(233		)
Distribution to noncontrolling interest	—	—			—				—					—					—				(17		)	(17		)
Stock granted, share-based compensation, net of forfeitures	—	—			(11			)	—					—					—				—			(11		)
Stock issued, dividend reinvestment plan	0.2	1			11				—					—					—				—			12
Stock issued, share-based compensation, net of forfeitures	0.5	3			19				—					—					—				—			22
Stock-based compensation expense, net of tax	—	—			14				—					—					—				—			14
As of December 31, 2014	119.6		$	599		$	2,087			$	1,312			$	(206			)		$	(8	)	$	44		$	3,828
Net income	—	—			—				353					—					—				20			373
Other comprehensive income	—	—			—				—					20					—				—			20
Dividends on common stock ($2.04 per share)	—	—			—				(244			)		—					—				—			(244		)
Distribution to noncontrolling interest	—	—			—				—					—					—				(18		)	(18		)
Stock granted, share-based compensation, net of forfeitures	—	—			(14			)	—					—					—				—			(14		)
Stock issued, dividend reinvestment plan	0.3	1			11				—					—					—				—			12
Stock issued, share-based compensation, net of forfeitures	0.5	3			13				—					—					—				—			16
Stock-based compensation expense, net of tax	—	—			2				—					—					—				—			2
As of December 31, 2015	120.4		$	603		$	2,099			$	1,421			$	(186			)		$	(8	)	$	46		$	3,975

See Notes to Consolidated Financial Statements.

AGL RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS



	Years ended December 31,
In millions	2015			2014			2013
Cash flows from operating activities
Net income	$	373		$	500		$	313
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization	397			380			397
Deferred income taxes	211			201			(16		)
Change in derivative instrument assets and liabilities	22			(155		)	66
Goodwill impairment	14			—			—
Gain on disposition of assets	—			(2		)	(11		)
Loss (income) from discontinued operations, net of tax	—			80			(5		)
Changes in certain assets and liabilities
Receivables, other than energy marketing	275			(55		)	(74		)
Inventories	65			(58		)	41
Prepaid and miscellaneous taxes	3			(244		)	103
Accrued/deferred natural gas costs	(6		)	(67		)	2
Accrued expenses	(9		)	32			39
Energy marketing receivables and trade payables, net	(25		)	113			(54		)
Trade payables, other than energy marketing	(75		)	(81		)	89
Other, net	136			21			70
Net cash flow (used in) provided by operating activities of discontinued operations	—			(10		)	11
Net cash flow provided by operating activities	1,381			655			971
Cash flows from investing activities
Expenditures for property, plant and equipment	(1,027		)	(769		)	(731		)
Disposition of assets	—			230			12
Acquisitions of assets	—			—			(154		)
Other, net	—			47			8
Net cash flow used in investing activities of discontinued operations	—			(13		)	(11		)
Net cash flow used in investing activities	(1,027		)	(505		)	(876		)
Cash flows from financing activities
Issuance of senior notes	248			—			494
Benefit, dividend reinvestment and stock purchase plan	13			22			33
Distribution to noncontrolling interest	(18		)	(17		)	(17		)
Net (repayments) issuances of commercial paper	(165		)	4			(206		)
Payment of senior notes	(200		)	—			(225		)
Dividends paid on common shares	(244		)	(233		)	(222		)
Contribution from noncontrolling interest	—			—			22
Net cash flow used in financing activities	(366		)	(224		)	(121		)
Net decrease in cash and cash equivalents - continuing operations	(12		)	(51		)	(26		)
Net decrease in cash and cash equivalents - discontinued operations	—			(23		)	—
Cash and cash equivalents (including held for sale) at beginning of period	31			105			131
Cash and cash equivalents (including held for sale) at end of period	19			31			105
Less cash and cash equivalents held for sale at end of period	—			—			24
Cash and cash equivalents (excluding held for sale) at end of period	$	19		$	31		$	81
Cash paid (received) during the period for
Interest	$	181		$	187		$	175
Income taxes	(26		)	422			120
Non cash financing transaction
Refinancing of gas facility revenue bonds	$	—		$	—		$	200

See Notes to Consolidated Financial Statements.

Notes to Consolidated Financial Statements

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.

Basis of Presentation

Our consolidated financial statements as of and for the period ended December 31, 2015 are prepared in accordance with GAAP and under the rules of the SEC. Our 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 Consolidated Statements of Income. See Note 11 for additional information. We have eliminated intercompany profits and transactions in consolidation except for intercompany profits where recovery of such amounts is probable under the affiliates’ rate regulation process.

In September 2014, we closed on the sale of Tropical Shipping, which operated within our former cargo shipping segment and whose financial results for the years ended December 31, 2014 and 2013 are reflected as discontinued operations on the Consolidated Statements of Income. Amounts shown in the following notes, unless otherwise indicated, exclude discontinued operations. See Note 15 for additional information on the sale of Tropical Shipping.

Certain amounts from prior periods have been reclassified to conform to the current period presentation. The 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 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. Following the effective time of the merger, we will become a wholly owned, direct subsidiary of Southern Company.

Completion of the merger remains subject to various closing conditions, including, among others (i) the receipt of required regulatory approvals from the Federal Communications Commission, California Public Utilities Commission, Georgia Commission, Illinois Commission, Maryland Commission, New Jersey BPU and Virginia Commission, and such approvals having become final orders and (iii) the absence of a judgment, order, decision, injunction, ruling or other finding or agency requirement of a governmental entity prohibiting the closing of the merger.

At a special meeting of shareholders held on November 19, 2015, the proposed merger was approved by our shareholders. The waiting period under the Hart-Scott-Rodino Act expired on December 4, 2015. We and Southern Company have made joint filings seeking regulatory approval of the proposed merger with all of the required state regulatory agencies.

The Merger Agreement contains certain termination rights for each party. In addition, the Merger Agreement, in certain circumstances, provides for the payment by AGL Resources of a $201 million termination fee to Southern Company and, in certain circumstances, provides for the reimbursement of expenses up to $5 million upon termination of the Merger Agreement (which reimbursement would reduce on a dollar-for-dollar basis any termination fee subsequently paid by us). As of December 31, 2015 we had recorded no liability for termination fees.

In connection with this transaction, we recorded merger-related costs in the accompanying Consolidated Statements of Income of $44 million ($26 million, net of tax) for the year ended December 31, 2015. The transaction costs incurred to date are comprised of $24 million of additional stock-based compensation expense associated with the proposed merger as we remeasured our performance share unit awards based upon the increase in trading price of our common stock since the announcement of the Merger Agreement, $16 million of expenses associated with financial advisory, legal and other merger-related costs and $4 million of board of directors stock-based compensation related to the aforementioned increase in the trading price of our common stock. We treated these costs as tax deductible since the requisite closing conditions to the merger have not yet been satisfied. Once the merger is closed, we will evaluate the tax deductibility of these costs and reflect any non-deductible amounts in the effective tax rate.

Additionally, subsequent to the announcement of the merger, AGL Resources and each member of the Board were named as defendants in four purported shareholder class action lawsuits relating to the merger, which were dismissed during the first quarter of 2016.

Note 3 - Significant Accounting Policies and Methods of Application

Cash and Cash Equivalents

Our cash and cash equivalents primarily consist of cash on deposit, money market accounts and certificates of deposit with original maturities of three months or less.

Energy Marketing Receivables and Payables

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

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

Wholesale services has a concentration of credit risk for services it provides to its counterparties. This credit risk is generally concentrated in 20 of its counterparties and is measured by 30-day receivable exposure plus forward exposure. We evaluate the credit risk of our counterparties using an S&P equivalent credit rating, which is determined by a process of converting the lower of the S&P or Moody’s rating to an internal rating ranging from 9 to 1, with 9 being equivalent to AAA/Aaa by S&P and Moody’s and 1 being equivalent to D/Default by S&P and Moody’s. A counterparty that does not have an external rating is assigned an internal rating based on the strength of its financial ratios. As of December 31, 2015, our top 20 counterparties represented 53%, or $196 million, of our total counterparty exposure and had a weighted average S&P equivalent rating of A-.

We have established credit policies to determine and monitor the creditworthiness of counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include cash or U.S. government securities held by a trustee. When wholesale services is engaged in more than one outstanding derivative transaction with the same counterparty and it also has 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 combined with a reasonable measure of our credit risk. Wholesale services also uses other netting agreements with certain counterparties with whom it conducts significant transactions.

Receivables and Allowance for Uncollectible Accounts

Our other trade receivables consist primarily of natural gas sales and transportation services billed to residential, commercial, industrial and other customers. We bill customers monthly, and our accounts receivable are due within 30 days. For the majority of our receivables, we establish an allowance for doubtful accounts based on our collection experience and other factors. For our remaining receivables, if we are aware of a specific customer’s inability to pay, we record an allowance for doubtful accounts against amounts due to reduce the receivable balance to the amount we reasonably expect to collect. If circumstances change, our estimate of the recoverability of accounts receivable could change as well. Circumstances that could affect our estimates include, but are not limited to, customer credit issues, customer deposits and general economic conditions. Customers’ accounts are written off once we deem them to be uncollectible.

Nicor Gas Credit risk exposure at Nicor Gas is mitigated by a bad debt rider approved by the Illinois Commission. The bad debt rider provides for the recovery from (or refund to) customers of the difference between Nicor Gas’ actual bad debt experience on an annual basis and the benchmark bad debt expense used to establish its base rates for the respective year. See Note 4 for additional information on the bad debt rider.

Atlanta Gas Light Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 14 Marketers in Georgia. The credit risk exposure to Marketers varies seasonally, with the lowest exposure in the non-peak summer months and the highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. The functions of the retail sale of gas include the purchase and sale of natural gas, customer service, billings and collections. We obtain credit security support in an amount equal to no less than two times a Marketer’s highest month’s estimated bill from Atlanta Gas Light.

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. In Georgia’s competitive environment, Marketers sell natural gas to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation and provides this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. On a

monthly basis, Atlanta Gas Light assigns to Marketers the majority of the pipeline storage services that it has under contract, along with a corresponding amount of inventory. Atlanta Gas Light retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand.

Nicor Gas’ inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year-end are charged to cost of goods sold at the estimated annual replacement cost. Inventory decrements that are not restored prior to year-end are charged to cost of goods sold at the actual LIFO cost of the layers liquidated. Since the cost of gas, including inventory costs, is charged to customers without markup, subject to Illinois Commission review, LIFO liquidations have no impact on net income. At December 31, 2015, the Nicor Gas LIFO inventory balance was $145 million. Based on the average cost of gas purchased in December 2015, the estimated replacement cost of Nicor Gas’ inventory at December 31, 2015 was $201 million, which exceeded the LIFO cost by $56 million. During 2015, we did not liquidate any of our LIFO-based inventory.

Our retail operations, wholesale services and midstream operations segments carry inventory at LOCOM, where cost is determined on a WACOG basis. For these segments, we evaluate the weighted average cost of their natural gas inventories against market prices to determine whether any declines in market prices below the WACOG are other than temporary. As indicated in the following table, for any declines considered to be other than temporary, we recorded LOCOM adjustments to cost of goods sold to reduce the value of our natural gas inventories to market value.



In millions	2015		2014		2013
Retail operations	$	3	$	4	$	1
Wholesale services ⁽¹⁾	19		73		8
Other	1		—		—
Total	$	23	$	77	$	9


(1)	The increase in 2014 was due to a significant decline in natural gas prices in December 2014.

Operational issues at a third-party storage facility during 2015 caused 5 Bcf of our inventory at wholesale services to be inaccessible. These operational issues at this facility have been resolved, and we began withdrawing the inventory in the fourth quarter of 2015. Our capacity contract with the facility expires at the end of the first quarter of 2016.

At midstream operations, mechanical integrity tests and engineering studies are periodically performed on the storage facilities in accordance with certain state regulatory requirements. During 2014, an engineering study and mechanical integrity tests were performed at one of our storage facilities and identified a lower amount of working gas capacity due to naturally occurring shrinkage of the storage cavern. Further, based on the lower capacity and an analysis of the volume of natural gas stored in the facility, we recorded $10 million in additional natural gas costs for the year ended December 31, 2014 to true-up the amount of retained fuel at this facility. Other storage facilities at midstream operations were not impacted.

Regulated Operations

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

Fair Value Measurements

We have financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value include cash and cash equivalents and derivative instruments. The carrying values of receivables, short and long-term investments, accounts payable, short-term debt, other current assets and liabilities, and accrued interest approximate their respective fair value. Our nonfinancial assets and liabilities include pension and welfare benefits. See Note 5 for additional fair value disclosures.

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

those inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by the guidance are as follows:

Level 1 Quoted prices in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 items consist of exchange-traded derivatives, money market funds and certain retirement plan assets.

Level 2 Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial and commodity instruments that are valued using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. We obtain market price data from multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the marketplace. Instruments in this category include shorter tenor exchange-traded and non-exchange-traded derivatives such as OTC forwards and options and certain retirement plan assets.

Level 3 Pricing inputs include significant unobservable inputs that may be used with internally developed methodologies to determine management’s best estimate of fair value from the perspective of market participants. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. Our Level 3 assets, liabilities and any applicable transfers are primarily related to our pension and welfare benefit plan assets as described in Note 5 and Note 7. We determine both transfers into and out of Level 3 using values at the end of the interim period in which the transfer occurred.

The authoritative guidance related to fair value measurements and disclosures also includes a two-step process to determine whether the market for a financial asset is inactive or a transaction is distressed. Currently, this authoritative guidance does not affect us, as our derivative instruments are traded in active markets.

Derivative Instruments

Our policy is to classify derivative cash flows and gains and losses within the same financial statement category as the hedged item, rather than by the nature of the instrument.

Fair Value Hierarchy Derivative assets and liabilities are classified in their entirety into the previously described fair value hierarchy levels based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The measurement of fair value incorporates various factors required under the guidance, which include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our own nonperformance risk on our liabilities. To mitigate the risk that a counterparty to a derivative instrument defaults on settlement or otherwise fails to perform under contractual terms, we have established procedures to monitor the creditworthiness of counterparties, seek guarantees or collateral backup in the form of cash or letters of credit and, in most instances, enter into netting arrangements. See Note 5 for additional fair value disclosures.

Netting of Cash Collateral and Derivative Assets and Liabilities under Master Netting Arrangements We maintain accounts with brokers to facilitate financial derivative transactions in support of our energy marketing and risk management activities. Based on the value of our positions in these accounts and the associated margin requirements, we may be required to deposit cash into these broker accounts.

We have elected to net derivative assets and liabilities under master netting arrangements on our Consolidated Balance Sheets. With that election, we are also required to offset cash collateral held in our broker accounts with the associated net fair value of the instruments in the accounts. See Note 5 for additional information about our cash collateral.

Natural Gas and Weather Derivative Instruments The fair value of the natural gas derivative instruments that we use to manage exposures arising from changing natural gas prices and warmer-than-normal weather risk reflects the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. We use external market quotes and indices to value substantially all of our derivative instruments. See Note 6 for additional derivative disclosures.

Distribution Operations Nicor Gas, subject to review by the Illinois Commission, and Elizabethtown Gas, in accordance with a directive from the New Jersey BPU, enter into derivative instruments to hedge the impact of market fluctuations in natural gas prices. In accordance with regulatory requirements, any realized gains or losses related to these derivatives are reflected in natural gas costs and ultimately included in billings to customers. As previously noted, such derivative instruments are reported at fair value each reporting period on our Consolidated Balance Sheets. Hedge accounting is not elected and, in accordance with accounting guidance pertaining to rate-regulated entities, unrealized changes in the fair value of these derivative instruments are deferred or accrued as regulatory assets or liabilities until the related revenue is recognized.

For our weather risk associated with Nicor Gas, we have a corporate weather hedging program that utilizes weather derivatives to reduce the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather in Illinois. These weather derivatives are carried at intrinsic value. We will continue to use available methods to mitigate our exposure to weather in Illinois.

Retail Operations We have designated a portion of our derivative instruments, consisting of financial swaps to manage the risk associated with forecasted natural gas purchases and sales, as cash flow hedges. We record derivative gains or losses arising from cash flow hedges in OCI and reclassify them into earnings in the same period that the underlying hedged item is recognized in earnings.

We currently have minimal hedge ineffectiveness, which occurs when the gains or losses on the hedging instrument more than offset the losses or gains on the hedged item. Any cash flow hedge ineffectiveness is recorded on our Consolidated Statements of Income in the period in which it occurs. We have not designated the remainder of our derivative instruments as hedges for accounting purposes and, accordingly, we record changes in the fair values of such instruments within cost of goods sold on our Consolidated Statements of Income in the period of change.

We also enter into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather in the Heating Season. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non exchange-traded contracts are also reflected in operating revenues in our Consolidated Statements of Income.

Wholesale Services We purchase natural gas for storage when the current market price we pay to buy and transport natural gas plus the cost to store and finance the natural gas is less than the market price we can receive in the future, resulting in a positive net operating margin. We use NYMEX futures and OTC contracts to sell natural gas at that future price to substantially protect the operating margin we will ultimately realize when the stored natural gas is sold. We also enter into transactions to secure transportation capacity between delivery points in order to serve our customers and various markets. We use NYMEX futures and OTC contracts to capture the price differential or spread between the locations served by the capacity in order to substantially protect the operating margin we will ultimately realize when we physically flow natural gas between delivery points. These contracts generally meet the definition of derivatives and are carried at fair value on our Consolidated Balance Sheets, with changes in fair value recorded in operating revenues on our Consolidated Statements of Income in the period of change. These contracts are not designated as hedges for accounting purposes.

The purchase, transportation, storage and sale of natural gas are accounted for on a weighted average cost or accrual basis, as appropriate, rather than on the fair value basis we utilize for the derivatives used to mitigate the natural gas price risk associated with our storage and transportation portfolio. We incur monthly demand charges for the contracted storage and transportation capacity and payments associated with asset management agreements, and we recognize these demand charges and payments on our Consolidated Statements of Income in the period they are incurred. This difference in accounting methods can result in volatility in our reported earnings, even though the economic margin is substantially unchanged from the dates the transactions were consummated.

Debt We estimate the fair value of debt using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality and risk profile. In determining the market interest yield curve, we consider our currently assigned ratings for unsecured debt and the secured rating for the Nicor Gas first mortgage bonds. See Note 5 for fair value disclosure.

Property, Plant and Equipment

A summary of our PP&E by classification as of December 31, 2015 and 2014 is provided in the following table.



In millions	2015		2014
Transportation and distribution	$	9,912	$	9,105
Storage facilities	1,255		1,202
Other	985		919
Construction work in progress	414		326
PP&E, gross	12,566		11,552
Less accumulated depreciation	2,775		2,462
PP&E, net	$	9,791	$	9,090

Distribution Operations Our natural gas utilities’ PP&E consists of property and equipment that is currently in use, being held for future use and currently under construction. We report PP&E at its original cost, which includes:


•	material and labor;


•	contractor costs;


•	construction overhead costs;


•	AFUDC; and,


•	Nicor Gas’ pad gas - the portion considered to be non-recoverable is recorded as depreciable PP&E, while the portion considered to be recoverable is recorded as non-depreciable PP&E.

We do not recognize any gains or losses on depreciable utility property that is retired or otherwise disposed, as required under the composite depreciation method. Such gains or losses are ultimately refunded to, or recovered from, customers through future rate adjustments. Our natural gas utilities also hold property, primarily land, that is not presently used and useful in utility operations and is not included in rate base. Upon sale, any gain or loss is recognized in other income.

Retail Operations, Wholesale Services, Midstream Operations and Other PP&E includes property that is in use and under construction, and we report it at cost. We record a gain or loss within operation and maintenance expense for retired or otherwise disposed-of property. Natural gas in salt-dome storage at Jefferson Island and Golden Triangle that is retained as pad gas is classified as non-depreciable PP&E and is carried at cost. Central Valley has two types of pad gas in its depleted reservoir storage facility: the first is non-depreciable PP&E, which is carried at cost, and the second is non-recoverable, which is depreciated over the life of the storage facility.

On April 11, 2014, we entered into two arrangements associated with the Dalton Pipeline. The first was a construction and ownership agreement through which we will have a 50% undivided ownership interest in the 106 mile Dalton Pipeline that will be constructed in Georgia and serve as an extension of the Transco natural gas pipeline system into northwest Georgia. We also entered into an agreement to lease our 50% undivided ownership in the Dalton Pipeline once it is placed in service. The lease payments to be received are $26 million annually for an initial term of 25 years. The lessee will be responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC-regulated tariff. Engineering design work has commenced and construction is expected to begin in the second quarter of 2016. At December 31, 2015, our 50% share of construction costs was $33 million and is reflected in construction work in process on our Consolidated Balance Sheets.

Depreciation Expense

We compute depreciation expense for distribution operations by applying composite straight-line rates (approved by the state regulatory agencies) to the investment in depreciable property. More information on our rates used and the rate method is provided in the following table.



	2015		2014		2013
Atlanta Gas Light ⁽¹⁾	2.4	%	2.3	%	2.6	%
Chattanooga Gas ⁽¹⁾	2.5		2.5		2.5
Elizabethtown Gas ⁽²⁾	2.4		2.5		2.4
Elkton Gas ⁽²⁾	2.7		2.8		2.4
Florida City Gas ⁽²⁾	3.9		3.9		3.8
Nicor Gas ^{(2) (3)}	3.1		3.1		3.1
Virginia Natural Gas ⁽¹⁾	2.5		2.5		2.5


(1)	Average composite straight-line depreciation rates for depreciable property, excluding transportation equipment, which may be depreciated in excess of useful life and recovered in rates.


(2)	Composite straight-line depreciation rates.


(3)	In October 2013, the Illinois Commission approved a composite depreciation rate of 3.07%. The depreciation rate was effective as of August 30, 2013, the date the depreciation study was filed, and had the effect of reducing our 2014 and 2013 depreciation expense by $51 million and $19 million, respectively.

For our non-regulated segments, we compute depreciation expense on a straight-line basis over the following estimated useful lives of the assets.



In years		Estimated useful life
Transportation equipment		5 – 10
Storage caverns		40 – 60
Other		up to 40

AFUDC and Capitalized Interest

AFUDC represents the estimated cost of funds, from both debt and equity sources, used to finance the construction of major projects and is capitalized in rate base for ratemaking purposes when the completed projects are placed in service. Atlanta Gas Light, Nicor Gas, Chattanooga Gas and Elizabethtown Gas are authorized by applicable state regulatory agencies or legislatures to capitalize the cost of debt and equity funds as part of the cost of PP&E construction projects on our Consolidated Balance Sheets. The capital expenditures of our other three utilities do not qualify for AFUDC treatment. More information on our authorized or actual AFUDC rates is provided in the following table.



	2015			2014			2013
Atlanta Gas Light	8.10		%	8.10		%	8.10		%
Nicor Gas⁽¹⁾	0.82		%	0.24		%	0.31		%
Chattanooga Gas	7.41		%	7.41		%	7.41		%
Elizabethtown Gas ⁽¹⁾	1.69		%	0.44		%	0.41		%
AFUDC (in millions)⁽²⁾	$	6		$	7		$	18


(1)	Variable rate is determined by FERC method of AFUDC accounting.


(2)	Amount recorded on the Consolidated Statements of Income.

Asset Retirement Obligations

We record a liability at fair value for an asset retirement obligation (ARO) when a legal obligation to retire the asset has been incurred, with an offsetting increase to the carrying value of the related asset. Accretion of the ARO due to the passage of time is recorded as an operating expense. We have recorded an ARO of $3 million at December 31, 2015 and 2014 principally for our storage facilities. For our distribution PP&E, we cannot reasonably estimate the fair value of this obligation because we have determined that we have insufficient internal or industry information to reasonably estimate the potential settlement dates or costs.

Impairment of Assets

Our goodwill is not amortized, but is subject to an annual impairment test. Our other long-lived assets, including our finite-lived intangible assets, require an impairment review when events or circumstances indicate that the carrying amount may not be recoverable. We base our evaluation of the recoverability of other long-lived assets on the presence of impairment indicators such as the future economic benefit of the assets, any historical or future profitability measurements and other external market conditions or factors.

Goodwill Our annual impairment test is performed at the reporting unit level during the fourth quarter of each year or more frequently if impairment indicators arise.

Our 2014 annual goodwill impairment test indicated that the estimated fair value of our storage and fuels reporting unit, that had $14 million of goodwill, within our midstream operations segment exceeded its carrying value by less than 5% and would be at risk of failing step 1 of the goodwill impairment test if a further decline in the estimated fair value were to occur. While preparing our third quarter 2015 financial statements, and in connection with our 2016 annual budget process, we assessed various market factors and projections prepared by both internal and external sources related to subscription rates for contracting capacity at our storage facilities as well as the profitability of our storage and fuels reporting unit. Based on this assessment, we concluded that a decline in projected storage subscription rates as well as a reduction in the near-term projection of the reporting unit’s profitability required us to perform an interim goodwill impairment test as of September 30, 2015.

Step 1 of our interim goodwill impairment test compared the fair value of the reporting unit to its carrying value utilizing the income approach, under which the fair value was estimated based on the present value of estimated future cash flows discounted at an appropriate interest rate. The result of our step 1 test revealed that the estimated fair value of our storage and fuels reporting unit was below its carrying value.

Step 2 of this interim goodwill impairment test compared the implied fair value of goodwill in our storage and fuels reporting unit, which was calculated as the residual amount from the reporting unit’s overall fair value after assigning fair values to its assets and liabilities under a hypothetical purchase price allocation as if the reporting unit had been acquired in a business combination, to its carrying value. Based on the result of our step 2 test, we recorded a non-cash impairment charge of the full $14 million ($9 million, net of tax) of goodwill.

For our 2015 annual goodwill impairment test of the remaining goodwill, we performed the qualitative step 0 assessment focusing on the following qualitative factors: macroeconomic conditions, industry and market conditions, cost factors, financial performance, entity specific events and events specific to each reporting unit. Our step 0 analysis concluded that it is more likely than not that the fair value of our reporting units that have goodwill exceeds their carrying amounts and a quantitative assessment was not required. The amounts of goodwill as of December 31, 2015 and 2014 are provided below.



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

Long-Lived Assets We depreciate or amortize our long-lived assets and other intangible assets, which are all located in the U.S., over their useful lives. We have no significant indefinite-lived intangible assets. These long-lived assets and other intangible assets are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through expected future cash flows. Impairment is indicated if the carrying amount of the long-lived asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If impairment is indicated, we record an impairment loss equal to the difference between the carrying value and the fair value of the long-lived asset. We determined that there were no long-lived asset impairments in 2015 or 2014; however, in 2013, we recorded an $8 million loss related to Sawgrass Storage.

Intangible Assets Our intangible assets within our retail operations segment are presented in the following table and represent the estimated fair value at the date of acquisition of the acquired intangible assets in our businesses. As indicated previously, we perform an impairment review when impairment indicators are present. If present, we first determine whether the carrying amount of the asset is recoverable through the undiscounted future cash flows expected from the asset. If the carrying amount is not recoverable, we measure the impairment loss, if any, as the amount by which the carrying amount of the asset exceeds its fair value.



		December 31, 2015							December 31, 2014
In millions	Weighted average amortization period (in years)	Gross		Accumulated amortization			Net		Gross		Accumulated amortization			Net
Customer relationships	13	$	132	$	(57	)	$	75	$	130	$	(42	)	$	88
Trade names	13	45		(11		)	34		45		(8		)	37
Total		$	177	$	(68	)	$	109	$	175	$	(50	)	$	125

We amortize these intangible assets in a manner in which the economic benefits are consumed utilizing the undiscounted cash flows that were used in the determination of their fair values. Amortization expense was $18 million in 2015, $20 million in 2014 and $18 million in 2013. Amortization expense for the next five years is expected to be as follows:



In millions	Amortization Expense
2016	$	17
2017	15
2018	14
2019	12
2020	11

Accounting for Retirement Benefit Plans

We recognize the funded status of our plans as an asset or a liability on our Consolidated Balance Sheets, measuring the plans’ assets and obligations that determine our funded status as of the end of the fiscal year. We generally recognize, as a component of OCI, the changes in funded status that occurred during the year that are not yet recognized as part of net periodic benefit cost. Because substantially all of its retirement costs are recoverable through base rates, Nicor Gas defers the change in funded status that would normally be charged or credited to comprehensive income to a regulatory asset or liability until the period in which the costs are included in base rates, in accordance with the authoritative guidance for rate-regulated entities. The assets of our retirement plans are measured at fair value within the funded status and are classified in the fair value hierarchy in their entirety based on the lowest level of input that is significant to the fair value measurement.

In determining net periodic benefit cost, the expected return on plan assets component is determined by applying our expected return on assets to a calculated asset value, rather than to the fair value of the assets as of the end of the previous fiscal year. For more information, see Note 7. In addition, we have elected to amortize gains and losses caused by actual experience that differ from our assumptions into subsequent periods. The amount to be amortized is the amount of the cumulative gain or loss as of the beginning of the year, excluding those gains and losses not yet reflected in the calculated value, that exceeds 10 percent of the greater of the benefit obligation or the calculated asset value. The amortization period is the average remaining service period of active employees.

Taxes

Income Taxes The reporting of our assets and liabilities for financial accounting purposes differs from the reporting for income tax purposes. The principal difference between net income and taxable income relates to the timing of deductions, primarily due to the benefits of tax depreciation since we generally depreciate assets for tax purposes over a shorter period of time than for book purposes. The determination of our provision for income taxes requires significant judgment, the use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items. We report the tax effects of depreciation and other temporary differences as deferred income tax assets or liabilities on our Consolidated Balance Sheets.

We have current and deferred income taxes on our Consolidated Statements of Income. Current income tax expense consists of federal and state income tax less applicable tax credits related to the current year. Deferred income tax expense is generally equal to the changes in the deferred income tax liability and regulatory tax liability during the year.

Accumulated Deferred Income Tax Assets and Liabilities As noted above, we report some of our assets and liabilities differently for financial accounting purposes than for income tax purposes. We report the tax effects of the differences in those items as deferred income tax assets or liabilities on our Consolidated Balance Sheets. We measure these deferred income tax assets and liabilities using enacted income tax rates.

With the sale of Tropical Shipping in the third quarter of 2014, we determined that the cumulative foreign earnings of that business would no longer be indefinitely reinvested offshore. Accordingly, we recognized income tax expense of $60 million in 2014 related to the cumulative foreign earnings for which no tax liabilities had been previously recorded, resulting in our repatriation of $86 million in cash. Refer to Note 15 for additional information.

Income Tax Benefits The authoritative guidance related to income taxes requires us to determine whether tax benefits claimed or expected to be claimed on our tax return should be recorded in our consolidated financial statements. Under this guidance, we may recognize the tax benefit from an uncertainty in income taxes only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the position. The tax benefits

recognized in the financial statements from such a position should be measured based upon the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement.

Uncertainty in Income Taxes We recognize accrued interest related to uncertainty in income taxes in interest expense and penalties in operating expense on our Consolidated Statements of Income.

Tax Collections We do not collect income taxes from our customers on behalf of governmental authorities. However, we do collect and remit various other taxes on behalf of various governmental authorities. We record these amounts on our Consolidated Balance Sheets. In other instances, we are allowed to recover from customers other taxes that are imposed upon us. We record such taxes as operating expenses and record the corresponding customer charges as operating revenues on our Consolidated Statements of Income.

Revenues

Distribution operations We record revenues when goods or services are provided to customers. Those revenues are based on rates approved by the state regulatory agencies of our utilities.

As required by the Georgia Commission, Atlanta Gas Light bills Marketers in equal monthly installments for each residential, commercial and industrial end-use customer’s distribution costs. Additionally, as required by the Georgia Commission, Atlanta Gas Light bills Marketers for capacity costs utilizing a seasonal rate design for the calculation of each residential end-use customer’s annual straight-fixed-variable charge, which reflects the historic volumetric usage pattern for the entire residential class. Generally, this seasonal rate design results in billing the Marketers a higher capacity charge in the winter months and a lower charge in the summer months, which impacts our operating cash flows. However, this seasonal billing requirement does not impact our revenues, which are recognized on a straight-line basis, because the associated rate mechanism ensures that we ultimately collect the full annual amount of the straight-fixed-variable charges.

All of our utilities, with the exception of Atlanta Gas Light, have rate structures that include volumetric rate designs that allow the opportunity to recover certain costs based on gas usage. Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. Additionally, unbilled revenues are recognized for estimated deliveries of gas not yet billed to these customers, from the last bill date to the end of the accounting period. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries to the end of the period.

The tariffs for Virginia Natural Gas, Elizabethtown Gas and Chattanooga Gas contain WNAs that partially mitigate the impact of unusually cold or warm weather on customer billings and operating margin. The WNAs have the effect of reducing customer bills when winter weather is colder-than-normal and increasing customer bills when weather is warmer-than-normal. In addition, the tariffs for Virginia Natural Gas, Chattanooga Gas and Elkton Gas contain revenue normalization mechanisms that mitigate the impact of conservation and declining customer usage.

Revenue Taxes We charge customers for gas revenue and gas use taxes imposed on us and remit amounts owed to various governmental authorities. Our policy for gas revenue taxes is to record the amounts charged by us to customers, which for some taxes includes a small administrative fee, as operating revenues, and to record the related taxes imposed on us as operating expenses on our Consolidated Statements of Income. Our policy for gas use taxes is to exclude these taxes from revenue and expense, aside from a small administrative fee that is included in operating revenues as the tax is imposed on the customer. As a result, the amount recorded in operating revenues will exceed the amount recorded in operating expenses by the amount of administrative fees that are retained by the company. Revenue taxes included in operating expenses were $101 million in 2015, $130 million in 2014 and $110 million in 2013.

Retail operations Revenues from natural gas sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Sales revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. In addition, unbilled revenues are recognized for estimated deliveries of gas not yet billed to these customers, from the most recent meter reading date to the end of the accounting period. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries during the period.

We recognize revenues on 12-month utility-bill management contracts as the lesser of cumulative earned or cumulative billed amounts. We recognize revenues for warranty and repair contracts on a straight-line basis over the contract term. Revenues for maintenance services are recognized at the time such services are performed.

Wholesale services Revenues from energy and risk management activities are required under authoritative guidance to be netted with the associated costs. Profits from sales between segments are eliminated and are recognized as goods or services sold to end-use customers. Transactions that qualify as derivatives under authoritative guidance related to derivatives and hedging are recorded at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are required to be presented net in revenue.

Midstream operations We record operating revenues for storage and transportation services in the period in which volumes are transported and storage services are provided. The majority of our storage services are covered under medium to long-term contracts at fixed market-based rates. We recognize our park and loan revenues ratably over the life of the contract.

Cost of Goods Sold

Distribution operations Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, we charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms set 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. In accordance with the authoritative guidance for rate-regulated entities, we defer or accrue (that is, include as an asset or liability on the Consolidated Balance Sheets and exclude from, or include on, the Consolidated Statements of Income, respectively) the difference between the actual cost of goods sold and the amount of commodity revenue earned in a given period, such that no operating margin is recognized related to these costs. The deferred or accrued amount is either billed or refunded to our customers prospectively through adjustments to the commodity rate. Deferred natural gas costs are reflected as regulatory assets and accrued natural gas costs are reflected as regulatory liabilities. For more information, see Note 4.

Retail operations Our retail operations customers are charged for actual or estimated natural gas consumed. Within our cost of goods sold, we also include costs of fuel and lost and unaccounted for gas, adjustments to reduce the value of our inventories to market value and gains and losses associated with certain derivatives. Costs to service our warranty and repair contract claims are recorded to cost of goods sold.

Operating Leases

We have certain operating leases with provisions for step rent or escalation payments and certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms, in accordance with authoritative guidance related to leases. This accounting treatment does not affect the future annual operating lease cash obligations. For more information, see Note 12.

Other Income

Our other income is detailed in the following table. For more information on our equity investment income, see Note 11.



In millions	2015		2014		2013
Equity investment income	$	6	$	8	$	3
AFUDC - equity	4		5		12
Other, net	3		1		1
Total other income	$	13	$	14	$	16

Non-Wholly Owned Entities

We hold ownership interests in a number of business ventures with varying ownership structures. We evaluate all of our partnership interests and other variable interests to determine if each entity is a VIE, as defined in the authoritative accounting guidance. If a venture is a VIE for which we are the primary beneficiary, we consolidate the assets, liabilities and results of operations of the entity. We reassess our conclusion as to whether an entity is a VIE upon certain occurrences, which are deemed reconsideration events under the guidance. We have concluded that the only venture that we are required to consolidate as a VIE, as we are the primary beneficiary, is SouthStar. On our Consolidated Balance Sheets, we recognize Piedmont’s share of SouthStar as a separate component of equity entitled “noncontrolling interest.” Piedmont’s share of current operations is reflected in “net income attributable to the noncontrolling interest” on our Consolidated Statements of Income. The consolidation of SouthStar has no effect on our calculation of basic or diluted earnings per common share amounts, which are based upon net income attributable to AGL Resources.

For entities that are not determined to be VIEs, we evaluate whether we have control or significant influence over the investee to determine the appropriate consolidation and presentation. Generally, entities under our control are consolidated, and entities over which we can exert significant influence, but do not control, are accounted for under the equity method of accounting. However, we also invest in partnerships and limited liability companies that maintain separate ownership accounts. All such investments are required to be accounted for under the equity method unless our interest is so minor that there is virtually no influence over operating and financial policies, as are all investments in joint ventures.

Investments accounted for under the equity method are included in long-term investments on our Consolidated Balance Sheets, and the equity income is recorded within other income on our Consolidated Statements of Income and was immaterial for all periods presented. For additional information, see Note 11.

Earnings Per Common Share

We compute basic earnings per common share attributable to AGL Resources by dividing our net income attributable to AGL Resources by the daily weighted average number of common shares outstanding. Diluted earnings per common share attributable to AGL Resources reflect the potential reduction in earnings per common share attributable to AGL Resources that occurs when potentially dilutive common shares are added to common shares outstanding.

We derive our potentially dilutive common shares by calculating the number of shares issuable under restricted stock, restricted stock units and stock options award programs. The vesting of certain shares of the restricted stock and restricted stock units depends on the satisfaction of defined performance criteria and/or time-based criteria. The future issuance of shares underlying the outstanding stock options depends on whether the market price of the common shares underlying the options exceeds the respective exercise prices of the stock options.

The following table shows the calculation of our diluted shares attributable to AGL Resources 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.



In millions (except per share amounts)	2015		2014			2013
Income from continuing operations attributable to AGL Resources	$	353	$	562		$	290
(Loss) income from discontinued operations, net of tax	—		(80		)	5
Net income attributable to AGL Resources	$	353	$	482		$	295
Denominator:
Basic weighted average number of common shares outstanding ⁽¹⁾	119.6		118.8			117.9
Effect of dilutive securities	0.3		0.4			0.4
Diluted weighted average number of common shares outstanding ⁽²⁾	119.9		119.2			118.3
Basic earnings (loss) per common share
Continuing operations	$	2.95	$	4.73		$	2.46
Discontinued operations	—		(0.67		)	0.04
Basic earnings per common share attributable to AGL Resources	$	2.95	$	4.06		$	2.50
Diluted earnings (loss) per common share
Continuing operations	$	2.94	$	4.71		$	2.45
Discontinued operations	—		(0.67		)	0.04
Diluted earnings per common share attributable to AGL Resources	$	2.94	$	4.04		$	2.49


(1)	Daily weighted average shares outstanding.


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

Sale of Compass Energy

On May 1, 2013, we sold Compass Energy, a non-regulated retail natural gas business supplying commercial and industrial customers, within our wholesale services segment. We received an initial cash payment of $12 million, which resulted in an $11 million pre-tax gain ($5 million, net of tax). Under the terms of the purchase and sale agreement, we were eligible to receive contingent cash consideration up to $8 million with a guaranteed minimum receipt of $3 million that was recognized during 2013. The remaining $5 million of contingent cash consideration was to be received from the buyer annually over a five-year earn-out period based upon the financial performance of Compass Energy. In the third quarter of 2014, we negotiated with the buyer to settle the future earn-out payments and we received $4 million, resulting in the recognition of a $3 million gain. We have a five-year agreement through April 2018 to supply natural gas to our former customers and as a result of our continued involvement, the sale of Compass Energy did not meet the criteria for treatment as a discontinued operation in 2014.

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 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, uncollectible accounts and other allowances for contingent losses, goodwill and other intangible assets, retirement plan benefit obligations, derivative and hedging activities and provisions for income taxes. We evaluate our estimates on an ongoing basis and our actual results could differ from our estimates.

Accounting Developments

Accounting standards adopted in 2015

In April 2015, the FASB issued updated authoritative guidance related to debt issuance costs. The amendment modifies the presentation of unamortized debt issuance costs on our Consolidated Balance Sheets. Under the new guidance, we present such amounts as a direct deduction from the face amount of the debt, similar to unamortized debt discounts and premiums, rather than as an asset. Amortization of the debt issuance costs continues to be reported as interest expense on the Consolidated Statements of Income. While the guidance would have been effective for us beginning January 1, 2016, we elected to adopt its provisions effective April 1, 2015, and have applied its provisions to each prior period presented for comparative purposes. This new guidance resulted in an adjustment to the presentation of debt issuance costs primarily from other long-term assets to offset the related debt balances in long-term debt totaling $20 million and $21 million as of December 31, 2015 and 2014, respectively. The April 2015 guidance did not address the classification of debt issuance costs related to line-of-credit arrangements and, consequently, we continued to report such costs as assets subject to amortization over the term of the arrangement. In August 2015, the FASB issued clarifying guidance supporting the deferral and presentation of line-of-credit related debt issuance costs as an asset and subsequently amortizing these costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the arrangement.

Other newly issued accounting standards and updated authoritative guidance

In May 2014, the FASB issued updated authoritative guidance related to revenue from contracts with customers. The update replaces most of the existing guidance with a single set of principles for recognizing revenue from contracts with customers. In

July 2015, the FASB delayed the effective date by one year and the guidance will now be effective for us beginning January 1, 2018. Early adoption of the standard is permitted, but not before the original effective date of December 15, 2016. The new guidance must be applied retrospectively to each prior period presented or via a cumulative effect upon the date of initial application. We have not yet determined the impact of this new guidance, nor have we selected a transition method.

In June 2014, the FASB issued an update to authoritative guidance related to accounting for a stock-based compensation performance target that could be achieved after the requisite service period. The guidance was issued to resolve diversity in practice. The new guidance was applied prospectively and became effective for us beginning January 1, 2016. We have determined that this new guidance will not have a material impact on our consolidated financial statements.

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

In April 2015, the FASB issued authoritative guidance related to the accounting for fees paid in connection with arrangements with cloud-based software providers. Under the new guidance, unless a software arrangement includes specific elements enabling customers to possess and operate software on platforms other than that offered by the cloud-based provider, the cost of such arrangements is to be accounted for as an operating expense of the period incurred. The new guidance was applied prospectively and became effective for us on January 1, 2016. We have determined that this new guidance will not have a material impact on our consolidated financial statements.

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

In July 2015, the FASB issued updated 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.

In November 2015, the FASB issued updated authoritative guidance to the Balance Sheet Classification of Deferred Taxes, which requires companies to present deferred income tax assets and deferred income tax liabilities as noncurrent in 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. 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 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, 2019; limited early adoption is permitted. We are currently evaluating the potential impact of this new guidance.

Note 4 – Regulated Operations

Our regulatory assets and liabilities reflected within our Consolidated Balance Sheets as of December 31 are summarized in the following table.



In millions	2015		2014
Regulatory assets
Recoverable ERC	$	31	$	49
Recoverable pension and retiree welfare benefit costs	12		12
Recoverable seasonal rates	10		10
Deferred natural gas costs	6		3
Other	9		9
Regulatory assets - current	68		83
Recoverable ERC	370		329
Recoverable pension and retiree welfare benefit costs	113		110
Recoverable regulatory infrastructure program costs	83		69
Long-term debt fair value adjustment	66		74
Other	38		49
Regulatory assets - long-term	670		631
Total regulatory assets	$	738	$	714
Regulatory liabilities
Accumulated removal costs	$	53	$	25
Bad debt over collection	42		33
Accrued natural gas costs	24		27
Other	15		27
Regulatory liabilities - current	134		112
Accumulated removal costs	1,538		1,520
Regulatory income tax liability	27		34
Bad debt over collection	21		12
Unamortized investment tax credit	20		22
Other	5		13
Regulatory liabilities - long-term	1,611		1,601
Total regulatory liabilities	$	1,745	$	1,713

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.

In the event that the provisions of authoritative guidance related to regulated operations were no longer applicable, we would recognize a write-off of regulatory assets that would result in a charge to net income. Additionally, while some regulatory liabilities would be written off, others would continue to be recorded as liabilities, but not as regulatory liabilities.

Although the natural gas distribution industry is competing with alternative fuels, primarily electricity, our utility operations continue to recover their costs through cost-based rates established by the state regulatory agencies. As a result, we believe that the accounting prescribed under the guidance remains appropriate. It is also our opinion that all regulatory assets are recoverable in future rate proceedings, and therefore, we have not recorded any regulatory assets that are recoverable but are not yet included in base rates or contemplated in a rate rider or proceeding. The regulatory liabilities that do not represent revenue collected from customers for expenditures that have not yet been incurred are refunded to ratepayers through a rate rider or base rates. If the regulatory liability is included in base rates, the amount is reflected as a reduction to the rate base used to periodically set base rates.

The majority of our regulatory assets and liabilities listed in the preceding table are included in base rates except for the regulatory infrastructure program costs, ERC, bad debt over collection, natural gas costs and energy efficiency costs, which are recovered through specific rate riders on a dollar-for-dollar basis. The rate riders that authorize the recovery of regulatory infrastructure program costs and natural gas costs include both a recovery of cost and a return on investment during the recovery period. Nicor Gas’ rate riders for environmental costs and energy efficiency costs provide a return of investment and expense including short-term interest on reconciliation balances. However, there is no interest associated with the under or over collections of bad debt expense.

Nicor Gas’ pension and retiree welfare benefit costs have historically been considered in rate proceedings in the same period they are accrued under GAAP. As a regulated utility, Nicor Gas expects to continue rate recovery of the eligible costs of these defined benefit retirement plans and, accordingly, associated changes in the funded status of Nicor Gas’ plans have been deferred as a regulatory asset or liability until recognized in net income, instead of being recognized in OCI. The Illinois Commission presently does not allow Nicor Gas the opportunity to earn a return on its recoverable retirement benefit costs. Such costs are expected to be recovered over a period of approximately 10 years. The regulatory assets related to debt are also not included in rate base, but the costs are recovered over the term of the debt through the authorized rate of return component of base rates.

Unrecognized Ratemaking Amounts The following table illustrates our authorized ratemaking amounts that are not recognized on our 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	Atlanta Gas Light			Virginia Natural Gas		Elizabethtown Gas		Nicor Gas		Total
December 31, 2015	$	103	⁽¹⁾	$	12	$	4	$	3	$	122
December 31, 2014	113			12		2		—		127

(1)

In October 2015, Atlanta Gas Light received an order from the Georgia Commission, which included a final determination of the true-up recovery related to the PRP. The order allows Atlanta Gas Light to recover $144 million of the $178 million of incurred and allowed costs that were deferred for future recovery. These deferred costs were originally requested in a February 2015 filing for a true-up of unrecovered revenue. See Note 12 for additional information on Atlanta Gas Light’s global resolution of this and other matters that were previously raised before the Georgia Commission.

Natural Gas Costs We charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms established by the state regulatory agencies. Under these mechanisms, all prudently incurred natural gas costs are passed through to customers without markup, subject to regulatory review. We defer or accrue the difference between the actual cost of 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 three rate riders that authorize dollar-for-dollar recovery. We expect to collect $31 million in revenues over the next 12 months, which is reflected as a current regulatory asset. We recovered $40 million in 2015, $51 million in 2014 and $24 million in 2013 from our ERC rate riders. The following table provides additional information on the estimated costs to remediate our current and former operating sites as of December 31, 2015.



In millions	# of sites	Probabilistic model cost estimates ⁽¹⁾	Engineering-based estimates⁽¹⁾		Amount recorded		Expected costs over next 12 months		Cost recovery period
Illinois⁽²⁾	26	$200 - $457	$	50	$	250	$	32	As incurred
New Jersey	6	115 - 195	7		122		18		7 years
Georgia and Florida	13	29 - 52	23		52		12		5 years
North Carolina ⁽³⁾	1	n/a	7		7		5		No recovery
Total	46	$344 - $704	$	87	$	431	$	67


(1)	The year-end ERC cost estimates were completed as of November 30, 2015. The liability recorded reflects a reduction of these cost estimates for expenses incurred during December.


(2)	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%.


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

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

Bad Debt Rider Nicor Gas’ bad debt rider provides for the recovery from, or refund to, customers of the difference between Nicor Gas’ actual bad debt experience on an annual basis and a benchmark, as determined by the Illinois Commission in February 2010. The over recovery is recorded as an increase to operating expenses on our Consolidated Statements of Income and a regulatory liability on our Consolidated Balance Sheets until refunded to customers. In the period refunded, operating expenses are reduced and the regulatory liability is reversed. The actual bad debt experience and resulting refunds are shown in the following table.



			Actual		Total		Amount refunded in				Amount to be refunded in
In millions	Benchmark		bad debt		refund		2014		2015		2016		2017
2015	$	63	$	12	$	51	$	—	$	—	$	30	$	21
2014	63		35		28		—		16		12		—
2013	63		21		42		25		17		—		—

Accumulated Removal Costs In accordance with regulatory treatment, our depreciation rates are comprised of two cost components - historical cost and the estimated cost of removal, net of estimated salvage, of certain regulated properties. We collect these costs in base rates through straight-line depreciation expense, with a corresponding credit to accumulated depreciation. Because the accumulated estimated removal costs are not a generally accepted component of depreciation, but meet the requirements of authoritative guidance related to regulated operations, we have reclassified them from accumulated depreciation to the accumulated removal cost regulatory liability on our Consolidated Balance Sheets. In the rate setting process, the liability for these accumulated removal costs is treated as a reduction to the net rate base upon which our regulated utilities have the opportunity to earn their allowed rate of return.

Regulatory Infrastructure Programs We have infrastructure improvement programs at several of our utilities. Descriptions of these are as follows.

Nicor Gas In 2013, Illinois enacted legislation that allows Nicor Gas to provide more widespread safety and reliability enhancements to its distribution system. The legislation stipulates that rate increases to customer bills as a result of any infrastructure investments shall not exceed an annual average of 4.0% of base rate revenues. In July 2014, the Illinois Commission approved our new regulatory infrastructure program, Investing in Illinois, for which we implemented rates under the program that became effective in March 2015. We filed the first annual update under the program with the Illinois Commission on April 1, 2015.

Atlanta Gas Light Our four-year STRIDE program was approved in December 2013 and is comprised of the Integrated System Reinforcement Program (i-SRP), the Integrated Customer Growth Program (i-CGP), and the Integrated Vintage Plastic Replacement Program (i-VPR).

The i-SRP is permitted to spend $445 million to upgrade our distribution system and liquefied natural gas facilities in Georgia, improve our peak-day system reliability and operational flexibility, and create a platform to meet long-term forecasted growth. The STRIDE program requires us to file an updated ten-year forecast of infrastructure requirements under i-SRP along with a new construction plan every three years for review and approval by the Georgia Commission.

Our i-CGP authorizes Atlanta Gas Light to spend $91 million to extend its pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia.

The purpose of the i-VPR program is to replace aging plastic pipe that was installed primarily in the 1960’s to the early 1980’s. We have identified approximately 3,300 miles of vintage plastic mains in our system that potentially should be considered for replacement over the next 15 - 20 years as it reaches the end of its useful life. In 2013, the Georgia Commission approved the replacement of 756 miles of vintage plastic pipe over four years at an estimated cost of $275 million.

Additional reporting requirements and monitoring by the staff of the Georgia Commission were included in the approval of our STRIDE programs, which authorized a phased-in approach to funding the programs through monthly rider surcharges that began in 2015 and will remain through 2025.

The orders for the STRIDE programs provide for recovery of all prudent costs incurred in the performance of the program. Atlanta Gas Light will recover from end-use customers, through billings to Marketers, the costs related to the programs net of any cost savings from the programs. All such amounts will be recovered through a combination of straight-fixed-variable rates and a STRIDE revenue rider surcharge. The regulatory asset represents recoverable incurred costs related to the programs that will be collected in future rates charged to customers through the rate riders. The future expected costs to be recovered through rates related to allowed, but not incurred costs, are recognized in an unrecognized ratemaking amount that is not reflected on our Consolidated Balance Sheets. This allowed cost is primarily the equity return on the capital investment under the program.

Atlanta Gas Light capitalizes and depreciates the capital expenditure costs incurred from the STRIDE programs over the life of the assets. Operation and maintenance costs are expensed as incurred. Recoveries, which are recorded as revenue, are based on a formula that allows Atlanta Gas Light to recover operation and maintenance costs in excess of those included in its current base rates, depreciation expense and an allowed rate of return on capital expenditures. However, Atlanta Gas Light is allowed the recovery of carrying costs on the under-recovered balance resulting from the timing difference.

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.

In 2009, the New Jersey BPU approved the enhanced infrastructure program for Elizabethtown Gas, which was created in response to the New Jersey Governor’s request for utilities to assist in the economic recovery by increasing infrastructure investments. In May 2011, the New Jersey BPU approved Elizabethtown Gas’ request to spend an additional $40 million under this program, the precursor to the accelerated infrastructure replacement program, before the end of 2012. Costs associated with the investment in this program are recovered through periodic adjustments to base rates that are approved by the New Jersey BPU. In August 2013, the New Jersey BPU approved the recovery of investments under this program through a permanent adjustment to base rates.

Additionally, in August 2013, we received approval from the New Jersey BPU for an extension of the accelerated infrastructure replacement program, which allows for infrastructure investment of $115 million over four years, effective as of September 1, 2013. Carrying charges on the additional capital expenditures will be deferred at a WACC of 6.65%, of which 4.27% will be within unrecognized ratemaking amounts and will be recognized in future periods when recovered through rates. Unlike the previous program, there will be no adjustment to base rates for the investments under the extended program until Elizabethtown Gas files its next rate case. We agreed to file a general rate case by September 2016.

In September 2013, Elizabethtown Gas filed for ENDURE, a program designed to improve our distribution system’s resiliency against coastal storms and floods. Under the proposed plan, Elizabethtown Gas invested $15 million in infrastructure and related facilities and communication planning over a one year period that began in January 2014. In July 2014, the New Jersey BPU approved a modified ENDURE plan that allowed Elizabethtown Gas to increase its base rates effective November 1, 2015 for investments made under the program. The program was completed in October 2015.

Virginia Natural Gas In 2012, the Virginia Commission approved SAVE, an accelerated infrastructure replacement program, which is expected to be completed over a five-year period. The program permits a maximum capital expenditure of $25 million per year, not to exceed $105 million in total. SAVE is subject to annual review by the Virginia Commission. We began recovering program costs through a rate rider that was effective August 1, 2012. The second year performance rate update was approved by the Virginia Commission in July 2014 and became effective as of August 2014.

In November 2015, Virginia Natural Gas filed with the Virginia Commission for approval of an extension to the SAVE program through 2021, requesting approval of $30 million in 2016 and $35 million in each of 2017 through 2021.

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

energySMART In May 2014, the Illinois Commission approved Nicor Gas’ energySMART, which outlines energy efficiency program offerings and therm reduction goals with spending of $93 million over a three-year period that began in June 2014. Nicor Gas’ first energy efficiency program ended in May 2014.

Investment Tax Credits Deferred investment tax credits associated with distribution operations are included as a regulatory liability on our Consolidated Balance Sheets. These investment tax credits are being amortized over the estimated lives of the related properties as credits to income tax expense.

Regulatory Income Tax Liability For our regulated utilities, we measure deferred income tax assets and liabilities using enacted income tax rates. Thus, when the statutory income tax rate declines before a temporary difference has fully reversed, the deferred income tax liability must be reduced to reflect the newly enacted income tax rates. However, the amount of the reduction is transferred to our regulatory income tax liability, which we are amortizing over the lives of the related properties as the temporary differences reverse over approximately 30 years.

Other Regulatory Assets and Liabilities Our recoverable pension and retiree welfare benefit plan costs for our utilities other than Nicor Gas are expected to be recovered through base rates over the next 8 to 17 years, based on the remaining recovery periods as designated by the applicable state regulatory agencies. This category also includes recoverable seasonal rates, which reflect the difference between the recognition of a portion of Atlanta Gas Light’s residential base rates revenues on a straight-line basis as compared to the collection of the revenues over a seasonal pattern. These amounts are fully recoverable through base rates within one year.

Note 5 - Fair Value Measurements

Retirement benefit plans assets

The assets of the AGL Resources Inc. Retirement Plan (AGL Plan) and the Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. (AGL Welfare Plan) were allocated 72% equity and 28% fixed income at December 31, 2015, and 70% equity, 29% fixed income and 1% cash at December 31, 2014 compared to our targets of 70% to 95% equity, 5% to 20% fixed income, and up to 10% cash for both periods. The plans’ investment policies provide for some variation in these targets. The actual asset allocations of our retirement plans are presented in the following table by level within the fair value hierarchy.



	December 31, 2015
	Pension plans⁽¹⁾										Welfare plans
In millions	Level 1		Level 2		Level 3		Total		% of total		Level 1		Level 2		Level 3		Total		% of total
Cash	$	4	$	—	$	—	$	4	—		$	1	$	—	$	—	$	1	1	%
Equity securities:
U.S. large cap⁽²⁾	$	75	$	199	$	—	$	274	32	%	$	—	$	52	$	—	$	52	58	%
U.S. small cap⁽²⁾	57		24		—		81		9	%	—		—		—		—		—
International companies ⁽³⁾	—		125		—		125		15	%	—		15		—		15		17	%
Emerging markets ⁽⁴⁾	—		28		—		28		3	%	—		—		—		—		—
Total equity securities	$	132	$	376	$	—	$	508	59	%	$	—	$	67	$	—	$	67	75	%
Fixed income securities:
Corporate bonds ⁽⁵⁾	$	—	$	91	$	—	$	91	11	%	$	—	$	22	$	—	$	22	24	%
Other (or gov’t/muni bonds)	—		151		—		151		18	%	—		—		—		—		—
Total fixed income securities	$	—	$	242	$	—	$	242	29	%	$	—	$	22	$	—	$	22	24	%
Other types of investments:
Global hedged equity⁽⁶⁾	$	—	$	—	$	40	$	40	5	%	$	—	$	—	$	—	$	—	—
Absolute return ⁽⁷⁾	—		—		42		42		5	%	—		—		—		—		—
Private capital ⁽⁸⁾	—		—		20		20		2	%	—		—		—		—		—
Total other investments	$	—	$	—	$	102	$	102	12	%	$	—	$	—	$	—	$	—	—
Total assets at fair value	$	136	$	618	$	102	$	856	100	%	$	1	$	89	$	—	$	90	100	%
% of fair value hierarchy	16%		72%		12%		100%				1%		99%		—		100%



	December 31, 2014
	Pension plans ⁽¹⁾										Welfare plans
In millions	Level 1		Level 2		Level 3		Total		% of total		Level 1		Level 2		Level 3		Total		% of total
Cash	$	4	$	1	$	—	$	5	1	%	$	1	$	—	$	—	$	1	1	%
Equity securities:
U.S. large cap ⁽²⁾	$	95	$	203	$	—	$	298	33	%	$	—	$	51	$	—	$	51	57	%
U.S. small cap ⁽²⁾	76		24		—		100		11	%	—		—		—		—		—
International companies ⁽³⁾	—		123		—		123		13	%	—		16		—		16		18	%
Emerging markets ⁽⁴⁾	—		31		—		31		3	%	—		—		—		—		—
Total equity securities	$	171	$	381	$	—	$	552	60	%	$	—	$	67	$	—	$	67	75	%
Fixed income securities:
Corporate bonds ⁽⁵⁾	$	—	$	233	$	—	$	233	25	%	$	—	$	22	$	—	$	22	24	%
Other (or gov’t/muni bonds)	—		33		—		33		4	%	—		—		—		—		—
Total fixed income securities	$	—	$	266	$	—	$	266	29	%	$	—	$	22	$	—	$	22	24	%
Other types of investments:
Global hedged equity⁽⁶⁾	$	—	$	—	$	29	$	29	3	%	$	—	$	—	$	—	$	—	—
Absolute return ⁽⁷⁾	—		—		42		42		5	%	—		—		—		—		—
Private capital ⁽⁸⁾	—		—		20		20		2	%	—		—		—		—		—
Total other investments	$	—	$	—	$	91	$	91	10	%	$	—	$	—	$	—	$	—	—
Total assets at fair value	$	175	$	648	$	91	$	914	100	%	$	1	$	89	$	—	$	90	100	%
% of fair value hierarchy	19%		71%		10%		100%				1%		99%		—		100%


(1)	Includes $9 million at December 31, 2015 and $9 million at December 31, 2014 of medical benefit (health and welfare) component for 401h accounts to fund a portion of the other retirement benefits.


(2)	Includes funds that invest primarily in U.S. common stocks.


(3)	Includes funds that invest primarily in foreign equity and equity-related securities.


(4)	Includes funds that invest primarily in common stocks of emerging markets.


(5)	Includes funds that invest primarily in investment grade debt and fixed income securities.


(6)	Includes funds that invest in limited / general partnerships, managed accounts, and other investment entities issued by non-traditional firms or “hedge funds.”


(7)	Includes funds that invest primarily in investment vehicles and commodity pools as a “fund of funds.”


(8)	Includes funds that invest in private equity and small buyout funds, partnership investments, direct investments, secondary investments, directly / indirectly in real estate and may invest in equity securities of real estate related companies, real estate mortgage loans, and real estate mezzanine loans.

The following is a reconciliation of our retirement plan assets in Level 3 of the fair value hierarchy.



	Fair value measurements using significant unobservable inputs - Level 3 ⁽¹⁾
In millions	Global hedged equity			Absolute return		Private capital			Total
Balance at December 31, 2013	$	43		$	39	$	22		$	104
Actual return on plan assets	1			3		2			6
Sales	(15		)	—		(4		)	(19		)
Balance at December 31, 2014	$	29		$	42	$	20		$	91
Actual return on plan assets	(1		)	—		3			2
Purchases	12			—		—			12
Sales	—			—		(3		)	(3		)
Balance at December 31, 2015	$	40		$	42	$	20		$	102

(1) There were no transfers out of Level 3, or between Level 1 and Level 2 for any of the periods presented.

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 Consolidated Balance Sheets as of December 31. See Note 6 for additional information on our derivative instruments.



	2015					2014
In millions	Assets⁽¹⁾		Liabilities			Assets⁽¹⁾		Liabilities
Natural gas derivatives
Quoted prices in active markets (Level 1)	$	53	$	(63	)	$	58	$	(80	)
Significant other observable inputs (Level 2)	122		(46		)	174		(94		)
Netting of cash collateral	33		63			52		81
Total carrying value ⁽²⁾	$	208	$	(46	)	$	284	$	(93	)


(1)	Balances of $10 million and $3 million at December 31, 2015 and 2014, respectively, 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 presents the carrying amount and fair value of our long-term debt as of December 31.



In millions	2015		2014
Long-term debt carrying amount ⁽¹⁾	$	3,820	$	3,781
Long-term debt fair value⁽²⁾	4,066		4,231


(1)	The change in the December 31, 2014 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. See Note 9 for additional information.


(2)	Fair value determined using Level 2 inputs.

Note 6 - Derivative Instruments

Our risk management activities are monitored by our Risk Management Committee, which consists of members of senior management and is charged with reviewing our risk management activities and enforcing policies. Our use of derivative instruments, including physical transactions, is limited to predefined risk tolerances associated with pre-existing or anticipated physical natural gas sales and purchases and system use and storage. We use the following types of derivative instruments and energy-related contracts to manage natural gas price, interest rate, weather, automobile fuel price and foreign currency risks when deemed appropriate:


•	forward, futures and options contracts;


•	financial swaps;


•	treasury locks;


•	weather derivative contracts;


•	storage and transportation capacity contracts; and


•	foreign currency forward contracts

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 December 31, 2015 and 2014, for agreements with such features, derivative instruments with liability fair values totaled $46 million and $93 million, respectively, for which we had posted no collateral to our counterparties as we exceed the minimum credit rating requirements. As of December 31, 2015, the maximum collateral that could have been required with these features was $2 million. For additional information on our credit-risk-related contingent features, see “Energy Marketing Receivables and Payables” in Note 3 herein. Our derivative instrument activities are included within operating cash flows as an increase (decrease) to net income of $22 million, $(155) million and $66 million for the periods ended December 31, 2015, 2014 and 2013, respectively.

The following table summarizes the various ways in which we account for our derivative instruments and the impact on our consolidated financial statements.





	Recognition and Measurement
Accounting Treatment	Balance Sheets	Income Statements
Cash flow hedge	Derivative carried at fair value	Ineffective portion of the gain or loss realized and unrealized on the derivative instrument is recognized in earnings
Cash flow hedge	Effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated OCI (loss)	Effective portion of the gain or loss realized and unrealized on the derivative instrument is reclassified out of accumulated OCI (loss) and into earnings when the hedged transaction affects earnings
Fair value hedge	Derivative carried at fair value	Gains or losses realized and unrealized on the derivative instrument and the hedged item are recognized in earnings. As a result, to the extent the hedge is effective, the gains or losses will offset and there is no impact on earnings. Any hedge ineffectiveness will impact earnings
Fair value hedge	Changes in fair value of the hedged item are recorded as adjustments to the carrying amount of the hedged item
Not designated as hedges	Derivative carried at fair value	Gains or losses realized and unrealized on the derivative instrument are recognized in earnings
Not designated as hedges	Distribution operations’ gains and losses on derivative instruments are deferred as regulatory assets or liabilities until included in cost of goods sold	Gains or losses realized and unrealized on the derivative instruments are ultimately included in billings to customers and are recognized in cost of goods sold in the same period as the related revenues

Quantitative Disclosures Related to Derivative Instruments

Our derivative instruments are comprised of both long and short natural gas positions. A long position is a contract to purchase natural gas, and a short position is a contract to sell natural gas. As of December 31, we had natural gas contracts outstanding in the following quantities:



In Bcf ⁽¹⁾	2015 ⁽²⁾		2014
Cash flow hedges	5		9
Not designated as hedges	(14	)	75
Total volumes	(9	)	84
Short position – cash flow hedges	(6	)	(4	)
Short position – not designated as hedges	(3,089	)	(2,828	)
Long position – cash flow hedges	11		13
Long position – not designated as hedges	3,075		2,903
Net (short) long position	(9	)	84


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


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

Derivative Instruments on our 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 Consolidated Balance Sheets until billed to customers. The following amounts deferred as a regulatory asset or liability on our Consolidated Balance Sheets represent the net realized gains (losses) related to these natural gas cost hedging activities as of December 31.



In millions	2015			2014
Nicor Gas	$	(47	)	$	10
Elizabethtown Gas	(20		)	2

The following table presents the fair values and Consolidated Balance Sheets classifications of our derivative instruments as of December 31.



		2015						2014
In millions	Classification	Assets			Liabilities			Assets			Liabilities
Designated as cash flow or fair value hedges
Natural gas contracts	Current	$	3		$	(5	)	$	6		$	(11	)
Natural gas contracts	Long-term	—			(2		)	—			(1		)
Interest rate swap agreements	Current	9			—			—			—
Total designated as cash flow or fair value hedges		$	12		$	(7	)	$	6		$	(12	)
Not designated as hedges
Natural gas and weather contracts	Current	$	751		$	(672	)	$	1,061		$	(1,020	)
Natural gas contracts	Long-term	179			(187		)	145			(119		)
Total not designated as hedges		$	930		$	(859	)	$	1,206		$	(1,139	)
Gross amount of recognized assets and liabilities ^{(1) (2)}		942			(866		)	1,212			(1,151		)
Gross amounts offset on our Consolidated Balance Sheets⁽²⁾		(724		)	820			(925		)	1,058
Net amounts of assets and liabilities presented on our Consolidated Balance Sheets ⁽³⁾		$	218		$	(46	)	$	287		$	(93	)


(1)	The gross amounts of recognized assets and liabilities are netted on our 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 $96 million as of December 31, 2015 and $133 million as of December 31, 2014. Cash collateral is included in the “Gross amounts offset on our Consolidated Balance Sheets” line of this table.


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

Derivative Instruments on our Consolidated Statements of Income

The following table presents the impacts of our derivative instruments on our Consolidated Statements of Income for the years ended December 31.



In millions	2015			2014			2013
Designated as cash flow or fair value hedges
Natural gas contracts – net gain (loss) reclassified from OCI into cost of goods sold	$	(10	)	$	4		$	(1	)
Natural gas contracts – net gain (loss) reclassified from OCI into operation and maintenance expense	(1		)	1			—
Interest rate swaps – net gain (loss) reclassified from OCI into interest expense	2			—			(3		)
Income tax	1			(2		)	1
Total designated as cash flow or fair value hedges, net of tax	$	(8	)	$	3		$	(3	)
Not designated as hedges ⁽¹⁾
Natural gas contracts - net fair value adjustments recorded in operating revenues	$	56		$	149		$	(90	)
Natural gas contracts - net fair value adjustments recorded in cost of goods sold⁽²⁾	(6		)	(7		)	2
Income tax	(19		)	(54		)	34
Total not designated as hedges, net of tax	$	31		$	88		$	(54	)
Total gains (losses) on derivative instruments, net of tax	$	23		$	91		$	(57	)


(1)	Associated with the fair value of derivative instruments held at December 31, 2015, 2014 and 2013.


(2)	Excludes (gains) and losses recorded in cost of goods sold associated with weather derivatives of $(12) million, $7 million and $5 million for the years ended December 31, 2015, 2014 and 2013, respectively.

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 years ended December 31, 2015, 2014 and 2013. Our expected gains and losses to be reclassified from OCI into cost of goods sold, operation and maintenance expense, interest expense and operating revenues and recognized on our Consolidated Statements of Income over the next 12 months are $2 million. These deferred gains are related to natural gas derivative contracts associated with retail operations’ and Nicor Gas’ system use. The expected gains are based upon the fair values of these financial instruments at December 31, 2015. The effective portions of gains and losses on derivative instruments qualifying as cash flow hedges that were recognized in OCI during the periods are presented on our Consolidated Statements of Income. See Note 10 for these amounts.

Note 7 - Employee Benefit Plans

Investment Policies, Strategies and Oversight of Plans

The Retirement Plan Investment Committee (the Committee) appointed by our Board of Directors is responsible for overseeing the investments of our defined benefit retirement plan and welfare plan. Further, we have an Investment Policy (the Policy) for our pension and welfare benefit plans whose goal is to preserve these plans’ capital and maximize investment earnings in excess of inflation within acceptable levels of capital market volatility. To accomplish this goal, the plans’ assets are managed to optimize long-term return while maintaining a high standard of portfolio quality and diversification.

In developing our allocation policy for the pension and welfare plan assets, we examined projections of asset returns and volatility over a long-term horizon. In connection with this analysis, we evaluated the risk and return trade-offs of alternative asset classes and asset mixes given long-term historical relationships as well as prospective capital market returns. We also conducted an asset-liability study to match projected asset growth with projected liability growth to determine whether there is sufficient liquidity for projected benefit payments. We developed our asset mix guidelines by incorporating the results of these analyses with an assessment of our risk posture, and taking into account industry practices. We periodically evaluate our investment strategy to ensure that plan assets are sufficient to meet the benefit obligations of the plans. As part of the ongoing evaluation, we may make changes to our targeted asset allocations and investment strategy.

Our investment strategy is designed to meet the following objectives:


•	Generate investment returns that, in combination with our funding contributions, provide adequate funding to meet all current and future benefit obligations of the plans.


•	Provide investment results that meet or exceed the assumed long-term rate of return, while maintaining the funded status of the plans at acceptable levels.


•	Improve funded status over time.


•	Decrease contribution and expense volatility as funded status improves.

To achieve these investment objectives, our investment strategy is divided into two primary portfolios of return seeking and liability hedging assets. Return seeking assets are intended to provide investment returns in excess of liability growth and reduce deficits in the funded status of the plans, while liability hedging assets are intended to reflect the sensitivity of the liabilities to changes in discount rates.

See Note 5 for a detailed listing of the investment types, amounts and percentages allocated to the plans. We will continue to diversify retirement plan investments to minimize the risk of large losses in a single asset class. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund. The Policy’s permissible investments include domestic and international equities (including convertible securities and mutual funds), domestic and international fixed income securities (corporate and government obligations), cash and cash equivalents and other suitable investments.

Equity market performance and corporate bond rates have a significant effect on our reported funded status. Changes in the projected benefit obligation (PBO) and accumulated postretirement benefit obligation (APBO) are mainly driven by the assumed discount rate. Additionally, equity market performance has a significant effect on our market-related value of plan assets (MRVPA), which is used by the AGL Plan to determine the expected return on the plan assets component of net annual pension cost. The MRVPA is a calculated value. Gains and losses on plan assets are spread through the MRVPA based on the five-year smoothing weighted average methodology.

Pension Benefits

We sponsor the AGL Plan, which is a tax-qualified defined benefit retirement plan for the following classes of eligible employees: i) AGL Resources’ non-union employees who were employed before January 1, 2012, ii) AGL Resources’ union employees who were employed before January 1, 2013, iii) former Nicor employees who were employed before January 1, 1998, iv) former NUI employees who were employed on or before December 31, 2005, and v) Florida City Gas union employees as of February 1, 2008, who previously participated in a union-sponsored multiemployer plan. A defined benefit plan specifies the amount of benefits an eligible participant will eventually receive using information about the participant, including information related to the participant’s earnings history, years of service and age. Our employees who are not eligible for the AGL Plan are entitled to employer provided benefits under their defined contribution plan that exceeds the defined contribution benefits for those employees who participate in the defined benefit plan.

The benefit formula for the former AGL Plan is currently a career average earnings formula. Participants who were employees as of July 1, 2000 and who were at least 50 years of age as of that date earned benefits until December 31, 2010 under a final average pay formula. Participants who were employed as of July 1, 2000, but did not satisfy the age requirement to continue under the final average earnings formula transitioned to the career average earnings formula on July 1, 2000.

Prior to 2013, we also sponsored two other tax-qualified defined benefit retirement plans for our eligible employees, the Nicor plan and NUI plan, which were merged into the AGL Plan on December 31, 2012. The participants of these former plans are now being offered their benefits, as described below, through the AGL Plan.

Participants in the former Nicor plan, employees hired before January 1, 1998, receive noncontributory defined pension benefits. Pension benefits are based on years of service and the highest average annual salary for management employees and job level for collectively bargained employees (referred to as pension bands). The benefit obligation related to collectively bargained benefits reflects the most recent collective bargained agreement terms with regards to the benefit increases. The former NUI plan included substantially all of NUI Corporation’s employees and provided pension benefits based on years of credited service and final average compensation as of the plan freeze date on December 31, 2005.

Welfare Benefits

We sponsor the AGL Welfare Plan, which is a defined benefit retiree health care plan for our eligible employees who reach the plan’s retirement age while working for us or are receiving benefits under the AGL Resources sponsored long-term disability plan for the legacy AGL employees. This plan includes medical coverage and life insurance benefits for eligible employees: i) AGL Resources’ employees who were employed as of June 30, 2002, and ii) former Nicor employees who were employed before March 18, 2014. Eligibility for these benefits is based on age and years of service.

Prior to 2013, we also sponsored the Nicor Welfare Benefit Plan, which was terminated as of January 1, 2013. Participants under that plan became eligible to participate in the AGL Welfare Plan. This change in plan participation eligibility did not affect the benefit terms.

The state regulatory agencies have approved phase-in plans that defer a portion of the related benefits expense for future recovery. Additionally, the plan terms include limits on the employer share of costs based on the coverage tier, hire date, plan elected and salary level of the employee at retirement.

The former AGL Welfare Plan requires contributions by the retirees. Our medical costs are limited to a pre-determined cap amount and eligible retirees pay 100% of the dental and vision premiums. Medicare eligible retirees covered by the former AGL Welfare Plan, including all of those at least age 65, receive benefits through our contribution to a retiree health reimbursement arrangement account. Additionally, on the pre-65 medical coverage of the former AGL Welfare Plan, our expected cost is determined by a retiree premium schedule based on salary level and years of service. Due to the cost limits, there is no impact on our periodic benefit cost or on our accumulated projected benefit obligation for a change in the assumed healthcare cost trend rate for this portion of the plan. The former Nicor Welfare Plan requires contributions for certain categories of retirees. For employees hired on or after January 1, 1983, our medical costs are limited to a pre-determined cap amount based on their years of service at retirement.

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 provides for a prescription drug benefit under Medicare Part D, as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Prescription drug coverage for the Nicor Gas Medicare-eligible population changed effective January 1, 2013 from an employer-sponsored prescription drug plan with the Retiree Drug Subsidy to an Employer Group Waiver Plan (EGWP). The EGWP replaces the employer-sponsored prescription drug plan.

We also have a separate unfunded supplemental retirement health care plan that provides health care and life insurance benefits to employees of discontinued businesses. This plan is noncontributory with defined benefits. The APBO associated with this plan was $2 million at December 31, 2015 and $3 million at December 31, 2014.

Assumptions

We considered a variety of factors in determining and selecting our assumptions for the discount rates at December 31. In the fourth quarter of 2015, we changed the method we use to estimate the service and interest cost components of net periodic benefit cost for our defined benefit pension and other postretirement benefit plans. Historically, we estimated the service and interest cost components using a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. We have elected to use a full yield curve approach in the estimation of these components of benefit cost by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows.

The following table presents the components of our pension and welfare costs for the years ended December 31.



	Pension plans									Welfare plans
Dollars in millions	2015			2014			2013			2015			2014			2013
Service cost	$	28		$	24		$	29		$	2		$	2		$	3
Interest cost	45			47			43			13			15			14
Expected return on plan assets	(65		)	(65		)	(62		)	(7		)	(7		)	(6		)
Net amortization of prior service cost	(2		)	(2		)	(2		)	(3		)	(3		)	(5		)
Recognized actuarial loss	31			22			35			6			6			8
Net periodic benefit cost	$	37		$	26		$	43		$	11		$	13		$	14
Assumptions used to determine benefit costs
Discount rate ⁽¹⁾	4.2%			5.0%			4.2%			4.0%			4.7%			4.0%
Expected return on plan assets⁽¹⁾	7.8%			7.8%			7.8%			7.8%			7.8%			7.8%
Rate of compensation increase ⁽¹⁾	3.7%			3.7%			3.7%			3.7%			3.7%			3.8%
Pension band increase⁽²⁾	2.0%			2.0%			2.0%			n/a			n/a			n/a


(1)	Rates are presented on a weighted average basis on a before tax basis for the Welfare plans.


(2)	Only applicable to the Nicor Gas union employees. The pension bands for the former Nicor Plan have been updated to reflect the new negotiated rates for 2016 and 2017 of 2.0% and 2.0%, respectively, as indicaated in the union agreement dated March 2014.

The following tables present details about our pension and welfare plans.



	Pension plans						Welfare plans
Dollars in millions	2015			2014			2015			2014
Change in plan assets
Fair value of plan assets, January 1,	$	906		$	907		$	99		$	93
Actual return on plan assets	(12		)	68			1			5
Employee contributions	—			—			1			2
Employer contributions	2			1			17			17
Benefits paid	(49		)	(70		)	(20		)	(19		)
Medicare Part D reimbursements	—			—			1			1
Fair value of plan assets, December 31,	$	847		$	906		$	99		$	99
Change in benefit obligation
Benefit obligation, January 1,	$	1,098		$	960		$	334		$	326
Service cost	28			24			2			2
Interest cost	45			47			13			15
Actuarial loss (gain)	(55		)	137			(13		)	8
Medicare Part D reimbursements	—			—			1			1
Benefits paid	(49		)	(70		)	(20		)	(19		)
Employee contributions	—			—			1			1
Benefit obligation, December 31,	$	1,067		$	1,098		$	318		$	334
Funded status at end of year	$	(220	)	$	(192	)	$	(219	)	$	(235	)
Amounts recognized on the Consolidated Balance Sheets
Long-term asset ⁽²⁾	$	78		$	97		$	—		$	—
Current liability	(4		)	(2		)	—			—
Long-term liability	(294		)	(287		)	(219		)	(235		)
Net liability at December 31,	$	(220	)	$	(192	)	$	(219	)	$	(235	)
Accumulated benefit obligation ⁽¹⁾	$	1,002		$	1,027		n/a			n/a
Assumptions used to determine benefit obligations
Discount rate	4.6		%	4.2		%	4.4		%	4.0		%
Rate of compensation increase	3.7			3.7			3.7			3.7
Pension band increase⁽³⁾	2.0			2.0			n/a			n/a


(1)	APBO differs from the projected benefit obligation in that APBO excludes the effect of salary and wage increases.


(2)	As a result of historically having multiple plans, a portion of our obligation is in an asset position.


(3)	Only applicable to the Nicor Gas union employees.

A portion of the net benefit cost or credit related to these plans has been capitalized as a cost of constructing gas distribution facilities and the remainder is included in operation and maintenance expense.

Assumptions used to determine the health care benefit cost for the AGL Welfare Plan are set forth in the following table.



	2015		2014
Health care cost trend rate assumed for next year	7.9	%	8.1	%
Ultimate rate to which the cost trend rate is assumed to decline	4.5	%	4.5	%
Year that reaches ultimate trend rate	2030		2030

Assumed health care cost trend rates can have a significant effect on the amounts reported for the health care plans. A one percentage point change in the assumed health care cost trend rates for the AGL Welfare Plan would have the following effects on our benefit obligation, and there was no effect on our service and interest cost.



In millions	Effect on benefit obligation
1% Health care cost trend rate increase	$	13
1% Health care cost trend rate decrease	(11		)

As a result of a cap on expected cost for the AGL Welfare Plan, a one percentage point increase or decrease in the assumed health care trend does not materially affect the Plan’s periodic benefit cost or accumulated benefit obligation. The effects presented above are related to the former Nicor Welfare Plan.

The following table presents the amounts not yet reflected in net periodic benefit cost and included in net regulatory assets and accumulated OCI as of December 31, 2015 and 2014.



	Net regulatory assets					Accumulated OCI					Total
In millions	Pension plans		Welfare plans			Pension plans			Welfare plans		Pension plans			Welfare plans
December 31, 2015
Prior service credit	$	—	$	(15	)	$	(4	)	$	—	$	(4	)	$	(15	)
Net loss	88		45			286			36		374			81
Total	$	88	$	30		$	282		$	36	$	370		$	66
December 31, 2014
Prior service credit	$	—	$	(18	)	$	(6	)	$	—	$	(6	)	$	(18	)
Net loss	76		57			307			36		383			93
Total	$	76	$	39		$	301		$	36	$	377		$	75

The 2016 estimated amortizations out of regulatory assets or accumulated OCI for these plans are set forth in the following table.



	Net regulatory assets					Accumulated OCI					Total
In millions	Pension plans		Welfare plans			Pension plans			Welfare plans		Pension plans			Welfare plans
Amortization of prior service credit	$	—	$	(3	)	$	(2	)	$	—	$	(2	)	$	(3	)
Amortization of net loss	7		2			17			3		24			5

We recorded regulatory assets for anticipated future cost recoveries of $125 million and $122 million as of December 31, 2015 and 2014, respectively.

The following table presents the gross benefit payments expected for the years ended December 31, 2016 through 2025 for our pension and welfare plans. There will be benefit payments under these plans beyond 2025.



In millions	Pension plans		Welfare plans
2016	$	79	$	20
2017	68		20
2018	70		21
2019	73		22
2020	75		23
2021-2025	374		116

Contributions

Our employees generally do not contribute to our pension and welfare plans; however, most Nicor Gas and pre-65 AGL retirees make contributions to their health care plan. We fund the qualified pension plans by contributing at least the minimum amount required by applicable regulations and as recommended by our actuary. However, we may also contribute in excess of the

minimum required amount. As required by The Pension Protection Act of 2006 (the Act), we calculate the minimum amount of funding using the traditional unit credit cost method.

The Act contained new funding requirements for single-employer defined benefit pension plans and established a 100% funding target (over a 7-year amortization period) for plan years beginning after December 31, 2007. In 2015 and 2014, we had no required contributions to the merged AGL Plan.

Employee Savings Plan Benefits

We sponsor defined contribution retirement benefit plans that allow eligible participants to make contributions to their accounts up to specified limits. Under these plans, our matching contributions to participant accounts were $17 million in 2015, $17 million in 2014 and $14 million in 2013.

Note 8 – Stock-Based Compensation

General

The AGL Resources Inc. Omnibus Performance Incentive Plan, as amended and restated, and the Long-Term Incentive Plan (1999) provide for the grant of incentive and nonqualified stock options, stock appreciation rights, shares of restricted stock, restricted stock units, performance cash awards and other stock-based awards to officers and key employees. Under the Omnibus Performance Incentive Plan, as of December 31, 2015, the number of shares issuable upon exercise of outstanding stock options, warrants and rights is 359,586 shares. Under the Long-Term Incentive Plan (1999), as of December 31, 2015, the number of shares issuable upon exercise of outstanding stock options, warrants and rights is 80,600 shares. The maximum number of shares available for future issuance under the Omnibus Performance Incentive Plan is 3,513,992 shares, which includes 1,514,116 shares previously available under the Nicor Inc. 2006 Long-Term Incentive Plan, as amended, pursuant to NYSE rules. No further grants will be made from the Long-Term Incentive Plan (1999) except for reload options that may be granted pursuant to the terms of certain outstanding options.

Accounting Treatment and Compensation Expense

We measure and recognize stock-based compensation expense for our stock-based awards over the requisite service period in our financial statements based on the estimated fair value at the date of grant for our stock-based awards using the modified prospective method. These stock awards include:


•	stock options;


•	stock and restricted stock awards; and


•	performance units (restricted stock units, performance share units and performance cash units).

Performance-based stock awards and performance units contain market and performance conditions. Stock options, restricted stock awards and performance units also contain a service condition. We estimate forfeitures over the requisite service period when recognizing compensation expense. These estimates are adjusted to the extent that actual forfeitures differ, or are expected to materially differ, from such estimates. The authoritative guidance requires excess tax benefits to be reported as a financing cash inflow. The difference between the proceeds from the exercise of our stock-based awards and the par value of the stock is recorded within additional paid-in capital.

We have granted stock awards with a grant price equal to the fair market value on the date of the grant. Fair market value is defined under the terms of the applicable plans as the closing price per share of AGL Resources common stock on the grant date. The following table provides additional information related to our cash and stock-based compensation awards.



In millions	2015		2014		2013
Compensation costs⁽¹⁾	$	40	$	24	$	22
Income tax benefits ⁽¹⁾	1		1		1
Excess tax benefits⁽²⁾	—		—		—


(1)	Recorded in our Consolidated Statements of Income.


(2)	Recorded in our Consolidated Balance Sheets.

Incentive and Nonqualified Stock Options

The stock options we granted generally have a three-year vesting period and expire 10 years after the date of grant. Participants realize value from option grants only to the extent that the fair market value of our common stock on the date of exercise of the option exceeds the fair market value of the common stock on the date of the grant.

As of December 31, 2015 and 2014, we had no unrecognized compensation costs related to stock options. Cash received from stock option exercises for 2015 and 2014 were $5 million and $9 million, respectively, and the income tax benefit from stock option exercises was immaterial for both years. The following tables summarize activity related to stock options for key employees and non-employee directors. As used in the table, intrinsic value for options means the difference between the current market value and the grant price.



Stock Options		Number of options		Weighted average exercise price		Weighted average remaining life (in years)	Aggregate intrinsic value (in millions)
Outstanding	December 31, 2012	1,528,590		$	36.09
Exercised		(617,358	)	35.37
Forfeited		(12,500	)	38.36
Outstanding ⁽¹⁾	December 31, 2013	898,732		$	36.55
Exercised		(267,182	)	36.84
Forfeited		(4,000	)	39.71
Outstanding ⁽¹⁾	December 31, 2014	627,550		$	36.41	2.2	$	11
Exercised		(523,400	)	36.00		1.1
Outstanding ^{(1) (2)}	December 31, 2015	104,150		$	38.46	1.3	$	3


(1)	All options outstanding at December 31, 2015, 2014 and 2013 were exercisable.


(2)	The range of exercise prices for the options outstanding at December 31, 2015 was $31.09 to $43.54.

We measure compensation cost related to stock options based on the fair value of these awards at their date of grant using the Black-Scholes option-pricing model. There were no options granted in 2015, 2014 and 2013. We use shares purchased under our 2006 share repurchase program to satisfy exercises to the extent that repurchased shares are available. Otherwise, we issue new shares from our authorized common stock.

Performance Units

In general, a performance unit is an award of the right to receive (i) an equal number of shares of our common stock, which we refer to as a restricted stock unit or (ii) cash, subject to the achievement of certain pre-established performance criteria, which we refer to as a performance cash unit. Performance units are subject to certain transfer restrictions and forfeiture upon termination of employment. The compensation cost of restricted stock unit awards is equal to the grant date fair value of the awards, recognized over the requisite service period, determined according to the authoritative guidance related to stock compensation. The compensation cost of performance cash unit awards is equal to the grant date fair value of the awards measured against progress towards the performance measure, recognized over the requisite service period. No other assumptions are used to value these awards.

Restricted Stock Units In general, a restricted stock unit is an award that represents the opportunity to receive a specified number of shares of our common stock, subject to the achievement of certain pre-established performance criteria. In 2015 and 2014, we granted 47,546 and 44,272, respectively, of restricted stock units (including dividends) to certain employees, of which 65,042 were outstanding as of December 31, 2015. The 2015 grants had a performance measurement period that ended December 31, 2015. The performance measure, which related to earnings before interest, income tax, depreciation and amortization, was met. As such, the related restricted stock awards will be granted in 2016 and are subject to a four-year vesting schedule.

Performance Share Unit Awards A performance share unit award represents the opportunity to receive cash and shares subject to the achievement of certain pre-established performance criteria. In 2015, 2014 and 2013, we granted performance share unit awards to certain officers. The 2015 performance share units have two performance measures. One measure, which accounts for 75%, relates to the company’s total shareholder return relative to a group of peer companies. The second measure, which accounts for 25%, relates to the company’s earnings per share, excluding wholesale services, over the three-year performance period. The 2014 and 2013 performance share units were measured entirely based on the company’s total shareholder return relative to a group of peer companies. The recorded liability and maximum potential liability related to the 2015, 2014 and 2013 grants are as follows:



In millions	Measurement period end date	Fair value accrued at December 31, 2015		Maximum aggregate payout
Granted in 2013	December 31, 2015	$	18	$	24
Granted in 2014	December 31, 2016	13		28
Granted in 2015	December 31, 2017	7		29

Stock and Restricted Stock Awards

The compensation cost of both stock awards and restricted stock awards is equal to the grant date fair value of the awards, recognized over the requisite service period. No other assumptions are used to value the awards. We refer to restricted stock as

an award of our common stock that is subject to time-based vesting or achievement of performance measures. Prior to vesting, restricted stock awards are subject to certain transfer restrictions and forfeiture upon termination of employment.

Stock Awards - Non-Employee Directors Non-employee director compensation may be paid in shares of our common stock in connection with initial election, the annual retainer, and chair retainers, as applicable. Stock awards for non-employee directors are 100% vested and non-forfeitable as of the date of grant. During 2015, we issued 26,527 shares with a weighted average fair value of $50.71 to our non-employee directors.

Restricted Stock Awards - Employees The following table summarizes the restricted stock awards activity for our employees during the last three years.



		Shares of restricted stock		Weighted average remaining vesting period (in years)	Weighted average fair value (per share)
Outstanding ⁽¹⁾	December 31, 2012	503,091			$	39.44
Issued		175,935			42.41
Forfeited		(33,352	)		40.64
Vested		(204,421	)		38.71
Outstanding⁽¹⁾	December 31, 2013	441,253			$	40.82
Issued		262,235			47.03
Forfeited		(14,895	)		43.41
Vested		(225,683	)		42.31
Outstanding ⁽¹⁾	December 31, 2014	462,910		1.8	$	43.54
Issued		274,012		3.1	51.38
Forfeited		(13,390	)	2.5	45.60
Vested		(324,700	)	—	51.68
Outstanding ⁽¹⁾	December 31, 2015	398,832		1.4	$	46.92

(1) Subject to restriction.

Employee Stock Purchase Plan (ESPP)

We have a nonqualified, broad-based ESPP for all eligible employees. As of December 31, 2015, there were 315,570 shares available for future issuance under this plan. Employees may purchase shares of our common stock in quarterly intervals at 85% of fair market value, and we record an expense for the 15% purchase price discount. Employee ESPP contributions may not exceed $25,000 per employee during any calendar year. The following table provides additional information about our ESPP as of December 31.



	2015		2014		2013
Shares purchased on the open market	106,994		100,199		97,734
Average purchase price (per share)	$	55.47	$	51.60	$	42.96
Total purchase price discount (in dollars)	$	793,931	$	739,598	$	628,358

Note 9 - Debt and Credit Facilities

Our financing activities, including long-term and short-term debt, are subject to customary approval or review by state and federal regulatory bodies. Our wholly owned subsidiary, AGL Capital, was established to provide for our ongoing financing needs through a commercial paper program, the issuance of various debt and hybrid securities and other financing arrangements. We fully and unconditionally guarantee all debt issued by AGL Capital. Nicor Gas is not permitted by regulation to make loans to affiliates or utilize AGL Capital for its financing needs. 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 that are included on our Consolidated Balance Sheets.



		December 31, 2015					December 31, 2014
Dollars in millions	Year(s) due	Weighted average interest rate⁽¹⁾		Outstanding			Weighted average interest rate⁽¹⁾		Outstanding
Short-term debt
Commercial paper - AGL Capital ⁽²⁾	2016	0.5	%	$	471		0.3	%	$	590
Commercial paper - Nicor Gas⁽²⁾	2016	0.4		539			0.2		585
Total short-term debt		0.4	%	$	1,010		0.3	%	$	1,175
Current portion of long-term debt	2016	4.9	%	$	545		5.0	%	$	200
Long-term debt - excluding current portion
Senior notes	2018-2043	5.0	%	$	2,455		5.0	%	$	2,625
First mortgage bonds	2019-2038	5.9		375			5.6		500
Gas facility revenue bonds	2022-2033	0.9		200			0.9		200
Medium-term notes	2017-2027	7.8		181			7.8		181
Total principal long-term debt		4.9	%	$	3,211		4.9	%	$	3,506
Unamortized fair value adjustment of long-term debt ⁽³⁾	2016-2038	n/a		68			n/a		80
Unamortized debt premium, net	n/a	n/a		16			n/a		16
Unamortized debt issuance costs	n/a	n/a		(20		)	n/a		(21		)
Total non-principal long-term debt		n/a		64			n/a		75
Total long-term debt - excluding current portion				$	3,275				$	3,581
Total debt				$	4,830				$	4,956


(1)	Interest rates are calculated based on the daily weighted average balance outstanding for the years ended December 31, 2015 and 2014.


(2)	As of December 31, 2015, the effective interest rates on our commercial paper borrowings were 0.7% for AGL Capital and 0.5% for Nicor Gas.


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

Short-term Debt

Our short-term debt at December 31, 2015 and 2014 was composed of borrowings under our commercial paper programs.

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 2015, our commercial paper maturities ranged from 1 to 63 days and at December 31, 2015, remaining terms to maturity ranged from 4 to 43 days. During 2015, total borrowings and repayments netted to a payment of $165 million. During 2015 there were no commercial paper issuances with original maturities over three months.

Credit Facilities On October 30, 2015, we entered into agreements to amend and extend the AGL Credit Facility and Nicor Gas Credit Facility. Under the terms of these agreements, we extended the maturity dates of the AGL Credit Facility and the Nicor Gas Credit Facility to November 9, 2018 and December 14, 2018, respectively. One of the banks elected not to participate in this extension and its total commitment of $75 million will continue through the fourth quarter of 2017. We also modified the credit facilities to provide for the limited consent by the lenders to the proposed merger with Southern Company. Additionally, we made similar changes to our Bank Rate Mode Covenants Agreement. At December 31, 2015 and 2014, there were no outstanding borrowings under either the AGL Capital or Nicor Gas credit facility.

Current Portion of Long-term Debt The current portion of our long-term debt at December 31, 2015 is composed of the portion of our long-term debt due within the next 12 months.

Long-term Debt

Our long-term debt at December 31, 2015 and 2014 consisted of medium-term notes: Series A, Series B, and Series C; senior notes; first mortgage bonds; and gas facility revenue bonds. We fully and unconditionally guarantee all of our senior notes and gas facility revenue bonds. Additionally, substantially all of Nicor Gas’ properties are subject to the lien of the indenture securing its first mortgage bonds. The majority of our long-term debt matures after fiscal year 2020. The annual maturities of our long-term debt for the next five years and thereafter are as follows:





Year	Amount (in millions)
2016	$	545
2017	22
2018	155
2019	350
2020	—
Thereafter	2,684
Total	$	3,756

Senior Notes On November 18, 2015 AGL Capital issued $250 million in 10-year senior notes at a fixed interest rate of 3.875%. The net proceeds from the senior notes, which are guaranteed by AGL Capital, were used to repay a portion of AGL Capital’s commercial paper, including $200 million we borrowed to repay our senior notes that matured on January 15, 2015. The balance of the net proceeds will be used for general corporate purposes, including capital expenditures associated with increased utility investment and construction of our new pipeline projects.

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, at which time we received $248 million in net proceeds that are classified as a financing activity on the Consolidated Statements of Cash Flow. The $2 million of debt issuance costs will be amortized to reduce interest expense over the remaining term of the senior notes. We performed a qualitative assessment of effectiveness as of December 31, 2015 and concluded that the remaining hedges are highly effective.

First Mortgage Bonds We assumed the first mortgage bonds of Nicor Gas as a result of the 2011 merger with Nicor.

Gas Facility Revenue Bonds We are party to a series of loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida under which five series of gas facility revenue bonds have been issued. These revenue bonds are issued by state agencies or counties to investors, and proceeds from the issuance then are loaned to us.

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 as of December 31, which are below the maximum allowed.



	AGL Resources				Nicor Gas
	2015		2014		2015		2014
Debt covenants ⁽¹⁾	54	%	55	%	56	%	62	%


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

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

Default Provisions

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


•	a maximum leverage ratio;


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


•	acceleration of other financial obligations; and


•	change of control provisions.

We have no triggering events in our debt instruments that are tied to changes in our specified credit ratings or our stock price and have not entered into any transaction that requires us to issue equity based on credit ratings or other triggering events. We

were in compliance with all existing debt provisions and covenants, both financial and non-financial, as of December 31, 2015 and 2014.

Note 10 - Equity

Preferred Securities

At December 31, 2015 and 2014, we had 10 million shares of authorized, unissued Class A junior participating preferred stock, no par value, and 10 million shares of authorized, unissued preferred stock, no par value.

Dividends

Our common shareholders may receive dividends when declared at the discretion of our Board of Directors. Dividends may be paid in cash, stock or other form of payment, and payment of future dividends will depend on our future earnings, cash flow, financial requirements and other factors.

Additionally, we derive a substantial portion of our consolidated assets, earnings and cash flow from the operation of regulated utility subsidiaries, whose legal authority to pay dividends or make other distributions to us is subject to regulation. As with most other companies, the payment of dividends is restricted by laws in the states where we conduct business. In certain cases, our ability to pay dividends to our common shareholders is limited by (i) our ability to pay our debts as they become due in the usual course of business and satisfy our obligations under certain financing agreements, including our debt-to-capitalization covenant, (ii) our ability to maintain total assets below total liabilities, and (iii) our ability to satisfy our obligations to any preferred shareholders.

Accumulated Other Comprehensive Loss

Our share of comprehensive income includes net income plus OCI (loss), which includes changes in fair value of certain derivatives designated as cash flow hedges, certain changes in pension and welfare benefit plans and reclassifications for amounts included in net income less net income, and OCI attributable to the noncontrolling interest. For more information on our derivative instruments, see Note 6. For more information on our pensions and retirement benefit obligations, see Note 7. Our OCI (loss) amounts are aggregated within accumulated other comprehensive loss on our 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.



In millions⁽¹⁾	Cash flow hedges			Retirement benefit plans			Total
Balance at December 31, 2012	$	(3	)	$	(215	)	$	(218	)
OCI, before reclassifications	1			66			67
Amounts reclassified from accumulated OCI	3			12			15
Balance at December 31, 2013	1			(137		)	(136		)
OCI, before reclassifications	(6		)	(71		)	(77		)
Amounts reclassified from accumulated OCI	(1		)	8			7
Balance at December 31, 2014	(6		)	(200		)	(206		)
OCI, before reclassifications	—			—			—
Amounts reclassified from accumulated OCI	8			12			20
Balance at December 31, 2015	$	2		$	(188	)	$	(186	)


(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 years ended December 31.



	December 31,
In millions⁽¹⁾	2015			2014
Cash flow hedges
Cost of goods sold (natural gas contracts)	$	(10	)	$	4
Operation and maintenance expense (natural gas contracts)	(1		)	1
Interest expense (interest rate contracts)	2			—
Total before income tax	(9		)	5
Income tax	1			(2		)
Cash flow hedges, net of income tax	(8		)	3
Less noncontrolling interest	—			2
Total cash flow hedges, net of income tax	(8		)	1
Retirement benefit plans
Operation and maintenance expense (actuarial losses) ⁽²⁾	(22		)	(15		)
Operation and maintenance expense (prior service credits)⁽²⁾	2			2
Total before income tax	(20		)	(13		)
Income tax	8			5
Total retirement benefit plans, net of income tax	(12		)	(8		)
Total reclassification	$	(20	)	$	(7	)


(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 for additional details about net periodic benefit cost.

Note 11 - Non-Wholly Owned Entities

Variable Interest Entities

On a quarterly basis, we evaluate our variable interests in other entities, primarily ownership interests, to determine if they represent a variable interest entity (VIE) as defined by the authoritative accounting guidance on consolidation, and if so, which party is the primary beneficiary. We have determined that SouthStar, a joint venture owned by us and Piedmont, is our only VIE for which we are the primary beneficiary. This requires us to consolidate its assets, liabilities and Statements of Income. Our conclusion that SouthStar is a VIE resulted from our equal voting rights with Piedmont not being proportional to our economic obligation to absorb 85% of losses or residual returns from the joint venture. We account for our ownership of SouthStar in accordance with authoritative accounting guidance, which is described within Note 3.

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 its entire 15% interest in SouthStar at fair market value. The parties currently are negotiating final terms.

SouthStar markets natural gas and related services under the trade name Georgia Natural Gas to customers in Georgia, and under various other trade names to customers in Illinois, Ohio, Florida, Maryland, Michigan and New York. Following are additional factors we considered in determining that we have the power to direct SouthStar’s activities that most significantly impact its performance.

Operations

Our wholly owned subsidiaries Nicor Gas and Atlanta Gas Light provide the following services, which affect SouthStar’s operations:


•	meter reading for SouthStar’s customers in Illinois and Georgia;


•	maintenance and expansion of the natural gas infrastructure in Illinois and Georgia; and


•	assignment of storage and transportation capacity used in delivering natural gas to SouthStar’s customers.

Liquidity and capital resources


•	guarantees of SouthStar’s activities with, and its credit exposure to, its counterparties and to certain natural gas suppliers in support of SouthStar’s payment obligations; and


•	support of SouthStar’s daily cash management activities and assistance ensuring SouthStar has adequate liquidity and working capital resources by allowing SouthStar to utilize the AGL Capital commercial paper program for its liquidity and working capital requirements in accordance with our services agreement.

Back office functions


•	accounting, information technology, legal, human resources, credit and internal controls services in accordance with our services agreement.

SouthStar’s earnings are allocated entirely in accordance with the ownership interests and are seasonal in nature, with the majority occurring during the first and fourth quarters of each year. SouthStar’s current assets consist primarily of natural gas

inventory, derivative instruments and receivables from its customers. SouthStar also has receivables from us due to its participation in AGL Capital’s commercial paper program. SouthStar’s current liabilities consist primarily of accrued natural gas costs, other accrued expenses, customer deposits, derivative instruments and payables to us from its participation in AGL Capital’s commercial paper program.

SouthStar’s contractual commitments and obligations, including operating leases and agreements with third-party providers, do not contain terms that would trigger material financial obligations in the event that such contracts were terminated. As a result, our maximum exposure to a loss at SouthStar is considered to be immaterial. SouthStar’s creditors have no recourse to our general credit beyond our corporate guarantees that we have provided to SouthStar’s counterparties and natural gas suppliers. We have provided no financial or other support that was not previously contractually required. With the exception of our corporate guarantees and the aforementioned limited protections related to goodwill and intangible assets, we have not entered into any arrangements that could require us to provide financial support to SouthStar.

Price and volume fluctuations of SouthStar’s natural gas inventories can cause significant variations in our working capital and cash flow from operations. Changes in our operating cash flows are also attributable to SouthStar’s working capital changes resulting from the impact of weather, the timing of customer collections, payments for natural gas purchases and cash collateral amounts that SouthStar maintains to facilitate its derivative instruments.

Cash flows used in our investing activities include capital expenditures for SouthStar of $3 million, $7 million and $3 million for the years ended December 31, 2015, 2014 and 2013, 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 years ended December 31, 2015, 2014 and 2013, SouthStar distributed $18 million, $17 million and $17 million, respectively, to Piedmont.

On September 1, 2013, we contributed to SouthStar our Illinois retail energy businesses with approximately 108,000 customers. Additionally, Piedmont contributed to SouthStar $22.5 million in cash to maintain its 15% ownership in the joint venture. In connection with the contribution of our Illinois retail energy businesses, we provided certain limited protections to Piedmont regarding the value of the contributed businesses related to goodwill and other intangible assets. Piedmont’s contribution is reflected as an increase to the noncontrolling interest on our Consolidated Balance Sheets and a financing activity on our Consolidated Statements of Cash Flows. These funds were used to reduce our commercial paper borrowings. The following table provides additional information on SouthStar’s assets and liabilities as of December 31, which are consolidated within our Consolidated Balance Sheets. The SouthStar amounts exclude intercompany eliminations and the balances of our wholly owned subsidiary with an 85% ownership interest in SouthStar.



	2015						2014
In millions	Consolidated		SouthStar		%		Consolidated		SouthStar		%
Current assets	$	2,115	$	245	12	%	$	2,886	$	236	8	%
Goodwill and other intangible assets	1,922		114		6		1,952		125		6
Long-term assets and other deferred debits	10,717		16		—		10,050		17		—
Total assets	$	14,754	$	375	3	%	$	14,888	$	378	3	%
Current liabilities	$	3,000	$	54	2	%	$	3,219	$	71	2	%
Long-term liabilities and other deferred credits	7,779		—		—		7,841		—		—
Total liabilities	10,779		54		1		11,060		71		1
Equity	3,975		321		8		3,828		307		8
Total liabilities and equity	$	14,754	$	375	3	%	$	14,888	$	378	3	%

The following table provides information on SouthStar’s operating revenues and operating expenses for the years ended December 31, which are consolidated within our Consolidated Statements of Income.



In millions	2015		2014
Operating revenues	$	711	$	866
Operating expenses
Cost of goods sold	490		645
Operation and maintenance	81		87
Depreciation and amortization	10		11
Taxes other than income taxes	1		1
Total operating expenses	582		744
Operating income	$	129	$	122

Equity Method Investments

Triton We have an investment in Triton, a cargo container leasing company, which is included within our “other” non-reportable segment. Container equipment that is acquired by Triton is accounted for in tranches as defined in Triton’s operating agreement, and investors make capital contributions to Triton to invest in each of the tranches. As of December 31, 2015, we had invested in seven tranches established by Triton.

Horizon Pipeline We own a 50% interest in a joint venture with Natural Gas Pipeline Company of America that is regulated by the FERC and is included within our midstream operations segment. Horizon Pipeline operates a 70-mile natural gas pipeline from Joliet, Illinois to near the Wisconsin/Illinois border. Nicor Gas typically contracts for 70% to 80% of the total capacity.

Pipeline Development Investments In the third quarter of 2014, we entered into partnerships to form two new interstate pipeline companies within our midstream operations segment, as described below. The capacity from these pipelines will further enhance system reliability as well as provide access to a more diverse supply of natural gas. We have concluded that, at present, both companies are VIEs. We are not considered the primary beneficiary and, therefore, we have not consolidated the financial statements for these companies on our consolidated financial statements because we share in the ability to direct the activities that most significantly impact their economic performance with their other member companies. We have accounted for our investments in these companies using the equity method of accounting, and have classified the investments within other noncurrent assets on our Consolidated Balance Sheets. The contractual commitments and obligations, including agreements with third-party providers, of these VIEs for which we are not the primary beneficiary do not contain terms that would trigger material financial obligations in the event that such contracts were terminated. As a result, our maximum exposure to a loss is considered to be immaterial.

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

Atlantic Coast Pipeline In September 2014, we entered into a project in which we hold a 5% ownership interest to develop and operate a 564-mile natural gas pipeline in North Carolina, Virginia and West Virginia with initial transportation capacity of 1.5 Bcf per day, which may be expanded to 2.0 Bcf per day.

Sawgrass Storage We previously owned a 50% interest in Sawgrass Storage, a joint venture between us and a privately held energy exploration and production company for the development of an underground natural gas storage facility in Louisiana with 30 Bcf of working gas capacity that is included within our midstream operations segment. In December 2013, the joint venture decided to terminate the development of this facility and recognized an impairment loss of $16 million, which reduced the carrying amount of the joint venture’s long-lived assets to fair value. Consequently, we recognized our 50% interest in the loss during the fourth quarter of 2013, resulting in an $8 million ($5 million, net of tax) charge to operating income. This joint venture was dissolved in May 2015.

The carrying amounts on our Consolidated Balance Sheets of our investments that are accounted for under the equity method at December 31 were as follows:



In millions	2015		2014
Triton	$	49	$	62
Horizon Pipeline	14		14
PennEast Pipeline	9		1
Atlantic Coast Pipeline	7		2
Other	1		1
Total	$	80	$	80

Income from our equity method investments is classified as other income on our Consolidated Statements of Income. The following table provides the income from our equity method investments for the years ended December 31. For more information on our other income, see Note 3.



In millions	2015		2014		2013
Triton	$	4	$	6	$	9
Horizon Pipeline	2		2		2
Other	—		—		(8		)

Note 12 - Commitments, Guarantees and Contingencies

We incur various contractual obligations and financial commitments in the normal course of business that are reasonably likely to have a material effect on liquidity or the availability of capital resources. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and commercial arrangements that are directly supported by related revenue-producing activities. In April 2015, Nicor Gas entered into a series of natural gas purchase obligations in the ordinary course of business, which are reflected in the table below. The following table illustrates our expected future contractual payments under our obligations and other commitments as of December 31, 2015.



In millions	Total		2016		2017		2018		2019		2020		2021 & thereafter
Recorded contractual obligations:
Long-term debt	$	3,756	$	545	$	22	$	155	$	350	$	—	$	2,684
Short-term debt	1,010		1,010		—		—		—		—		—
Environmental remediation liabilities (1)	431		67		79		70		61		52		102
Total	$	5,197	$	1,622	$	101	$	225	$	411	$	52	$	2,786
Unrecorded contractual obligations and commitments^{(2) (7)}:
Pipeline charges, storage capacity and gas supply⁽³⁾	$	5,007	$	795	$	536	$	392	$	370	$	318	$	2,596
Interest charges ⁽⁴⁾	2,418		181		158		156		151		133		1,639
Operating leases ⁽⁵⁾	159		31		26		18		16		15		53
Asset management agreements⁽⁶⁾	28		11		9		6		2		—		—
Standby letters of credit, performance/surety bonds⁽⁷⁾	73		73		—		—		—		—		—
Other	5		3		1		1		—		—		—
Total	$	7,690	$	1,094	$	730	$	573	$	539	$	466	$	4,288


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


(2)	In accordance with GAAP, these items are not reflected on our Consolidated Balance Sheets.

(3)

Includes charges recoverable through a natural gas cost recovery mechanism or alternatively billed to marketers and demand charges associated with Sequent. The gas supply balance includes amounts for Nicor Gas and SouthStar gas commodity purchase commitments of 37 Bcf at floating gas prices calculated using forward natural gas prices as of December 31, 2015, and is valued at $76 million. As we do for certain of our affiliates, we provide guarantees to certain gas suppliers for SouthStar in support of payment obligations.


(4)	Floating rate interest charges are calculated based on the interest rate as of December 31, 2015 and the maturity date of the underlying debt instrument. As of December 31, 2015, we have $49 million of accrued interest on our Consolidated Balance Sheets that will be paid in 2016.

(5)

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


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


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

We are also involved in legal or administrative proceedings before various courts and agencies with respect to general claims, environmental remediation and other matters. Although we are unable to determine the ultimate outcomes of these contingencies, we believe that our financial statements appropriately reflect these amounts, including the recording of liabilities when a loss is probable and reasonably estimable.

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.

Financial guarantees AGL Equipment Leasing Inc. (AEL), a wholly owned subsidiary, holds our interest in Triton and has an obligation to restore to zero any deficit in its equity account for income tax purposes in the unlikely event that Triton is liquidated and a deficit balance remains. This obligation was not impacted by the 2014 sale of Tropical Shipping and continues for the life of the Triton partnerships. Any payment is effectively limited to the net assets of AEL, which were less than $1 million at December 31, 2015. We believe the likelihood of any such payment by AEL is remote and, as such, no liability has been recorded for this obligation.

Indemnities In certain instances, we have undertaken to indemnify current property owners and others against costs associated with the effects and/or remediation of contaminated sites for which we may be responsible under applicable federal or state environmental laws, generally with no limitation as to the amount. These indemnifications relate primarily to ongoing coal tar cleanup, as discussed in the “Environmental Matters” section below. We believe that the likelihood of payment under our other environmental indemnifications is remote. No liability has been recorded for such indemnifications as the fair value was inconsequential at inception.

Regulatory Matters

In February 2015, Atlanta Gas Light made a filing with the Georgia Commission for a rate true-up of allowed unrecovered revenue of $178 million through December 2014 related to its PRP. In October 2015, Atlanta Gas Light received a final order from the Georgia Commission, which represented a resolution of all matters previously outstanding before the Georgia Commission, including a final determination of the true-up recovery related to the PRP. This order allows Atlanta Gas Light to recover $144 million of the $178 million unrecovered program revenue that was requested in its February 2015 filing. The remaining unrecovered amount relates primarily to recoveries of previously allowed rate of return amounts, which are included in our unrecognized ratemaking amount and does not have a material impact on our consolidated financial statements as of December 31, 2015. Provisions in the order resulted in the recognition of $1 million of interest expense related to the PRP true-up for the year ended December 31, 2015 on our Consolidated Statements of Income.

We began recovering the $144 million in October 2015 through the monthly PRP surcharge, which increased by $0.82 on October 1, 2015 and will further increase by $0.81 on each of October 1, 2016 and October 1, 2017. The cumulative total monthly increase to the PRP surcharge will remain at $2.44 and be effective until the earlier of the full recovery of the under-recovered amount or December 31, 2025. During 2015 we recognized $2 million of revenue for this program.

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

In August 2014, staff of the Illinois Commission and the CUB filed testimony in the Nicor Gas 2003 gas cost prudence review disputing certain gas loan transactions offered by Nicor Gas under its Chicago Hub services and requesting refunds of $18 million and $22 million, respectively. We filed surrebuttal testimony in December 2014 disputing that any refund is due, as Nicor Gas was authorized to enter into these transactions and revenues associated with such transactions reduced ratepayers’ costs as either credits to the PGA or reductions to base rates consistent with then-current Illinois Commission orders governing these activities. In July 2015, the Administrative Law Judge issued a proposed order concluding that Nicor Gas’ supply costs and purchases in 2003 were prudent, its reconciliation of the related costs was proper, and the propositions by the staff of the Illinois Commission and the CUB were based on hindsight speculation, which is expressly prohibited in a prudence review examination. In September 2015, the Illinois Commission issued a final order approving the proposal of the Administrative Law Judge. In November 2015, the Illinois Commission granted the CUB’s petition for a rehearing on this matter. In February 2016, the Administrative Law Judge issued a proposed order on rehearing affirming the original order by the Illinois Commission, which now requires approval by the Illinois Commission.

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

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 for additional information on our environmental remediation costs.

In September 2015, the EPA 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 EPA 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 be material to earnings in a particular period, they will not have a material adverse effect on our consolidated financial position or cash flows for the year.

The company and each member of the Board were named as defendants in four purported shareholder class action lawsuits filed in the United States District Court for the Northern District of Georgia, Atlanta Division, which we refer to as the “Court”: Patrick Baker v. AGL Resources Inc., et al., which we refer to as the “Baker Action”, Jeff Morton v. AGL Resources Inc., et al., which we refer to as the “Morton Action”, Sarah Halberstam and Baruch Z. Halberstam (as custodian for Benjamin Halberstam) v. AGL Resources Inc., et al., which we refer to as the “Halberstam Action”, and Manuel Abt v. AGL Resources, Inc., et al., which we refer to as the “Abt Action”, filed on September 16, 2015, September 22, 2015, September 28, 2015 and October 9, 2015, respectively. Southern Company and Merger Sub were also named as defendants in the Baker Action and the Morton Action. We refer to the Baker Action, the Morton Action, the Halberstam Action and the Abt Action, collectively, as the “Actions”. The Actions alleged that our preliminary proxy statement contained false and misleading statements and omitted

material information in violation of certain provisions under the Exchange Act. The Actions also alleged that the members of the Board were liable for those alleged misstatements and omissions. The Morton Action further alleged that the members of the Board breached their fiduciary duties owed to the shareholders of the company in connection with the merger and that Southern Company and Merger Sub aided and abetted such breaches. The Actions sought, among other things, preliminary and permanent injunctive relief enjoining the merger, rescission or rescissory damages in the event the merger is implemented and an award of attorneys’ and experts’ fees and costs. On October 23, 2015, the Court consolidated the four actions, and on January 5, 2016, the Court dismissed the consolidated action without prejudice.

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

In February 2012, we committed to a stipulation with the staff of the Illinois Commission for a resolution of the dispute through credits to Nicor Gas customers of $64 million. On November 5, 2012, the Administrative Law Judges issued a proposed order for a refund of $72 million to ratepayers. In the fourth quarter of 2012, we increased our accrual for this dispute by $8 million for a total of $72 million as a result of these developments and their effect on the estimated liability.

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

Note 13 - Income Taxes

Income Tax Expense

The relative split between current and deferred taxes is due to a variety of factors, including true-ups of prior year tax returns, and most importantly, the timing of our property-related deductions. Components of income tax expense on the Consolidated Statements of Income are shown in the following table.



In millions	2015			2014			2013
Current income taxes
Federal ⁽¹⁾	$	(11	)	$	113		$	164
State	10			38			35
Deferred income taxes
Federal	198			184			(8		)
State	18			17			(11		)
Amortization of investment tax credits	(2		)	(2		)	(3		)
Total income tax expense	$	213		$	350		$	177


(1)	We incurred an $11 million federal net operating loss in 2015, which will be carried back and fully utilized against prior year income tax.

The reconciliations between the statutory federal income tax rate of 35%, the effective rate and the related amount of income tax expense for the years ended December 31, on our Consolidated Statements of Income are presented in the following table.



In millions	2015			2014			2013
Computed tax expense at statutory rate	$	205		$	325		$	165
State income tax, net of federal income tax benefit	21			36			20
Tax effect of net income attributable to the noncontrolling interest	(8		)	(7		)	(7		)
Amortization of investment tax credits	(2		)	(2		)	(3		)
Affordable housing credits	(1		)	(2		)	(2		)
Flexible dividend deduction	(2		)	(2		)	(2		)
Sale of Compass Energy	—			—			6
Other	—			2			—
Total income tax expense	$	213		$	350		$	177

Accumulated Deferred Income Tax Assets and Liabilities

We report some of our assets and liabilities differently for financial accounting purposes than we do for income tax purposes. We report the tax effects of the differences in those items as deferred income tax assets or liabilities on our Consolidated Balance Sheets. We measure the assets and liabilities using income tax rates that are currently in effect. The current portion of our deferred income taxes is recognized within current assets on our Consolidated Balance Sheets. We have provided a

valuation allowance for some of these items that reduce our net deferred tax assets to amounts we believe are more likely than not to be realized in future periods. With respect to our continuing operations, we have net operating losses in various jurisdictions. Components that give rise to the net current and long-term accumulated deferred income tax liability are as follows.



	As of December 31,
In millions	2015			2014
Current accumulated deferred income tax liabilities
Mark-to-market	$	37		$	33
Inventory	53			26
Total current accumulated deferred income tax liabilities	90			59
Current accumulated deferred income tax assets
Compensation accruals	30			30
Lower of cost or market	6			26
Allowance for doubtful accounts	8			12
Other	19			21
Total current accumulated deferred income tax assets	63			89
Valuation allowances ⁽¹⁾	(4		)	(6		)
Total current accumulated deferred income tax assets, net of valuation allowances	59			83
Net current accumulated deferred income tax (liability) asset	$	(31	)	$	24
Long-term accumulated deferred income tax liabilities
Property - accelerated depreciation and other property-related items	$	2,019		$	1,801
Investments in partnerships	12			16
Acquisition intangibles	12			14
Mark-to-market	1			12
Other	102			85
Total long-term accumulated deferred income tax liabilities	2,146			1,928
Long-term accumulated deferred income tax assets
Unfunded pension and retiree welfare benefit obligation	120			117
Deferred investment tax credits	5			6
Other	124			95
Total long-term accumulated deferred income tax assets	249			218
Valuation allowances⁽¹⁾	(15		)	(14		)
Total long-term accumulated deferred income tax assets, net of valuation allowances	234			204
Net long-term accumulated deferred income tax liability	$	1,912		$	1,724

(1)

The total valuation allowance in 2015 and 2014 is $19 million and $20 million, respectively. For 2015, the valuation allowance is related to our investment in Triton. For 2014, the total is composed of $1 million due to net operating losses in New Jersey of a former non-operating facility that are not allowed in New Jersey and $19 million related to our investment in Triton. New Jersey net operating losses expired in 2014, resulting in a reduction of the valuation allowance.

Tax Benefits

As of December 31, 2015 and December 31, 2014, we did not have a liability for unrecognized tax benefits. Based on current information, we do not anticipate that this will change materially in 2016. As of December 31, 2015, we did not have a liability recorded for payment of interest or penalties associated with uncertainty in income taxes, nor did we have any such interest or penalties during 2015 or 2014.

We file a U.S. federal consolidated income tax return and various state income tax returns. We are no longer subject to income tax examinations by the Internal Revenue Service or in any state for years before 2012.

Note 14 - 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.”

In September 2014, we sold Tropical Shipping, which historically operated within our cargo shipping segment. The financial results of these businesses for the years ended December 31, 2014 and 2013 are reflected as discontinued operations on the

Consolidated Statements of Income. Amounts shown in this note for total assets as of December 31, 2013 exclude assets held for sale and other amounts shown, unless otherwise indicated, exclude discontinued operations. Cargo shipping also included our investment in Triton, which was not part of the sale and has been reclassified to a non-reportable segment. See Note 15 for additional information.

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

We are also involved in several related and complementary businesses. Our retail operations segment includes retail natural gas marketing to end-use customers primarily in Georgia and Illinois. Additionally, retail operations provides home equipment protection products and services. Our wholesale services segment engages in natural gas storage and gas pipeline arbitrage and related activities. Additionally, this segment provides natural gas asset management and/or related logistics services for each of our utilities except Nicor Gas, as well as for non-affiliated companies. Our midstream operations segment includes our non-utility storage and pipeline operations, including the operation of high-deliverability natural gas storage assets. Our other 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 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 years ended December 31 are shown in the following tables.



2015
In millions	Distribution operations		Retail operations		Wholesale services ⁽¹⁾			Midstream operations			Other			Intercompany eliminations			Consolidated
Operating revenues from external parties	$	2,880	$	835	$	202		$	55		$	11		$	(42	)	$	3,941
Intercompany revenues	169		—		—			—			—			(169		)	—
Total operating revenues	3,049		835		202			55			11			(211		)	3,941
Operating expenses
Cost of goods sold	1,291		518		19			19			4			(206		)	1,645
Operation and maintenance	687		137		67			25			3			(5		)	914
Depreciation and amortization	336		25		1			18			17			—			397
Taxes other than income taxes	164		3		3			5			6			—			181
Merger-related expenses	—		—		—			—			44			—			44
Goodwill impairment	—		—		—			14			—			—			14
Total operating expenses	2,478		683		90			81			74			(211		)	3,195
Operating income (loss)	571		152		112			(26		)	(63		)	—			746
Other income (expense)	9		—		(4		)	3			5			—			13
EBIT	$	580	$	152	$	108		$	(23	)	$	(58	)	$	—		$	759
Total assets	$	12,517	$	686	$	935		$	692		$	9,664		$	(9,740	)	$	14,754
Capital expenditures	$	957	$	7	$	2		$	27		$	—		$	34		$	1,027



2014
In millions	Distribution operations		Retail operations		Wholesale services⁽¹⁾			Midstream operations			Other			Intercompany eliminations			Consolidated
Operating revenues from external parties	$	3,802	$	994	$	578		$	88		$	7		$	(84	)	$	5,385
Intercompany revenues	199		—		—			—			—			(199		)	—
Total operating revenues	4,001		994		578			88			7			(283		)	5,385
Operating expenses
Cost of goods sold	2,223		683		77			57			—			(275		)	2,765
Operation and maintenance	699		147		75			26			—			(8		)	939
Depreciation and amortization	317		28		1			18			16			—			380
Taxes other than income taxes	189		4		3			6			6			—			208
Total operating expenses	3,428		862		156			107			22			(283		)	4,292
Gain (loss) on disposition of assets	—		—		3			—			(1		)	—			2
Operating income (loss)	573		132		425			(19		)	(16		)	—			1,095
Other income (expense)	8		—		(3		)	2			7			—			14
EBIT	$	581	$	132	$	422		$	(17	)	$	(9	)	$	—		$	1,109
Total assets	$	12,037	$	670	$	1,402		$	694		$	9,706		$	(9,621	)	$	14,888
Capital expenditures	$	715	$	11	$	2		$	15		$	26		$	—		$	769



2013
In millions	Distribution operations		Retail operations		Wholesale services⁽¹⁾			Midstream operations			Other			Intercompany eliminations			Consolidated
Operating revenues from external parties	$	3,230	$	858	$	60		$	74		$	8		$	(21	)	$	4,209
Intercompany revenues	182		—		—			—			—			(182		)	—
Total operating revenues	3,412		858		60			74			8			(203		)	4,209
Operating expenses
Cost of goods sold	1,687		564		21			33			—			(195		)	2,110
Operation and maintenance	687		132		49			24			3			(8		)	887
Depreciation and amortization	339		27		1			17			13			—			397
Taxes other than income taxes	167		3		3			5			9			—			187
Total operating expenses	2,880		726		74			79			25			(203		)	3,581
Gain on disposition of assets	—		—		11			—			—			—			11
Operating income (loss)	532		132		(3		)	(5		)	(17		)	—			639
Other income (expense)	14		—		—			(5		)	7			—			16
EBIT	$	546	$	132	$	(3	)	$	(10	)	$	(10	)	$	—		$	655
Total assets ⁽²⁾	$	11,629	$	685	$	1,163		$	713		$	10,426		$	(10,088	)	$	14,528
Capital expenditures	$	684	$	9	$	2		$	12		$	24		$	—		$	731

(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 for the years ended December 31, are shown in the following table. Wholesale services 2014 operating revenues are related to colder-than-normal weather and extreme volatility and are not indicative of future performance.



In millions	Third party gross revenues		Intercompany revenues	Total gross revenues	Less gross gas costs	Operating revenues
2015	$	6,286	408	6,694	6,492	$	202
2014	$	10,709	718	11,427	10,849	$	578
2013	$	7,681	417	8,098	8,038	$	60


(2)	Total assets reported as of December 31, 2013 exclude assets held for sale.

Note 15 - Discontinued Operations

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

During the first quarter of 2014, based upon the negotiated sales price, we recorded a non-cash goodwill impairment charge of $19 million, for which there was no income tax benefit. Additionally, we recognized a total charge of $7 million in the second

and third quarters of 2014 related to the suspension of depreciation and amortization on assets for which we were not compensated by the buyer.

The financial results of these businesses are reflected as discontinued operations, and the prior periods presented have been recast to reflect the discontinued operations. The components of discontinued operations recorded on the Consolidated Statements of Income as of December 31, are as follows:



In millions	2014			2013
Operating revenues	$	243		$	365
Operating expenses
Cost of goods sold	149			222
Operation and maintenance⁽¹⁾	75			110
Depreciation and amortization⁽²⁾	5			19
Taxes other than income taxes	5			6
Loss on sale and goodwill impairment⁽³⁾	28			—
Total operating expenses	262			357
Operating (loss) income	(19		)	8
(Loss) income before income taxes	(19		)	8
Income tax expense ⁽⁴⁾	(61		)	(3		)
(Loss) income from discontinued operations, net of tax	$	(80	)	$	5


(1)	Includes $1 million for another business not related to Tropical Shipping that we discontinued in 2014 and was included in our other segment.


(2)	We ceased depreciating and amortizing Tropical Shipping’s assets on April 4, 2014.


(3)	Primarily relates to the suspension of depreciation and amortization during 2014 totaling $7 million, and $19 million of goodwill attributable to Tropical Shipping that was impaired as of March 31, 2014, based on the negotiated sales price.


(4)	Includes $60 million that was recorded in 2014 related to the cumulative foreign earnings for which no tax liabilities had been previously recorded.

Note 16 - Selected Quarterly Financial Data (Unaudited)

The variance in our quarterly earnings is primarily the result of the seasonal nature of the distribution of natural gas to customers, the volatility within our wholesale services segment and the sale of our cargo shipping segment in 2014. During the Heating Season, natural gas usage and operating revenues are generally higher at our distribution operations and retail operations segments as more customers are connected to our distribution systems and natural gas usage is higher in periods of colder weather. However, our base operating expenses, excluding cost of goods sold, interest expense and certain incentive compensation costs, are incurred relatively uniformly over any given year. Thus, our operating results can vary significantly from quarter to quarter as a result of seasonality.

Our 2015 operating revenues and operating income were lower than 2014, primarily as a result of significantly colder-than-normal weather in 2014, lower volatility in the natural gas market and transportation constraints in the Northeast and Midwest. Our quarterly financial data for 2015 and 2014 are summarized below.



In millions, except per share amounts	March 31			June 30		September 30			December 31
2015
Operating revenues	$	1,721		$	674	$	584		$	962
Operating income	364			107		59			216
EBIT	367			111		61			220
Net income	205			44		12			112
Net income attributable to AGL Resources	193			42		11			107
Basic earnings (loss) per common share	1.62			0.35		0.09			0.89
Diluted earnings (loss) per common share	1.62			0.35		0.09			0.89
2014
Operating revenues	$	2,462		$	889	$	589		$	1,445
Operating income	592			139		78			286
EBIT	595			141		81			292
Income from continuing operations	346			59		23			152
Income from continuing operations attributable to AGL Resources	334			57		23			148
(Loss) income from discontinued operations, net of tax	(50		)	1		(31		)	—
Net income (loss) attributable to AGL Resources	284			58		(8		)	148
Basic earnings (loss) per common share:
Continuing operations	2.82			0.48		0.19			1.24
Discontinued operations	(0.43		)	0.01		(0.25		)	—
Diluted earnings (loss) per common share:
Continuing operations	2.81			0.48		0.19			1.24
Discontinued operations	(0.43		)	0.01		(0.25		)	—

Our basic and diluted earnings per common share are calculated based on the weighted daily average number of common shares and common share equivalents outstanding during the quarter. Those totals differ from the basic and diluted earnings per common share attributable to AGL Resources common shareholders shown in the Consolidated Statements of Income, which are based on the weighted average number of common shares and common share equivalents outstanding during the entire year.

Schedule II

AGL Resources Inc. and Subsidiaries

VALUATION AND QUALIFYING ACCOUNTS - FOR EACH OF THE THREE YEARS IN THE PERIOD ENDED December 31, 2015.



			Additions
In millions	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts		Deductions			Balance at end of period
2013
Allowance for uncollectible accounts	$	28	$	37	$	—	$	(36	)	$	29
Income tax valuation	22		—		—		—			22
2014
Allowance for uncollectible accounts	$	29	$	54	$	2	$	(50	)	$	35
Income tax valuation	22		—		—		(2		)	20
2015
Allowance for uncollectible accounts	$	35	$	27	$	3	$	(36	)	$	29
Income tax valuation	20		—		—		(1		)	19

SOUTHERN CO - FORM 8-K - EX-99.1 - EXHIBIT 99.1 - May 5, 2016

Attached files

SOUTHERN CO Reports