SOUTHERN CO - FORM 8-K - EX-99.2 - EXHIBIT 99.2

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8-K - 8-K - SOUTHERN CO	so-aglprofomafin8xk5x16.htm
EX-23.1 - EXHIBIT 23.1 - SOUTHERN CO	ex23-1soxaglproformafin8xk.htm
EX-99.3 - EXHIBIT 99.3 - SOUTHERN CO	proformafinancials-q12016.htm
EX-99.1 - EXHIBIT 99.1 - SOUTHERN CO	ex99-1soxaglproformafin8xk.htm

EXHIBIT 99.2

AGL RESOURCES INC. QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2016

AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITIED)



	As of
In millions, except share and per share amounts	March 31, 2016		December 31, 2015		March 31, 2015
Current assets
Cash and cash equivalents	$	20	$	19	$	41
Receivables
Natural gas, unbilled revenues and other	564		516		834
Energy marketing	365		445		611
Less allowance for uncollectible accounts	36		29		48
Total receivables, net	893		932		1,397
Inventories	335		651		302
Derivative instruments, including cash collateral	160		206		189
Prepaid expenses	62		218		38
Regulatory assets	50		68		63
Other	17		21		49
Total current assets	1,537		2,115		2,079
Long-term assets and other deferred debits
Property, plant and equipment	12,777		12,566		11,689
Less accumulated depreciation	2,833		2,775		2,515
Property, plant and equipment, net	9,944		9,791		9,174
Goodwill	1,813		1,813		1,827
Regulatory assets	661		670		634
Intangible assets	105		109		116
Other	276		256		289
Total long-term assets and other deferred debits	12,799		12,639		12,040
Total assets	$	14,336	$	14,754	$	14,119
Current liabilities
Short-term debt	$	557	$	1,010	$	526
Current portion of long-term debt	470		545		75
Energy marketing trade payables	363		418		586
Other accounts payable – trade	250		255		285
Accrued expenses	231		200		259
Regulatory liabilities	159		134		168
Customer deposits and credit balances	141		165		109
Accrued environmental remediation liabilities	68		67		93
Derivative instruments, including cash collateral	64		44		48
Temporary LIFO liquidation	48		—		87
Current deferred income taxes	20		31		—
Other	118		131		135
Total current liabilities	2,489		3,000		2,371
Long-term liabilities and other deferred credits
Long-term debt	3,273		3,275		3,505
Accumulated deferred income taxes	1,921		1,912		1,738
Regulatory liabilities	1,632		1,611		1,612
Accrued pension and retiree welfare benefits	513		515		526
Accrued environmental remediation liabilities	355		364		326
Other	83		102		77
Total long-term liabilities and other deferred credits	7,777		7,779		7,784
Total liabilities and other deferred credits	10,266		10,779		10,155
Commitments, guarantees and contingencies (see Note 11)
Contingently redeemable noncontrolling interest	38		—		—



Equity
Common stock, $5 par value; 750,000,000 shares authorized; outstanding: 120,679,004 shares at March 31, 2016, 120,376,721 shares at December 31, 2015, and 119,927,459 shares at March 31, 2015	604			603			601
Additional paid-in capital	2,110			2,099			2,090
Retained earnings	1,539			1,421			1,444
Accumulated other comprehensive loss	(213		)	(186		)	(201		)
Treasury shares, at cost: 216,523 shares at March 31, 2016, December 31, 2015, and March 31, 2015	(8		)	(8		)	(8		)
Total common shareholders’ equity	4,032			3,929			3,926
Noncontrolling interest	—			46			38
Total equity	4,032			3,975			3,964
Total liabilities, redeemable noncontrolling interest and equity	$	14,336		$	14,754		$	14,119

See Notes to Condensed Consolidated Financial Statements (Unaudited).

AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)



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

See Notes to Condensed Consolidated Financial Statements (Unaudited).

AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(UNAUDITED)



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

See Notes to Condensed Consolidated Financial Statements (Unaudited).

AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(UNAUDITED)



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



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

See Notes to Condensed Consolidated Financial Statements (Unaudited).

AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)



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

See Notes to Condensed Consolidated Financial Statements (Unaudited).

AGL RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 - Organization and Basis of Presentation

General

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

Our Condensed Consolidated Balance Sheet as of December 31, 2015 was derived from our audited consolidated financial statements. We have prepared the accompanying unaudited condensed consolidated financial statements under the rules and regulations of the SEC. In accordance with such rules and regulations, we have condensed or omitted certain information and notes that would typically be included in our annual audited financial statements. Our unaudited condensed consolidated financial statements reflect all adjustments of a normal recurring nature that are, in the opinion of management, necessary for a fair statement of our financial results for the interim periods and should be read in conjunction with our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K.

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

Basis of Presentation

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

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

Note 2 - Proposed Merger with Southern Company

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

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

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

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

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

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

Note 3 - Significant Accounting Policies and Methods of Application

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

Use of Accounting Estimates

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

Inventories

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

Nicor Gas’ inventory is carried at cost on a LIFO basis. Under the LIFO method, inventory decrements occurring during the year that are expected to be restored prior to year-end are charged to cost of goods sold at the estimated annual replacement cost, and the difference between this cost and the actual liquidated LIFO layer cost is recorded as a temporary LIFO liquidation on our unaudited Condensed Consolidated Balance Sheets. Interim inventory decrements that are not expected to be restored prior to year-end are charged to cost of goods sold at the actual LIFO cost of the layers liquidated. The inventory decrement as of March 31, 2016 is expected to be restored prior to year-end and the inventory decrement as of March 31, 2015 was restored prior to December 31, 2015.

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



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

Goodwill

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



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

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

Earnings per Common Share

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



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


(1)	Daily weighted average shares outstanding.


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

Accounting Developments

Accounting standards adopted in 2016

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


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


•	consolidation of other legal entities into our financial statements;


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


•	reducing the diversity in fair value measurements hierarchy disclosures.

Other newly issued accounting standards and updated authoritative guidance

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

In February 2016, the FASB issued updated authoritative guidance related to accounting for lease transactions. The new guidance will require all organizations that use leased assets, referred to as "lessees," to recognize all leases with terms of more than 12 months on the balance sheet as right of use assets and corresponding liabilities. Lessees will continue to recognize lease

expense based on classification of the lease, using a straight-line expense pattern for operating leases and a front-loaded expense pattern for financing leases. The accounting for lessors is substantially equivalent to the existing guidance. It also requires additional disclosures, both qualitative and quantitative, including amount, timing, and uncertainty of cash flows arising from leases. The new guidance is effective for us beginning January 1, 2019 and must be applied using the modified retrospective approach to each prior period presented. Early adoption of this new guidance is permitted. We are currently evaluating the potential impact of this new guidance.

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

In November 2015, the FASB issued updated authoritative guidance related to the balance sheet classification of deferred taxes, which requires companies to present deferred income tax assets and deferred income tax liabilities as noncurrent on a classified balance sheet instead of the current requirement to separate deferred income tax liabilities and assets into current and noncurrent amounts. The guidance is effective for us beginning January 1, 2017, and early application is permitted either prospectively or retrospectively. We have determined that this new guidance will not have a material impact on our consolidated financial statements.

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

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

Note 4 - Regulated Operations

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



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

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

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



In millions	March 31, 2016		December 31, 2015		March 31, 2015
Atlanta Gas Light ⁽¹⁾	$	105	$	103	$	119
Virginia Natural Gas	12		12		12
Elizabethtown Gas	4		4		2
Nicor Gas	3		3		—
Total	$	124	$	122	$	133


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

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

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

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

Our accrued environmental remediation liabilities are not regulatory liabilities; however, the associated expenses are deferred as corresponding regulatory assets until the costs are recovered from customers. We primarily recover these deferred costs through rate riders that authorize dollar-for-dollar recovery. We expect to collect $21 million in revenues over the next 12 months, which is reflected as a current regulatory asset. The following table provides additional information on the estimated costs to remediate our current and former operating sites as of March 31, 2016.



In millions	# of sites	Probabilistic model cost estimates	Engineering-based estimates		Amount recorded		Expected costs over next 12 months		Cost recovery period
Illinois ⁽¹⁾	26	$200 - $457	$	46	$	246	$	30	As incurred
New Jersey	6	115 - 195	7		122		25		7 years
Georgia and Florida	13	29 - 52	21		50		13		5 years
North Carolina ⁽²⁾	1	n/a	5		5		—		No recovery
Total	46	$344 - $704	$	79	$	423	$	68


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


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

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

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

Note 5 - Fair Value Measurements

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

Derivative Instruments

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



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


(1)	Balances of $9 million at March 31, 2016, $10 million at December 31, 2015 and $1 million at March 31, 2015, associated with certain weather derivatives have been excluded, as they are accounted for based on intrinsic value rather than fair value.


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

Debt

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



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


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


(2)	Fair value determined using Level 2 inputs.

Note 6 - Derivative Instruments

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

Quantitative Disclosures Related to Derivative Instruments

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



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


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


(2)	99% of these contracts have durations of two years or less and 1% expire between two and five years.

Derivative Instruments on our Unaudited Condensed Consolidated Balance Sheets

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



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

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



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


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

(2)

As required by the authoritative guidance related to derivatives and hedging, the gross amounts of recognized assets and liabilities do not include cash collateral held on deposit in broker margin accounts of $165 million as of March 31, 2016, $96 million as of December 31, 2015, and $210 million as of March 31, 2015. Cash collateral is included in the “Gross amounts offset on our unaudited Condensed Consolidated Balance Sheets” line of this table.


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

Derivative Instruments on the Unaudited Condensed Consolidated Statements of Income

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



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


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


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

Any amounts recognized in operating income related to ineffectiveness or due to a forecasted transaction that is no longer expected to occur were immaterial for the three months ended March 31, 2016 and 2015. Our expected net losses to be reclassified from OCI into cost of goods sold, operation and maintenance expense, interest expense and operating revenues to be recognized on our unaudited Condensed Consolidated Statements of Income over the next 12 months are $4 million. These deferred losses are related to natural gas derivative contracts associated with retail operations’ and Nicor Gas’ system use and our interest rate swaps. The expected losses are based upon the fair values of these financial instruments at March 31, 2016. The effective portions of gains and losses on derivative instruments qualifying as cash flow hedges that were recognized in OCI during the periods are presented on our unaudited Condensed Consolidated Statements of Income. See Note 9 for these amounts.

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

Note 7 - Employee Benefit Plans

Pension Benefits

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



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

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

Welfare Benefits

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



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

Note 8 - Debt and Credit Facilities

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



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


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


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

Commercial Paper Programs

We maintain commercial paper programs at AGL Capital and at Nicor Gas that consist of short-term, unsecured promissory notes used in conjunction with cash from operations to fund our seasonal working capital requirements. Working capital needs fluctuate during the year and

are highest during the injection period in advance of the Heating Season. Nicor Gas’ commercial paper program supports working capital needs at Nicor Gas, while all of our other subsidiaries and SouthStar participate in AGL Capital’s commercial paper program. During the first three months of 2016, our commercial paper maturities ranged from 1 to 59 days, and at March 31, 2016, remaining terms to maturity ranged from 1 to 46 days. During the first three months of 2016, there were no commercial paper issuances with original maturities over three months.

Long-Term Debt

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

On January 23, 2015, we executed $800 million in notional value of 10-year and 30-year fixed-rate forward-starting interest rate swaps to hedge potential interest rate volatility prior to our senior note issuance in the fourth quarter of 2015 and our anticipated issuances in 2016. We have designated the forward-starting interest rate swaps, which are settled on the respective debt issuance dates, as cash flow hedges. We settled $200 million of these interest rate swaps on November 18, 2015, in conjunction with the aforementioned senior note issuance. We performed a qualitative assessment of effectiveness on the remaining interest rate swaps as of March 31, 2016 and concluded that the remaining hedges are highly effective.

Financial and Non-Financial Covenants

The AGL Credit Facility and the Nicor Gas Credit Facility each include a financial covenant that requires us to maintain a ratio of total debt to total capitalization of no more than 70% at the end of any month. The following table contains our debt-to-capitalization ratios for the dates presented, which are below the maximum allowed.



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


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

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

Default Provisions

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


•	a maximum leverage ratio;


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


•	acceleration of other financial obligations; and


•	change of control provisions.

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

Note 9 - Equity

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



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


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

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



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


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


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

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

SouthStar, a joint venture owned by us and Piedmont, is our only VIE for which we are the primary beneficiary. For additional information on SouthStar, see Note 11 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. Earnings from SouthStar in 2016 and 2015 were allocated entirely in accordance with the ownership interests.

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

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



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

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



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

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



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

Equity Method Investments

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

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



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

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



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

Note 11 - Commitments, Guarantees and Contingencies

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

We are also involved in legal or administrative proceedings before various courts and agencies with respect to general claims, environmental remediation and other matters. While we are unable to determine the ultimate outcomes of these contingencies, we believe that our financial statements appropriately reflect these amounts, including the recording of liabilities when a loss is probable and reasonably estimable. For more information on these matters, see Note 12 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K.

Contingencies and Guarantees

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

Regulatory Matters

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

Environmental Matters

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

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

Litigation

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

Note 12 - Segment Information

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

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

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

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

Three months ended March 31, 2016



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

Three months ended March 31, 2015



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


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



In millions	Third party gross revenues		Intercompany revenues	Total gross revenues	Less gross gas costs	Operating revenues
Three months ended March 31, 2016	$	1,443	81	1,524	1,461	$	63
Three months ended March 31, 2015	$	2,146	150	2,296	2,206	$	90

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



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

SOUTHERN CO - FORM 8-K - EX-99.2 - EXHIBIT 99.2 - May 5, 2016

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SOUTHERN CO Reports